ITEM 1. BUSINESS
DESCRIPTION OF THE TRUST
The Santa Fe Energy Trust (the "Trust"), created under the laws of the State of Texas, maintains its offices at the office of the Trustee, The Chase Manhattan Bank, successor by merger to Chase Bank of Texas, National Association, formerly known as Texas Commerce Bank National Association, (the "Trustee"), 600 Travis, Suite 1150, Houston, Texas 77002. The telephone number of the Trust is (713) 216-5087.
The Trust was formed pursuant to an Organizational Trust Agreement dated as of October 22, 1992. Effective November 19, 1992, the Organizational Trust Agreement was amended and restated by the Trust Agreement of Santa Fe Energy Trust between Devon SFS Operating, Inc. ("Devon"), formerly Santa Fe Snyder Corporation, formerly Santa Fe Energy Resources, Inc. (Santa Fe) and The Chase Manhattan Bank, successor by merger to Chase Bank of Texas, National Association formerly known as Texas Commerce Bank National Association (the "Trust Agreement"). Under the terms of the Trust Agreement, Devon conveyed royalty interests in certain oil and gas properties to the Trust. In exchange for the conveyance of such royalty interests, the Trust issued 6,300,000 units of undivided beneficial interest ("Trust Units"). The Trust Units and the Treasury Obligations (hereinafter defined) were deposited with The Chase Manhattan Bank, successor by merger to Chase Bank of Texas, National Association formerly known as Texas Commerce Bank National Association as depositary (the "Depositary") in exchange for 6,300,000 Depositary Units (hereinafter defined). Each Depositary Unit consists of beneficial ownership of one Trust Unit and a $20 face amount beneficial ownership interest in a $1,000 face amount zero coupon United States Treasury obligation ("Treasury Obligation") maturing on February 15, 2008 ("Liquidation Date"). The Depositary Units are evidenced by Secure Principal Energy Receipts ("SPERs"), which are issued and transferable only in denominations of 50 Depositary Units or an integral multiple thereof. The Depositary Units are traded on the New York Stock Exchange under the symbol SFF.
The Trust Units and Treasury Obligations are held by the Depositary for the holders of Depositary Units ("Holders"). The Treasury Obligations consist of a portfolio of United States Treasury stripped interest coupons that mature on the Liquidation Date in the aggregate face amount of $126,000,000, which amount equals $20 multiplied by the aggregate number of Depositary Units issued and outstanding. Since Depositary Units may be issued or transferred only in denominations of 50 or integral multiples thereof, each holder of 50 Depositary Units owns the entire beneficial interest in a discrete Treasury Obligation, in a face amount of $1,000, the minimum denomination of such Treasury Obligations. The Treasury Obligations do not pay current interest. See "Description of Trust Units and Depositary Units--Federal Income Tax Matters".
The Trust is a grantor trust formed by Devon to hold royalty interests in certain oil and gas properties owned by Devon (the "Royalty Properties"). The principal asset of the Trust consists of (i) two term royalty interests (the Wasson ODC Royalty and the Wasson Willard Royalty-collectively, the "Wasson Royalties") conveyed to the Trust out of Devon's royalty interests in two production units (the Wasson ODC Unit and the Wasson Willard Unit) in the Wasson Field, and (ii) a net profits royalty interest (the "Net Profits Royalties") conveyed to the Trust out of Devon's royalty interests and
working interests in a diversified portfolio of oil and gas properties (the "Net Profits Properties") located in 12 states (collectively, the "Royalty Interests").
The terms of the Trust Agreement provide, among other things, that: (1) the Trust cannot acquire any asset other than the Royalty Interests or engage in any business or investment activity of any kind whatsoever, except that cash being held by the Trustee as a reserve for liabilities or for distribution at the next distribution date will be placed in bank accounts or certificates; (2) the Trustee can establish cash reserves and borrow funds to pay liabilities of the Trust and can pledge assets of the Trust to secure payment of the borrowing; (3) the Trustee will receive the payments attributable to the Royalty Interests and pay all expenses, liabilities and obligations of the Trust; (4) the Trustee will make quarterly distributions to Holders of cash available for distribution in February, May, August and November of each year; (5) the Trustee is not required to make business decisions affecting the Trust Units or the Trust assets, but under certain circumstances, the Trustee may be required to approve or disapprove an extraordinary transaction affecting the Trust and the Holders; and (6) the Trust will be liquidated on or prior to the Liquidation Date. The discussion of terms of the Trust Agreement contained herein is qualified in its entirety by reference to the Trust Agreement itself, which is an exhibit to this Form 10-K and is available upon request from the Trustee.
The Trustee is paid an annual fee of approximately $12,500. The Trust is responsible for paying all legal, accounting, engineering and stock exchange fees, printing costs and other administrative expenses incurred by or at the direction of the Trustee. Trustee fees and Trust administrative expenses totalled $298,000, $303,000 and $265,000 in 2000, 1999 and 1998, respectively, although such costs could be greater or less in subsequent periods depending on future events. In addition, the Trust paid Devon an annual fee of $252,000, $244,000 and $234,000 in 2000, 1999 and 1998, respectively. Such fee will increase by 3.5% per year, payable quarterly, to reimburse Devon for overhead expenses.
The Wasson Royalties were conveyed from Devon to the Trust pursuant to a single instrument of conveyance (the "Wasson Conveyance"). The Net Profits Royalties were conveyed from Devon to the Trust pursuant to separate, substantially similar conveyances (the "Net Profits Conveyances") except with respect to the Net Profits Royalties in properties located within the State of Louisiana and its related state waters. Due to the effect of certain Louisiana laws governing the transfer of properties to trusts, the Louisiana Net Profits Royalties were conveyed from Devon to the Trust pursuant to a separate conveyance in the form of a secured interest in proceeds of production from such properties (the "Louisiana Conveyance"). The Louisiana Conveyance provides the Trust with the economic equivalent of the Net Profits Royalties determined with respect to the Net Profits Properties located in Louisiana. The Net Profits Conveyances, Wasson Conveyance and Louisiana Conveyance are referred to collectively as the Conveyances.
Devon owns the Royalty Properties subject to and burdened by the Royalty Interests. Devon will receive all payments relating to the sale of production from the Royalty Properties and will be required, pursuant to the Conveyances, to pay to the Trust the portion thereof attributable to the Royalty Interests. Under the Conveyances, the amounts payable with respect to the Royalty Interests will be computed with respect to each calendar quarter, and such amounts will be paid by Devon to the Trust not later than 60 days after the end of each calendar quarter. The amounts paid to the Trust will not include interest on any amounts payable with respect to the Royalty Interests which are held by Devon prior to payment to the Trust. Devon will be entitled to retain any amounts attributable to the Royalty Properties which are not required to be paid to the Trust with respect to the Royalty Interests.
The following descriptions of the Wasson Royalties and the Net Profits Royalties, and the calculation of amounts payable to the Trust in respect thereof, are subject to and qualified by the more detailed provisions of the Conveyances included as exhibits to this Form 10-K and available upon request from the Trustee.
THE WASSON ROYALTIES
THE WASSON ODC ROYALTY. The Wasson ODC Royalty was conveyed out of Devon's 12.3934% royalty interest in the Wasson ODC Unit and entitles the Trust to receive quarterly royalty payments with respect to oil production from the Wasson ODC Unit for each calendar quarter during the period ending on December 31, 2007. The royalties payable with respect to the Wasson ODC Royalty for any calendar quarter are determined by multiplying (a) the Average Per Barrel Price (as defined below) received for such quarter with respect to oil production from the Wasson ODC Unit by (b) the Royalty Production (as defined below) for such quarter related to the Wasson ODC Royalty.
"Royalty Production" for the Wasson ODC Royalty is defined as 12.3934% of the lesser of (i) the actual number of gross barrels of oil produced for such quarter from the Wasson ODC Unit and (ii) the applicable maximum quarterly gross production limitation set forth in the table below. The table also shows the maximum number of barrels of Royalty Production that may be produced per quarter in respect of the Wasson ODC Royalty (12.3934% of the quarterly gross production limitation).
The Wasson ODC Royalty will terminate on December 31, 2007. Thus, the Trustee will make a final quarterly distribution from the Wasson ODC Royalty in respect of the fourth quarter of 2007 on or about the Liquidation Date.
THE WASSON WILLARD ROYALTY. The Wasson Willard Royalty was conveyed out of Devon's 6.8355% royalty interest in the Wasson Willard Unit and entitles the Trust to receive quarterly royalty payments with respect to oil production from the Wasson Willard Unit for each calendar quarter during the period ending on December 31, 2003. The royalty payable for any calendar quarter is determined by multiplying (a) the Average Per Barrel Price (as defined below) received for such quarter with respect to oil production from the Wasson Willard Unit by (b) the Royalty Production (as defined below) for such quarter related to the Wasson Willard Royalty.
"Royalty Production" for the Wasson Willard Royalty is defined as 6.8355% of the lesser of (i) the actual number of gross barrels of oil produced for such quarter from the Wasson Willard Unit and (ii) the applicable maximum quarterly gross production limitation set forth in the table below. The table also shows the maximum number of barrels of Royalty Production that may be produced per quarter in respect of the Wasson Willard Royalty (6.8355% of the quarterly gross production limitation).
AVERAGE PER BARREL PRICE. The "Average Per Barrel Price" with respect to the Wasson Royalties for any calendar quarter generally means (a) the aggregate revenues received by Devon for such quarter from the sale of oil production from its royalty interest in the Wasson Field production unit to which the particular Wasson Royalty relates less certain actual costs for such quarter which consist of post-production costs (including gathering, transporting, separating, processing, treatment, storing and marketing charges), costs of litigation concerning title to or operations of the Wasson Royalties, severance taxes, ad valorem taxes, excise taxes (including windfall profits taxes, if any), sales taxes and other similar taxes imposed upon the reserves or upon production, delivery or sale of such production, costs of audits, insurance premiums and amounts reserved for the foregoing, divided by (b) the aggregate number of barrels produced for such quarter from its royalty interest in the Wasson Field production unit to which the particular Wasson Royalty relates.
THE NET PROFITS ROYALTIES
The Net Profits Royalties entitle the Trust to receive, on a quarterly basis, 90% of the Net Proceeds (as defined in the Net Profits Conveyances) from the sale of production from the Net Profits Properties. The Net Profits Royalties are not limited in term, although under the Trust Agreement the Trustee is directed to sell the Net Profits Royalties prior to the Liquidation Date. The definitions, formulas, accounting procedures and other terms governing the computation of Net Proceeds are detailed and extensive, and reference is made to the Net Profits Conveyances and the Louisiana Conveyance for a more detailed discussion of the computation thereof.
CALCULATION OF NET PROCEEDS. "Net Proceeds" generally means, for any calendar quarter, (a) with respect to Net Profits Properties that are conveyed from working interests, the excess of Gross Proceeds (as defined below) over all costs, expenses and liabilities incurred in connection with exploring, prospecting and drilling for, operating, producing, selling and marketing oil and gas, including, without limitation, all amounts paid as royalties, overriding royalties, production payments or other burdens against production pursuant to permitted encumbrances, delay rentals, payments in connection with the drilling or deferring of drilling of any well in the vicinity, adjustment payments to others in connection with contributions upon pooling, unitization or communitization, rent for use of or damage to the surface, costs under any joint operating unit or similar agreement, costs incurred with respect to reworking, drilling, equipping, plugging back, completing and recompleting wells, making production ready or available for market, constructing production and delivery facilities, producing, transporting, compressing, dehydrating, separating, treating, storing and marketing production, secondary or tertiary recovery or other operations conducted for the purpose of enhancing production, litigation concerning title to or operation of the working interests, renewals and extensions of leases, and taxes, and (b) with respect to Net Profits Properties that are conveyed from royalty interests, the excess of Gross Proceeds over all costs, expenses and liabilities incurred in making production available or ready for market, including, without limitation, costs paid for gathering, transporting, compressing, dehydrating, separating, treating, storing and marketing oil and gas, litigation concerning title to or operation of royalty interests, taxes, costs of audits and insurance premiums.
"Gross Proceeds" generally means, for any calendar quarter, the amount of cash received by Devon during such quarter from the sales of oil and gas produced from the Net Profits Properties excluding (a) all amounts attributable to nonconsent operations conducted with respect to any working interest in which Devon or its assignee is a nonconsenting party and which is dedicated to the recoupment or reimbursement of penalties, costs and expenses of the consenting parties, (b) damages arising from any cause other than drainage or reservoir injury, (c) rental for reservoir use, (d) payments in connection with the drilling of any well on or in the vicinity of the Net Profits Properties and (e) all amounts set aside as reserved amounts. Gross Proceeds will not include (x) consideration for the transfer or sale of the Net Profits Properties (except as provided below under "Description of the Trust--Support Payments") or (y) any amount not received for oil and gas lost in the production or
marketing thereof or used by the owner of the Net Profits Properties in drilling, production and plant operations. Gross Proceeds includes payments for future production to the extent they are not subject to repayment in the event of insufficient subsequent production.
If a dispute arises as to the correct or lawful sales prices of any oil or gas produced from any of the Net Profits Properties, then for purposes of determining whether the amounts have been received by the owner of the Net Profits Properties and therefore constitute Gross Proceeds (a) the amounts withheld by a purchaser and deposited with an escrow agent shall not be considered to be received by the owner of the Net Profits Properties until actually collected, (b) amounts received by the owner of the Net Profits Properties and promptly deposited with a non-affiliated escrow agent will not be considered to have been received until disbursed to it by such escrow agent and (c) amounts received by the owner of the Net Profits Properties and not deposited with an escrow agent will be considered to have been received.
The Trust is not liable to the owners or operators of the Net Profits Properties for any operating, capital or other costs or liabilities attributable to the Net Profits Properties or oil and gas produced therefrom, and the Trustee is not obligated to return any income received from the Net Profits Royalties. Overpayments to the Trust will reduce future amounts payable.
SUPPORT PAYMENTS
The Wasson Conveyance provides that the Trust is entitled to additional quarterly royalty payments ("Support Payments"), subject to certain limitations herein described, out of Devon's remaining royalty interests in the Wasson ODC Unit during the period ending on December 31, 2002 (the "Support Period") in the event that the net cash available for distribution to Holders from the Royalty Interests for any calendar quarter during the Support Period is less than an amount sufficient to distribute to Holders a minimum supported quarterly royalty per Depositary Unit equal to $0.39 per Depositary Unit (the "Minimum Quarterly Royalty"). Effective July 1, 1999 and as required by the Trust Agreement, the Trust released its Net Profits Royalty interest in the Jeffress field in connection with the sale by Devon of the underlying Net Profits Property. The Trust received 90% of the net proceeds from this sale in the fourth quarter 1999 distribution. As a result of this sale, there was a proportionate reduction of the Minimum Quarterly Royalty from $0.40 per Depositary Unit to $0.39 per Depositary Unit. Distributions paid in 1994, 1995, 1998 and 1999 included Support Payments of $868,000 (approximately $0.14 per Depositary Unit), $1,206,000 (approximately $0.19 per Depositary Unit), $94,000 (approximately $0.01 per Depositary Unit), and $2,011,000 (approximately $0.32 per Depositary Unit), respectively. The Support Payments paid in 1994 were required primarily due to lower realized oil prices and capital expenditures incurred with respect to the Net Profits Properties, a substantial portion of which related to the drilling of new wells. The Support Payments paid in 1995 were required primarily due to lower natural gas prices and a continuation of drilling expenditures. The Support Payments paid in 1998 and 1999 were required primarily due to lower oil and gas prices realized on the Net Profits Properties. In 1996, the first six months of 1997, the fourth quarter of 1999, and the first quarter of 2000, Devon recouped Support Payments made in prior periods totalling $1,009,000 (approximately $0.16 per Depositary Unit), $1,065,000 (approximately $0.17 per Depositary Unit), $1,831,000 (approximately $0.29 per Depositary Unit), and $275,000 (approximately $0.04 per Depositary Unit), respectively (see "--Reduction of Royalty Interests"). Future recoupments will be made only to the extent of future Support Payments. Depending on factors such as sales prices and volumes and the level of operating costs and capital expenditures, Support Payments may be required in subsequent quarters to allow the Trust to make distributions of $0.39 per Depositary Unit per quarter.
CALCULATION OF AMOUNT OF SUPPORT PAYMENT. Support Payments payable to the Trust for any calendar quarter during the Support Period shall be equal to the additional amount necessary to cause the Minimum Quarterly Royalty for such quarter to be paid by the Trust in respect of all outstanding
Trust Units; provided, that the aggregate amount of Support Payments, net of any amounts recouped by Devon pursuant to reductions in the royalties payable with respect to the Royalty Interests as described below, will be limited to $19.4 million (the "Aggregate Support Payment Limitation Amount"), as such amount may be replenished upon recoupment of certain amounts as described in the following paragraph. As a result of the Trust's release of its Net Profits Royalty interest in connection with the sale by Devon of the Jeffress Field in the fourth quarter of 1999, there was a proportionate reduction in the Aggregate Support Payment Limitation Amount from $20.0 million to $19.4 million.
REDUCTION OF ROYALTY INTERESTS. In the event Support Payments are paid to the Trust for any quarter, the royalties payable with respect to the Wasson Royalties will be reduced in future quarters (including quarters after the Support Period but prior to the Liquidation Date) after the Trust has received (or amounts are set aside for payment of) proceeds from all of the Royalty Interests in amounts sufficient to pay 112.5% of the Minimum Quarterly Royalty ($0.44 per Depositary Unit) on all Trust Units outstanding at the end of such quarter in order to permit Devon to recoup the aggregate amount of the Support Payments. As a result of the Trust's release of its Net Profits Royalty interest in connection with the sale by Devon of the Jeffress Field in the fourth quarter of 1999, there was a proportionate reduction in the distribution per Depositary Unit over which Devon is entitled to recoup Support Payments from $0.45 per Depositary Unit to $0.44 per Depositary Unit. Any such reduction in royalties payable with respect to the Royalty Interests would be made first to the Wasson ODC Royalty and then, if additional reductions are necessary, from the Wasson Willard Royalty. The effect of such reductions in the royalties payable with respect to the Wasson Royalties would be to eliminate distributions in excess of $0.44 per Depositary Unit until the Support Payments, if any, received by the Trust have been recouped by Devon through such reductions in the Wasson Royalties.
PROPORTIONATE REDUCTION OF MINIMUM QUARTERLY ROYALTY AND AGGREGATE SUPPORT PAYMENT LIMITATION AMOUNT UPON CERTAIN SALES. In the event that Devon causes the Trust to sell or release a portion of the Net Profits Royalties in connection with the sale by Devon of underlying Net Profits Properties, the Minimum Quarterly Royalty and the Aggregate Support Payment Limitation Amount will be adjusted proportionately downward to equal the product resulting from multiplying each of the Minimum Quarterly Royalty and the Aggregate Support Payment Limitation Amount by a fraction, the numerator of which will be the Remaining Royalty Interests Amount (as defined below) and the denominator of which will be the Existing Royalty Interests Amount (as defined below). For such purposes, the "Remaining Royalty Interests Amount" means, at any time, the Existing Royalty Interests Amount (as defined below) less the present value of the future net revenues attributable to the portion of the Net Profits Royalties sold or released by the Trust, determined by reference to the reserve report for the Royalty Properties prepared in accordance with guidelines of the Securities and Exchange Commission (the "Commission") as of the December 31 immediately preceding the date of the sale. The "Existing Royalty Interests Amount" means, at any time, the then present value of the future net revenues attributable to the Royalty Interests (including the portion sold or released by the Trust), determined by reference to the reserve report for the Royalty Properties prepared in accordance with Commission guidelines as of the December 31 immediately preceding the date of the sale. Following any such sale of Net Profits Royalties, the Trustee will notify the Holders of the adjusted Minimum Quarterly Royalty and the adjusted Aggregate Support Payment Limitation Amount.
OTHER MATTERS
Payments to the Trust are attributable to the sale of depleting assets. Thus, the reserves attributable to the Royalty Properties are expected to decline over time. Based on the estimated production volumes in the Reserve Report (hereinafter defined), on a barrel of oil equivalent basis, the oil and gas production from proved reserves attributable to the Trust in the year preceding the Liquidation Date is expected to be approximately 49% of the oil and gas production attributable to the Trust in 2000.
Under the terms of the Conveyances, neither the Trustee, the Trust nor the Holders will be able to influence or control the operation or future development of the Royalty Properties. Devon operates only a small number of the Royalty Properties and is not expected to be able to significantly influence the operations or future development of the Royalty Properties that are royalty interests or that consist of relatively small working interests. Such operations will generally be controlled by persons unaffiliated with the Trustee and Devon. Devon, however, owns working interests in the Wasson ODC Unit and the Wasson Willard Unit and may be able to exercise some influence, though not control, over unit operations.
The tertiary recovery operations in the Wasson Field have required substantial capital expenditures and will involve future capital expenditures for CO2 acquisition, particularly in the Wasson Willard Unit. A prolonged oil price downturn could cause the operators in the Wasson Field to reassess the economic viability of production operations notwithstanding their substantial investment. Such decisions will not be in the control of either Devon or the Trustee and could have the effect of substantially reducing expected production from the Wasson Field.
The current operators of the Royalty Properties are under no obligation to continue operating such properties, and neither the Trustee, the Holders nor Devon will be able to appoint or control the appointment of replacement operators. The operators of the Net Profits Properties and any transferee have the right to abandon any well or property on a Net Profits Property, if, in their opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities, and upon termination of any such lease that portion of the Net Profits Royalties relating thereto will be extinguished.
The Trust Agreement provides that Devon may sell the Royalty Properties, subject to and burdened by the Royalty Interests, without the consent of the Holders. In addition, Devon may, without the consent of the Holders, require the Trust to release up to $5 million of the Net Profit Royalties in any 12-month period (limited to $15 million in the aggregate for all sales prior to January 1, 2002) in connection with a sale of the Net Profits Properties provided that the Trust receives an amount equal to 90% of the net proceeds received by Devon with respect to the Net Profits Properties sold and such cash price represents the fair market value of such properties (which fair market value for sales in excess of $500,000 will be determined by independent appraisal). Such sales can be required of the Trust without regard to any dollar limitation on and after December 31, 2005. Any net sales proceeds paid to the Trust are distributable to Holders for the quarter in which such proceeds are received. Pursuant to the Trust Agreement, the Trust may not sell the Wasson ODC Royalty or the Wasson Willard Royalty without the consent of Devon. Under the Trust Agreement, Devon has a right of first refusal to purchase any of the Royalty Interests at fair market value, or if applicable the offered third- party price, prior to the Liquidation Date.
The Trust has no employees. Administrative functions of the Trust are performed by the Trustee.
DESCRIPTION OF THE TRUST UNITS AND DEPOSITARY UNITS
The following information is subject to the detailed provisions of the Custodial Deposit Agreement entered into by Devon, the Trustee, the Depositary and all holders from time to time of SPERs (the "Deposit Agreement"), which is an exhibit to this Form 10-K and is available upon request from the Trustee.
The functions of the Depositary under the Deposit Agreement are custodial and ministerial in nature and for the benefit of Holders. The Deposit Agreement and the issuance of SPERs thereunder provide Holders an administratively convenient form of holding an investment in the Trust and a Treasury Obligation. Each Depositary Unit is evidenced by a SPER, which is issued by the Depositary and transferable only in denominations of 50 Depositary Units or an integral multiple thereof. Accordingly, each Holder of 50 Depositary Units owns a beneficial interest in 50 Trust Units and the
entire beneficial interest in a discrete Treasury Obligation in a face amount of $1,000, or $20 per Depositary Unit.
The deposited Trust Units and Treasury Obligations are held solely for the benefit of the Holders and do not constitute assets of the Depositary or the Trust. The Depositary has no power to assign, transfer, pledge or otherwise dispose of any of the Trust Units or Treasury Obligations, except as described under "Possible Divestiture of Depositary Units and Trust Units".
Generally, the Depositary Units are entitled to participate in distributions with respect to the Trust Units and such distributions with respect to the Treasury Obligations and the liquidation of the remaining assets of the Trust.
Upon the written request of a Holder for withdrawal of Trust Units and Treasury Obligations evidenced by SPERs in denominations of 50 Depositary Units or an integral multiple thereof from deposit and the surrender of such Holder's SPER in compliance with the terms of the Deposit Agreement, the Holder surrendering such Depositary Units will be entitled to receive the underlying Trust Units, which will be uncertificated, and whole Treasury Obligation as described herein. These withdrawn Trust Units will be evidenced on the books of the Trustee by a transfer of such Trust Units from the name of the Depositary to the name of the withdrawing Holder. Holders of withdrawn Trust Units will be entitled to receive Trust distributions and periodic Trust information (including tax information) directly from the Trustee. Due to the accreting nature of the value of the zero coupon Treasury Obligations, the withdrawal and sale of a Treasury Obligation underlying Depositary Units prior to its maturity will result in the Holder receiving less than the face value for its Treasury Obligation investment. The amount a withdrawing Holder may receive from the sale of a Treasury Obligation prior to its maturity will be affected by such factors as then current interest rates and the small size of the Treasury Obligation relative to typical trades in the secondary market for United States Treasury obligations (which may result in a discount to quoted market values).
Pursuant to the Trust Agreement and the related transfer application, withdrawn Trust Units are not transferable except by operation of law. A holder of withdrawn Trust Units may, however, transfer such Trust Units in denominations of 50 (or an integral multiple thereof) to the Depositary for redeposit, together with Treasury Obligations in the face amount equal to $1,000 for each 50 Trust Units redeposited, in exchange for Depositary Units. Such redeposit may be effected by delivering written notice of such transfer jointly to the Depositary and the Trustee together with proper documentation necessary to transfer the requisite Treasury Obligations into the name of the Depositary.
DISTRIBUTIONS
The Trustee determines for each calendar quarter during the term of the Trust the amount of cash available for distribution to holders of Depositary Units and the Trust Units evidenced thereby. Such amount (the "Quarterly Distribution Amount") is equal to the excess, if any, of the cash received by the Trust from the Royalty Interests then held by the Trust during such quarter, plus any other cash receipts of the Trust during such quarter, over the liabilities of the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for the payments of contingent or future obligations of the Trust. Based on industry practice and the payment procedures relating to the Net Profits Royalties, cash received by the Trustee in a particular quarter from the Net Profits Royalties generally represents proceeds from sales of production for the three months ending two months prior to the end of such quarter with respect to gas, and one month prior to the end of such quarter with respect to oil. For example, the royalty income received by the Trust for the third calendar quarter with respect to gas is attributable to production in the months of May, June and July (for which Devon would have received payment from the purchasers in July, August and September, respectively). Since proceeds from the sale of production from the Wasson Properties are received within one month of production, payments in respect of the Wasson Royalties
are made for production from the calendar quarter to which the Quarterly Distribution Amount relates. The Quarterly Distribution Amount for each quarter is payable to Holders of Depositary Units of record on the 45th day following each calendar quarter (or the next succeeding business day following such day if such day is not a business day) or such later date as the Trustee determines is required to comply with legal or stock exchange requirements (the "Quarterly Record Date"). The Trustee distributes cash to the Holders within two months after the end of each calendar quarter to each person who was a Holder of Depositary Units of record on a Quarterly Record Date.
The net taxable income of the Trust for each calendar quarter is reported by the Trustee for tax purposes as belonging to the Holders of record to whom the Quarterly Distribution Amount is distributed. Because under current tax law the Trust is classified for tax purposes as a "grantor trust" (see "Federal Income Tax Matters"), each cash-basis Holder's share of the net taxable income of the Trust is realized by such Holder for tax purposes in the calendar quarter received by the Trustee, rather than in the quarter distributed by the Trustee. Taxable income of a Holder may differ from the Quarterly Distribution Amount because the Treasury Obligations are treated as generating interest income prior to the time any cash payments are received thereon, a portion of the payments received on the Wasson Royalties are treated as a nontaxable return of principal, and cost depletion reduces taxable income but not the Quarterly Distribution Amount. There may also be minor variances because of the possibility that, for example, a reserve will be established in one quarter that will not give rise to a tax deduction until a subsequent quarter, an expenditure paid for in one quarter will have to be amortized for tax purposes over several quarters, etc. See "Federal Income Tax Matters."
Each Holder of Depositary Units (including the underlying Trust Units) of record as of the business day next preceding the Liquidation Date will be entitled to receive a liquidating distribution equal to a pro rata portion of the net proceeds from the sale of the Net Profits Royalties (to the extent not previously distributed) and a pro rata portion of the proceeds from the matured Treasury Obligations.
POSSIBLE DIVESTITURE OF DEPOSITARY UNITS AND TRUST UNITS
The Trust Agreement imposes no restrictions based on nationality or other status of holders of Trust Units. However, the Trust Agreement and the Deposit Agreement provide that in the event of certain judicial or administrative proceedings seeking the cancellation or forfeiture of any property in which the Trust has an interest because of the nationality, citizenship, or any other status, of any one or more holders of Trust Units including Holders of Depositary Units, the Trustee will give written notice thereof to each holder whose nationality, citizenship or other status is an issue in the proceeding, which notice will constitute a demand that such holder dispose of his Depositary Units or withdrawn Trust Units within 30 days. If any holder fails to dispose of his Depositary Units or withdrawn Trust Units in accordance with such notice, cash distributions on such units are subject to suspension. In the event a holder fails to dispose of Depositary Units in accordance with such notice, the Depositary may cancel such holder's Depositary Units and reissue them in the name of the Trustee, whereupon the Trustee will use its reasonable efforts to sell the Depositary Units and remit the net sale proceeds to such holder. In the case of Trust Units withdrawn from deposit with the Depositary, the Trustee shall redeem such Trust Units not divested in accordance with such notice, for a cash price equal to the then-current market price of the Depositary Units less the then-current, over-the-counter bid price of the related, withdrawn Treasury Obligations. The redemption price will be paid out in quarterly installments limited to the amount that otherwise would have been distributed in respect of such redeemed Trust Units.
LIABILITY OF HOLDERS
The Trust is intended to be classified as an "express trust" under Texas law and thus subject to the Texas Trust Code. Under the Texas Trust Code, a trust beneficiary will not be held personally liable for
obligations incurred by the Trust except in limited circumstances principally related to wrongful conduct by the trust beneficiary. It is unclear whether the Trust constitutes an "express trust" under the Texas Trust Code. If the Trust were held not to be an express trust, a Holder could be jointly and severally liable for any liability of the Trust in the event that (i) the satisfaction of such liability was not by contract limited to the assets of the Trust and (ii) the assets of the Trust were insufficient to discharge such liability. Examples of such liability would include liabilities arising under environmental laws and damages arising from product liability and personal injury in connection with the Trust's business. Each Holder should weigh this potential exposure in deciding whether to retain or transfer his Trust Units.
LIQUIDATION OF THE TRUST
The Trust will be liquidated and the Net Profits Royalties will be sold on or prior to the Liquidation Date. Holders of record as of the business day next proceeding the Liquidation Date will be entitled to receive a terminating distribution with respect to each Depositary Unit equal to a pro rata portion of the net proceeds from the sale of the Net Profits Royalties (to the extent not previously distributed) and a pro rata portion of the proceeds from the matured Treasury Obligations. Under the Trust Agreement, Devon has a right of first refusal to purchase any of the Royalty Interests at fair market value, or if applicable, the offered third-party price, prior to the Liquidation Date.
FEDERAL INCOME TAX MATTERS
This section is a summary of Federal income tax matters of general application which addresses all material tax consequences of the ownership and sale of Depositary Units. Except where indicated, the discussion below describes general Federal income tax considerations applicable to individuals who are citizens or residents of the United States. Accordingly, the following discussion has limited application to domestic corporations and persons subject to specialized Federal income tax treatment, such as tax-exempt entities, regulated investment companies and insurance companies. The following discussion does not address tax consequences to foreign persons. It is impractical to comment on all aspects of Federal, state, local and foreign laws that may affect the tax consequences of the transactions contemplated hereby and of an investment in Depositary Units as they relate to the particular circumstances of every Holder. EACH HOLDER SHOULD CONSULT HIS OWN TAX ADVISOR WITH RESPECT TO HIS PARTICULAR CIRCUMSTANCES.
This summary is based on current provisions of the Internal Revenue Code of 1986, as amended (the Code), existing and proposed regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the Code have not been interpreted by the courts or the Internal Revenue Service (IRS).
No ruling has been or will be requested from the IRS with respect to any matter affecting the Trust or Holders, and thus no assurance can be provided that the statements set forth herein (which do not bind the IRS or the courts) will not be challenged by the IRS or will be sustained by a court if so challenged.
TREATMENT OF DEPOSITARY UNITS
Under current law, a purchaser of a Depositary Unit is treated, for Federal income tax purposes, as purchasing directly an interest in the Treasury Obligations and the assets of the Trust. A purchaser is therefore required to allocate the purchase price of his Depositary Unit between the interest in the Treasury Obligations and the assets of the Trust in the proportion that the fair market value of each bears to the fair market value of the Depositary Unit. Information regarding purchase price allocations is furnished to Holders by the Trustee.
CLASSIFICATION AND TAXATION OF THE TRUST
Under current law, the Trust is classified for federal income tax purposes as a grantor trust. As a grantor trust, the Trust is not subject to tax. For tax purposes, Holders are considered to own and receive the Trust's income and principal directly as though no trust were in existence. The Trust files an information return, reporting all items of income, credit or deduction which must be included in the tax returns of Holders.
DIRECT TAXATION OF HOLDERS
Because under current law the Trust is treated as a grantor trust for Federal income tax purposes and each Holder is treated, for Federal income tax purposes, as owning a direct interest in the Treasury Obligations and the assets of the Trust, each Holder is taxed directly on his pro rata share of the income attributable to the Treasury Obligations and the assets of the Trust and is entitled to claim his pro rata share of the deductions attributable to the Trust (subject to certain limitations discussed below). Income and expenses attributable to the assets of the Trust and the Treasury Obligations are taken into account by Holders consistent with their method of accounting and without regard to the taxable year or accounting method employed by the Trust.
The Trust makes quarterly distributions to Holders of record on each Quarterly Record Date. The terms of the Trust Agreement seek to assure to the extent practicable that taxable income attributable to such distributions is reported by the Holder who receives such distributions, assuming that he is the owner of record on the Quarterly Record Date. In certain circumstances, however, a Holder may not receive the distribution attributable to such income. For example, if the Trustee establishes a reserve or borrows money to satisfy debts and liabilities of the Trust, income associated with the cash used to establish that reserve or to repay that loan must be reported by the Holder on his tax return even though that cash is not distributed to him. In addition, Holders are required to recognize certain interest income attributable to the Treasury Obligations even though such interest is not paid currently to the Holders.
The Trust allocates income and deductions to Holders based on record ownership at Quarterly Record Dates. Such allocation method is intended to cause the taxable income of the Trust to be reported by those persons who are Holders of record on the Quarterly Record Date for such quarter and, as a result receive the distributions for such quarter. It is unknown whether the IRS will accept that allocation or will require income and deductions of the Trust to be determined and allocated daily or require some method of proration. If the IRS were successful in seeking that the Trust utilize a different method of allocating taxable income, Trust income might in certain cases be taxed to Holders other than those who received the distribution relating to such income, and the Trust might incur additional administrative expenses in complying with such method of allocation.
TREATMENT OF TRUST UNITS
Because the Trust is treated as a grantor trust for tax purposes, each Holder is treated as purchasing and owning directly an interest in the Royalty Interests. The purchaser of a Depositary Unit is required to allocate the portion of his total purchase price allocated to the Trust Unit among the Royalty Interests in the proportion that the fair market value of each of the Royalty Interests bears to the total fair market value of all of the Royalty Interests. For purposes of making this allocation, the Royalty Interests include the Wasson ODC Royalty, the Wasson Willard Royalty and the Net Profits Royalties. Information regarding purchase price allocations is furnished to Holders by the Trustee.
INTEREST INCOME
Based on representations made by Devon regarding the reserves burdened by the Wasson Royalties and the expected life of the Wasson Royalties, the Wasson Royalties are properly treated as
"production payments" under Section 636(a) of the Code. Under the rules of such Code section, each Holder is treated as making a mortgage loan on the Wasson Properties to Devon in an amount equal to the amount of the purchase price of each Depositary Unit allocated to the Wasson Royalties. Because production payments are treated as debt instruments for tax purposes, the Wasson Royalties are subject to the Original Issue Discount (OID) rules of Sections 1272 through 1275 of the Code. Section 1272 generally requires the periodic inclusion of original issue discount in income of the purchaser of a debt instrument. Section 1275 provides special rules and authorizes the IRS to prescribe regulations modifying the statutory provisions where, by reason of contingent payments, the tax treatment provided under the statutory provisions does not carry out the purposes of such provisions. Proposed regulations dealing with contingent payments were issued in 1986 and modified in 1991 (the "Original Proposed Regulations"). During December 1994, the IRS replaced the Original Proposed Regulations with new proposed regulations and, during June 1996, the IRS redesignated the 1994 proposed regulations as final regulations (the "New Regulations"). However, the New Regulations are by their terms applicable only to debt instruments that are issued on or after August 13, 1996. The New Regulations further provide, in the case of a contingent debt instrument issued before August 13, 1996, that a taxpayer may use any reasonable method to account for the debt instrument, including a method that would have been required under the proposed regulations when the debt instrument was issued. Because the Original Proposed Regulations were in effect when the Wasson Royalties were issued to the Trust, the tax treatment of the Wasson Royalties has been reported to the Holders under the provisions of the Original Proposed Regulations.
Under the rules set forth in the Original Proposed Regulations, each payment (at the time the amount of such payment becomes fixed) made to the Trust with respect to the Wasson Royalties is treated first as consisting of a payment of interest to the extent of interest deemed accrued under the OID rules (based on the long term Applicable Federal Rate in effect at the time the amount of such payment becomes fixed) and the excess (if any) is treated as a payment of principal. The total amount treated as principal is limited to the amount of the purchase price of each Depositary Unit allocated to the Wasson Royalties.
Holders are also required to recognize and report OID interest income attributable to the Treasury Obligations. In general, the total amount of OID interest income a Holder is required to recognize over the term of the Treasury Obligations is calculated as the difference between the amount of the purchase price of a Depositary Unit allocated to the Treasury Obligations and the pro rata portion of the face amount of such Treasury Obligations attributable to the Depositary Unit. The portion of OID interest income so calculated which is required to be included in income by a Holder for any particular period is generally determined by multiplying the Holder's adjusted issue price in the Treasury Obligations by the yield to maturity of the Treasury Obligations.
ROYALTY INCOME AND DEPLETION
The income from the Net Profits Royalties is royalty income subject to an allowance for depletion. The depletion allowance must be computed separately by each Holder for each oil or gas property (within the meaning of Code Section 614). The IRS presently takes the position that a net profits interest carved out of multiple properties is a single property for depletion purposes. Accordingly, the Trust has taken the position that the Net Profits Royalties are a single property for depletion purposes until such time as the issue is resolved in some other manner.
The allowance for depletion with respect to a property is determined annually and is the greater of cost depletion or, if allowable, percentage depletion. Percentage depletion is generally available to "independent producers" (generally persons who are not substantial refiners or retailers of oil or gas or their primary products) on the equivalent of 1,000 barrels of production per day. Percentage depletion is a statutory allowance generally equal to 15% of the gross income from production from a property, subject to a net income limitation which is 100% of the taxable income from the property, computed
without regard to depletion deductions and certain loss carrybacks. For tax years beginning after December 31, 1997, and before January 1, 2002, the 100% of taxable income limitation on percentage depletion does not apply to "marginal production." Additionally, the percentage depletion rate for "marginal production" is adjusted annually and is generally greater than 15%. Marginal production includes (i) "stripper well property," generally defined as a domestic crude oil or natural gas property producing 15 barrel equivalents or less per day per well, and (ii) "heavy oil," generally defined as domestic crude oil produced from any property if such crude oil had a weighted average gravity of 20 degrees API or less. The depletion deduction attributable to percentage depletion for a taxable year is limited to 65% of the taxpayer's taxable income for the year before allowance of "independent producers" percentage depletion and certain loss carrybacks. Unlike cost depletion, percentage depletion is not limited to the adjusted tax basis of the property, although it reduces such adjusted tax basis (but not below zero).
In computing cost depletion for each property for any year, the adjusted tax basis of that property at the beginning of that year is divided by the estimated total units (Bbls of oil or Mcf of gas) recoverable from that property to determine the per-unit allowance for such property. The per-unit allowance is then multiplied by the number of units produced and sold from that property during the year. Cost depletion for a property cannot exceed the adjusted tax basis of such property. Since the Trust is taxed as a grantor trust, each Holder computes cost depletion using his basis in his Trust Units allocated to the Net Profits Royalties. Information is provided to each Holder reflecting how that basis should be allocated among each property represented by his Trust Units.
OTHER INCOME AND EXPENSES
The Trust may generate some interest income on funds held as a reserve or held until the next distribution date. Expenses of the Trust include administrative expenses of the Trustee. Under the Code, certain miscellaneous itemized deductions of an individual taxpayer are deductible only to the extent that in the aggregate they exceed 2% of the taxpayer's adjusted gross income. Certain administrative expenses attributable to the Trust Units may have to be aggregated with an individual Holder's other miscellaneous itemized deductions to determine the excess over 2% of adjusted gross income. The amount of such expenses has not been, and is not expected to be, significant in relation to the Trust's income.
NON-PASSIVE ACTIVITY INCOME AND LOSS
The income and expenses of the Trust are not taken into account in computing passive activity losses and income under Code Section 469 for a Holder who acquires and holds Depositary Units as an investment.
UNRELATED BUSINESS TAXABLE INCOME
Certain organizations that are generally exempt from tax under Code Section 501 are subject to tax on certain types of business income defined in Code Section 512 as unrelated business income. The income of the Trust will not constitute unrelated business taxable income within the meaning of Code Section 512 so long as the Trust Units are not "debt-financed property" within the meaning of Code Section 514(b). In general, a Trust Unit would be debt-financed if the Holder incurs debt to acquire a Trust Unit or otherwise incurs or maintains a debt that would not have been incurred or maintained if such Trust Unit had not been acquired.
SALE OF DEPOSITARY UNITS
Generally, a Holder will realize gain or loss on the sale or exchange of his Depositary Units measured by the difference between the amount realized on the sale or exchange and his adjusted basis for such Depositary Units. Gain or loss on the sale of Depositary Units by a Holder who is not a dealer with respect to such Depositary Units and who has a holding period for the Depositary Units of more than one year may be eligible for lower capital gains rate, except to the extent of the depletion recapture amount (as described below). Capital gains of each noncorporate Holder arising from a sale of Depository Units generally are currently subject to tax at a rate of 20% (10% if the noncorporate Holder is in the 15% tax bracket) if such Depository Units have been held for more than 12 months. If a noncorporate Holder has held the Depository Units for 12 months or less, any such capital gain recognized on the sale of such Depository Units will be subject to tax at ordinary income tax rates (of which the maximum rate is currently 39.6%).
For Federal income tax purposes, the sale of a Depositary Unit is treated as a sale by the Holder of his interest in the Treasury Obligations and the assets of the Trust. Thus, upon the sale of Depositary Units, a Holder must treat as ordinary income his depletion recapture amount, which is an amount equal to the lesser of (i) the gain on that sale attributable to disposition of the Net Profits Royalties or (ii) the sum of the prior depletion deductions taken with respect to the Net Profits Royalties (but not in excess of the initial basis of such Depositary Units allocated to the Net Profits Royalties). It is possible that the IRS would take the position that a portion of the sales proceeds is ordinary income to the extent of any accrued income at the time of sale allocable to the Depositary Units sold, but which has not been distributed to the selling Holder.
A Holder's initial basis in his Depositary Units is equal to the amount paid for such Depositary Units. Such basis is increased by the amount of any OID interest income recognized by the Holder attributable to the Treasury Obligations. Such basis is reduced by deductions for depletion claimed by the Holder (but not below zero). In addition, such basis is reduced by the amount of any payments attributable to the Wasson Royalties which are treated as payments of principal under the OID rules. A Holder's basis would also be increased by any increase in reserves retained by the Trust and would be reduced by any reduction in such reserves.
SALE OF NET PROFITS ROYALTIES
In certain circumstances, Devon may cause the Trustee, without the consent of the Holders, to release a portion of the Net Profits Royalties in connection with a sale by Devon of the underlying Net Profits Properties. Additionally, the assets of the Trust, including the Net Profits Royalties, will be sold by the Trustee prior to the Liquidation Date in anticipation of the termination of the Trust. A sale by the Trust of Net Profits Royalties will be treated for Federal income tax purposes as a sale of Net Profits Royalties by a Holder. Thus, a Holder will recognize gain or loss on a sale of Net Profits Royalties by the Trust. A portion of that income may be treated as ordinary income to the extent of depletion recapture. See "Sale of Depositary Units," above.
BACKUP WITHHOLDING
In general, distributions of Trust income are not subject to "backup withholding" unless: (i) the Holder is an individual or other noncorporate taxpayer and (ii) such Holder fails to furnish and certify as to the correctness of his taxpayer identification number (which for an individual, would be such individual's social security number) or such Holder fails to comply with certain reporting procedures.
TAX SHELTER REGISTRATION
The Trust is registered as a tax shelter with the IRS, as required by Code Section 6111. The Trust's tax shelter registration number is 92322000636.
A Holder who sells or otherwise transfers a Trust Unit in a subsequent transaction must furnish the tax shelter registration number to the transferee. The penalty for failure of the transferor of a Trust Unit to furnish such tax shelter registration number to a transferee is $100 for each such failure. Holders must disclose the tax shelter registration number of the Trust on IRS Form 8271 which is required to be attached to each tax return on which any deduction, loss, credit or other benefit generated by the Trust is claimed or income of the Trust is included. A Holder who fails to disclose the tax shelter registration number on his return, without reasonable cause for such failure, will be subject to a $250 penalty for each such failure. (Any penalties discussed herein are not deductible for income tax purposes.)
ISSUANCE OF A TAX SHELTER REGISTRATION NUMBER DOES NOT INDICATE THAT AN INVESTMENT IN DEPOSITARY UNITS OR TRUST UNITS OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS.
ERISA CONSIDERATIONS
The Employee Retirement Income Security Act of 1974, as amended ("ERISA"), imposes certain requirements on pension, profit-sharing and other employee benefit plans ("Plans") to which it applies, and contains standards on those persons who are fiduciaries with respect to such Plans. In addition, under the Code, there are similar requirements and standards which are applicable to certain Plans and individual retirement accounts (whether or not subject to ERISA) (collectively, together with Plans subject to ERISA, referred to herein as Qualified Plans).
A fiduciary of a Qualified Plan should carefully consider fiduciary standards under ERISA regarding the Plan's particular circumstances before authorizing an investment in Trust Units. A fiduciary should first consider (i) whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA, (ii) whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA and (iii) whether the investment is in accordance with the documents and instruments governing the Plan as required by Section 404(a)(1)(D) of ERISA.
In order to avoid the application of certain penalties, a fiduciary must also consider whether the acquisition of Depositary Units representing Trust Units and/or operation of the Trust might result in direct or indirect nonexempt prohibited transactions under Section 406 of ERISA and Code Section 4975. In determining whether there are such prohibited transactions, a fiduciary must determine whether there are "plan assets" involved in the transaction. Department of Labor regulations ("the DOL Regulations") address whether or not a Qualified Plan's assets (such as a Depositary Unit) would be deemed to include an interest in the underlying assets of an entity (such as the Trust) for purposes of the reporting, disclosure and fiduciary responsibility provisions of ERISA and analogous provisions of the Code, if the Plan acquires an "equity interest" in such entity. The DOL Regulations provide that the underlying assets of an entity will not be considered "plan assets" if the interests in the entity are a publicly offered security. Trust Units represented by Depositary Units are considered to be "publicly offered" for this purpose if they are part of a class of securities that is (i) widely held (i.e., owned by more than 100 investors independent of the issuer and each other), (ii) freely transferable, and (iii) registered under Section 12(b) or 12(g) of the Exchange Act. Although no assurances can be given, it is believed that these requirements have been satisfied. Fiduciaries, however, will need to determine whether the acquisition of Depositary Units representing Trust Units is a nonexempt prohibited transaction under the general requirements of ERISA Section 406 and Code Section 4975.
Due to the complexity of the prohibited transaction rules and the penalties imposed upon persons involved in prohibited transactions, it is important that potential Qualified Plan investors consult with their counsel regarding the consequences under ERISA and the Code of their acquisition and ownership of Depositary Units.
STATE TAX CONSIDERATIONS
The following is intended as a brief summary of certain information regarding state income taxes and other state tax matters affecting individuals who are Holders. Holders are urged to consult their own legal and tax advisors with respect to these matters.
Each Holder should consider state and local tax consequences of an investment in Depositary Units. The Trust owns the Royalty Interests burdening oil and gas properties located in Alabama, Arkansas, California, Colorado, Kansas, Louisiana, Mississippi, New Mexico, North Dakota, Oklahoma, Texas and Wyoming. Of these, all but Texas and Wyoming have income taxes applicable to individuals. As stated, Texas currently has no individual income tax and the Reserve Report reflects that more than 50% of the estimated future net cash inflows generated by the Trust will be attributable to properties located in Texas. A Holder may be required to file state income tax returns and/or to pay taxes in those states imposing income taxes and may be subject to penalties for failure to comply with such requirements. Further, in some states the Trust may be taxed as a separate entity.
The Depositary currently provides information prepared by the Trustee concerning the Depositary Units sufficient to identify the income from Depositary Units that is allocable to each state. Holders of Depositary Units should consult their own tax advisors to determine their income tax filing requirements with respect to their share of income of the Trust allocable to states imposing an income tax on such income.
The Trust Units represented by Depositary Units may constitute real property or an interest in real property under the inheritance, estate and probate laws of some or all of the states listed above. If the Depositary Units are held to be real property or an interest in real property under the laws of a state in which the Royalty Properties are located, the holders of Depositary Units may be subject to devolution, probate and administration laws, and inheritance or estate and similar taxes under the laws of such state.
DESCRIPTION OF THE TREASURY OBLIGATIONS
The Treasury Obligations consist of a portfolio of interest coupons stripped from United States Treasury Bonds. All of the Treasury Obligations become due on the Liquidation Date in the aggregate face amount of $126,000,000, which amount equals $20 per outstanding Depositary Unit. The Treasury Obligations were purchased on behalf of the Depositary at a deep discount from face value at a price of $30.733 per hundred dollars, which was approximately the asked price on the over-the-counter U.S. Treasury market for such obligations on November 12, 1992 (after adjustment for five-day settlement). The Treasury Obligations were deposited with the Depositary on November 19, 1992 in connection with the initial public offering of Depositary Units.
The Treasury Obligations were issued under the Separate Trading of Registered Interest and Principal of Securities program of the U.S. Treasury, which permits the trading of the Treasury Obligations in book-entry form. The Treasury Obligations are held for the benefit of Holders in the name of the Depositary in book-entry form with a Federal Reserve Bank subject to withdrawal by a Holder. The deposited Treasury Obligations are not considered assets of the Depositary or the Trust. In the unlikely event of default by the U.S. Treasury in the payment of the Treasury Obligations when due, each Holder would have the right to withdraw a deposited Treasury Obligation in a face amount of $1,000 for each 50 Depositary Units and, as a real party in interest and as the owner of the entire beneficial interest in discrete Treasury Obligations, proceed directly and individually against the United States of America in whatever manner he deems appropriate without any requirement to act in concert with the Depositary, other Holders or any other person.
DESCRIPTION OF THE ROYALTY PROPERTIES
THE WASSON PROPERTIES
The Wasson Royalties were conveyed to the trust out of Devon's 12.3934% royalty interest in the Wasson ODC Unit and its 6.8355% royalty interest in the Wasson Willard Unit, located in the Wasson Field. Devon also owns working interests in each of these units. The Wasson Field has been significantly redeveloped for tertiary recovery operations utilizing CO2 flooding, which commenced in 1984. Most of the capital expenditures for plant, facilities, wells and equipment necessary for such tertiary recovery operations have been made, although ongoing capital expenditures for CO2 acquisition will be required to complete the flood of the Wasson Field, particularly the Wasson Willard Unit. The Wasson Royalties are not subject to development costs or operating costs (including CO2 acquisition costs).
The Wasson ODC Unit and the Wasson Willard Unit are production units formed by the various interest owners in the Wasson Field to facilitate development and production of certain geographically concentrated leases. The Wasson ODC Unit covers approximately 7,840 acres with approximately 315 producing wells and is operated by Altura Energy, Ltd. The Wasson Willard Unit covers approximately 13,520 acres with approximately 335 producing wells and is operated by a subsidiary of BP Amoco p.l.c. Production attributable to Devon's royalty interests in the Wasson ODC Unit and Wasson Willard Unit is marketed by Devon and in some cases is sold at the wellhead at market responsive prices that approximate spot oil prices for West Texas Sour crude, and in other cases is sold at points within common carrier pipeline systems on terms whereby Devon pays the cost of transporting same to such points. Devon may sell its royalty interests in the Wasson Field subject to and burdened by the Wasson Royalties, without the consent of the Trustee of the Trust or the Holders. The Wasson Royalties may not be sold by the Trust without the consent of Devon.
THE NET PROFITS PROPERTIES
The Royalty Properties burdened by the Net Profits Royalties consist of royalty and working interests in a diversified portfolio of producing properties located in established oil and gas producing areas in 12 states. Almost 89% of the discounted present value of estimated future net revenues attributable to the Net Profits Royalties is generated from Net Profits Properties located in Texas, Oklahoma and Louisiana and related state waters. Production attributable to the Net Profits Properties is principally sold at market responsive prices.
Devon owns the Net Profits Properties subject to and burdened by the Net Profits Royalties, and is entitled to proceeds attributable to its ownership interest in excess of 90% of the Net Proceeds paid to the Trust. Devon is required to receive payments representing the sale of production from the Net Profits Properties, deduct the costs described above and pay 90% of the net amount to the Trust. Devon may sell the Net Profits Properties subject to and burdened by the Net Profits Royalties. In addition, Devon may, subject to certain limitations, cause the Trust to release portions of the Net Profits Royalties in connection with the sale of the underlying Net Profits Properties.
Devon estimates that as of December 31, 2000, the Net Profits Properties covered approximately 243,000 gross acres (approximately 36,000 net to Devon). Productive well information generally is not made available by operators to owners of royalties and overriding royalties. Accordingly, such information is unavailable to Devon for the Net Profits Properties.
TITLE TO PROPERTIES
The Conveyances contain a warranty of title, limited to claims by, through or under Devon, and covering the Wasson Properties and certain of the Net Profits Properties. The Conveyances contain no title warranty with respect to the remaining Net Profits Properties. As is customary in the oil and gas
industry, Devon or the operator of its properties performs only a perfunctory title examination when it acquires leases, except leases covering proved reserves. Generally, prior to drilling a well, a more thorough title examination of the drill site tract is conducted and curative work is performed with respect to significant title defects, if any, before proceeding with operations. The Royalty Properties are typically subject, to one degree or another, to one or more of the following: (i) royalties and other burdens and obligations, expressed and implied, under oil and gas leases; (ii) overriding royalties (such as the Royalty Interests) and other burdens created by Devon or its predecessors in title; (iii) a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles; (iv) liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements; (v) pooling, unitization and communitization agreements, declarations and orders; and (vi) easements, restrictions, rights-of-way and other matters that commonly affect property. To the extent that such burdens and obligations affect Devon's rights to production and production revenues from the Royalty Properties, they have been taken into account in calculating the Royalty Interests and in estimating the size and value of the Trust's reserves attributable to the Royalty Interests.
It is not entirely clear that all of the Royalty Interests would be treated as fully conveyed real or personal property interests under the laws of each of the states in which the Royalty Properties are located. The Conveyances (other than the Louisiana Conveyance) state that the Royalty Interests constitute real property interests and Devon has recorded the Conveyances (other than the Louisiana Conveyance) in the appropriate real property records of the states in which the Royalty Properties are located in accordance with local recordation provisions. If during the term of the Trust, Devon becomes involved as a debtor in bankruptcy proceedings, it is not entirely clear that all of the Royalty Interests would be treated as fully conveyed property interests under the laws of each of the states in which the Royalty Properties are located. If in such a proceeding a determination were made that a Royalty Interest (or a portion thereof) did not constitute fully conveyed property interests under applicable state law, the Conveyance related to such Royalty Interest (or a portion thereof) could be subject to rejection as an executory contract (a term used in the Federal Bankruptcy Code to refer to a contract under which the obligations of both the debtor and the other party to the contract are so unsatisfied that the failure of either to complete performance would constitute a material breach excusing performance of the other) in a bankruptcy proceeding involving Devon. In such event, the Trust would be treated as an unsecured creditor of Devon with respect to such Royalty Interest in the pending bankruptcy. Under Louisiana law, the Louisiana Conveyance constitutes personal property that could be rejected as an executory contract in a bankruptcy proceeding involving Devon, although the mortgage on the Royalty Properties that is burdened by the Louisiana Conveyance and which secures the Trust's interests in such Royalty Properties should enhance the Trust's position in the event of such a proceeding. No assurance can be given that the Royalty Interests would not be subject to rejection in a bankruptcy proceeding as executory contracts.
RESERVES
A study of the proved oil and gas reserves attributable to the Trust as of December 31, 2000 has been made by Ryder Scott Company, independent petroleum consultants. The following letter (Reserve Report) summarizes such reserve study. The Trust has not filed reserve estimates covering the Royalty Properties with any other Federal authority or agency.
(RYDER SCOTT LETTERHEAD)
January 29, 2001
Devon Energy Corporation 20 North Broadway, Suite 1500 Oklahoma City, Oklahoma 73102-8260
Gentlemen:
At your request, we have prepared certain data for the Santa Fe Energy Trust (Trust) as of December 31, 2000 relevant to the supplementary information dictated by Financial Accounting Standards Board (FASB) Statement No. 69 (SFAS 69). SFAS 69 establishes the set of disclosures for oil and gas producing activities as required by Securities and Exchange Commission (SEC) Regulation S-K.
The Trust is a grantor trust formed to hold interests in certain domestic oil and gas properties owned by Devon SFS Operating, Inc., a wholly-owned subsidiary of Devon Energy Corporation hereinafter referred to as Devon. The interests conveyed to the Trust consist of royalty interests in the Wasson Field, Texas (Wasson Royalties) and a net profits interest derived from working and royalty interests in numerous other properties (Net Profits Royalties). The properties included in the Trust are located in the states of Alabama, Arkansas, California, Colorado, Kansas, Louisiana, Mississippi, New Mexico, North Dakota, Oklahoma, Texas, Wyoming, and in state waters offshore Louisiana.
The estimated reserve quantities and future income quantities presented in this report are related to a large extent to hydrocarbon prices. Hydrocarbon prices in effect at December 31, 2000 were used in the preparation of this report as required by SEC and FASB rules; however, actual future prices may vary significantly from December 31, 2000 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report.
The summary of our estimates of the proved net reserves attributable to the Trust as of December 31, 2000 are presented below:
The estimated proved reserves and income quantities for the Wasson Royalties presented in this report are calculated by multiplying the net revenue interest attributable to each of the Wasson Royalties by the total amount of oil estimated to be economically recoverable from the respective
productive units, subject to production limitations applicable to the Wasson Royalties and additional "Support Payments", which have been described to us by Devon. For purposes of this report, the volume of reserves attributable to the Support Payments, if any, is calculated assuming an additional royalty interest in the Wasson ODC property.
Reserve quantities are calculated differently for the Net Profits Royalties because such interests do not entitle the Trust to a specific quantity of oil or gas but to 90 percent of the Net Proceeds derived therefrom. Accordingly, there is no precise method of allocating estimates of the quantities of proved reserves attributable to the Net Profits Royalties between the interest held by the Trust and the interests to be retained by Devon. For purposes of this presentation, the proved reserves attributable to the Net Profits Royalties have been proportionately reduced to reflect the future estimated costs and expenses deducted in the calculation of Net Proceeds with respect to the Net Profits Royalties. Accordingly, the reserves presented for the Net Profits Royalties reflect quantities of oil and gas that are free of future costs or expenses based on the price and cost assumptions utilized in this report. The allocation of proved reserves of the Net Profits Properties between the Trust and Devon will vary in the future as relative estimates of future gross revenues and future net incomes vary. Furthermore, Devon requested that, for purposes of our report, the Net Profits Royalties be calculated beyond the Liquidation Date of February 15, 2008, even though by the terms of the Trust Agreement the Net Profits Royalties will be sold by the Trustee on or about this date and a liquidating distribution of the sales proceeds from such sale would be made to holders of Trust Units.
Devon has indicated that the conveyance of the Wasson Royalties to the Trust provides that the Trust may receive additional income from the Wasson ODC Unit through Support Payments. Payment of the additional income is subject to numerous limitations which are detailed in the Conveyance. Based on the production profiles and pricing assumptions in this report and the terms of the Conveyance as described to us by Devon, no additional net cash inflow is required from future Support Payments as of December 31, 2000. Based on the original terms of the Conveyance, the Support Payments are limited to a total payment of $20,000,000 from inception through 2002, which is the time the Support Payments are terminated. However, with the sale of the Jeffress Field during 1999, this limitation has been reduced to $19,400,000. As of December 31, 2000, there were no unrecouped Support Payments so the remaining maximum obligation with respect to the Support Payments is $19,400,000. In accordance with information provided by Devon, we have calculated total estimated net revenue of $14,818,319 to be available for Support Payments as of December 31, 2000.
The "Liquid" reserves shown in this report are comprised of crude oil, condensate and natural gas liquids. Natural gas liquids comprise 3.8 percent of the Trust's developed liquid reserves and 3.8 percent of the Trust's developed and undeveloped liquid reserves. All hydrocarbon liquid reserves are expressed in standard 42 gallon barrels. All gas volumes are sales gas expressed in MMCF at the pressure and temperature bases of the area where the gas reserves are located. No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist.
RESERVES INCLUDED IN THIS REPORT
The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:
PROVED OIL AND GAS RESERVES. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:
(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves";
(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and
(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
PROVED UNDEVELOPED RESERVES. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff's view on specific questions pertaining to proved oil and gas reserves.
Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The
relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)
In determining whether "proved undeveloped reserves" encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion?. .. The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)
Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)
The staff believes that since coalbed methane gas can be recovered from coal in its natural and original location, it should be included in proved reserves, provided that it complies in all other respects with the definition of proved oil and gas reserves as specified in Rule 4-10(a)(2) including the requirement that methane production be economical at current prices, costs, (net of the tax credit) and existing operating conditions. (extracted from SAB-85)
Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission's official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.
Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.
REVENUE AND INCOME ESTIMATES
In accordance with the standardized measure criteria of SFAS 69, our estimates of future cash inflows, future costs, and future net cash inflows before income tax, as well as our estimated reserve quantities, as of December 31, 2000 are presented below.
In the case of the Wasson Royalties, the future cash inflows are gross revenues after gathering and transportation costs where applicable, but before any other deductions. The production costs are based on current data and include production taxes and ad valorem taxes provided by Devon.
In the case of the Net Profits Royalties, the future cash inflows are, as described previously, after consideration of future costs or expenses based on the price and cost assumptions utilized in this report. Therefore, the future cash inflows are the same as the future net cash inflows.
HYDROCARBON PRICES
Devon furnished us with hydrocarbon prices in effect at December 31, 2000 and with its forecasts of future prices which take into account SEC and FASB rules, current market prices, contract prices, and fixed and determinable price escalations where applicable.
In accordance with SFAS 69, December 31, 2000 market prices were determined using the daily oil price or daily gas sales price ("spot price") adjusted for oilfield or gas gathering hub and wellhead price differences (e.g. grade, transportation, gravity, sulfur and BS&W) as appropriate, and as provided by Devon. In accordance with SEC and FASB specifications, changes in market prices subsequent to December 31, 2000 were not considered in this report.
For hydrocarbon products sold under contract, the contract price including fixed and determinable escalations, exclusive of inflation adjustments, was used until expiration of the contract. Upon contract expiration, the price was adjusted to the current market price for the area and held at this adjusted price to depletion of the reserves.
The effects of derivative instruments designated as price hedges of oil and gas quantities, if any, are not reflected in our individual property evaluations.
COSTS
Operating costs for the leases and wells in this report were provided by Devon and include only those costs directly applicable to the leases or wells. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the leases and wells under terms of operating agreements. No deduction was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments that are not charged directly to the leases or wells.
Development costs were furnished to us by Devon and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. At the request of Devon, their estimate of zero abandonment costs after salvage value for onshore properties was used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Devon's estimate.
Current costs were held constant throughout the life of the properties.
GENERAL
The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered. Estimates of proved reserves may increase or decrease as a result of future operations of Devon. Moreover, due to the nature of the Support Payments and the Net Profits Royalties, a change in the future costs, or prices, or capital expenditures different from those projected herein may result in a change in the computed reserves and the Net Proceeds to the Trust even if there are no revisions or additions to the gross reserves attributed to the property.
While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC and FASB, omitted from consideration in making this evaluation.
The estimates of reserves presented herein are based upon a detailed study of the properties in which the Trust has interests; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. Devon has informed us that they have furnished us all of the accounts, records, geological and engineering data and reports, and other data required for this investigation. The ownership interests, terms of the Trust, prices, taxes, costs, and other factual data furnished by Devon were accepted without independent verification. The estimates presented in this report are based on data available through July 2000.
Neither Ryder Scott Company nor any of our employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future cash inflows for the subject properties.
Very truly yours, RYDER SCOTT COMPANY, L.P. Fred W. Ziehe, P.E. Senior Vice President
The value of the Depositary Units and the Trust Units evidenced thereby are substantially dependent upon the proved reserves and production levels attributable to the Royalty Interests. There are many uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the timing of development expenditures. The reserve data set forth herein, although prepared by independent engineers in a manner customary in the industry, are estimates only, and actual quantities and values of oil and gas are likely to differ from the estimated amounts set forth herein. In addition, the discounted present values shown herein were prepared using guidelines established by the Securities and Exchange Commission for disclosure of reserves and should not be considered representative of the market value of such reserves or the Depositary Units or the Trust Units evidenced thereby. A market value determination would include many additional factors.
Distributions to Holders could be adversely affected if any of the hazards typically associated with the development, production and transportation of oil and gas were to occur, including personal injuries, property damage, damage to productive formations or equipment and environmental damages. Uninsured costs for damages from any of the foregoing will directly reduce payments to the Trust from those Royalty Properties that are working interests, and will reduce payments to the Trust from those Royalty Properties that are royalties and overriding royalties to the extent such damages reduce the volumes of oil and gas produced.
In contrast to the Net Profits Royalties, which have no contractually imposed production limitations, the Wasson Royalties have been structured with quarterly production limitations. Thus, the Trust and Holders will not receive cash distributions from oil production from the two Wasson production units burdened by the Wasson Royalties in excess of such amounts. While the Wasson ODC Unit is expected to produce at levels substantially in excess of the applicable production limitations, failure of actual production from either of the two Wasson production units to meet or exceed the applicable quarterly production limitations will reduce amounts payable in respect of the Wasson Royalties.
PROCEEDS, PRODUCTION AND AVERAGE PRICES
Reference is made to "Results of Operations" under Item 7 of this Form 10-K.
ASSETS
Reference is made to Item 6 of this Form 10-K for information relating to the assets of the Trust.
COMPETITION AND MARKETS
COMPETITION. The oil and gas industry is highly competitive in all of its phases. Devon and the other operators of the Royalty Properties will encounter competition from major oil and gas companies, international energy organizations, independent oil and gas concerns, and individual producers and operators. Many of these competitors have greater financial and other resources than Devon and the other operators of the Royalty Properties. Competition may also be presented by alternative fuel sources, including heating oil and other fossil fuels.
MARKETS. Production attributable to Devon's royalty interests in the Wasson ODC Unit and the Wasson Willard Unit is marketed by Devon and is in some cases sold at the wellhead at market responsive prices that approximate spot oil prices for West Texas sour crude, and in other cases is traded at points within common carrier pipeline systems.
With respect to the Net Profits Properties, where such properties consist of royalty interests, the operators of the properties will make all decisions regarding the marketing and sale of oil and gas production. Although Devon generally has the right to market oil and gas produced from the Royalty Properties that are working interests, Devon generally relies on the operators of the properties to
market the production. The ability of the operators to market the oil and gas produced from the Royalty Properties will depend upon numerous factors beyond their control, including the extent of domestic production and imports of oil and gas, the proximity of the gas production to gas pipelines, the availability of capacity in such pipelines, the demand for oil and gas by utilities and other end-users, the effects of inclement weather, state and Federal regulation of oil and gas production and Federal regulation of gas sold or transported in interstate commerce. There is no assurance that such operators will be able to market all of the oil or gas produced from the Royalty Properties or that favorable prices can be obtained for the oil and gas produced.
In view of the many uncertainties affecting the supply and demand for oil, gas and refined petroleum products, Devon is unable to make reliable predictions of future oil and gas prices and demand or the overall effect they will have on the Trust. Devon does not believe that the loss of any of its purchasers would have a material adverse effect on the Trust, since substantially all of the oil and gas sales from the Royalty Properties are made on the spot market at market responsive prices.
GOVERNMENTAL REGULATION
OIL AND GAS REGULATION
The production, transportation and sale of oil and gas from the Royalty Properties are subject to or affected by Federal and state governmental regulation, including regulations concerning maximum allowable rates of production, regulation of the terms of service and tariffs charged by gatherers and pipelines, taxes, the prevention of waste, the conservation of oil and gas, pollution controls and various other matters. The United States has governmental power to permit increases in the amount of oil imported from other countries and to impose pollution control measures.
FEDERAL REGULATION OF GAS. The Net Profits Properties are subject to or affected by the jurisdiction of the Federal Energy Regulatory Commission ("FERC") and the Department of Energy with respect to various aspects of oil and gas operations including marketing and production of oil and gas. Under the Natural Gas Act of 1938, the FERC regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. The FERC's jurisdiction over interstate natural gas sales was substantially modified by the Natural Gas Policy Act, under which the FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for all "first sales" of natural gas. Because "first sales" include typical wellhead sales by producers, all natural gas produced from the Net Profits Properties is being sold at market prices, subject to the terms of any private contracts which may be in effect. The FERC's jurisdiction over natural gas transportation was not affected by the Decontrol Act.
Sales of natural gas from the Net Profits Properties are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, the FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of gas to the primary role of gas transporters. Through similar orders affecting intrastate pipelines that provide similar interstate services, the FERC expanded the impact of open access regulations to intrastate commerce.
Beginning in April 1992, the FERC issued Order No. 636 and a series of related orders, which required interstate pipelines to provide open-access transportation on a not unduly discriminatory basis for all natural gas shippers. All gas marketing by the pipelines was required to be divested to a marketing affiliate, which operates separately from the transporter and in direct competition with other gas merchants. Although Order No. 636 does not directly regulate production and marketing activities, it does affect how buyers and sellers gain access to the necessary transportation facilities and how natural gas is sold in the marketplace.
The courts have largely affirmed the significant features of Order No. 636 and the numerous related orders pertaining to individual pipelines. However, some appeals remain pending and the FERC continues to review and modify its regulations regarding the transportation of natural gas. For example, the FERC Order No. 637 which:
- lifts the cost-based cap on pipeline transportation rates in the capacity release market until September 30, 2002, for short-term releases of pipeline capacity of less than one year,
- permits pipelines to file for authority to charge different maximum cost-based rates for peak and off-peak periods,
- encourages, but does not mandate, auctions for pipeline capacity,
- requires pipelines to implement imbalance management services,
- restricts the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow orders, and
- implements a number of new pipeline reporting requirements.
Order No. 637 also requires the FERC staff to analyze whether the FERC should implement additional fundamental policy changes. These include whether to pursue performance-based or other non-cost based ratemaking techniques and whether the FERC should mandate greater standardization in terms and conditions of service across the interstate pipeline grid.
In April 1999 the FERC issued Order No. 603, which implemented new regulations governing the procedure for obtaining authorization to construct new pipeline facilities. In September 1999, the FERC issued a related policy statement establishing a presumption in favor of requiring owners of new pipeline facilities to charge rates for service on new pipeline facilities based solely on the costs associated with such new pipeline facilities. It remains to be seen what effect the FERC's other activities will have on the access to markets, the fostering of competition and the cost of doing business.
As a result of these changes, sellers and buyers of gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties. Devon believes these changes generally have improved the access to markets for the gas from the Net Profits Properties while, at the same time, substantially increasing competition in the natural gas marketplace. Devon cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on production and marketing of gas from the Net Profits Properties.
In the past, Congress has been very active in the area of gas regulation. However, as discussed above, the more recent trend has been in favor of deregulation and the promotion of competition in the gas industry. Thus, in addition to "first sale" deregulation, Congress also repealed incremental pricing requirements and gas use restraints previously applicable. There are other legislative proposals pending in the Federal and state legislatures which, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on the production and marketing of gas from the Net Profits Properties. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on the production and marketing of gas from the Net Profits Properties, cannot be predicted.
FEDERAL REGULATION OF PETROLEUM. Sales of oil and natural gas liquids from the Royalty Properties are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through
interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations have generally been approved on judicial review. Every five years, the FERC will examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The first such review took place in 2000. Any changes will not take effect until July 2001. Devon is not able to predict with certainty what effect, if any these relatively new federal regulations will have on it.
STATE REGULATION. Many state jurisdictions have at times imposed limitations on the production of gas premised on conservation concerns and the protection of correlative rights by such methods as restricting the rate of flow for gas wells below their actual capacity to produce and by imposing acreage limitations for the drilling of a well. States may also impose additional regulation of these matters. Most states regulate the production and sale of oil and gas, including requirements for obtaining drilling permits, the method of developing new fields, provisions for the unitization or pooling of oil and gas properties, the spacing, operation, plugging and abandonment of wells and the prevention of waste of oil and gas resources. The rate of production may be regulated and the maximum daily production allowable from oil and gas wells may be established on a market demand or conservation basis or both.
ENVIRONMENTAL REGULATION
GENERAL. Activities on the Royalty Properties are subject to existing Federal, state and local laws and regulations governing environmental quality and pollution control. Devon cannot predict what effect this or additional regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from operations on the Royalty Properties could have on the Trust. Environmental matters have an effect on the Trust only to the extent of revenues attributable to the Trust's interests in the Royalty Properties.
SOLID AND HAZARDOUS WASTE. The Royalty Properties include numerous properties that have produced oil and gas for many years and hydrocarbons or other solid wastes may have been disposed or released on or under the Royalty Properties. State and Federal laws applicable to oil and gas wastes and properties have become increasingly more stringent. Under these new laws, Devon or an operator of the Royalty Properties could be required to remove or remediate previously disposed wastes or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.
The operators of the Royalty Properties may generate wastes that are subject to the Federal Resource Conservation and Recovery Act and comparable state statutes. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes and is considering the adoption of more stringent disposal standards for nonhazardous wastes. Furthermore, it is anticipated that additional wastes (which could include certain wastes generated by oil and gas operations) will be designated as "hazardous wastes", which are subject to more rigorous and costly disposal requirements.
SUPERFUND. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the owner and operator of a site and companies that disposed or arranged for the disposal of the hazardous substance found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to
threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs of such action. In the course of their operations, the operators of the Royalty Properties have generated and will generate wastes that may fall within CERCLA's definition of "hazardous substances." Devon or the operators of the Royalty Properties may be responsible under CERCLA for all or part of the costs to clean up sites at which such wastes have been disposed.
AIR EMISSIONS. The operators of the Royalty Properties are subject to Federal, state and local regulations concerning the control of emissions from sources of air pollution. Administrative enforcement actions for failure to comply strictly with air regulations or permits are generally resolved by payment of a monetary penalty and correction of any identified deficiencies. Alternatively, regulatory agencies could require the operators to forego construction or operation of certain air pollution emission sources.
OSHA. The operators of the Royalty Properties are subject to the requirements of the Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and similar state statutes require an operator to organize information about hazardous materials used or produced in its operations. Certain of this information must be provided to employees, state and local government authorities and local citizens.
ITEM 2.
ITEM 2. PROPERTIES.
Reference is made to Item 1 of this Form 10-K.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
The Royalty Properties related to the Trust are the subject of lawsuits and governmental proceedings from time to time arising in the ordinary course of business. While the outcome of lawsuits or other proceedings involving the Royalty Properties cannot be predicted with certainty, these matters are not expected to have a material adverse effect on the financial position or cash proceeds and distributable cash of the Trust.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during the year ended December 31, 2000.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED HOLDER MATTERS.
The Depositary Units are traded on the New York Stock Exchange--ticker symbol SFF. The high and low closing sales prices and distributions for each quarter in the years ended December 31, 1999 and 2000 were as follows (in dollars):
At March 1, 2001, the 6,300,000 Depositary Units outstanding were held by 279 holders of record.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
GENERAL; LIQUIDITY AND CAPITAL RESOURCES
Santa Fe Energy Trust (the "Trust") was formed on October 22, 1992 with The Chase Manhattan Bank, successor by merger to Chase Bank of Texas, National Association, formerly known as Texas Commerce Bank, National Association as trustee (the "Trustee"), to acquire and hold certain royalty interests (the "Royalty Interests") in certain properties (the "Royalty Properties") conveyed to the Trust by Devon SFS Operating, Inc. ("Devon"), formerly Santa Fe Snyder Corporation, formerly Santa Fe Energy Resources, Inc. ("Santa Fe"). The Trust is a passive entity with the Trustee's primary responsibility being the collection and distribution of proceeds from the Royalty Interests and the payment of Trust liabilities and expenses (see Note 1 to the financial statements of the Trust). The Royalty Interests consist of two term royalty interests in two production units (the Wasson ODC Unit and the Wasson Willard Unit) in the Wasson field in west Texas (the "Wasson Royalties") and a net profits royalty interest (the "Net Profits Royalties") in certain royalty and working interest properties in a diversified portfolio of properties located predominantly in Texas, Louisiana and Oklahoma (the "Net Profits Properties"). Under the terms of the Trust Agreement, the Trustee cannot engage in any other business or commercial activity or acquire any asset other than the Royalty Interests initially conveyed to the Trust. Therefore, the Royalty Interests are the sole source of funds for the Trust from which to
pay expenses and liabilities and make distributions to the holders of the Trust Units. The Trust will be liquidated on or before February 15, 2008 (the "Liquidation Date").
The Wasson Royalties are fixed percentage royalty interests in specified levels of quarterly maximum production from the underlying properties in each year during the term of the respective royalty. The Wasson ODC Royalty and the Wasson Willard Royalty terminate on December 31, 2007 and December 31, 2003, respectively. The Net Profits Royalties are life-of-property interests which will be sold by the Trust prior to the Liquidation Date. The Net Profits Royalties entitle the Trust to receive 90% of the net proceeds (after deducting, among other things, the costs of production and marketing and capital expenditures) from the sale of production from the Net Profits Properties. The Net Profits Properties are generally mature producing oil and gas properties and the production and reserves attributable to such properties are expected to decline substantially over the life of the Trust. The Net Profits Royalties are expected to have a relatively small liquidation value at the Liquidation Date.
For any calendar quarter ending on or prior to December 31, 2002, the Trust will receive additional royalty payments ("Support Payments") to the extent it needs such payments to distribute $0.39 per Trust Unit per quarter. Effective July 1, 1999 and as required by the Trust Agreement, the Trust released its Net Profits Royalty interest in the Jeffress field in connection with the sale by Devon of the underlying Net Profits Property. The Trust received 90% of the net proceeds from this sale in the fourth quarter 1999 distribution. As a result of this sale, there was a proportionate reduction of the Minimum Quarterly Royalty from $0.40 per Depositary Unit to $0.39 per Depositary Unit, a proportionate reduction of the Aggregate Support Payment Limitation Amount from $20.0 million to $19.4 million and a proportionate reduction in the distribution per Depositary Unit over which Devon is entitled to recoup Support Payments from $0.45 per Depositary Unit to $0.44 per Depositary Unit. Such Support Payments are limited to Devon's remaining royalty interest in the Wasson ODC Unit. If Support Payments are received, certain proceeds otherwise payable to the Trust in subsequent quarters may be reduced to recoup the amount of such Support Payments. The aggregate amount of Support Payments, net of any amounts recouped, is limited to $19.4 million on a revolving basis. From inception through the end of 2000, the Trust received Support Payments totalling $4.2 million. During 1996, the first six months of 1997, the fourth quarter of 1999 and the first quarter of 2000, Devon recouped all such payments. Future recoupments will be made only to the extent of future support payments. Depending on factors such as sales prices and volumes and the level of operating costs and capital expenditures, Support Payments may be required in subsequent quarters to allow the Trust to make distributions of $0.39 per Trust Unit per quarter.
Trust expenses include accounting, engineering, legal and other professional fees, Trustee fees, an administrative fee paid to Devon and other out-of-pocket expenses. From time to time Devon may, at its sole discretion and without any obligation to do so, advance funds to the Trust for the timely payment of such expenses and receive reimbursement therefor in later periods. In addition, the Trustee is authorized to borrow funds required to pay liabilities of the Trust, provided that such borrowings are repaid in full prior to making further distributions to the holders of the Trust Units. Currently there are no such borrowings outstanding or contemplated other than the above-described advances which Devon has made or may make.
The Trust's results of operations are dependent upon the sales prices and quantities of oil and gas produced from the Royalty Properties, the costs of producing such resources and the amount of capital expenditures made with respect to such properties. Royalty income is recorded by the Trust when received, generally during the quarter following the end of the quarter in which revenues are received and costs and expenses are paid by Devon. Cash proceeds from the Royalty Properties may fluctuate from quarter to quarter due to the timing of receipts and payments of revenues and expenses as well as changes in prices and production volumes. In addition, amounts for future exploration and development costs may be reserved from time to time.
Since, on an equivalent basis, the majority of the Trust's proved reserves are crude oil, even relatively modest changes in crude oil prices may significantly affect the Trust's revenues and results of operations. Crude oil prices are subject to significant changes in response to fluctuations in the domestic and world supply and demand and other market conditions as well as the world political situation as it affects OPEC and other producing countries. In addition, a substantial portion of the Trust's revenues come from properties which produce sour (i.e., high sulfur content) crude oil which sells at prices lower than sweeter (i.e., low sulfur content) crude oils. The Trust's weighted average crude oil sales price (excluding the effect of Support Payments and recoupments) for 2000, 1999 and 1998 was $25.27, $13.47 and $13.93, respectively (see Results of Operations).
Natural gas prices fluctuate due to weather conditions, the level of natural gas in storage, the relative balance between supply and demand and other economic factors. The Trust's weighted average price per Mcf for natural gas in 2000, 1999 and 1998 was $2.71, $1.89 and $2.37 respectively.
RESULTS OF OPERATIONS
Royalty income is recorded by the Trust when received, generally during the quarter following the end of the quarter in which revenues are received and costs and expenses are paid by Devon. Cash proceeds from the Royalty Properties may fluctuate from quarter to quarter due to the timing of receipts and payments of revenues and costs and expenses as well as changes in prices and production volumes. The following table reflects pertinent information with respect to the cash proceeds from the Royalty Properties and the net distributable cash of the Trust. The information presented with respect to the first quarter of 2001 reflects revenues received and costs and expenses paid by Devon in the fourth quarter of 2000. In the first quarter of 2001 the Trust received a payment of $4,476,046 and on
February 28, 2001 made a cash distribution of $4,426,046, or $0.70 per Trust Unit, to unitholders of record on February 15, 2001.
The Trust's weighted average crude oil sales prices were $26.91 per barrel for the Wasson Royalties and $22.79 per barrel for the Net Profits Royalties in 2000 compared with $14.60 per barrel and $11.72 per barrel, respectively, in 1999 and $14.10 per barrel and $13.68 per barrel, respectively, in 1998.
Weighted average crude oil prices in the first quarter of 2001 were $29.71 per barrel for the Wasson Royalties and $31.97 per barrel for the Net Profits Royalties.
The weighted average natural gas price per Mcf in 2000, 1999 and 1998 was $2.71, $1.89 and $2.37, respectively. Natural gas sales prices averaged $4.28 per Mcf in the first quarter of 2001.
Cash proceeds in 1996 and 1997 were reduced by $1,009,000 and $1,065,000, respectively, as Devon recouped all Support Payments made in prior periods. Cash proceeds in the fourth quarter of 1998, and the first, second and third quarters of 1999 included Support Payments of $94,000, $779,000, $691,000 and $541,000, respectively. Cash proceeds in the fourth quarter of 1999 were reduced by $1,831,000 as Devon recouped the 1998 Support Payment of $94,000 and $1,737,000 of the 1999 Support Payments. Cash proceeds in the first quarter 2000 were reduced by $274,000 as Devon recouped the remaining Support Payments.
Proceeds from the Net Profits Royalties are net of capital expenditures with respect to the exploration and development of the Net Profits Properties. Capital expenditures for 2000, 1999 and 1998 totalled $632,000, $772,000 and $1,314,000, respectively. Capital expenditures are expected to be approximately $450,000 in 2001. Operating expenses for the Net Profits Royalties averaged $4.31 per barrel of oil equivalent ("BOE") in 2000 compared to $4.24 per BOE 1999 and $3.78 per BOE in 1998. Operating expenses averaged $5.18 per BOE in the first quarter of 2001. Operating expenses may fluctuate from quarter to quarter due to the timing of payments.
FORWARD LOOKING STATEMENTS
Management's Discussion and Analysis of Financial Condition and Results of Operations includes certain statements (other than statements of historical fact) that constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used herein, the words "anticipates," "expects," "believes," "intends" or "projects" and similar expressions are intended to identify forward-looking statements. It is important to note that actual results could differ materially from those projected by such forward-looking statements. Although it is believed that the expectations reflected in such forward-looking statements are reasonable and such forward-looking statements are based on the best data available at the time this report is filed with the Securities and Exchange Commission, no assurance can be given that such expectations will prove correct. Factors that could cause results to differ materially from the results discussed in such forward-looking statements include, but are not limited to, the following: production variances from expectations, volatility of oil and gas prices, the need to develop and replace reserves, the capital expenditures required to fund operations, environmental risks, uncertainties about estimates of reserves, competition and government regulation and political risks. All such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
DISCLOSURES ABOUT MARKET RISK
Production attributable to Devon's royalty interest in the Wasson ODC Unit and the Wasson Willard Unit is marketed by Devon and is in some cases sold at the wellhead at market responsive prices and in other cases is traded at points within common carrier pipeline systems.
With regard to the Net Profits Properties, where such properties consist of royalty interests, the operators of the properties will make all decisions regarding the marketing and sale of oil and gas production. The ability of the operators to market the oil and gas produced from the Royalty Properties will depend upon numerous factors beyond their control, including the proximity of the gas production to gas pipelines, the availability of capacity in such pipelines, state and Federal regulation of
oil and gas production and Federal regulation of gas sold or transported in interstate commerce. There is no assurance that such operators will be able to market all of the oil or gas produced from the Royalty Properties or that favorable prices can be obtained for the oil and gas produced.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
See Item 14 on page 37 herein for the Exhibits, Financial Statement Schedules, Supplementary Data and reports on Form 8-K.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
PREVIOUS INDEPENDENT ACCOUNTANTS
Certain accounting functions for the Santa Fe Energy Trust ("the Registrant") have previously been provided by Santa Fe Snyder Corporation ("Santa Fe Snyder"). For efficiency purposes, the Registrant has utilized the services of the same independent accountants engaged by Santa Fe Snyder, which accountants have been PricewaterhouseCoopers, LLP.
On August 29, 2000 Santa Fe Snyder was merged with and into a subsidiary of Devon Energy Corporation ("Devon"), and Santa Fe Snyder became a wholly-owned subsidiary of Devon. Devon's independent accountants are KPMG LLP.
The Registrant, as of December 11, 2000, dismissed PricewaterhouseCoopers LLP as its independent accountants.
The reports of PricewaterhouseCoopers LLP on the financial statements of the Registrant for the past two fiscal years ended December 31, 1999 and 1998 contained no adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles.
The decision to change independent accountants was made by The Chase Manhattan Bank, acting in its capacity as the Registrant's trustee. The Registrant has no board of directors.
In connection with its audits for the two most recent fiscal years and through the date of the change in independent accountants, there were no disagreements with PricewaterhouseCoopers LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure which disagreements, if not resolved to the satisfaction of PricewaterhouseCoopers LLP, would have caused it to make reference to the subject matter of the disagreement in connection with its report on the Registrant's financial statements for such periods.
During the two most recent fiscal years and through the date of the change in independent accountants, there were no "reportable events," as that term is defined in Item 304(a)(1)(v) of Regulation S-K, with respect to the services provided by PricewaterhouseCoopers LLP.
NEW INDEPENDENT ACCOUNTANTS
The Chase Manhattan Bank, acting in its capacity as trustee of the Registrant, as of December 11, 2000, informed KPMG LLP of its decision to retain such firm as the independent accountants of the Registrant.
During the two most recent fiscal years and through the date of the change in independent accountants, the Registrant did not consult with KPMG LLP on matters (i) regarding the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Registrant's financial statements, or (ii) which concerned the subject matter of a disagreement or reportable event with the former auditor (as described in Item 304 of Regulation S-K).
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
There are no directors or executive officers of the Registrant. The Trustee is a corporate trustee which may be removed by the affirmative vote of Holders of a majority of the Trust Units then outstanding at a meeting of the Holders of the Trust at which a quorum is present.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Not applicable.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) Security Ownership of Certain Beneficial Owners.
Not Applicable.
(b) Security Ownership of Management.
Not applicable.
(c) Changes in Control.
The Registrant knows of no arrangements, including the pledge of securities of the Registrant, the operation of which may at a subsequent date result in a change in control of the Registrant.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A)(1)FINANCIAL STATEMENTS
The following financial statements are included in this Annual Report on Form 10-K on the pages as indicated:
(A)(2)SCHEDULES
Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.
(A)(3)EXHIBITS
(Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference.)
(B) REPORTS ON FORM 8-K
A Form 8-K dated December 11, 2000, was filed disclosing a change in the Trust's independent accountants.
INDEPENDENT AUDITORS' REPORT
To the Trustee and Unitholders of the Santa Fe Energy Trust
We have audited the financial statements listed in the accompanying index appearing under Item 14(a)(1) on page 37 as of December 31, 2000 and for the year then ended. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 audit provides a reasonable basis for our opinion.
As described in Note 2, these financial statements have been prepared on the basis of cash receipts and disbursements, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
In our opinion, the financial statements audited by us present fairly, in all material respects, the financial position of the Santa Fe Energy Trust at December 31, 2000, and the cash proceeds and distributable cash and the changes in trust corpus for the year ended December 31, 2000, on the basis of accounting described in Note 2.
KPMG LLP
Oklahoma City, Oklahoma March 26, 2001
REPORT OF INDEPENDENT ACCOUNTANTS
To the Trustee and Unitholders of the Santa Fe Energy Trust
We have audited the financial statements listed in the accompanying index appearing under Item 14(a)(1) on page 37 as of December 31, 1999 and for each of the two years then ended. 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 auditing standards generally accepted in the United States of America. 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 2, these financial statements have been prepared on the basis of cash receipts and disbursements, which is a comprehensive basis of accounting other than accounting standards generally accepted in the United States of America.
In our opinion, the financial statements audited by us present fairly, in all material respects, the financial position of the Santa Fe Energy Trust at December 31, 1999, and the cash proceeds and distributable cash and the changes in trust corpus for each of the two years in the period ended December 31, 1999, on the basis of accounting described in Note 2.
PRICEWATERHOUSECOOPERS LLP
Houston, Texas February 25, 2000
SANTA FE ENERGY TRUST STATEMENT OF CASH PROCEEDS AND DISTRIBUTABLE CASH (IN THOUSANDS, EXCEPT PER UNIT DATA)
STATEMENT OF ASSETS AND TRUST CORPUS (IN THOUSANDS, EXCEPT UNIT DATA)
The accompanying notes are an integral part of the financial statements.
SANTA FE ENERGY TRUST STATEMENT OF CHANGES IN TRUST CORPUS (IN THOUSANDS)
The accompanying notes are an integral part of the financial statements.
SANTA FE ENERGY TRUST NOTES TO FINANCIAL STATEMENTS
(1) THE TRUST
Santa Fe Energy Trust (the "Trust") was formed on October 22, 1992, with The Chase Manhattan Bank, successor by merger to Chase Bank of Texas, National Association formerly known as Texas Commerce Bank, National Association as trustee (the "Trustee"), to acquire and hold certain royalty interests (the "Royalty Interests") in certain properties (the "Royalty Properties") conveyed to the Trust by Devon SFS Operating, Inc. ("Devon"), formerly Santa Fe Snyder Corporation, formerly Santa Fe Energy Resources, Inc. ("Santa Fe"). The Royalty Interests consist of two term royalty interests in two production units in the Wasson field in west Texas (the "Wasson Royalties") and a net profits royalty interest in certain royalty and working interests in a diversified portfolio of properties located in twelve states (the "Net Profits Royalties"). The Royalty Interests are passive in nature and the Trustee has no control over or responsibility relating to the operation of the Royalty Properties. The Trust will be liquidated on February 15, 2008 (the "Liquidation Date").
In November 1992, 5,725,000 Depositary Units, each consisting of beneficial ownership of one unit of undivided beneficial interest in the Trust ("Trust Units") and a $20 face amount beneficial ownership interest in a $1,000 face amount zero coupon United States Treasury obligation maturing on or about February 15, 2008, were sold in a public offering for $20 per Depositary Unit. A total of $114.5 million was received from public investors, of which $38.7 million was used to purchase the Treasury obligations and $5.7 million was used to pay underwriting commissions and discounts. Devon received the remaining $70.1 million and 575,000 Depositary Units. In the first quarter of 1994 Devon sold in a public offering the 575,000 Depositary Units which it held.
The trust agreement under which the Trust was formed (the "Trust Agreement") provides, among other things, that:
- the Trustee shall not engage in any business or commercial activity or acquire any asset other than the Royalty Interests initially conveyed to the Trust;
- the Trustee may not sell all or any portion of the Wasson Royalties or substantially all of the Net Profits Royalties without the prior consent of Devon;
- Devon may sell the Royalty Properties, subject to and burdened by the Royalty Interests, without consent of the holders of the Trust Units; following any such transfer, the Royalty Properties will continue to be burdened by the Royalty Interests and after any such transfer the royalty payment attributable to the transferred property will be calculated separately and paid by the transferee;
- the Trustee may establish a cash reserve for the payment of any liability which is contingent, uncertain in amount or that is not currently due and payable;
- the Trustee is authorized to borrow funds required to pay liabilities of the Trust, provided that such borrowings are repaid in full prior to further distributions to the holders of the Trust Units;
- the Trustee will make quarterly cash distributions to the holders of the Trust Units.
(2) BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on the cash basis of accounting for revenues and expenses. Royalty income is recorded when received (generally during the quarter following the end of the quarter in which the income from the Royalty Properties is received by Devon) and is net of any cash basis exploration and development expenditures and amounts reserved for any future exploration and development costs. Expenses of the Trust, which will include accounting, engineering, legal, and other professional fees, Trustee fees, an administrative fee paid to Devon and out-of-pocket expenses, are recognized when paid. Under accounting principles generally accepted in the United
SANTA FE ENERGY TRUST NOTES TO FINANCIAL STATEMENTS (CONTINUED)
(2) BASIS OF ACCOUNTING (CONTINUED) States of America, revenues and expenses would be recognized on an accrual basis. Amortization of the Trust's investment in Royalty Interests is recorded using the unit-of-production method in the period in which the cash is received with respect to such production; therefore, a statement of cash flows is not presented.
The conveyance of the Royalty Interests to the Trust was accounted for as a purchase transaction. The $87,276,000 reflected in the Statement of Assets and Trust Corpus as Investment in Royalty Interests represents 6,300,000 Trust Units valued at $20 per unit less the $38,724,000 paid for the Treasury obligations. The carrying value of the Trust's investment in the Royalty Interests is not necessarily indicative of the fair value of such Royalty Interests.
The Trust is a grantor trust and as such is not subject to income taxes and accordingly no recognition has been given to income taxes in the Trust's financial statements. The tax consequences of owning Trust Units are included in the income tax returns of the individual Trust Unit holders.
The preparation of the Trust's financial statements requires the use of certain estimates. Actual results may differ from such estimates.
(3) THE ROYALTY INTERESTS
The Wasson Royalties consist of interests conveyed out of Devon's royalty interest in the Wasson ODC Unit (the "ODC Royalty") and the Wasson Willard Unit (the "Willard Royalty"). The ODC Royalty entitles the Trust to receive quarterly royalty payments with respect to 12.3934% of the actual gross oil production from the Wasson ODC Unit, subject to certain quarterly limitations set forth in the conveyance agreement, for the period from November 1, 1992 to December 31, 2007. The Willard Royalty entitles the Trust to receive quarterly royalty payments with respect to 6.8355% of the actual gross oil production from the Wasson Willard Unit, subject to certain quarterly limitations set forth in the conveyance agreement, for the period from November 1, 1992 to December 31, 2003.
The Net Profits Royalties entitle the Trust to receive, on a quarterly basis, 90% of the net proceeds, as defined in the conveyance agreement, from the sale of production from the properties subject to the conveyance agreement. The Net Profits Royalties are not limited in term, although the Trustee is required to sell such royalties prior to the Liquidation Date.
For any calendar quarter ending on or prior to December 31, 2002, the Trust will receive additional royalty payments ("Support Payments") from Devon to the extent it needs such payments to distribute $0.39 per Trust Unit per quarter. Effective July 1, 1999 and as required by the Trust Agreement, the Trust released its Net Profits Royalty interest in the Jeffress field in connection with the sale by Devon of the underlying Net Profits Property. The Trust received 90% of the net proceeds from this sale in the fourth quarter 1999 distribution. As a result of this sale, there was a proportionate reduction of the Minimum Quarterly Royalty from $0.40 per Depositary Unit to $0.39 per Depositary Unit, a proportionate reduction of the Aggregate Support Payment Limitation Amount from $20.0 million to $19.4 million and a proportionate reduction in the distribution per Depositary Unit over which Devon is entitled to recoup Support Payments from $0.45 per Depositary Unit to $0.44 per Depositary Unit. Such Support Payments are limited to Devon's remaining royalty interest in the Wasson ODC Unit. If such Support Payments are received, certain proceeds otherwise payable to the Trust in subsequent quarters may be reduced to recoup the amount of such Support Payments. The aggregate of the Support Payments, net of any amounts recouped, will be limited to $19,400,000 on a revolving basis. From inception through the end of 2000 the Trust received Support Payments totalling $4,179,000. During 1996, the first six months of 1997, the fourth quarter of 1999 and the first quarter of
SANTA FE ENERGY TRUST NOTES TO FINANCIAL STATEMENTS (CONTINUED)
(3) THE ROYALTY INTERESTS (CONTINUED) 2000, Devon recouped all such payments. Future recoupment will be made only to the extent of future Support Payments.
(4) DISTRIBUTIONS TO TRUST UNIT HOLDERS
The Trust has received royalty payments net of administrative fees paid to Devon and made distributions as follows:
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(a) Reduced by recoupment of Support Payment of $275,000, or $0.04346 per Trust Unit.
(b) Includes Support Payment of $779,000, or $0.12363 per Trust Unit.
(c) Includes Support Payment of $691,000, or $0.10981 per Trust Unit.
(d) Includes Support Payment of $541,000, or $0.08583 per Trust Unit.
(e) Reduced by recoupment of Support Payment of $1,831,000, or $0.29071 per Trust Unit.
(f) Includes Support Payment of $94,000, or $0.014904 per Trust Unit.
(5) COMMITMENTS AND CONTINGENCIES
The Royalty Properties related to the Trust are the subject of lawsuits and governmental proceedings from time to time arising in the ordinary course of business. While the outcome of lawsuits or other proceedings involving the Royalty Properties cannot be predicted with certainty, these matters are not expected to have a material adverse effect on the financial position or cash proceeds and distributable cash of the Trust.
SUPPLEMENTAL INFORMATION TO FINANCIAL STATEMENTS (UNAUDITED)
OIL AND GAS RESERVES
The following table sets forth changes in the Royalty Interests' proved oil and gas reserves (all located in the United States) for each of the three years ended December 31, 2000. The year-end reserves were prepared by Ryder Scott Company, independent petroleum consultants. Proved reserve quantities for each of the Wasson Royalties are calculated by multiplying the net revenue interest attributable to each of the Wasson Royalties in effect for a given year by the total amount of oil estimated to be economically recoverable from the respective production units, subject to quarterly production limitations and additional "Support Payments." The volume of reserves attributable to the Support Payments is calculated assuming an additional royalty interest in the Wasson ODC property. Reserve quantities are calculated differently for the Net Profits Royalties because such interests do not entitle the Trust to a specific quantity of oil or gas but to the Net Proceeds derived therefrom. Proved reserves attributable to the Net Profits Royalties are calculated by deducting from estimated quantities of oil and gas reserves an amount of oil and gas sufficient, if sold at the prices used in preparing the reserve estimates for the Net Profits Royalties, to pay the future estimated costs and expenses deducted in the calculation of Net Proceeds with respect to the Net Profits Royalties. Accordingly, the reserves presented for the Net Profits Royalties reflect quantities of oil and gas that are free of future costs or expenses if the price and cost assumptions set forth in the applicable reserve report occur.
The following estimates of proved and proved developed reserve quantities and related standardized measure of discounted net cash flows are estimates only, and do not purport to reflect realizable values or fair market values of the Trust's reserves. It is emphasized that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
The information presented relates to the operations of the Royalty Properties for the calendar years ended December 31, 2000, 1999 and 1998. Proceeds from the sales of production were received by the Trust during the second, third and fourth quarters of the year indicated and the first quarter of the subsequent year.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVE QUANTITIES
The standardized measure of discounted future net cash flows is computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent a year to reflect the estimated timing of the future cash flows.
Estimated future cash flows represent an estimate of future net revenues from the production of proved reserves using estimated sales prices and estimates of the production costs, ad valorem and production taxes, and future development costs necessary to produce such reserves. No deduction has been made for depletion, depreciation or any indirect costs such as professional and administrative fees.
The sales prices used in the calculation of estimated future net cash flows are based on the prices in effect at year-end with consideration of price changes only to the extent provided by contractural arrangements in existence at year-end.
Operating costs and ad valorem and production taxes are estimated based on current costs with respect to producing oil and gas properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions.
The information presented with respect to estimated future net revenues and cash flows and the present value thereof is not intended to represent the fair value of oil and gas reserves. Actual future sales prices and production and development costs may vary significantly from those in effect at December 31, 2000, 1999 and 1998 and actual future production may not occur in the periods or amounts projected. This information is presented to allow a reasonable comparison of reserve values prepared using standardized measurement criteria and should be used only for that purpose.
The standardized measure of discounted future net cash flows from the Royalty Interests' proved oil and gas reserve quantities at December 31, 2000, 1999 and 1998 are presented in the following table (in thousands of dollars):
As of December 31, 2000 total estimated future net cash flows available for Support Payments were approximately $14.8 million.
The following table sets forth the changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands of dollars):
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(a) Relates to the operations of the Royalty Properties for the calendar years ended December 31, 2000, 1999 and 1998. The proceeds related to such operations were received by the Trust during the second, third and fourth quarters of the year indicated and the first quarter of the subsequent year.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED ON THIS 2ND DAY OF APRIL, 2001.
The Registrant, Santa Fe Energy Trust, has no principal executive officer, principal financial officer, controller or principal accounting officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided.