Certain Definitions

As used herein, the following terms have the meanings indicated: “Bbl” means barrel, “MBbls” means thousand barrels, “Mcf” means thousand cubic feet and “MMcf” means million cubic feet. Natural gas volumes are converted to “barrels of oil equivalent” using the ratio of six Mcf of natural gas to one barrel of crude oil.

PART I

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, JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank, successor by merger to Chase Bank of Texas, National Association, formerly Texas Commerce Bank National Association (the “Trustee” or “JPMorgan Chase Bank”), 700 Lavaca, Austin, Texas 78701. The telephone number of the Trust is (800) 852-1422. On our web site, located at “www.businesswire.com/cnn/sff.htm”, we post the following filings as soon as reasonably practicable after they are electronically filed with or furnished to the Securities and Exchange Commission: our annual reports on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. All such filings on our web site are available free of charge.

The Trust will terminate on or before February 15, 2008. 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 Energy Production Company, L.P. (“Devon”), successor by merger to Devon SFS Operating, Inc., formerly Santa Fe Snyder Corporation, formerly Santa Fe Energy Resources, Inc. and JPMorgan Chase Bank (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 JPMorgan Chase Bank, 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. Please read “Description of the 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”). Through December 31, 2003, the principal asset of the Trust

consisted 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 11 states (collectively, the “Royalty Interests”). The Trust’s conveyed ownership in the Wasson Willard Unit, as well as the Wasson Willard Royalty, terminated on December 31, 2003. As of December 31, 2005 and December 31, 2004, respectively, the principal asset of the Trust consisted of the Wasson ODC Royalty and the Net Profits Royalties. As of December 31, 2005, the Net Profits Royalties conveyed to the Trust were located in seven states.

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 terminate 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 $136,000. 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 totaled $612,000, $494,000 and $439,000 in 2005, 2004 and 2003, respectively, although such costs could be more or less in subsequent periods depending on future events. In addition, the Trust paid Devon an annual fee of $304,000, $294,000 and $285,000 in 2005, 2004 and 2003, 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).

Calendar Quarters in the Year Ending December 31,	Wasson ODC Royalty Quarterly Gross Production Limitation (MBbls)		Wasson ODC Royalty Maximum Net Quarterly Production (MBbls)
2006		502		62.2
2007		486		60.2

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 entitled the Trust to receive quarterly royalty payments with respect to oil production from the Wasson Willard Unit for each calendar quarter during the period ended December 31, 2003. The royalty payable for any calendar quarter was 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 was 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. The Trust’s conveyed ownership in the Wasson Willard Unit, as well as the Wasson Willard Royalty which was approximately $1.4 million in 2003, terminated on December 31, 2003, with final distribution made in the first quarter of 2004.

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 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.

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 61% of the oil and gas production attributable to the Trust in 2005. Sales of properties would reduce this percentage further.

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 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 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 fourth calendar quarter with respect to gas is attributable to production in the months of August, September and October (for which Devon would have received payment from the purchasers in October, November and December, respectively). Since proceeds from the sale of production from the Wasson ODC Unit are received within one month of production, payments in respect of the Wasson ODC Royalty 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” (please read “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. Please read “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.

Termination and Liquidation of the Trust

The Trust will terminate and the Net Profits Royalties are to 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 Net Profits Royalties and, when applicable, the Wasson Willard Royalty. 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, 2006, 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. Any 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 would be a long-term capital gain or loss, except to the extent of the depletion recapture amount (as described below). 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 would be a short-term capital gain which is subject to tax at ordinary income tax rates.

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. Please read “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.

The Trust is registered as a tax shelter under prior law. This may increase the risk of an audit of the Trust or a Holder.

Prior to the enactment of the American Jobs Creation Act of 2004, certain types of entities were required to register with the IRS as “tax shelters,” based on a perception that those entities might claim tax benefits that were unwarranted. The Trust registered as a tax shelter under such prior law. The American

Jobs Creation Act of 2004 repealed the tax shelter registration requirement and replaced it with a regime that requires reporting, and may require registration, of certain “reportable transactions.” See “Reportable Transactions” below. It is not anticipated that the Trust will engage in any reportable transactions. Nevertheless, the likelihood that the Trust or a Holder will be audited may be higher because the Trust registered as a tax shelter under prior law, and might be increased if the Trust were to participate in a reportable transaction. Any such audit might lead to tax adjustments.

Reportable Transactions

If the Trust were to engage in a “reportable transaction,” the Trust (and possibly its Holders) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million. The Trust’s participation in a reportable transaction could increase the likelihood that the Trust’s federal income tax information return (and possibly a Holder’s tax return) would be audited by the IRS.

Moreover, if the Trust were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, its Holders may be subject to the following provisions of the American Jobs Creation Act of 2004:

· accuracy-related penalties,

· for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and

· in the case of a listed transaction, an extended statute of limitations.

It is not anticipated that the Trust will engage in any “reportable transactions.”

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 or has owned the Royalty Interests burdening oil and gas properties located in Alabama, Arkansas, Colorado, Kansas, Louisiana, Mississippi, New Mexico, North Dakota, Oklahoma, Texas, Wyoming, and in state waters offshore Louisiana. 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 41% 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 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 United States Treasury stripped interest coupons. 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. The Trust’s conveyed ownership in the Wasson Willard Unit terminated at the end of 2003. 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. The Wasson Royalties are not subject to development costs or operating costs (including CO2 acquisition costs).

The Wasson ODC Unit is a production unit 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 310 producing wells and is operated by Occidental Petroleum Limited. Production attributable to Devon’s royalty interest in the Wasson ODC 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 the same to such points. Devon may sell its royalty interests in the Wasson Field subject to and burdened by the Wasson ODC Royalty, without the consent of the Trustee of the Trust or the Holders. The Wasson ODC Royalty 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 seven states. Approximately 60% 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 in state waters offshore Louisiana. 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. Please read “Description of the Trust—Other Matters.”

Devon estimates that as of December 31, 2005, the Net Profits Properties covered approximately 208,000 gross acres (approximately 31,000 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

The value of the Depositary Units and the Trust Units evidenced thereby substantially depend on 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.

A study of the proved oil and gas reserves attributable to the Trust as of December 31, 2005 has been made by Ryder Scott Company, L.P., 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 23, 2006

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, 2005 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 Energy Corporation (Devon). The interests conveyed to the Trust consist of royalty interests in the Wasson ODC and Willard Units 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 Trust’s conveyed ownership in the Willard Unit terminated at the end of 2003. Therefore, as of this report date, there is no further consideration of this interest in this unit in this report. The properties included in the Trust are located in the states of Arkansas, Louisiana, New Mexico, North Dakota, Oklahoma, Texas and Wyoming.

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, 2005 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, 2005 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, 2005 are presented below:

	Santa Fe Energy Trust As of December 31, 2005
	Liquids (MBbls)	Gas (MMCF)		Estimated Future Net Cash Inflows (M$)		Present Value at 10% (M$)
Proved Net Developed and Undeveloped
Wasson ODC Royalty	489.8		0		25,101.2	22,871.4
Wasson Willard Royalty	0		0		0	0
Net Profits Royalties	785.0		3,894		77,847.4	42,768.6
Totals	1,274.8		3,894		102,948.6	65,640.0
Proved Net Developed
Wasson ODC Royalty	489.8		0		25,101.2	22,871.4
Wasson Willard Royalty	0		0		0	0
Net Profits Royalties	785.0		3,894		77,847.4	42,768.6
Totals	1,274.8		3,894		102,948.6	65,640.0

The estimated proved reserves and income quantities for the Wasson ODC Royalty presented in this report are calculated by multiplying the net revenue interest attributable to the Wasson ODC Royalty by the total amount of oil estimated to be economically recoverable from the productive unit, subject to production limitations applicable to the Wasson ODC Royalty, which has been described to us by Devon.

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 through 2002, at which time the Support Payments terminated. Therefore, as of this report date, there is no further consideration of these support payments.

The “Liquid” reserves shown in this report are comprised of crude oil, condensate and natural gas liquids. Natural gas liquids comprise 0.9 percent of the Trust’s developed liquid reserves and 0.9 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;

(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, 2005 are presented as follows.

	Santa Fe Energy Trust As of December 31, 2005
	Net Profits Royalties
	Royalty Interests		Working Interests	Totals	Wasson ODC Royalties		Totals
Total Proved
Future Cash Inflows (M$)		8,398.1	69,449.3	77,847.4		27,261.6	105,109.0
Future Costs
Production (M$)		0	0	0		2,160.4	2,160.4
Development (M$)		0	0	0		0	0
Total Costs (M$)		0	0	0		2,160.4	2,160.4
Future Net Cash Inflows
Before Income Tax (M$)		8,398.1	69,449.3	77,847.4		25,101.2	102,948.6
Present Value at 10%
Before Income Tax (M$)		4,395.0	38,373.6	42,768.6		22,871.4	65,640.0
Proved Net Developed Reserves
Liquids (MBbls)		105.8	679.2	785.0		489.8	1,274.8
Gas (MMCF)		309	3,585	3,894		0	3,894
Proved Net Undeveloped Reserves
Liquids (MBbls)		0	0	0		0	0
Gas (MMCF)		0	0	0		0	0
Total Proved Net Reserves
Liquids (MBbls)		105.8	679.2	785.0		489.8	1,274.8
Gas (MMCF)		309	3,585	3,894		0	3,894

In the case of the Wasson ODC Royalty, the future cash inflows are gross revenues before any 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, 2005 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, 2005 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, 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, 2005 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 and certain transportation costs. 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 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 2005.

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.
	/s/ FRED W. ZIEHE
	Fred W. Ziehe, P.E. Managing Senior Vice President

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 “—Description of the Treasury Obligations” and “—Description of the Royalty Properties” 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 interest in the Wasson ODC 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 affect the amount of oil imported from other countries and to impose pollution control measures.

Federal Regulation of Gas. Sales of gas from 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 the gas operations including marketing and production of gas. Under the Natural Gas Act of 1938 (the “NGA”), 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 and transportation was substantially modified by the Natural Gas Policy Act of 1978 (the “NGPA”), 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 that may be in effect. The FERC’s jurisdiction over interstate 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. Following the passage by Congress of the NGPA, the FERC adopted a series of regulatory changes that have significantly altered the transportation and marketing of natural gas. Beginning in October 1985, the FERC implemented a series of major pipeline restructuring orders that have, among other things, increased the transparency of pipeline transactions by expanding the internet posting and reporting requirements for pipeline transactions, required pipelines to treat their energy affiliates on a similar basis to unaffiliated shippers, and required pipelines to perform “open access” transportation of gas owned by others, “unbundle” their sales and transportation functions, and allow shippers to release their unneeded capacity temporarily and permanently to other shippers. These various orders have sought 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 under the NGPA, the FERC expanded the impact of certain aspects of its open access regulations to intrastate pipelines offering service through their facilities in interstate commerce.

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. The Trust 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. It remains to be seen, however, what effect the FERC’s other activities will have on access to markets, the fostering of competition and the cost of doing business. The Trust 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. The Trust does not believe that it will be affected by any such new or different regulations materially differently than other sellers of natural gas with which it competes.

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, or “lighter handed” regulation, and the promotion of competition in the gas industry. In light of this increased reliance on market forces, under the provisions of the Energy Policy Act of 2005, the NGA has been amended to prohibit any forms of market manipulation in connection with the transportation, purchase or sale of natural gas, and the FERC has been directed to establish new regulations that are intended to increase natural gas pricing transparency through, among other things, expanded dissemination of information about the availability and prices of gas sold. The 2005 Act also significantly increases the penalties for violations of the NGA, to up to $1 million per day for each violation. There regularly 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. Again, the Trust does not believe that it will be affected by any such new legislative proposals materially differently than any other sellers of natural gas with which it competes.

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. Every five years, the FERC is required to examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The second of these required reviews was commenced in July of 2005, where the FERC has proposed to continue the use of a similar indexing methodology for a further five year period. Another FERC proceeding that may impact oil pipeline transportation costs relates to an ongoing proceeding to determine whether and to what extent oil pipelines should be permitted to include in their transportation rates an allowance for income taxes attributable to non-corporate partnership interests. Following a court remand, the FERC has established a policy that a pipeline structured as a master limited partnership or similar non-corporate entity is entitled to a tax allowance with respect to income for which there is an “actual or potential income tax liability”, to be determined on a case by basis. Devon is not able to predict with certainty what effect, if any these 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, pollution control and requiring consistency with applicable coastal zone management plans. 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 generally have an effect on the Trust only to the extent of revenues attributable to the Trust’s interests in the Royalty Properties. If the Trust were held not to be an “express trust,” a Holder could be jointly and severally liable under the environmental laws for operations or contamination on the Royalty Properties.

Solid and Hazardous Waste. The Royalty Properties include numerous properties that have produced oil and gas for many years. 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 stringent. Under these 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), to perform remedial plugging operations to prevent future contamination and/or to compensate government agencies for damage to natural resources.

The operators of the Royalty Properties generate wastes that are subject to the Federal Resource Conservation and Recovery Act and comparable state statutes. These laws limit the disposal options for hazardous wastes. Federal and state agencies also regularly evaluate the potential 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 authorizes the EPA and certain third parties to take actions in response to hazardous substance releases 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 or related state laws for all or part of the costs to clean up sites at which such wastes have been disposed, as well as for damages for injury to natural resources.

Oil Spills. The federal Oil Pollution Act of 1990 (“OPA”) and implementing federal regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term “waters of the United States” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns liability to each responisble party for oil removal costs and a variety of public and private damages.

Discharge of Pollutants. The Federal Water Pollution Control Act and implementing federal regulations and permits, govern the discharge of certain contaminants into waters of the United States, including the discharge of fill material into wetlands. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies may also require the cessation of construction or operation of certain facilities that are the source of unauthorized water discharges or the restoration of wetlands that have been improperly filled. Devon or the operators of the Royalty Properties could incur liability under these laws.

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. Devon or the operators of the Royalty Properties could incur liability under these laws.

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. Devon or the operators of the Royalty Properties could incur liability under these laws.

Item 1a. Risk Factors.

The Trust’s business activities, and the oil and gas industry in general, are subject to a variety of risks. If any of the following risk factors should occur, the Trust’s profitability, financial condition and/or liquidity could be materially impacted. As a result, Holders could lose part or all of their investment in the Trust.

Oil, natural gas and NGL prices are volatile.

The Trust’s financial results are highly dependent on the prices of and demand for oil, natural gas and NGLs. A significant downward movement of the prices for these commodities could have a material adverse effect on the Trust’s estimated proved reserves, sales and profitability. Historically, prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond the Trust’s control. These factors include, but are not limited to:

· consumer demand for oil, natural gas and NGLs;

· OPEC production restraints;

· weather conditions or acts of force majeure;

· the level of imports and exports of oil, natural gas and NGLs;

· the price and availability of alternative fuels;

· the overall economic environment; and

· governmental regulations and taxes.

The operators of the Net Profits Properties and any transferee have the right to abandon any well or 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.

Estimates of oil, natural gas and NGL proved reserves are uncertain and may change if the assumptions on which such estimates are based prove to be incorrect.

The amount of future cash distributions to Holders depends upon, among other things, the accuracy of the production and reserves estimated to be attributable to the Royalty Interests. The process of estimating oil, gas and NGL reserves is complex, inherently uncertain and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir, particularly for new discoveries. Due to such judgment involved, different reserve engineers may develop different estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a given reservoir may change substantially over time as a result of several factors including additional development activity, the viability of production under varying economic conditions and variations in production levels and associated costs. Consequently, material revisions to existing reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have a material adverse effect on the Trust’s estimates of future net revenue, as well as the Trust’s financial condition and profitability.

Future exploratory drilling involves substantial expenditures and may not result in commercially productive reservoirs. Distributions to Holders may be adversely affected by many hazards.

Substantial costs are often required to locate properties and drill exploratory wells. Such activities are subject to numerous risks, including the risk that we will not encounter commercially productive oil or gas

reservoirs. In addition, oil and gas properties can become damaged or drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:

· unexpected drilling conditions;

· pressure or irregularities in reservoir formations;

· equipment failures or accidents;

· fires, explosions, blow-outs and surface cratering;

· marine risks such as capsizing, collisions and hurricanes;

· personal injuries;

· damage to productive formations;

· other adverse weather conditions;

· lack of access to pipelines or other methods of transportation;

· environmental hazards or liabilities; and

· shortages or delays in the delivery of equipment.

Distributions to Holders could be adversely affected if any of the hazards described above were to occur. 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.

A significant occurrence of one of these factors could result in a partial or total loss of the Trust’s investment in a particular property. In addition, drilling activities may not be successful in establishing proved reserves. Such a failure could have an adverse effect on the Trust’s future results of operations and financial condition. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.

The Wasson ODC Royalty has been structured with a quarterly production limitation. Thus, the Trust and the Holders will not receive cash distributions from oil production from the Wasson ODC production unit burdened by the Wasson ODC Royalty in excess of such amount. Failure of actual production from the Wasson ODC production unit to meet or exceed applicable quarterly production limitation will reduce amounts payable with respect to the Wasson ODC Royalty.

The Trust is passive in nature and has no control over the field operations of, sale of oil or gas from, or development of the underlying properties.

Oil and gas properties are typically managed pursuant to an operating agreement among the working interest owners of the interest in the properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the Trustee nor the Holders has any contractual ability to influence or control the field operations of, sale of oil or gas from, 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 a working interest in the Wasson ODC 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. A prolonged oil price downturn in the future 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, the Trustee or the Holders 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 Depositary Units are passive investments that entitle the Holders to only receive cash distributions from the Royalty Interests.

The oil and gas reserves attributable to the underlying properties of the Trust are depleting assets and production from those reserves will diminish over time. The Trust is precluded from acquiring other oil and gas properties or royalty interests to replace the depleting assets and production.

The net proceeds payable to the Trust from the Royalty Properties are derived from the sale of the production of oil and gas from the underlying properties. The oil and gas attributable to the underlying properties are depleting assets, which means that the reserves of gas attributable to the underlying property will decline over time. As a result, the quantity of oil and gas produced from the underlying properties is expected to decline over time. The oil and gas production from proved reserves attributable to the Trust in the year preceding the Liquidation Date is expected to be approximately 61% of the oil and gas production attributable to the Trust in 2005. Sales of properties would reduce this percentage further. Additionally, future maintenance projects on the wells to which the underlying properties beyond that which is currently estimated may affect the quantity of proved reserves that can be economically produced from the wells to which the underlying properties relate. If operators of the wells do not implement required maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently estimated in the reserve report.

Government laws and regulations can change.

The Trust’s operations are subject to federal laws and regulations of the United States. In addition, the Trust is also subject to those laws and regulations of various states and local governments. Pursuant to such laws and regulations, numerous government departments and agencies have also issued extensive rules binding on the oil and gas industry and its individual members. Some of these laws, regulations and rules carry substantial penalties for failure to comply. Changes in such laws, regulations and rules have, and at times in the future could, affect the Trust’s future operations. Political developments can restrict production levels, enact price controls, change environmental protection requirements, and increase taxes, royalties and other amounts payable to governments or governmental agencies. Although the Trust is unable to predict changes to existing laws and regulations, such changes could significantly impact the Trust’s profitability.

Environmental matters and costs can be significant.

The Trust is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the Trust for the cost of pollution clean-up resulting from the Trust’s operations in affected areas.

The Trust will terminate on or before February 15, 2008. The full liquidation value of the Trust after its termination is uncertain.

The Trust will terminate and the Net Profits Royalties are to be sold on or before the Liquidation Date, February 15, 2008. Each holder of Depositary Units of record as of the day next preceding the Liquidation Date will be entitled to receive a liquidating distribution equal to (1) $20 per Depositary Unit from the proceeds of the matured Treasury Obligations, plus (2) a pro rata portion of the net proceeds from the sale of Net Profits Royalties, to the extent not previously distributed. Following the Liquidation Date, Holders will no longer receive quarterly distributions and the Depositary Units will no longer trade. Please read “Description of the Trust Units and Depositary Units—Termination and Liquidation of the Trust.”

The timing of sales of Net Profits Royalties, future oil and gas prices and future production levels are uncertain. These and other factors make uncertain the ultimate liquidation value of the Trust for matters unrelated to the Treasury obligations.

Item 1b. Unresolved Staff Comments.

Not applicable.

Item 2. Properties.

Reference is made to Item 1 of this Form 10-K.

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. Submission of Matters to a Vote of Security Holders.

There were no matters submitted to a vote of the Holders during the year ended December 31, 2005.

PART II

Item 5. Market for Registrant’s Units and Related Holder Matters.

The Depositary Units are traded on the New York Stock Exchange under ticker symbol SFF. The high and low sales prices and distributions for each quarter in the years ended December 31, 2005 and 2004 were as follows (in dollars):

	Sales Prices				Distribution
	Low		High		Paid
2004:
First Quarter	$	27.25	$	30.50		$	0.71784
Second Quarter	26.30		30.21			0.68670
Third Quarter	27.50		31.45			0.76869
Fourth Quarter	28.25		34.47			0.93712
2005:
First Quarter	$	31.97	$	38.00		$	0.92772
Second Quarter	33.30		39.50			0.90372
Third Quarter	39.05		44.90			1.32023		(a)
Fourth Quarter	25.74		43.65			0.84909

(a) Includes proceeds from the sale of Net Profits Properties of $2.4 million or $0.37372 per Trust Unit.

At February 28, 2006, the 6,300,000 Depositary Units outstanding were held by 207 holders of record.

Securities Authorized for Issuance Under Equity Compensation Plans

None.

Item 6. Selected Financial Data.

	2005		2004		2003		2002		2001
	(thousands, except per unit data)
Year Ended December 31:
Total Royalties	$	26,109	$	20,364	$	22,193	$	11,659	$	19,011
Distributable Cash	25,205		19,595		21,383		11,135		18,422
Distributable Cash per Trust Unit	4.00076		3.11035		3.39421		1.76729		2.92414
At December 31:
Investment in Royalty Interests, net	$	4,847	$	7,191	$	9,905	$	13,137	$	16,951
Trust Corpus	4,940		7,296		10,029		13,175		17,007

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

General; Liquidity and Capital Resources

The Trust was formed on October 22, 1992. The Trust holds Royalty Interests in the Royalty Properties conveyed to the Trust by Devon. The Trust is a passive entity that collects royalty income generated by the Royalty Properties.

The Trust’s results of operations depend on 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.

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 oil 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 per Bbl for 2005, 2004 and 2003 was $44.88, $32.49 and $27.87, respectively.

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 2005, 2004 and 2003 was $5.62, $5.04 and $4.56, respectively.

Trust expenses include accounting, engineering, legal and other professional fees, Trustee fees, an administrative fee paid to Devon and other out-of-pocket expenses. Please read Item 1, Business, for a more detailed discussion of the Trust and its business. 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. The Trust will terminate on or before February 15, 2008 (the “Liquidation Date”).

The Trust’s ability to pay expenses primarily depends on receipt of royalty income. Devon may, at its sole discretion and without obligation to do so, advance funds to the Trust to enable the Trust to pay expenses. The Trustee is authorized to borrow funds required to pay liabilities of the Trust, provided that any such borrowings are repaid in full prior to making further distributions to Holders. As of December 31, 2005, Devon had no outstanding advances to the Trust.

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 2006 reflects revenues received and costs and expenses paid by Devon in the fourth quarter of 2005. On February 28, 2006, the Trust made a cash distribution of $6.2 million, or $0.98324 per Trust Unit, to Holders of record on February 15, 2006.

										First
	Year Ended December 31,									Quarter
	2005			2004			2003			2006
										(Unaudited)
*Volumes and Prices*
Oil Volumes (Bbls):
Wasson ODC Royalty	274,100			296,800			282,000				66,400
Wasson Willard Royalty(1)	—			12,000			51,200				—
Net Profits Royalties	183,386			191,794			170,918				38,928
Gas Volumes (Mcf):
Net Profits Royalties	1,286,273			1,378,071			1,428,824				197,048
Oil Average Prices ($/Bbl):
Wasson ODC Royalty	$	48.00		$	34.41		$	28.68			$	53.83
Wasson Willard Royalty(1)	—			28.50			28.52				—
Net Profits Royalties	40.22			29.77			26.32				53.82
Gas Average Prices ($/Mcf):
Net Profits Royalties	$	5.62		$	5.04		$	4.56			$	7.98
*Cash Proceeds and Distributable Cash (in thousands of dollars, except as noted)*
Wasson ODC Royalty:
Sales	$	13,156		$	10,213		$	8,089			$	3,574
Operating Expenses	(695		)	(718		)	(532		)		(170		)
	12,461			9,495			7,557				3,404
Wasson Willard Royalty(1):
Sales	—			342			1,460				—
Operating Expenses	—			(10		)	(59		)		—
	—			332			1,401				—
Net Profits Royalties:
Sales	14,604			12,657			11,074				3,676
Proceeds From the Sale of Property	2,354			—			4,572				—
Operating Expenses	(2,768		)	(2,323		)	(2,272		)		(674		)
Capital (Expenditures) Recoveries	(542		)	203			(139		)		(35		)
	13,648			10,537			13,235				2,967
Total Royalties	26,109			20,364			22,193				6,371
Administrative Fee to Devon	(304		)	(294		)	(285		)		(77		)
Payment Received	25,805			20,070			21,908				6,294
Cash Withheld for Trust Expenses	(600		)	(475		)	(525		)		(100		)
Distributable Cash	$	25,205		$	19,595		$	21,383			$	6,194
Distributable Cash Per Unit	$	4.00076		$	3.11035		$	3.39421			$	0.98324

(1) 2004 production, sales and operating expenses for the Wasson Willard Unit are related to calendar year 2003 operations. These are the last production, sales and operating expenses the Trust will report since the Trust’s conveyed ownership in the Wasson Willard Unit terminated on December 31, 2003.

Sales increased $4.5 million from 2004 to 2005. Sales increased $5.7 million and $0.7 million, respectively, due to a $12.39 per barrel increase in the average price of oil from $32.49 per barrel in 2004 to $44.88 per barrel in 2005, and a $0.58 per Mcf increase in the average gas price from $5.04 per Mcf in 2004 to $5.62 per Mcf in 2005. A production decrease of approximately 58,000 barrels of oil equivalent from 2004 to 2005 caused sales to decrease $1.9 million. The decrease was primarily due to production decreases resulting from the sale of certain Net Profits properties, the declining maximum Wasson ODC royalty and the termination of the Trust’s conveyed ownership in the Wasson Willard Unit.

Sales increased $2.6 million from 2003 to 2004. Sales increased $2.3 million and $0.6 million, respectively, due to a $4.62 per barrel increase in the average price of oil from $27.87 per barrel in 2003 to $32.49 per barrel in 2004, and a $0.48 per Mcf increase in the average gas price from $4.56 per Mcf in 2003 to $5.04 per Mcf in 2004. A production decrease of approximately 12,000 barrels of oil equivalent from 2003 to 2004 caused sales to decrease $0.3 million. The decrease was mainly due to the termination of the Trust’s conveyed ownership in the Wasson Willard Unit partially offset by production increases for the Wasson ODC Royalty and the Net Profits Royalties.

Proceeds from the sale of property were $2.4 million in 2005 and $4.6 million in 2003 due to the sale of certain Net Profits Properties in those years.

Operating expenses increased $0.4 million from 2004 to 2005 and $0.2 million from 2003 to 2004. These increases were primarily related to timing of payments and increases in recurring lease operating expenses and ad valorem taxes.

Proceeds from the Net Profits Properties are net of capital expenditures with respect to the development of the Net Profits Properties. Capital expenditures in 2005 and 2003 totaled $542,000 and $139,000. Capital recoveries in 2004 were $203,000.

Cash withheld for trust expenses remained essentially flat from 2003 to 2004 and increased $0.1 million from 2004 to 2005. This change was primarily related to timing of payments and an increase in fees from external tax accountants and attorneys.

Critical Accounting Policies

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, and an administrative fee paid to Devon and out-of-pocket expenses are recognized when paid. Under accounting principles generally accepted in the United States of America, revenues and expenses would be recognized on an accrual basis. Amortization of the Trust’s investment in Royalty Interest 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 Trust’s use of cash basis accounting is based upon the focus of the Trust’s operations to distribute available cash to Holders on a quarterly basis.

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. Quantitative and Qualitative Disclosures About Market Risk.

Not applicable.

Item 8. Financial Statements and Supplementary Data.

See Item 15 for the Exhibits and Financial Statement Schedules.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9a. Controls and Procedures.

Disclosure Controls and Procedures

The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by Devon to JPMorgan Chase Bank, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, the Trustee carried out an evaluation of the Trustee’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the controls and procedures are effective.

Due to the contractual arrangements of (i) the Trust Agreement and (ii) Devon’s conveyances of the Royalty Interests to the Trust regarding information furnished by the working interest owners, the Trustee relies on (i) information provided by Devon and the working interest owners, including all information relating to the Royalty Properties burdened by the Royalty Interests, such as operating data, data regarding operating and capital expenditures, geological data relating to reserves, information regarding environmental and other conditions relating to the Royalty Properties, liabilities and potential liabilities potentially affecting the revenues to the Trust’s interest, the effects of regulatory changes and of the compliance of the operators of the Royalty Properties with applicable laws, rules and regulations, the

number of producing wells and acreage, and plans for future operating and capital expenditures, and (ii) conclusions of independent reserve engineers regarding reserves. The conclusions of the independent reserve engineers are based on information received from Devon and the working interest owners.

Changes in Internal Control Over Financial Reporting.

To the knowledge of the Trustee, there have not been any changes in the Trust’s internal control over financial reporting during the fiscal quarter ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Devon and the working interest owners.

Due to the nature of the Trust, as well as the nature of the underlying Royalty Interests, there may be inherent weaknesses that are not subject to change or modification by the Trustee or its employees. 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 a working interest in the Wasson ODC Unit and may be able to exercise some influence, though not control, over unit operations. The contractual limitations creating inherent weaknesses in disclosure controls and procedures may be deemed to include:

· The working interest owners alone control (i) historical operating data, including production volumes, marketing of products, operating and capital expenditures, environmental and other liabilities, the effects of regulatory changes and the number of producing wells and acreage, (ii) plans for future operating and capital expenditures, (iii) geological data relating to reserves and (iv) projected production. Neither the Trustee nor Devon (to the extent Devon is not also the working interest owner) control this information, and they rely entirely on the working interest owners to provide accurate and timely information when requested for use in the Trust’s reports.

· The Trustee relies on information provided by Devon that is collected by Devon from working interest owners. While the Trustee may request information through Devon, only Devon has authority to request and receive financial information regarding the Royalty Properties from the working interest owners. The Trustee generally does not have any direct contact with working interest owners, other than Devon, and relies on Devon to request and obtain information for use in the Trust’s reports.

· Under the terms of the Trust Agreement, the Trustee is entitled to, and in fact does rely, upon certain experts in good faith, including the independent reserve engineer with respect to the annual reserve report. The conveyances also restrict access to and the review of confidential data provided by Devon and working interest owners. While the Trustee has no reason to believe its reliance upon experts is unreasonable, this reliance on experts and restricted access to information may be viewed as a weakness.

The Trustee does not intend to expand its responsibilities beyond those permitted or required by the Trust Agreement.

Internal Control Over Financial Reporting

TRUSTEE’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

JPMorgan Chase Bank, N.A. (the “Trustee”), of Santa Fe Energy Trust is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f).

Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.

Under the supervision and with the participation of the Trustee, the Trustee conducted an evaluation to assess the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2005 based upon criteria set forth in the framework Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the Trustee’s assessment, the Trustee concludes that, as of December 31, 2005, the Trust’s internal control over financial reporting is effective.

The Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2005 has been audited by KPMG LLP, an independent registered public accounting firm who audited the Trust’s financial statements as of and for the year ended December 31, 2005, as stated in their report which is included herein.

	SANTA FE ENERGY TRUST
	by: JPMorgan Chase Bank, N.A., Trustee
	By:	/s/ Mike Ulrich
		Mike Ulrich Vice President and Trust Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Trustee and Unitholders
Santa Fe Energy Trust:

We have audited the Trustee’s assessment, included in the accompanying Trustee’s Report on Internal Control Over Financial Reporting, that Santa Fe Energy Trust maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trustee of Santa Fe Energy Trust is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the Trustee’s assessment and an opinion on the effectiveness of the Trust’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating the Trustee’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Trustee’s assessment that Santa Fe Energy Trust maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Santa Fe Energy Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets and trust corpus of the Santa Fe Energy Trust as of December 31, 2005 and 2004, and the related statements of cash proceeds and distributable cash and changes in trust corpus for each of the years in the three-year period ended December 31, 2005, and our report dated March 14, 2006 expressed an unqualified opinion on those financial statements.

/s/ KPMG LLP
Oklahoma City, Oklahoma
March 14, 2006

Item 9b. Other Information.

None.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a)(1) Financial Statements

The following financial statements are included in this Annual Report on Form 10-K on the pages as indicated:

	Page in this Form 10-K
Audited Financial Statements
Report of Independent Registered Public Accounting Firm		43
Statements of Cash Proceeds and Distributable Cash for the Years Ended December 31, 2005, 2004 and 2003		44
Statements of Assets and Trust Corpus as of December 31, 2005 and 2004		44
Statements of Changes in Trust Corpus for the Years Ended December 31, 2005, 2004 and 2003		45
Notes to Financial Statements		46
Unaudited Financial Information
Supplemental Information to the Financial Statements		49

(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.)

		SEC File or Registration Number		Exhibit Number
3(a)*	Form of Trust Agreement of Santa Fe Energy Trust		33-51760		3.1
4(a)*	Form of Custodial Deposit Agreement		33-51760		4.2
4(b)*	Form of Secure Principal Energy Receipt (included as Exhibit A to Exhibit 4(a))		33-51760		4.1
10(a)*	Form of Net Profits Conveyance (Multi-State)		33-51760		10.1
10(b)*	Form of Wasson Conveyance		33-51760		10.2
10(c)*	Form of Louisiana Mortgage		33-51760		10.3
31	Certification required by Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934
32	Certification required by Rule 13a-14(b) or Rule 15d-14(b) under the Securites Exchange Act of 1934 and 18 U.S.C. Section 1350

SANTA FE ENERGY TRUST
STATEMENTS OF CASH PROCEEDS AND DISTRIBUTABLE CASH
(in thousands, except per unit data)

	Year Ended December 31,
	2005			2004			2003
Royalty income:
ODC royalty	$	12,461		$	9,495		$	7,557
Willard royalty	—			332			1,401
Net profits royalty	13,648			10,537			13,235
Total royalties	26,109			20,364			22,193
Administrative fee to Devon Energy Corporation	(304		)	(294		)	(285		)
Cash withheld for trust expenses	(600		)	(475		)	(525		)
Distributable cash	$	25,205		$	19,595		$	21,383
Distributable cash per trust unit	$	4.00076		$	3.11035		$	3.39421
Trust units outstanding	6,300			6,300			6,300

STATEMENTS OF ASSETS AND TRUST CORPUS
(in thousands, except unit data)

	December 31,
	2005			2004
ASSETS
Current assets—cash	$	93		$	105
Investment in royalty interests, at cost	87,276			87,276
Less: accumulated amortization	(82,429		)	(80,085		)
	4,847			7,191
Total assets	$	4,940		$	7,296
TRUST CORPUS
Trust corpus, 6,300,000 trust units issued and outstanding	$	4,940		$	7,296

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 JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank, successor by merger to Chase Bank of Texas, National Association formerly 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 Energy Production Company, L.P. (“Devon”), successor by merger to Devon SFS Operating, Inc., formerly Santa Fe Snyder Corporation, formerly Santa Fe Energy Resources, Inc. Through December 31, 2003, the Royalty Interests consisted 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 11 states (the “Net Profits Royalties”). On December 31, 2003, the term on the royalty interest in one of the Wasson production units terminated. 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 terminate on or before 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 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; and

SANTA FE ENERGY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)

(1) The Trust (Continued)

· 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 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 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 Statements 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

Through December 31, 2003, the Wasson Royalties consisted 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”). On December 31, 2003, the term on the royalty interest in the Wasson Willard unit terminated. 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 entitled 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.

SANTA FE ENERGY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)

(3) The Royalty Interests (Continued)

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.

(4) Distributions to Trust Unit Holders

The Trust has received royalty payments net of administrative fees paid to Devon and made distributions as follows:

	Royalty Payment			Distributions
	Received			Amount		Per Trust Unit
	(in thousands, except per unit data)
2005
First quarter	$	5,944		$	5,844		$	0.92772
Second quarter	5,744			5,694			0.90372
Third quarter	8,668		(a)	8,318			1.32023
Fourth quarter	5,449			5,349			0.84909
	$	25,805		$	25,205		$	4.00076
2004
First quarter	$	4,622		$	4,522		$	0.71784
Second quarter	4,427			4,327			0.68670
Third quarter	5,067			4,842			0.76869
Fourth quarter	5,954			5,904			0.93712
	$	20,070		$	19,595		$	3.11035
2003
First quarter	$	8,199	(b)	$	8,149		$	1.29361
Second quarter	4,389			4,239			0.67301
Third quarter	4,906			4,731			0.75075
Fourth quarter	4,414			4,264			0.67684
	$	21,908		$	21,383		$	3.39421

(a) Includes proceeds from the sale of Net Profits properties of $2.4 million or $0.37372 per Trust Unit.

(b) Includes proceeds from the sale of Net Profits properties of $4.6 million or $0.72565 per Trust Unit.

(5) Commitments and Contingencies

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, 2005. The year-end reserves were prepared by Ryder Scott Company, L.P., independent petroleum consultants. Proved reserve quantities for the Wasson ODC Royalty are calculated by multiplying the net revenue interest attributable to the Wasson ODC Royalty in effect for a given year by the total amount of oil estimated to be economically recoverable from the production unit subject to production limitations applicable to the Wasson ODC Royalty. Proved reserves for each of the three years ended December 31, 2005 do not include any reserves for the Willard Royalty. 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.

	Crude Oil and Liquids (MBbls)			Natural Gas (MMcf)
	(Unaudited)
Proved reserves at December 31, 2002		1,915			6,711
Revisions of previous estimates		397			932
Production		(511	)		(1,411	)
Proved reserves at December 31, 2003		1,801			6,232
Revisions of previous estimates		301			414
Production		(489	)		(1,447	)
Proved reserves at December 31, 2004		1,613			5,199
Revisions of previous estimates		118			723
Sales of minerals in place		(15	)		(953	)
Production		(441	)		(1,075	)
Proved reserves at December 31, 2005		1,275			3,894
Proved developed reserves at December 31,
2002		1,915			6,711
2003		1,801			6,232
2004		1,613			5,199
2005		1,275			3,894

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, 2005, 2004 and 2003. 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 contractual 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, 2005, 2004 and 2003, 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, 2005, 2004 and 2003 are presented in the following table (in thousands of dollars):

	December 31,
	2005			2004			2003
	(Unaudited)
Future cash inflows	$	105,109		$	97,364		$	90,954
Future production costs	2,160			2,466			2,529
Net future cash flows	102,949			94,898			88,425
Discount at 10% for timing of cash flows	(37,309		)	(28,086		)	(29,332		)
Standardized measure of discounted future net cash flows for proved reserves	$	65,640		$	66,812		$	59,093

The following table sets forth the changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands of dollars):

	2005			2004			2003
	(Unaudited)
Balance at beginning of year	$	66,812		$	59,093		$	58,031
Production, net of related property taxes(a)	(27,206		)	(21,689		)	(18,645		)
Sales of minerals-in-place	(5,173		)	—			—
Net changes in prices and costs	22,304			10,640			3,433
Revisions of previous estimates	2,108			12,653			10,653
Interest factor-accretion of discount	6,795			6,115			5,621
	(1,172		)	7,719			1,062
Balance at end of year	$	65,640		$	66,812		$	59,093

(a) Relates to the operations of the Royalty Properties for the calendar years ended December 31, 2005, 2004 and 2003. 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.

(Mark One)
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
	SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2005
	or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
	SECURITIES EXCHANGE ACT OF 1934

Texas	76-6081498
(State or Other Jurisdiction Incorporation or Organization)	(I.R.S. Employer Identification No.)
JPMorgan Chase Bank, N.A., Trustee
Institutional Trust Services
700 Lavaca
Austin, Texas	78701
(Address of Principal Executive Offices)	(Zip Code)

	Title of Each Class			Name of Each Exchange On Which Registered
Depositary Units, Evidenced by Secure Principal Energy Receipts			New York Stock Exchange

Balance at December 31, 2002	$	13,175
Cash proceeds	21,908
Cash distributions	(21,383		)
Trust expenses	(439		)
Amortization of royalty interests	(3,232		)
Balance at December 31, 2003	10,029
Cash proceeds	20,070
Cash distributions	(19,595		)
Trust expenses	(494		)
Amortization of royalty interests	(2,714		)
Balance at December 31, 2004	7,296
Cash proceeds	25,805
Cash distributions	(25,205		)
Trust expenses	(612		)
Amortization of royalty interests	(2,344		)
Balance at December 31, 2005	$	4,940

		Page
	PART I
Item 1.	Business	1
	Description of the Trust	1
	Description of the Trust Units and Depositary Units	5
	Description of the Treasury Obligations	14
	Description of the Royalty Properties	15
	Competition and Markets	24
	Governmental Regulation	24
Item 1a.	Risk Factors	28
Item 1b.	Unresolved Staff Comments	31
Item 2.	Properties	31
Item 3.	Legal Proceedings	31
Item 4.	Submission of Matters to a Vote of Security Holders	31
	PART II
Item 5.	Market for Registrant’s Units and Related Holder Matters	32
Item 6.	Selected Financial Data	32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 7a.	Quantitative and Qualitative Disclosures about Market Risk	36
Item 8.	Financial Statements and Supplementary Data	36
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	36
Item 9a.	Controls and Procedures	36
Item 9b.	Other Information	40
	PART III
Item 10.	Directors and Executive Officers of the Registrant	41
Item 11.	Executive Compensation	41
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Holder Matters	41
Item 13.	Certain Relationships and Related Transactions	41
Item 14.	Principal Accountant Fees and Services	41
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	42

		SANTA FE ENERGY TRUST
		By		JPMORGAN CHASE BANK, N.A. TRUSTEE
		By		/s/ MIKE ULRICH
				Mike Ulrich Vice President and Trust Officer

		SEC File or Registration Number		Exhibit Number
3(a)*	Form of Trust Agreement of Santa Fe Energy Trust	33-51760	3.1
4(a)*	Form of Custodial Deposit Agreement	33-51760	4.2
4(b)*	Form of Secure Principal Energy Receipt (included as Exhibit A to Exhibit 4(a))	33-51760	4.1
10(a)*	Form of Net Profits Conveyance (Multi-State)	33-51760	10.1
10(b)*	Form of Wasson Conveyance	33-51760	10.2
10(c)*	Form of Louisiana Mortgage	33-51760	10.3
31	Certification required by Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
32	Certification required by Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350.

	/s/ MIKE ULRICH
	Mike Ulrich
	Vice President and Trust Officer

	/s/ MIKE ULRICH
	Mike Ulrich,
Date: March 14, 2006	Vice President and Trust Officer