Santa Fe Energy Trust
(Exact name of Registrant as Specified in its Charter)

Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act). Yes o No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No ý

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

The aggregate market value of the outstanding Depositary Units held by non-affiliates of the Registrant as of June 30, 2006, was $185,220,000 based on the closing sales price of $29.40 per unit.

On February 14, 2008, immediately prior to the termination of the registrant, 6,300,000 Depositary Units were outstanding.


		Page
SPECIAL NOTE	1
Certain Definitions	1
PART I
Item 1.	Business	2
Item 1A.	Risk Factors	23
Item 1B.	Unresolved Staff Comments	23
Item 2.	Properties	24
Item 3.	Legal Proceedings	24
Item 4.	Submission of Matters to a Vote of Security Holders	24
PART II
Item 5.	Market for Registrant's Units, Related Holder Matters and Issuer Purchases of Units	24
Item 6.	Selected Financial Data	25
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	29
Item 8.	Financial Statements and Supplementary Data	29
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	29
Item 9A.	Controls and Procedures	29
Item 9B.	Other Information	35
PART III
Item 10.	Directors, Executive Officers of the Registrant and Corporate Governance	35
Item 11.	Executive Compensation	35
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	35
Item 13.	Certain Relationships and Related Transactions, and Director Independence	35
Item 14.	Principal Accounting Fees and Services	35
PART IV
Item 15.	Exhibits, Financial Statement Schedules	36
Appendix A	Reserve Report dated November 30, 2007 prepared by Ryder Scott Company, LP.	A-1

The filing of this Annual Report on Form 10-K for the year ended December 31, 2006 was delayed as a result of issues regarding certain overpayments to the Trust and related issues regarding the Trust's ownership of certain assets. As a result of those issues, the Trustee of Santa Fe Energy Trust concluded on May 1, 2007 that the Trust's previously-issued financial statements should no longer be relied upon, as set forth in the Trust's Report on Form 8-K filed on May 3, 2007. The Trustee subsequently determined to restate the Trust's financial statements for the years ended December 31, 2005 and 2004. The restated financial statements are included in this Annual Report on Form 10-K. The adjustments made as a result of the restatement are more fully discussed in Note 8 of the Notes to the Financial Statements of Santa Fe Energy Trust for the year ended December 31, 2006 and in Part II—Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations" included in this Annual Report on Form 10-K. For a description of the control deficiencies identified by the Trustee as a result of the overpayment issues and related issues as described in this Annual Report on Form 10-K, see Part II—Item 9A—"Controls and Procedures."

The Trust intends to file its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2007, June 30, 2007 and September 31, 2007 promptly after the filing of this Annual Report on Form 10-K for the year ended December 31, 2006.

On December 18, 2007, the Trust consummated the sale of all or substantially all of its assets to Amen Properties, Inc. and certain other purchasers for approximately $51.5 million, and, in accordance with the Trust's governing documents, the Trust liquidated on February 15, 2008. Unitholders received 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 (subject to reserves for expenses and contingencies) and a pro rata portion of the proceeds from the matured Treasury Obligations. See Item 1—"Business—Description of the Trust—Sale of Net Profits Royalties".

Trading in the Depositary Units was halted at the close of business on February 14, 2008, and the Depositary Units were delisted by the New York Stock Exchange at the same time. The Trust filed a Form 15 on March 17, 2008.

Readers are cautioned to review this Annual Report on Form 10-K in its entirety.

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.

Please see the Special Note at the beginning of this Annual Report on Form 10-K.

Santa Fe Energy Trust (the "Trust"), was created under the laws of the State of Texas and prior to its termination, maintained its offices at the office of the Trustee, The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A.), which purchased substantially all of the corporate trust business of the former 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 "The Bank of New York"), 919 Congress Avenue, Suite 500, Austin, Texas 78701. The telephone number of the Trust was (512) 479-2562. The Trust posted to the web site located at "www.businesswire.com/cnn/sff.htm" the following filings as soon as reasonably practicable after they were electronically filed with or furnished to the Securities and Exchange Commission: annual reports on Form 10-K, quarterly reports on Form 10-Q, 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 were made available free of charge.

The Trust has sold its assets and terminated on February 15, 2008. The Trust closed its transfer books and the Depositary Units were delisted by The New York Stock Exchange at the same time.

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 the Trustee (the "Trust Agreement"). Under the terms of the Trust Agreement, Devon conveyed royalty and net profits interests in certain oil and gas properties to the Trust. In exchange for the conveyance of such interests, the Trust issued 6,300,000 units of undivided beneficial interest ("Trust Units"). The Trust Units and the Treasury Obligations (hereinafter defined) were deposited with The Bank of New York, as depositary (the "Depositary"), in exchange for 6,300,000 Depositary Units (hereinafter defined). Each Depositary Unit consisted 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 were evidenced by Secure Principal Energy Receipts ("SPERs"), which were issued and transferable only in denominations of 50 Depositary Units or an integral multiple thereof. The Depositary Units were traded on the New York Stock Exchange under the symbol SFF until the close of business on February 14, 2008.

The Trust Units and Treasury Obligations were held by the Depositary for the holders of Depositary Units ("Holders"). The Treasury Obligations consisted of a portfolio of United States Treasury stripped interest coupons that matured 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 then issued and outstanding. Since Depositary Units were issued or transferred only in denominations of 50 or integral multiples thereof, each holder of 50 Depositary Units owned 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 did not pay current interest. Please read "Description of the Trust Units and Depositary Units—Federal Income Tax Matters".

The Trust was a grantor trust formed by Devon to hold 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, 2006 and December 31, 2005, respectively, the principal assets of the Trust consisted of the Wasson ODC Royalty and the Net Profits Properties. As of December 31, 2006, the Net Profits Royalties conveyed to the Trust were located in eight states. On December 18, 2007 the Net Profits Royalties were sold to Amen Properties, Inc. for approximately $51.5 million.

The terms of the Trust Agreement provided, 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 prior to liquidation; (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 Trust had no employees. Administrative functions of the Trust were performed by the Trustee, which was paid an annual fee of approximately $136,000. The Trust was 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 $609,000, $612,000 and $494,000 in 2006, 2005 and 2004, respectively. In addition, the Trust paid Devon an annual fee of $310,000, $300,000 and $289,000 in 2006, 2005 and 2004, respectively. The annual fee to Devon increased to $322,000 in 2007.

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 provided 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 owned the Royalty Properties that were subject to and burdened by the Royalty Interests. Prior to the Trust's sale of the Net Profits Royalties, Devon received all payments relating to the sale of production from the Royalty Properties and was 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 were computed with respect to each calendar quarter, and such amounts were paid by Devon to the Trust not later than 60 days after the end of each calendar quarter. The amounts paid to the Trust did not include interest on any amounts payable with respect to

the Royalty Interests which were held by Devon prior to payment to the Trust. Devon was entitled to retain any amounts attributable to the Royalty Properties which were 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.

The Wasson ODC Royalty. The Wasson ODC Royalty was conveyed out of Devon's 12.3934% royalty interest in the Wasson ODC Unit and entitled the Trust to receive quarterly royalty payments with respect to oil production from the Wasson ODC Unit for each calendar quarter. The royalties payable with respect to the Wasson ODC Royalty for any calendar quarter were 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 was 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 could be produced per quarter in respect of the Wasson ODC Royalty (12.3934% of the quarterly gross production limitation).

The Wasson ODC Royalty terminated on December 31, 2007. Thus, the Trustee made 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 meant (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 related.

Prior to the sale of the Net Profits Royalties, the Net Profits Royalties entitled 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 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.

The Conveyances provided that if a dispute arose 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 had been received by the owner of the Net Profits Properties and therefore constituted Gross Proceeds (a) the amounts withheld by a purchaser and deposited with an escrow agent would 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 would 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 would be considered to have been received.

The Trust Agreement, as amended with the affirmative vote of the holders of a majority of the Units on July 5, 2007, directed the Trustee, without any further vote of the Unitholders, to use all reasonable efforts to sell all of the Net Profits Royalties held by the Trust for cash with an effective date between June 30, 2006 and October 31, 2007. In late 2006 and January 2007 the Trustee obtained written proposals from three independent financial advisors, and selected Stifel, Nicolaus & Company, Incorporated ("Stifel Nicolaus") to serve as financial advisor to the Trustee in connection with the sale of the Net Profits Royalties, and formally engaged Stifel Nicolaus as the Trustee's financial advisor in May 2007.

On November 8, 2007, the Trustee entered into a Purchase and Sale Agreement (the "Purchase Agreement") providing for the sale of the Net Profits Royalties to Amen Properties, Inc. ("Amen"), effective as of October 1, 2007. The sale of the Net Profits Royalties pursuant to the Purchase Agreement closed on December 18, 2007, for an aggregate purchase price, after all adjustments required by the Purchase Agreement, of approximately $51.5 million. In connection with the transactions contemplated by the Purchase Agreement, Devon waived its right to purchase any or all of the interests sold at the same price and on the same terms of the sale to Amen.

The effective date of the sale under the Purchase Agreement was October 1, 2007. Subject to various limitations, the Purchase Agreement provided for potential adjustments to the purchase price resulting from, among other things, title and environmental issues, if any, affecting the interests to be sold, adjustments for overproduction or underproduction of natural gas from the properties to which the interests relate, and changes in excess of specified amounts to the price of West Texas Intermediate Crude Oil for December 2008 as of the business day prior to the closing date. The contractual adjustment for changes in the price of West Texas Intermediate Crude Oil for December 2008 resulted in an increase to the purchase price of approximately $1 million. The Purchase Agreement also provided for an increase to the purchase price in the event that a revised reserve report (the "Revised Reserve Report") relating to the interests being sold to be prepared and delivered to the parties prior to closing reflected an increase in the aggregate net present value of the interests as of December 31, 2006, when compared to the reserve report available to the parties at the time of the execution of the Purchase Agreement, and after making certain adjustments to the Revised Reserve Report in accordance with the Purchase Agreement. The contractual provision for adjustments based on the Revised Reserve Report did not result in any adjustment to the purchase price.

The closing of the purchase occurred on December 18, 2007. The closing was conditioned on, among other things, the Trustee's receipt of an opinion from a nationally recognized investment banking firm regarding the fairness, from a financial point of view, of the transactions contemplated by the Purchase Agreement. The Purchase Agreement also included other conditions, representations, warranties, covenants and other customary provisions, including provisions limiting the types and amounts of any claims the parties might otherwise assert against each other and providing limitations on the time after the closing during which any such claims could be made.

The Trustee received an opinion from Stifel, Nicolaus & Company, Incorporated that the transactions contemplated by the Purchase Agreement were fair, from a financial point of view. Stifel, Nicolaus, which acted as the Trustee's financial advisor in connection with the sale of the Properties, is a nationally recognized investment banking and securities firm with membership on all the principal United States' securities exchanges. As part of its investment banking activities, Stifel Nicolaus is

regularly engaged in the independent valuation of businesses and securities in connection with mergers, acquisitions, underwritings, sales and distributions of listed and unlisted securities, private placements and valuations for estate, corporate and other purposes. The full text of Stifel Nicolaus' written opinion dated December 17, 2007, which sets forth the assumptions made, matters considered and limitations of the review undertaken, is filed as an exhibit to this Annual Report on Form 10-K.

The description herein of the material terms of the Purchase Agreement is qualified in its entirety by reference to the Purchase Agreement, which is filed as an exhibit to this Form 10-K.

In accordance with the documents governing the Trust, the Trustee distributed the net proceeds of the sale (after deducting amounts necessary to pay any fees, expenses, liabilities and other obligations of the Trust, and after setting aside an amount of $1,000,000 the Trustee determined to hold in reserve for additional expenses) to unitholders in late February 2008.

In April 2006, in preparation for the Trust's sale of the Net Profits Royalties in accordance with the Trust Agreement, Devon began a review of its files relating to the Net Profits Royalties. In July 2006 Devon informed the Trustee that the files Devon had acquired as a result of its acquisition of Santa Fe in 2000 relating to the Trust's Net Profits Royalties were incomplete, and that significant effort would be required to supplement the files with documentation of a quality adequate to facilitate the sale of the Net Profits Royalties. Devon continued its review of the title documentation relating to the Trust's Net Profits Interests through late 2006 and most of 2007, including significant efforts to research and resolve various title issues and questions arising up until shortly prior to the closing of the sale of the Net Profits Royalties in accordance with the Purchase Agreement.

In February 2007 Devon informed the Trustee that it appeared that a number of interests that had been reported as being owned by the Trust might have been incorrectly reported, and that these issues could potentially affect the Trust's ownership and thus the asset base to be sold when the Trust sold its Net Profits Royalties. The Trustee and Stifel Nicolaus inquired whether the issues meant that prior quarterly distributions to the Trust could have been greater than they should have been, and Devon responded that that was likely, but that the review of the documentation of the Net Profits Royalties was not complete and that the information discussed at the meeting was preliminary and subject to change at that time.

On March 7, 2007, Devon informed the Trustee that Devon continued to believe that it might have incorrectly reported interests not actually held by the Trust as being owned by the Trust, and that it might have overpaid the Trust during 2006 and prior years by as much as $4 million, but stated that Devon could not provide any reliable estimate of the amount of the possible overpayments at that time. During the following weeks, the Trustee and Devon discussed the issues involved several times. Independent oil and gas title consultants from multiple consulting firms were retained, and Devon committed internal resources in its effort to complete its review and to determine whether it had actually included interests not owned by the Trust in the reports previously sent to the Trustee and to the Trust's independent petroleum engineers, and whether it had actually overpaid the Trust, and if so, by how much. In addition, the Trustee retained outside consultants to review the work being performed by Devon and its outside consultants.

Devon subsequently provided the Trustee with further estimates of the aggregate amount it believed it had overpaid the Trust, with the amount increasing to an aggregate of at least $10,590,555 over the seven-year period ended December 31, 2006.

recoup a portion of the amount Devon had overpaid the Trust. The aggregate amount Devon recouped through the distribution paid in February 2008 was approximately $7.7 million.

The independent oil and gas auditing firm retained by the Trustee to review the work performed by Devon and its independent oil and gas title consultants has confirmed to the Trustee that Devon did make overpayments as discussed above to the Trust.

As a result of the matters described above, the Trustee requested a revised reserve report from the Trust's independent petroleum engineers. On July 18, 2007, the Trustee received a reserve report prepared for the Trust by its independent petroleum engineers, Ryder Scott Company, L.P. ("Ryder Scott"). The reserve report, which was based on information furnished to Ryder Scott by Devon indicated that, as of December 31, 2006, the estimated future net revenues attributable to the interests held by the Trust and classified as proved net reserves were $62.9 million, and that the present value of those estimated future net revenues, discounted at 10% annually in accordance with SEC guidelines, was $39.1 million. Subsequently, on December 4, 2007, the Trustee received further revised reserve report (the "Revised Reserve Report") prepared for the Trust by Ryder Scott. The Revised Reserve Report, which was based on corrected information furnished to Ryder Scott by Devon, indicated that, as of December 31, 2006, the estimated future net revenues attributable to the interests held by the Trust were $64.1 million (an increase of $1.2 million from the $62.9 million estimate contained in the Ryder Scott report dated July 16, 2007), and that the standardized measure of discounted estimated future net cash flows, discounted at 10% annually in accordance with SEC guidelines, was $44.9 million (an increase of $5.8 million from the $39.1 million estimate contained in the Ryder Scott report dated July 16, 2007). The estimated future net revenues and the standardized measure of discounted estimated future net cash flows were not adjusted to account for production since December 31, 2006 or for changes in market prices after that date. The Revised Reserve Report, dated November 30, 2007, is attached as Appendix A to this Annual Report on Form 10-K. Readers are cautioned to review the Revised Reserve Report in its entirety.

On May 1, 2007, as a result of the matters described above, the Trustee concluded, based on the information furnished to the Trustee by Devon as described above, that the Trust's previously-issued financial statements, which include supplemental oil and gas reserve information, should no longer be relied upon. The Trustee subsequently determined to restate the Trust's financial statements for the years ended December 31, 2005 and 2004. The adjustments made as a result of the restatement are more fully discussed in Note 8 of the Notes to the Financial Statements of Santa Fe Energy Trust for the year ended December 31, 2006 and in Item 7 of Part II—Management's Discussion and Analysis of Financial Condition and Results of Operations—included in this Annual Report on Form 10-K.

Please see the Special Note at the beginning of this Annual Report on Form 10-K.

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 Deposit Agreement effectively terminated in connection with the termination of the Trust.

The functions of the Depositary under the Deposit Agreement were custodial and ministerial in nature and for the benefit of Holders. The Deposit Agreement and the issuance of SPERs thereunder provided Holders an administratively convenient form of holding an investment in the Trust and a Treasury Obligation. Each Depositary Unit was evidenced by a SPER, which was 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 owned 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 were held solely for the benefit of the Holders and did not constitute assets of the Depositary or the Trust. Generally, the Depositary Units were 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.

The Trustee determined 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") was 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 represented 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 was 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 were received within one month of production, payments in respect of the Wasson ODC Royalty were made for production from the calendar quarter to which the Quarterly Distribution Amount relates. The Quarterly Distribution Amount for each quarter was 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 was not a business day) or such later date as the Trustee determined was required to comply with legal or stock exchange requirements (the "Quarterly Record Date"). The Trustee distributed 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 was or will be 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."

The Trust was 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 constituted 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.

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.

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.

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.

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.

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.

Based on representations made by Devon regarding the reserves burdened by the Wasson ODC Royalty and the expected life of the Wasson ODC Royalty, the Wasson ODC Royalty is properly treated as a "production payment" 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 ODC Royalty to Devon in an amount equal to the amount of the purchase price of each Depositary Unit allocated to the Wasson ODC Royalty. Because production payments are treated as debt instruments for tax purposes, the Wasson ODC Royalty is 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 ODC Royalty was issued to the Trust, the tax treatment of the Wasson ODC Royalty 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 ODC Royalty 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 ODC Royalty.

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.

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, 2008, the 100% of taxable income limitation on percentage depletion does not apply to "marginal production." 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.

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.

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.

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.

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.

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.

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.

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.

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 Royalty Interests burdening oil and gas properties located in Arkansas, California, Louisiana, New Mexico, North Dakota, Oklahoma, Texas and Wyoming. Of these states, all but Texas and Wyoming have individual income taxes. As stated, Texas currently has no individual income tax and the Reserve Report reflects that 50% of the estimated future net cash inflows generated by the Trust will be attributable to properties located in Texas. A Holder may be required to file state income tax returns and/or to pay taxes in those states imposing individual 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.

Furthermore, some states may tax the Trust as a separate entity. In 2006, Texas enacted certain changes to its franchise tax. The amended franchise tax is known as the Texas Margin Tax. In general, legal entities that do business in Texas will be subject to the Texas Margin Tax. Although it is not clear, the Trust may be considered an entity that is subject to the Margin Tax. The Texas legislature is working to clarify provisions with respect to the effective date of the Texas Margin Tax for entities that cease to exist during 2007. Depending on the interaction between the liquidation date of the Trust and the forthcoming legislative clarification, the Trust may be in existence during a period of time for which the Margin Tax will apply. If the Texas Margin Tax applies it will be imposed at 1% of Texas-sourced taxable margin measured by the ratio of gross receipts from business done in Texas to gross receipts from business done everywhere. The taxable margin is computed as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation.

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 state income tax filing requirements with respect to their share of allocable Trust 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.

Please see the Special Note at the beginning of this Annual Report on Form 10-K.

The Treasury Obligations consisted 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 equaled $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.

Please see the Special Note at the beginning of this Annual Report on Form 10-K.

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 ownership in the Wasson Willard Unit terminated at the end of 2003.

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 300 producing wells and is operated by Occidental Petroleum Limited. Production attributable to Devon's royalty interest in the Wasson ODC Unit was marketed by Devon and in some cases was sold at the wellhead at market responsive prices that approximate spot oil prices for West Texas Sour crude, and in other cases was sold at points within common carrier pipeline systems on terms whereby Devon pays the cost of transporting the same to such points.

The Royalty Properties burdened by the Net Profits Royalties consisted of royalty and working interests in producing properties located in established oil and gas producing areas in eight states. The Net Profits Royalties have been sold. See "—Sale of Net Profits Royalties". Prior to the sale of the Net Profits Royalties, Devon owned the Net Profits Properties subject to and burdened by the Net Profits Royalties, and was entitled to proceeds attributable to its ownership interest in excess of 90% of the Net Proceeds paid to the Trust. Devon was 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 estimated that as of December 31, 2006, the Net Profits Properties covered approximately 207,000 gross acres (approximately 30,000 net to Devon).

The Conveyances contained 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 contained 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 were 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.

Prior to the sale of the Net Profits Royalties, the value of the Depositary Units and the Trust Units evidenced thereby substantially depended 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. As described elsewhere herein, the Trust sold the Royalty Interests on December 18, 2007. See Item 1—"Business—Description of the Trust—Sale of Net Profits Royalties".

A report of the proved oil and gas reserves attributable to the Trust as of December 31, 2006 has been made by Ryder Scott Company, L.P., independent petroleum consultants, based on information furnished by Devon. The following description summarizes such reserve report, and a summary of the reserve report is attached as Appendix A to this Annual Report on Form 10-K. The Trust has not filed reserve estimates covering the Royalty Properties with any other Federal authority or agency.

The interests originally conveyed to the Trust consisted 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 interest in the Willard Unit terminated at the end of 2003. The properties in which the Trust had an interest at December 31, 2006 were located in the states of Arkansas, California, Louisiana, New Mexico, North Dakota, Oklahoma, Texas, and Wyoming.

The estimated reserve quantities and future income quantities presented in the reserve report are related to a large extent to hydrocarbon prices. Hydrocarbon prices in effect at December 31, 2006 were used in the preparation of the report as required by applicable rules. Actual prices at any other date would have been different. Volumes of reserves actually produced and amounts of income actually received may therefore have differed significantly from the estimated quantities presented in the reserve report.

The following table sets forth, as of December 31, 2006, certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to the underlying properties and the Net Profits Royalties, in each case derived from the reserve report. A summary of the reserve report is included as Appendix A to this Report on Form 10-K.

			Santa Fe Energy Trust As of December 31, 2006

			Liquids (MBbls)		Gas (MMCF)		Estimated Future Net Cash Inflows (M$)		Present Value at 10% (M$)
Proved Net Developed and Undeveloped
	Wasson ODC Royalty			240.9		0		12,522.6		11,944.3
	Net Profits Royalties			743.1		3,023		51,622.6		32,921.1

		Totals		984.0		3,023		64,145.2		44,865.4
Proved Net Developed
	Wasson ODC Royalty			240.9		0		12,522.6		11,944.3
	Net Profits Royalties			681.3		3,023		49,077.0		31,427.8

		Totals		922.2		3,023		61,599.6		43,372.1

The estimated proved reserves and income quantities for the Wasson ODC Royalty were 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.

Reserve quantities were calculated differently for the Net Profits Royalties because the 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 held 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 the reserve report. The allocation of proved reserves of the Net Profits Properties between the Trust and Devon have historically varied as relative estimates of future gross revenues and future net incomes vary. Furthermore, for purposes of the reserve report, the Net Profits Royalties were calculated beyond the Liquidation Date of February 15, 2008, even though by the terms of the Trust Agreement the Net Profits Royalties were required to be sold by the Trustee on or about that date, and in fact were sold on December 17, 2007.

The "Liquid" reserves shown in the reserve report are comprised of crude oil, condensate and natural gas liquids. Natural gas liquids comprise 9.8 percent of the Trust's developed liquid reserves and 11.7 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.

In accordance with the standardized measure criteria of SFAS 69, estimates of future cash inflows, future costs, and future net cash inflows before income tax, as well as estimated reserve quantities, as of December 31, 2006, all as set forth in the reserve report, are presented as follows.

			Santa Fe Energy Trust As of December 31, 2006

			Net Profits Royalties
			Royalty Interests		Working Interests		Totals		Wasson Royalties		Totals
Total Proved
	Future Cash Inflows (M$)			22,336.6		29,286.0		51,622.6		13,600.4		65,223.0
Future Costs
	Production (M$)			0		0		0		1,077.8		1,077.8
	Development (M$)			0		0		0		0		0

		Total Costs (M$)		0		0		0		1,077.8		1,077.8
Future Net Cash Inflows Before Income Tax (M$)				22,336.6		29,286.0		51,622.6		12,522.6		64,145.2
Present Value at 10% Before Income Tax (M$)				12,650.5		20,270.6		32,921.1		11,944.3		44,865.4
Proved Net Developed Reserves
	Liquids (MBbls)			374.5		306.8		681.3		240.9		922.2
	Gas (MMCF)			246		2,777		3,023		0		3,023
Proved Net Undeveloped Reserves
	Liquids (MBbls)			61.8		0		61.8		0		61.8
	Gas (MMCF)			0		0		0		0		0
Total Proved Net Reserves
	Liquids (MBbls)			436.3		306.8		743.1		240.9		984.0
	Gas (MMCF)			246		2,777		3,023		0		3,023

In the case of the Wasson Royalties, 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 the reserve report. Therefore, the future cash inflows are the same as the future net cash inflows.

The reserves shown in the reserve 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. 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 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.

Reference is made to "—Description of the Treasury Obligations" and "—Description of the Royalty Properties" for information relating to the assets of the Trust.

Please see the Special Note at the beginning of this Annual Report on Form 10-K.

Competition. The oil and gas industry is highly competitive in all of its phases. Devon and the other operators of the Royalty Properties encountered 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.

Markets. Production attributable to Devon's royalty interest in the Wasson ODC Unit was marketed by Devon and in some cases sold at the wellhead at market responsive prices that approximated spot oil prices for West Texas sour crude, and in other cases was 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 made all decisions regarding the marketing and sale of oil and gas production. Although Devon generally had the right to market oil and gas produced from the Royalty Properties that were working interests, Devon generally relied on the operators of the properties to market the production.

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 or gas 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 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 gas marketing affiliate shippers 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 was amended to prohibit any forms of market manipulation in connection with the transportation, purchase or sale of natural gas, and the FERC has established 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 and a five yearly re-determination. 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. In March, 2006, to implement the second of the required five-yearly re-determinations, the FERC established an upward adjustment in the index to track oil pipeline cost changes. The FERC determined that the Producer Price Index for Finished Goods plus 1.3 percent (PPI plus 1.3 percent) should be the oil pricing index for the five-year period beginning July 1, 2006. Another FERC proceeding that may impact oil pipeline transportation costs relates to a 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. The Trust is not able to predict with certainty what effect, if any these federal regulations or FERC proceedings 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.

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 responsible 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.

Please see the Special Note at the beginning of this Annual Report on Form 10-K.

As described elsewhere in this Form 10-K, the Trust sold the Net Profits Royalties on December 18, 2007, and liquidated in February 2008. The Trustee distributed the net proceeds of the sale, together with the distribution for the quarter ended December 31, 2007, to Holders of record at the close of business on February 14, 2008. In accordance with the documents governing the Trust, the Trustee will continue to act as such for a period of time after the Liquidation Date for the purposes of winding up the affairs of the Trust. The Trustee established a reserve of $1,000,000 for the payment of Trust expenses and contingencies. The Trustee intends to distribute any amount remaining in the reserve account to Holders of record at the close of business on February 14, 2008 at such time, if any, that the Trustee determines that there is no longer any need for the reserves. The Trustee is unable to predict when or whether that will occur, or if it does, how much would be available for distribution.

The Royalty Properties related to the Trust have been the subject of lawsuits and governmental proceedings from time to time arising in the ordinary course of business. These matters have not had a material adverse effect on the financial position or cash proceeds and distributable cash of the Trust.

There were no matters submitted to a vote of the Holders during the quarter ended December 31, 2006.

Item 5. Market for Registrant's Units, Related Holder Matters and Issuer Purchases of Units.

Prior to February 15, 2008, the Depositary Units were 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, 2006 and 2005 were as follows (in dollars):

		Sales Prices

		Sales Prices				Distribution Paid
		Low		High		Distribution Paid
2006:
	First Quarter	$	27.30	$	32.72	$	0.98324
	Second Quarter		27.52		31.00		1.17243	(a)
	Third Quarter		27.18		34.11		0.89734	(b)
	Fourth Quarter		27.45		31.73		0.96390
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	(c)
	Fourth Quarter		25.74		43.65		0.84909

At February 23, 2007, the 6,300,000 Depositary Units outstanding were held by 207 holders of record.

		2006		2005		2004		2003		2002

		(thousands, except per unit data)
Year Ended December 31:
	Total Royalties Income	$	26,189	$	23,109	$	15,924	$	19,658	$	11,641
	Distributable Cash		25,307		25,205		19,595		21,383		11,135
	Distributable Cash per Trust Unit		4.01691		4.00076		3.11035		3.39421		1.76729
At December 31:
	Investment in Royalty Interests, net	$	2,381	$	3,511	$	5,876	$	8,440	$	11,460
	Trust Corpus		2,690		3,604		5,981		8,564		11,498

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

Please see the Special Note at the beginning of this Annual Report on Form 10-K.

The Trust was formed on October 22, 1992. As more fully described elsewhere in this Form 10-K, the Trust sold the Net Profits Royalties on December 18, 2007, and liquidated in February 2008. The Trustee distributed the net proceeds of the sale, together with the distribution for the quarter ended December 31, 2007, to Holders of record at the close of business on February 14, 2008. In accordance with the documents governing the Trust, the Trustee will continue to act as such for a period of time after the Liquidation Date for the purposes of winding up the affairs of the Trust. The Trustee established a reserve of $1,000,000 for the payment of Trust expenses and contingencies. The Trustee intends to distribute any amount remaining in the reserve account to Holders of record at the close of business on February 14, 2008 at such time, if any, that the Trustee determines that there is no longer any need for the reserves. The Trustee is unable to predict when or whether that will occur, or if it does, how much would be available for distribution.

Prior to the sale of the Net Profits Royalties, the Trust held Royalty Interests in the Royalty Properties conveyed to the Trust by Devon. The Trust was a passive entity that collected royalty income generated by the Royalty Properties.

The Trust's results of operations depended 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 were crude oil, even relatively modest changes in crude oil prices could 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 came 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.

Natural gas prices fluctuate due to weather conditions, the availability of pipeline and underground storage capacity, the level of natural gas in storage, the relative balance between supply and demand and other economic factors.

Trust expenses included 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. The Trust terminated on February 15, 2008 (the "Liquidation Date").

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 2007 reflects revenues received and costs and expenses paid by Devon in the fourth quarter of 2006. On February 28, 2007, the Trust made a cash distribution of $5.5 million, or $0.87731 per Trust Unit, to Holders of record on February 15, 2007.

			Year Ended December 31,

			Year Ended December 31,									First Quarter 2007
			2006			2005			2004			First Quarter 2007
						(Restated)			(Restated)			(Unaudited)
*Volumes and Prices*
	Oil Volumes (Bbls):
		Wasson ODC Royalty		253,000			274,100			296,800			62,200
		Wasson Willard Royalty(1)		—			—			12,000			—
		Net Profits Royalties		111,630			113,927			130,003			34,695
	Gas Volumes (Mcf):
		Net Profits Royalties		786,066			1,064,250			1,279,872			221,823
	Oil Average Prices ($/Bbl):
		Wasson ODC Royalty	$	59.55		$	48.04		$	34.40		$	53.34
		Wasson Willard Royalty(1)		—			—			28.50			—
		Net Profits Royalties		55.74			40.22			29.77			56.57
	Gas Average Prices ($/Mcf):
		Net Profits Royalties	$	7.65		$	5.61		$	5.04		$	5.44
*Cash Proceeds and Distributable Cash (in thousands of dollars, except as noted)*
	Wasson ODC Royalty:
		Sales	$	15,066		$	13,169		$	10,209		$	3,318
		Operating Expenses		(941	)		(695	)		(718	)		(234	)

				14,125			12,474			9,491			3,084

	Wasson Willard Royalty(1):
		Sales		—			—			342			—
		Operating Expenses		—			—			(10	)		—

				—			—			332			—

	Net Profits Royalties:
		Sales		12,519			12,352			10,377			3,179
		Proceeds From the Sale of Property		482			2,354			—			—
		Operating Expenses		(856	)		(2,562	)		(2,220	)		(535	)
		Capital Expenditures		(81	)		(1,509	)		(2,056	)		(47	)

				12,064			10,635			6,101			2,597

	Total Royalties			26,189			23,109			15,924			5,681
	Administrative Fee to Devon			(310	)		(300	)		(289	)		(79	)
	Payments Made to Trust in error(2)			253			2,996			4,435			—

	Payments Received			26,132			25,805			20,070			5,602
	Cash Withheld for Trust Expenses			(825	)		(600	)		(475	)		(75	)

	Distributable Cash		$	25,307		$	25,205		$	19,595		$	5,527

	Distributable Cash Per Unit		$	4.01691		$	4.00076		$	3.11035		$	0.87731

Sales increased $2.0 million from 2005 to 2006. Sales increased $4.8 million and $1.5 million, respectively, due to a $12.79 per barrel increase in the average price of oil from $45.54 per barrel in 2005 to $58.33 per barrel in 2006, and a $2.04 per Mcf increase in the average gas price from $5.61 per Mcf in 2005 to $7.65 per Mcf in 2006. A production decrease of approximately 70,000 barrels of oil equivalent from 2005 to 2006 caused sales to decrease $4.3 million. The decrease was primarily due to the sale of certain Net Profits properties and the declining maximum Wasson ODC royalty.

Sales increased $4.6 million from 2004 to 2005. Sales increased $5.2 million and $0.7 million, respectively, due to a $12.76 per barrel increase in the average price of oil from $32.78 per barrel in 2004 to $45.54 per barrel in 2005, and a $0.57 per Mcf increase in the average gas price from $5.04 per Mcf in 2004 to $5.61 per Mcf in 2005. A production decrease of approximately 87,000 barrels of oil equivalent from 2004 to 2005 caused sales to decrease $1.3 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.

Proceeds from the sale of property were $0.5 million in 2006 and $2.4 million in 2005 due to the sale of certain Net Profits Properties in those years.

Operating expenses decreased $1.5 million from 2005 to 2006 primarily due to an out-of-period adjustment related to the Net Profits Royalties. In the second quarter of 2006, Devon determined that in prior periods, it had overstated certain of the Trust's operating expenses in the calculations of the Net Profits Royalties. Accordingly, in the second quarter of 2006, Devon remitted $1.3 million or $0.20973 per Trust Unit to the Trust to adjust for the prior periods' overstatement of expenses. Operating expenses increased $0.3 million from 2004 to 2005. The increase was primarily related to 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 2006, 2005 and 2004 totaled $0.1 million, $1.5 million and $2.1 million, respectively.

Cash withheld for trust expenses increased $0.2 million from 2005 to 2006 and $0.1 million from 2004 to 2005. These changes were primarily related to increases in fees for external tax accountants and attorneys. In 2007, these expenses are expected to increase significantly in connection with the termination of the Trust on or before February 15, 2008.

In April 2006, in preparation for the Trust's sale of the Net Profits Royalties in conjunction with the liquidation of the Trust, Devon began a review of its files relating to the Net Profits Royalties. As a result of this review, Devon identified a number of overpayments it had made to the Trust related to royalty interests that the Trust did not actually own. Devon determined and the Trustee ultimately agreed that for the seven-year period ended December 31, 2006 the Trust had been overpaid by approximately $10.6 million. The portion of this total overpayment that relates to 2006, 2005 and 2004 was $0.3 million, $3.0 million and $4.4 million, respectively.

As allowed by the conveyances to the Trust, Devon recouped approximately $7.7 million of the overpayments throughout 2007 and 2008 through a reduction of Net Profits Royalties due to the Trust in 2007 and 2008.

On December 19, 2007, the Trustee announced that it had completed the sale of all of the Net Profits Royalties held by the Trust to Amen Properties, Inc. and certain other purchasers. The

aggregate price for the assets sold was approximately $51.5 million, after making adjustments pursuant to the purchase agreement. The Trustee distributed the net proceeds of the sale (after deducting amounts necessary to pay all current fees, expenses, liabilities and other obligations of the Trust, and after setting aside a reserve of $1,000,000 for expenses) on February 29, 2008 to unitholders of record at the close of business on February 14, 2008.

The United States Treasury book-entry securities representing stripped-interest coupons held by the Trustee as Custodian matured on February 15, 2008. The Trustee sent instructions and a form of letter of transmittal to unitholders of record at the close of business on February 14, 2008 with instructions for submitting certificates to the processing agent named in the instructions. The processing agent has distributed [substantially all] of the cash proceeds of the United States Treasury book-entry securities, and will distribute remaining funds as promptly as practicable upon its receipt of Unitholders' certificates or, if necessary, compliance with procedures for lost, stolen, mutilated or destroyed certificates.

The Trust was liquidated on February 15, 2008. The Trustee will continue to act as trustee of the trust estate until the trust estate has been finally distributed and the affairs of the Trust have been wound up.

Trading in the Trust's units on The New York Stock Exchange stopped immediately following the close of business on February 14, 2008, and The New York Stock Exchange delisted the units at that time.

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.

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: timing of Net Profits Royalties sales, 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. Further, all statements in this document, including all forward-looking statements, are expressly qualified in their entirety by the Special Note at the beginning of this Form 10-K.

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

As a result of the issues described in this Annual Report on Form 10-K and in the Trust's prior Current Reports on Form 8-K regarding certain overpayments Devon made to the Trust and related issues regarding the Trust's ownership of certain assets, the Trustee of the Trust concluded on May 1, 2007 that the Trust's previously-issued financial statements should no longer be relied upon, as set forth in the Trust's Report on Form 8-K filed on May 3, 2007. The Trustee subsequently determined to restate the Trust's financial statements for the years ended December 31, 2005 and 2004 to identify overpayments made to the Trust. The restated financial statements are included in this Annual Report on Form 10-K. The adjustments made as a result of the restatement are more fully discussed in Note 8 of the Notes to the Financial Statements of Santa Fe Energy Trust for the year ended December 31, 2006 and in Part II—Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations" included in this Annual Report on Form 10-K.

As a result of the restatement and the issues leading to the restatement, the Trustee has identified deficiencies in the Trust's internal control over financial reporting that led to the failure to prevent or detect the errors which led to the restatement. The Trustee has concluded that the control deficiencies represented a material weakness in the Trust's internal control over financial reporting. These matters are discussed more fully below.

The Trust 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 The Bank of New York Mellon Trust Company, 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 Trust's disclosure controls and procedures. Based upon that evaluation and the restatement of the Trust's financial statements as described above, which arose from the material weakness in internal control over financial reporting described herein, Mike Ulrich, as Trust Officer of the Trustee, has concluded that the Trust's disclosure controls and procedures were not effective as of December 31,

2006. However, based on the additional procedures performed by Devon and the independent consultants retained by Devon during 2007, and the additional procedures performed by the independent oil and gas auditing firm retained by the Trustee to review the work performed by Devon and its consultants, the Trustee believes that the financial statements included in this Annual Report on Form 10-K fairly present, in all material respects, the financial position and results of operations and cash flows of the Trust as of the dates, and for the periods presented in accordance with generally accepted accounting principles.

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 historically relied 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.

Prior to 2007, the Trustee reviewed the quarterly information provided to the Trustee by Devon, as well as the annual information provided to the Trustee by the Trust's independent reserve engineers regarding reserves, and discussed the information as it deemed appropriate with representatives of Devon and the engineers. However, prior to 2007, as previously disclosed, the Trustee ultimately relied on the information provided and did not have controls or procedures in place to verify certain of the accuracy of the information Devon provided to the Trustee or that Devon provided to the engineers. Specifically, the Trustee did not have internal controls or procedures in place to verify that the information Devon furnished to the Trust's independent petroleum engineers was accurate or that the quarterly payments Devon made to the Trust under the Conveyances to the Trust were complete and related to specific properties in which the Trust held an interest.

Based on the Trustee's evaluation, there were not any changes in the Trust's internal control over financial reporting during the fiscal quarter ended December 31, 2006 that materially affected, or are reasonably likely to materially affect, the Trust's internal control over financial reporting.

During 2007 (subsequent to the period covered by this report) there were changes in the Trust's internal control over financial reporting that materially affected the Trust's internal control over financial reporting. As a result of the material weakness described in the Trustee's Report on Internal Control over Financial Reporting, in addition to committing internal resources to the review, Devon retained independent oil and gas title consultants from two consulting firms, which reviewed Devon's title files relating to the Trust, to determine whether Devon had actually included interests not owned by the Trust in the reports previously sent to the Trustee and to the Trust's independent petroleum engineers, and whether it had actually overpaid the Trust. In addition, the Trustee retained outside consultants to review the work being performed by Devon and its outside consultants. In the opinion of the Trustee, the reviews conducted by Devon and the consulting firms it retained and the review conducted by the consulting firm retained by the Trustee, materially affected the Trust's internal control over financial reporting subsequent to December 31, 2006.

The Bank of New York Mellon Trust Company, N.A., as trustee (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).

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.

An evaluation was conducted under the supervision and with the participation of the Trustee to assess the effectiveness of the Trust's internal control over financial reporting as of December 31, 2006 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 that assessment, the Trustee concluded that, as of December 31, 2006, the Trust's internal control over financial reporting was not effective.

A material weakness is a control deficiency, or combination of control deficiencies, that results in a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

The Trustee determined that a material weakness existed relating to its accounting for royalty income. Specifically, its policies, procedures and control activities were not designed to adequately detect errors in royalty income that could arise in the process of accounting for quarterly payments received by the Trust. This material weakness resulted in payments unrelated to royalty interests held by the Trust being erroneously recognized as royalty income and the restatement of the Trust's interim and annual financial statements.

The Trustee's assessment of the effectiveness of the Trust's internal control over financial reporting as of December 31, 2006 has been audited by KPMG LLP, an independent registered public accounting

firm. Their audit opinion on the Trustee's assessment of internal control over financial reporting is on page 33 of this filing.

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 did not maintain effective internal control over financial reporting as of December 31, 2006, because of the effect of the material weakness identified with respect to the accounting for royalty income, 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 material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in the Trustee's assessment: The Trustee determined that a material weakness existed relating to its accounting for royalty income. Specifically, its policies and procedures and control activities were not designed to adequately detect errors in royalty income that could arise in the process of accounting for quarterly payments received by the Trust. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the December 31, 2006 financial statements of Santa Fe Energy Trust. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2006 financial statements, and this report does not affect our report dated May 21, 2010, which expressed an unqualified opinion on those financial statements.

In our opinion, the Trustee's assessment that Santa Fe Energy Trust did not maintain effective internal control over financial reporting as of December 31, 2006, 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, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Santa Fe Energy Trust has not maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Item 10. Directors, Executive Officers of the Registrant and Corporate Governance.

There are no directors or executive officers of the Registrant. The Trustee is a corporate trustee which may be removed by the affirmative vote of Holders of a majority of the Trust Units then outstanding at a meeting of the Holders of the Trust at which a quorum is present.

The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons. The Trust does not have a board of directors or an audit committee, and therefore it does not have an audit committee financial expert.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The Registrant knows of no arrangements, including the pledge of securities of the Registrant, the operation of which may at a subsequent date result in a change in control of the Registrant. However, as described elsewhere herein, on December 18, 2007 the Registrant sold all of its assets.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional services firms and related fees are granted by the Trustee.

Aggregate fees billed for the annual audit and quarterly reviews for each of the years ended December 31, 2006 and 2005 for professional services rendered by KPMG LLP were $285,000 and $120,000, respectively.

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



Audited Financial Statements
	Report of Independent Registered Public Accounting Firm	38
	Statements of Cash Proceeds and Distributable Cash for the Years Ended December 31, 2006, 2005 and 2004	39
	Statements of Assets and Trust Corpus as of December 31, 2006 and 2005	40
	Statements of Changes in Trust Corpus for the Years Ended December 31, 2006, 2005 and 2004	41
	Notes to Financial Statements	42
Unaudited Financial Information
	Supplemental Information to the Financial Statements	48

Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.

(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
10(d)*	Purchase and Sale Agreement dated November 8, 2007	1-11450	10.1
10(e)*	Ratification and Joinder Agreement dated as of December 17, 2007	1-11450	10.1
10(f)*	Opinion of Stifel, Nicolaus & Company, Incorporated, dated December 17, 2007	1-11450	10.2
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.

We have audited the accompanying statements of assets and trust corpus of Santa Fe Energy Trust as of December 31, 2006 and 2005, 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, 2006. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with 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 the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 2, these financial statements were prepared on the basis of cash receipts and disbursements, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Santa Fe Energy Trust as of December 31, 2006 and 2005, and the cash proceeds and distributable cash and the changes in trust corpus for each of the years in the three-year period ended December 31, 2006, on the basis of accounting described in Note 2.

As discussed in Note 8 to the financial statements, the financial statements as of December 31, 2005 and for each of the years in the two-year period then ended have been restated.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Santa Fe Energy Trust's internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated May 21, 2010 expressed an unqualified opinion on the Trustee's assessment of, and an adverse opinion on the effective operation of, internal control over financial reporting as of December 31, 2006.

SANTA FE ENERGY TRUST

STATEMENTS OF CASH PROCEEDS AND DISTRIBUTABLE CASH

(in thousands, except per unit data)

		Year Ended December 31,

		2006			2005			2004
					(Restated)			(Restated)
Royalty income:
	ODC royalty	$	14,125		$	12,474		$	9,491
	Willard royalty		—			—			332
	Net profits royalty		12,064			10,635			6,101

Total royalty income			26,189			23,109			15,924
Administrative fee to Devon Energy Corporation			(310	)		(300	)		(289	)
Payments made to Trust in error			253			2,996			4,435
Cash withheld for trust expenses			(825	)		(600	)		(475	)

Distributable cash		$	25,307		$	25,205		$	19,595

Distributable cash per trust unit		$	4.01691		$	4.00076		$	3.11035

Trust units outstanding			6,300			6,300			6,300

SANTA FE ENERGY TRUST

STATEMENTS OF ASSETS AND TRUST CORPUS

(in thousands, except unit data)

	December 31,

	2006			2005
				(Restated)
ASSETS
Current assets—cash	$	309		$	93

Investment in royalty interests, at cost		87,276			87,276
Less: accumulated amortization		(84,895	)		(83,765	)

		2,381			3,511

Total assets	$	2,690		$	3,604

TRUST CORPUS
Trust corpus, 6,300,000 trust units issued and outstanding	$	2,690		$	3,604


Balance at December 31, 2003 (Restated)		$	8,564
	Cash proceeds		20,070
	Cash distributions		(19,595	)
	Trust expenses		(494	)
	Amortization of royalty interests (Restated)		(2,564	)

Balance at December 31, 2004 (Restated)			5,981
	Cash proceeds		25,805
	Cash distributions		(25,205	)
	Trust expenses		(612	)
	Amortization of royalty interests (Restated)		(2,365	)

Balance at December 31, 2005 (Restated)			3,604
	Cash proceeds		26,132
	Cash distributions		(25,307	)
	Trust expenses		(609	)
	Amortization of royalty interests		(1,130	)

Balance at December 31, 2006		$	2,690

Santa Fe Energy Trust (the "Trust") was formed on October 22, 1992, with The Bank of New York Trust Company, N.A., who purchased substantially all of the corporate trust business of 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 former Trustee of the Trust, 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.

In November 1992, 5,725,000 Depositary Units, each consisting of beneficial ownership of one unit of undivided beneficial interest in the Trust ("Trust Units") and a $20 face amount beneficial ownership interest in a $1,000 face amount zero coupon United States Treasury obligation maturing on or about February 15, 2008, were sold in a public offering for $20 per Depositary Unit. A total of $114.5 million was received from public investors, of which $38.7 million was used to purchase the Treasury obligations and $5.7 million was used to pay underwriting commissions and discounts. Devon received the remaining $70.1 million and 575,000 Depositary Units. In the first quarter of 1994 Devon sold in a public offering the 575,000 Depositary Units which it held.

The trust agreement under which the Trust was formed (the "Trust Agreement") provides, among other things, that:

The 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. Estimates of oil and gas reserves are significant estimates that impact the recorded amount of depletion. Actual results may differ from such estimates.

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.

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. (See note 9)

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

					Distributions

		Royalty Payment Received			Amount		Per Trust Unit
		(in thousands, except per unit data)
2006
	First quarter	$	6,294		$	6,194	$	0.98324
	Second quarter		7,487	(a)		7,387		1.17243
	Third quarter		6,078	(b)		5,653		0.89734
	Fourth quarter		6,273			6,073		0.96390

		$	26,132		$	25,307	$	4.01691

2005
	First quarter	$	5,944		$	5,844	$	0.92772
	Second quarter		5,744			5,694		0.90372
	Third quarter		8,668	(c)		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

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.

Reported in 2006 are sales by the Trust of interests in certain Net Profits Royalties for proceeds of $0.5 million, or $0.07643 per Trust Unit. Reported in 2005 are sales by the Trust of interests in certain Net Profits Royalties for proceeds of $2.4 million, or $0.37372 per Trust Unit.

In the second quarter of 2006, Devon determined that in prior periods, it had overstated certain of the Trust's operating expenses in the calculations of the Net Profits Royalties. Accordingly, in the second quarter of 2006, Devon remitted $1.3 million or $0.20973 per Trust Unit to the Trust to adjust for the prior periods' overstatement of expenses.

In April 2006, in preparation for the Trust's sale of the Net Profits Royalties in accordance with the Trust Agreement, Devon began a review of its files relating to the Net Profits Royalties. As a result of this review which continued through the remainder of 2006 and most of 2007, Devon identified a number of interests in the Net Profits Royalties which were not actually held by the Trust but which had been reported as being owned by the Trust. Consequently, Devon concluded that it had overpaid the Trust approximately $10.6 million over the seven-year period ended December 31, 2006. An independent oil and gas auditing firm retained by the Trustee to review the work performed by Devon and its independent oil and gas title consultants confirmed to the Trustee that Devon did make such overpayments to the Trust.

In accordance with provisions of the Conveyances providing that overpayments to the Trust would reduce future amounts payable to the Trust, beginning with the distribution paid in May 2007, Devon began to withhold amounts otherwise distributable to the Trust on the Net Profits royalties in order to recoup a portion of the amount Devon had overpaid the Trust. The aggregate amount Devon recouped through February 2008 was approximately $7.7 million.

As stated in Note 2, the financial statements of the Trust are prepared on the cash basis of accounting. Therefore, the error described above does not impact previously reported distributions for the seven-year period ended December 31, 2006. However, amounts previously reported for royalty income received and administrative fees paid to Devon during this time period were overstated. The

adjustments that were made to correct this error in the accompanying 2005 and 2004 Statements of Cash Proceeds and Distributable Cash are summarized below.

		Statement of Cash Proceeds and Distributable Cash

		Year Ended December 31, 2005									Year Ended December 31, 2004
		Previously Reported			Adjustment			Restated			Previously Reported			Adjustment			Restated
		(In Thousands)
Royalty income:
	ODC royalty	$	12,461		$	13		$	12,474		$	9,495		$	(4	)	$	9,491
	Willard royalty		—			—			—			332			—			332
	Net profits royalty		13,648			(3,013	)		10,635			10,537			(4,436	)		6,101

Total royalty income			26,109			(3,000	)		23,109			20,364			(4,440	)		15,924
Administrative fee to Devon			(304	)		4			(300	)		(294	)		5			(289	)
Payments made to Trust in error			—			2,996			2,996			—			4,435			4,435
Cash withheld for trust expenses			(600	)		—			(600	)		(475	)		—			(475	)

Distributable cash		$	25,205		$	—		$	25,205		$	19,595		$	—		$	19,595

Additionally, amounts previously reported for amortization of royalty interests during the seven-year period ended December 31, 2006 were also overstated. This error also caused a similar overstatement of trust corpus. The adjustments that were made to correct this error in the accompanying 2005 and 2004 Statements of Changes in Trust Corpus and the statement of Assets and Trust Corpus as of December 31, 2005 are summarized below.

	Statement of Changes in Trust Corpus

	Previously Reported			Adjustment			Restated
	(In Thousands)
Trust corpus, December 31, 2003	$	10,029		$	(1,465	)	$	8,564
Cash proceeds		20,070			—			20,070
Cash distributions		(19,595	)		—			(19,595	)
Trust expenses		(494	)		—			(494	)
Amortization of royalty interests		(2,714	)		150			(2,564	)

Trust corpus, December 31, 2004		7,296			(1,315	)		5,981
Cash proceeds		25,805			—			25,805
Cash distributions		(25,205	)		—			(25,205	)
Trust expenses		(612	)		—			(612	)
Amortization of royalty interests		(2,344	)		(21	)		(2,365	)

Trust corpus, December 31, 2005	$	4,940		$	(1,336	)	$	3,604

The ownership error caused the Trust's previously reported estimates of proved reserves and the related reserves-based disclosures to be overstated by a material amount. As a result, prior period amounts included in "Supplemental Information to Financial Statements (Unaudited)" have been restated to reflect the Trust's correct ownership interests.

On December 19, 2007, the Trustee announced that it completed the sale of all of the Net Profits Royalties held by the Trust to Amen Properties, Inc. and certain other purchasers. The aggregate price for the assets sold was approximately $51.5 million, after making adjustments pursuant to the purchase agreement. The Trustee distributed an aggregate of $49,466,382, or $7.8518 per Unit, as the net proceeds of the sale of the Trust's assets (after deducting amounts necessary to pay fees, expenses, liabilities and other obligations of the Trust, and after the establishment of a reserve of $1,000,000 for anticipated expenses) on February 29, 2008 to unitholders of record at the close of business on February 14, 2008. The distribution was made concurrently with the Trust's distribution for the quarter ended December 31, 2007. The Trust ceased operations subsequent to the distribution.

The ownership error discussed in Note 8 of the Notes to the Financial Statements of Santa Fe Energy Trust caused the Trust's previously reported estimates of proved reserves and the related reserves-based disclosures to be overstated by a material amount. As a result, prior period amounts included in "Supplemental Information to Financial Statements (Unaudited)" have been restated to reflect the Trust's correct ownership interests. All amounts that have been corrected are labeled as "Restated".

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, 2006. 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. 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. Note: Amounts at and for the years ended December 31, 2005, 2004, and 2003 have been restated from their previously reported amounts.

								Previously Reported

		Crude Oil and Liquids (MBbls)			Natural Gas (MMcf)			Crude Oil and Liquids (MBbls)			Natural Gas (MMcf)
		(Unaudited)						(Unaudited)
Proved reserves at December 31, 2003			1,372			5,883			1,801			6,232
Revisions of previous estimates			301			414			301			414
Production			(439	)		(1,289	)		(489	)		(1,447	)

Proved reserves at December 31, 2004			1,234			5,008			1,613			5,199
Revisions of previous estimates			118			723			118			723
Sales of minerals in place			(15	)		(953	)		(15	)		(953	)
Production			(387	)		(1,064	)		(441	)		(1,075	)

Proved reserves at December 31, 2005			950			3,714			1,275			3,894
Revisions of previous estimates			414			141			—			—
Sales of minerals in place			(15	)		(46	)		—			—
Production			(365	)		(786	)		—			—

Proved reserves at December 31, 2006			984			3,023			—			—

Proved developed reserves at December 31,
	2003		1,372			5,883			1,801			6,232
	2004		1,234			5,008			1,613			5,199
	2005		950			3,714			1,275			3,894
	2006		922			3,023			—			—

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, 2006, 2005 and 2004. 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, 2006, 2005 and 2004, 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, 2006, 2005 and 2004 are presented in the following table (in thousands of dollars):

	December 31,									Previously Reported December 31,

	2006			2005			2004			2005			2004
				(Restated)			(Restated)
	(Unaudited)
Future cash inflows	$	65,223		$	75,880		$	72,991		$	105,109		$	97,364
Future production costs		(1,078	)		(2,160	)		(2,466	)		(2,160	)		(2,466	)

Net future cash flows		64,145			73,720			70,525			102,949			94,898
Discount at 10% for timing of cash flows		(19,280	)		(17,728	)		(12,754	)		(37,309	)		(28,086	)

Standardized measure of discounted future net cash flows for proved reserves	$	44,865		$	55,992		$	57,771		$	65,640		$	66,812

Future cash inflows are computed by applying year-end prices (averaging $60.78 per barrel of oil, $5.36 per Mcf of gas and $32.70 per barrel of natural gas liquids at December 31, 2006) to the year-end quantities of proved reserves.

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

	December 31,									Previously Reported December 31,

	2006			2005			2004			2005			2004
				(Restated)			(Restated)
	(Unaudited)
Balance at beginning of year	$	55,992		$	57,771		$	50,423		$	66,812		$	59,093
Production, net of related property taxes(a)		(28,149	)		(27,206	)		(21,689	)		(27,206	)		(21,698	)
Sales of minerals-in-place		(616	)		(5,324	)		—			(5,173	)		—
Net changes in prices and costs		724			22,363			12,276			22,304			10,640
Revisions of previous estimates		11,840			7,301			9,235			2,108			12,653
Interest factor—accretion of discount		5,599			5,777			5,042			6,795			6,115
Other		(525	)		(4,690	)		2,484			—			—

Balance at end of year	$	44,865		$	55,992		$	57,771		$	65,640		$	66,812

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 21st day of May, 2010

The Registrant, Santa Fe Energy Trust, has no principal executive officer, principal financial officer, controller or principal accounting officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided.

Devon Energy Corporation
20 North Broadway, Suite 1500
Oklahoma City, Oklahoma 73102-8260

At your request, we have prepared a revised report of certain data for the Santa Fe Energy Trust (Trust) as of December 31, 2006 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. This current report reflects revisions to our previous report dated July 16, 2007, based on receiving new revised accounting data, for certain of these properties, for revenues, costs, and net production volumes from Devon Energy Corporation (Devon) subsequent to submitting our previous report. The revised accounting data resulted in changes to certain operating costs, taxes, and price differentials, as well as historical net production volumes used to forecast estimated remaining reserves. In addition, there were changes based on a correction to the discounting of income projections.

The Trust is a grantor trust formed to hold interests in certain domestic oil and gas properties owned by 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, California, 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, 2006 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, 2006 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, 2006 are presented below:

			Santa Fe Energy Trust As of December 31, 2006

			Liquids (MBbls)		Gas (MMCF)		Estimated Future Net Cash Inflows (M$)		Present Value at 10% (M$)
Proved Net Developed and Undeveloped
	Wasson ODC Royalty			240.9		0		12,522.6		11,944.3
	Wasson Willard Royalty			0		0		0		0
	Net Profits Royalties			743.1		3,023		51,622.6		32,921.1

		Totals		984.0		3,023		64,145.2		44,865.4
Proved Net Developed
	Wasson ODC Royalty			240.9		0		12,522.6		11,944.3
	Wasson Willard Royalty			0		0		0		0
	Net Profits Royalties			681.3		3,023		49,077.0		31,427.8

		Totals		922.2		3,023		61,599.6		43,372.1

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 are 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 9.8 percent of the Trust's developed liquid reserves and 11.7 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.

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.

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.

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, 2006 are presented as follows.

			Santa Fe Energy Trust As of December 31, 2006

			Net Profits Royalties
			Royalty Interests		Working Interests		Totals		Wasson Royalties		Totals
Total Proved
	Future Cash Inflows (M$)			22,336.6		29,286.0		51,622.6		13,600.4		65,223.0
Future Costs
	Production (M$)			0		0		0		1,077.8		1,077.8
	Development (M$)			0		0		0		0		0

		Total Costs (M$)		0		0		0		1,077.8		1,077.8
Future Net Cash Inflows Before Income Tax (M$)				22,336.6		29,286.0		51,622.6		12,522.6		64,145.2
Present Value at 10% Before Income Tax (M$)				12,650.5		20,270.6		32,921.1		11,944.3		44,865.4
Proved Net Developed Reserves
	Liquids—(MBbls)			374.5		306.8		681.3		240.9		922.2
	Gas (MMCF)			246		2,777		3,023		0		3,023
Proved Net Undeveloped Reserves
	Liquids (MBbls)			61.8		0		61.8		0		61.8
	Gas (MMCF)			0		0		0		0		0
Total Proved Net Reserves
	Liquids (MBbls)			436.3		306.8		743.1		240.9		984.0
	Gas (MMCF)			246		2,777		3,023		0		3,023

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.

Devon furnished us with hydrocarbon prices in effect at December 31, 2006 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, 2006 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, 2006 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.

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.

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 December 2006.

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.

		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
10(d)*	Purchase and Sale Agreement dated November 8, 2007	1-11450	10.1
10(e)*	Ratification and Joinder Agreement dated as of December 17, 2007	1-11450	10.1
10(f)*	Opinion of Stifel, Nicolaus & Company, Incorporated, dated December 17, 2007	1-11450	10.2
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.


(Mark One)
ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
Or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


Texas (State or Other Jurisdiction Incorporation or Organization)		76-6081498 (I.R.S. Employer Identification No.)
The Bank of New York Mellon Trust Company, N.A. Global Corporate Trust 919 Congress Avenue, Suite 500 Austin, Texas (Address of Principal Executive Offices)		78701 (Zip Code)


Large accelerated filer o		Accelerated filer ý		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Calendar Quarters in the Year Ending December 31,		Wasson ODC Royalty Quarterly Gross Production Limitation (MBbls)			Wasson ODC Royalty Maximum Net Quarterly Production (MBbls)

2007			486			60.2


		SANTA FE ENERGY TRUST
		by:		The Bank of New York Mellon Trust Company, N.A., Trustee
		By:		/s/ MIKE ULRICH Mike Ulrich Vice President


		SANTA FE ENERGY TRUST
		By		THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., TRUSTEE
		By		/s/ MIKE ULRICH Mike Ulrich Vice President


		Very truly yours,
		RYDER SCOTT COMPANY, L.P.
		/s/ DONALD M. HAUSEN Donald M. Hausen Petroleum Engineer
FWZ/sm
Reviewed by:
/s/ FRED W. ZIEHE Fred W. Ziehe, P.E. Managing Senior Vice President


		/s/ MIKE ULRICH Mike Ulrich
Date: May 21, 2010		Vice President