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EX-23.2 - EX-23.2 - TORCH ENERGY ROYALTY TRUSTh75705exv23w2.htm
EX-32.1 - EX-32.1 - TORCH ENERGY ROYALTY TRUSTh75705exv32w1.htm
EX-31.1 - EX-31.1 - TORCH ENERGY ROYALTY TRUSTh75705exv31w1.htm
EX-23.3 - EX-23.3 - TORCH ENERGY ROYALTY TRUSTh75705exv23w3.htm
EX-23.1 - EX-23.1 - TORCH ENERGY ROYALTY TRUSTh75705exv23w1.htm
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2009
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-12474
TORCH ENERGY ROYALTY TRUST
(Exact Name of Registrant as Specified in its Charter)
     
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
  74-6411424
(I.R.S. Employer Identification No.)
Rodney Square North
1100 North Market Street
Wilmington, Delaware 19890
(Address of Principal Executive Offices; Zip Code)
(Registrant’s Telephone number, Including Area Code)
(302) 636-6016
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
     
Title of each class   Name of Each Exchange on
Which Registered
     
Units of Beneficial Interest   New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12 (G) OF THE ACT: None
     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 þ
     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 þ
     Indicated by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(b) 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 þ
     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. þ
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
             
Large accelerated filer o   Accelerated filer o   Non-accelerated filer o (Do not check if a smaller reporting company)   Small reporting company þ
     Indicated by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ
     The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter was $8,179,228.20.
     At March 31, 2010, there were 8,600,000 Units of Beneficial Interest of the Trust outstanding.
 
 

 


 

Torch Energy Royalty Trust
Annual Report on Form 10-K
For the fiscal year ended December 31, 2009
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 EX-23.1
 EX-23.2
 EX-23.3
 EX-31.1
 EX-32.1

 


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Torch Energy Royalty Trust
PART I
Item 1. Business
This document includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts included in this document, including without limitation, statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” regarding the financial position, estimated quantities and net present values of reserves of the Torch Energy Royalty Trust (“Trust”) and statements that include the words “believe”, “expects”, “anticipates”, “intends”, “estimates”, “projects”, “target”, “goal”, “plans”, “objectives”, “should” or similar expressions or variations are forward-looking statements. Torch Energy Advisors Incorporated (“Torch”) and the Trust can give no assurances that the assumptions upon which these statements are based will prove to be correct. Important factors that could cause actual results to differ materially from Torch’s expectations (“Cautionary Statements”) are disclosed under “Risk Factors” elsewhere in this document. All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified by the Cautionary Statements.
General
The Trust was formed effective October 1, 1993, pursuant to a trust agreement (“Trust Agreement”) among Wilmington Trust Company, not in its individual capacity but solely as trustee of the Trust (“Trustee”), Torch Royalty Company (“TRC”) and Velasco Gas Company, Ltd. (“Velasco”) as owners of certain oil and natural gas properties (“Underlying Properties”) and Torch Energy Advisors Incorporated (“Torch”) as grantor. TRC and Velasco created net profits interests (“Net Profits Interests”) and conveyed such interests to Torch. The Trust was formed under the Delaware statutory trust act (formerly known as the Delaware business trust act). TRC and Velasco created net profits interests (“Net Profits Interests”) which burden certain oil and natural gas properties (“Underlying Properties”) and Torch conveyed the Net Profits Interests to the Trust in exchange for an aggregate of 8,600,000 units of beneficial interest (“Units”). Such Units were sold to the public through various underwriters in November 1993. The current working interest owners of the Underlying Properties are Torch Royalty Company, Torch E&P Company, Samson Lone Star Limited Partnership and Constellation Energy Partners LLC (“Working Interest Owners”).
The sole purpose of the Trust is to hold the Net Profits Interests, to receive payments from the Working Interest Owners, and to make payments to Unitholders. The Trust does not conduct any business activity and has no officers, directors or employees. The Trust and Trustee rely on third party service providers to perform administrative services for the Trust. Torch provided accounting, bookkeeping, informational and other services to the Trust related to the Net Profits Interests pursuant to the Administrative Services Agreement effective October 1, 1993 and an oral arrangement after termination of the Administrative Services Agreement on January 29, 2008 through April 1, 2008. From November 7, 2008 through December 23, 2008, Torch provided certain accounting services in connection with the Trust’s preparation of its Form 10-K for the year ended December 31, 2007 pursuant to an agreement between the Trust and Torch dated November 7, 2008. To facilitate the winding down of the Trust, Torch currently provides certain accounting and other services for the Trust pursuant to an agreement with the Trust entered into on March 26, 2009. The initial term of the agreement expired March 31, 2010. On March 31, 2010, Torch and the Trust extended the expiration date of the agreement by one year to March 31, 2011 or as sooner terminated by written notice from either party within 5 business days notice.
The Trust has no officers, directors or employees. The Trust and Trustee rely solely on receiving accurate information, reports and other representations from Torch and other service providers to the Trust. In executing and submitting this report on behalf of the Trust and with respect to Bruce L. Bisson in executing

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the certifications relating to this report, the Trustee and Bruce L. Bisson have relied upon the accuracy of such reports, information and representations.
In connection with the formation of the Trust, TRC and Velasco contracted to sell the oil and natural gas production from the Underlying Properties to Torch Energy Marketing Inc. (“TEMI”), a subsidiary of Torch, under a purchase contract (“Purchase Contract”) which expired upon termination of the Trust on January 29, 2008 (“Termination Date”). See Marketing Arrangements in this section for oil and natural gas pricing information pertaining to the Underlying Properties. The Working Interest Owners receive payments reflecting the proceeds of oil and natural gas sold and aggregate these payments, deduct applicable costs and make payments to the Trustee each quarter for the amounts due to the Trust. Prior to the termination of the Trust, Unitholders received quarterly cash distributions relating to oil and natural gas produced and sold from the Underlying Properties. Following the termination of the Trust, the Trustee established a non-interest bearing segregated cash reserve account (“Cash Reserve”) for payment by the Trust of certain actual, contingent and uncertain liabilities of the Trust. See footnote 4 of the Trust’s audited financial statements for additional information concerning the Cash Reserve. Because no additional properties will be contributed to the Trust, the assets of the Trust deplete over time and a portion of each cash distribution made by the Trust is analogous to a return of capital.
The Underlying Properties constitute working interests in the Chalkley Field in Louisiana (“Chalkley Field”), the Robinson’s Bend Field in the Black Warrior Basin in Alabama (“Robinson’s Bend Field”), fields that produce from the Cotton Valley formations in Texas (“Cotton Valley Fields”) and fields that produce from the Austin Chalk formation in Texas (“Austin Chalk Fields”). The Underlying Properties represent interests in all productive formations from 100 feet below the deepest productive formation in each field to the surface when the Trust was formed. The Trust therefore has no interest in deeper productive formations.
Separate conveyances (“Conveyances”) were used to transfer the Net Profits Interests in each state. Net proceeds (“Net Proceeds”), generally defined as gross revenues received from the sale of production attributable to the Underlying Properties during any period less property, production, severance and similar taxes, and development, operating, and certain other costs (excluding operating and development costs from the Robinson’s Bend Field prior to January 1, 2003), are calculated separately for each Conveyance. If, during any period, costs and expenses deducted in calculating Net Proceeds exceed gross proceeds under a Conveyance, neither the Trust nor Unitholders are liable to pay such excess directly, but the Trust will receive no payments for distribution to Unitholders with respect to such Conveyance until future gross proceeds exceed future costs and expenses plus the cumulative excess of such costs and expenses not previously recouped by TRC and Velasco plus interest thereon. The complete definitions of Net Proceeds are set forth in the Conveyances.
The Trust received the affirmative vote of the Unitholders of more than 66 2/3% of the outstanding Units to terminate the Trust at the meeting of Unitholders held on January 29, 2008. Upon termination of the Trust, among other things, the Trustee is required to sell the Net Profits Interests. Specifically, pursuant to Section 9.03(e) of the Trust Agreement if the property of the Trust Estate (as defined in the Trust Agreement) has not been sold prior to the end of one calendar year following the termination date, the Trustee, thereafter, must cause such assets to be sold at public auction. As the Trust was terminated by a vote of the Unitholders on January 29, 2008 (the “Termination Date”), the Trustee anticipates it will continue to consult with the Trust’s and Trustee’s financial and legal advisors in preparing the sales process and obtaining the necessary information required for disclosure regarding the Units to carry out the sale requirement under Section 9.03(e). No assurances can be given that the Trustee will be able to sell the Net Profits Interests, or the price that will be distributed to Unitholders following such a sale. Such distributions could be below the market value of the Units. The Trust can give no assurances of the effect of the results of the affirmative vote to terminate the Trust by the Unitholders on the continued listing of the Units on the New York Stock Exchange (NYSE) or any other national quotation system.

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As previously disclosed by the Trust in certain of its filings with the Securities and Exchange Commission (“SEC”), the Trust and certain working interest owners (TRC, Torch E&P Company and Constellation Energy Partners LLC) of the Underlying Properties were involved in an arbitration proceeding relating to the proper calculation of the quarterly Net Profits Interests payments owed to the Trust following the termination of the Trust. The working interest owners contended that the pricing mechanism contained in the terminated Purchase Contract (including the sharing price and minimum price mechanism) should continue to be utilized to calculate the quarterly Net Profits Interests payments. In the arbitration proceeding, the Trustee, not in its individual capacity but solely as Trustee of the Trust, contended that the sharing price mechanism of the Purchase Contract (which determined the calculation of the Net Profits Interests prior to the termination of the Oil and Gas Purchase Contract) did not survive the termination of the Purchase Contract or the termination of the Trust. On April 11, 2008, Trust Venture Company, LLC, which owns the majority of Units in the Trust, submitted an unopposed request to intervene in the arbitration and became a party to the arbitration. Trust Venture Company, LLC agreed with the Trustee, and took the position in the arbitration, that the sharing price mechanism of the Purchase Contract did not survive the termination of the Purchase Contract or the termination of the Trust.
The hearing on the merits in the arbitration commenced on June 16, 2008 and was completed on June 20, 2008. On July 18, 2008, alternative dispute resolution provider JAMS, through a panel of three arbitrators (“Arbitrators”), released an award notice to all parties (the “Award Notice”). In the Award Notice, the Arbitrators found that the Conveyances are not ambiguous and the pricing mechanism of the Purchase Contract is incorporated by reference into the Conveyances notwithstanding termination of the Purchase Contract. The Arbitrators therefore concluded that the pricing mechanism (including the sharing price and minimum price mechanism) continues to burden the Net Profits Interests and will do so for the life of the Conveyances. The Arbitrators also denied each party’s request for fees and costs; each party was required to bear its own fees and costs related to the arbitration. The Trust and Trustee incurred expenses as a result of the arbitration and expect to continue to incur expenses, including but not limited to legal fees, as a result of the winding down of the Trust. See also Item 3. Legal Proceedings for subsequent event information concerning the arbitration and Award Notice.
As previously disclosed by Trust in its Current Report on Form 8-K filed with the Securities and Exchange Commission (the “SEC”) on April 23, 2010, the Trust received a letter from the NYSE on April 20, 2010 informing the Trust that, as a result of its failure to timely file its Annual Report on Form 10-K for the fiscal year ended December 31, 2009 (the “2009 Annual Report”) with the SEC, the Trust was subject to certain procedures as specified in Section 802.01E, “SEC Annual Report Timely Filing Criteria,” of the NYSE’s Listed Company Manual (“Section 802.01E”) and further, regardless of the procedures specified in Section 802.01E, the NYSE could commence delisting procedures at any time during any period that is available to complete the filing of the 2009 Annual Report, if circumstances warrant.
As the Trust had been unable to obtain complete and accurate information regarding reserve information and the financial statements of the Trust required to be included in the 2009 Annual Report, the Trust remained unable to timely file its 2009 Annual Report. Therefore, the Trust requested an extension for continued listing and trading on the NYSE notwithstanding its failure to file its 2009 Annual Report. Failure of the Trust to make progress in its efforts to complete and file its SEC reports or failing to meet the minimum listing criteria could result in a suspension of the Trust’s listing and trading privileges.
Marketing Arrangements and Price Sharing
In connection with the formation of the Trust, TRC, Velasco and TEMI entered into the Purchase Contract which expired upon termination of the Trust. Pursuant to the Purchase Contract, TEMI was obligated to purchase all net production attributable to the Underlying Properties for an index price for oil and natural gas (“Index Price”), less certain gathering, treating and transportation charges, which were calculated monthly.

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The Index Price equals 97% of the weighted average spot market prices of oil and natural gas (“Average Market Prices”) at the four locations where TEMI sold production.
The Purchase Contract also provided that TEMI pay a minimum price (“Minimum Price”) for natural gas production, which is adjusted annually for inflation. When TEMI paid a purchase price based on the Minimum Price it received price credits (“Price Credits”), equal to the difference between the Index Price and the Minimum Price, that it was entitled to deduct in determining the purchase price when the Index Price for natural gas exceeded the Minimum Price. In addition, if the Index Price for natural gas exceeded the sharing price, which is adjusted annually for inflation (“Sharing Price”), TEMI was entitled to deduct 50% of such excess (“Price Differential”) in determining the purchase price. TEMI had an annual option to discontinue the Minimum Price commitment. However, if TEMI discontinued the Minimum Price commitment, it would no longer be entitled to deduct the Price Differential in calculating the purchase price and would have forfeited all accrued Price Credits. TEMI had no outstanding Price Credits on the Termination Date and had not exercised its option to discontinue the Minimum Price Commitment prior to the Purchase Contract’s expiration date.
Upon the Trust’s termination, the Working Interest Owners utilized the same pricing mechanisms (including the Sharing Price and Minimum Price commitment mechanisms) as the expired Purchase Contract in calculating Net Proceeds due to the Trust. The Minimum Price was $1.95, $1.87 and $1.83 per MMBtu for 2009, 2008 and 2007, respectively. The Sharing Price was $2.40, $2.30 and $2.26 for 2009, 2008 and 2007, respectively. The Working Interest Owners also have the same annual option to discontinue the Minimum Price commitment. As of December 31, 2009, the Working Interest Owners had no outstanding Price Credits and had not exercised its right to discontinue the Minimum Price commitment.
Gas production is purchased at the wellhead. Therefore, Net Proceeds do not include any amounts received in connection with extracting natural gas liquids from such production at natural gas processing or treating facilities.
Gathering, Treating and Transportation Arrangements
The Purchase Contract, which expired upon the Trust’s termination, entitled TEMI to deduct certain natural gas gathering, treating and transportation fees in calculating the purchase price for natural gas in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields. The amounts that were deducted in calculating the purchase price for such natural gas were set forth in the Purchase Contract and were not affected by the actual costs incurred by TEMI to gather, treat and transport natural gas. Upon the Trust’s termination, the Working Interest Owners were entitled to deduct the same natural gas gathering, treating and transportation fees that had previously been deducted by TEMI pursuant to the Purchase Contract in calculating Net Proceeds due to the Trust.
For the Robinson’s Bend Field, a gathering, treating and transportation fee of $0.260 per MMBtu, adjusted annually for inflation ($0.327, $0.314 and $0.308 per MMBtu for 2009, 2008, and 2007, respectively), plus fuel usage equal to 5% of revenues is deducted in computing Net Proceeds due to the Trust. Additionally, a gathering fee of $0.05 per MMBtu is deducted in calculating the purchase price for production from 73 of the 426 wells in the Robinson’s Bend Field. In computing Net Proceeds due to the Trust for the Austin Chalk Fields, $0.38 per MMBtu plus 17% of revenues are deducted as a fee to gather, treat and transport natural gas production. The purchase price for natural gas for production attributable to certain wells in the Cotton Valley Fields is reduced by a transportation fee of $0.045 per MMBtu.
During the years ended December 31, 2009, 2008 and 2007, gathering, treating and transportation fees deducted from the Net Proceeds calculations pertaining to production during the twelve months ended September 30, 2009, 2008 and 2007 in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled

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$1.0 million, $1.4 million and $1.5 million for 2009, 2008 and 2007, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase price from the Chalkley Field.
On February 5, 2008, the Trust and Trustee confirmed the existence of the Second Amendment to the Water Gathering and Disposal Agreement dated November 30, 2004 entered into by Robinson’s Bend Operating Company, LLC, a Delaware company, successor in interest to Torch Energy Associates, Ltd., a Texas limited partnership (“Producer”), and Everlast Energy LLC, a Delaware company, successor in interest to Velasco Gas Company Ltd., a Texas limited partnership, (“Gatherer”) (the “Second Amendment”). The Second Amendment provides that Section 3.1 of the Water Gathering and Disposal Agreement entered into as of August 9, 1990, by and between Producer’s and Gatherer’s respective predecessors in interest, as amended by the First Amendment to Water Gathering and Disposal Agreement entered into as of October 1, 1993, by and between such parties was amended such that the Producer shall pay Gatherer a fee of $0.53 per barrel for gathering, separation and disposal of water until Trust terminates, at which point Producer shall pay Gatherer a fee of $1.00 per barrel for gathering, separation and disposal of water.
Neither the Trust nor the Trustee is a party to the Agreement or the Second Amendment and the Trust did not approve or ratify the Second Amendment. No assurance can be given of the effect of the Second Amendment on the Trust, its assets or the production costs chargeable to the Trust based on the Agreement. Pursuant to the Alabama Conveyance for the Trust, certain production costs including “second category costs” as defined in the conveyance are chargeable to the Trust, provided that the costs and expenses paid by a working interest owner to an affiliate of the working interest owner and chargeable to the Trust for performing such operations or services shall not exceed competitive contract charges prevailing in the area for such operations or services. The Trust believes that the costs associated with the Agreement are considered “second category costs” and are likely subject to the competitive limitation noted above. See also Item 3. Legal Proceedings for subsequent event information concerning these matters.
Net Profits Interests
The Net Profits Interests entitle the Trust to receive 95% of the Net Proceeds attributable to oil and natural gas produced and sold from wells (other than infill wells) on the Underlying Properties. In calculating Net Proceeds from the Robinson’s Bend Field, operating and development costs incurred prior to January 1, 2003 were not deducted. In addition, the amounts paid to the Trust from the Robinson’s Bend Field during any calendar quarter are subject to a volume limitation (“Volume Limitation”) equal to the gross proceeds from the sale of 912.5 MMcf of natural gas, less property, production, severance and related taxes. The Robinson’s Bend Field production attributable to the Trust did not meet the Volume Limitation during the years ended December 31, 2009, 2008 and 2007 and is not expected to do so in the future.
The Net Profits Interests also entitle the Trust to 20% of the Net Proceeds of wells drilled on the Underlying Properties since the Trust’s establishment into formations in which the Trust has an interest, other than wells drilled to replace damaged or destroyed wells (“Infill Wells”). Infill Wells Net Proceeds (“Infill Well Net Proceeds”) represent the aggregate gross revenues received from Infill Wells less the aggregate amount of the following Infill Well costs: i) property, production, severance and similar taxes; ii) development costs; iii) operating costs; and iv) interest on the recovered portion, if any, of the foregoing costs computed at a rate of interest announced publicly by Citibank, N.A. in New York as its base rate.
Availability of Reports
The Trust’s principal offices are located at Rodney Square North, 1100 North Market Street, Wilmington, Delaware 19890. The telephone number is (302) 636-6016. The Trust files quarterly and annual reports and other information with the Securities and Exchange Commission (“SEC”). You may read and copy any document that we file at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms. Our SEC filings are also available to the public from the SEC’s website at http://www.sec.gov and on our website, http://www.torchroyalty.com, which features all of our current SEC

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filings free of charge as soon as reasonably practicable after they are filed with the SEC. Our SEC filings are also available at the office of the NYSE. For further information on obtaining copies of our public filings from the NYSE, visit the NYSE website at http://www.nyse.com. Information contained on the Trust’s website or any other website referenced herein is not incorporated by reference into this report and does not constitute a part of this report.
Item 1A. Risk Factors
You should carefully consider the following risk factors in addition to the other information included in this report. The risks set forth below are in addition to risks that apply to most businesses. The Trustee is in the process of winding down and liquidating the Trust after the affirmative vote of the requisite number of Unitholders. See Trust Termination below in this item. The other Risk Factors set forth below should be considered in light of the wind up and liquidation of the Trust. If any of these risks or uncertainties actually occur, the Trust’s financial condition and results of operations and the future and current value of the Net Profits Interests could be materially adversely affected. Additional risks not presently known to the Trust or which the Trust considers immaterial based on information currently available to it may also materially adversely affect the Trust. Because of these factors, past financial performance should not be considered an indication of future performance.
Trust Termination
The Trust received the affirmative vote of the Unitholders of more than 66 2/3% of the outstanding Units to terminate the Trust at the meeting of Unitholders held on January 29, 2008. Upon termination of the Trust, among other things, the Trustee is required to sell the Net Profits Interests. No assurances can be given that the Trustee will be able to sell the Net Profits Interests, or that the ultimate proceeds that will be distributed to Unitholders following such a sale will be equivalent to the market value of such interests. Such distributions could be below the market value of the Units. The Trust and Trustee cannot anticipate the results that such termination of the Trust will have on its ability to sell the Net Profits Interests.
Specifically, pursuant to Section 9.03(e) of the Trust Agreement if the property of the Trust Estate (as defined in the Trust Agreement) has not been sold prior to the end of one calendar year following the termination date (prior to January 29, 2009), the Trustee must then cause such assets to be sold at public auction. As the Trust was terminated by a vote of the Unitholders on January 29, 2008, the Trustee anticipates it will continue to consult with the Trust’s and Trustee’s financial and legal advisors in preparing the sales process and obtaining the necessary information required for disclosure regarding the Units to carry out the sale requirement under Section 9.03(e). There can be no assurance at this time of the specific timetable in which the Trust and Trustee would be able to obtain all the information advisable and necessary concerning the Net Profits Interests in order to prepare and finalize the sales process.
The Trust’s continuing failure to timely file certain periodic reports with the SEC during the wind up and liquidation of the Trust may pose significant risks to the Trust’s business, which could materially and adversely affect the Trust financial condition and results of operation and the current and/or future value of the Net Profits Interests.
The public trading price for the Units tends to be tied to the recent and expected levels of cash distribution on the Units. The amounts available for distribution by the Trust vary in response to numerous factors outside the control of the Trust, including prevailing prices for natural gas produced from the Trust’s Net Profits Interests. The market price is not necessarily indicative of the value that the Trust would realize if it sold those Net Profits Interests to a third party buyer. In addition, such market price is not necessarily reflective of the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a Unitholder over the life of these depleting assets will equal or exceed the purchase price paid by the Unitholder.

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The Trust can give no assurances of the effect of the results of the affirmative vote to terminate the Trust by the Unitholders on the continued listing of the Units on the NYSE or any other national quotation system. Failure of the Trust to make progress in its efforts to complete and file its SEC reports or failing to meet the minimum listing criteria of the NYSE could result in a suspension of the Trust’s listing and trading privileges. If the NYSE does not grant the Trust extensions to file its periodic reports with the NYSE, it has the right to begin proceedings to delist the units. A delisting of the Trust’s units may have a material adverse effect on the Trust, among other things reducing the liquidity and market price of the units.
If natural gas and oil prices decline significantly, the Trust’s cash flow from operations will likely decline and the Trust may have to lower the cash distributions or may not be able to pay distributions at all during the wind up and liquidation of the Trust.
The Trust’s cash distributions, operating results and the value of the Net Profits Interest are substantially dependent on prices of natural gas and, to a lesser extent, oil. Prices for oil and natural gas are volatile and are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond the control of the Trust and/or Torch. These factors include:
    The domestic and foreign supply of and demand for oil and natural gas;
 
    The price and quantity of foreign imports of oil and natural gas;
 
    The level of consumer product demand;
 
    Weather conditions, including but not limited to, hurricanes in the Gulf of Mexico, can adversely impact cash distributions received by the Trust. If the wells drilled on the Underlying Properties and related infrastructure were to be damaged by adverse weather conditions, cash flows distributed to Unitholders could be delayed during the period in which damage to such assets were repaired. Additionally, costs associated with such repairs not covered by insurance would reduce cash distributions received by the Trust;
 
    Overall domestic and global economic conditions;
 
    Political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America and Russia, and acts of terrorism or sabotage;
 
    The ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
 
    Technological advances affecting energy consumption;
 
    Domestic and foreign governmental regulations and taxation;
 
    The impact of energy conservation efforts;
 
    The capacity of natural gas pipelines and other transportation facilities to the Trust’s production; and
 
    The price and availability of alternative fuels.
Any substantial and extended decline in the price of natural gas and oil would have an adverse effect on the Trust’s revenues, cash distributions and current and/or future value of the Net Profits Interests.
Trust expenses may have an adverse impact on the distributions to Unitholders during the wind up and liquidation of the Trust.
Trust expenses, Sarbanes-Oxley compliance and legal fees during the wind down and liquidation of the Trust may have an adverse effect on the ability of the Trust to pay quarterly distributions to the Unitholders. The Trustee has set up a cash reserve account pursuant to the Trust Agreement in order to provide the funds necessary for an orderly wind up and liquidation of the Trust.

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The estimated reserve quantities in this report are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of the Trust’s reserves.
Estimates of economically recoverable natural gas and oil reserves and of future net cash flows are based upon a number of variable factors and assumptions, all of which are to some degree speculative and may vary considerably from actual results. Prices for oil and natural gas are volatile and are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond the control of the Trust and/or Torch. Therefore, actual production, revenues, taxes and development and operation expenditures may not occur as estimated. As disclosed by the Trust in its Annual Report on Form 10-K for the period ended December 31, 2007 and in this Annual Report, on December 30, 2008, Trust Venture Company, LLC filed and subsequently served a derivative lawsuit against Constellation Energy Partners LLC in Alabama state court alleging counts, in accordance with, inter alia, Section 3816 of the Delaware Statutory Trust Act, codified at 12 Del. C. 3816(a), to (i) recover any overcharges to the Trust by Constellation Energy Partners LLC related to administrative costs, water gathering, treating and disposal costs and severance taxes and (ii) require Constellation Energy Partners LLC to provide an accounting of its revenues and expenses as required under the Conveyance filed of record in Tuscaloosa County, Alabama. There can be no assurance as to the outcome or result of this derivative lawsuit or the effect of the derivative lawsuit may have on the calculation of the reserve reports and the estimated reserve quantities.
Future results of the Trust will depend upon the ability of the owners of the Underlying Properties to develop, produce and sell their oil and natural gas reserves and the corresponding proceeds from such sales which may vary widely. The reserve data included herein are estimates only and are subject to many uncertainties. Actual quantities of oil and natural gas may differ considerably from the amounts set forth herein. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The present value, discounted at 10%, of future net cash flows from proved reserves attributable to the Net Profits Interests does not represent the fair market value of the proved reserves, or the price at which the Net Profits Interests could be sold. A determination of fair market value would involve consideration of many factors in addition to the present value, discounted at 10%. An impairment loss is recognized when the net carrying value of the Net Profits Interests exceeds its fair market value. No impairment loss was recognized during the years ended December 31, 2009, 2008 and 2007.
As more Infill Wells are drilled, they could cause a reduction in amounts payable to the Trust or a purchaser of the Net Profits Interests.
The Net Profits Interests include a 20 percent net profit interest in Infill Wells. Infill Wells may recover a portion of the reserves that would otherwise be produced from wells burdened by the Trust’s Net Profits Interests. Since the Trust is entitled to receive 95 percent of the Net Proceeds from production burdened by its Net Profits Interests but only 20 percent of the net profits from Infill Wells, the drilling of Infill Wells may reduce payments to the Trust, and ultimately distributions to Trust Unitholders.
The Trust’s business is subject to operational risks that may not be fully insured, which, if they were to occur, could adversely affect the Trust’s financial condition or results of operations and, as a result, the Trust’s ability to pay distributions to Unitholders.
Cash payments to the Trust are derived from the production and sale of natural gas and oil, which operations are subject to risk inherent in such activities, such as blowouts, cratering, explosions, damage to equipment caused by weather conditions, facility or equipment malfunctions, uncontrollable flows of oil, natural gas or well fluids, fires, pollution and other environmental risks. These risks could result in substantial losses which are deducted in calculating the Net Proceeds paid to the Trust due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and

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suspension of operations. The Trust may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on the Trust’s business activities, financial condition, results of operations and ability to pay distributions to Unitholders. The failure of an operator of the Underlying Properties to conduct its operations or discharge its obligations in a proper manner could have an adverse effect on the Net Proceeds payable to the Trust.
The Trust may be unable to compete effectively with larger companies, which may adversely affect the Trust’s ability to generate sufficient revenue and its ability to pay distributions to Unitholders prior to the windup and liquidation of the Trust.
The Trust’s distributions are dependent on natural gas production and prices and, to a lesser extent, oil production and prices from the Underlying Properties. The natural gas industry is highly competitive in all of its phases. In marketing production from the Underlying Properties, major natural gas companies, independent natural gas concerns, and individual producers and operators may provide competition. Many of these competitors have greater financial and other resources than the companies marketing the production of the Trust. Competition may also be presented by alternative fuel sources, including heating oil and other fossil fuels. In addition, the Trust and Trustee do not independently monitor the Working Interest Owners financial viability on an ongoing basis which may have an effect on the Trust and its ability to pay distributions to the Unitholders.
The Trust’s operations are subject to regulations which may limit the Trust’s production of natural gas or the price that the Trust receives for natural gas.
The production, transportation and sale of natural gas from the Underlying Properties are subject to Federal and state governmental regulation, including regulation of tariffs charged by pipelines, taxes, the prevention of waste, the conservation of natural gas, pollution controls and various other matters. The United States has governmental power to impose pollution control measures.
If it is determined that the Trust is subject to the Texas margin tax, the Trustee may have to withhold a disproportionate amount from future distributions to pay the tax liability.
The Trustee does not intend to pay any amounts for the Texas margin tax for tax years 2007, 2008 and 2009, based on the assumption that the Trust is exempt from tax as a passive entity; however, there is currently no clear statutory authority that the Trust meets requirements for the margin tax exemption as a passive entity. If it is subsequently determined that the Trust is not exempt from the margin tax, the Trust would be required to deduct and withhold from future distributions the amounts necessary to pay the margin tax for the years ended December 31, 2007, 2008 and 2009, including the tax liability accruing on income distributed after December 2006 attributable to 2007, 2008 and 2009 Trust revenues from which no tax was withheld. For more information about the Texas margin tax, see Note 3 to the Trust’s financial statements.
Federal Regulation
The Underlying Properties are subject to the jurisdiction of FERC with respect to various aspects of natural gas operations including the marketing and production of natural gas. The Natural Gas Act and the Natural Gas Policy Act (collectively, the “Acts”) mandate Federal regulation of interstate transportation of natural gas. The Natural Gas Wellhead Decontrol Act of 1989 terminated wellhead price controls on all domestic natural gas on January 1, 1993. Numerous questions have been raised concerning the interpretation and implementation of several significant provisions of the Acts and of the regulations and policies promulgated by FERC there under. A number of lawsuits and administrative proceedings have been instituted which challenge the validity of regulations implementing the Acts. In addition, FERC currently has under

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consideration various policies and proposals that may affect the marketing of natural gas under new and existing contracts. Accordingly, Torch is unable to predict the impact of any such government regulation.
In the past, Congress has been very active in the area of natural gas regulation. Legislation enacted in repeals incremental pricing requirements and natural gas use restraints previously applicable. 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 Underlying Properties and the Trust.
State Regulation
Many state jurisdictions have at times imposed limitations on the production of natural gas by restricting the rate of flow for natural gas wells below their actual capacity to produce and by imposing acreage limitations for the drilling of a well. States may also impose additional regulations of these matters. Most states regulate the production of natural gas, including requirements for obtaining drilling permits, the method of developing new fields, provisions for the unitization or pooling of natural gas properties, the spacing, operation, plugging and abandonment of wells and the prevention of waste of natural gas resources. The rate of production may be regulated and the maximum daily production allowable from natural gas wells may be established on a market demand or conservation basis or both.
Because the Trust handles oil and natural gas petroleum products, the Trust may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances in the environment.
Activities on the Underlying Properties are subject to existing Federal, state and local laws, rules and regulations relating to the protection of public health and welfare, safety and the environment, including, without limitation, laws regulating the release of materials into the environment and laws protecting areas of particular environmental concern. It is anticipated that, absent the occurrence of an unanticipated event, compliance with these laws will not have a material adverse effect upon the Trust or Unitholders. Torch has informed the Trust that it cannot predict what effect future regulation or legislation, enforcement policies there under, and claims for damages to property, employees, other persons and the environment resulting from operations on the Underlying Properties could have on the Trust or Unitholders. However, pursuant to the terms of the Conveyances, any costs or expenses incurred by TRC or Velasco in connection with environmental liabilities, to the extent arising out of or relating to activities occurring on, or in connection with, or conditions existing on or under, the Underlying Properties before October 1, 1993, will be borne by TRC or Velasco and not the Trust and will not be deducted in calculating Net Proceeds and will, therefore, not reduce amounts payable to the Trust.
Net Proceeds Attributable to the Robinson’s Bend Field have declined significantly.
Prior to December 31, 2002, lease operating expenses were not deducted in calculating the Net Proceeds payable to the Trust from the Robinson’s Bend Field. In accordance with the provisions of the Net Profits Interest conveyance covering the Robinson’s Bend Field, commencing with the second quarter 2003 distribution (pertaining to the quarter ended March 31, 2003 production) lease operating expenses and capital expenditures have been deducted in calculating Net Proceeds. These expenses and expenditures are being reviewed by the Trust, including the Second Amendment of the Water Gathering and Disposal. The Trust receives no payments for distributions to Unitholders with respect to the Robinson’s Bend Field when proceeds do not exceed the sum of costs and expenses and the cumulative excess of such costs and expenses including interest (“Robinson’s Bend Field Cumulative Deficit”). The Trust received no payments for distributions to Unitholders with respect to the Robinson’s Bend Field during the each of the three years ended December 31, 2007, 2008 and 2009.

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The Robinson’s Bend Field Cumulative Deficit at December 31, 2009 (pertaining to production as of September 30, 2009) was approximately $2.8 million. Neither the Trust nor Unitholders are liable to pay such deficit. However, the Trust will receive no payments with respect to the Robinson’s Bend Field until future proceeds exceed the Robinson’s Bend Cumulative Deficit.
The market price for the Trust’s Units may not reflect the value of the Net Profits Interests held by the Trust.
The public trading price for the Trust Units tends to be tied to the recent and expected levels of cash distributions on the Trust Units. The amounts available for distribution by the Trust vary in response to numerous factors outside the control of the Trust, including prevailing prices for oil and natural gas produced from the Underlying Properties. The market price of the Trust Units is not necessarily indicative of the value that the Trust would realize if the Net Profits Interests were sold to a third party buyer. In addition, such market price is not necessarily reflective of the fact that, since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Trust Units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a Unitholder over the life of these depleting assets will equal or exceed the purchase price paid by the Unitholder.
Financial information of the Trust is not prepared in accordance with GAAP.
The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the U.S., or GAAP. Although this basis of accounting is permitted for royalty trusts by the Securities and Exchange Commission, the financial statements of the Trust differ from GAAP financial statements because net profits income is not accrued in the month of production, expenses are not recognized when incurred and cash reserves may be established for certain contingencies that would not be recorded in GAAP financial statements.
The Trust is dependent on certain service providers to provide various services to the Trust.
The Trust and Trustee rely on third party service providers to perform administrative services, Sarbanes-Oxley compliance services and other services for the Trust. Torch provided accounting, bookkeeping, informational and other services to the Trust related to the Net Profits Interests pursuant to the Administrative Services Agreement effective October 1, 1993 and an oral arrangement after termination of the Administrative Services Agreement on January 29, 2008 through April 1, 2008.
On November 7, 2008, the Trust and Torch entered an agreement whereby Torch provided certain accounting services in connection with the preparation of the Trust’s Form 10-K for the year ended December 31, 2007. Such service agreement expired December 23, 2008.
To facilitate the winding down of the Trust, Torch currently provides certain accounting and other services for the Trust pursuant to an agreement with the Trust entered into on March 26, 2009. The initial term of the agreement expired on March 31, 2010. On March 31, 2010, Torch and the Trust extended the expiration date of the agreement by one year to March 31, 2011 or as sooner terminated by written notice from either party within 5 business days notice. The inability of the Trust to hire qualified services providers to assist in the wind up and liquidation of the Trust may have a material adverse effect on the operations of the Trust.
Unitholders have limited voting rights.
Voting rights as a Unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Unitholders or an annual or other periodic re-

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election of the Trustee. Unlike corporations which are generally governed by boards of directors elected by their equity holders, the Trust is administered by a corporate trustee in accordance with the Trust Agreement and other organizational documents. The Trustee has extremely limited discretion in its administration of the Trust as set forth in the Trust’s Trust Agreement.
Item 1B. Unresolved Staff Comments
The Trust does not currently have any unresolved Securities and Exchange Commission staff comments.
Item 2. Properties
Description of the Underlying Properties
Chalkley Field. The Underlying Properties in the Chalkley Field, located in Cameron Parish, Louisiana, include an average 16.2% working interest (12.1% net revenue interest) in five unitized wells (excluding Infill Wells) producing from the Miogyp “B” reservoir. As of December 31, 2009, one Infill Well has been drilled on the Underlying Properties in the Chalkley Field. The average working interest and net revenue interest (net to the Trust’s 20% interest) for the Chalkley Infill Well is approximately 3.2% and 2.4%. These wells produce from a depth in excess of 14,000 feet. A subsidiary of ExxonMobil Corporation operates the wells.
Robinson’s Bend Field. The Underlying Properties include an average 40.0% working interest (30.4% net revenue interest) in 392 wells (excluding Infill Wells) in the Robinson’s Bend Field in the Black Warrior Basin of Alabama. As of December 31, 2009, 34 Infill Wells have been drilled on the Underlying Properties in the Robinson’s Bend Field. The average working interest and net revenue interest of the Robinson’s Bend Infill Wells (net to the Trust’s 20% interest) is approximately 6.0% and 4.5%, respectively. All of the wells in the Robinson’s Bend Field are operated by a third party, Robinson’s Bend Operating II, LLC.
Cotton Valley Fields. The Underlying Properties include an average 52.9% working interest (39.2% net revenue interest) in 41 wells (excluding Infill Wells) in four fields that produce from the Upper and Lower Cotton Valley formations in Texas. As of December 31, 2009, 32 Infill Wells have been drilled on the Underlying Properties in the Cotton Valley Fields. The average working interest and net revenue interest of the Cotton Valley Fields Infill Wells (net to the Trust’s 20% interest) is approximately 14.8% and 11.4%, respectively. A subsidiary of Torch operates 40 of these wells. The remaining wells are operated by Samson Lone Star Limited Partnership (“Samson”).
Austin Chalk Fields. The Underlying Properties include an average of 18.4% working interest (14.1% net revenue interest) in 63 wells in the Austin Chalk Fields of Central Texas. Production from these fields is derived primarily from the highly fractured Austin Chalk formation using horizontal drilling techniques. A subsidiary of Torch operates two wells in the Austin Chalk Fields. The remaining wells in the Austin Chalk Fields are operated by third parties.
Oil and Natural Gas Reserves
The pre-tax future net cash flows, discounted at 10%, attributable to the net proved reserves of the Net Profits Interests was approximately $10.9 million as of December 31, 2009. Future cash flows attributable to the Robinson’s Bend Field’s Net Profits Interest were estimated to have no value to the Trust as of December 31, 2009. See Note 7 of the audited financial statements for additional information concerning the net proved reserves of the Net Profits Interests.

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As disclosed by the Trust in its Annual Report on Form 10-K for the year ended December 31, 2008 and in this Annual Report, on December 31, 2009, Trust Venture Company, LLC filed and subsequently served a derivative lawsuit against Constellation Energy Partners LLC in Alabama state court alleging counts, in accordance with, inter alia, Section 3816 of the Delaware Statutory Trust Act, codified at 12 Del. C. 3816(a), to (i) recover any overcharges to the Trust by Constellation Energy Partners LLC related to administrative costs, water gathering, treating and disposal costs and severance taxes and (ii) require Constellation Energy Partners LLC to provide an accounting of its revenues and expenses as required under the Conveyance filed of record in Tuscaloosa County, Alabama. There can be no assurance as to the outcome or result of this derivative lawsuit or the effect of the derivative lawsuit may have on the calculation of the reserve reports and the estimated reserve quantities.
Well Count and Acreage Summary
The following table shows, as of December 31, 2009, the gross and net interest in oil and natural gas wells for the Underlying Properties:
                                 
    Natural Gas Wells     Oil Wells  
    Gross     Net     Gross     Net  
Chalkley Field
    6       0.8              
Robinson’s Bend Field
    426       170.4              
Cotton Valley Fields
    73       25.4              
Austin Chalk Fields
    28       4.7       35       5.9  
 
                       
 
                               
Total
    533       201.3       35       5.9  
 
                       
The following table shows the gross and net acreage for the Underlying Properties as of December 31, 2009. A gross acre in the following table refers to the number of acres in which a working interest is owned directly by the Trust. The number of net acres is the sum of the fractional ownership of working interests owned directly by the Trust in the gross acres expressed as a whole number and percentages thereof. A net acre is deemed to exist when the sum of fractional ownership of working interests in gross acres equals one.
                 
    Acreage  
    Gross     Net  
Chalkley Field
    2,152       348  
Robinson’s Bend Field
    33,404       14,288  
Cotton Valley Fields
    4,411       2,606  
Austin Chalk Fields
    23,895       4,042  
Total
    63,862       21,284  
 
           
Drilling Activity
The following table sets forth the results of drilling activity for the Underlying Properties during the three years ended December 31, 2009. Gross wells, as it applies to wells in the following table, refers to the number of wells in which a working interest is owned directly by the owners of the Underlying Properties and Infill Wells (“Gross Well”). A net well (“Net Well”) represents the sum of the fractional ownership working interests in the Gross Wells expressed as whole numbers and percentages thereof.
All of the wells shown below represent Infill Wells drilled on the Underlying Properties in the Chalkley Field, Cotton Valley Fields and the Robinson’s Bend Field. The Net Profits Interest entitle the Trust to 20% of Infill Well Net Proceeds which is defined as gross proceeds from the sale of production attributable to Infill Wells less all production, drilling and completion costs of such wells. Infill Well Net Proceeds are calculated by aggregating the proceeds and costs from Infill Wells on a state by state basis.

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    Development Wells – Chalkley Field (a)
    Gross   Net
    Productive   Dry Holes   Total   Productive   Dry Holes   Total
2009
  0   0   0   0   0   0
2008
  0   0   0   0   0   0
2007
  1   0   1   0.03   0   0.03
                         
    Development Wells – Cotton Valley Fields
    Gross   Net
    Productive   Dry Holes   Total   Productive   Dry Holes   Total
2009
  0   0   0   0.0   0   0.0
2008
  1   0   1   0.2   0   0.2
2007
  2   0   2   0.3   0   0.3
                         
    Development Wells – Robinson’s Bend Field (b)
    Gross   Net
    Productive   Dry Holes   Total   Productive   Dry Holes   Total
2009
  0   0   0   0   0   0
2008
  3   0   3   0.2   0   0.2
2007
  8   0   8   1.2   0   1.2
 
(a)   The Trust has not received cash distributions with respect to the Infill Well drilled in the Chalkley Field. As of December 31, 2009, costs and expenses exceeded gross revenues by approximately $2.4 million (before interest). The Trust will receive no payments for distributions with respect to the Chalkley Field Infill Well until the future proceeds exceed the sum of future costs and expenses and the cumulative excess of such costs and expenses including interest.
 
(b)   The Trust has not received cash distributions with respect to the Infill Wells drilled in the Robinson’s Bend Field. As of December 31, 2009 (pertaining to sales through September 30, 2009), costs and expenses exceeded gross revenues by approximately $1.6 million. The Trust will receive no payments for distributions with respect to the Robinson’s Bend Infill Wells until the future proceeds exceed the sum of future costs and expenses and the cumulative excess of such costs and expenses including interest.
There was no other drilling activity on the Underlying Properties during the three years ended December 31, 2009.
Oil and Natural Gas Sales Prices and Production Costs
The following table sets forth, for the Underlying Properties, the net production volumes of natural gas and oil, the weighted average lifting cost and taxes per Mcfe deducted in calculating Net Proceeds and the weighted average sales price per Mcf of natural gas and Bbl of oil for production attributable to Net Proceeds received by the Trust during the years ended December 31, 2009, 2008 and 2007 (derived from production during the twelve months ended September 30, 2009, 2008 and 2007, respectively).
                         
    Chalkley, Cotton Valley And Austin Chalk Fields  
    2009     2008     2007  
Production:
                       
Natural Gas (MMcf)
    1,342       1,544       1,811  
Oil (Mbbl)
    15       14       15  
 
                       
Weighted average lifting cost per Mcfe
  $ 1.31     $ 0.92     $ 1.15  
Weighted average taxes on production per Mcfe
  $ 0.33     $ 0.47     $ 0.39  
Weighted average sales price (a)
                       
Natural Gas ($/Mcf)
  $ 3.46     $ 5.51     $ 4.29  
Oil ($/Bbl)
  $ 48.11     $ 95.11     $ 57.51  

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    Robinson’s Bend Field  
    2009     2008     2007  
Production:
                       
Natural Gas (MMcf)
    1,530       1,579       1,667  
Oil (Mbbl)
                 
 
                       
Weighted average lifting cost per Mcfe
  $ 4.49     $ 4.19     $ 3.59  
Weighted average taxes on production per Mcfe
  $ 0.23     $ 0.47     $ 0.34  
Weighted average sales price (a)
                       
Natural Gas ($/Mcf)
  $ 2.92     $ 4.85     $ 3.83  
Oil ($/Bbl)
  $     $     $  
 
(a)   Average sales prices are reflective of natural gas prices received by the Trust less certain gathering, treating and transportation charges.
Item 3. Legal Proceedings
On October 16, 2008, Trust Venture Company, LLC and Wilmington Trust Company, solely in its capacity as Trustee for the Torch Energy Royalty Trust, (together, “Plaintiffs”) filed a petition against Torch Royalty Company, Torch E&P Company, and Constellation Energy Partners LLC (collectively, “Defendants”) in the District Court of Harris County, Texas. The petition sought to vacate the arbitration award issued by the JAMS Panel in Defendants’ favor on July 18, 2008 in the arbitration captioned Torch Royalty Co., et al. v. Wilmington Trust Co., et al., JAMS Reference No. 13100017310. See Item 1. Business – General for a description of the arbitration. Defendants filed a motion to dismiss the Plaintiffs’ petition and to confirm the arbitration award. On or about December 10, 2008, the Court entered an Order dismissing the petition and granting the Defendants’ motion to confirm the arbitration award.
On December 22, 2008, the Trustee received a demand letter from Trust Venture Company, LLC with respect to certain enumerated costs — including administrative costs and costs for water gathering, treating and disposal — that are deducted by the working interest owners of certain of the Underlying Properties from the Net Profit Interests before remitting the Net Proceeds to the Trustee and the Trust. Trust Venture Company, LLC has concluded that the Trust has been overcharged (and continues to be overcharged) by the working interest owners of certain of the Underlying Properties and that these overcharges have damaged the Trust (and as a result, all of the Trust’s Unitholders). In addition, Trust Venture Company, LLC asserts that the working interest owners have failed to provide the required accountings as set forth in the Conveyances and that the Trust may request the court to require the working interest owners to provide such an accounting. Trust Venture Company, LLC requested that the Trustee either institute legal action against the working interest owners, or authorize Trust Venture Company, LLC to commence a derivative action against the current working interest owner of the Alabama property in accordance with, inter alia, Section 3816 of the Delaware Statutory Trust Act, codified at 12 Del. C. 3816(a), to recover all overcharges related to administrative costs, water gathering, treating and disposal costs and all overcharges reflected in the accounting. The Trustee responded on December 22, 2008 to Trust Venture Company, LLC with a request for additional information which it has now received. The Trustee carefully considered Trust Venture Company, LLC’s demand letter, and concluded, in the reasoned exercise of its business judgment, that it is in the best interest of the Trust and all Unitholders to authorize Trust Venture Company, LLC to commence a derivative action and provided its authorization as of December 30, 2008.
As disclosed by the Trust in its Annual Report on Form 10-K for the year ended December 31, 2007 (“2007 Annual Report”), Trust Venture intended to commence a derivative action against Constellation Energy Partners LLC, the working interest owner of certain oil and natural gas fields located in Alabama, in accordance with, inter alia, Section 3816 of the Delaware Statutory Trust Act, codified at 12 Del. C. 3816(a), to (i) recover any overcharges to the Trust by Constellation Energy Partners LLC related to administrative costs, water gathering, treating and disposal costs and severance taxes and (ii) require Constellation Energy Partners LLC to provide an accounting of its revenues and expenses as required under the Conveyance filed of record in Tuscaloosa County, Alabama. On December 30, 2008, Trust Venture filed and subsequently

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served a derivative lawsuit against Constellation Energy Partners LLC in Alabama state court alleging such overcharges, challenging the calculation of the Net Profits Interests under the Conveyances that were used to transfer the net profits interests in each state, and demanding an accounting of Constellation Energy Partners LLC’s revenues and expenses. In response to the derivative lawsuit, on February 9, 2009, Constellation Energy Partners LLC filed in Alabama state court a motion to dismiss such lawsuit without prejudice in favor of arbitration in Texas on various grounds, including Trust Venture’s alleged lack of standing and Trust Venture’s alleged failure to comply with certain contractual agreements. The Alabama state court denied Constellation Energy Partners LLC’s motion to dismiss on February 25, 2009, and so the Alabama derivative action is proceeding against Constellation Energy Partners LLC.
On February 12, 2009, the Trustee received a certified copy of a demand for arbitration dated February 9, 2009 by Constellation Energy Partners LLC before JAMS in Texas (the “Demand Notice”) seeking a declaratory judgment that Constellation Energy Partners LLC (i) correctly calculated and paid the Net Profits Interests payments due to the Trust, (ii) correctly charged the Trust for certain well accounting services and severance taxes, and (iii) has complied with its contractual reporting requirements due to the Trust. In the Demand Notice, Constellation Energy Partners LLC claimed that, because the Trust authorized Trust Venture to file the derivative lawsuit, “there exists a judicable conflict between Constellation Energy Partners LLC and the Trust that is subject to resolution by arbitration.”
On February 12, 2009, Trust Venture filed an emergency motion in Alabama state court to stay the arbitration demanded by Constellation Energy Partners LLC until such time as the court issues a judgment as to the enforceability of the arbitration agreement made by and between the Trust and Constellation Energy Partners LLC. The court denied that motion on February 25, 2009. On March 9, 2009, the Trustee filed its own motion in the same Alabama state court seeking to intervene in the derivative action for the limited purpose of moving for a stay of the Texas arbitration until resolution of the derivative action. The Alabama state court heard oral argument on the Trustee’s motion on March 25, 2009, and on April 1, 2009, the Alabama state court denied the Trustee’s motion to stay the Texas arbitration and further denied Constellation Energy Partners LLC’s motion to stay the Alabama state court derivative action. Subsequently, the Trustee filed a motion to dismiss or stay the Texas arbitration with JAMS and the arbitration panel heard oral argument on April 10, 2009 and on April 13, 2009 granted the Trustee’s motion to stay the Texas arbitration proceedings pending the outcome of the Alabama derivative action. The arbitration panel subsequently entered an Order of Dismissal with respect to the Texas arbitration dated July 27, 2009. There can be no assurance as to the outcome or result of the Alabama derivative litigation or that Constellation Energy Partners LLC will not challenge the Order of Dismissal entered by the arbitration panel on July 27, 2009 or file other arbitration claims. On August 21, 2009, the Alabama state court added the Trust as a nominal plaintiff in the Alabama derivative action that is proceeding against Constellation Energy Partners LLC.
Item 4. (Removed and Reserved)

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PART II
Item 5. Market for Registrant’s Units, Related Unitholder Matters and Registrants Purchases of Equity Securities
The Units are listed and traded on the NYSE under the symbol “TRU.” At March 31, 2010, there were 8,600,000 Units outstanding and approximately181 Unitholders of record. The following table sets forth, for the periods indicated, the high and low sales prices per Unit on the NYSE and the amount of quarterly cash distributions per Unit made by the Trust:
                         
                    Cash  
    High     Low     Distributions  
Fiscal Year Ended December 31, 2008:
                       
Quarter ended March 31, 2008
  $ 10.91     $ 8.47     $ 0.03  
Quarter ended June 30, 2008
  $ 12.65     $ 6.57     $ 0.00  
Quarter ended September 30, 2008
  $ 9.74     $ 1.63     $ 0.00  
Quarter ended December 31, 2008
  $ 4.18     $ 1.01     $ 0.00  
 
                       
Fiscal Year Ended December 31, 2009:
                       
Quarter ended March 31, 2009
  $ 2.99     $ 1.19     $ 0.00  
Quarter ended June 30, 2009
  $ 4.80     $ 1.44     $ 0.35  
Quarter ended September 30, 2009
  $ 8.74     $ 3.20     $ 0.00  
Quarter ended December 31, 2009
  $ 7.35     $ 4.36     $ 0.10  
 
                       
Interim Period:
                       
Quarter ended March 31, 2010
  $ 5.35     $ 3.36     $ 0.00  
Quarter ended June 30, 2010
  $ 5.48     $ 3.75     $ 0.00  
Item 6. Selected Financial Data (In thousands, except per Unit amounts)
                                         
    Year Ended December 31,  
    2009     2008     2007     2006     2005  
Net profits income
  $ 2,516     $ 6,217     $ 4,842     $ 7,796     $ 5,818  
Distributable income
  $ 1,236     $ 3,162     $ 4,133     $ 7,262     $ 5,601  
Distributions declared
  $ 3,891     $ 258     $ 4,102     $ 7,250     $ 5,590  
Distributable income per Unit
  $ 0.14     $ 0.37     $ 0.48     $ 0.84     $ 0.65  
Cash Reserve per Unit
  $ 0.10     $ 0.46     $ 0.00     $ 0.00     $ 0.00  
Distributions per Unit
  $ 0.45     $ 0.03     $ 0.48     $ 0.84     $ 0.65  
Total assets (at end of period)
  $ 15,250     $ 19,623     $ 16,694     $ 18,386     $ 21,675  
Distributable income of the Trust consists of the excess of net profits income plus Infill Well Net Proceeds and other income less general and administrative expenses of the Trust. The Trust recognizes net profits income during the period in which amounts are received by the Trust.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
Discussion of Years Ended December 31, 2009, 2008, and 2007
Because a modified cash basis of accounting is utilized by the Trust, Net Proceeds attributable to the Underlying Properties for the years ended December 31, 2009, 2008 and 2007 are derived from actual oil and natural gas production from October 1, 2008 through September 30, 2009, October 1, 2007 through September 30, 2008 and October 1, 2006 through September 30, 2007, respectively. The following tables set forth oil and natural gas sales attributable to the Underlying Properties during the three years ended December 31, 2009.
                         
    Bbls of Oil  
    2009     2008     2007  
Chalkley Field
    2,906       3,550       4,027  
Robinson’s Bend Field
                 
Cotton Valley Fields
    1,560       1,552       1,855  
Austin Chalk Fields
    10,322       9,069       9,229  
 
                 
 
                       
Total
    14,788       14,171       15,111  
 
                 
                         
    Mcf of Natural Gas  
    2009     2008     2007  
Chalkley Field
    702,898       822,474       976,994  
Robinson’s Bend Field
    1,529,997       1,579,276       1,666,553  
Cotton Valley Fields
    513,335       580,232       643,745  
Austin Chalk Fields
    125,887       140,911       190,591  
 
                 
 
                       
Total
    2,872,117       3,122,893       3,477,883  
 
                 
For the year ended December 31, 2009, net profits income was $2.5 million, as compared to $6.2 million and $4.8 million for the same periods in 2008 and 2007, respectively. The decrease in net profits income during 2009 as compared to 2008 is mainly due to lower average oil and natural gas prices paid to the Trust in 2009. The increase in net profits income during 2008 as compared to 2007 is mainly due to higher average oil and natural gas prices paid to the Trust in 2008.
Commencing with the second quarter of 2003 distribution (pertaining to the quarter ended March 31, 2003 production) lease operating expenses and capital expenditures have been deducted in calculating Robinson’s Bend Net Proceeds. The Trust received no payments with respect to the Robinson’s Bend Field during each of the years ended December 31, 2009, 2008 and 2007.
The Robinson’s Bend Field Cumulative Deficit (pertaining to production as of September 30, 2009) is approximately $2.8 million. Neither the Trust nor Unitholders are liable to pay such deficit. However, the Trust will receive no payments with respect to the Robinson’s Bend Field until future proceeds exceed the Robinson’s Bend Cumulative Deficit.
Natural gas production attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin Chalk Fields was 1,342,120 Mcf, 1,543,617 Mcf and 1,811,330 Mcf in 2009, 2008 and 2007, respectively. Natural gas production attributable to the Underlying Properties in the Robinson’s Bend Field was 1,529,997 Mcf, 1,579,276 Mcf and 1,666,553 Mcf in 2009, 2008 and 2007, respectively. Natural gas production decreased during each of the years ended December 31, 2009 as a result of normal production declines. Oil

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production attributable to the Underlying Properties for the year ended December 31, 2009 was 14,788 Bbls as compared to 14,171 Bbls and 15,111 Bbls for the same periods in 2008 and 2007, respectively.
The average price used to calculate Net Proceeds for natural gas, before gathering, treating and transportation deductions, during the year ended December 31, 2009 was $3.41 per MMBtu as compared to $5.42 and $4.33 per MMBtu for the years ended December 31, 2008 and 2007, respectively. The average price used to calculate Net Proceeds for oil during the years ended December 31, 2009, 2008 and 2007 was $48.11, $95.11 and $57.51 per Bbl, respectively.
Prior to the Trust’s termination on January 29, 2008, TEMI deducted the Price Differential and was committed to pay a Minimum Price for natural gas. When TEMI paid a purchase price for natural gas based on the Minimum Price, TEMI received Price Credits which it was entitled to deduct in determining the purchase price when the Index Price for natural gas exceeded the Minimum Price. TEMI had not exercised its right to discontinue the Minimum Price commitment and had no outstanding Price Credits on the Termination Date. Additionally, if the Index Price for natural gas exceeded $2.10 per MMBtu, adjusted annually for inflation, TEMI deducted 50% of such excess in calculating the Net Proceeds payable to the Trust.
Upon the Trust’s termination, the Working Interest Owners used the same pricing mechanisms (including the Sharing Price and Minimum Price commitment mechanisms) in calculating Net Proceeds due to the Trust. The Minimum Price per MMBtu for 2009, 2008 and 2007 was $1.95, $1.87 and $1.83, respectively. The Sharing Price per MMBtu for 2009, 2008 and 2007 was $2.40, $2.30 and $2.26, respectively. The deduction of the Price Differential in connection with the Sharing Price mechanism reduced Net Proceeds during the years ended December 31, 2009, 2008, and 2007 by $3.0 million, $10.1 million and $7.1 million, respectively. The Working Interest Owners also have the same annual option to discontinue the Minimum Price commitment. As of December 31, 2009, the Working Interest Owners had no outstanding Price Credits and had not exercised their right to discontinue the Minimum Price commitment. No Price Credits were deducted in calculating the purchase price related to net profits income during the three years ended December 31, 2009.
During the years ended December 31, 2009, 2008 and 2007, the Infill Well Proceeds generated from the Infill Wells located in the Cotton Valley Fields was approximately $89,000, $161,000 and $400,000, respectively.
Lease operating expenses and capital expenditures attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin Chalk Fields deducted in calculating Net Proceeds during the years ended December 31, 2009, 2008 and 2007 totaled $2.2 million, $2.5 million and $2.8 million, respectively.
General and administrative expenses during the year ended December 31, 2009 were $1.4 million as compared to $3.3 million and $1.2 million during each of the years ended December 31, 2008 and 2007, respectively. General and administrative expenses were significantly greater in 2008 as compared to 2009 and 2007 as a result of legal fees incurred by the Trust in connection with the arbitration proceeding between the Trust and certain working interest owners of the Underlying Properties relating to the proper calculation of the quarterly Net Profits Interests payments owed to the Trust following the termination of the Trust. See Item 3. Legal Proceedings. During each of the three years ended December 31, 2009, general and administrative expenses include costs pertaining to administrative services provided by Torch and the Trustee, legal fees, accounting fees, reserve report preparation fees, and Unitholder report printing fees.
Pursuant to Section 3.07 of the Trust Agreement, the Trustee established a cash reserve (“Cash Reserve”) following the Trust’s termination in 2008 for the payment of actual, contingent and uncertain liabilities associated with the liquidation and winding down of the Trust and the Trust’s arbitration. During 2009 and 2008, the Trust received cash payments totaling $3.2 million and $7.1 million (including $0.6 million and

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$0.7 million paid to the Trust by a certain working interest owner in 2009 and 2008, respectively, that is classified as restricted cash due to potential overpayment — see note 6 to the audited financial statements) from the Working Interest Owners of the Underlying Properties pertaining to net profits income attributable to production from the Underlying Properties during the twelve months ended September 30, 2009 and 2008, respectively. During 2008, $6.1 million of the cash payments received by the Trust was allocated into the Cash Reserve. No cash payments received by the Trust in 2009 were allocated to the Cash Reserve. In 2009, cash receipts received by the Trust from the Working Interest Owners during 2009 (excluding restricted cash), net of general and administrative costs paid by the Trust during 2009, were distributed to Unitholders along with the release of certain Cash Reserves accumulated in 2008. The Cash Reserve as of December 31, 2009 and 2008 was $0.8 million and $4.0 million, respectively.
For the year ended December 31, 2009, distributable income was $1.2 million, or $0.14 per Unit, as compared to $3.2 million, or $0.37 per Unit, and $4.1 million, or $0.48 per Unit, for the same periods in 2008 and 2007, respectively. Total cash distributions of $3.9 million, or $0.45 per Unit, were made during the year ended December 31, 2009 as compared to $0.3 million, or $0.03 per Unit, and $4.1 million, or $0.48 per Unit, for the same periods in 2008 and 2007, respectively.
Net profits received by the Trust during the years ended December 31, 2009, 2008 and 2007, derived from production sold during the twelve months ended September 30, 2009, 2008 and 2007, respectively, was computed as shown in the following table (in thousands):
                                                                         
    Year Ended December 31,  
    2009     2008     2007  
    Chalkley, Cotton Valley and     Robinson’s Bend             Chalkley, Cotton Valley     Robinson’s Bend             Chalkley, Cotton Valley     Robinson’s Bend        
    Austin Chalk Fields     Field     Total     and Austin Chalk Fields     Field     Total     and Austin Chalk Fields     Field     Total  
Oil and natural gas revenues
  $ 5,356     $ 4,472             $ 9,846     $ 7,662             $ 8,649     $ 6,391          
 
                                                           
 
                                                                       
Direct operating expenses:
                                                                       
Lease operating expenses (including property tax)
    1,872       6,877               1,491       6,619               2,195       5,986          
Severance tax
    474       358               771       743               741       568          
 
                                                     
 
    2,346       7,235               2,262       7,362               2,936       6,554          
 
                                                           
 
                                                                       
Net proceeds before capital expenditures
    3,010       (2,763 )             7,584       300               5,713       (163 )        
Capital expenditures
    362       1               1,040       4               616       141          
 
                                                           
 
                                                                       
 
    2,648       (2,764 )             6,544       296               5,097       (304 )        
Cumulative Deficit
                                                           
 
                                                           
 
    2,648       (2,764 )             6,544       296               5,097       (304 )        
 
                                                     
Net profits percentage
    95 %     (a)             95 %     (a)             95 %     (a)        
 
                                                           
 
                                                                       
Net profits income
  $ 2,516     $     $ 2,516     $ 6,217     $     $ 6,217     $ 4,842     $     $ 4,842  
 
                                                     
 
(a)   With respect to the Robinson’s Bend Field, the Trust received no cash distributions during each of the years ended December 31, 2009, 2008 and 2007 (pertaining to production during the twelve months ended September 30, 2009, 2008 and 2007, respectively.)

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Critical Accounting Policies
Reserve Estimates
The proved reserves of the Trust are estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, estimates are made regarding the amount and timing of future operating costs, production volumes and severance taxes, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also change. Any variance in these assumptions could materially affect the estimated quantity and value of the Trust’s reserves. Independent petroleum engineering firms are engaged to estimate the Trust’s proved hydrocarbon liquid and natural gas reserves.
As disclosed by the Trust in its Annual Report on Form 10-K for the year ended December 31, 2008 and in this Annual Report, on December 31, 2009, Trust Venture Company, LLC filed and subsequently served a derivative lawsuit against Constellation Energy Partners LLC in Alabama state court alleging counts, in accordance with, inter alia, Section 3816 of the Delaware Statutory Trust Act, codified at 12 Del. C. 3816(a), to (i) recover any overcharges to the Trust by Constellation Energy Partners LLC related to administrative costs, water gathering, treating and disposal costs and severance taxes and (ii) require Constellation Energy Partners LLC to provide an accounting of its revenues and expenses as required under the Conveyance filed of record in Tuscaloosa County, Alabama. There can be no assurance as to the outcome or result of this derivative lawsuit or the effect of the derivative lawsuit may have on the calculation of the reserve reports and the estimated reserve quantities.
Modified Cash Basis
The financial statements of the Trust are prepared on a modified cash basis although financial statements filed with the Securities and Exchange Commission are normally required to be prepared in accordance with accounting principles generally accepted in the United States. Since the operations of the Trust are limited to the distribution of income from the Net Profits Interests, the item of primary importance to the reader of the financial statements of the Trust is the amount of cash distributions to the Unitholders for the period reported.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk
The Trust is exposed to market risk, including adverse changes in commodity prices. The Trust’s assets constitute Net Profits Interests in the Underlying Properties. As a result, the Trust’s operating results can be significantly affected by fluctuations in commodity prices caused by changing market forces and the price received for production from the Underlying Properties.
All production from the Underlying Properties during the period from the inception of the Trust to the Trust’s termination on January 29, 2008 was sold pursuant to a Purchase Contract between TRC, Velasco, and TEMI. The Purchase Contract expired upon the Trust’s termination. Pursuant to the Purchase Contract, TEMI was obligated to purchase all net production attributable to the Underlying Properties for an Index Price, less certain other charges, which were calculated monthly. The Index Price calculation was based on market prices of oil and natural gas and therefore was subject to commodity price risk. The Purchase Contract also provided a Minimum Price paid by TEMI for natural gas, adjusted annually for inflation. When TEMI paid a purchase price based on the Minimum Price, it received Price Credits equal to the difference between the Index Price and the Minimum Price that TEMI was entitled to deduct when the Index Price exceeded the Minimum Price. Additionally, if the Index Price exceeded the Sharing Price, TEMI was

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entitled to deduct such excess, Price Differential. TEMI had the annual option to discontinue the Minimum Price commitment. However, if TEMI discontinued the Minimum Price commitment, it would no longer be entitled to deduct the Price Differential and would forfeit all accrued Price Credits. TEMI did not exercise its right to discontinue the Minimum Price commitment and had no outstanding Price Credits on the Termination Date.
Upon the Trust’s termination, the Working Interest Owners calculated Net Proceeds owed to the Trust utilizing the same pricing mechanisms (including the Sharing Price and Minimum Price commitment mechanisms) as the terminated Purchase Contract. The Minimum Price per MMBtu was $1.95, $1.87 and $1.83 for 2009, 2008 and 2007, respectively. The Sharing Price was $2.40, $2.30 and $2.26 per MMBtu in 2009, 2008 and 2007, respectively. See Item 1. Business and Item 1A. Risk Factors relating to the termination of the Trust and the arbitration proceeding relating to the proper calculation of the Net Profits Interests payments owed to the Trust following termination of the Trust and the current Alabama litigation. The Working Interest Owners also have the same annual option to discontinue the Minimum Price commitment. However, if the Working Interest Owners discontinue the Minimum Price commitment, they will no longer be entitled to deduct the Price Differential and will forfeit all accrued Price Credits. The Working Interest Owners have not exercised their option to discontinue the Minimum Price commitment and have no outstanding Price Credits as of December 31, 2009.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Wilmington Trust Company
as Trustee of Torch Energy Royalty Trust
and to the Unitholders:
We have audited the accompanying statements of assets, liabilities and trust corpus of the Torch Energy Royalty Trust (the “Trust”) as of December 31, 2009 and 2008, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Trust. 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 audits 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 Trust, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
We were not engaged to examine the Trustee’s assertion about the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2009 included in the accompanying annual report on Form 10-K and, accordingly we do not express an opinion thereon.
As described in Note 2, the accompanying financial statements are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Trust as of December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with the basis of accounting described in Note 2.
As discussed in Note 1 to the financial statements, the Trust terminated effective January 29, 2008. Certain responsibilities of the Trustee, including those associated with selling the assets of the Trust, are also as described in Note 1.
         
   
/s/ UHY LLP    
Houston, Texas   
August 25, 2010   

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STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
(In Thousands)
                 
    December 31,     December 31,  
    2009     2008  
ASSETS
               
Cash
  $ 847     $ 3,963  
Restricted cash
    1,288       730  
Net profits interests in oil and natural gas properties (net of accumulated amortization of $167,485 and $165,670 at December 31, 2009 and 2008, respectively)
    13,115       14,930  
 
           
 
  $ 15,250     $ 19,623  
 
           
 
               
LIABILITIES AND TRUST CORPUS
               
 
               
Trust expense payable
  $ 2,076     $ 1,979  
Trust corpus
    13,174       17,644  
 
           
 
  $ 15,250     $ 19,623  
 
           
The accompanying notes to financial statements
are an integral part of these statements.

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STATEMENTS OF DISTRIBUTABLE INCOME
(In thousands, except per Unit amounts)
                         
    Year Ended December 31,  
    2009     2008     2007  
Net profits income
  $ 2,516     $ 6,217     $ 4,842  
Infill well net proceeds
    89       161       400  
Other income
    24       37       54  
 
                 
 
    2,629       6,415       5,296  
 
                       
General and administrative expenses
    1,393       3,253       1,163  
 
                 
 
                       
Distributable income
  $ 1,236     $ 3,162     $ 4,133  
 
                 
 
                       
Distributable income per Unit (8,600 Units)
  $ 0.14     $ 0.37     $ 0.48  
 
                 
 
                       
Distributions per Unit
  $ 0.45     $ 0.03     $ 0.48  
 
                 
The accompanying notes to financial statements
are an integral part of these statements.

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STATEMENTS OF CHANGES IN TRUST CORPUS
(In thousands)
                         
    Year Ended December 31,  
    2009     2008     2007  
Trust corpus, beginning of year
  $ 17,644     $ 16,449     $ 18,164  
 
                       
Amortization of Net Profits Interests
    (1,815 )     (1,709 )     (1,746 )
 
                       
Distributable income
    1,236       3,162       4,133  
 
                       
Distributions to Unitholders
    (3,891 )     (258 )     (4,102 )
 
                 
 
                       
Trust Corpus, end of year
  $ 13,174     $ 17,644     $ 16,449  
 
                 
The accompanying notes to financial statements
are an integral part of these statements.

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Notes to the Financial Statements
1. Nature of Operations
The Torch Energy Royalty Trust (“Trust”) was formed effective October 1, 1993, pursuant to a trust agreement (“Trust Agreement”) among Wilmington Trust Company, not in its individual capacity but solely as trustee of the Trust (“Trustee”), Torch Royalty Company (“TRC”) and Velasco Gas Company, Ltd. (“Velasco”) as owners of certain oil and natural gas properties (“Underlying Properties”) and Torch Energy Advisors Incorporated (“Torch”) as grantor. The Trust was formed under the Delaware statutory trust act (formerly known as the Delaware business trust act). TRC and Velasco created net profits interests (“Net Profits Interests”) and conveyed such interests to Torch. TRC and Velasco created net profits interests (“Net Profits Interests”) which burden certain oil and natural gas properties (“Underlying Properties”) and Torch conveyed the Net Profits Interests to the Trust in exchange for an aggregate of 8,600,000 units of beneficial interest (“Units”). Such Units were sold to the public through various underwriters in November 1993. The current working interest owners of the Underlying Properties are Torch Royalty Company, Torch E&P Company, Samson Lone Star Limited Partnership and Constellation Energy Partners LLC (“Working Interest Owners”).
The Trust has no officers, directors or employees. The Trust and Trustee rely solely on receiving accurate information, reports and other representations from Torch and other service providers to the Trust. In executing and submitting this report on behalf of the Trust and with respect to Bruce L. Bisson in executing the certifications relating to this report, the Trustee and Bruce L. Bisson have relied upon the accuracy of such reports, information and representations.
The Trust received the affirmative vote of the Unitholders of more than 66 2/3% of the outstanding Units to terminate the Trust at the meeting of Unitholders held on January 29, 2008. Upon termination of the Trust, among other things, the Trustee is required to sell the Net Profits Interests. Specifically, pursuant to Section 9.03(e) of the Trust Agreement if the property of the Trust Estate (as defined in the Trust Agreement) has not been sold prior to the end of one calendar year following the termination date, the Trustee, thereafter, must cause such assets to be sold at public auction. As the Trust was terminated by a vote of the Unitholders on January 29, 2008 (the “Termination Date”), the Trustee anticipates it will continue to consult with the Trust’s and Trustee’s financial and legal advisors in preparing the sales process and obtaining the necessary information required for disclosure regarding the Units to carry out the sale requirement under Section 9.03(e). Therefore, after termination of the Trust, the remaining assets of the Trust will be sold, and the proceeds therefrom (after expenses) will be distributed to the unitholders (“Unitholders”). The sole purpose of the Trust is to hold the Net Profits Interests, to receive payments from TRC and Velasco, and to make payments to Unitholders. The Trust does not conduct any business activity.
No assurances can be given that the Trustee will be able to sell the Net Profits Interests, or the price that will be distributed to Unitholders following such a sale. Such distributions could be below the market value of the Units. The Trust can give no assurances of the effect of the results of the affirmative vote to terminate the Trust by the Unitholders on the continued listing of the Units on the New York Stock Exchange (NYSE) or any other national quotation system.
TRC and Velasco receive payments reflecting the proceeds of oil and natural gas sold and aggregate these payments, deduct applicable costs and make payments to the Trustee each quarter for the amounts due to the Trust. Prior to the Trust’s termination on January 29, 2008, Unitholders received quarterly cash distributions relating to oil and natural gas produced and sold from the Underlying Properties. Pursuant to Section 3.07 of the Trust Agreement, the Trustee established a cash reserve (“Cash Reserve”) in 2008 following the Trust’s termination. See Note 4 (Distributions and Income Computations) of the Trust’s

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financial statements for additional information regarding cash distributions and the Cash Reserve. Because no additional properties will be contributed to the Trust, the assets of the Trust deplete over time and a portion of each cash distribution made by the Trust is analogous to a return of capital.
The only assets of the Trust, other than cash, the cash reserve account and temporary investments being held for the payment of actual, contingent and uncertain liabilities and for distribution to Unitholders, are the Net Profits Interests. Under the Trust Agreement, the Trustee receives the payments attributable to the Net Profits Interests and pays all expenses, liabilities and obligations of the Trust. The Trustee has the discretion to establish a cash reserve for the payment of any liability that is contingent or uncertain in amount or that otherwise is not currently due and payable. The Trustee is entitled to cause the Trust to borrow money to pay expenses, liabilities and obligations that cannot be paid out of cash held by the Trust. The Trustee is entitled to cause the Trust to borrow from any source, including from the entity serving as Trustee, provided that the entity serving as Trustee shall not be obligated to lend to the Trust. To secure payment of any such indebtedness (including any indebtedness to the Trustee), the Trustee is authorized to (i) mortgage and otherwise encumber the entire Trust estate or any portion thereof; (ii) carve out and convey production payments; (iii) include all terms, powers, remedies, covenants and provisions it deems necessary or advisable, including confession of judgment and the power of sale with or without judicial proceedings; and (iv) provide for the exercise of those and other remedies available to a secured lender in the event of a default on such loan. The terms of such indebtedness and security interest, if funds were loaned by the Trustee, must be similar to the terms which the Trustee would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and the Trustee shall be entitled to enforce its rights with respect to any such indebtedness and security interest as if it were not then serving as Trustee.
The Trustee is authorized and directed to sell and convey the Net Profits Interests without Unitholder approval in certain instances as described in the Trust Agreement, including upon termination of the Trust. The Trustee is empowered by the Trust Agreement to employ consultants, legal and financial advisors and agents (including Torch) and to make payments of all fees for services or expenses out of the assets of the Trust.
2. Basis of Accounting, Significant Accounting Policies and Recent Accounting Pronouncements
The financial statements of the Trust are prepared on a modified cash basis and are not intended to present the financial position and results of operations in conformity with accepted accounting principles generally accepted in the United States of America (“GAAP”). Preparation of the Trust’s financial statements on such basis includes the following:
  Revenues are recognized in the period in which amounts are received by the Trust. Therefore, revenues recognized during the years ended December 31, 2009, 2008 and 2007 are derived from oil and natural gas production sold during the twelve-month periods ended September 30, 2009, 2008 and 2007, respectively. General and administrative expenses are recognized on an accrual basis.
 
  Amortization of the Net Profits Interests is calculated on a unit-of-production basis and charged directly to Trust corpus.
 
  Distributions to Unitholders are recorded when declared by the Trustee.
 
  An impairment loss is recognized when the net carrying value of the Net Profits Interests exceeds its fair market value. No such impairment was recorded during the three years ended December 31, 2009.

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  The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because net profits income is not accrued in the period of production and amortization of the Net Profits Interests is not charged against operating results.
 
  Restricted cash represents monies paid to the Trust by a working interest owner of the Underlying Properties that may represent a potential overpayment pertaining to oil and natural gas sales from certain Infill Wells during periods subsequent to the Trust’s termination.
 
  In May 2009, the FASB issued authoritative guidance on subsequent events. FASB ASC 855 establishes general standards of accounting for and disclosure of transactions and events that occur after the balance sheet date but before financial statements are issued or available to be issued. The guidance is set forth in topic 855 of the codification, and it is effective for fiscal years and interim periods after June 15, 2009. Adoption of the guidance in the second quarter of 2009 did not impact the trust financial position or results of operation.
 
  At December 31, 2009, the Trust adopted the Securities and Exchange Commission’s (SEC) Modernization of Oil and Gas Reporting, as well as the conforming rule changes issued by the Financial Accounting Standards Board. Upon adoption, the primary rule change that impacted the Trust’s year-end 2009 reserve estimates were those related to assumptions for pricing. The SEC’s prior rules required proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. The revised rules require reserve estimates to be calculated using an unweighted average of the first-day-of-the-month price for the preceding 12-month period.
3. Federal Income Taxes and Texas State Margin Tax
Tax counsel has advised the Trust and Trustee that, under current tax law, the Trust is classified as a grantor trust for federal income tax purposes and not an association taxable as a business entity. However, the opinion of tax counsel is not binding on the Internal Revenue Service. As a grantor trust, the Trust is not subject to federal income tax.
Because the Trust is treated as a grantor trust for federal income tax purposes and a Unitholder is treated as directly owning an interest in the Net Profits Interests, each Unitholder is taxed directly on such Unitholder’s pro rata share of income attributable to the Net Profits Interests consistent with the Unitholder’s method of accounting and without regard to the taxable year or accounting method employed by the Trust. Amounts payable with respect to the Net Profits Interests are paid to the Trust on the quarterly record date established for quarterly distributions in respect to each calendar quarter during the term of the Trust, and the income and deductions from such payments are allocated to the Unitholders of record on such date.
In May 2006, the State of Texas passed legislation to implement a margin tax at a rate of 1% to be imposed generally on federal gross revenues (up to 70%), as apportioned to Texas less certain costs and deductions, as specifically set forth in the new legislation. The effective date of the legislation was January 1, 2008, but the tax was generally imposed on revenues generated in 2007 and thereafter (earlier for certain fiscal year taxpayers). Entities subject to tax generally include trusts unless otherwise exempt, and most other types of entities having limited liability protection. Trusts that meet certain statutory requirements are generally exempt from the margin tax as “passive entities.”
Since the Trust is exempt from the margin tax at the Trust level as a passive entity, each Unitholder that is a taxable entity would generally include its share of the Trust’s revenue in its margin tax computation.

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This revenue would be sourced to Texas under Texas Comptroller guidance that provides such income is sourced according to the principal place of business of the Trust, which is Texas.
4. Distributions and Income Computations
Each quarter the amount of cash available for distribution to Unitholders (the “Quarterly Distribution Amount”) is equal to the excess, if any, of the cash received by the Trust, on the last day of the second month following the previous calendar quarter (or the next business day thereafter) ending prior to the dissolution of the Trust, from the Net Profits Interests then held by the Trust plus, with certain exceptions, any other cash receipts of the Trust during such quarter, subject to adjustments for changes made by the Trustee during such quarter in the Cash Reserve established for the payment of actual, contingent and uncertain liabilities of the Trust. Based on the payment procedures relating to the Net Profits Interest, cash received by the Trust on the last day of the second month of a particular quarter from the Net Profits Interests generally represents proceeds from the sale of oil and natural gas produced from the Underlying Properties during the preceding calendar quarter. The Quarterly Distribution Amount for each quarter is generally payable to Unitholders of record on the last day of the second month of the calendar quarter unless such day is not a business day, in which case the record date is the next business day thereafter. The Trust distributes the Quarterly Distribution Amount within approximately 10 days after the record date to each person who was a Unitholder of record on the associated record date.
During the year ended December 31, 2008, the Trust received cash payments totaling $7.1 million ($6.4 million recorded as net profits income and Infill Well net proceeds included in the statement of distributable income and $0.7 million recorded as an accounts payable. The received cash of $0.7 million paid to the Trust by a certain working interest owner is classified as restricted cash as of December 31, 2008 due to potential overpayment — see note 6 to the financial statements) from the Working Interest Owners for net profits income pertaining to production from the Underlying Properties during the twelve months ended September 30, 2008. Of these cash receipts, $6.1 million was allocated into the Cash Reserve and $258,000, or $0.03 per Unit, were distributed to Unitholders and recorded as payable to the Unitholders. As of December 31, 2008 the Cash Reserve was $4.0 million.
During the year ended December 31, 2009, the Trust received cash payments totaling $3.2 million ($2.6 million recorded as net profits income and Infill Wells net proceeds included in the statement of distributable income and $0.6 million recorded as an accounts payable. The received cash of $0.6 million paid to the Trust by a certain working interest owner is classified as restricted cash as of December 31, 2009 due to potential overpayment — see note 6 to the financial statements) from the Working Interest Owners for net profits income pertaining to production from the Underlying Properties during the twelve months ended September 30, 2009. None of these cash receipts were allocated into the Cash Reserve. During the twelve months ended December 31, 2009, $3.9 million, or $0.45 per Unit, were distributed to Unitholders and recorded as payable to the Unitholders. Such cash distributions during 2009 included (i) a release of funds from the Cash Reserve representing Net Proceeds related to Underlying Property production during the twelve months ended December 31, 2008 and (ii) Net Proceeds related to the Underlying Property production during the twelve months ended September 30, 2009. As of December 31, 2009 the Cash Reserve was $0.8 million.
5. Related Party Transactions
TRC and Velasco contracted to sell the oil and natural gas production from the Underlying Properties to Torch Energy Marketing, Inc. (“TEMI”), a subsidiary of Torch, under a purchase contract (“Purchase Contract”). Upon termination of the Trust, the Purchase Contract expired and the Working Interest Owners calculate the Net Proceeds owed to the Trust utilizing the same pricing mechanisms (including the sharing price and minimum price commitment mechanisms) as the expired Purchase Contract. The continuation of the sharing price and minimum price terms and conditions of the Purchase Contract terms was the subject of an arbitration and the Trust has assumed the applicability of such terms for purpose of this report. See Item 1. Business, Item 1A. Risk Factors and Item 3. Legal Proceedings regarding

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developments concerning the termination of the Trust and arbitration with respect to certain terms and conditions of the Purchase Contract continuing after the termination of the Trust.
Marketing Arrangements and Price Sharing
In connection with the formation of the Trust, TRC, Velasco and TEMI entered into the Purchase Contract which expired on the Termination Date. Under the Purchase Contract, TEMI was obligated to purchase all net production attributable to the Underlying Properties for an index price for oil and natural gas (“Index Price”), less certain gathering, treating and transportation charges, which were calculated monthly. The Index Price equals 97% of the average spot market prices of oil and natural gas (“Average Market Prices”) at the four locations where TEMI sold production.
The Purchase Contract also provided that TEMI paid a minimum price (“Minimum Price”) for natural gas production, adjusted annually for inflation. When TEMI paid a purchase price based on the Minimum Price it received price credits (“Price Credits”), equal to the difference between the Index Price and the Minimum Price, that it was entitled to deduct in determining the purchase price when the Index Price for natural gas exceeded the Minimum Price. In addition, if the Index Price for natural gas exceeded the sharing price, which was adjusted annually for inflation (“Sharing Price”), TEMI was entitled to deduct 50% of such excess (“Price Differential”) in determining the purchase price. TEMI had an annual option to discontinue the Minimum Price commitment. However, if TEMI discontinued the Minimum Price commitment, it would no longer be entitled to deduct the Price Differential in calculating the purchase price and would have forfeited all accrued Price Credits. As of the Termination Date, TEMI had no outstanding Price Credits and had not exercised its option to discontinue the Minimum Price commitment.
Upon the Trust’s termination, the Working Interest Owners utilized the same pricing mechanisms (including the Sharing Price and Minimum Price commitment mechanisms) as the expired Purchase Contract in calculating Net Proceeds due to the Trust. The Working Interest Owners also have the same annual option to discontinue the Minimum Price commitment. The Minimum Price per MMBtu was $1.95, $1.87 and $1.83 for 2009, 2008 and 2007, respectively. The Sharing Price was $2.40, $2.30 and $2.26 per MMBtu in 2009, 2008 and 2007, respectively. See Item 1. Business for additional information concerning the pricing mechanism utilized to compute the Trust’s Net Proceeds during the periods prior to and subsequent to the Trust’s termination and the related arbitration. As of December 31, 2009, the Working Interest Owners had no outstanding Price Credits and had not exercised their right to discontinue the Minimum Price commitment.
Natural gas production is purchased at the wellhead and, therefore, distributions do not include any amounts received in connection with extracting natural gas liquids from such production at natural gas processing or treating facilities.
Gathering, Treating and Transportation Arrangements
The Purchase Contract, which expired upon the Trust’s termination, entitled TEMI to deduct certain natural gas gathering, treating and transportation fees in calculating the purchase price for natural gas in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields. The amounts that were deducted in calculating the purchase price for such natural gas were set forth in the Purchase Contract and were not affected by the actual costs incurred by TEMI to gather, treat and transport natural gas. Upon the Trust’s termination, the Working Interest Owners became entitled to deduct the same natural gas gathering, treating and transportation fees that had previously been deducted by TEMI pursuant to the Purchase Contract in calculating Net Proceeds due to the Trust.

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For the Robinson’s Bend Field, a gathering, treating and transportation fee of $0.260 per MMBtu, adjusted annually for inflation ($0.327, $0.314 and $0.308 per MMBtu for 2009, 2008, and 2007, respectively), plus fuel usage equal to 5% of revenues is deducted in computing Net Proceeds due to the Trust. Additionally, a gathering fee of $0.05 per MMBtu is deducted in calculating the purchase price for production from 73 of the 426 wells in the Robinson’s Bend Field. In computing Net Proceeds due to the Trust for the Austin Chalk fields, $0.38 per MMBtu plus 17% of revenues are deducted as a fee to gather, treat and transport natural gas production. TEMI deducted from the purchase price for natural gas for production attributable to certain wells in the Cotton Valley Fields a transportation fee of $0.045 per MMBtu.
During the years ended December 31, 2009, 2008 and 2007, such fees deducted from the Net Proceeds calculations, attributable to production during the twelve months ended September 30, 2009, 2008 and 2007, in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $1.0 million, $1.4 million and $1.5 million, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase price from the Chalkley Field.
Operator Overhead Fees
A subsidiary of Torch operates certain oil and natural gas interests burdened by the Net Profits Interests in the Cotton Valley and Austin Chalk Fields. The Underlying Properties are charged, on the same basis as other third parties, for all customary expenses and costs reimbursements associated with these activities. Operator overhead fees deducted from the Net Proceeds computations for the Cotton Valley and Austin Chalk fields totaled $227,000, $215,000 and $200,000 for the years ended December 31, 2009, 2008 and 2007, respectively.
Administrative Services Agreements
The sole purpose of the Trust is to hold the Net Profits Interests, to receive payments from TRC and Velasco, and to make payments to Unitholders. The Trust does not conduct any business activity and has no officers, directors or employees. The Trust and Trustee rely on third party service providers to perform administrative services for the Trust.
Torch provided accounting, bookkeeping, informational and other services to the Trust related to the Net Profits Interests pursuant to the Administrative Services Agreement effective October 1, 1993 and an oral arrangement after termination of the Administrative Services Agreement on January 29, 2008 through April 1, 2008. On November 7, 2008, an agreement was entered into between the Trust and Torch that engaged Torch to provide certain accounting services in connection with the Trust’s preparation and filing of the Trust’s Form 10-K for the year ended December 31, 2007.
To facilitate the winding down of the Trust, Torch currently provides certain accounting and other services for the Trust pursuant to an agreement with the Trust entered into on March 26, 2009. The initial term of the agreement expired on March 31, 2010. On March 31, 2010, Torch and the Trust extended the expiration date of the agreement by one year to March 31, 2011 or as sooner terminated by written notice from either party within 5 business days notice.
Services fees charged to the Trust by TEAI for services pertaining to the three years ended December 31, 2009 were $335,000, $371,000 and $414,000, respectively.

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Compensation of the Trustee and Transfer Agent
The Trust Agreement provides that the Trustee be compensated for its administrative services, out of the Trust assets, in an annual amount of $80,000, plus an hourly charge for services in excess of a combined total of 250 hours annually at its standard rate. In accordance with provisions in the Trust Agreement, the Trustee may increase its compensation for its administrative services as a result of unusual or extraordinary services rendered by the Trustee.
Additionally, the Trustee receives a transfer agency fee of $5.00 annually per account (minimum of $15,000 annually), subject to change each December, beginning December 1994, based upon the change in the Producer’s Price Index as published by the Department of Labor, Bureau of Labor Statistics, plus $1.00 for each certificate issued. The Trustee is entitled to reimbursement for out-of-pocket expenses.
Total administrative and transfer agent fees charged by the Trustee during the year ended December 31, 2009, 2008 and 2007 were $130,000, $177,000 and $95,000, respectively.
6. Trust Expense Payable
Trust expense payable as reflected on the Trust’s statements of assets, liabilities and trust corpus was $2.1 million and $2.0 million at December 31, 2009 and 2008, respectively. Included in such payable are general and administrative expense accruals of $0.8 million and $1.3 million as of December 31, 2009 and 2008, respectively, mainly pertaining to the Trust’s legal fees, audit fees and administrative services fees. The remaining balances included in Trust Expense Payable as of December 31, 2009 and 2008 of $1.3 million and $0.7 million, respectively, represent a potential overpayment from a working interest owner of the Underlying Properties pertaining to oil and natural gas sales from certain Infill Wells during periods subsequent to the Trust’s termination.
7. Supplemental Oil and Natural Gas Information (Unaudited)
Total proved oil and natural gas reserves attributable to the Net Profits Interests as of December 31, 2009, 2008 and 2007 are based upon reserve reports prepared by T.J. Smith & Company, Inc. and Netherland, Sewell & Associates, Inc. (“Independent Reserve Engineers”). Future net cash flows were computed by applying the Purchase Contract prices for oil and natural gas to estimated future production, less the estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves. The estimated reserve quantities in this report are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of the Trust’s reserves. See Item 1A. Risk Factors for information regarding assumptions and price volatility.
Reserve Quantities:
The following table sets forth the estimated total proved and proved developed oil and natural gas reserves attributable to the Trust’s Net Profits Interests (all located in the United States) for the years ended December 31, 2009, 2008 and 2007, based on reserve reports prepared by Independent Reserve Engineers. As a net profits interest does not entitle the Trust to a specific quantity of oil or natural gas, but to a portion of oil and natural gas sufficient to yield a specified portion of the Net Proceeds derived therefrom, proved reserves attributable to a net profits interest are calculated by deducting an amount of oil or natural gas sufficient, if sold at the prices used in preparing the reserve estimates for the Underlying Properties, to pay an amount of applicable future estimated production expenses, development costs and taxes for such Underlying Properties (“Net Equivalent Volumes”). The use of disclosing Net Equivalent

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Volumes to estimate reserve volumes attributable to the Net Profits Interests is standard practice in the industry.
At December 31, 2009, the Trust adopted the SEC Modernization of Oil and Gas Reporting, as well as the conforming rule changes issued by the Financial Accounting Standards Board. Upon adoption, the primary rule change that impacted the Trust’s year-end 2009 reserve estimates were those related to assumptions for pricing. The SEC’s prior rules required proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. The revised rules require reserve estimates to be calculated using an unweighted average of the first-day-of-the-month price for the preceding 12-month period. The SEC’s new pricing rules adversely impacted the estimated future net cash flows of the Net Profits Interests at December 31, 2009. The present value of the Trust’s proved reserves at December 31, 2009 utilizing the SEC’s pricing rules pursuant to the SEC Modernization of Oil and Gas Reporting was $10.9 million. The present value of the Trust’s proved reserves utilizing the SEC’s prior rules of using the year-end oil and gas prices was $16.9 million.
Year-end reserves for 2009 attributable to the Trust’s Net Profits Interests were estimated utilizing the unweighted average of the first-day-of-the-month price during 2009, pursuant to the revised SEC pricing rules. Year-end reserves for 2008 and 2007 attributable to the Trust’s Net Profits Interests utilized year-end pricing for natural gas, pursuant to the SEC’s pricing rules which were in effect during each of the two years ended December 31, 2008. In accordance with such SEC pricing rules, year-end reserves and the related future net revenues attributable to the Trust’s Net Profits Interests were estimated utilizing a Purchase Contract price for natural gas, after gathering fees, of $3.20 per Mcf, $4.14 per Mcf and $4.71 per Mcf for 2009, 2008 and 2007, respectively. Such Purchase Contract prices were calculated utilizing the Henry Hub natural gas prices of $3.87 per MMBtu, $5.71 per MMBtu and $6.80 per MMBtu for 2009, 2008 and 2007, respectively).
Year-end reserves at December 31, 2009 were 4.7 billion cubic feet equivalent (“Bcfe”) as compared to year-end 2008 and 2007 reserves of 7.7 Bcfe and 10.5 Bcfe, respectively. The revisions of the estimated oil and natural gas volumes and the related present value of the estimated net future revenues as of December 31, 2009, 2008 and 2007 is primarily a result of fluctuations of natural gas prices utilized in computing the year-end reserves for each of the years then ended.
The Robinson’s Bend Field estimated reserves as of December 31, 2009, 2008 and 2007 were estimated to have no value.
                                                 
    2009     2008     2007  
            Natural             Natural             Natural  
Description   Oil     Gas     Oil     Gas     Oil     Gas  
    (Bbls)     (Mcf)     (Bbls)     (Mcf)     (Bbls)     (Mcf)  
Proved reserves at beginning of year
    37       7,491       48       10,202       42       10,302  
Revisions
    (2 )     (2,381 )     (3 )     (1,710 )     15       1,032  
Extensions and discoveries
                                   
Production
    (7 )     (579 )     (8 )     (1,001 )     (9 )     (1,132 )
 
                                   
 
                                               
Proved reserves at end of year
    28       4,531       37       7,491       48       10,202  
 
                                   
 
                                               
Proved developed reserves at beginning of year
    37       7,491       48       10,202       42       10,273  
 
                                   
 
                                               
Proved developed reserves at end of year
    28       4,531       37       7,491       48       10,202  
 
                                   

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (in thousands):
Estimated future net cash flows from the Net Profits Interests in proved oil and natural gas reserves at December 31, 2009, 2008 and 2007 are presented in the following table:
                         
    December 31,  
    2009     2008     2007  
Future cash inflows
  $ 32,487     $ 55,206     $ 84,417  
Future costs and expenses
    (16,344 )     (22,702 )     (31,595 )
 
                 
Net future cash flows
    16,143       32,504       52,822  
Discount at 10% for timing of cash flows
    (5,205 )     (12,090 )     (21,944 )
 
                 
Present value of future net cash flows for proved reserves
  $ 10,938     $ 20,414     $ 30,878  
 
                 
The following table sets forth the changes in the present value of estimated future net revenues from proved reserves attributable to the Trust’s Net Profits Interests during the years ended December 31, 2009, 2008 and 2007:
                         
    Year Ended December 31,  
    2009     2008     2007  
Balance at beginning of year
  $ 20,414     $ 30,878     $ 26,376  
Sales of oil and natural gas produced, net of production costs
    (2,153 )     (6,286 )     (5,584 )
Accretion of discount
    2,041       3,088       2,638  
Extensions and discoveries
    0       0       0  
Revision of prior-year estimates, change in prices and other
    (9,364 )     (7,266 )     7,448  
 
                 
Balance at end of year
  $ 10,938     $ 20,414     $ 30,878  
 
                 
Estimates of future net cash flows from proved reserves of natural gas and oil condensate were made in accordance with ASC 932, Extractive Activities — Oil and Gas. The Trust has not filed or included in reports to any other Federal authority or agency any estimates of proved net oil and natural gas reserves.

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8. Quarterly Financial Data (Unaudited — in thousands, except per Unit amounts)
The following table sets forth, for the periods indicated, summarized quarterly financial data:
                         
                    Distributable  
    Net Profits     Distributable     Income  
    Income     Income     Per Unit  
Quarter ended March 31, 2009
  $ 1,019     $ 763     $ 0.089  
Quarter ended June 30, 2009
    656       264       0.031  
Quarter ended September 30, 2009
    507       189       0.022  
Quarter ended December 31, 2009
    334       20       0.002  
 
                 
 
                       
 
  $ 2,516     $ 1,236     $ 0.144  
 
                 
 
                       
Quarter ended March 31, 2008
  $ 1,484     $ 686     $ 0.080  
Quarter ended June 30, 2008
    1,582       172       0.020  
Quarter ended September 30, 2008
    1,655       1,092       0.127  
Quarter ended December 31, 2008
    1,496       1,212       0.141  
 
                 
 
                       
 
  $ 6,217     $ 3,162     $ 0.368  
 
                 
9. Subsequent Events
Except as set forth below, no events occurred from December 31, 2009 to the date of this filing that are reportable pursuant to FASB ASC 855.
The Trust was recently informed by TRC that there was a potential overpayment relating to the Austin Chalk field. The potential overpayment to the Trust occured with respect to the five year period ended December 31, 2009 and resulted from TRC utilizing an estimated wellhead mcf volume to calculate the applicable revenues, net of gathering fees. TRC has provided the summary caculations associated with the proposed wellhead volume adjustment which utilizes the actual wellhead mcf volume data. TRC proposed total wellhead adjustment for the five year period ended December 31, 2009 with interest is $751,684. The Trust is analyzing the data provided by TRC with respect to the proposed wellhead adjustment. The Trust has requested additional information from TRC in order to further evaluate the TRC proposed wellhead adjustment. Pursuant to the Texas Conveyance with respect to the Austin Chalk field, the Trust would not be obligated to return any overpayment paid to the Trust by TRC but the amount otherwise payable to the Trust in respect of the Net Profits Interests for any subsequent quarters will be reduced by an amount equal to such actual overpayment, plus an amount equal to interest at the Citibank, N.A. prime rate (as specifically set forth in the Texas Conveyance) on the unrecouped balance of such overpayment from the date of such overpayment until TRC has recovered such overpayment plus such interest.

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Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures.
The Trustee carried out an evaluation of the effectiveness of the design and operation of the Trust’s disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this report. Based upon that evaluation, the Trustee concluded that the Trust’s disclosure controls and procedures are effective in timely alerting the Trustee to material information relating to the Trust required to be included in the Trust’s periodic filings with the SEC. In their evaluation of disclosure controls and procedures, the Trustee and Trust have relied, to the extent considered reasonable, on information provided by Torch and Watkins Meegan LLC, an accounting firm contracted by the Trust to perform certain Sarbanes-Oxley compliance for the Trust.
Changes in Internal Control over Financial Reporting.
There has not been any change in the Trust’s internal control over financial reporting during the fourth quarter of 2009 that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trust and Trustee rely on third party service providers to perform administrative services for the Trust. Torch provided accounting, bookkeeping, informational and other services to the Trust related to the Net Profits Interests pursuant to the Administrative Services Agreement effective October 1, 1993 and an oral arrangement after termination of the Administrative Services Agreement on January 29, 2008 through April 1, 2008. To facilitate the winding down of the Trust, Torch and the Trust entered into an Agreement on March 26, 2009. Pursuant to the agreement, Torch provides certain accounting and other services for the Trust. The initial term of such agreement expired on March 31, 2010. On March 31, 2010, Torch and the Trust extended the expiration date of the agreement by one year to March 31, 2011 or as sooner terminated by written notice from either party within 5 business days notice.
Report on Internal Control Over Financial Reporting.
The Trust and Trustee are responsible for establishing and maintaining adequate control over financial reporting, as such term is defined in Rule 13a-15 promulgated under the Securities Exchange Act of 1934, as amended.
The internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Trust; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with a modified cash basis of accounting as described in Note 2 to the notes to financial statements, and that receipts and expenditures of the Trust are being made only in accordance with authorizations of the Trustee of the Trust; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Trust’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. All internal control systems, no matter how well designed, have inherent limitations, including the possibility of human error and the circumvention of overriding controls. Accordingly, even effective internal control over financial reporting can provide only reasonable assurance with respect to

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financial statement preparation. 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.
The Trustee assessed the effectiveness of the internal control over financial reporting as of December 31, 2009. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on the assessment, the Trustee believes that, as of December 31, 2009, the Trust’s internal control over financial reporting was effective based on those criteria.
This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. The Trustee’s report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only the Trustee’s report in this annual report.
Item 9B. Other Information
None.

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Torch Energy Royalty Trust
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
The Registrant has no directors, executive officers or employees. The Trustee is a corporate trustee that may be removed as trustee under the Trust Agreement, with or without cause, at a meeting duly called and held by the affirmative vote of Unitholders of not less than a majority of all the Units then outstanding. Any such removal of the Trustee shall be effective only at such time as a successor trustee fulfilling the requirements of Section 3807(a) of the Delaware Statutory Trust Act has been appointed and has accepted such appointment.
The Registrant has not adopted a code of ethics applicable to its principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions because the Trust does not have any such officers or employees. The Trust has no directors and therefore no audit committee or audit committee financial expert or a nominating committee.
Section 16(a) of the Securities Exchange Act of 1934 requires that beneficial owners of more than 10% of the registrant’s equity securities file initial reports of beneficial ownership and reports of changes in beneficial ownership with the Securities and Exchange Commission and the New York Stock Exchange. To the Trustee’s knowledge, based solely on the information furnished to the Trust, the Trust is unaware of any person that failed to file on a timely basis reports required by Section 16(a) filing requirements with respect to the Units during and for the year ended December 31, 2009.
Item 11. Executive Compensation
The following is a description of certain fees and expenses paid or borne by the Trust, including fees paid to Torch, the Trustee, the transfer agent or their affiliates.
Ongoing Administrative Expenses. The Trust is responsible for paying all legal, accounting, engineering and stock exchange fees, printing costs and other administrative and out-of-pocket expenses incurred by or at the direction of the Trustee in its capacity as Trustee and/or transfer agent.
Compensation of the Trustee and Transfer Agent. The Trust Agreement provides that the Trustee be compensated for its administrative services, out of the Trust assets, in an annual amount of $80,000, plus an hourly charge for services in excess of a combined total of 250 hours annually at its standard rate. In accordance with provisions in the Trust Agreement, the Trustee may increase its compensation for its administrative services as a result of unusual or extraordinary services rendered by the Trustee.
Additionally, the Trustee receives a transfer agency fee of $5.00 annually per account (minimum of $15,000 annually), subject to change each December, beginning December 1994, based upon the change in the Producer’s Price Index as published by the Department of Labor, Bureau of Labor Statistics, plus $1.00 for each certificate issued. The Trustee is entitled to reimbursement for out-of-pocket expenses.
Fees to Torch. Torch receives a service fee for accounting, bookkeeping and informational services related to the Net Profits Interests as described below in “Item 13 — Administrative Services Agreement.”
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholders Matters
The following table sets forth, as of August 1, 2010, certain information with respect to the ownership of Units held by all persons known by the Trust to be the beneficial owners of 5% or more of the

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outstanding Units. Information set forth in the table with respect to beneficial ownership of Units has been obtained from filings made by the named beneficial owners with the Securities and Exchange Commission as of August 1, 2010. The Trust has no employees, officers or directors. The Trust does not have an “Equity Compensation Plan”.
                 
    Shares Beneficially Owned  
Name of Beneficial Owner and Address   Units     Percent of Class  
5% Unitholder: (1)
               
 
               
Trust Venture Company, LLC (2)
Two Greenwich Plaza, First Floor
Greenwich, CT 06830
    6,502,762       75.6 %
 
               
Trust Acquisition Company, LLC (2)
Two Greenwich Plaza, First Floor
Greenwich, CT 06830
               
 
               
Silver Point Capital, L.P. (2)
Two Greenwich Plaza, First Floor
Greenwich, CT 06830
               
 
               
Edward A. Mulé (2)
Two Greenwich Plaza, First Floor
Greenwich, CT 06830
               
 
               
Robert J. O’Shea (2)
Two Greenwich Plaza, First Floor
Greenwich Plaza, First Floor
Greenwich, CT 06830
               
 
               
 
(1)   Based on Form 4 filed on April 30, 2008.
 
(2)   Trust Venture Company, LLC, Trust Acquisition Company, LLC, Silver Point Capital, L.P., Edward A. Mule and Robert J. O’Shea are each a reporting person and member of a reporting group pursuant to a Joint Filing Agreement dated as of July 6, 2007 for purposes of the Securities Exchange Act of 1934, as amended.
Item 13. Certain Relationships and Related Transactions
Administrative Services Agreements
Pursuant to the Trust Agreement, Torch and the Trust entered into the Administrative Services Agreement effective October 1, 1993. The following summary of certain provisions of the Administrative Services Agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, the provisions of the Administrative Services Agreement. The Trust and Trustee rely on third party service providers to perform administrative services for the Trust.
Prior to April 1, 2008, Torch provided accounting, bookkeeping, informational and other services to the Trust related to the Net Profits Interests pursuant to an administrative services agreement effective October 1, 1993 (“Administrative Services Agreement”) and an oral arrangement after termination of the Administrative Services Agreement on January 29, 2008 through April 1, 2008.
On November 7, 2008, an agreement was entered into between the Trust and Torch which engaged Torch to provide certain accounting services in connection with the Trust’s preparation and filing of the Trust’s Form 10-K for the year ended December 31, 2007. Such agreement expired on December 23, 2008.
To facilitate the winding down of the Trust, Torch provides certain accounting and other services for the Trust pursuant to an agreement with the Trust dated March 26, 2009. The initial term of the Services Agreement expired March 31, 2010. On March 31, 2010, Torch and the Trust extended the expiration

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date of the agreement by one year to March 31, 2011 or as sooner terminated by written notice from either party within 5 business days notice.
Administrative services fees of $335,000, $371,000 and $414,000 are included in general and administrative expenses for the years ended December 31, 2009, 2008 and 2007, respectively.
Marketing Arrangements and Price Sharing
In connection with the formation of the Trust, TRC, Velasco and TEMI entered into a Purchase Contract, which expired upon the termination of the Trust (January 29, 2008). Pursuant to the Purchase Contract, TEMI was obligated to purchase all net production attributable to the Underlying Properties for an Index Price for oil and natural gas less certain gathering, treating and transportation charges, which were calculated monthly. The Purchase Contract also provided that TEMI pay a Minimum Price for natural gas production, adjusted annually for inflation. When TEMI paid a purchase price based on the Minimum Price it received Price Credits equal to the difference between the Index Price and the Minimum Price, that it was entitled to deduct in determining the purchase price when the Index Price for natural gas exceeded the Minimum Price. In addition, if the Index Price for natural gas exceeded the Sharing Price, which is adjusted annually for inflation, TEMI was entitled to deduct 50% of such excess (“Price Differential”) in determining the purchase price. TEMI had an annual option to discontinue the Minimum Price commitment. However, if TEMI discontinued the Minimum Price commitment, it would no longer be entitled to deduct the Price Differential in calculating the purchase price and would have forfeited all accrued Price Credits. As of the Termination Date, TEMI had no outstanding Price Credits and had not exercised its option to discontinue the Minimum Price Commitment.
Upon the Trust’s termination, the Working Interest Owners utilized the same pricing mechanisms (including the Sharing Price and Minimum Price commitment mechanisms) as the expired Purchase Contract in calculating Net Proceeds due to the Trust. The Working Interest Owners also have the same annual option to discontinue the Minimum Price commitment. The Minimum Price per MMBtu was $1.95, $1.87 and $1.83 for 2009, 2008 and 2007, respectively. The Sharing Price was $2.40, $2.30 and $2.26 per MMBtu in 2009, 2008 and 2007, respectively. As of December 31, 2009, the Working Interest Owners had no accumulated Price Credits and had not exercised their right to discontinue the Minimum Price commitment.
No Price Credits were deducted in calculating the purchase price related to Net Proceeds during the three years ended December 31, 2009. As a result the Sharing Price arrangement, Net Proceeds attributable to the Underlying Properties during the years ended December 31, 2009, 2008 and 2007 were reduced by $3.0 million, $10.1 million and $7.1 million, respectively.
Gathering, Treating and Transportation Arrangements
The Purchase Contract, which expired upon the Trust’s termination, entitled TEMI to deduct certain natural gas gathering, treating and transportation fees in calculating the purchase price for natural gas in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields. The amounts that were deducted in calculating the purchase price for such natural gas were set forth in the Purchase Contract and were not affected by the actual costs incurred by TEMI to gather, treat and transport natural gas. Upon the Trust’s termination, the Working Interest Owners became entitled to deduct the same natural gas gathering, treating and transportation fees that had previously been deducted by TEMI pursuant to the Purchase Contract in calculating Net Proceeds due to the Trust.
For the Robinson’s Bend Field, a gathering, treating and transportation fee of $0.260 per MMBtu, adjusted for inflation ($0.327, $0.314 and $0.308 per MMBtu for 2009, 2008, and 2007, respectively),

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plus fuel usage equal to 5% of revenues is deducted in computing Net Proceeds due to the Trust. Additionally, a gathering fee of $0.05 per MMBtu is deducted in calculating the purchase price for production from 73 of the 426 wells in the Robinson’s Bend Field. In computing Net Proceeds due to the Trust for the Austin Chalk Fields, $0.38 per MMBtu plus 17% of revenues are deducted as a fee to gather, treat and transport natural gas production. TEMI deducted from the purchase price for natural gas for production attributable to certain wells in the Cotton Valley Fields a transportation fee of $0.045 per MMBtu.
During the years ended December 31, 2009, 2008 and 2007, gathering, treating and transportation fees deducted from the Net Proceeds calculations pertaining to production during the twelve months ended September 30, 2009, 2008 and 2007 in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $1.0 million, $1.4 million and $1.5 million for 2009, 2008 and 2007, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase price from the Chalkley Field.
Item 14. Principal Accountant Fees and Services
UHY LLP personnel work under the direct control of UHY LLP partners and are leased from wholly-owned subsidiaries of UHY Advisors, Inc. in an alternative practice structure.
The Trust does not have an audit committee, and has no audit committee pre-approval policy with respect to fees paid to UHY. Any pre-approval of services performed by UHY and related fees is granted by the Trustee. The outside auditors are appointed and engaged by the Trust. Fees for services performed by UHY for the years ended December 31, 2009 and 2008 are:
                 
    2009     2008  
Audit Fees
  $ 100,000     $ 120,000  
Audit Related Fees
    0       0  
Tax Fees
    0       0  
All Other Fees
    0       0  
 
           
 
  $ 100,000     $ 120,000  
 
           

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Torch Energy Royalty Trust
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a)   The following documents are filed as part of this report:
     1. Financial Statements
Torch Energy Royalty Trust
Report of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus at December 31, 2009 and 2008
Statements of Distributable Income for the Years Ended December 31, 2009, 2008 and 2007
Statements of Changes in Trust Corpus for the Years Ended December 31, 2009, 2008 and 2007
Notes to Financial Statements
     2. Financial Statement Schedules
Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the financial statements and notes thereto.
     3. Exhibits
     Exhibit
     Number Exhibit
     4. Instruments Defining the Rights of Security Holders, Including Indentures.
         
 
  4.1 Form of Torch Energy Royalty Trust Agreement.*
 
 
  4.2 Form of Louisiana Trust Agreement.*
 
 
  4.3 Specimen Trust Unit Certificate.*
 
 
  4.4 Designation of Ancillary Trustee.*
     10. Material Contracts.
         
 
  10.1 Purchase Agreement between TRC, Velasco and TEMI.*
 
 
  10.2 Gas Gathering Agreement between TEMI and Bahia Gas Gathering, Ltd.*
 
 
  10.3 Amendment to Gas Gathering Agreement.*
 
 
  10.4 Water Gathering and Disposal Agreement and First Amendment between Torch Energy Associates, Ltd. and Velasco.*
 
 
  10.5 Form of Texas Conveyance.*
 
 
  10.6 Form of Louisiana Conveyance.*
 
 
  10.7 Form of Alabama Conveyance.*
 
 
  10.8 Standby Performance Agreement between Torch and the Trust.*
 
 
  10.9 Amendment to Water Gathering Contract.*
 
 
  10.10 First Amendment to Oil and Gas Purchase Contract (previously filed on form 10-Q for the quarter ended September 30, 1994). *
 
 
  10.11 Second amendment to Water Gathering and Disposal Agreement (previously filed on Form 8-K on February 11, 2008).**

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     23. Consents of Experts and Counsel.
         
 
  23.1 -   Consent of T.J. Smith & Company, Inc.
 
 
  23.2 -   Consent of Netherland, Sewell and Associates, Inc.
 
 
  23.3 -   Consent of Watkins Meegan LLC
     31. Rule 13a-14(a)/15d-14(a) Certifications.
         
 
  31.1 -   Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
     32. Section 1350 Certifications.
         
 
  32.1 -   Certification of Wilmington Trust Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
*   Incorporated by reference from Registration Statements on Form S-1 of Torch Energy Advisors Incorporated (Registration No. 33-68688) dated November 16, 1993.
 
**   Incorporated by reference from Form 8-K dated February 11, 2008.

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SIGNATURES
Pursuant to the requirements 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.
         
  TORCH ENERGY ROYALTY TRUST
 
 
  By:   Wilmington Trust Company,    
    not in its individual capacity but   
    solely as Trustee for the Trust   
 
     
  By:   /s/ Bruce L. Bisson    
    Bruce L. Bisson, Vice President   
       
 
Date: August 25, 2010
(The Trust has no employees, directors or executive officers.)

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