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EX-23.2 - EX-23.2 - TORCH ENERGY ROYALTY TRUSTd668101dex232.htm
EX-23.1 - EX-23.1 - TORCH ENERGY ROYALTY TRUSTd668101dex231.htm
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-K

 

 

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

OR

 

¨ 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   74-6411424

(State or Other Jurisdiction of

Incorporation or Organization)

 

(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  ¨    No  x

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  ¨    No  x

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  ¨    No  x

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  ¨    No  ¨

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

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   ¨    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Small reporting company   x

Indicated by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

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 of 2013 was $912,111.

At January 27, 2014, there were 8,600,000 Units of Beneficial Interest of the Trust outstanding.

 

 

 


Table of Contents

Torch Energy Royalty Trust

Annual Report on Form 10-K

For the fiscal year ended December 31, 2012

TABLE OF CONTENTS

 

              Page
Number
 

PART I

       
  Item 1.   

Business

     1   
  Item 1A.   

Risk Factors

     7   
  Item 1B.   

Unresolved Staff Comments

     11   
  Item 2.   

Properties

     11   
  Item 3.   

Legal Proceedings

     15   
  Item 4.   

Removed and Reserved

     17   
PART II        
  Item 5.   

Market for Registrant’s Units, Related Unitholder Matters and Registrant Purchases of Equity Securities

     17   
  Item 6.   

Selected Financial Data

     18   
  Item 7.   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     19   
  Item 7a.   

Quantitative and Qualitative Disclosures About Market Risk

     24   
  Item 8.   

Financial Statements and Supplementary Data

     25   
  Item 9.   

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

     41   
  Item 9A.   

Controls and Procedures

     41   
  Item 9B.   

Other Information

     42   
PART III        
  Item 10.   

Directors, Executive Officers and Corporate Governance

     43   
  Item 11.   

Executive Compensation

     43   
  Item 12.   

Security Ownership of Certain Beneficial Owners and Management and Related Unitholders Matters

     43   
  Item 13.   

Certain Relationships and Related Transactions

     44   
  Item 14.   

Principal Accountant Fees and Services

     46   
PART IV        
  Item 15.   

Exhibits, Financial Statement Schedules

     47   
    

Signatures

     49   

 

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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”) which burden the Underlying Properties and conveyed such interests to Torch. The Trust was formed under the Delaware statutory trust act (formerly known as the Delaware business trust act). 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 working interest owners of the Underlying Properties were TRC, Torch E&P Company, Samson Lone Star Limited Partnership and Constellation Energy Partners LLC (“Working Interest Owners”). On December 13, 2011, the Trust sold all of its Net Profits Interests, which burdened certain working interests owned by Constellation Energy Partners LLC, attributable to the Underlying Properties in the Robinson’s Bend Field. See Note 5 of the accompanying financial statements and Item 3. Legal Proceedings for additional information.

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 on March 31, 2010 and was thereafter extended from year to year, up to the period ending August 30, 2013. Torch currently provides the Trust via letter agreement the administrative services historically provided by Torch to the Trust through December 31, 2013 consistent with past practice and (ii) from December 31, 2013 to April 30, 2014 shall provide services to the Trust in support of any tax correspondence (tax booklet) and tax filings that might be necessary for the year ended December 31, 2013 consistent with past practice and other related services necessary to complete the wind

 

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down of the Trust that are also consistent with past practice. Subsequently, the inability of the Trust to hire qualified services providers to assist in the wind down and liquidation of the Trust may have a material adverse effect on the operations of the Trust.

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 David A. Vanaskey in executing the certifications relating to this report, the Trustee and David A. Vanaskey 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 under the Net Profits Interests. 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 Note 4 of the Trust’s accompanying 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. The Trust sold all of its Net Profits Interests attributable to the Underlying Properties in the Robinson’s Bend Field on December 13, 2011. See Note 5 of the Trust’s accompanying financial statements and Item 3. Legal Proceedings for additional information concerning the sale of the Robinson’s Bend Field Net Profit Interests. On August 30, 2013, the Trust simultaneously signed and closed a purchase and sale agreement by and among the Trust, TRC, Torch E&P Company, N.M.L. Inc., of Texas (formerly Torch Energy Services, Inc.), and Torch, pursuant to which the Trust and the Torch Energy Louisiana Royalty Trust sold certain net profits interests attributable to the underlying working interests in certain fields that produce from the Cotton Valley Fields, Austin Chalk Fields and Chalkley Field for a purchase price of $3,258,330. The Trust is the sole beneficiary of the Torch Energy Louisiana Royalty Trust which held the Net Profits Interests in the fields in Louisiana. The buying parties were the successful bidder in the public auction of the net profit interests attributable to underlying working interests in the Cotton Valley Fields, Austin Chalk Fields and the Chalkley Field. The purchase agreement contains customary representations, warranties and covenants. The Trust no longer receives any proceeds from the Net Profits Interests for the Cotton Valley Fields, Austin Chalk Fields and the Chalkley Field as of the effective date of the purchase agreement for those fields (May 1, 2013).

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,

 

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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 the Working Interest Owners plus interest thereon. The complete definitions of Net Proceeds are set forth in the Conveyances.

On January 24, 2013, the Trust received notice from NYSE Regulation, Inc. (“NYSE Regulation”) informing the Trust that NYSE Regulation has determined to commence proceedings to delist the Trust’s units from the New York Stock Exchange (“NYSE”), with trading of the units to be suspended prior to the opening of NYSE trading on January 30, 2013. NYSE Regulation informed the Trust that the delisting determination was based on the Trust’s delay in filing its Annual Report for the year ended December 31, 2011 on Form 10-K and subsequent Quarterly Reports for the fiscal quarters ending in 2012 with the Securities and Exchange Commission. The Trust had previously utilized the six-month cure period under Section 802.01C of the NYSE Listed Company Manual and a subsequent three-month extension of the filing date for the Annual Report to January 16, 2013 from NYSE Regulation, the Trust was unable to file the Annual Report by this extended deadline. NYSE Regulation declined the Trust’s request for further extension under Section 802.01C of the NYSE Listed Company Manual of the filing deadline. NYSE Regulation also noted that the average closing price of the Trust’s units had previously fallen below the NYSE’s continued listing minimum share price standard (Section 802.01E of the NYSE Listed Company Manual) of $1.00 over a consecutive 30 trading day period. Trading of the Units was suspended prior to the opening of NYSE trading on Wednesday, January 30, 2013. The Trust commenced trading on the Pink Sheets on that same day, under the symbol “TRRU”.

Termination of the Trust and Liquidation of the Trust’s Net Profits Interests

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 (the “Termination Date”). 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.

On August 4, 2011, the Trust entered into a material definitive agreement for advisory and marketing services with an effective date of August 1, 2011 with respect to the sale of the Net Profits Interests pursuant to an agreement with PLS, Inc., a Texas corporation. The Trust notified Robinson’s Bend Production II, LLC. (“RBP II”), a Delaware limited liability company and a subsidiary of Constellation Energy Partners LLC, on November 3, 2011 that it was the successful bidder in the public auction of the sale of the Net Profits Interests attributable to the Robinson’s Bend Field. On December 13, 2011, the Trust entered into a purchase and sale agreement by and between RBP II pursuant to which the Trust agreed to sell, and RBP II agreed to purchase, all of the Trust’s Net Profits Interests attributable to the Underlying Properties in the Robinson’s Bend Field for a purchase price of $1,000,000. The sale signed and closed simultaneously on December 13, 2011.

On August 30, 2013, the Trust also simultaneously signed and closed a purchase and sale agreement by and among the Trust, TRC, Torch E&P Company, N.M.L. Inc., of Texas (formerly Torch Energy Services, Inc.), and Torch, pursuant to which the Trust and the Torch Energy Louisiana Royalty Trust sold certain net profits interests attributable to the underlying working interests in certain fields that produce from the Cotton Valley Fields, Austin Chalk Fields and Chalkley Field for a purchase price of $3,258,330. The buying parties were the successful bidder in the public auction of the net profit interests attributable to underlying working interests in the Cotton Valley Fields, Austin Chalk Fields and the Chalkley Field. The Trust no longer receives any proceeds from the Net Profits Interests for the Cotton Valley Fields, Austin Chalk Fields and the Chalkley Field as of the effective date of the purchase agreement for those fields (May 1, 2013).

 

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On December 4, 2013, the Trust filed a Current Report on Form 8-K (the “Initial Report”) to report the announcement of a quarterly distribution. The Trust filed Amendment No. 1 to the Initial Report on Form 8-K/A on December 5, 2013, which amended and restated the Initial Report in its entirety, and which was filed solely for the purpose of clarifying the per unit reference of the distribution. On December 13, 2013, the Trust filed Amendment No. 2 on Form 8-K/A which amends and restates the Initial Report and Amendment No. 1 in its entirety and revised the distribution amount down due to additional expenses forecasted in the wind down and liquidation of the Trust. On December 13, 2013, the Trust announced the distribution to the unitholders of $3,031,349 or $.35 per unit, payable on December 30, 2013 to unitholders of record on December 23, 2013. Immediately following the distribution the Cash Reserve was approximately $510,000. To the extent that any of the Cash Reserve remains after the payment of all of the Trust’s expenses, the Trustee may make one or more additional cash distributions to the unitholders of record; however, no assurance can be made that any such distributions will occur.

The Trustee anticipates it will continue to consult with the Trust’s and Trustee’s financial and legal advisors in the wind down of the Trust.

Legal Proceedings

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 Item 3. Legal Proceedings for subsequent event information concerning the arbitration and Award Notice.

 

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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. 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 $2.05, $1.99 and $1.97 per MMBtu for 2012, 2011 and 2010, respectively. The Sharing Price was $2.54, $2.46 and $2.43 for 2012, 2011 and 2010, respectively. Following the Trust’s termination, the Working Interest Owners also have the same annual option to discontinue the Minimum Price commitment. As of December 31, 2012, 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 ($0.335 and $0.331 for 2011 and 2010, 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. On December 13, 2011, the Trust sold all of its Net Profits Interests, which burdened certain working interests owned by Constellation Energy Partners LLC, attributable to the Underlying Properties in the Robinson’s Bend Field. See Note 5 of the accompanying financial statements and Item 3. Legal Proceedings for additional information.

 

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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, 2012, 2011 and 2010, gathering, treating and transportation fees deducted from the Net Proceeds calculations pertaining to production during the twelve months ended September 30, 2012, 2011 and 2010 in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $0.09 million, $0.9 million and $1.0 million, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase price from the Chalkley Field.

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. All of the Net Profits Interests have been sold as of August 2013 and the Trust is winding down its operations. 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, 2011 and 2010. On December 13, 2011, the Trust sold all of its Net Profits Interests attributable to the Underlying Properties in the Robinson’s Bend Field to RBP II. See Note 5 of the accompanying financial statements and Item 3. Legal Proceedings for additional information.

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 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 filings free of charge as soon as reasonably practicable after they are filed with the SEC. 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.

Widely Held Fixed Investment Trust Reporting Information

Some Trust Units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street

 

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name, collectively referred to herein as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. Wilmington Trust Company, not in its individual capacity but solely as the Trustee for the Trust, Rodney Square North, 1100 North Market Street, Wilmington, Delaware 19890, telephone number (302) 636-6016, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted on the Trust’s website at http://www.torchroyalty.com. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust Units. Unitholders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units. Each Unitholder should consult his, her or its tax advisor for compliance matters.

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. All of the Net Profits Interests have been sold as of August 2013 and the Trustee is in the process of winding down and liquidating the Trust after the affirmative vote of the requisite number of Unitholders. The Trust no longer receives any proceeds from the Net Profits Interests for the Cotton Valley Fields, Austin Chalk Fields and the Chalkley Field as of the effective date of the purchase agreement for those fields (May 1, 2013). All of the Risk Factors set forth below are qualified in this regard. See Trust Termination below in this item for further information. 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 occurs, 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 and Liquidation

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. On August 4, 2011 the Trust entered into a material definitive agreement for advisory and marketing services with an effective date of August 1, 2011 with respect to the sale of the Net Profits Interests pursuant to an agreement with PLS, Inc., a Texas corporation.

The Trust notified RBP II on November 3, 2011 that it was the successful bidder in the public auction of the sale of the Net Profits Interests attributable to the Robinson’s Bend Field. On December 13, 2011, the Trust entered into a purchase and sale agreement by and between RBP II pursuant to which the Trust agreed to sell, and RBP II agreed to purchase, all of the Trust’s Net Profits Interests attributable to the Underlying Properties in the Robinson’s Bend Field for a purchase price of $1,000,000. The sale signed and closed simultaneously on December 13, 2011.

On August 30, 2013, the Trust simultaneously signed and closed a purchase and sale agreement by and among the Trust, TRC, Torch E&P Company, N.M.L. Inc., of Texas (formerly Torch Energy Services, Inc.), and Torch, pursuant to which the Trust and the Torch Energy Louisiana Royalty Trust sold certain net profits interests attributable to the underlying working interests in certain fields that produce from the Cotton Valley

 

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Fields, Austin Chalk Fields and Chalkley Field for a purchase price of $3,258,330. The buying parties were the successful bidder in the public auction of the net profit interests attributable to underlying working interests in the Cotton Valley Fields, Austin Chalk Fields and the Chalkley Field.

All of the Net Profits Interests have been sold as of August 2013 and the Trustee is in the process of winding down and liquidating the Trust after the affirmative vote of the requisite number of Unitholders. The Trust no longer receives any proceeds from the Net Profits Interests for the Cotton Valley Fields, Austin Chalk Fields and the Chalkley Field as of the effective date of the purchase agreement for those fields (May 1, 2013). The Trustee anticipates it will continue to consult with the Trust’s and Trustee’s financial and legal advisors in the wind down of the Trust.

The Trust’s continuing failure to timely file certain periodic reports with the SEC during the wind down and liquidation of the Trust may pose significant risks to the Trust’s business, which could materially and adversely affect the Trust financial condition.

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. There is no guarantee that distributions made to a Unitholder over the life of these depleting assets or distributions following a sale of the Net Profits Interests will equal or exceed the purchase price paid by the Unitholder.

All of the Net Profits Interests have been sold as of August 2013 and the Trustee is in the process of winding down and liquidating the Trust after the affirmative vote of the requisite number of Unitholders. The Trust no longer receives any proceeds from the Net Profits Interests for the Cotton Valley Fields, Austin Chalk Fields and the Chalkley Field as of the effective date of the purchase agreement for those fields (May 1, 2013).

The Trust may have to lower the cash distributions or may not be able to pay distributions at all during the wind down and liquidation of the Trust.

All of the Net Profits Interests have been sold as of August 2013 and the Trustee is in the process of winding down and liquidating the Trust after the affirmative vote of the requisite number of Unitholders. The Trust no longer receives any proceeds from the Net Profits Interests for the Cotton Valley Fields, Austin Chalk Fields and the Chalkley Field as of the effective date of the purchase agreement for those fields (May 1, 2013).

Trust expenses may have an adverse impact on the distributions to Unitholders during the wind down 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 down and liquidation of the Trust.

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

 

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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.

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. During the year ended December 31, 2012, no impairment loss was recognized. An impairment loss of $6.8 million was recognized in 2011 and no impairment loss was recognized during 2010.

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 periods subsequent to January 1, 2008, 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. 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). 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 each of the five years ending December 31, 2012, including the tax liability accruing on income distributed after December 2006 attributable to Trust revenues during the six years ended December 31, 2012 from which no tax was withheld. For more information about the Texas margin tax, see Note 3 to the Trust’s accompanying 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 consideration various policies and proposals that may affect the marketing of natural gas under new and existing contracts. Accordingly, the Trust and Trustee 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.

 

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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.

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 or distributions following the sales of the Net Profits Interests 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, including wind-down 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 and was thereafter extended from year to year, up to the period ending August 30, 2013. Torch currently provides the Trust via letter agreement the administrative services

 

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historically provided by Torch to the Trust through December 31, 2013 consistent with past practice and (ii) from December 31, 2013 to April 30, 2014 shall provide services to the Trust in support of any tax correspondence (tax booklet) and tax filings that might be necessary for the year ended December 31, 2013 consistent with past practice and other related services necessary to complete the wind down of the Trust that are also consistent with past practice. Subsequently, the inability of the Trust to hire qualified services providers to assist in the wind down 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-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, 2012, 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. On December 13, 2011, the Trust sold all of its Net Profits Interests attributable to the Underlying Properties in the Robinson’s Bend Field. See Note 5 of the accompanying financial statements and Item 3. Legal Proceedings for additional information. Prior to such sale, the Underlying Properties in the Robinson’s Bend Field included an average 40.2% working interest (30.5% net revenue interest) in 392 wells (excluding Infill Wells) in the Robinson’s Bend Field in the Black Warrior Basin of Alabama and 34 Infill Wells. The average working interest and net revenue interest of the Robinson’s Bend Infill Wells (net to the Trust’s 20% interest) was approximately 6.8% and 5.2%, respectively. All of the wells in the Robinson’s Bend Field are operated by a third party, RBP II, a subsidiary of Constellation Energy Partners LLC.

Cotton Valley Fields. The Underlying Properties include an average 56.8% working interest (44.0% 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, 2012, 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 15.3% and 12.4%, respectively. A subsidiary of Torch operates 40 of these wells. The remaining wells are operated by Samson Lone Star Limited Partnership (“Samson”).

 

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Austin Chalk Fields. The Underlying Properties include an average of 15.1% working interest (11.6% net revenue interest) in 59 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.

All of the Net Profits Interests have been sold as of August 2013 and the Trustee is in the process of winding down and liquidating the Trust after the affirmative vote of the requisite number of Unitholders. The Trust no longer receives any proceeds from the Net Profits Interests for the Cotton Valley Fields, Austin Chalk Fields and the Chalkley Field as of the effective date of the purchase agreement for those fields (May 1, 2013).

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 $6.5 million as of December 31, 2012. See Note 8 of the Trust’s accompanying financial statements for additional information concerning the net proved reserves of the Net Profits Interests.

Well Count and Acreage Summary

The following table shows, as of December 31, 2012, 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 (a)

     —           —           —           —     

Cotton Valley Fields

     73         25.4         —           —     

Austin Chalk Fields

     26         4.3         35         5.9   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     105         30.5         35         5.9   
  

 

 

    

 

 

    

 

 

    

 

 

 

The following table shows the gross and net acreage for the Underlying Properties as of December 31, 2012. A gross acre in the following table refers to the number of acres in which a working interest is burdened by the Trust’s Net Profits Interests. The number of net acres is the sum of the fractional ownership of working interests burdened by the Trust’s Net Profits Interests 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 (a)

     —           —     

Cotton Valley Fields

     4,411         2,606   

Austin Chalk Fields

     22,468         3,791   
  

 

 

    

 

 

 

Total

     29,031         6,745   
  

 

 

    

 

 

 

 

(a) On December 13, 2011, the Trust sold all of its Net Profits Interests attributable to the Underlying Properties in the Robinson’s Bend Field. See Note 5 and Item 3. Legal Proceedings for additional information.

 

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Drilling Activity

The following table sets forth the results of drilling activity for the Underlying Properties during the three years ended December 31, 2012. 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. The Net Profits Interests 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.

 

Development Wells - Chalkley Field (a)  
Gross     Net  
    Productive     Dry Holes     Total     Productive     Dry Holes     Total  
2012     0        0        0        0        0        0   
2011     0        0        0        0        0        0   
2010     0        0        0        0        0        0   
Development Wells - Cotton Valley Fields  
Gross     Net  
    Productive     Dry Holes     Total     Productive     Dry Holes     Total  
2012     0        0        0        0        0        0   
2011     0        0        0        0        0        0   
2010     0        0        0        0        0        0   
Development Wells - Austin Chalk Fields  
Gross     Net  
    Productive     Dry Holes     Total     Productive     Dry Holes     Total  
2012     0        0        0        0        0        0   
2011     0        0        0        0        0        0   
2010     0        1        1        0        .04        .04   
Development Wells - Robinson’s Bend Field (b)  
Gross     Net  
    Productive     Dry Holes     Total     Productive     Dry Holes     Total  
2012     0        0        0        0        0        0   
2011     0        0        0        0        0        0   
2010     0        0        0        0        0        0   

 

(a) In 2007, an Infill Well was drilled in the Chalkley Field for which the Trust has not received cash distributions. As of December 31, 2012, costs and expenses exceeded gross revenues by approximately $2.2 million (before interest expense). 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) On December 13, 2011, the Trust sold all of its net profits interests attributable to the Underlying Properties in the Robinson’s Bend Field. See Note 5 of the Trust’s accompanying financial statements and Item 3. Legal Proceedings for additional information.

 

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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 during the years ended December 31, 2012, 2011 and 2010 (derived from production during the twelve months ended September 30, 2012, 2011 and 2010, respectively).

In 2012 and 2011, Net Proceeds paid to the Trust were reduced by $1.3 million and $0.4 million, respectively, as a result of TRC recouping overpayments made to the Trust in 1994 and 1995 pertaining to the Chalkley Field (“Chalkley Gas Volume Adjustment”). In 2010, Net Proceeds paid to the Trust with respect to net profits income generated in the Austin Chalk Fields were reduced by $826,000 (including interest expense of $70,000) to recoup overpayments to the Trust by TRC during the five year period ended December 31, 2009 (“Austin Chalk Gas Volume Adjustment”). The effects of the Chalkley Gas Volume Adjustment and the Austin Chalk Gas Volume Adjustment have been excluded from the data set forth in the table below, except for information included in footnote (a) and (b).

 

     Chalkley, Cotton Valley And Austin Chalk Fields  
     2012 (a)      2011 (a)      2010 (b)  

Production:

        

Natural Gas (MMcf)

     907         1,004         1,156   

Oil (Mbbl)

     7         8         13   

Weighted average lifting cost per Mcfe

   $ 1.29       $ .56       $ 1.47   

Weighted average taxes on production per Mcfe

   $ 0.24       $ 0.27       $ 0.33   

Weighted average sales price (c)

        

Natural Gas ($/Mcf)

   $ 2.54       $ 3.20       $ 3.34   

Oil ($/Bbl)

   $ 88.55       $ 83.09       $ 69.10   
     Robinson’s Bend Field  
     2012 (d)      2011      2010  

Production:

        

Natural Gas (MMcf)

     —           1,416         1,473   

Oil (Mbbl)

     —           —           —     

Weighted average lifting cost per Mcfe

   $ —         $ 4.60       $ 4.80   

Weighted average taxes on production per Mcfe

   $ —         $ 0.18       $ 0.21   

Weighted average sales price (c)

        

Natural Gas ($/Mcf)

   $ —         $ 2.73       $ 2.89   

Oil ($/Bbl)

   $ —         $ —         $ —     

 

(a) Excludes the effect of the Chalkley Gas Volume Adjustment which reduced Net Proceeds received by the Trust in 2012 and 2011 by $1.3 million and $0.4 million, respectively. See Note 4 of the accompanying financial statements for additional information.
(b) Excludes the effect of the Austin Chalk Gas Volume Adjustment. Gas volumes related to such adjustment were 53 MMcf pertaining to gas sales during the twelve month ended December 31, 2009 and 0 MMcf pertaining to gas sales during each twelve month period ended 2011 and 2010. The total natural gas sales volumes pertaining to the Austin Chalk Gas Volume Adjustment of 198 MMcf were compensated with natural gas sales volumes in 2010.
(c) Average sales prices are reflective of natural gas prices received by the Trust less certain gathering, treating and transportation charges.
(d) On December 13, 2011, the Trust sold all of its net profits interests attributable to the Underlying Properties in the Robinson’s Bend Field. See Note 5 of the Trust’s audited financials statements and Item 3. Legal Proceedings for additional information.

 

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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 TRC, 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 Company, LLC filed and subsequently 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 Company, LLC’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

 

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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 Company, LLC 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.

The Trust has also previously disclosed information regarding the termination of the Trust, the ongoing Alabama derivative litigation, the concluded Texas arbitration and other information regarding the Trust on its 2007, 2008, 2009, 2010 and 2011 Annual Report on Form 10-K filed with the SEC and its Current Reports on Form 8-K filed with the SEC. The Unitholders are urged to read the above mentioned and all other filings by the Trust with the SEC carefully and in their entirety.

On February 23, 2011, the Trust issued a press release and disclosed information regarding the ongoing Alabama derivative litigation on its Current Report on Form 8-K. In the press release, the Trust announced that it and the derivative unitholder plaintiff reached an agreement in principle with Constellation Energy Partners LLC to settle certain claims in the litigation, captioned Trust Venture Company, LLC v. Constellation Energy Partners LLC (CV-2008-900751), filed by the derivative plaintiff on the Trust’s behalf in the Circuit Court of Tuscaloosa County, Alabama (the “Settlement”).

As stated in the press release and the Notice of Pendency of Derivative Action, Proposed Settlement of Derivative Action, Settlement Hearing, and Right to Appear, in the form approved by the Court and attached to the Form 8-K filed with the SEC on February 23, 2011, subject to the approval of the Court, the derivative plaintiff (Trust Venture Company, LLC) and the Trust have agreed to settle the claims against Constellation Energy Partners LLC in the derivative action, and to enter into mutual, general releases with Constellation Energy Partners LLC in return for (i) a payment of $1,200,000 to the derivative plaintiff by Robinson’s Bend Production II (“RBP II”), which is a Delaware limited liability company and an affiliate of Constellation Energy Partners LLC, to reimburse the derivative plaintiff for the legal fees and expenses it incurred in prosecuting the derivative action, (ii) an irrevocable bid by RBP II of not less than $1,000,000 for its purchase from the Trust of the net overriding royalty interest (“Alabama NORRI”), when such Alabama NORRI is separately offered for sale by the Trust at public auction within 180 days of the effective date of the Settlement, with such bid amount to be deposited by RBP II in a third-party escrow account pending the public auction, and (iii) a third amendment to that certain Water Gathering and Disposal Agreement

 

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providing that, for a period of ten years commencing on the first day of the month following the effective date of the settlement, the charges for the gathering, separation, and disposal of water from oil and gas wells located in Tuscaloosa County, Alabama that are owned and operated by RBP II (“Wells”) shall be $0.53 per barrel of water. (RBP II currently charges $1.00 per barrel of water for the gathering, separation, and disposal of such water from the Wells).

The Alabama Circuit Court of Tuscaloosa County, Alabama convened a hearing on the settlement on April 11, 2011, at 2:00 p.m. CDT (the “Settlement Hearing”). At the Settlement Hearing, the Court determined whether or not (i) to approve the Settlement as memorialized in the proposed Settlement and Release Agreement with Constellation Energy Partners LLC, and (ii) to approve an Order ending this derivative action. On February 23, 2011, the Trust sent the Notice of Pendency of Derivative Action, Proposed Settlement of Derivative Action, Settlement Hearing, and Right to Appear to the Trust’s unitholders of record as of February 11, 2011, as required by the Settlement. On April 18, 2011, the Trust issued a press release and disclosed information on its Current Report on Form 8-K that the Alabama Circuit Court of Tuscaloosa County, Alabama approved in all respects the settlement as memorialized in the proposed Settlement and Release Agreement and ordered that the matter be dismissed, with prejudice, costs taxed as paid. In the Order and Final Judgment entered by the Court dated as of April 13, 2011, the Circuit Court acknowledged receiving the report from counsel for the trustee of the Trust that no objections to the proposed settlement in this matter had been received, and the Court confirmed after review that the Settlement and Release Agreement is fair, reasonable and adequate. The proposed Settlement and Release Agreement became effective on June 13, 2011.

As previously disclosed on current Report Form 8-K filed on January 31, 2008, 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 January 29, 2008. Pursuant to the Trust Agreement of the Trust, the “Termination Date” of the Trust is 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 must cause such assets to be sold at public auction. All of the Net Profits Interests have been sold and the Trust is wind-down operations. No assurances can be given that the Trustee with respect to the amount that will be distributed to Unitholders following the sales. Such distributions could be below the market value of the Units.

Item 4. (Removed and Reserved).

PART II

Item 5. Market for Registrant’s Units, Related Unitholder Matters and Registrant Purchases of Equity Securities.

The Units are currently listed and traded on the Pink Sheets under the symbol “TRRU.” At December 31, 2012, there were 8,600,000 Units outstanding and approximately 154 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:

 

     High      Low      Distributions  
Fiscal Year Ended December 31, 2011:         

Quarter ended March 31, 2011

   $ 4.22       $ 2.50       $ 0.00   

Quarter ended June 30, 2011

   $ 3.08       $ 1.50       $ 0.00   

Quarter ended September 30, 2011

   $ 3.59       $ 1.50       $ 0.17   

Quarter ended December 31, 2011

   $ 6.30       $ 2.05       $ 0.00   
Fiscal Year Ended December 31, 2012:         

Quarter ended March 31, 2012

   $ 3.20       $ 1.97       $ 0.00   

Quarter ended June 30, 2012

   $ 2.65       $ 1.41       $ 0.00   

Quarter ended September 30, 2012

   $ 1.79       $ 1.31       $ 0.00   

Quarter ended December 31, 2012

   $ 1.75       $ 0.56       $ 0.00   

 

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Item 6. Selected Financial Data. (In thousands, except per unit amounts)

 

     2012     2011     2010     2009      2008  

Net profits income

   $ —    (a)    $ 1,411  (a)    $ 1,285  (b)    $ 2,516       $ 6,217   

Net Profits Interests sale proceeds

   $ —        $ 1,000  (c)    $ —        $ —         $ —     

Infill Well Net Proceeds

   $ 141      $ 320      $ 1,937      $ 89       $ 161   

Distributable income (loss)

   $ (1,059 ) (a)    $ 1,251  (a)    $ 2,060  (b)    $ 1,236       $ 3,162   

Distributions declared

   $ —        $ 1,462      $ —        $ 3,891       $ 258   

Distributable income (loss) per Unit

   $ (0.12 ) (a)    $ 0.15  (a)    $ 0.24  (b)    $ 0.14       $ 0.37   

Cash Reserve per Unit

   $ 0.13      $ 0.28      $ 0.29      $ 0.10       $ 0.46   

Distributions per Unit

   $ —        $ 0.17      $ 0.00      $ 0.45       $ 0.03   

Total assets (at end of period)

   $ 4,480      $ 5,865      $ 14,219      $ 15,250       $ 19,623   

 

(a) In 2012 and 2011, net profits income and distributable income were each reduced by $1.3 million, or $0.15 per unit, and $369,000, or $0.04 per unit, respectively, as a result of the Chalkley Gas Volume Adjustment. See Note 4 to the Trust’s accompanying financial statements for additional information.
(b) In 2010, net profits income and distributable income were reduced by $756,000 and 826,000 (including $70,000 of interest expense), respectively, by the Austin Chalk Gas Volume Adjustment. Distributable income per unit was reduced by $0.10 for such adjustment. See Note 4 to the Trust’s accompanying financial statements for additional information.
(c) On December 13, 2011, the Trust sold all of its net profits interests attributable to the Underlying Properties in the Robinson’s Bend Field. See Note 5 of the accompanying financial statements and Item 3. Legal Proceedings for additional information concerning the sale of the Robinson’s Bend Field Net Profits Interests.

Distributable income of the Trust consists of the excess of net profits income plus Net Profits Interests sale proceeds and Infill Well Net Proceeds less general and administrative expenses and interest expense. The Trust recognizes net profits income and Net Profits Interests Sale proceeds during the period in which such 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, 2012, 2011, and 2010

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, 2012, 2011 and 2010 are derived from actual oil and natural gas production from October 1, 2011 through September 30, 2012, October 1, 2010 through September 30, 2011 and October 1, 2009 through September 30, 2010, respectively. The following tables set forth oil and natural gas sales attributable to the Underlying Properties during the three years ended December 31, 2012.

The data set forth in the table below, except for information contained in footnotes (a) and (b), excludes the effect of the Chalkley Gas Volume Adjustment and the Austin Chalk Gas Volume Adjustment. See Note 4 to the Trust’s accompanying financial statements for additional information concerning these adjustments.

 

     Bbls of Oil  
     2012 (a)     2011 (a)      2010  

Chalkley Field

     1,590        1,906         2,337   

Robinson’s Bend Field

     —          —           —     

Cotton Valley Fields

     1,395        1,038         1,042   

Austin Chalk Fields

     4,140        5,261         9,256   
  

 

 

   

 

 

    

 

 

 

Total

     7,125        8,205         12,635   
  

 

 

   

 

 

    

 

 

 
     Mcf of Natural Gas  
     2012 (a)     2011 (a)      2010  

Chalkley Field

     455,933        536,449         609,035   

Robinson’s Bend Field

     —    (c)      1,416,087         1,473,483   

Cotton Valley Fields

     380,585        414,982         438,941   

Austin Chalk Fields

     70,667        53,002         108,062  (b) 
  

 

 

   

 

 

    

 

 

 

Total

     907,185        2,420,520         2,629,521   
  

 

 

   

 

 

    

 

 

 

 

(a) Excludes the effect of the Chalkley Gas Volume Adjustment which reduced Net Proceeds paid to the Trust in 2012 and 2011 by $1.3 million and $0.4 million, respectively. The Chalkley Gas Volume Adjustment did not affect Net Proceeds received by the Trust in 2010. See Note 4 to the Trust’s accompanying financial statements for additional information.
(b) Excludes the effect of the Austin Chalk Gas Volume Adjustment. Oil sales were not impacted by this adjustment. See Note 4 to the Trust’s accompanying financial statements for additional information.
(c) On December 13, 2011 the Trust sold all of its Net Profits Interests attributable to the Underlying Properties in the Robinson’s Bend Field. See Note 5 of the accompanying financial statements for additional information.

The Trust received no net profits income from the Trust during 2012 as a result of the Chalkley Gas Volume Adjustment which recouped overpayments made to the Trust by TRC in 1994 and 1995. Neither the Trust nor Unitholders are obligated to return such overpayment to TRC; however, the Trust will receive no Net Proceeds with respect to TRC’s interests in the Underlying Properties of the Chalkley Field, the Cotton Valley Fields and the Austin Chalk Fields (“TRC Underlying Property Interests”) until future Net Proceeds from the TRC Underlying Property Interests, plus accrued interest, exceed the unrecouped balance of such

 

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overpayment. During the year ended December 31, 2012, TRC withheld Net Proceeds from the Trust totaling $1.3 million. As of December 31, 2012, the unrecouped balance of the Chalkey Gas Volume Adjustment was $1.3 million. See Notes 4 and 10 of the accompanying financial statements for additional information.

For the year ended December 31, 2011, net profits income was $1.4 million, as compared to $1.3 million in 2010. Net profits income in 2011 was adversely impacted by TRC withholding Net Proceeds totaling $0.4 million as a result of the Chalkley Gas Volume Adjustment.

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, 2012, 2011 and 2010. On December 13, 2011, the Trust entered into a purchase and sale agreement by and among the Trust and Robinson’s Bend Production II, LLC (“RBP II”), a Delaware limited liability company and a subsidiary of Constellation Energy Partners LLC, pursuant to which the Trust agreed to sell, and RBP II agreed to purchase, all of the Trust’s Net Profits Interests attributable to the Underlying Properties in the Robinson’s Bend Field for a purchase price of $1,000,000. See Note 5 of the Trust accompanying financial statements and Item 3. Legal Proceedings concerning the sale of the Robinson’s Bend Field Net Profits Interests.

Prior to the effects of the Chalkley Gas Volume Adjustment and Austin Chalk Gas Volume Adjustment (See Note 4 to the Trust’s accompanying financial statements), natural gas production attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin Chalk Fields was 907 MMcf, 1,004 MMcf and 1,156 MMcf in 2012, 2011 and 2010, respectively. Natural gas production decreased during each of the three years ended December 31, 2012 mainly as a result of normal production declines.

Natural gas production attributable to the Underlying Properties (excluding production generated from the Infill Wells) in the Robinson’s Bend Field was 1,416 MMcf and 1,473 MMcf in 2011 and 2010, respectively. Natural gas production decreased in 2011 as compared to 2010 mainly as a result of normal production declines. Oil production attributable to the Underlying Properties for the year ended December 31, 2012 was 7,125 Bbls as compared to 8,205 Bbls and 12,635 Bbls for the same periods in 2011 and 2010, respectively.

The average price used to calculate Net Proceeds for natural gas, before gathering, treating and transportation deductions, during the year ended December 31, 2012 was $2.44 per MMBtu as compared to $3.27 and $3.36 per MMBtu for the years ended December 31, 2011 and 2010, respectively. Such average gas price calculations exclude the effects of the Chalkley Gas Volume Adjustment and Austin Chalk Gas Volume Adjustment discussed in Note 4 of the Trust’s accompanying financial statements. The average price used to calculate Net Proceeds for oil during the years ended December 31, 2012, 2011 and 2010 was $88.55, $83.09 and $69.11 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.

 

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The Minimum Price per MMBtu for 2012, 2011 and 2010 was $2.05, $1.99 and $1.97, respectively. The Sharing Price per MMBtu for 2012, 2011 and 2010 was $2.54, $2.46 and $2.43, respectively. The deduction of the Price Differential in connection with the Sharing Price mechanism reduced Net Proceeds during the years ended December 31, 2012, 2011, and 2010 by $0.2 million, $1.9 million and $2.5 million, respectively. Following the Trust’s termination, the Working Interest Owners also have the same annual option to discontinue the Minimum Price commitment. As of December 31, 2012, the Working Interest Owners had no outstanding Price Credits and had not exercised their right to discontinue the Minimum Price commitment. Price Credits totaling $8,000 were deducted in calculating the purchase price related to net profits income during the year ended December 31, 2012. All such Price Credits were recouped by the Working Interest Owners during the year ended December 31, 2012. No Price Credits were deducted in calculating the purchase price related to net profits income during the years ended December 31, 2011 and 2010.

In 2008 and 2009, the Trust received $1.3 million from a certain working interest owner with respect to the Infill Wells which was classified as restricted cash prior to 2010 due to potential overpayment (“Restricted Infill Well Net Proceeds”). In 2010, the Trust determined that the Restricted Infill Well Net Proceeds were rightly owned by the Trust. Accordingly, in 2010 the Trust classified the Restricted Infill Well Net Proceeds as unrestricted cash, decreased the Trust expense payable on the Trust’s Statements of Assets, Liabilities and Trust Corpus and increased Infill Well Net Proceeds included in distributable income by $1.3 million.

During the three years ended December 31, 2012, 2011 and 2010, Infill Well Net Proceeds were $141,000, $320,000 and $1.9 million, respectively. Infill Well Net Proceeds in 2010 were favorably impacted by the recognition of the $1.3 million of Restricted Infill Well Net Proceeds. See Note 4 of the Trust’s accompanying financial statements for information concerning Restricted Infill Well Net Proceeds. Infill Well Net Proceeds during each of the three years ended December 31, 2012 were mainly generated from Infill Wells in the Cotton Valley Fields.

Prior to the effect of the Chalkley Gas Volume Adjustment, 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 were $1.3 million, $1.7 million and $2.2 million in 2012, 2011 and 2010, respectively.

General and administrative expenses were $1.2 million, $1.5 million and $1.1 million during each of the years ended December 31, 2012, 2011 and 2010, respectively. During each of the three years ended December 31, 2012, 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 2012, 2011 and 2010, the Trust received cash payments totaling $141,000, $1.7 million and $1.9 million, respectively, from the Working Interest Owners of the Underlying Properties pertaining to net profits income. In 2011, the Trust received $1,000,000 from RBP II in connection with the Trust’s sale of all its Net Profits Interests in the Robinson’s Bend Field. During 2012, 2011 and 2010, $141,000, $1.3 million and $3.2 million (including Restricted Infill Well Net Proceeds of $1.3 million), respectively, of the cash payments received by the Trust were allocated into the Cash Reserve. The Cash Reserve as of December 31, 2012 and 2011 was $1.1 million and $2.4 million, respectively.

For the year ended December 31, 2012, the Trust incurred a distributable loss of $1.1 million, or $0.12 per Unit. During the year ended December 31, 2011, distributable income was $1.3 million, or $0.15 per Unit, as compared to $2.1 million, or $0.24 per Unit for the same period in 2010. Total cash distributions of $1.5 million, or $0.17 per Unit, were made during the years ended December 31, 2011. No cash distributions were made to Unitholders in 2012 and 2010.

 

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Net profits income received by the Trust during the years ended December 31, 2012, 2011 and 2010, derived from production sold during the twelve months ended September 30, 2012, 2011 and 2010, respectively, was computed as shown in the following table (in thousands):

 

     Year Ended December 31,  
     2012 (a)      2011 (a)      2010 (b)  
     Chalkley,
Cotton
Valley
and
Austin
Chalk
Fields
    Robinson’s
Bend
Field
    Total      Chalkley,
Cotton
Valley
and
Austin
Chalk
Fields
    Robinson’s
Bend
Field
    Total      Chalkley,
Cotton
Valley
and
Austin
Chalk
Fields
    Robinson’s
Bend
Field
    Total  

Oil and natural gas revenues

   $ 2,932      $ —           $ 3,899      $ 3,868         $ 3,944      $ 4,254     
  

 

 

   

 

 

      

 

 

   

 

 

      

 

 

   

 

 

   

Direct operating expenses:

            

Lease operating expenses (including property tax)

     1,222        —             1,640        6,513           1,811        7,074     

Severance tax

     225        —             280        258           404        305     
  

 

 

   

 

 

      

 

 

   

 

 

      

 

 

   

 

 

   
     1,447        —             1,920        6,771           2,215        7,379     
  

 

 

   

 

 

      

 

 

   

 

 

      

 

 

   

 

 

   

Net proceeds before capital expenditures

     1,485        —             1,979        (2,903        1,729        (3,125  

Capital expenditures

     67        —             105        56           376        14     
  

 

 

   

 

 

      

 

 

   

 

 

      

 

 

   

 

 

   
     1,418        —             1,874        (2,959        1,353        (3,139  

Net profits percentage

     95     —    (c)         95     —    (c)         95     —    (c)   
  

 

 

   

 

 

      

 

 

   

 

 

      

 

 

   

 

 

   
     1,347        —             1,780        (2,959        1,285        (3,139  

Chalkley Gas Volume Adj. (a)

     (1,347     —             (369     —             —          —       
  

 

 

   

 

 

      

 

 

   

 

 

      

 

 

   

 

 

   

Net profits income

   $ —        $ —        $ —         $ 1,411     

$

—  

  

  $ 1,411      

$

1,285

  

 

$

—  

  

  $ 1,285   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

 

(a) The Chalkley Gas Volume Adjustment reduced net profits income in 2012 and 2011 by $1.3 million and $369,000, respectively. See Notes 4 and 10 to the Trust’s accompanying financial statements for additional information.
(b) Net of the Austin Chalk Gas Volume Adjustment which reduced net profits income in 2010 by $756,000. See Note 4 to the Trust’s accompanying financial statements for additional information.
(c) With respect to the Robinson’s Bend Field, the Trust received no cash distributions during each of the years ended December 31, 2011 and 2010 (pertaining to production during the twelve months ended September 30, 2011 and 2010, respectively). The Trust sold all of its net profits interests attributable to the Underlying Properties in the Robinson’s Bend Field on December 13, 2011. See Note 5 of the accompanying financial statements. See also Item 3. Legal Proceeding for additional information concerning the sale of the Robinson’s Bend Field Net Profits Interests.

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

 

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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.

Chalkley Gas Volume Adjustment

During the three months ended December 31, 2011, TRC determined that it had overpaid the Trust $3.0 million (including $1.9 million of accrued interest) with respect to TRC’s Underlying Property interests in the Chalkley Field. Neither the Trust nor Unitholders are obligated to return such overpayment to TRC; however, the Trust will receive no Net Proceeds with respect to TRC’s interests in the Underlying Properties of the Chalkley Field, the Cotton Valley Fields and the Austin Chalk Fields (“TRC Underlying Property Interests”) until future Net Proceeds from the TRC Underlying Property Interests, plus accrued interest, exceed the unrecouped balance of such overpayment. Accordingly, during the year ended December 31, 2012 and the quarter ended December 31, 2011, TRC did not pay the Trust Net Proceeds of $1.3 million and $0.4 million, respectively, generated from TRC’s Underlying Property Interests attributable to oil and gas sales during the twelve months ended September 30, 2012 and the three months ended September 30, 2011, respectively. As of December 31, 2012, the unrecouped balance of the Chalkley Gas Volume Adjustment was $1.3 million.

On August 30, 2013, the Trust simultaneously signed and closed a Purchase and Sale Agreement (“PSA”) by and among the Trust, TRC, Torch E&P Company, N.M.L. Inc., of Texas (formerly Torch Energy Services, Inc.), and Torch, pursuant to which the Trust and the Torch Energy Louisiana Royalty Trust sold all of its remaining net profits interests attributable to the underlying working interests in certain fields that produce from the Cotton Valley Fields, Austin Chalk Fields and Chalkley Field for a purchase price of $3,258,330.

Pursuant to the PSA, TRC provided the Trust a release, including a release of claims with respect to TRC’s unrecouped balance pertaining to the Chalkley Gas Volume Adjustment. The unrecouped balance of $0.5 million consisted of the total amount claimed by TRC of $3.1 million minus net proceeds from the underlying properties withheld by TRC of $2.6 million. The PSA also provided TRC a release of claims with respect to the Trust Net Proceeds generated from TRC’s Underlying Property Interest attributable to oil and gas sales. The PSA also contains customary representations, warranties and covenants. The Trust no longer receives any proceeds from the Net Profits Interests for the Cotton Valley Fields, Austin Chalk Fields and the Chalkley Field as of May 1, 2013.

Austin Chalk Gas Volume Adjustment

The Austin Chalk Gas Volume Adjustment reduced proceeds received by the Trust in 2010 by $826,000 (including $70,000 of interest expense) pertaining to net profits income generated by the Underlying Properties in the Austin Chalk Fields. The Austin Chalk Gas Volume Adjustment recouped overpayments to the Trust by TRC during the five year period ended December 31, 2009 which resulted from TRC utilizing estimated wellhead gas volumes for certain wells in the Austin Chalk Fields in computing Net Proceeds due to the Trust. In 2010, the Austin Chalk Gas Volume Adjustment was calculated utilizing actual wellhead gas sales volumes and resulted in a 198 MMcf downward adjustment to gas sales volumes included in the net profits income calculations with respect to the Austin Chalk Field. Oil revenues, severance taxes, lease operating expenses and capital expenditures included in Net Proceeds due to the Trust during the five year period ended December 31, 2009 were not affected by the Austin Chalk Gas Volume Adjustment.

 

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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 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 $2.05, $1.99 and $1.97 for 2012, 2011 and 2010, respectively. The Sharing Price was $2.54, $2.46 and $2.43 per MMBtu in 2012, 2011 and 2010, 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 Alabama litigation. Following the Trust’s termination, 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, 2012.

 

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Item 8. Financial Statements and Supplementary Data.

INDEX TO FINANCIAL STATEMENTS

 

     Page  

Report of Independent Registered Public Accounting Firm

     26   

Statements of Assets, Liabilities and Trust Corpus at December 31, 2012 and 2011

     27   

Statements of Distributable Income (loss) for the Years Ended December 31, 2012, 2011 and 2010

     28   

Statements of Changes in Trust Corpus for the Years Ended December 31, 2012, 2011 and 2010

     29   

Notes to Financial Statements

     30   

 

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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, 2012 and 2011, and the related statements of distributable income (loss) and changes in trust corpus for each of the three years in the period ended December 31, 2012. 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, 2012 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, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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
February 3, 2014

 

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STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

(In Thousands)

 

     December 31,
2012
     December 31,
2011
 
ASSETS      

Cash reserve

   $ 1,139       $ 2,383   

Net profits interests in oil and natural gas properties (net of accumulated amortization of $177,259 and $177,118 at December 31, 2012 and 2011, respectively)

     3,341         3,482   
  

 

 

    

 

 

 
   $ 4,480       $ 5,865   
  

 

 

    

 

 

 
LIABILITIES AND TRUST CORPUS      

Trust expense payable

   $ 290       $ 475   

Trust corpus

     4,190         5,390   
  

 

 

    

 

 

 
   $ 4,480       $ 5,865   
  

 

 

    

 

 

 

The accompanying notes to financial statements

are an integral part of these statements.

 

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STATEMENTS OF DISTRIBUTABLE INCOME (LOSS)

(In thousands, except per unit amounts)

 

     Year Ended December 31,  
     2012     2011      2010  

Net profits income

   $ —        $ 1,411       $ 1,285   

Infill well net proceeds

     141        320         1,937   

Net profits interests sale proceeds

     —          1,000         —     
  

 

 

   

 

 

    

 

 

 
     141        2,731         3,222   

General and administrative expenses

     1,200        1,480         1,092   

Interest expense

     —          —           70   
  

 

 

   

 

 

    

 

 

 

Distributable income \ (loss)

   $ (1,059   $ 1,251       $ 2,060   
  

 

 

   

 

 

    

 

 

 

Distributable (loss) income per Unit (8,600 Units)

   $ (0.12   $ 0.15       $ 0.24   
  

 

 

   

 

 

    

 

 

 

Distributions per Unit

   $ 0.00      $ 0.17       $ 0.00   
  

 

 

   

 

 

    

 

 

 

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,  
     2012     2011     2010  

Trust corpus, beginning of year

   $ 5,390      $ 13,852      $ 13,174   

Amortization of Net Profits Interests

     (141     (1,501     (1,382

Impairment expense

     —          (6,750     —     

Distributable income \ (loss)

     (1,059     1,251        2,060   

Distributions to Unitholders

     —          (1,462     —     
  

 

 

   

 

 

   

 

 

 

Trust Corpus, end of year

   $ 4,190      $ 5,390      $ 13,852   
  

 

 

   

 

 

   

 

 

 

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”) which burden the Underlying Properties and conveyed such interests to Torch. 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 working interest owners of the Underlying Properties were 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 David A. Vanaskey in executing the certifications relating to this report, the Trustee and David A. Vanaskey 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 (the “Termination Date”). 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. See Note 5 of the Trust’s accompanying financial statements for additional information concerning the liquidation of the Trust’s Net Profits Interests.

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. The Trust has sold all of the Net Profits Interests and is winding down operations.

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 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 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

 

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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 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. Revenues recognized during the years ended December 31, 2012, 2011 and 2010 are generally derived from oil and natural gas production sold during the twelve-month periods ended September 30, 2012, 2011 and 2010, respectively. The Trust did not receive revenues from TRC with respect to production during the twelve-month period ended September 30, 2012 and the three-month period ended September 30, 2011 as a result of TRC recouping overpayments made to the Trust in 1994 and 1995 with respect to the Chalkley Field (the “Chalkley Gas Volume Adjustment”). See Note 4 of the Trust’s accompanying financial statements for additional information.

 

  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.

 

  The Trust reviews the Net Profits Interests for impairment whenever events or changes in circumstances indicate the carrying amount of the Net Profits Interests may not be recoverable. Recoverability is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the Net Profits Interests. If such asset is considered to be impaired, the impairment recognized is measured by the amount by which the carrying amount of the assets exceeds either the fair value or the estimated discounted cash flows of the assets, whichever is more readily measurable. During the year ended December 31, 2011, an impairment loss of $6.8 million was recognized. At December 31, 2012 and 2010, no impairment was deemed necessary.

 

  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.

 

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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. 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 Interests, 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.

 

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During 2011, TRC determined that it had overpaid the Trust $3.0 million (including $1.9 million of accrued interest as of December 31, 2011) in 1994 and 1995 with respect to TRC’s Underlying Property interests in the Chalkley Field. Neither the Trust nor Unitholders are obligated to return such overpayment to TRC; however, the Trust will receive no Net Proceeds with respect to TRC’s interests in the Underlying Properties of the Chalkley Field, the Cotton Valley Fields and the Austin Chalk Fields (“TRC Underlying Property Interests”) until future Net Proceeds from the TRC Underlying Property Interests, plus accrued interest, exceed the unrecouped balance of such overpayment. The Chalkley Gas Volume Adjustment was settled on August 30, 2013. See Note 5 of the Trust’s accompanying financial statements for further discussion.

Year Ended December 31, 2012

As a result of the Chalkley Gas Volume Adjustment, TRC withheld Net Proceeds from the Trust in 2012 totaling $1.3 million generated from TRC’s Underlying Property Interests during the twelve months ended September 30, 2012. As of December 31, 2012, the unrecouped balance of the Chalkley Gas Volume Adjustment was $1.3 million. During the year ended December 31, 2012, the Trust received cash payments totaling $141,000 from the Working Interest Owners which are recorded as Infill Well Net Proceeds included in the Statements of Distributable Income (Loss) and received no net profits income in 2012 as a result of the Chalkey Gas Volume Adjustment. During the twelve months ended December 31, 2012, no cash distributions were made to the Unitholders. As of December 31, 2012, the Cash Reserve was $1.1 million.

Year Ended December 31, 2011

During the three months ended December 31, 2011, TRC did not pay the Trust Net Proceeds of $0.4 million generated from TRC’s Underlying Property Interests attributable to oil and gas sales during the three months ended September 30, 2011 as a result of the Chalkely Gas Volume Adjustment. As of December 31, 2011, the unrecouped balance of the Chalkley Gas Volume Adjustment was $2.6 million.

During the year ended December 31, 2011, the Trust received cash payments totaling $1.8 million from the Working Interest Owners which are recorded as net profits income and Infill Well Net Proceeds included in the Statements of Distributable Income. The Trust also received a cash payment of $1.0 million from RBP II in connection with the sale of all of the Trust’s Net Profits Interests in the Robinson’s Bend Field. Such receipt is classified as Net profits income sales proceeds in the statements of distributable Income. During the twelve months ended December 31, 2011, $1.5 million, or $0.17 per Unit, were distributed to Unitholders. As of December 31, 2011, the Cash Reserve was $2.4 million.

Year Ended December 31, 2010

In 2008 and 2009, the Trust received $1.3 million from a certain working interest owner with respect to the Infill Wells which was classified as restricted cash prior to 2010 due to potential overpayment (“Restricted Infill Well Net Proceeds”). In 2010, the Trust determined that the Restricted Infill Well Net Proceeds were rightly owned by the Trust. Accordingly, in 2010 the Trust classified the Restricted Infill Well Net Proceeds as unrestricted cash, decreased the Trust expense payable on the Trust’s Statements of Assets, Liabilities and Trust Corpus and increased Infill Well Net Proceeds included in distributable income by $1.3 million.

Cash receipts received by the Trust in 2010 were reduced by $826,000 (including $70,000 of interest expense) pertaining to net profits income generated by the Underlying Properties in the Austin Chalk

 

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Field (“Austin Chalk Gas Volume Adjustment”). The Austin Chalk Gas Volume Adjustment recouped overpayments to the Trust by TRC during the five year period ended December 31, 2009 which resulted from TRC utilizing estimated wellhead gas volumes for certain wells in the Austin Chalk Field in computing Net Proceeds due to the Trust. In 2010, the Austin Chalk Gas Volume Adjustment was calculated utilizing actual wellhead gas sales volumes and resulted in a 198 MMcf downward adjustment to gas sales volumes included in the net profits income calculations with respect to the Austin Chalk Field. Gas revenues, net of applicable revenue deducts and before interest expense, included in Net Proceeds paid to the Trust in 2010 were adjusted downward by $756,000. The Austin Chalk Gas Volume Adjustment did not affect oil revenues, severance taxes, lease operating expenses and capital expenditures included in Net Proceeds due to the Trust during the five year period ended December 31, 2009. During the year ended December 31, 2010, the Trust received cash payments totaling $1.9 million from the Working Interest Owners which are recorded as net profits income and Infill Well Net Proceeds included in the statement of distributable income. No cash was distributed to Unitholders during the year ended December 31, 2010. As of December 31, 2010 the Cash Reserve was $2.5 million.

 

5. Termination and Liquidation of the Net Profits Interests

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, the Termination Date. 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.

On August 4, 2011 the Trust entered into a material definitive agreement for advisory and marketing services with an effective date of August 1, 2011 with respect to the sale of the Net Profits Interests pursuant to an agreement with PLS, Inc., a Texas corporation. The Trust notified Robinson’s Bend Production II, LLC (“RBP II”), a Delaware limited liability company and a subsidiary of Constellation Energy Partners, on November 3, 2011 that it was the successful bidder in the public auction of the sale of the Net Profits Interests attributable to the Robinson’s Bend Field. On December 13, 2011, the Trust entered into a purchase and sale agreement by and between RBP II pursuant to which the Trust agreed to sell, and RBP II agreed to purchase, all of the Trust’s Net Profits Interests attributable to the Underlying Properties in the Robinson’s Bend Field for a purchase price of $1,000,000. The sale signed and closed simultaneously on December 13, 2011.

The Trustee anticipates it will continue to consult with the Trust’s and Trustee’s financial and legal advisors in the wind down of the Trust.

 

6. 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 applied the applicability of such terms for purpose of this report in accordance with the arbitration decision.

 

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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. Following the Trust’s termination, the Working Interest Owners also have the same annual option to discontinue the Minimum Price commitment. The Minimum Price per MMBtu was $2.05, $1.99 and $1.97 for 2012, 2011 and 2010, respectively. The Sharing Price was $2.54, $2.46 and $2.43 per MMBtu in 2012, 2011 and 2010, respectively. As of December 31, 2012, 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.

For the Robinson’s Bend Field, a gathering, treating and transportation fee of $0.260 per MMBtu, adjusted annually for inflation ($0.335 and $0.331 per MMBtu for 2011 and 2010 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.

 

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During the years ended December 31, 2012, 2011 and 2010, such fees deducted from the Net Proceeds calculations, attributable to production during the twelve months ended September 30, 2012, 2011 and 2010, in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $0.09 million, $0.9 million and $1.0 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 $232,000, $227,000 and $235,000 for the years ended December 31, 2012, 2011 and 2010, respectively.

Administrative Services Agreements

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. 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 and was thereafter extended from year to year, up to the period ending August 30, 2013. Torch currently provides the Trust via letter agreement the administrative services historically provided by Torch to the Trust through December 31, 2013 consistent with past practice and (ii) from December 31, 2013 to April 30, 2014 shall provide services to the Trust in support of any tax correspondence (tax booklet) and tax filings that might be necessary for the year ended December 31, 2013 consistent with past practice and other related services necessary to complete the wind down of the Trust that are also consistent with past practice. Subsequently, the inability of the Trust to hire qualified services providers to assist in the wind down and liquidation of the Trust may have a material adverse effect on the operations of the Trust.

Services fees charged to the Trust by Torch for the years ended December 31, 2012, 2011 and 2010 were $460,000, $460,000 and $345,000, 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 were $104,000, $149,000 and $130,000 during the years ended December 31, 2012, 2011 and 2010, respectively.

 

7. Trust Expense Payable

Trust expense payable as reflected on the Trust’s Statements of Assets, Liabilities and Trust Corpus was $0.3 million and $0.5 million at December 31, 2012 and 2011, respectively. Such payables represent general and administrative expense accruals.

 

8. Supplemental Oil and Natural Gas Information (Unaudited)

Total proved oil and natural gas reserves attributable to the Net Profits Interests as of December 31, 2012, 2011 and 2010 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.

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, 2012, 2011 and 2010, 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 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.

 

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Year-end reserves for 2010 attributable to the Trust’s Net Profits Interests were estimated utilizing the unweighted average of the first-day-of-the-month price during 2010, pursuant to the revised SEC pricing rules. In accordance with such SEC pricing rules, year-end reserves and the related future net revenues attributable to the Trust’s Net Profits Interests as of December 31, 2012 and 2011 were estimated utilizing a Purchase Contract price for natural gas, after gathering fees, of $2.65 per Mcf, $3.37 per Mcf and $3.49 per Mcf for 2012, 2011 and 2010, respectively. Such Purchase Contract prices were calculated utilizing the Henry Hub natural gas prices of $2.76 per MMBtu, $4.12 per MMBtu and $4.38 per MMBtu for 2012, 2011 and 2010, respectively.

Year-end reserves at December 31, 2012 were 3.3 billion cubic feet equivalent (“Bcfe”) as compared to year-end 2011 and 2010 reserves of 3.2 Bcfe and 4.0 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, 2012, 2011 and 2010 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, 2010 were estimated to have no value. On December 13, 2011, the Trust sold all of its Net Profits Interests attributable to the Underlying Properties in the Robinson’s Bend Field. See Note 5 of the Trust’s accompanying financial statements and Item 3. Legal Proceedings for additional information concerning the Robinson’s Bend Field Net Profits Interests Sale.

 

Description

   2012     2011     2010  
     Oil     Natural
Gas
    Oil     Natural
Gas
    Oil     Natural
Gas
 
     (Bbls)     (Mcf)     (Bbls)     (Mcf)     (Bbls)     (Mcf)  

Proved reserves at beginning of year

     14        3,157        17        3,917        28        4,531   

Revisions

     8        434        1        (218     (6     (7

Extensions and discoveries

     —          —          —          —          —          —     

Production

     (3     (428     (4     (542     (5     (607
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved reserves at end of year

     19        3,163        14        3,157        17        3,917   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves at beginning of year

     14        3,157        17        3,917        28        4,531   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves at end of year

     19        3,163        14        3,157        17        3,917   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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, 2012, 2011 and 2010 are presented in the following table:

 

     December 31,  
     2012     2011     2010  

Future cash inflows

   $ 19,686      $ 24,089      $ 29,326   

Future costs and expenses

     (9,699     (12,191     (14,324
  

 

 

   

 

 

   

 

 

 

Net future cash flows

     9,987        11,898        15,002   

Discount at 10% for timing of cash flows

     (3,489     (3,744     (4,656
  

 

 

   

 

 

   

 

 

 

Present value of future net cash flows for proved reserves

   $ 6,498      $ 8,154      $ 10,346   
  

 

 

   

 

 

   

 

 

 

 

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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, 2012, 2011 and 2010:

 

     Year Ended December 31,  
     2012     2011     2010  

Balance at beginning of year

   $ 8,154      $ 10,346      $ 10,938   

Sales of oil and natural gas produced, net of production costs

     (1,359     (2,108     (1,301

Accretion of discount

     815        1,035        1,094   

Extensions and discoveries

     0        0        0   

Revision of prior-year estimates, change in prices and other

     (1,112     (1,119     (385
  

 

 

   

 

 

   

 

 

 

Balance at end of year

   $ 6,498      $ 8,154      $ 10,346   
  

 

 

   

 

 

   

 

 

 

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.

 

9. Quarterly Financial Data (Unaudited – in thousands, except per unit amounts)

The following table sets forth, for the periods indicated summarized quarterly financial data:

 

     Net Profits
Income
     Distributable
Income\(Loss)
    Distributable
Income
Per Unit
 

Quarter ended March 31, 2012 (a)

   $ —         $ (334   $ (0.04

Quarter ended June 30, 2012 (a)

     —           (255     (0.03

Quarter ended September 30, 2012 (a)

     —           (230     (0.03

Quarter ended December 31, 2012 (a)

     —           (240     (0.03
  

 

 

    

 

 

   

 

 

 
   $ —         $ (1,059   $ (0.12
  

 

 

    

 

 

   

 

 

 

Quarter ended March 31, 2011

   $ 466       $ 60      $ 0.01   

Quarter ended June 30, 2011

     447         218        0.03   

Quarter ended September 30, 2011

     498         281        0.03   

Quarter ended December 31, 2011 (a)

     0         692        0.08   
  

 

 

    

 

 

   

 

 

 
   $ 1,411       $ 1,251      $ 0.15   
  

 

 

    

 

 

   

 

 

 

 

(a) Net Profits Income and Distributable Income during the year ended December 31, 2012 and quarter ended December 31, 2011 were adversely affected by $1.3 million and $0.4 million, respectively, as a result of the Chalkley Volume Adjustment. See Note 4 of the Trust’s accompanying financial statements for additional information.

 

10. Subsequent Events

On January 24, 2013, the Trust received notice from NYSE Regulation, Inc. (“NYSE Regulation”) informing the Trust that NYSE Regulation has determined to commence proceedings to delist the Trust’s units from the New York Stock Exchange (“NYSE”), with trading of the units to be suspended prior to the opening of NYSE trading on January 30, 2013.

 

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NYSE Regulation informed the Trust that the delisting determination was based on the Trust’s delay in filing its Annual Report for the year ended December 31, 2011 on Form 10-K and subsequent Quarterly Reports for the fiscal quarters ending in 2012 with the Securities and Exchange Commission. The Trust had previously utilized the six-month cure period under Section 802.01C of the NYSE Listed Company Manual and a subsequent three-month extension of the filing date for the Annual Report to January 16, 2013 from NYSE Regulation, the Trust was unable to file the Annual Report by this extended deadline. NYSE Regulation declined the Trust’s request for further extension under Section 802.01C of the NYSE Listed Company Manual of the filing deadline. NYSE Regulation also noted that the average closing price of the Trust’s units had previously fallen below the NYSE’s continued listing minimum share price standard (Section 802.01E of the NYSE Listed Company Manual) of $1.00 over a consecutive 30 trading day period. Trading of the Units was suspended prior to the opening of NYSE trading on Wednesday, January 30, 2013. The Trust commenced trading on the Pink Sheets on that same day, under the symbol “TRRU”.

On August 30, 2013, the Trust simultaneously signed and closed a Purchase and Sale Agreement (“PSA”) by and among the Trust, TRC, Torch E&P Company, N.M.L. Inc., of Texas (formerly Torch Energy Services, Inc.), and Torch, pursuant to which the Trust and the Torch Energy Louisiana Royalty Trust sold all of its remaining net profits interests attributable to the underlying working interests in certain fields that produce from the Cotton Valley Fields, Austin Chalk Fields and Chalkley Field for a purchase price of $3,258,330.

Pursuant to the PSA, TRC provided the Trust a release, including a release of claims with respect to TRC’s unrecouped balance pertaining to the Chalkley Gas Volume Adjustment. The unrecouped balance of $0.5 million consisted of the total amount claimed by TRC of $3.1 million minus net proceeds from the underlying properties withheld by TRC of $2.6 million. The PSA also provided TRC a release of claims with respect to the Trust Net Proceeds generated from TRC’s Underlying Property Interest attributable to oil and gas sales. The PSA also contains customary representations, warranties and covenants. The Trust no longer receives any proceeds from the Net Profits Interests for the Cotton Valley Fields, Austin Chalk Fields and the Chalkley Field as of May 1, 2013, the effective date of the PSA.

On December 4, 2013, the Trust filed a Current Report on Form 8-K (the “Initial Report”) to report the announcement of a quarterly distribution. The Trust filed Amendment No. 1 to the Initial Report on Form 8-K/A on December 5, 2013, which amended and restated the Initial Report in its entirety, and which was filed solely for the purpose of clarifying the per unit reference of the distribution. On December 13, 2013, the Trust filed Amendment No. 2 on Form 8-K/A which amends and restates the Initial Report and Amendment No. 1 in its entirety and revised the distribution amount down due to additional expenses forecasted in the wind down and liquidation of the Trust. On December 13, 2013, the Trust announced the distribution to the unitholders of $3,031,349 or $.35 per unit, payable on December 30, 2013 to unitholders of record on December 23, 2013. Immediately following the distribution the Cash Reserve was approximately $510,000. To the extent that any of the Cash Reserve remains after the payment of all of the Trust’s expenses, the Trustee may make one or more additional cash distributions to the unitholders of record; however, no assurance can be made that any such distributions will occur.

 

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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 2012 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 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, 2011, Torch and the Trust extended the expiration date of the agreement by one year to March 31, 2012 or as sooner terminated by written notice from either party within 5 business days’ notice and thereafter such agreement was extended for the period covering up to August 30, 2013. Torch currently provides the Trust via letter agreement the administrative services historically provided by Torch to the Trust through December 31, 2013 consistent with past practice and (ii) from December 31, 2013 to April 30, 2014 shall provide services to the Trust in support of any tax correspondence (tax booklet) and tax filings that might be necessary for the year ended December 31, 2013 consistent with past practice and other related services necessary to complete the wind down of the Trust that are also consistent with past practice. Subsequently, 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.

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

 

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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 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, 2012. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on the assessment, the Trustee believes that, as of December 31, 2012, 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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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, 2012.

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 November 1, 2013, 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

 

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more of the 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 November 1, 2013. The Trust has no employees, officers or directors. The Trust does not have an “Equity Compensation Plan”.

 

Name of Beneficial Owner and Address

   Shares Beneficially Owned  
     Units      Percent of Class  

5% Unitholder: (1)

     

Trust Acquisition Company, LLC (2)

Two Greenwich Plaza, First Floor

Greenwich, CT 06830

     5,917,320         68.81

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 Schedule 13D/A Amendment No. 15 filed with the Securities and Exchange Commission on February 28, 2012 (the “Schedule 13D”) and the most recent Form 4 filed January 2, 2013.
(2) 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 February 282012 for purposes of the Securities Exchange Act of 1934, as amended, as filed as Exhibit 7.01 to the Schedule 13D.

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.

 

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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 and was thereafter extended from year to year, up to the period ending August 30, 2013. Torch currently provides the Trust via letter agreement the administrative services historically provided by Torch to the Trust through December 31, 2013 consistent with past practice and (ii) from December 31, 2013 to April 30, 2014 shall provide services to the Trust in support of any tax correspondence (tax booklet) and tax filings that might be necessary for the year ended December 31, 2013 consistent with past practice and other related services necessary to complete the wind down of the Trust that are also consistent with past practice. Subsequently, the inability of the Trust to hire qualified services providers to assist in the wind down and liquidation of the Trust may have a material adverse effect on the operations of the Trust.

Administrative services fees of $460,000, $460,000 and $345,000 are included in general and administrative expenses for the years ended December 31, 2012, 2011 and 2010, 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 $2.05, $1.99 and $1.97 for 2012, 2011 and 2010, respectively. The Sharing Price was $2.54, $2.46 and $2.43 per MMBtu in 2012, 2011 and 2010, respectively. As of December 31, 2012, the Working Interest Owners had no accumulated Price Credits and had not exercised their right to discontinue the Minimum Price commitment.

Price Credits totaling $8,000 were deducted in calculating the purchase price related to Net Proceeds during the years ended December 31, 2012. All such Price Credits were recouped by Working Interest Owners in 2012. No Price Credits were deducted in calculating the purchase price related to Net Proceeds during the years ended December 31, 2011 and 2010. As a result the Sharing Price arrangement, Net Proceeds attributable to the Underlying Properties during the years ended December 31, 2012, 2011 and 2010 were reduced by $0.2 million, $1.9 million and $2.5 million, respectively.

 

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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 ($0.335 and $0.331 per MMBtu for 2011 and 2010, 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, 2012, 2011 and 2010, gathering, treating and transportation fees deducted from the Net Proceeds calculations pertaining to production during the twelve months ended September 30, 2012, 2011 and 2010 in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $0.09 million, $0.9 million and $1.0 million, 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.

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, 2012 and 2011 are:

 

     2012      2011  

Audit Fees

   $ 114,000       $ 129,000   

Audit Related Fees

     0         0   

Tax Fees

     0         0   

All Other Fees

     0         0   
  

 

 

    

 

 

 
   $ 114,000       $ 129,000   
  

 

 

    

 

 

 

 

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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, 2012 and 2011

Statements of Distributable Income (Loss) for the Years Ended December 31, 2012, 2011 and 2010

Statements of Changes in Trust Corpus for the Years Ended December 31, 2012, 2011 and 2010

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). **
  10.12 -    Purchase and Sale Agreement between Trust, TRC, Torch E&P and Torch (previously filed on Form 8-K on August 30, 2013).

 

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Torch Energy Royalty Trust

 

  10.13 -   Purchase and Sale Agreement between Trust and RBP II (previously filed on Form 8-K on December 13, 2011).
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/ David A. Vanaskey

  David A. Vanaskey
  Vice President

Date: February 3, 2014

(The Trust has no employees, directors or executive officers.)