UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2006

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

TORCH ENERGY ROYALTY TRUST

(Exact Name of Registrant as Specified in its Charter)

Delaware (State or Other Jurisdiction of		74-6411424 (I.R.S. Employer Identification No.)
Incorporation or Organization)

Title of each class		Name of Each Exchange on Which Registered
Units of Beneficial Interest		New York Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12 (G) OF THE ACT: None

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

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

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

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

     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 filed o     Accelerated Filer o     Non-accelerated filer þ

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

     The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter was $72.4 million.

     At March 27, 2007, there were 8,600,000 Units of Beneficial Interest of the Trust outstanding.

 

 

Annual Report on Form 10-K

For the fiscal year ended December 31, 2006

TABLE OF CONTENTS

						Page
						Number
PART I
		Item 1.		Business			2
		Item 1A.		Risk Factors			5
		Item 1B.		Unresolved Staff Comments			9
		Item 2.		Properties			9
		Item 3.		Legal Proceedings			13
		Item 4.		Submission of Matters to a Vote of Unitholders			13
PART II
		Item 5.		Market for Registrant’s Units and Related Unitholder Matters			14
		Item 6.		Selected Financial Data			14
		Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			15
		Item 7a.		Quantitative and Qualitative Disclosures About Market Risk			18
		Item 8.		Financial Statements and Supplementary Data			19
		Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			31
		Item 9A.		Controls and Procedures			31
		Item 9B.		Other Information			31
PART III
		Item 10.		Directors and Executive Officers of the Registrant			32
		Item 11.		Executive Compensation			32
		Item 12.		Security Ownership of Certain Beneficial Owners and Management			33
		Item 13.		Certain Relationships and Related Transactions			33
		Item 14.		Principal Accountant Fees and Services			35
PART IV
		Item 15.		Exhibits and Financial Statement Schedules			36
		—		Signatures			38
Consent of T.J. Smith & Company, Inc.
Netherland, Sewell and Associates, Inc.
Rule 13a-14(a)/15d-14(a) Certifications
Section 1350 Certification

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 under the Delaware Business Trust Act pursuant to a trust agreement (“Trust Agreement”) among Wilmington Trust Company, as trustee (“Trustee”), Torch Royalty Company (“TRC”), Velasco Gas Company Ltd. (“Velasco”) and Torch as grantor. TRC and Velasco created net profits interests (“Net Profits Interests”) which burden certain oil and gas properties (“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. Pursuant to an administrative services agreement (“Administrative Services Agreement”), Torch provides accounting, bookkeeping, informational and other services related to the Net Profits Interest.

The Trust will terminate upon the first to occur of (i) an affirmative vote of the holders of not less than 66-2/3% of the outstanding Units to liquidate the Trust; (ii) such time as the ratio of the cash amounts received by the Trust from the Net Profits Interests to administrative costs of the Trust is less than 1.2 to 1.0 for three consecutive quarters; (iii) March 1 of any year if it is determined, based on a reserve report as of December 31 of the prior year, that the present value of estimated pre-tax future net cash flows, discounted at 10%, of proved reserves attributable to the Net Profits Interests is equal to or less than $25.0 million; or (iv) December 31, 2012. The Trust has not terminated as none of the aforementioned events have occurred. (See “Termination of Trust” disclosure on page 8 for additional information.) Upon termination of the Trust, the remaining assets of the Trust will be sold and the proceeds therefrom (after expenses) will be distributed to the unitholders (“Unitholders”). The sole purpose of the Trust is to hold the Net Profits Interests, to receive payments from TRC and Velasco, and to make payments to Unitholders. The Trust does not conduct any business activity and has no employees.

TRC and Velasco contracted to sell the oil and gas production from the Underlying Properties to Torch Energy Marketing Inc. (“TEMI”), a subsidiary of Torch, under a purchase contract (“Purchase Contract”). TRC and Velasco receive payments reflecting the proceeds of oil and gas sold and aggregate these payments, deduct applicable costs and make payments to the Trustee each quarter for the amounts due to the Trust. Unitholders receive quarterly cash distributions relating to oil and gas produced and sold from the Underlying Properties. Because no additional properties will be contributed to the Trust, the assets of

the Trust deplete over time and a portion of each cash distribution made by the Trust is analogous to a return of capital.

The Underlying Properties constitute working interests in the Chalkley Field in Louisiana (“Chalkley Field”), the Robinson’s Bend Field in the Black Warrior Basin in Alabama (“Robinson’s Bend Field”), fields that produce from the Cotton Valley formations in Texas (“Cotton Valley Fields”) and fields that produce from the Austin Chalk formation in Texas (“Austin Chalk Fields”). The Underlying Properties represent interests in all productive formations from 100 feet below the deepest productive formation in each field to the surface when the Trust was formed. The Trust therefore has no interest in deeper productive formations.

Separate conveyances (“Conveyances”) were used to transfer the Net Profits Interests in each state. Net proceeds (“Net Proceeds”), generally defined as gross revenues received from the sale of production attributable to the Underlying Properties during any period less property, production, severance and similar taxes, and development, operating, and certain other costs (excluding operating and development costs from the Robinson’s Bend Field prior to January 1, 2003), are calculated separately for each Conveyance. If, during any period, costs and expenses deducted in calculating Net Proceeds exceed gross proceeds under a Conveyance, neither the Trust nor Unitholders are liable to pay such excess directly, but the Trust will receive no payments for distribution to Unitholders with respect to such Conveyance until future gross proceeds exceed future costs and expenses plus the cumulative excess of such costs and expenses not previously recouped by TRC and Velasco plus interest thereon. The complete definitions of Net Proceeds are set forth in the Conveyances.

Marketing Arrangements

In connection with the formation of the Trust, TRC, Velasco and TEMI entered into the Purchase Contract, which expires upon the termination of the Trust. Under the Purchase Contract, TEMI is obligated to purchase all net production attributable to the Underlying Properties for an index price for oil and gas (“Index Price”), less certain gathering, treating and transportation charges, which are calculated monthly. The Index Price equals the average spot market prices of oil and gas (“Average Market Prices”) at the four locations where TEMI sells production.

The Purchase Contract also provides that TEMI pay a minimum price (“Minimum Price”) for gas production. The Minimum Price is adjusted annually for inflation and was $1.80, $1.77 and $1.73 per MMBtu for 2006, 2005 and 2004, respectively. When TEMI pays a purchase price based on the Minimum Price it receives price credits (“Price Credits”), equal to the difference between the Index Price and the Minimum Price, that it is entitled to deduct in determining the purchase price when the Index Price for gas exceeds the Minimum Price. In addition, if the Index Price for gas exceeds the sharing price, which is adjusted annually for inflation (“Sharing Price”), TEMI is entitled to deduct 50% of such excess (“Price Differential”) in determining the purchase price. The Sharing Price was $2.22, $2.18 and $2.13 per MMBtu in 2006, 2005 and 2004, respectively. TEMI has an annual option to discontinue the Minimum Price commitment. However, if TEMI discontinues the Minimum Price commitment, it will no longer be entitled to deduct the Price Differential in calculating the purchase price and will forfeit all accrued Price Credits. TEMI has not exercised its option 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 gas processing or treating facilities.

Gathering, Treating and Transportation Arrangements

The Purchase Contract entitles TEMI to deduct certain gas gathering, treating and transportation fees in calculating the purchase price for gas in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields. The amounts that may be deducted in calculating the purchase price for such gas are set forth in the Purchase Contract and are not affected by the actual costs incurred by TEMI to gather, treat and transport gas. For the Robinson’s Bend Field, TEMI is entitled to deduct a gathering, treating and transportation fee of $0.260 per MMBtu adjusted for inflation ($0.303, $0.298 and $0.292 per MMBtu for 2006, 2005, and 2004, respectfully), plus fuel usage equal to 5% of revenues. Additionally, a fee of $.05 per MMBtu, representing a gathering fee payable to a non-affiliate of Torch, is deducted in calculating the purchase price for production from 68 of the 393 wells in the Robinson’s Bend Field. TEMI deducts $0.38 per MMBtu plus 17% of revenues in calculating the purchase price for production from the Austin Chalk Fields as a fee to gather, treat and transport gas production. TEMI deducts from the purchase price for 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, 2006, 2005 and 2004, gathering, treating and transportation fees deducted from the Net Proceeds calculations pertaining to production during the twelve months ended September 30, 2006, 2005 and 2004 in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $1.7 million, $1.6 million and $1.4 million for 2006, 2005 and 2004, 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 gas produced and sold from wells (other than infill wells) on the Underlying Properties. In calculating Net Proceeds from the Robinson’s Bend Field, operating and development costs incurred prior to January 1, 2003 were not deducted. In addition, the amounts paid to the Trust from the Robinson’s Bend Field during any calendar quarter are subject to a volume limitation (“Volume Limitation”) equal to the gross proceeds from the sale of 912.5 MMcf of 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, 2006, 2005 and 2004 and is not expected to do so in the future.

The Net Profits Interests also entitle the Trust to 20% of the Net Proceeds of wells drilled on the Underlying Properties since the Trust’s establishment into formations in which the Trust has an interest, other than wells drilled to replace damaged or destroyed wells (“Infill Wells”). Infill well 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 Website address is www.torchroyalty.com. The Trust provides access through this website to its annual report on Form 10-K, quarterly reports on Form 10-Q and any current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after these reports are filed or furnished electronically with the Securities and Exchange Commission. Information contained on the Trust’s website or any other website referenced herein is not incorporated by reference into this report and does not constitute a part of this report.

Item 1A. Risk Factors

You should carefully consider the following risk factors in addition to the other information included in this report. If any of these risks or uncertainties actually occur, the Trust’s financial condition and results of operations 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.

If oil and gas prices decline significantly for a prolonged period, the Trust’s cash flow from operations will decline and the Trust may have to lower the cash distributions or may not be able to pay distributions at all.

The Trust’s cash distributions, operating results and the value of the Net Profits Interest are substantially dependent on prices of gas and, to a lesser extent, oil. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of Torch. These factors include:

	o		The domestic and foreign supply of and demand for oil and gas;
	o		The price and quantity of foreign imports of oil and gas;
	o		The level of consumer product demand;
	o		Weather conditions, including but not limited to, hurricanes in the Gulf of Mexico, can adversely impact cash distributions received by the Trust. If the wells drilled on the Underlying Properties and related infrastructure were to be damaged by adverse weather conditions, cash flows distributed to Unitholders could be delayed during the period in which damage to such assets were repaired. Additionally, costs associated with such repairs not covered by insurance would reduce cash distributions received by the Trust ;
	o		Overall domestic and global economic conditions;
	o		Political and economic conditions and events in foreign oil and gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America and Russia, and acts of terrorism or sabotage;
	o		The ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
	o		Technological advances affecting energy consumption;
	o		Domestic and foreign governmental regulations and taxation;
	o		The impact of energy conservation efforts;
	o		The capacity of natural gas pipelines and other transportation facilities to the Trust’s production; and
	o		The price and availability of alternative fuels.

Any substantial and extended decline in the price of oil and gas would have an adverse effect on the Trust’s revenues, cash distributions and value of the Net Profits Interests.

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 oil and gas 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. 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. The reserve data included herein are estimates only and are subject to many uncertainties. Actual quantities of oil and natural gas may differ considerably from the amounts set forth herein. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The present value, discounted at 10%, of future net cash flows from proved reserves attributable to the Net Profits Interests does not represent the fair market value of the proved reserves, or the price at which the Net Profits Interests could be sold. A determination of fair market value would involve consideration of many factors in addition to the present value, discounted at 10%. An impairment loss is recognized when the net carrying value of the Net Profits Interests exceeds its fair market value. No impairment loss was recognized during the years ended December 31, 2006, 2005 and 2004.

The Trust’s business is subject to operational risks that may not be fully insured, which, if they were to occur, could adversely affect the Trust’s financial condition or results of operations and, as a result, the Trust’s ability to pay distributions to Unitholders.

Cash payments to the Trust are derived from the production and sale of oil and gas, which operations are subject to risk inherent in such activities, such as blowouts, cratering, explosions, damage to equipment caused by weather conditions, facility or equipment malfunctions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. These risks could result in substantial losses which are deducted in calculating the Net Proceeds paid to the Trust due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. As is customary in the industry, the Trust maintains insurance against some but not all of these risks. Additionally, the Trust may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on the Trust’s business activities, financial condition, results of operations and ability to pay distributions to Unitholders. The failure of an operator of the Underlying Properties to conduct its operations or discharge its obligations in a proper manner could have an adverse effect on the Net Proceeds payable to the Trust.

The Trust may be unable to compete effectively with larger companies, which may adversely affect the Trust’s ability to generate sufficient revenue and its ability to pay distributions to Unitholders

The Trust’s distributions are dependent on gas production and prices and, to a lesser extent, oil production and prices from the Underlying Properties. The gas industry is highly competitive in all of its phases. In marketing production from the Underlying Properties, TEMI encounters competition from major gas companies, independent gas concerns, and individual producers and operators. Many of these competitors have greater financial and other resources than TEMI. Competition may also be presented by alternative fuel sources, including heating oil and other fossil fuels.

The Trust’s operations are subject to regulations which may limit the Trust’s production of natural gas or the price that the Trust receives for natural gas.

The production, transportation and sale of natural gas from the Underlying Properties are subject to Federal and state governmental regulation, including regulation of tariffs charged by pipelines, taxes, the prevention of waste, the conservation of gas, pollution controls and various other matters. The United States has governmental power to impose pollution control measures.

Federal Regulation

The Underlying Properties are subject to the jurisdiction of FERC with respect to various aspects of gas operations including the marketing and production of gas. The Natural Gas Act and the Natural Gas Policy Act (collectively, the “Acts”) mandate Federal regulation of interstate transportation of gas. The Natural Gas Wellhead Decontrol Act of 1989 terminated wellhead price controls on all domestic 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 thereunder. 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 gas under new and existing contracts. Accordingly, Torch is unable to predict the impact of any such government regulation.

In the past, Congress has been very active in the area of gas regulation. Legislation enacted in repeals incremental pricing requirements and gas use restraints previously applicable. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on the Underlying Properties and the Trust.

State Regulation

Many state jurisdictions have at times imposed limitations on the production of gas by restricting the rate of flow for gas wells below their actual capacity to produce and by imposing acreage limitations for the drilling of a well. States may also impose additional regulations of these matters. Most states regulate the production of gas, including requirements for obtaining drilling permits, the method of developing new fields, provisions for the unitization or pooling of gas properties, the spacing, operation, plugging and abandonment of wells and the prevention of waste of gas resources. The rate of production may be regulated and the maximum daily production allowable from gas wells may be established on a market demand or conservation basis or both.

Because the Trust handles oil and gas petroleum products, the Trust may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances in the environment.

Activities on the Underlying Properties are subject to existing Federal, state and local laws, rules and regulations relating to the protection of public health and welfare, safety and the environment, including, without limitation, laws regulating the release of materials into the environment and laws protecting areas of particular environmental concern. It is anticipated that, absent the occurrence of an unanticipated event, compliance with these laws will not have a material adverse effect upon the Trust or Unitholders. Torch has informed the Trust that it cannot predict what effect future regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from operations on the Underlying Properties could have on the Trust or Unitholders. However, pursuant to the terms of the Conveyances, any costs or expenses incurred by TRC or Velasco in connection with environmental liabilities, to the extent arising out of or relating to activities occurring on, or in connection with, or conditions existing on or under, the Underlying Properties before October 1, 1993, will be borne by TRC or Velasco and not the Trust and will not be deducted in calculating Net Proceeds and will, therefore, not reduce amounts payable to the Trust.

Net Proceeds Attributable to the Robinson’s Bend Field have declined significantly.

Prior to December 31, 2002, lease operating expenses were not deducted in calculating the Net Proceeds payable to the Trust from the Robinson’s Bend Field. In accordance with the provisions of the Net Profits Interest conveyance covering the Robinson’s Bend Field, commencing with the second quarter 2003 distribution (pertaining to the quarter ended March 31, 2003 production) lease operating expenses and capital expenditures have been deducted in calculating Net Proceeds. The Trust receives no payments for distributions to Unitholders with respect to the Robinson’s Bend Field when proceeds do not exceed the sum of costs and expenses and the cumulative excess of such costs and expenses including interest (“Robinson’s Bend Field Cumulative Deficit”). The Trust received approximately $0.6 million in 2006 (pertaining to production during the twelve month period ended September 30, 2006) for payments for distributions to Unitholders with respect to the Robinson’s Bend Field. The Trust received no payments for distributions to Unitholders with respect to the Robinson’s Bend Field during the years ended December 31, 2005 and 2004.

In calculating the Robinson’s Bend Field Net Proceeds pertaining to the quarter ended December 31, 2006 production, costs and expenses exceed revenues by approximately $50,000. Therefore, the Trust received no payments with respect to the Robinson’s Bend Field during the quarter ended March 31, 2007. The Robinson’s Bend Field Cumulative Deficit (pertaining to production as of December 31, 2006) is approximately $50,000. Neither the Trust nor Unitholders are liable to pay such deficit. However, the Trust will receive no payments with respect to the Robinson’s Bend Field until future proceeds exceed the Robinson’s Bend Cumulative Deficit.

The market price for the Trust Units may not reflect the value of the Net Profits Interests held by the Trust.

The public trading price for the Trust Units tends to be tied to the recent and expected levels of cash distributions on the Trust Units. The amounts available for distribution by the Trust vary in response to numerous factors outside the control of the Trust, including prevailing prices for oil and natural gas produced from the Underlying Properties. The market price of the Trust Units is not necessarily indicative of the value that the Trust would realize if the Net Profits Interests were sold to a third party buyer. In addition, such market price is not necessarily reflective of the fact that, since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Trust Units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a Unitholder over the life of these depleting assets will equal or exceed the purchase price paid by the Unitholder.

If the Trust terminates there is no assurance that the Trustee can sell the Net Profits Interests or the amount it will be sold for.

The Trust will terminate on March 1 of any year if it is determined that the pre-tax future net cash flows, discounted at 10%, attributable to the estimated net proved reserves of the Net Profits Interests on the preceding December 31 are less than $25.0 million. The pre-tax future net cash flows, discounted at 10%, attributable to estimated net proved reserves of the Net Profits Interests as of December 31, 2006 was approximately $26.4 million. Such reserve report was prepared pursuant to Securities and Exchange Commission guidelines and utilized an unescalated Purchase Contract price (after gathering, treating and transportation fees) of $4.06 per Mcf. The computation of the $4.06 per Mcf Purchase Contract price was based on an unescalated Henry Hub spot price for natural gas on December 31, 2006 of $5.64 per MMBtu. The December 31, 2006 reserve value was greater than $25.0 million. Therefore, the Trust did not terminate as of March 1, 2007. Upon termination of the Trust, the Trustee is required to sell the Net

Profits Interests. No assurances can be given that the Trustee will be able to sell the Net Profits Interests, or the amounts that will be distributed to Unitholders following such a sale. Such distributions could be below the market price of the Units.

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 Torch and its subsidiaries to provide administrative services to the Trust.

Torch is the administrative service provider to the Trust and a party to that certain Administrative Services Agreement whereby Torch provides certain administrative and related services to the Trust. See Item 13 – Administrative Services Agreement. If Torch and its subsidiaries or TEMI were to become unable to meet their obligations to the Trust, such inability might 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 for 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.

Item 1B. Unresolved Staff Comments

As of December 31, 2006, the Trust did not 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 four unitized wells producing from the Miogyp “B” reservoir. The wells produce from a depth in excess of 14,000 feet. A subsidiary of ExxonMobil Corporation operates the unitized wells.

Robinson’s Bend Field. The Underlying Properties include an average 42.5% working interest (32.3% net revenue interest) in 393 wells in the Robinson’s Bend Field in the Black Warrior Basin of Alabama. As of December 31, 2006, 23 Infill Wells have been drilled on the Underlying Properties in the Robinson’s

Bend Field. The average working interest and net revenue interest of the Robinson’s Bend Infill Wells (net to the Trust’s 20% interest) is approximately 5.9% and 4.4%, respectively. All of the wells in the Robinson’s Bend Field are operated by a third party, Robinson’s Bend Operating II, LLC.

Cotton Valley Fields. The Underlying Properties include an average 51.4% working interest (39.8% net revenue interest) in 41 wells in four fields that produce from the Upper and Lower Cotton Valley formations in Texas. As of December 31, 2006, 29 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 13.9% and 11.1%, respectively. A subsidiary of Torch operates 40 of these wells. The remaining wells are operated by Samson Lone Star Limited Partnership (“Samson”).

Austin Chalk Fields. The Underlying Properties include an average of 13.5% working interest (10.9% net revenue interest) in 74 wells in the Austin Chalk Fields of Central Texas. Production from these fields is derived primarily from the highly fractured Austin Chalk formation using horizontal drilling techniques. A subsidiary of Torch operates two wells in the Austin Chalk Fields. The remaining wells in the Austin Chalk Fields are operated by third parties.

Oil and 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 $26.4 million as of December 31, 2006. Future cash flows attributable to the Robinson’s Bend Field’s Net Profits Interest were estimated to have no value to the Trust as of December 31, 2006. See Note 6 of the audited 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, 2006, the gross and net interest in oil and gas wells for the Underlying Properties:

		Gas Wells								Oil Wells
		Gross				Net				Gross				Net
Chalkley Field			4				.6				—				—
Robinson’s Bend Field			416				169.3				—				—
Cotton Valley Fields			70				24.9				—				—
Austin Chalk Fields			31				5.7				43				8.0
Total			521				200.5				43				8.0

The following table shows the gross and net acreage for the Underlying Properties as of December 31, 2006. A gross acre in the following table refers to the number of acres in which a working interest is owned directly by the Trust. The number of net acres is the sum of the fractional ownership of working interests owned directly by the Trust in the gross acres expressed as a whole number and percentages thereof. A net acre is deemed to exist when the sum of fractional ownership of working interests in gross acres equals one.

		Acreage
		Gross				Net
Chalkley Field			2,152				348
Robinson’s Bend Field			33,404				14,288
Cotton Valley Fields			4,411				2,606
Austin Chalk Fields			28,508				5,170
Total			68,475				22,412

Drilling Activity

The following table sets forth the results of drilling activity for the Underlying Properties during the three years ended December 31, 2006. Gross wells, as it applies to wells in the following table, refers to the number of wells in which a working interest is owned directly by the owners of the Underlying Properties and Infill Wells (“Gross Well”). A net well (“Net Well”) represents the sum of the fractional ownership working interests in the Gross Wells expressed as whole numbers and percentages thereof.

All of the wells shown below represent Infill Wells drilled on the Underlying Properties in the Cotton Valley Fields and the Robinson’s Bend Field. The Infill Wells in the Cotton Valley Fields are operated by Samson and the Infill Wells in the Robinson’s Bend Field are operated by Robinson’s Bend Operating II, LLC. The Net Profits Interest entitle the Trust to 20% of Infill Well Net Proceeds which is defined as gross proceeds from the sale of production attributable to Infill Wells less all production, drilling and completion costs of such wells. Infill Well Net Proceeds are calculated by aggregating the proceeds and costs from Infill Wells on a state by state basis.

Development Wells – Cotton Valley Fields
		Gross												Net
						Dry												Dry
		Productive				Holes				Total				Productive				Holes				Total
2006			4				0				4				0.6				0				.6
2005			6				0				6				0.7				0				0.7
2004			0				0				0				0				0				0
Development Wells – Robinson’s Bend Field (a)
		Gross												Net
						Dry												Dry
		Productive				Holes				Total				Productive				Holes				Total
2006			12				0				12				0.6				0				0.6
2005			11				0				11				0.7				0				0.7
2004			0				0				0				0				0				0

There was no other drilling activity on the Underlying Properties during the three years ended December 31, 2006.

Oil and Gas Sales Prices and Production Costs

The following table sets forth, for the Underlying Properties, the net production volumes of 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 gas and Bbl of oil for production attributable to cash distributions received by Unitholders during years ended December 31, 2006, 2005 and 2004 (derived from production during the twelve months ended September 30, 2006, 2005 and 2004, respectively).

		Chalkley, Cotton Valley
		And Austin Chalk Fields
		2006				2005				2004
Production:
Gas (MMcf)			1,955				2,088				2,496
Oil (Mbbl)			19				22				25
Weighted average lifting cost per Mcfe		$	1.01			$	.96			$	.77
Weighted average taxes on production per Mcfe		$	.42			$	.35			$	.30
Weighted average sales price (a)
Gas ($/Mcf)		$	5.27			$	4.45			$	3.72
Oil ($/Bbl)		$	58.56			$	46.14			$	30.58

		Robinson’s Bend Field
		2006				2005				2004
Production:
Gas (MMcf)			1,762				1,826				1,927
Oil (Mbbl)			—				—				—
Weighted average lifting cost per Mcfe		$	3.43			$	3.22			$	3.04
Weighted average taxes on production per Mcfe		$	.45			$	.36			$	.27
Weighted average sales price (a)
Gas ($/Mcf)		$	4.71			$	3.98			$	3.25
Oil ($/Bbl)		$	—			$	—			$	—

Item 3. Legal Proceedings

There are no pending legal proceedings, as of the date of this filing, to which the Trust is a party.

Item 4. Submission of Matters to a Vote of Unitholders

During the year ended December 31, 2006, no matter was submitted to the Unitholders for a vote.

PART II

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

The Units are listed and traded on the New York Stock Exchange under the symbol “TRU.” At March 1, 2007, there were 8,600,000 Units outstanding and approximately 355 Unitholders of record. The following table sets forth, for the periods indicated, the high and low sales prices per Unit on the New York Stock Exchange (“NYSE”) and the amount of quarterly cash distributions per Unit made by the Trust:

										Cash
		High				Low				Distributions
Quarter ended March 31, 2005		$	8.11			$	6.45			$	.22
Quarter ended June 30, 2005		$	8.15			$	6.13			$	.12
Quarter ended September 30, 2005		$	7.20			$	6.60			$	.15
Quarter ended December 31, 2005		$	7.23			$	6.44			$	.16
Quarter ended March 31, 2006		$	8.10			$	6.84			$	.35
Quarter ended June 30, 2006		$	9.00			$	7.13			$	.25
Quarter ended September 30, 2006		$	10.22			$	7.02			$	.14
Quarter ended December 31, 2006		$	7.64			$	6.28			$	.10

On March 23, 2007, the high and low sales price per unit on the NYSE was $6.71 and $6.57, respectively.

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

		Year Ended December 31,
		2006				2005				2004				2003				2002
Net profits income		$	7,796			$	5,818			$	6,161			$	8,969			$	9,357
Distributable income		$	7,262			$	5,601			$	5,657			$	8,036			$	8,616
Distributions declared		$	7,250			$	5,590			$	5,728			$	7,989			$	8,652
Distributable income per Unit		$	0.84			$	0.65			$	0.66			$	0.93			$	1.00
Distributions per Unit		$	0.84			$	0.65			$	0.67			$	0.93			$	1.01
Total assets (at end of period)		$	18,386			$	21,675			$	23,801			$	26,458			$	31,265

Distributable income of the Trust consists of the excess of net profits income plus Infill Well Net Proceeds less general and administrative expenses and interest expense of the Trust. The Trust recognizes net profits income during the period in which amounts are received by the Trust.

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

Results of Operations

Discussion of Years Ended December 31, 2006, 2005, and 2004

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, 2006, 2005 and 2004 are derived from actual oil and gas production from October 1, 2005 through September 30, 2006, October 1, 2004 through September 30, 2005 and October 1, 2003 through September 30, 2004, respectively. The following tables set forth oil and gas sales attributable to the Underlying Properties during the three years ended December 31, 2006.

		Bbls of Oil
		2006				2005				2004
Chalkley Field			4,520				5,155				6,756
Robinson’s Bend Field			—				—				—
Cotton Valley Fields			1,529				1,852				2,077
Austin Chalk Fields			12,787				15,315				16,574
Total			18,836				22,322				25,407

		Mcf of Gas
		2006				2005				2004
Chalkley Field			1,102,855				1,226,513				1,514,308
Robinson’s Bend Field			1,761,754				1,825,667				1,926,899
Cotton Valley Fields			664,283				684,434				836,987
Austin Chalk Fields			187,423				177,512				144,270
Total			3,716,315				3,914,126				4,422,464

For the year ended December 31, 2006, net profits income was $7.8 million, as compared to $5.8 million and $6.2 million for the same periods in 2005 and 2004, respectively. The increase in net profits income during 2006 as compared to 2005 is due to higher average gas prices paid to the Trust in 2006 combined with payments received by the Trust in 2006 with respect to the Robinson’s Bend Field. The decrease in net profits income during 2005 as compared to 2004 is primarily due to an increase in capital expenditures in 2005 as a result of workovers performed on wells in the Chalkley Field, Cotton Valley Fields and Austin Chalk Fields.

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 for distributions to Unitholders with respect to the Robinson’s Bend Field during the years ended December 31, 2005 and 2004. The Trust received approximately $0.6 million in 2006 (pertaining to production during the twelve month period ended September 30, 2006) for payments for distributions to Unitholders with respect to the Robinson’s Bend Field.

In calculating the Robinson’s Bend Field Net Proceeds pertaining to the quarter ended December 31, 2006 production, costs and expenses exceed revenues by approximately $50,000. Therefore, the Trust received no payments with respect to the Robinson’s Bend Field during the quarter ended March 31, 2007. The Robinson’s Bend Field Cumulative Deficit (pertaining to production as of December 31, 2006) is approximately $50,000. Neither the Trust nor Unitholders are liable to pay such deficit.

However, the Trust will receive no payments with respect to the Robinson’s Bend Field until future proceeds exceed the Robinson’s Bend Cumulative Deficit.

Gas production attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin Chalk Fields was 1,954,561 Mcf, 2,088,459 Mcf and 2,495,565 Mcf in 2006, 2005 and 2004, respectively. Gas production attributable to the Underlying Properties in the Robinson’s Bend Field was 1,761,754 Mcf, 1,825,667 Mcf and 1,926,899 Mcf in 2006, 2005 and 2004, respectively. Gas production decreased during each of the years ended December 31, 2006 as a result of normal production declines. Oil production attributable to the Underlying Properties for the year ended December 31, 2006 was 18,836 Bbls as compared to 22,322 Bbls and 25,407 Bbls for the same periods in 2005 and 2004, respectively.

The average price used to calculate Net Proceeds for gas, before gathering, treating and transportation deductions, during the year ended December 31, 2006 was $5.28 per MMBtu as compared to $4.43 and $3.68 per MMBtu for the years ended December 31, 2005 and 2004, respectively. The average price used to calculate Net Proceeds for oil during the years ended December 31, 2006, 2005 and 2004 was $58.56, $46.14 and $30.58 per Bbl, respectively. When TEMI pays a purchase price for gas based on the Minimum Price, TEMI receives Price Credits which it is entitled to deduct in determining the purchase price when the Index Price for gas exceeds the Minimum Price. As of December 31, 2006, TEMI had no outstanding Price Credits. No Price Credits were deducted in calculating the purchase price related to distributions during the three years ended December 31, 2006.

Additionally, if the Index Price for gas exceeds $2.10 per MMBtu, adjusted annually for inflation ($2.22 per MMBtu, $2.18 per MMBtu and $2.13 per MMBtu for 2006, 2005 and 2004 production, respectively), TEMI is entitled to deduct 50% of such excess in calculating the purchase price. Such price sharing arrangement reduced Net Proceeds during the years ended December 31, 2006, 2005, and 2004 by $11.1 million, $8.9 million and $6.8 million, respectively.

During the years ended December 31, 2006, 2005 and 2004, the Trust was distributed approximately $516,000, $708,000 and $443,000, respectively, of Infill Well Proceeds generated from Infill Wells located in the Cotton Valley Fields. The Trust received no Infill Well Proceeds during the six months ended December 31, 2006. During this period, the Infill Wells’ costs and expenses exceeded gross revenues as a result of capital expenditures associated with additional Infill Wells drilled in the Cotton Valley Fields during this period.

Lease operating expenses and capital expenditures attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin Chalk Fields deducted in calculating distributions during the years ended December 31, 2006, 2005 and 2004 totaled $3.0 million, $3.4 million and $2.8 million, respectively. The increase in costs and expenses during the year ended December 31, 2005 as compared to the years ended December 2006 and 2004 is mainly due to workovers performed on certain wells in 2005 in the Chalkley, Cotton Valley and Austin Chalk Fields.

General and administrative expenses during the year ended December 31, 2006 was $1.0 million as compared to $0.9 million during each of the years ended December 31, 2005 and 2004. These expenses primarily relate to administrative services provided by Torch and the Trustee, and legal fees.

For the year ended December 31, 2006, distributable income was $7.3 million, or $0.84 per Unit, as compared to $5.6 million, or $0.65 per Unit, and $5.7 million, or $0.66 per Unit, for the same periods in 2005 and 2004, respectively. Total cash distributions of $7.3 million, or $0.84 per Unit, were made during the year ended December 31, 2006 as compared to $5.6 million, or $0.65 per Unit, and $5.7 million, or $0.67 per Unit, for the same periods in 2005 and 2004, respectively.

Net profits received by the Trust during the years ended December 31, 2006, 2005 and 2004, derived from production sold during the twelve months ended September 30, 2006, 2005 and 2004, respectively, was computed as shown in the following table (in thousands):

		Year Ended December 31,
		2006												2005												2004
		Chalkley,												Chalkley,												Chalkley,
		Cotton												Cotton												Cotton
		Valley and												Valley and												Valley and
		Austin				Robinson’s								Austin				Robinson’s								Austin				Robinson’s
		Chalk				Bend								Chalk				Bend								Chalk				Bend
		Fields				Field				Total				Fields				Field				Total				Fields				Field				Total
Oil and gas revenues		$	11,409			$	8,292							$	10,330			$	7,258							$	10,053			$	6,268
Direct operating expenses:
Lease operating expenses (including property tax)			2,078				6,051								2,126				5,873								2,035				5,852
Severance tax			877				797								778				652								782				517
			2,955				6,848								2,904				6,525								2,817				6,369
Net proceeds before capital expenditures			8,454				1,444								7,426				733								7,236				(101	)
Capital expenditures			929				189								1,302				876								751				136
			7,525				1,255								6,124				(143	)							6,485				(237	)
Cumulative Deficit			—				(763	)							—				—								—				—
			7,525				492
Net profits percentage			95	%			—	(a)							95	%			—	(a)							95	%			—	(a)
Net profits income		$	7,149			$	647			$	7,796			$	5,818			$	—			$	5,818			$	6,161			$	—			$	6,161

Termination of the Trust

The Trust will terminate on March 1 of any year if it is determined that the pre-tax future net cash flows, discounted at 10%, attributable to estimated net proved reserves of the Net Profits Interests on the preceding December 31 are less than $25.0 million. The pre-tax future net cash flows, discounted at 10%, attributable to estimated net proved reserves of the Net Profits Interests as of December 31, 2006 was approximately $26.4 million. Such reserve report was prepared pursuant to Securities and Exchange Commission guidelines and utilized an unescalated Henry Hub spot price for natural gas on December 31, 2006 of $5.64 per MMBtu. The December 31, 2006 reserve value was greater than $25.0 million. Therefore, the Trust did not terminate as of March 1, 2007. No assurances can be given that the Trust will not terminate on March 1, 2008. Upon termination of the Trust, The Trustee is required to sell the Net Profits Interests. No assurances can be given that the Trustee will be able to sell the Net Profits Interests, or the price that will be distributed to Unitholders following such a sale. Such distributions could be below the market value of the Units.

Critical Accounting Policy

Reserve Estimates

The proved reserves of the Trust are estimated quantities of oil and 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 judgement. For example, estimates are made regarding the amount and timing of future operating costs, production volumes and severance taxes, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also change. Any variance in these assumptions could materially affect the estimated quantity and value of the Trust’s reserves.

Despite the inherent imprecision in these engineering estimates, the reserves are significant to the potential automatic termination of the Trust if it is determined that the pre-tax future net cash flows, discounted at 10%, attributable to the estimated net proved reserves of the Net Profits Interests are less than $25.0 million. Independent petroleum engineering firms are engaged to estimate the Trust’s proved hydrocarbon liquid and gas reserves.

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 is sold pursuant to a Purchase Contract between TRC, Velasco, and TEMI. Pursuant to the Purchase Contract, TEMI is obligated to purchase all net production attributable to the Underlying Properties for an Index Price, less certain other charges, which are calculated monthly. The Index Price calculation is based on market prices of oil and gas and therefore is subject to commodity price risk. The Purchase Contract expires upon termination of the Trust and provides a Minimum Price paid by TEMI for gas. The Minimum Price is adjusted annually for inflation and was $1.80, $1.77 and $1.73 per MMBtu for 2006, 2005 and 2004, respectively. When TEMI pays a purchase price based on the Minimum Price, it receives Price Credits equal to the difference between the Index Price and the Minimum Price that it is entitled to deduct when the Index Price exceeds the Minimum Price. Additionally, if the Index Price exceeds the Sharing Price, TEMI is entitled to deduct such excess, the Price Differential. The Sharing Price was $2.22, $2.18 and $2.13 per MMBtu in 2006, 2005 and 2004, respectively. TEMI has an annual option to discontinue the Minimum Price commitment. However, if TEMI discontinues the Minimum Price commitment, it will no longer be entitled to deduct the Price Differential and will forfeit all accrued Price Credits. TEMI has not exercised its option to discontinue the Minimum Price Commitment.

Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

		Page
Report of Independent Registered Public Accounting Firm			20
Statements of Assets, Liabilities and Trust Corpus at December 31, 2006 and 2005			21
Statements of Distributable Income for the Years Ended December 31, 2006, 2005 and 2004			22
Statements of Changes in Trust Corpus for the Years Ended December 31, 2006, 2005 and 2004			23
Notes to Financial Statements			24

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, 2006 and 2005, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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 management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 2, the 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, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with the basis of accounting described in Note 2.

As discussed in Note 6 to the financial statements, the present value of the estimated future net revenues from proved reserves attributable to the Trust’s Net Profits Interests as of December 31, 2006 was approximately $26.4 million. As further discussed in Note 1 to the financial statements, the Trust will terminate on March 1 of any year in which it is determined that on December 31 of the prior year that the present value of estimated future net revenues from proved developed reserves attributable to the Trust’s Net Profits Interest is equal to or less than $25.0 million.

\s\ UHY LLP
Houston, Texas
April 12, 2007

Torch Energy Royalty Trust

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
(In thousands)

		December 31,				December 31,
		2006				2005
ASSETS
Cash		$	1			$	1
Net profits interests in oil and gas properties (net of accumulated amortization of $162,215 and $158,926 at December 31, 2006 and 2005, respectively)			18,385				21,674
		$	18,386			$	21,675
LIABILITIES AND TRUST CORPUS
Trust expense payable		$	222			$	234
Trust corpus			18,164				21,441
		$	18,386			$	21,675

The accompanying notes to financial statements
are an integral part of these statements.

Torch Energy Royalty Trust

STATEMENTS OF DISTRIBUTABLE INCOME
(In thousands, except per Unit amounts)

		Year Ended December 31,
		2006				2005				2004
Net profits income		$	7,796			$	5,818			$	6,161
Infill Well Net Proceeds			516				708				443
			8,312				6,526				6,604
General and administrative expenses			965				925				947
Interest Expense			85				—				—
			1,050				925				947
Distributable income		$	7,262			$	5,601			$	5,657
Distributable income per Unit (8,600 Units)		$	0.84			$	0.65			$	0.66
Distributions per Unit		$	0.84			$	0.65			$	0.67

The accompanying notes to financial statements
are an integral part of these statements.

Torch Energy Royalty Trust

STATEMENTS OF CHANGES IN TRUST CORPUS
(In thousands)

		Year Ended December 31,
		2006				2005				2004
Trust corpus, beginning of year		$	21,441			$	23,556			$	26,284
Amortization of Net Profits Interests			(3,289	)			(2,126	)			(2,657	)
Distributable income			7,262				5,601				5,657
Distributions to Unitholders			(7,250	)			(5,590	)			(5,728	)
Trust Corpus, end of year		$	18,164			$	21,441			$	23,556

The accompanying notes to financial statements
are an integral part of these statements.

Torch Energy Royalty Trust

Notes to 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, as trustee (“Trustee”), Torch Royalty Company (“TRC”) and Velasco Gas Company, Ltd. (“Velasco”) as owners of certain oil and gas properties (“Underlying Properties”) and Torch Energy Advisors Incorporated (“Torch”) as grantor. TRC and Velasco created net profits interests (“Net Profits Interests”) and conveyed such interests to Torch. 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 Trust will terminate upon the first to occur of: (i) an affirmative vote of the holders of not less than 66-2/3% of the outstanding Units to liquidate the Trust; (ii) such time as the ratio of the cash amounts received by the Trust from the Net Profits Interests to administrative costs of the Trust is less than 1.2 to 1.0 for three consecutive quarters; (iii) March 1 of any year if it is determined based on a reserve report as of December 31 of the prior year that the present value of estimated pre-tax future net cash flows, discounted at 10%, of proved reserves attributable to the Net Profits Interests is equal to or less than $25.0 million; or (iv) December 31, 2012. After termination of the Trust, the remaining assets of the Trust will be sold, and the proceeds therefrom (after expenses) will be distributed to the unitholders (“Unitholders”). The sole purpose of the Trust is to hold the Net Profits Interests, to receive payments from TRC and Velasco, and to make payments to Unitholders. The Trust does not conduct any business activity.

TRC and Velasco receive payments reflecting the proceeds of oil and gas sold and aggregate these payments, deduct applicable costs and make payments to the Trustee each quarter for the amounts due to the Trust. Unitholders receive quarterly cash distributions relating to oil and gas produced and sold from the Underlying Properties. 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 expenses and liabilities and for distribution to Unitholders, are the Net Profits Interests. Under the Trust Agreement, the Trustee receives the payments attributable to the Net Profits Interests and pays all expenses, liabilities and obligations of the Trust. The Trustee has the discretion to establish a cash reserve for the payment of any liability that is contingent or uncertain in amount or that otherwise is not currently due and payable. The Trustee is entitled to cause the Trust to borrow money to pay expenses, liabilities and obligations that cannot be paid out of cash held by the Trust. The Trustee is entitled to cause the Trust to borrow from any source, including from the entity serving as Trustee, provided that the entity serving as Trustee shall not be obligated to lend to the Trust. To secure payment of any such indebtedness (including any indebtedness to the Trustee), the Trustee is authorized to (i) mortgage and otherwise encumber the entire Trust estate or any portion thereof; (ii) carve out and convey production payments; (iii) include all terms, powers, remedies, covenants and provisions it deems necessary or advisable, including confession of judgement 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.

Torch Energy Royalty Trust

Notes to Financial Statements

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 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

The financial statements of the Trust are prepared on a modified cash basis and are not intended to present the financial position and results of operations in conformity with accepted accounting principles generally accepted in the United States of America (“GAAP”). Preparation of the Trust’s financial statements on such basis includes the following:

–		Revenues are recognized in the period in which amounts are received by the Trust. Therefore, revenues recognized during the years ended December 31, 2006, 2005 and 2004 are derived from oil and gas production sold during the twelve-month periods ended September 30, 2006, 2005 and 2004, respectively. General and administrative expenses are recognized on an accrual basis.
–		Amortization of the Net Profits Interests is calculated on a unit-of-production basis and charged directly to trust corpus.
–		Distributions to Unitholders are recorded when declared by the Trustee.
–		An impairment loss is recognized when the net carrying value of the Net Profits Interests exceeds its fair market value. No such impairment was recorded during the three years ended December 31, 2006.
–		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.

3. Federal Income Taxes

Tax counsel has advised the 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.

Torch Energy Royalty Trust

Notes to Financial Statements

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 any cash reserves established for the payment of contingent or future obligations of the Trust. Based on the payment procedures relating to the Net Profits Interest, cash received by the Trust on the last day of the second month of a particular quarter from the Net Profits Interests generally represents proceeds from the sale of oil and gas produced from the Underlying Properties during the preceding calendar quarter. The Quarterly Distribution Amount for each quarter is 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.

5. Related Party Transactions

Marketing Arrangements

TRC and Velasco contracted to sell the oil and gas production from the Underlying Properties to Torch Energy Marketing, Inc. (“TEMI”), a subsidiary of Torch, under a purchase contract (“Purchase Contract”). Under the Purchase Contract, TEMI is obligated to purchase all net production attributable to the Underlying Properties for an index price for oil and gas (“Index Price”), less certain gathering, treating and transportation charges, which are calculated monthly. The Index Price equals 97% of the average spot market prices of oil and gas (“Average Market Prices”) at the four locations where TEMI sells production.

The Purchase Contract also provides that a minimum price paid by TEMI for gas production is $1.70 per MMBtu adjusted annually for inflation (“Minimum Price”). When TEMI pays a purchase price based on the Minimum Price it receives price credits (“Price Credits”) equal to the difference between the Index Price and the Minimum Price that it is entitled to deduct in determining the purchase price when the Index Price for gas exceeds the Minimum Price. Price Credits are computed on a monthly basis. As of December 31, 2006, TEMI had no outstanding Price Credits. No Price Credits were deducted in calculating the purchase price related to distributions received by Unitholders during the three years ended December 31, 2006.

In addition, if the Index Price for gas exceeds $2.10 per MMBtu adjusted annually for inflation (“Sharing Price”), TEMI is entitled to deduct 50% of such excess (“Price Differential”) in determining the purchase price. As a result of such Sharing Price arrangement, Net Proceeds attributable to the Underlying Properties during the years ended December 31, 2006, 2005 and 2004 were reduced by $11.1 million, $8.9 million and $6.8 million, respectively. TEMI has an annual option to discontinue the Minimum Price commitment. However, if TEMI discontinues the Minimum Price commitment, it will no longer be entitled to deduct the Price Differential in calculating the purchase price and will forfeit all accrued Price Credits. TEMI has not exercised its option to discontinue the Minimum Price Commitment. The Minimum Price in 2006, 2005 and 2004 was approximately $1.80, $1.77 and $1.73 per MMBtu for 2006, 2005 and 2006, respectively. The Sharing Price in 2006, 2005 and 2004 was approximately $2.22, $2.18 and $2.13 per MMBtu, respectively.

Torch Energy Royalty Trust

Notes to Financial Statements

Gross revenues (before deductions for applicable gathering, treating and transportation charges) from TEMI included in the Net Proceeds calculations attributable to the Underlying Properties for the years ended December 31, 2006, 2005 and 2004 were $21.4 million, $19.2 million and $17.7 million, respectively.

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 gas processing or treating facilities.

Gathering, Treating and Transportation Arrangements

The Purchase Contract entitles TEMI to deduct certain gas gathering, treating and transportation costs in calculating the purchase price for gas in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields. The amounts that may be deducted in calculating the purchase price for such gas are set forth in the Purchase Contract and are not affected by the actual costs incurred by TEMI to gather, treat and transport gas. In the Robinson’s Bend Field, TEMI is entitled to deduct a gathering, treating and transportation fee of $0.26 per MMBtu adjusted annually for inflation ($0.303, $0.298 and $0.292 per MMBtu for 2006, 2005 and 2004, respectively, plus fuel usage equal to 5% of revenues. Additionally, a fee of $0.05 per MMBtu, representing a gathering fee payable to a non-affiliate of Torch, is deducted in calculating the purchase price for production from 68 of the 393 wells in the Robinson’s Bend Field. TEMI also deducts $0.38 per MMBtu plus 17% of revenues in calculating the purchase price for production from the Austin Chalk Fields, as a fee to gather, treat and transport gas production. TEMI deducts from the purchase price for gas in the Cotton Valley Fields a transportation fee of $0.045 per MMBtu for production attributable to certain wells. This transportation fee is paid to a third party. During the years ended December 31, 2006, 2005 and 2004, such fees deducted from the Net Proceeds calculations, attributable to production during the twelve months ended September 30, 2006, 2005 and 2004, in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $1.7 million, $1.6 million and $1.4 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 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 $191,000, $184,000 and $184,000 for the years ended December 31, 2006, 2005 and 2004, respectively.

Administrative Services Agreement

Pursuant to the Trust Agreement, Torch and the Trust entered into an administrative services agreement, effective October 1, 1993. The Trust is obligated, throughout the term of the Trust, to pay to Torch each quarter an administrative services fee for accounting, bookkeeping, informational and other services relating to the Net Profits Interests. The administrative services fee is $87,500 per calendar quarter commencing October 1, 1993. The amount of the administrative services fee is adjusted annually, based upon the change in the Producer’s Price Index as published by the Department of Labor, Bureau of Labor

Torch Energy Royalty Trust

Notes to Financial Statements

Statistics. Administrative services fees of $407,000, $400,000 and $391,000 were paid by the Trust to Torch during the three years ended December 31, 2006, 2005 and 2004, respectively.

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 $41,000, 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. During 2005, due to the impact of the Sarbanes-Oxley Act on the Trust, the Trustee increased its compensation for administrative services to $80,000 per year. Total administrative and transfer agent fees charged by the Trustee were $85,000, $84,000 and $56,000 for the years ended December 31, 2006, 2005 and 2004, respectively.

6. Supplemental Oil and Gas Information (Unaudited)

Total proved oil and gas reserves attributable to the Net Profits Interests as of December 31, 2006, 2005 and 2004 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 end-of-period Purchase Contract prices for oil and gas to estimated future production, less the estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves.

Reserve Quantities:

The following table sets forth the estimated total proved and proved developed oil and gas reserves attributable to the Trust’s Net Profits Interests (all located in the United States) for the years ended December 31, 2006, 2005 and 2004, 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 gas, but to a portion of oil and 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 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.

Year-end reserves at December 31, 2006 were 10.6 billion cubic feet equivalent (“Bcfe”) as compared to year-end 2005 and 2004 reserves of 19.5 Bcfe and 14.4 Bcfe, respectively. In accordance with Securities and Exchange Commission reporting guidelines, year-end reserves and the related future net revenues attributable to the Trust’s Net Profits Interests are estimated utilizing the Purchase Contract Price for gas, after gathering fees ($4.06, $5.55 and $4.18 per Mcf for 2006, 2005 and 2004, respectively). Such Purchase Contract prices were calculated utilizing the Henry Hub gas prices on the last day of the entity’s fiscal year ($5.64, $10.08 and $6.18 per MMBtu for 2006, 2005 and 2004, respectively).

The downward revision of the estimated oil and gas volumes and the related present value of the estimated net future revenues as of December 31, 2006 is primarily a result of lower natural gas prices on December 31, 2006 as compared to natural gas prices on December 31, 2005. The Robinson’s Bend Field estimated reserves as of December 31, 2006 (and December 31, 2004) were estimated to have no value. As of December 31, 2005, the Robinson’s Bend Field’s estimated reserves attributable to the Underlying Properties was 5.8 Bcf. The present value of the estimated future net revenues, discounted at 10%,

Torch Energy Royalty Trust

Notes to Financial Statements

attributable to the Underlying Properties in the Robinson’s Bend Field was approximately $13.3 million as of December 31, 2005.

Description		2006								2005								2004
		Oil				Gas				Oil				Gas				Oil				Gas
		(Mbbl)				(MMcf)				(Mbbl)				(MMcf)				(Mbbl)				(MMcf)
Proved reserves at beginning of year			56				19,164				61				14,055				67				14,079
Revisions			(5	)			(7,687	)			7				6,300				9				1,568
Extensions and discoveries			—				30				—				—				—				—
Production			(9	)			(1,205	)			(12	)			(1,191	)			(15	)			(1,592	)
Proved reserves at end of year			42				10,302				56				19,164				61				14,055
Proved developed reserves at beginning of year			54				18,789				55				12,025				61				12,022
Proved developed reserves at end of year			42				10,273				54				18,789				55				12,025

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (in thousands):

Estimated future net cash flows from the Net Profits Interests in proved oil and gas reserves at December 31, 2006, 2005 and 2004 are presented in the following table:

		December 31,
		2006				2005				2004
Future cash inflows		$	73,506			$	260,111			$	92,844
Future costs and expenses			(28,941	)			(151,917	)			(31,965	)
Net future cash flows			44,565				108,194				60,879
Discount at 10% for timing of cash flows			(18,189	)			(47,409	)			(21,892	)
Present value of future net cash flows for proved reserves		$	26,376			$	60,785			$	38,987

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, 2006, 2005 and 2004:

		Year Ended December 31,
		2006				2005				2004
Balance at beginning of year		$	60,785			$	38,987			$	37,172
Sales of oil and gas produced, net of production costs			(5,843	)			(7,143	)			(7,476	)
Accretion of discount			6,079				3,899				3,717
Extensions and discoveries			82				—				—
Revision of prior-year estimates, change in prices and other			(34,727	)			25,042				5,574
Balance at end of year		$	26,376			$	60,785			$	38,987

Estimates of future net cash flows from proved reserves of gas and oil condensate were made in accordance with Financial Accounting Standards Board Statement 69, “Disclosure about Oil and Gas Producing Activities.” The Trust has not filed or included in reports to any other Federal authority or agency any estimates of proved net oil and gas reserves.

Torch Energy Royalty Trust

Notes to Financial Statements

7. Quarterly Financial Data (Unaudited – in thousands, except per Unit amounts)

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

										Distributable
		Net Profits				Distributable				Income
		Income				Income				Per Unit
Quarter ended March 31, 2006		$	3,216			$	3,003			$	.35
Quarter ended June 30, 2006			2,014				2,173				.25
Quarter ended September 30, 2006			1,488				1,248				.15
Quarter ended December 31, 2006			1,078				838				.09
		$	7,796			$	7,262			$	.84
Quarter ended March 31, 2005		$	1,837			$	1,889			$	.22
Quarter ended June 30, 2005			1,110				1,025				.12
Quarter ended September 30, 2005			1,482				1,290				.15
Quarter ended December 31, 2005			1,389				1,397				.16
		$	5,818			$	5,601			$	.65

Torch Energy Royalty Trust

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

None.

Item 9A. Controls and Procedures

Based on their evaluation as of December 31, 2006, the Trustee has concluded that the Trust’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities and Exchange Act of 1934 (the “Exchange Act”)) are effective to ensure that information required to be disclosed by the Trust in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. The Trustee, in making these determinations, has relied to the extent reasonable on information provided by Torch.

There were no changes in the Trust’s internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act during the quarter ended December 31, 2006 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financing reporting.

Item 9B. Other Information

None.

Torch Energy Royalty Trust

PART III

Item 10. Directors and Executive Officers of the Registrant

Compensation Discussion and Analysis

The Registrant has no directors or executive officers. 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 Business 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.

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 $41,000, 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. During 2005, due to the impact of the Sarbanes-Oxley Act on the Trust, the Trustee increased its compensation for administrative services to $80,000 per year.

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 will receive, throughout the term of the Trust, an administrative services fee for accounting, bookkeeping and informational services related to the Net Profits Interests as described below in “Item 13 – Administrative Services Agreement.”

Torch Energy Royalty Trust

Item 12. Security Ownership of Certain Beneficial Owners and Management

The following table sets forth, as of March 27, 2007, certain information with respect to the ownership of Units held by all persons known by the Company to be the beneficial owners of 5% or 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 March 9, 2007. The Trust has no officers or directors. The Trust does not have an “Equity Compensation Plan”.

		Shares Beneficially Owned
Name of Beneficial Owner and Address		Units				Percent of Class
5% Unitholder:
Fairchild Energy Investment Co. LLC (1)			764,100				8.88	%
19800 MacArthur Boulevard, Suite 700 Irvine, Califormia 92612

Item 13. Certain Relationships and Related Transactions

Administrative Services Agreement

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 is obligated, throughout the term of the Trust, to pay to Torch each quarter an administrative services fee for accounting, bookkeeping, informational and other services relating to the Net Profits Interests. The administrative services fee is $87,500 per calendar quarter, adjusted annually, based upon the change in the Producer’s Price Index as published by the Department of Labor, Bureau of Labor Statistics. Administrative services fees of $407,000, $400,000 and $391,000 were paid by the Trust to Torch during the years ended December 31, 2006, 2005 and 2004, respectively.

Marketing Arrangement

TRC and Velasco contracted to sell the oil and gas production from the Underlying Properties to TEMI under a Purchase Contract. Under the Purchase Contract, TEMI is obligated to purchase all net production attributable to the Underlying Properties for an Index Price for oil and gas less certain gathering, treating and transportation charges, which are calculated monthly. The Purchase Contract also provides that TEMI pay the Minimum Price for gas production. When TEMI pays a purchase price based on the Minimum Price, it receives Price Credits equal to the difference between the Index Price and the Minimum Price that it is entitled to deduct in determining the purchase price when the Index Price for gas exceeds the Minimum Price. Price Credits are computed on a monthly basis, and as of December 31, 2006, TEMI had no outstanding Price Credits.

In addition, if the Index Price for gas exceeds the Sharing Price, TEMI is entitled to deduct the Price Differential in determining the purchase price. As a result of such Sharing Price arrangement, Net

Torch Energy Royalty Trust

Proceeds attributable to the Underlying Properties during the years ended December 31, 2006, 2005 and 2004 were reduced by $11.1 million, $8.9 million and $6.8 million, respectively. TEMI has an annual option to discontinue the Minimum Price commitment. However, if TEMI discontinues the Minimum Price commitment, it will no longer be entitled to deduct the Price Differential in calculating the purchase price and will forfeit all accrued Price Credits. TEMI has not exercised its option to discontinue the Minimum Price Commitment. The Minimum Price in 2006, 2005 and 2004 was approximately $1.80, $1.77 and $1.73 per MMBtu, respectively. The Sharing Price in 2006, 2005 and 2004 was approximately $2.22, $2.18 and $2.13 per MMBtu, respectively.

Gross revenues (before deductions for applicable gathering, treating and transportation charges) from TEMI included in the Net Proceeds calculation attributable to the Underlying Properties for the years ended December 31, 2006, 2005 and 2004 were $21.4 million, $19.2 million and $17.7 million, respectively.

Gathering, Treating and Transportation Arrangements

The Purchase Contract entitles TEMI to deduct certain gas gathering, treating and transportation costs in calculating the purchase price for gas in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields. The amounts that may be deducted in calculating the purchase price for such gas are set forth in the Purchase Contract and are not affected by the actual costs incurred by TEMI to gather, treat and transport gas. In the Robinson’s Bend Field, TEMI is entitled to deduct a gathering, treating and transportation fee of $0.26 per MMBtu commencing October 1, 1993 adjusted for inflation ($0.303, $0.298 and $0.292 per MMBtu for 2006, 2005 and 2004, respectively), plus fuel usage equal to 5% of revenues, payable to Bahia Gas Gathering, Ltd., a subsidiary of Torch, pursuant to a gas gathering agreement. Additionally, a fee of $0.05 per MMBtu, representing a gathering fee payable to a non-affiliate of Torch, is deducted in calculating the purchase price for production from 68 of the 393 wells in the Robinson’s Bend Field. TEMI also deducts $0.38 per MMBtu plus 17% of revenues in calculating the purchase price for production from the Austin Chalk Fields, as a fee to gather, treat and transport gas production. TEMI deducts from the purchase price for gas a transportation fee of $0.045 MMBtu for production attributable to certain wells in the Cotton Valley Fields. During the years ended December 31, 2006, 2005 and 2004, gas gathering, treating and transportation fees, deducted by TEMI from the Net Proceeds calculations attributable to production during the twelve months ended September 30, 2006, 2005 and 2004 in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $1.7 million, $1.6 million and $1.4 million, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase price from the Chalkley Field.

Torch Energy Royalty Trust

Item 14. Principal Accountant Fees and Services

The firm of UHY LLP (“UHY’) acts as our principal independent registered public accounting firm. Through December 31, 2006, UHY had a continued relationship with UHY Advisors, Inc. (“Advisors”) from which it leased auditing staff who were full-time, permanent employees of Advisors and through which UHY’s partners provide non-audit services. UHY has no full-time employees and therefore none of the audit services performed were provided by permanent full-time employees of UHY. UHY manages and supervises the audit services and audit staff, and is exclusively responsible for the opinion rendered in connection with its examination.

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 Torch and the Trustee. The outside auditors are appointed and engaged by Torch and the Trustee. Fees for services performed by UHY for the years ended December 31, 2006 and 2005 are:

		2006				2005
Audit Fees		$	111,000			$	113,579
Audit Related Fees			0				0
Tax Fees			0				0
All Other Fees			0				0
		$	111,000			$	113,579

Torch Energy Royalty Trust

PART IV

Item 15. Exhibits and 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, 2006 and 2005
Statements of Distributable Income for the Years Ended December 31, 2006, 2005 and 2004
Statements of Changes in Trust Corpus for the Years Ended December 31, 2006, 2005 and 2004
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 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). *

23.

Consents of Experts and Counsel.

23.1 –

Consent of T.J. Smith & Company, Inc.

Torch Energy Royalty Trust

23.2

- Netherland, Sewell and Associates, Inc.

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.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		TORCH ENERGY ROYALTY TRUST
		By:		Wilmington Trust Company,
				not in its individual capacity but solely as Trustee for the Trust
		By:		/s/ Bruce L. Bisson   Bruce L. Bisson, Vice President

Date: April 16, 2007

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

Torch Energy Royalty Trust

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 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). *

23.

Consents of Experts and Counsel.

23.1 –

Consent of T.J. Smith & Company, Inc.

23.2 –

Netherland, Sewell and Associates, Inc.

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.