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, 2005, 2004 and 2003.

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 will be 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. Recently enacted legislation 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”). During the period from July 1, 2003 to December 31,

7

2005, the Trust did not receive payments with respect to the Robinson’s Bend Field. During such period, Robinson’s Bend Field costs and expenses (including interest) exceeded net revenues by approximately $646,000. During the quarter ended March 31, 2006, Net Proceeds generated from the Net Profits Interests pertaining to the Robinson’s Bend Field exceeded the Robinson’s Bend Field Cumulative Deficit. Accordingly, distributions received by Unitholders during the quarter ended March 31, 2006 included approximately $425,000 of Net Proceeds from the Net Profits Interests in the Robinson’s Bend Field. If a Robinson’s Bend Cumulative Deficit were to develop again, Unitholders would cease to receive proceeds attributable to the Robinson’s Bend Field until future proceeds exceeded future costs and expenses and the cumulative excess of such costs and expenses including interest.

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, 2005 was approximately $60.8 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 $5.55 per Mcf. The computation of the $5.55 per Mcf Purchase Contract price was based on an unescalated Henry Hub spot price for natural gas on December 31, 2005 of $10.08 per MMBtu. The December 31, 2005 reserve value was greater than $25.0 million. Therefore, the Trust did not terminate on March 1, 2006. Based on oil and gas reserve estimates at December 31, 2005 prepared by independent reserve engineers, Torch projects that unless the Henry Hub spot price for natural gas on December 31, 2006 exceeds approximately $6.25 per MMBtu, the Trust will terminate on 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.

Item 1B. Unresolved Staff Comments

Not applicable.

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 33.8% working interest (25.6% net revenue interest) in 405 wells in the Robinson’s Bend Field in the Black Warrior Basin of Alabama. 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 30.4% working interest (23.6% net revenue interest) in 66 wells in four fields that produce from the Upper and Lower Cotton Valley formations in Texas. A subsidiary of Torch operates 41 of these wells. The remaining 25 wells are operated by Samson Lone Star Limited Partnership (“Samson”).

Austin Chalk Fields. The Underlying Properties include an average of 16.8% working interest (13.3% net revenue interest) in 79 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 attributable to the Chalkey Field, Cotton Valley Fields, Austin Chalk Fields and Robinson’s Bend Field was approximately $60.8 million as of December 31, 2005. 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, 2005, 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			405				169.0				—				—
Cotton Valley Fields			66				24.3				—				—
Austin Chalk Fields			34				5.8				45				8.1
Total			509				199.7				45				8.1

The following table shows the gross and net acreage for the Underlying Properties as of December 31, 2005. 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			28,816				5,019
Total			68,783				22,261

Drilling Activity

The following table sets forth the results of drilling activity for the Underlying Properties during the three years ended December 31, 2005. 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
Gross														Net
						Dry												Dry
		Productive				Holes				Total				Productive				Holes				Total
2005			17				0				17				1.4				0				1.4
2004			0				0				0				0				0				0
2003			1				0				1				.2				0				.2

There was no other drilling activity on the Underlying Properties during the three years ended December 31, 2005.

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, 2005, 2004 and 2003 (derived from production during the twelve months ended September 30, 2005, 2004 and 2003, respectively).

		Chalkley, Cotton Valley
		And Austin Chalk Fields
		2005				2004				2003
Production:
Gas (MMcf)			2,088				2,496				2,835
Oil (Mbbl)			22				25				24
Weighted average lifting cost per Mcfe		$	.96			$	.77			$	.53
Weighted average taxes on production per Mcfe		$	.35			$	.30			$	.24
Weighted average sales price (b)
Gas ($/Mcf)		$	4.45			$	3.72			$	3.64
Oil ($/Bbl)		$	46.14			$	30.58			$	24.00

      

		Robinson's Bend Field
		2005				2004				2003
Production:
Gas (MMcf)			1,826				1,927				2,014
Oil (Mbbl)			—				—				—
Weighted average lifting cost per Mcfe		$	3.22	(a)		$	3.04	(a)		$	2.75	(a)
Weighted average taxes on production per Mcfe		$	.36			$	.27			$	.25
Weighted average sales price (b)
Gas ($/Mcf)		$	3.98			$	3.25			$	3.12
Oil ($/Bbl)		$	—			$	—			$	—

(a)

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. Commencing with the second quarter of 2003 distribution (pertaining to the quarter ended March 31, 2003 production) lease operating expenses and capital expenditures were deducted in calculating Net Proceeds in the Robinson’s Bend Field.

(b)

Average sales prices are reflective of purchase prices paid by TEMI, pursuant to the Purchase Contract, less certain gathering, treating and transportation charges.

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, 2005, 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 27, 2006, there were 8,600,000 Units outstanding and approximately 390 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, 2004		$	7.10			$	5.68			$	.15
Quarter ended June 30, 2004		$	7.58			$	5.16			$	.17
Quarter ended September 30, 2004		$	6.70			$	5.70			$	.19
Quarter ended December 31, 2004		$	7.75			$	6.23			$	.16
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

On March 27, 2006, the high and low sales price per unit on the NYSE was $8.20 and $7.97, respectively.

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

		Year Ended December 31,
		2005				2004				2003				2002				2001
Net profits income		$	5,818			$	6,161			$	8,969			$	9,357			$	16,843
Distributable income		$	5,601			$	5,657			$	8,036			$	8,616			$	16,181
Distributions declared		$	5,590			$	5,728			$	7,989			$	8,652			$	16,211
Distributable income per Unit		$	0.65			$	0.66			$	0.93			$	1.00			$	1.88
Distributions per Unit		$	0.65			$	0.67			$	0.93			$	1.01			$	1.89
Total assets (at end of period)		$	21,675			$	23,801			$	26,458			$	31,265			$	36,696

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

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

Results of Operations

Discussion of Years Ended December 31, 2005, 2004, and 2003

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, 2005, 2004 and 2003 are derived from actual oil and gas production from October 1, 2004 through September 30, 2005, October 1, 2003 through September 30, 2004 and October 1, 2002 through September 30, 2003, respectively. The following tables

set forth oil and gas sales attributable to the Underlying Properties during the three years ended December 31, 2005.

		Bbls of Oil
		2005				2004				2003
Chalkley Field			5,155				6,756				7,887
Robinson’s Bend Field			—				—				—
Cotton Valley Fields			1,852				2,077				3,532
Austin Chalk Fields			15,315				16,574				12,683
Total			22,322				25,407				24,102

        

		Mcf of Gas
		2005				2004				2003
Chalkley Field			1,226,513				1,514,308				1,750,133
Robinson’s Bend Field			1,825,667				1,926,899				2,013,653
Cotton Valley Fields			684,434				836,987				1,004,949
Austin Chalk Fields			177,512				144,270				79,514
Total			3,914,126				4,422,464				4,848,249

For the year ended December 31, 2005, net profits income was $5.8 million, as compared to $6.2 million and $9.0 million for the same periods in 2004 and 2003, respectively. 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. The decrease in net profits income during 2004 as compared to 2003 is primarily due to the Trust receiving no payments with respect to the Robinson’s Bend Field during 2004 in addition to increased lease operating expenses and capital expenditures in 2004 as compared to 2003.

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 approximately $1.3 million in 2003 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 six months ended December 31, 2003 and during the years ended December 31, 2004 and 2005. During the period from July 1, 2003 to December 31, 2005, Robinson’s Bend Field Cumulative Deficit was approximately $646,000. During the quarter ended March 31, 2006, net proceeds generated from the Net Profits Interests exceeded Robinson’s Bend Field Cumulative Deficit. Accordingly, distributions received by Unitholders during the quarter ended March 31, 2006 included approximately $425,000 of Net Proceeds from the Net Profits Interests in the Robinson’s Bend Field. If a Robinson’s Bend Cumulative Deficit were to develop again, Unitholders would cease to receive proceeds attributable to the Robinson’s Bend Field until future future proceeds exceeded future costs and expenses and the cumulative excess of such costs and expenses including interest attributable to the Robinson’s Bend Field.

Gas production attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin Chalk Fields was 2,088,459 Mcf, 2,495,565 Mcf and 2,834,596 Mcf in 2005, 2004 and 2003, respectively. Gas production attributable to the Underlying Properties in the Robinson’s Bend Field was 1,825,667 Mcf, 1,926,899 Mcf and 2,013,653 Mcf in 2005, 2004 and 2003, respectively. Gas production decreased during each of the years ended December 31, 2005 as a result of normal production declines. Oil production attributable to the Underlying Properties for the year ended December 31, 2005 was 22,322 Bbls as compared to 25,407 Bbls and 24,102 Bbls for the same periods in 2004 and 2003, respectively.

The average price used to calculate Net Proceeds for gas, before gathering, treating and transportation deductions, during the year ended December 31, 2005 was $4.43 per MMBtu as compared to $3.68 and $3.56 per MMBtu for the years ended December 31, 2004 and 2003, respectively. The average price used to calculate Net Proceeds for oil during the years ended December 31, 2005, 2004 and 2003 was $46.14, $30.58 and $24.00 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, 2005, 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, 2005.

Additionally, if the Index Price for gas exceeds $2.10 per MMBtu, adjusted annually for inflation ($2.18 per MMBtu, $2.13 per MMBtu and $2.12 per MMBtu for 2005, 2004 and 2003 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, 2005, 2004, and 2003 by $8.9 million, $6.8 million and $6.9 million, respectively.

During the years ended December 31, 2005 and 2004, the Trust was distributed approximately $708,000 and $443,000, respectively, of Infill Well Proceeds generated from Infill Wells located in the Cotton Valley Fields. The Trust did not receive any proceeds pertaining to such wells during the year ended December 31, 2003 as the Infill Wells’ costs and expenses exceeded gross revenues prior to January 1, 2004.

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, 2005, 2004 and 2003 totaled $3.4 million, $2.8 million and $2.1 million, respectively. The increase in costs and expenses during each of the years ended December 31, 2005 and 2004 is mainly due to workovers performed on certain wells in the Chalkley, Cotton Valley and Austin Chalk Fields. Higher insurance expense and increased lease operating expenses in the Chalkley Field during 2004 also contributed to the increase in costs and expenses in 2004.

General and administrative expenses during each of the years ended December 31, 2005, 2004 and 2003 amounted to $0.9 million. These expenses primarily relate to administrative services provided by Torch and the Trustee, and legal fees.

For the year ended December 31, 2005, distributable income was $5.6 million, or $0.65 per Unit, as compared to $5.7 million, or $0.66 per Unit, and $8.0 million, or $0.93 per Unit, for the same periods in 2004 and 2003, respectively. Total cash distributions of $5.6 million, or $0.65 per Unit, were made during the year ended December 31, 2005 as compared to $5.7 million, or $0.67 per Unit, and $8.0 million, or $0.93 per Unit, for the same periods in 2004 and 2003, respectively.

Net profits received by the Trust during the years ended December 31, 2005, 2004 and 2003, derived from production sold during the twelve months ended September 30, 2005, 2004 and 2003, respectively, was computed as shown in the following table (in thousands):

		Year Ended December 31,
		2005												2004												2003
		Chalkley,				Robinson's								Chalkley,				Robinson's								Chalkley,				Robinson's
		Cotton Valley and				Bend								Cotton Valley and				Bend								Cotton Valley and				Bend
		Austin Chalk Fields				Field				Total				Austin Chalk Fields				Field				Total				Austin Chalk Fields				Field				Total
Oil and gas revenues		$	10,330			$	7,258							$	10,053			$	6,268							$	10,892			$	6,283
Direct operating expenses:
Lease operating expenses (including property tax)			2,126				5,873	(a)							2,035				5,852	(a)							1,571				4,181	(a)
Severance tax			778				652								782				517								717				504
			2,904				6,525								2,817				6,369								2,288				4,685
Net proceeds before capital expenditures			7,426				733								7,236				(101	)							8,604				1,598
Capital expenditures			1,302				876								751				136								513				441
Net proceeds			6,124				(143	)							6,485				(237	)							8,091				1,157
Net profits percentage			95	%			—	(b)							95	%			—	(b)							95	%			—	(b)
Net profits income		$	5,818			$	—			$	5,818			$	6,161			$	—			$	6,161			$	7,686			$	1,283			$	8,969

	(a)		Commencing with the second quarter 2003 distribution (pertaining to production during the quarter ended March 31, 2003), lease operating expenses and capital expenditures were deducted in calculating Net Proceeds from the Robinson’s Bend Field. Lease operating expenses and capital expenditures (in thousands) were $6,749, $5,988 and $5,969 during 2005, 2004 and 2003, respectively.
	(b)		With respect to the Robinson’s Bend Field, the Trust received no cash distributions during the six months ended December 31, 2003 and during each of the years ended December 31, 2004 and 2005. During such periods, the Robinson’s Bend Field costs and expenses (including interest) exceeded revenues by approximately $646,000.

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, 2005 was approximately $60.8 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, 2005 of $10.08 per MMBtu. The December 31, 2005 reserve value was greater than $25.0 million. Therefore, the Trust did not terminate on March 1, 2006. Based on oil and gas reserve estimates at December 31, 2005 prepared by independent reserve engineers, Torch projects that unless the Henry Hub spot price for natural gas on December 31, 2006 exceeds approximately $6.25 per MMBtu, the Trust will terminate on 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 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 $1.77, $1.73 and $1.71 per MMBtu for 2005, 2004 and 2003, 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 $2.18, $2.13 and $2.12 per MMBtu in 2005, 2004 and 2003, 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
Reports of Independent Registered Public Accounting Firms			19
Statements of Assets, Liabilities and Trust Corpus at December 31, 2005 and 2004			21
Statements of Distributable Income for the Years Ended December 31, 2005, 2004 and 2003			22
Statements of Changes in Trust Corpus for the Years Ended December 31, 2005, 2004 and 2003			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, 2005 and 2004, and the related statements of distributable income and changes in trust corpus for the years then ended. 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, 2005 and 2004, and the results of its operations and its cash flows for the years then ended in conformity with the basis of accounting described in Note 2.

\s\ UHY Mann Frankfort Stein & Lipp CPAs, LLP
Houston, Texas
March 30, 2006

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 distributable income and changes in trust corpus of the Torch Energy Royalty Trust (the “Trust”) for the year ended December 31, 2003. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides 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.

In our opinion, the financial statements referred to above present fairly, in all material respects the results of its operations and its cash flows for the year ended December 31, 2003 in conformity with the accounting principles described in Note 2.

\s\ Ernst & Young LLP
Houston, Texas
March 25, 2004

Torch Energy Royalty Trust

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

ASSETS

		December 31,				December 31,
		2005				2004
Cash		$	1			$	1
Net profits interests in oil and gas properties (net of accumulated amortization of $158,926 and $156,800 at December 31, 2005 and 2004, respectively)			21,674				23,800
		$	21,675			$	23,801

LIABILITIES AND TRUST CORPUS

Trust expense payable		$	234			$	245
Trust corpus			21,441				23,556
		$	21,675			$	23,801

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,
		2005				2004				2003
Net profits income		$	5,818			$	6,161			$	8,969
Infill Well Net Proceeds			708				443				—
Interest income			—				—				2
			6,526				6,604				8,971
General and administrative expenses			925				947				935
Distributable income		$	5,601			$	5,657			$	8,036
Distributable income per Unit (8,600 Units)		$	0.65			$	0.66			$	0.93
Distributions per Unit		$	0.65			$	0.67			$	0.93

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,
		2005				2004				2003
Trust corpus, beginning of year		$	23,556			$	26,284			$	31,044
Amortization of Net Profits Interests			(2,126	)			(2,657	)			(4,806	)
Distributable income			5,601				5,657				8,035
Distributions to Unitholders			(5,590	)			(5,728	)			(7,989	)
Trust Corpus, end of year		$	21,441			$	23,556			$	26,284

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, 2005, 2004 and 2003 are derived from oil and gas production sold during the twelve-month periods ended September 30, 2005, 2004 and 2003, 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, 2005.
-		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, 2005, 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, 2005.

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, 2005, 2004 and 2003 were reduced by $8.9 million, $6.8 million and $6.9 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 2005, 2004 and 2003 was approximately $1.77, $1.73 and $1.71 per MMBtu for 2005, 2004 and 2003, respectively. The Sharing Price in 2005, 2004 and 2003 was approximately $2.18, $2.13 and $2.12 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, 2005, 2004 and 2003 were $19.2 million, $17.7 million and $18.5 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 ($0.298, $0.292 and $0.289 per MMBtu for 2005, 2004 and 2003, respectively, plus fuel usage equal to 5% of revenues, payable to Bahia Gas Gathering, Ltd. (“Bahia”), 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 394 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, 2005, 2004 and 2003, such fees deducted from the Net Proceeds calculations, attributable to production during the twelve months ended September 30, 2005, 2004 and 2003, in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $1.6 million, $1.4 million and $1.3 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 $184,000, $184,000 and $176,000 for the years ended December 31, 2005, 2004 and 2003, 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 $400,000, $391,000 and $388,000 were paid by the Trust to Torch during the three years ended December 31, 2005, 2004 and 2003, 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. The Trustee receives a transfer agency fee of $5.00 annually per account (minimum of $15,000 annually), subject to change each December 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 also entitled to reimbursement for out-of-pocket expenses. Total administrative and transfer agent fees charged by the Trustee were $84,000 for the year ended December 31, 2005. Total administrative and transfer agent fees charged by the Trustee were $56,000 in each of the years ended December 31, 2004 and 2003.

6.

Supplemental Oil and Gas Information (Unaudited)

Total proved oil and gas reserves attributable to the Net Profits Interests as of December 31, 2005 and 2004 are based upon reserve reports prepared by T.J. Smith & Company, Inc. and Netherland, Sewell & Associates, Inc. Total proved oil and gas reserves attributable to the Net Profits Interests as of December 31, 2003 are based on reserve reports prepared by T.J. Smith & Company, Inc., Netherland, Sewell & Associates, Inc. and Ryder Scott Company, L.P. (“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, 2005, 2004 and 2003, 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, 2005 were 19.5 billion cubic feet equivalent (“Bcfe”) as compared to year-end 2004 and 2003 reserves of 14.4 Bcfe and 14.5 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 ($5.55, $4.18 and $4.11 per Mcf for 2005, 2004 and 2003). Such Purchase Contract prices were calculating utilizing the Henry Hub gas prices on the last day of the entity’s fiscal year ($10.08, $6.18 and $5.97 per MMBtu for 2005, 2004 and 2003, respectively). The favorable revision of the estimated gas volumes and the related present value of the estimated future net revenues during 2005 are primarily due to the increase in the natural gas price on December 31, 2005 as compared to the gas price on December 31, 2004 and 2003. As of December 31, 2005, the Robinson’s Bend Field’s estimated

Torch Energy Royalty Trust

Notes to Financial Statements

reserves attributable to the Underlying Properties was 5.8 Bcf. The present value of the estimated future net revenues, discounted at 10%, attributable to the Underlying Properties in the Robinson’s Bend Field is approximately $13.3 million. The Robinson’s Bend Field estimated reserves attributable to the Underlying Properties as of December 31, 2004 and December 31, 2003 were estimated to have no value.

Oil and gas reserves as of December 31, 2003 were restated to reflect Net Equivalent Volumes. The oil and gas reserves as of December 31, 2003 reflected in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2003 (20.2 Bcfe) reflected an estimate of the total production anticipated from the Underlying Properties, net to the Trust’s net profits interest percentage. The reserve restatement had no effect on the Statement of Assets, Liabilities and Trust Corpus as of December 31, 2003, or the Statement of Distributable Income and Statement of Changes in Trust Corpus for the year ended December 31, 2003. Additionally, the restatement had no impact on the estimate of the future net cash flows as of Decemeber 31, 2003.

																		2003
Description		2005								2004								(Restated)
		Oil				Gas				Oil				Gas				Oil				Gas
		(Mbbl)				(MMcf)				(Mbbl)				(MMcf)				(Mbbl)				(MMcf)
Proved reserves at beginning of year			61				14,055				67				14,079				90				17,592
Revisions			7				6,300				9				1,568				(9	)			(1,661	)
Extensions and discoveries			—				—				—				—				—				—
Production			(12	)			(1,191	)			(15	)			(1,592	)			(14	)			(1,852	)
Proved reserves at end of year			56				19,164				61				14,055				67				14,079
Proved developed reserves at beginning of year			55				12,025				61				12,022				90				17,592
Proved developed reserves at end of year			54				18,789				55				12,025				61				12,022

Torch Energy Royalty Trust

Notes to Financial Statements

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, 2005, 2004 and 2003 are presented in the following table:

		December 31,
		2005				2004				2003
Future cash inflows		$	260,111			$	92,844			$	83,202
Future costs and expenses			(151,917	)			(31,965	)			(24,712	)
Net future cash flows			108,194				60,879				58,490
Discount at 10% for timing of cash flows			(47,409	)			(21,892	)			(21,318	)
Present value of future net cash flows for proved reserves		$	60,785			$	38,987			$	37,172

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, 2005, 2004 and 2003:

		Year Ended December 31,
		2005				2004				2003
Balance at beginning of year		$	38,987			$	37,172			$	40,838
Sales of oil and gas produced, net of production costs			(7,143	)			(7,476	)			(7,587	)
Accretion to discount			3,899				3,717				4,084
Extensions and discoveries			—				—				—
Revision of prior-year estimates, change in prices and other			25,042				5,574				(163	)
Balance at end of year		$	60,785			$	38,987			$	37,172

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, 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
Quarter ended March 31, 2004		$	1,488			$	1,304			$	.15
Quarter ended June 30, 2004			1,687				1,445				.17
Quarter ended September 30, 2004			1,622				1,570				.18
Quarter ended December 31, 2004.			1,364				1,338				.16
		$	6,161			$	5,657			$	.66

Torch Energy Royalty Trust

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

During August 2004, E&Y resigned as the Trust’s independent auditor based upon its annual review of its audit client portfolio. The Trust had no disagreements with Ernst & Young LLP (“E&Y”) concerning their audit or the application of accounting principles. On October 21, 2004, the Trust engaged UHY Mann Frankfort Stein & Lipp CPAs, LLP (“UHY”) as its principal independent registered public accountants.

Item 9A. Controls and Procedures

Based on their evaluation as of December 31, 2005, 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, 2005 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

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 serves 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.”

Item 12. Security Ownership of Certain Beneficial Owners and Management

The following table sets forth, as of March 28, 2006, 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 28, 2006. The Trust has no officers or directors. The Trust does not have an “Equity Compensation Plan”.

Torch Energy Royalty Trust

Name of Beneficial Owner and Address		Shares Beneficially Owned
		Units				Percent of Class
5% Unitholder:
Barington Companies Equity Partners, L.P.(1)			446,400				5.19	%
888 Seventh Avenue
17th Floor
New York, New York 10019

     (1) Information is based on a 13D/A filed with the SEC on March 24, 2006, on behalf of Barington Companies Equity Partners, L.P., Barington Companies Investors, LLC, Barington Companies Offshore Fund, Ltd. (BVI), Barington Investments, L.P., Barington Companies Advisors, LLC, Barington Capital Group, L.P., LNA Capital Corp., James Mitarotonda, Alpine Associates, A Limited Partnership, Alpine Partners, L.P., Alpine Associates II, L.P., Palisades Partners, L.P., Eckert Corporation, Victoria Eckert, Gordon A. Uehling, Jr., Arbitrage & Trading Management Company and Robert E. Zoellner. As reported, each entity generally has sole voting and dispositive power over the securities it beneficially owns.

     Barington Companies Equity Partners, L.P. beneficially owns an aggregate of 37,600 Units. As the general partner of Barington Companies Equity Partners, L.P., Barington Companies Investors, LLC may be deemed to beneficially own the 37,600 Units owned by Barington Companies Equity Partners, L.P.

     Barington Companies Offshore Fund, Ltd. (BVI) beneficially owns 28,200 Units. Barington Investments, L.P. beneficially owns 28,200 Units. As the investment advisor to Barington Companies Offshore Fund, Ltd. (BVI) and the general partner of Barington Investments, L.P., Barington Companies Advisors, LLC may be deemed to beneficially own the 28,200 Units owned by Barington Companies Offshore Fund, Ltd. (BVI) and the 28,200 Units owned by Barington Investments, L.P. As the Managing Member of Barington Companies Advisors, LLC, Barington Capital Group, L.P. may be deemed to beneficially own the 28,200 Units beneficially owned by Barington Investments, L.P. and the 28,200 Units owned by Barington Companies Offshore Fund, Ltd. (BVI). As the majority member of Barington Companies Investors, LLC, Barington Capital Group, L.P. may also be deemed to beneficially own the 37,600 Units owned by Barington Companies Equity Partners, L.P. As the general partner of Barington Capital Group, L.P., LNA Capital Corp. may be deemed to beneficially own the 37,600 Units owned by Barington Companies Equity Partners, L.P., the 28,200 Units beneficially owned by Barington Investments, L.P. and the 28,200 Units owned by Barington Companies Offshore Fund, Ltd. (BVI). As the sole stockholder and director of LNA Capital Corp., Mr. Mitarotonda may be deemed to beneficially own the 37,600 Units owned by Barington Companies Equity Partners, L.P., the 28,200 Units beneficially owned by Barington Investments, L.P. and the 28,200 Units owned by Barington Companies Offshore Fund, Ltd. (BVI). Mr. Mitarotonda has sole voting and dispositive power with respect to the 37,600 Units owned by Barington Companies Equity Partners, L.P., the 28,200 Units beneficially owned by Barington Investments, L.P. and the 28,200 Units owned by Barington Companies Offshore Fund, Ltd. (BVI).

     Alpine Associates, A Limited Partnership beneficially owns 273,000 Units. Alpine Partners, L.P. beneficially owns 45,000 Units. Alpine Associates II, L.P. beneficially owns 22,200 Units. Palisades Partners, L.P. beneficially owns approximately 12,200 Units. As the general partner of each of Alpine Associates, A Limited Partnership, Alpine Partners, L.P. and Alpine Associates II, L.P., Eckert Corporation may be deemed to beneficially own the 273,000 Units owned by Alpine Associates, A Limited Partnership, the 45,000 Units owned by Alpine Partners, L.P. and the 22,200 Units owned by Alpine Associates II, L.P. As the sole stockholder and director of Eckert Corporation, Ms. Eckert may be deemed to beneficially own the 273,000 Units owned by Alpine Associates, A Limited Partnership, the 45,000 Units owned by Alpine Partners, L.P. and the 22,200 Units owned by Alpine Associates II, L.P.

     As the general partner of Palisades Partners, L.P., Mr. Uehling may be deemed to beneficially own the 12,200 Units owned by Palisades Partners, L.P. Pursuant to investment advisory agreements with each of Alpine Associates II, L.P. and Palisades Partners, L.P., Arbitrage & Trading Management Company may be deemed to beneficially own (but they do not have voting power over the 22,200 Units owned by Alpine Associates II, L.P. and the 12,200 Units owned by Palisades Partners, L.P. As the owner and operator of Arbitrage & Trading

Torch Energy Royalty Trust

Management Company, Mr. Zoellner may be deemed to beneficially own the 22,200 Units owned by Alpine Associates II, L.P. and the 12,200 Units owned by Palisades Partners, L.P.

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 $400,000, $391,000 and $388,000 were paid by the Trust to Torch during the years ended December 31, 2005, 2004 and 2003, 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, 2005, 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 Proceeds attributable to the Underlying Properties during the years ended December 31, 2005, 2004 and 2003 were reduced by $8.9 million, $6.8 million and $6.9 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 2005, 2004 and 2003 was approximately $1.77, $1.73 and $1.71 per MMBtu, respectively. The Sharing Price in 2005, 2004 and 2003 was approximately $2.18, $2.13 and $2.12 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, 2005, 2004 and 2003 were $19.2 million, $17.7 million and $18.5 million, respectively.

Torch Energy Royalty Trust

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 ($0.298, $0.292 and $0.289 per MMBtu for 2005, 2004 and 2003, 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 394 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, 2005, 2004 and 2003, gas gathering, treating and transportation fees, deducted by TEMI from the Net Proceeds calculations attributable to production during the twelve months ended September 30, 2005, 2004 and 2003 in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $1.6 million, $1.4 million and $1.3 million, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase price from the Chalkley Field.

Item 14. Principal Accountant Fees and Services

The Trust does not have an audit committee, and has no audit committee pre-approval policy with respect to fees paid to UHY. Any pre-approval of services performed by UHY and related fees is granted by 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, 2005 and 2004 are:

		2005				2004
Audit Fees		$	113,579			$	117,041
Audit Related Fees			0				0
Tax Fees			0				0
All Other Fees			0				0
		$	113,579			$	117,041

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

Reports of Independent Registered Public Accounting Firms
Statements of Assets, Liabilities and Trust Corpus at December 31, 2005 and 2004
Statements of Distributable Income for the Years Ended December 31, 2005, 2004 and 2003
Statements of Changes in Trust Corpus for the Years Ended December 31, 2005, 2004 and 2003
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.
						23.2  -     Netherland, Sewell and Associates, Inc.

Torch Energy Royalty Trust

				23.3  -     Consent of Ryder Scott Company, L.P.

			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.

			99.			Additional Exhibits.
						99.1  -     Financial Statements of Torch Energy Advisors Incorporated.

*

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.

Date: March 31, 2006

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

Index to Exhibits

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.*
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). *
Consents of Experts and Counsel.
23.1		-		Consent of T.J. Smith & Company, Inc.
23.2		-		Netherland, Sewell and Associates, Inc.
23.3		-		Consent of Ryder Scott Company, L.P.
Rule 13a-14(a)/15d-14(a) Certifications.
31.1		-		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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.
Additional Exhibits.
99.1		-		Financial Statements of Torch Energy Advisors Incorporated.

*

Incorporated by reference from Registration Statements on Form S-1 of Torch Energy Advisors Incorporated (Registration No. 33-68688) dated November 16, 1993.