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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 ($0.298, $0.292 and $0.289 per MMBtu for 2005, 2004, and 2003, respectfully), plus fuel usage equal to 5% of revenues, payable to Bahia Gas Gathering, Ltd. (“Bahia”), an affiliate of Torch, pursuant to a gas gathering agreement. 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 394 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, 2005, 2004 and 2003, gathering, treating and transportation fees deducted from the Net Proceeds calculations pertaining 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 for 2005, 2004 and 2003, 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, 2005, 2004 and 2003 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 websites 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.

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:

	•		The domestic and foreign supply of and demand for oil and gas;

	•		The price and quantity of foreign imports of oil and gas;

	•		The level of consumer product demand;

	•		Weather conditions;

	•		Overall domestic and global economic conditions;

	•		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;

•

The ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

	•		Technological advances affecting energy consumption;

	•		Domestic and foreign governmental regulations and taxation;

	•		The impact of energy conservation efforts;

•

The capacity of natural gas pipelines and other transportation facilities to the Trust’s production; and

•

The price and availability of alternative fuels.

Any substantial and extended decline in the price of 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, 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,

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.

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

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.

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.

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

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.

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.

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

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:

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

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.

Exhibits

Exhibit
Number Exhibit


			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). *

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.


	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: 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.

EX-23.1 2 h34498exv23w1.htm CONSENT OF T.J. SMITH & COMPANY, INC. exv23w1

Exhibit 23.1

CONSENT OF T.J. SMITH & COMPANY, INC.

We hereby consent to the use of our report dated March 21, 2006 regarding Torch Energy Royalty Trust and to the reference to our firm included in this Form 10-K.


	T.J. SMITH & COMPANY, INC.
	By:	/s/ T. J. Smith
		T.J. Smith

Houston, Texas
March 29, 2006

EX-23.2 3 h34498exv23w2.htm NETHERLAND, SEWELL AND ASSOCIATES, INC. exv23w2

Exhibit 23.2

CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC.

We hereby consent to the use of our reports dated March 21 and 22, 2006 regarding Torch Energy Royalty Trust interest for the year ended December 31, 2005 and to reference to our firm included in this Form 10-K.


	Netherland, Sewell and Associates, Inc.
	By:	/s/ Danny D. Simmons
		Danny D. Simmons
		Executive Vice President

Houston, Texas
March 29, 2006

EX-23.3 4 h34498exv23w3.htm CONSENT OF RYDER SCOTT COMPANY, L.P. exv23w3

Exhibit 23.3

CONSENT OF RYDER SCOTT COMPANY, L.P.

We hereby consent to the use of our report dated January 29, 2004 regarding Torch Energy Royalty Trust interest for the year ended December 31, 2003 and to reference to our firm included in this Form 10-K.


	RYDER SCOTT COMPANY, L.P.
	By:	/s/ Ryder Scott Company, L.P.
		Ryder Scott Company, L.P.

Houston, Texas
March, 29, 2006

EX-31.1 5 h34498exv31w1.htm CERTIFICATION PURSUANT TO SECTION 302 exv31w1

Exhibit 31.1

CERTIFICATIONS

I, Bruce L. Bisson, certify that:

	1.		I have reviewed this annual report on Form 10-K of Torch Energy Royalty Trust, for which Wilmington Trust Company acts as Trustee;

	2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

	3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this report;

	4.		I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15 (e) and 15d-15(e)), or for causing such procedures to be established or maintained, for the registrant and have:

	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

	b)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	c)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors:

	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)		Any fraud, whether or not material, that involves persons who have a significant role in the registrant’s internal control over financial reporting.

In giving the certifications in paragraphs 4 and 5 above, I have relied to the extent I consider reasonable on information provided to me by Torch Energy Advisors Incorporated.



Date: March 31, 2006	By:	/s/ Bruce L. Bisson
		Bruce L. Bisson
		Vice President Wilmington Trust Company

EX-32.1 6 h34498exv32w1.htm CERTIFICATION PURSUANT TO SECTION 906 exv32w1

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The following certification accompanies the issuer’s Annual Report on Form 10-K and is not filed, as provided in SEC Release Nos. 33-8238, 34-47986 dated June 5, 2003.

In connection with the Annual Report of Torch Energy Royalty Trust (the “Trust”) on Form 10-K for the year ended December 31, 2005, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Bruce L. Bisson, Vice President, of Wilmington Trust Company, the trustee of the Trust, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

	1)		The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and

	2)		The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

A signed original of this written statement required by Section 906 has been provided to the Torch Energy Royalty Trust and will be retained by the Torch Energy Royalty Trust and furnished to the Securities and Exchange Commission or its staff upon request.

Dated: March 31, 2006



		\s\Bruce L. Bisson
		Bruce L. Bisson, Vice President

EX-99.1 7 h34498exv99w1.htm FINANCIAL STATEMENTS OF TORCH ENERGY ADVISORS INCORPORATED exv99w1

Exhibit 99.1

In view of the possible materiality of the financial condition of Torch Energy Advisors Incorporated (“Torch”) to the Minimum Price commitment, which relates to the Purchase Contract between the Trust and Torch, Torch’s financial statements are provided as an exhibit to the Trust’s annual report on Form 10-K. Upon the termination of the Minimum Price commitment, such financial statements will not be included in this annual filing.

TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED

The following should be read in conjunction with the consolidated financial statements, and the related notes thereto, of Torch Energy Advisors Incorporated and Subsidiaries (the “Company”).

DISCUSSION OF YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

Revenues

The Company’s service activities, which include accounting and finance, oil and gas operations and engineering, hydrocarbon marketing, acquisitions and divestitures, and various administrative services, accounted for 42% of revenues in 2005. Revenues for such service activities are received under various outsourcing and management contracts and are classified primarily as Service Fees or Operating Fees. Service Fees include payments for management and administrative services, fees for providing drilling rig crew services to third parties, certain hydrocarbon marketing activities, and consulting services. The Company also receives fees related to oil and gas field operations, which it classifies as Operating Fees. Operating Fees are a combination of fees paid by clients and reimbursements received from working interest owners customarily paid to the operator of oil and gas properties.

Service Fees were $8.8 million in 2005, up 38% from $6.4 million in 2004. Service Fees were $6.4 million in 2004, down 15% from $7.5 million in 2003.

Operating fees totaled $.4 million in both 2005 and 2004. Operating fees totaled $.4 million, down 20% from $.5 million in 2003.

Until December 2004, the Company’s principal oil and gas properties related to the 2001 purchase of oil and gas properties in Louisiana and Texas by Milam Energy L.P. (“Milam”), a wholly-owned partnership. These properties were sold to third parties in October and December 2004. In July and September 2005, all properties owned by Person Panna Maria LLC (“PPM”) and Big Energy, LLC (“Big Energy”), respectively, were sold to third parties. The results of Milam, PPM and Big Energy are classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation. The Company maintains other interests in oil and gas fields in Texas and Louisiana. Oil and gas revenues for 2005 were $5.5 million, up 72% from $3.2 million in 2004. This increase is due to the purchase of a well in May 2004 from which a second well began producing in August 2005. Oil and gas revenues for 2004 were $3.2 million, up 220% from $1.0 million in 2003 due to the purchase of the well in May 2004.

Hedging activities mainly consist of financial swap contracts entered into for the purpose of hedging the impact of market fluctuations on production. There was no hedging activity for 2005 and 2004. Hedging activities resulted in a loss of $100,000 in 2003.

TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED

From time to time, the Company has sold interests in various oil and gas properties, securities, and other assets. In September 2005, all properties owned by Big Energy were sold to a third party for $4.0 million, resulting in a gain of approximately $1.0 million. In July 2005, all properties owned by PPM were sold to third parties for $10.3 million, resulting in a gain of approximately $9.5 million. Both the Big Energy and PPM gains are included in income from discontinued operations for the year ended December 31, 2005. In February 2005, the Company sold its interest in a certain gas field to a third party. The purchaser assumed the $1.1 million liability for plugging and abandonment obligations included in other current liabilities at December 31, 2004. As a result of this sale, the Company recognized a $1.1 million gain and retained a 3.33% overriding royalty interest in the property. In October and December 2004, Milam entered into separate agreements to sell its oil and gas properties. In October 2004, Milam sold its interest in a field for $3.6 million, resulting in a loss of approximately $3.1 million. In December 2004, Milam sold its remaining fields for $11.8 million resulting in a gain of approximately $1.8 million. Both the gain and loss are included in income from discontinued operations for the year ended December 31, 2004. In January 2003, the Company sold its assets in a coal bed methane field in Alabama for $43 million in cash, resulting in a gain of approximately $41 million. During the year ended December 31, 2003, the Company sold pieces of art to third parties for a total of $1,057,000, generating a gain of $68,000. In December 2003, Torch Energy Finance Company (“TEFC”) and the Company sold Torch Energy Finance Fund LPI (“TEFF”) to a third party for $325,000 plus the assumption of a credit facility, resulting in a gain of $17,487,000. In December 2003, the Company sold 58,231 Resources Connection Inc. shares for $1,609,000, resulting in a gain of $811,000.

Expenses

The Company includes in cost of services all of the personnel costs of providing services to its clients pursuant to its outsourcing agreements. The level of expense recorded by the Company from year to year is subject to variability related to client activity level. Cost of services totaled $446,000, $467,000 and $2.1 million in 2005, 2004 and 2003, respectively. The decrease in 2004 is due to the cancellation of several contracts in 2003.

General and administrative expenses totaled $6.7 million, $5.7 million and $11.8 million in 2005, 2004 and 2003, respectively. The 18% increase in general and administrative costs in 2005 is primarily due to performance incentives. The 52% reduction in general and administrative costs in 2004 is due to a reduction in workforce resulting in a reduction in salaries and benefits, performance incentives and office rent.

TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED

Oil and gas operating expenses for 2005 totaled $838,000, up 23% from $683,000 in 2004 due to the purchase of a well in May 2004 from which a second well began producing in August 2005. Oil and gas operating expenses for 2004 totaled $683,000, up 128% from $300,000 in 2003 due to the purchase of the well in May 2004. The Company’s average oil and gas operating expenses per Mcfe was $.84, $1.16 and $1.95 in 2005, 2004 and 2003, respectively.

Interest expense for 2005 totaled $1.9 million, down 14% from $2.2 million in 2004 due to a reduction in debt for principal payments in early 2005. Interest expense for 2004 totaled $2.2 million, down 27% from $3.0 million in 2003 due to the sale of TEFF and the assumption of a credit facility by a third party in December 2003.

Equity in Earnings of Affiliates and Investees

The Company recorded equity earnings of $162,000 for the year ended December 31, 2005 and an equity loss of $2.7 million and $3.1 million for the years ended December 31, 2004 and 2003, respectively. The equity losses in 2004 and 2003 represent the Company’s loss in P2 Energy Solutions (“P2ES”), a company that provides software solutions and technology services for the energy industry. The equity earnings in 2005 represents the Company’s income in P2ES for January through March 2005. In December 2004, P2ES was contributed to Tristone Energy Services, Inc. (“Tristone”) and as a minority shareholder of P2ES, and on April 19, 2005 the Company exchanged its shares of stock in P2ES for shares in Tristone. At December 31, 2005, the Company has a 4.86% interest on a fully-diluted basis in Tristone, resulting in the Company changing the accounting method for its investment to the cost method.

Net Income

The foregoing activities resulted in the following net income (amounts in thousands):


	2005		2004			2003
Income (loss) from continuing operations before income taxes and cumulative effect of change in accounting principal	$	13,994	$	(1,731	)	$	50,322

Net income	$	20,719	$	849		$	46,720

TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED

LIQUIDITY AND CAPITAL RESOURCES

Net cash provided by operating activities was $10.1 million for the year ended December 31, 2005. Net cash provided by operating activities was $3.5 million for the year ended December 31, 2004. Net cash used in operating activities was $10.5 million for the year ended December 31, 2003. The Company spent $2.3 million, $6.3 million and $1.1 million on investments in property and equipment in 2005, 2004, and 2003, respectively. During 2005, the Company sold its oil and gas interests in PPM and Big Energy generating $10.3 million and $4.0 million, respectively, in proceeds from the sale of discontinued operations. During 2004, the Company sold its oil and gas interests in Milam generating $15.4 million in proceeds from the sale of discontinued operations. During 2003, the Company sold its interest in coal-seam gas production payment properties located in Alabama generating $43 million in cash.

Financing Activities

On September 30, 1996, the Company recorded TAC’s $25.5 million Senior Subordinated Note (the “Note”) payable to Torchmark as part of the purchase price for the Management Buyout. The principal of the Note was due and payable on September 30, 2004, and it accrued interest at 9% per annum. During 2003 and 2002, the Note was reduced by $838,000, and $500,000, respectively, in connection with the settlement of litigation involving the Predecessor, Torchmark, and a third party. On January 1, 2005, the Note was renegotiated resulting in five $500,000 payments for principal and accrued interest due in 2005, $5.0 million due in 2006, $5.0 million due in 2007 and the remaining unpaid balance of principal and interest due on May 1, 2008. As a result of the renegotiation, the Company recognized an $86,000 gain on the forgiveness of debt and a gain of approximately $1.4 million on the forgiveness of accrued interest expense. Interest accrues at the prime rate plus 2% (9.25% at December 31, 2005). As of December 31, 2005, the outstanding balance is $21.2 million, of which $17.9 million has been classified as long-term.

On May 17, 2001, Milam entered into an $18 million Promissory Note with a third party, which increased to $22 million on November 18, 2003. Until the sale of the properties (see Note 10 of the Notes to Consolidated Financial Statements), interest accrued on the indebtedness at the sum of seven percent (7.0%) plus the three month London Inter Bank Offer Rate (“LIBOR”) plus a three percent (3.0%) default rate. Monthly principal and interest payments were due based on cash flows from certain oil and gas properties. In December 2004, proceeds from the sale of the Milam properties were used to pay down the note and the remaining principal balance was forgiven resulting in a gain of $5.6 million for the year ended December 31, 2004. This gain is included in income from discontinued operations for the year ended December 31, 2004.

TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED

In connection with the purchase of certain assets including rigs and real property in January 2002 (see Note 10 of the Notes to Consolidated Financial Statements), the Company entered into a note for $3,175,000 payable to the seller (“Grayson Note”). Principal payments on the note plus interest on the unpaid principal balance are due monthly, and the note matures in February 2007. Interest accrues at the prime rate adjusted at the beginning of each quarter for increases or decreases during the previous quarter (6.75% at December 31, 2005). At December 31, 2005 and 2004, the outstanding principal balance on the Grayson Note is $0.6 million and $1.3 million, respectively, which is included in liabilities of discontinued operations (see Note 3 of the Notes to Consolidated Financial Statements).

In connection with the termination of certain former employees, the Company entered into notes for options previously granted (“Option Notes”). The terms of the notes vary from between 5 and 10 years commencing on the date of termination and interest accrues at the prime rate (7.25% at December 31, 2005). At December 31, 2005 and 2004, the outstanding principal balance on the Option Notes is $1.3 million and $1.6 million, respectively.

On February 6, 2004, Big Energy entered into a $50 million credit facility (the “Big Energy Facility”) with a bank. Interest accrues on indebtedness at the bank’s prime rate plus .5%, but in no event less than a per annum rate of 4.5%. The Big Energy oil and gas properties secured the Big Energy Facility. In September 2005, proceeds from the sale of the Big Energy properties were used to pay off the note. At December 31, 2004, the outstanding balance under the Big Energy Facility is included in liabilities of discontinued operations (see Note 3 of the Notes to Consolidated Financial Statements).

The following table lists contractual obligations including obligations related to discontinued operations of the Company by due date or expiration date:


	Payments Due by Period
			Less than						After 5
Contractual Obligations	Total		1 year		1-3 years		4-5 years		years
Long Term Debt	$	23,594	$	4,266	$	18,849	$	479	$	—
Operating Leases		2,315		572		997		626		120

Total Contractual Cash Obligations	$	25,909	$	4,838	$	19,846	$	1,105	$	120

There are no other commercial commitments at December 31, 2005.

TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED

Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk that the value of the contractual portfolio will change, either favorably or unfavorably, in response to changes in prices. The Company’s major market risk is commodity price risk related to natural gas and crude oil price risk management services and its oil and gas production. Historically, market prices for oil and gas production and related financial derivative contracts have been volatile and unpredictable. Pricing volatility is expected to continue.

The Company did not have any open option contracts or other financial derivative contracts at December 31, 2005.

Interest Rate Risk — The Company’s exposure to changes in interest rates primarily results from short-term changes in the prime and LIBOR rates. A 10% increase in the prime and floating LIBOR rates would have the effect of increasing interest costs to the Company by $210,000 per year.

Outlook

The Company’s primary business focus is directed toward making additional investments in proved oil and gas properties and midstream assets. The Company believes that it has now structured its operations to a size that the core business can now sustain and can be used as a platform to seek out new investments.

Consolidated Financial Statements

Torch Energy Advisors Incorporated and Subsidiaries
As of December 31, 2005 and 2004

Torch Energy Advisors Incorporated and Subsidiaries

Consolidated Financial Statements

As of December 31, 2005 and 2004

Contents


Reports of Independent Auditors			1

Audited Financial Statements

Consolidated Balance Sheets			4
Consolidated Statements of Operations			6
Consolidated Statements of Stockholder’s Equity (Deficit)			7
Consolidated Statements of Cash Flows			8
Notes to Consolidated Financial Statements			10

Report of Independent Auditors

The Board of Directors
Torch Energy Advisors Incorporated

We have audited the accompanying consolidated balance sheets of Torch Energy Advisors Incorporated and Subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholder’s equity (deficit), and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the 2004 financial statements of P2 Energy Solutions, Inc., an investment which as discussed in Note 18 to the consolidated financial statements, was accounted for by the equity method of accounting until April 1, 2005. The investment in P2 Energy Solutions, Inc. was $9.4 million as of December 31, 2004, and the equity in its net loss was $2.7 million for the year then ended. The financial statements of P2 Energy Solutions, Inc. for the year ended December 31, 2004 were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the 2004 amounts included for P2 Energy Solutions, Inc., is based solely on the report of the other auditors.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Torch Energy Advisors Incorporated and Subsidiaries at December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3, effective January 1, 2003, the Company changed its method of accounting for Asset Retirement Obligations.

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

Report of Independent Auditors

The Board of Directors
Torch Energy Advisors Incorporated

We have audited the accompanying consolidated statements of operations, stockholder’s deficit, and cash flows of Torch Energy Advisors Incorporated and Subsidiaries (the “Company”) for the year ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of P2 Energy Solutions, Inc. (a corporation in which the Company has a 21.15% interest) have been audited by other auditors whose report has been furnished to us; insofar as our opinion on the consolidated financial statements relates to the amounts included for P2 Energy Solutions, Inc., it is based solely on their report.

We conducted our audit in accordance with auditing standards generally accepted in the 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 and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audit and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated results of Torch Energy Advisors Incorporated and Subsidiaries’ operations and their cash flows for the year ended December 31, 2003, in conformity with accounting principles generally accepted in the United States.

As discussed in Note 2, effective January 1, 2003, the Company changed its method of accounting for Asset Retirement Obligations.

\s\ Ernst & Young LLP
Houston, Texas
April 9, 2004

Except for discontinued operations as it relates to Milam Energy LP as discussed in Note 3 for the year ended December 31, 2003, as to which the date is April 12, 2005, and except for discontinued operations as it relates to Torch Rig Services, Inc. and PPM Live Oak Energy, LLC as discussed in Note 3 for the year ended December 31, 2003, as to which the date is March 28, 2006

Report of Independent Auditors

The Board of Directors
P2 Energy Solutions, Inc.:

We have audited the accompanying consolidated balance sheets of P2 Energy Solutions, Inc. (a Delaware corporation) and subsidiaries as of September 30, 2004 and 2003, and the related statements of operations, stockholders’ equity and comprehensive loss, and cash flows for each for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 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.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of P2 Energy Solutions, Inc. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years then ended in conformity with accounting principles generally accepted in the United States of America.

\s\ KPMG LLP
Denver, Colorado
April 8, 2005

Torch Energy Advisors Incorporated and Subsidiaries

Consolidated Balance Sheets


	December 31
	2005			2004
	(amounts in thousands except
	share data)
Assets
Current assets:
Cash and cash equivalents	$	19,084		$	8,459
Restricted cash		1,499			173
Accounts receivable — product marketing		871			5,834
Accounts receivable — joint interest billing		527			325
Accounts receivable — oil and gas and other		3,679			381
Prepaid drilling costs		25			242
Other current assets		638			336
Current assets of discontinued operations		5,089			6,592

Total current assets		31,412			22,342

Property and equipment, at cost:
Oil and gas (successful efforts method)		3,165			2,146
Other fixed assets		5,610			4,881

		8,775			7,027

Accumulated depreciation, depletion and amortization		(6,177	)		(5,936	)

		2,598			1,091

Notes receivable — related parties		—			794
Notes receivable		—			122
Investment		9,986			9,359
Marketable securities		1,575			—
Other assets		423			312
Assets of discontinued operations		2,847			8,178

Total assets	$	48,841		$	42,198


	December 31
	2005			2004
	(amounts in thousands except
	share data)
Liabilities and stockholder’s equity (deficit)
Current liabilities:
Accounts payable — product marketing	$	3,622		$	5,500
Accounts payable and accrued liabilities		7,097			10,028
Due to affiliates, net		2,517			1,808
Notes payable — other		568			821
Senior subordinated note payable — affiliate		3,286			1,819
Revenue, royalty, and production taxes payable		3,102			2,909
Current liabilities of discontinued operations		2,462			4,262

Total current liabilities		22,654			27,147

Notes payable — other		1,047			1,331
Senior subordinated note payable — affiliate		17,914			21,267
Other long-term liabilities		198			198
Liabilities of discontinued operations		366			1,843

Commitments and contingencies		—			—

Minority interest		404			1,262

Stockholder’s equity (deficit):
Common stock, par value $1.00, 1,000 shares authorized, issued, and outstanding		1			1
Additional paid-in capital		1,999			1,999
Retained earnings (deficit)		17,443			(2,899	)
Due from stockholder		(11,339	)		(9,951	)
Notes receivable — related party		(984	)		—
Accumulated other comprehensive income		(862	)		—

Total stockholder’s equity (deficit)		6,258			(10,850	)

Total liabilities and stockholder’s equity (deficit)	$	48,841		$	42,198

See accompanying notes.

Torch Energy Advisors Incorporated and Subsidiaries

Consolidated Statements of Operations


	Year ended December 31
	2005			2004			2003
	(amounts in thousands)
Income:
Oil and gas revenues	$	5,483		$	3,171		$	1,011
Product marketing and other trading, net		71			337			301
Gain (loss) from price risk management activities		—			—			(99	)
Service fees		8,841			6,413			7,487
Operating fees		385			378			505
Interest and other income		1,747			1001			3,658
Forgiveness of debt		1,500			—			—
Gain on sale of assets and investments		5,335			10			58,871

		23,362			11,310			71,734

Costs and expenses:
Cost of services		446			467			2,094
Oil and gas operating expenses		838			683			346
Depreciation, depletion, and amortization		504			210			123
Dry hole costs		—			495			459
Plugging and abandonment costs		—			—			15
Provision for impairment of oil & gas properties		—			—			45
Accretion expense		8			70			44
General and administrative expenses		6,713			5,678			11,839
Provision for credit losses (gains)		(987	)		(450	)		23
Interest expense		1,893			2,186			2,958
Other expense		165			998			334

Total costs and expenses		9,580			10,337			18,280

Impairment and equity in earnings (losses) of investees		162			(2,704	)		(3,132	)

Income (loss) from continuing operations before income taxes and cumulative effect of change in accounting principle		13,944			(1,731	)		50,322
Income tax benefit (provision)		(105	)		1			(13	)

Income (loss) from continuing operations		13,839			(1,730	)		50,309
Income (loss) from discontinued operations		6,880			2,579			(3,437	)

Income before cumulative effect of change in accounting principle		20,719			849			46,872
Cumulative effect of change in accounting principle		—			—			152

Net income	$	20,719		$	849		$	46,720

See accompanying notes.

Torch Energy Advisors Incorporated and Subsidiaries

Consolidated Statements of Stockholder’s Equity (Deficit)

For the Years Ended December 31, 2005, 2004, and 2003

(amounts in thousands)


							Accumulated									Notes			Total
					Additional		Other			Retained						Receivable —			Stockholder’s
	Common Stock				Paid-In		Comprehensive			Earnings			Due From			Related			(Deficit)
	Shares		Amount		Capital		Income, Net			(Deficit)			Stockholder			Party			Equity

Balance, December 31, 2002		1	$	1	$	1,999	$	553		$	(42,458	)	$	(8,463	)	$	—		$	(48,368	)
Dividends paid		—		—		—		—			(7,817	)		—			—			(7,817	)
Advances to stockholder		—		—		—		—			—			(1,272	)		—			(1,272	)
Comprehensive income:
Unrealized loss in value of investment in equity securities		—		—		—		(553	)		—			—			—			(553	)
Net income		—		—		—		—			46,720			—			—			46,720

Total comprehensive income																				46,167

Balance, December 31, 2003		1		1		1,999		—			(3,555	)		(9,735	)		—			(11,290	)
Dividends paid		—		—		—		—			(193	)		—			—			(193	)
Advances to stockholder		—		—		—		—			—			(216	)		—			(216	)
Net income		—		—		—		—			849			—			—			849

Balance, December 31, 2004		1		1		1,999		—			(2,899	)		(9,951	)		—			(10,850	)
Dividends paid		—		—		—		—			(377	)		—			—			(377	)
Advances to stockholder		—		—		—		—			—			(1,388	)		—			(1,388	)
Notes receivable — related party		—		—		—		—			—			—			(984	)		(984	)
Comprehensive income:
Unrealized loss in value of investment in equity securities		—		—		—		(862	)		—			—			—			(862	)
Net income		—		—		—		—			20,719			—			—			20,719

Total comprehensive income																				19,857

Balance, December 31, 2005		1	$	1	$	1,999	$	(862	)	$	17,443		$	(11,339	)	$	(984	)	$	6,258

See accompanying notes.

Torch Energy Advisors Incorporated and Subsidiaries

Consolidated Statements of Cash Flows


	Year ended December 31
	2005			2004			2003
	(amounts in thousands)
Cash flows from operating activities
Net income	$	20,719		$	849		$	46,720
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization		1,303			2,322			2,188
Impairment and equity losses (earnings) in investees		(162	)		2,704			3,132
Provision for impairment of oil & gas properties		—			—			45
Accretion expense		28			428			276
Minority interest		4,504			563			—
Provision for credit losses (gains)		(707	)		(450	)		398
Price risk management activities		—			182			(659	)
Gain on sale of assets and investments		(16,300	)		(4,381	)		(58,871	)
Cumulative effect of change in accounting principle		—			—			152
Other		—			60			(2,314	)
Noncash assumption of debt		—			—			1,756
Noncash forgiveness of debt		(1,500	)		—			(400	)
Changes in operating assets and liabilities, net of effects of acquisitions accounted for under the purchase method of accounting:
Accounts receivable		477			507			2,156
Due from/to affiliates		706			(313	)		(547	)
Other current assets		421			2,397			(2,021	)
Accounts payable and accrued liabilities		57			(766	)		(1,653	)
Revenue, royalty, and production taxes payable		193			281			968
Other		379			(921	)		(1,829	)

Net cash provided by (used in) operating activities		10,118			3,462			(10,503	)

See accompanying notes.

Torch Energy Advisors Incorporated and Subsidiaries

Consolidated Statements of Cash Flows (continued)


	Year ended December 31
	2005			2004			2003
	(amounts in thousands)
Cash flows from investing activities
Restricted cash		(886	)	$	(86	)		(744	)
Notes receivable		122			(45	)		1,840
Proceeds from the sale of assets		17,356			16,750			45,493
Investment in property and equipment		(2,272	)		(6,349	)		(1,083	)
Additions to investment		(445	)		—			—
Marketable securities investment		(2,437	)		—			—
Purchase price adjustments on PPM Live Oak Energy LLC		—			197			—

Net cash provided by investing activities		11,438			10,467			45,506

Cash flows from financing activities
Proceeds from line of credit with bank	$	—		$	1,000		$	—
Proceeds from note payable		1,702			2,354			1,976
Repayment of senior subordinated note payable- affiliate		—			—			(338	)
Repayment of note payable to bank		(835	)		(165	)		(18,740	)
Repayment of note payable		(4,681	)		(16,483	)		(4,081	)
Contributions from minority interests		—			129			—
Distributions to minority interests		(5,352	)		(65	)		—
Payment of dividend		(377	)		(193	)		(7,817	)
Advances to stockholder, net		(1,388	)		(216	)		(1,272	)

Net cash used in financing activities		(10,931	)		(13,639	)		(30,272	)


Net increase in cash and cash equivalents		10,625			290			4,731
Cash and cash equivalents at beginning of year		8,459			8,169			3,438


Cash and cash equivalents at end of year	$	19,084		$	8,459		$	8,169


Supplemental disclosures of cash flow information
Cash paid during the year for:
Interest	$	869		$	3,341		$	5,563

Income taxes	$	105		$	3		$	14

See accompanying notes.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements

December 31, 2005

1. Organization

Torch Energy Advisors Incorporated and its Subsidiaries (collectively, “TEAI” or the “Company”), receives revenue from services provided to energy companies, principally drilling, and interests it holds in oil and gas properties. Operations for the Company are headquartered in Houston, Texas, with an operational district office in California.

Until September 1996, TEAI (the “Predecessor” when discussing periods prior to September 30, 1996) operated as a single business segment and was a wholly owned subsidiary of Torchmark, an insurance and financial services holding company headquartered in Birmingham, Alabama. On September 30, 1996, certain members of the Predecessor’s executive management, through the formation of Management Holding Company (“MHC”) and Torch Acquisition Company (“TAC”), purchased TEAI from Torchmark (the “Management Buyout”) (see Note 9). Torchmark retained a warrant for 10% of TAC’s common stock on a fully diluted basis. The Management Buyout was recorded using the purchase method of accounting as TEAI’s executive management had no ownership in the Predecessor. During 1997, MHC was merged into TAC.

2. Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of TEAI, including all wholly-owned and majority-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.

Significant Subsidiaries

Permian Basin Well Services, L.P. (“Permian Basin”), a wholly-owned subsidiary, was formed on April 4, 2005 for the purpose of providing drilling rig crew services and land based workover rigs to third parties. Activities for Permian Basin are consolidated in the Company’s financial statements.

In February 2004, the Company formed Big Energy, LLC (“Big Energy”), for the purpose of owning and investing in oil and gas properties. Torch E&P Company, a wholly-owned subsidiary of the Company, owned 71.25% of Big Energy. In August 2005, an overriding

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements(continued)

2. Summary of Significant Accounting Policies (continued)

royalty interest was sold to Search Drilling Company, a wholly-owned subsidiary. In September 2005, all remaining properties owned by Big Energy were sold to a third party. The results of Big Energy are classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation (see Note 3).

On December 2, 2003, the Company formed PPM Live Oak Energy, LLC (“PPM”), for the purpose of owning and investing in oil and gas properties. PPM also owned a compression facility serving the properties. Torch E&P Company owned 75% of PPM in 2003 and 62.5% of PPM in 2004. In July 2005, all properties owned by PPM were sold to third parties. The results of PPM are classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation (see Note 3).

Effective April 2001, the Company formed Milam Energy L.P. (“Milam”), for the purpose of acquiring and developing oil and gas properties. Milam Energy GP, L.L.C., served as the sole general partner (0.1%) and TEAI served as the sole limited partner (99.9%). By December 2004, all properties owned by Milam were sold to third parties. The results of Milam are classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation (see Note 3).

Effective February 29, 2000, the Company formed Torch Energy TM, Inc. (“TETM”), to conduct energy product marketing activities. Activities for TETM are consolidated in the Company’s financial statements.

Torch Rig Services, Inc. (“TRS”), a wholly-owned subsidiary, was formed on June 11, 1999 for the purpose of providing drilling rig crew services and land based workover rigs to third parties. On March 30, 2006, the Company closed on the sale of all remaining property to a third party (see Note 10). As a result, the results of TRS are classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation (see Note 3).

Torch Energy Finance Fund LPI (“TEFF”), a Texas limited liability partnership, was formed on September 6, 1995. The partnership agreement was amended on July 14, 1997 for the purpose of allowing TEFF to provide growth capital through loans and equity investments to small and mid-size oil and gas companies for use in acquisition and exploitation opportunities. Torch Energy Finance Company (“TEFC”), a wholly-owned

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

subsidiary, served as the sole general partner (10%) and the Company served as the sole limited partner (90%). Activities for TEFF are consolidated in the Company’s financial statements. Investments of TEFF were carried under the equity method. In December 2003, TEFC and the Company sold TEFF to a third party.

Investees

Novistar Inc. (“Novistar”) was formed on April 24, 1998 and commenced operations, effective January 1, 1999, upon the contribution by the Company of all assets and liabilities related to the operations of Novistar, consisting primarily of software and computer equipment. Novistar provides business process services including transaction processing, information management, and process reengineering in three principal areas: oil and gas property administration, information technology, and procurement and inventory management. On February 18, 2000, Novistar acquired from Oracle Corporation (“Oracle”) the Oracle Energy Upstream business, which specializes in licensing, support, and implementation of application software, including related consulting services. As part of the purchase price, Oracle received a 21.12% interest in Novistar (see Note 10). In February 2001, Novistar purchased software from Accenture in exchange for a 1.7% interest in Novistar.

On December 31, 2002, TEAI formed a 100% owned subsidiary which purchased all of the outstanding shares of Novistar. The subsidiary merged with Novistar (“New Novistar”) and eliminated all historic shareholders of Novistar. On December 31, 2002, New Novistar merged with Paradigm Technologies, a Petroleum Place company, that provides software solution and technology services for the energy industry, to create P2 Energy Solutions (“P2ES”). As a result of the merger, the Company received a 40% interest in P2ES, resulting in the Company changing the accounting method for its investment to the equity method. On December 19, 2003, P2ES merged with a third party, resulting in a decrease in the Company’s interest in P2ES to 21.15%. The Company’s Statement of Operations for the years ended December 31, 2004 and 2003 reflects the equity method for P2ES. In December 2004, P2ES was contributed to Tristone Energy Services, Inc. (“Tristone”) and as a minority shareholder of P2ES on April 19, 2005, the Company exchanged its shares of stock in P2ES for shares in Tristone. In addition, Torch exercised its option to purchase its pro rata share of common stock that Tristone acquired from certain third parties. The Company received 9,196 shares of Tristone common stock for $445,000. At December 31, 2005, the Company has 183,910 shares of Tristone common stock, a 4.86% interest on a fully-diluted basis, resulting in the Company

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

changing the accounting method for its investment to the cost method. The Company’s Statement of Operations for the year ended December 31, 2005 reflects equity in earnings calculated under the equity method for P2ES for January through March. The Company’s Balance Sheet at December 31, 2005 reflects an investment at cost in Tristone of approximately $10.0 million.

Cash and Cash Equivalents

Cash in excess of the Company’s daily requirements is generally invested in short-term, highly liquid investments with original maturities of three months or less. Such investments are carried at cost, which approximates fair value and, for purposes of reporting cash flows, are considered to be cash equivalents.

The Company maintains its cash in bank deposits with various major financial institutions. These accounts, at times, exceed federally insured limits. Deposits in the United States are guaranteed by the Federal Deposit Insurance Corporation up to $100,000. The Company monitors the financial condition of the financial institutions and has not experienced any losses on such accounts.

Restricted Cash

The Company had a restricted cash account, which was required by Milam’s May 17, 2001 promissory note with a third party (see Note 12). The balance in the restricted cash account at December 31, 2005 is $300,000. The balance in the restricted cash account which is classified as current assets of discontinued operations (see Note 3) at December 31, 2004 is $690,000.

The Company has a restricted cash account, which is required by PPM’s July 7, 2005 Escrow Agreements which are required by PPM’s July 7, 2005 Agreement of Sale and Purchase (see Note 10). The balance in the restricted cash account for the Escrow Agreements at December 31, 2005 is $1,250,000 of which $250,000 is classified as current assets of discontinued operations (see Note 3).

The Company collateralizes any open letters of credit with cash (see Note 13). As of December 31, 2005 and 2004, the Company has outstanding open letters of credit collateralized by cash for $199,000 and $173,000, respectively.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Allowance for Doubtful Accounts

The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectibility. The Company accrues a reserve on a receivable when, based on the judgement of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2005 and 2004, the Company had an allowance for doubtful accounts of $0.6 million and $3.0 million, respectively.

Prepaid Drilling Costs

At December 31, 2005, prepaid drilling costs mainly consist of a cash call for the Company’s interest in an exploratory well. At December 31, 2004, prepaid drilling costs mainly consisted of cash calls for the Company’s interest in a different exploratory well. These costs were re-classified to other long-term assets during 2005 as the well was shut-in pending a determination as to whether to re-complete the well.

Marketable Securities

Marketable securities are classified in three categories: trading, available-for-sale, or held-to-maturity. Trading securities are bought and held principally for the purpose of selling such securities in the near term. Held-to-maturity securities are those securities in which the Company has the ability and intent to hold the security until maturity. All other securities not included in trading or held-to-maturity are classified as available-for-sale.

The Company has no held-to-maturity or trading securities at December 31, 2005. The Company has available-for-sale securities which are recorded at fair value, with unrealized gains and losses excluded from earnings, and reported as accumulated comprehensive income, a separate component of stockholder’s equity.

Dividend and interest income are recognized when earned. Realized gains and losses for securities classified as available-for-sale are included in earnings and are derived using the specific identification method for determining the cost of securities sold.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Property and Equipment

Oil and gas properties are accounted for on the successful efforts method whereby costs, including lease acquisition and intangible drilling costs associated with exploration efforts which result in the discovery of proved reserves and costs associated with development wells, whether or not productive, are capitalized. Gain or loss is recognized when a property is sold or ceases to produce and is abandoned. Capitalized costs of producing oil and gas properties are amortized using the unit-of-production method based on units of proved reserves as estimated by independent petroleum engineers.

The Company recognizes an impairment loss when the carrying amount of a long-lived asset exceeds the sum of the estimated undiscounted future cash flows of the asset. For each long-lived asset determined to be impaired, an impairment loss equal to the difference between the carrying value and the fair value of the depletable unit is recognized. The fair value of the oil and gas properties, on a depletable unit basis, is estimated to be the present value of expected future cash flows computed by applying estimated future oil and gas prices, as determined by management, to estimated future production of oil and gas reserves over the economic lives of the reserves. No impairment was recognized during the years ended December 31, 2005 and 2004. An impairment of approximately $45,000 was recognized for the year ended December 31, 2003.

Costs of acquiring undeveloped oil and gas leases are capitalized and assessed periodically to determine whether an impairment has occurred; appropriate impairments are recorded when necessary. No such allowance was required during the years ended December 31, 2005, 2004, and 2003.

Fixed assets are depreciated on a straight-line basis over their estimated useful lives, which range from three to ten years. Leasehold improvements, which are recorded at cost, are amortized on a straight-line basis over their estimated useful lives or the life of the lease, whichever is shorter.

Revenue Recognition

The Company recognizes revenues related to TRS as services are rendered. Revenues for TRS are classified as discontinued operations for the years ended December 31, 2005, 2004 and 2003 (see Note 3).

The Company recognizes oil and gas revenues from its interests in oil and natural gas producing activities as the hydrocarbons are produced and sold.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Marketing commissions are based on a fixed percentage of the negotiated sales price of crude oil and natural gas and a fixed monthly fee. Marketing commissions are recognized in revenue during the month of crude oil and natural gas production when the services are performed.

Gas Balancing

The Company uses the entitlement method for recording sales of natural gas. Under the entitlement method of accounting, revenue is recorded based on the Company’s net revenue interest in production. Deliveries of natural gas in excess of the Company’s net revenue interest are recorded as liabilities and under-deliveries are recorded as assets.

Production imbalances are recorded at the lower of the sales price in effect at the time of production or the current market value, as allowed contractually. At December 31, 2005, the Company’s payable for gas sales over the Company’s entitled share was approximately $197,000. At December 31, 2004, the Company’s receivable for gas sales under the Company’s entitled share was approximately $3,000.

Accounting for Price Risk Management Activities

The Company periodically enters into certain financial derivative contracts utilized for non-trading purposes to hedge the impact of market price fluctuations on contractual commitments and forecasted transactions related to its oil and gas production. On January 1, 2001, the Company adopted the provisions of Statement of Financial

Accounting Standards No. 133 (“SFAS 133”), Accounting for Derivative Instruments and Hedging Activities, for the accounting of its hedge transactions. SFAS 133 establishes accounting and reporting standards requiring that all derivative instruments be recorded in the Consolidated Balance Sheet as either an asset or liability measured at fair value and requires that the changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

During 2003, the Company entered into certain over-the-counter swap contracts to hedge the cash flow of the forecasted sale of oil and gas production. The Company did not elect to document and designate these as hedges. Thus, the changes in the fair value of these over-the-counter swap contracts are reflected in earnings in the consolidated statements of operations in gain (loss) from price risk management activities for the year ended December 31, 2003.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Concentrations of Credit Risk

Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract. Financial instruments which potentially subject the Company to credit risk consist principally of trade receivables. Customers not meeting the Company’s credit standards are required to provide an acceptable form of payment security. At December 31, 2005 and 2004, trade receivables were predominantly with energy related and energy trading companies in the United States.

Income Taxes

Effective in 1997, TEAI and its subsidiaries elected to be treated as qualified Subchapter S corporations under Section 1361 (b)(3) of the Internal Revenue Code of 1986. The effect of the election is that TAC will file an S corporation tax return that includes TEAI and subsidiaries. Each TAC stockholder is responsible for reporting their share of taxable income or loss and no federal income taxes are recorded by the Company, except for a tax on excess net passive income and certain built-in gains, if applicable.

Reclassifications

Certain reclassifications of prior years amounts have been made to conform with current year presentation.

Use of Estimates

Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities as of the reporting date and the reporting of revenues and expenses during the reporting period to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States. Actual results could differ from those estimates.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Asset Retirement Obligations

The Company adopted SFAS No. 143 “Accounting for Asset Retirement Obligations” on January 1, 2003, which resulted in an increase to net oil and gas properties of $254,000 and additional liabilities related to asset retirement obligations (“ARO”) of $2 million. These amounts reflect the ARO of the Company had the provisions of SFAS No. 143 been applied since inception and resulted in a non-cash cumulative effect decrease to earnings of $152,000. In accordance with the provisions of SFAS No. 143, the Company records an abandonment liability associated with its oil and gas wells and platforms when those assets are placed in service. Under SFAS No. 143, depletion expense is reduced since a discounted ARO is depleted in the property balance rather than the undiscounted value previously depleted under the old rules. The lower depletion expense under SFAS No. 143 is offset, however, by accretion expense, which is recognized over time as the discounted liability is accreted to its expected settlement value.

Inherent in the fair value calculation of ARO are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

The following table is a reconciliation of the asset retirement obligation liability since adoption (in thousands):


Asset retirement obligation upon adoption on January 1, 2003	$	5,759
Liabilities incurred		212
Liabilities settled		—
Accretion expense		276
Revisions in estimated liabilities		—

Asset retirement obligation at December 31, 2003		6,247
Liabilities incurred		97
Liabilities settled		(5,347	)
Accretion expense		428
Revisions in estimated liabilities		233

Asset retirement obligation at December 31, 2004		1,658
Liabilities incurred		68
Liabilities settled		(1,686	)
Accretion expense		28
Revisions in estimated liabilities		—

Asset retirement obligation at December 31, 2005	$	68

Liabilities incurred during 2003 relate to the acquisition of properties by PPM. Liabilities incurred during 2004 relate to the acquisition of properties by Big Energy. Liabilities settled during 2004 relate to the sale of the Milam properties. Liabilities incurred during 2005 relate to the Company receiving a working interest in a gas field that reached payout. Liabilities settled during 2005 relate to the sale of a gas field and the sale of properties by PPM and Big Energy.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

3. Discontinued Operations

In October and December 2004, Milam entered into separate agreements to sell all of its oil and gas properties. In October 2004, Milam sold its interest in a field for $3.6 million, resulting in a loss of approximately $3.1 million. In December 2004, Milam sold its remaining fields for $11.8 million resulting in a gain of approximately $1.8 million. The proceeds from the sale were used to pay down the outstanding debt balance related to these properties and the remaining principal balance was forgiven, resulting in a gain of $5.6 million for the year ended December 31, 2004 (see Note 12). Milam was a component of the Company’s oil and gas property segment, and accordingly its results have been classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation.

In July 2005, all properties owned by PPM were sold to third parties for $10.3 million, resulting in a gain of approximately $9.5 million. PPM was a component of the Company’s oil and gas property segment, and accordingly its results have been classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation.

In August 2005, an overriding royalty interest was sold by Big Energy to Search Drilling Company, a wholly-owned subsidiary, for $500,000 payable out of future production. In September 2005, all remaining properties owned by Big Energy were sold to a third party for $4.0 million, resulting in a gain of approximately $1.0 million. The proceeds from the sale were used to pay off the outstanding debt balance related to these properties (see Note 12). Big Energy was a component of the Company’s oil and gas property segment, and accordingly its results have been classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation.

During 2005, TRS sold three rigs and insurance proceeds for damages were received on two rigs for total proceeds of $630,000, resulting in a gain of $511,000. On March 30, 2006, the Company closed on the sale of all remaining property to a third party for $10.1 million. TRS is a component of the Company’s service activities segment, and accordingly its results have been classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

3. Discontinued Operations (continued)

Comparative balance sheets of the discontinued operations are as follows (in thousands):


	December 31
	2005			2004

Restricted cash	$	250		$	690
Accounts receivable — oil and gas and other		4,446			4,938
Other current assets		393			964

Total current assets		5,089			6,592
Land		70			70
Oil and gas (successful efforts method)		—			4,433
Other fixed assets		5,858			6,211
Accumulated depreciation, depletion and amortization		(3,698	)		(3,667	)
Other assets		617			1,131

Total assets	$	7,936		$	14,770

Accounts payable and accrued liabilities	$	2,050		$	2,763
Due to affiliates, net		—			3
Notes payable to bank		—			180
Notes payable — other		412			1,316

Total current liabilities		2,462			4,262
Notes payable — other		366			1,334
Other liabilities		—			509

Total liabilities	$	2,828		$	6,105

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

3. Discontinued Operations (continued)

Operating results of discontinued operations are as follows (in thousands):


	Year Ended December 31
	2005		2004			2003

Oil and gas revenues	$	3,048	$	9,410		$	8,658
Gas plant fees		926		1,139			—
Gain (loss) from price risk management activities		—		—			(1,161	)
Service fees		13,135		14,004			13,789
Interest and other income		177		18			15
Gain (loss) on sale of assets		10,824		(1,210	)		—
Cost of services		11,711		13,036			13,843
Oil and gas operating expenses		1,641		3,816			4,282
Depreciation, depletion and amortization		798		2,112			2,065
Dry hole costs		—		2,196			—
Accretion expense		20		358			232
General and administrative expense		2,361		1,913			1,536
Provision for credit losses (gains)		281		—			375
Interest expense		55		2,368			2,405
Minority interest		4,504		563			—
Gain on forgiveness of debt		141		5,580			—

Income (loss) from discontinued operations	$	6,880	$	2,579		$	(3,437	)

4. Related Party Transactions

Due From Stockholder

The Company has advanced approximately $11.3 million to TAC ($1.4 million in 2005, $0.2 million in 2004 and $1.3 million in 2003), which was used to repurchase common stock awarded to former shareholders and a director. The related amount due from stockholder is reflected as a contra-equity account in the accompanying Consolidated Financial Statements.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

4. Related Party Transactions (continued)

Notes Receivable

On January 1, 2000, the Company was issued a promissory note from one of the Company’s officers for $1.42 million. This note bears interest at 8% and has principal and interest payments due annually through December 31, 2005. Since payment was not received at December 31, 2005, the note balance of $794,000, and the related accrued interest, was reclassified from a long-term note receivable to a contra-equity account.

Asset Management

In the ordinary course of business, the Company incurs amounts resulting from the payment of costs and expenses on behalf of related parties and from charging management fees under the terms of the respective management and administrative agreements. Such amounts are settled on a regular basis, generally monthly.

Due to affiliates, net

In the ordinary course of business, the Company incurs expenses and receives revenues on behalf of related parties. The majority of the payable at December 31, 2005 and 2004 relates to the Company’s role as sponsor and operator of certain properties in which the Torch Energy Royalty Trust (the “Trust”) owns a net profits interest (see Note 11). Such amounts are settled on a regular basis, generally quarterly.

Well Operations

The Company operates properties in which related parties have an ownership interest. These related parties are charged for all customary expenses and cost reimbursements associated with such activities on the same basis as third parties. Operators’ fees charged to affiliates by the Company for the years ended December 31, 2005, 2004, and 2003 for these activities were approximately $385,000, $378,000, and $380,000, respectively.

5. Investments

In September 1999, the Company received 800,000 common shares of Carpatsky Petroleum, Inc. (“Carpatsky”), a Canadian publicly traded company, valued at $0.1 million, for operational technical services provided by the Company. In October 1999, the Company received 6,597,720 Carpatsky shares valued at $0.9 million and a warrant to acquire an additional 6,207,808 shares in full satisfaction of a $0.7 million note and

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

5. Investments (continued)

related interest due from Carpatsky. During 2000, the Company recognized an impairment loss on its entire investment in Carpatsky, as it was determined that the carrying value exceeded the fair value of the investment. In April 2005, the Company sold its Carpatsky shares and immediately purchased one share of Cardinal Resources PLC (“CDL”), an independent oil and gas exploration and production company operating in the Ukraine and publicly traded on the Alternate Investment Market of the London Stock Exchange, for every two Carpatsky shares previously owned. As a result, the Company recognized a $2.4 million gain upon the sale of Carpatsky shares. At December 31, 2005, the Company recorded a $.9 million unrealized loss based on the difference between cost and market value in its investment in CDL, resulting in a carrying value of approximately $1.6 million.

In October 2002, the Company received 58,231 shares of Resources Connection, Inc. (“RCI”); a Delaware incorporated publicly traded company, valued at $798,000, as proceeds for the sale of TPC. In December 2003, the Company sold the 58,231 RCI shares for $1,609,000, resulting in a gain of $811,000.

6. Fixed Assets

Fixed assets consist of the following as of December 31 (in thousands):


	2005			2004

Computer hardware, software, and office equipment	$	4,102		$	4,006
Rigs and related equipment		399			—
Furniture, fixtures, leasehold improvements, art, rental equipment, and vehicles		1,109			875

		5,610			4,881
Less accumulated depreciation		(4,734	)		(4,546	)

	$	876		$	335

Depreciation expense for the years ended December 31, 2005, 2004, and 2003 amounted to $109,000, $74,000, and $101,000, respectively.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

7. Other Assets

The components of other assets are as follows (in thousands) as of December 31:


	2005		2004

Prepaid drilling costs	$	235	$	—
Interest on long-term note receivable		—		127
Life insurance cash value		110		87
Other		78		98

	$	423	$	312

8. Benefit Plans

Effective January 1, 1996, the Company established a 401(k) retirement plan. The 401(k) retirement plan is funded by employee and Company contributions. Employees may contribute up to 15% of their salaries and the Company matches 50% of employee contributions up to 6%. The Company’s contributions to this plan totaled approximately $7,000, $25,000, and $47,000 for the years ended December 31, 2005, 2004, and 2003, respectively. In addition, the Company established a discretionary 401(k) retirement plan. During the first quarter of the year, the Company has the option of contributing up to an additional 3% of each employee’s salary for the previous year to the plan. The Company made no contributions to the discretionary plan in 2005, 2004 and 2003.

9. Management Buyout

On September 30, 1996, the Management Buyout occurred whereby certain members of the Company’s executive management purchased the Company from Torchmark for $41 million; $25.5 million in the form of a senior subordinated note payable (see Note 12) and $15.5 million in cash. As a result of this transaction, the Company received working and other interests in oil and gas properties. In addition, the Company received interests in certain oil and gas properties in exchange for consideration of up to $7 million, which is payable solely out of production and is contingent upon the properties achieving pricing and profitability thresholds. Based upon the performance of the properties, none of these thresholds were achieved, and no such liability was recorded at December 31, 2005 and 2004.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

10. Acquisitions and Dispositions of Assets

Milam

In October and December 2004, Milam entered into separate agreements to sell all of its oil and gas properties. In October 2004, Milam sold its interest in a field for $3.6 million, resulting in a loss of approximately $3.1 million. In December 2004, Milam sold its remaining fields for $11.8 million resulting in a gain of approximately $1.8 million. The proceeds from the sale were used to pay down the outstanding debt balance related to these properties and the remaining principal balance was forgiven resulting in a gain of $5.6 million (see Note 12). The results of Milam are classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation (see Note 3).

Big Energy, LLC

In February 2004, Big Energy purchased an interest in certain oil and gas properties located in Louisiana from a third party for $2.1 million. In August 2005, an overriding royalty interest was sold to Search Drilling Company, a wholly-owned subsidiary, for $500,000 payable out of future production. In September 2005, all remaining properties owned by Big Energy were sold to a third party for $4.0 million, resulting in a gain of approximately $1.0 million. The proceeds from the sale were used to pay off the outstanding debt balance related to these properties (see Note 12). The results of Big Energy are classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation (see Note 3).

Person Panna Maria, LLC

In June 2003, the Company purchased a 4% interest in the oil and gas interests in PPM for $80,000 which currently owns a compression facility serving the properties. In December 2003, the Company purchased an additional 80% interest in PPM for $270,000. In January 2004, the Company purchased an additional 4.5% interest in PPM for $15,000. In July 2005, all properties owned by PPM were sold to third parties for $10.3 million, resulting in a gain of approximately $9.5 million. The results of PPM are classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation (see Note 3).

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

10. Acquisitions and Dispositions of Assets (continued)

Coal Bed Methane Field

In January 2003, the Company sold its oil and gas interest in a coal bed methane field in Alabama for $43 million in cash, resulting in a gain of approximately $41 million. Proceeds of $18.7 million were used to payoff the outstanding balance on the Credit Facility (see Note 12). In addition, due to the sale of this field, the Senior Subordinated Note was reduced by $500,000.

Gas Field

In February 2005, the Company sold its interest in a gas field located in the Gulf of Mexico to a third party. The purchaser assumed a $1.1 million plugging and abandonment liability that was included in current liabilities at December 31, 2004. As a result of this sale, the Company recognized a gain of $1.1 million and retained a 3.33% overriding royalty interest in the property.

Art

During the year ended December 31, 2005, the Company purchased one piece of art for $100,000. During the year ended December 31, 2004, the Company purchased two pieces of art for approximately $238,000. During the year ended December 31, 2003, the Company sold pieces of art to third parties for a total of $1,057,000, generating a gain of $68,000.

RCI Shares

In December 2003, the Company sold 58,231 shares of RCI for $1,609,000, resulting in a gain of $811,000.

TEFF

In December 2003, TEFC and the Company sold TEFF to a third party for $325,000, plus the assumption of a credit facility with a bank, resulting in a gain of $17,487,000.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

10. Acquisitions and Dispositions of Assets (continued)

Torch Rig Services

During 2005, TRS sold three rigs and insurance proceeds for damages were received on two rigs for total proceeds of $630,000, resulting in a gain of $511,000. In addition, two rigs were sold to Permian Basin. Since both TRS and Permian Basin are wholly-owned subsidiaries, no gain or loss was recognized on the sale. On March 30, 2006, the Company closed on the sale of all remaining property to a third party for $10.1 million. As a result, the results of TRS are classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation (see Note 3).

Novistar and P2ES

On December 31, 2002, TEAI formed a 100% owned subsidiary which purchased all of the outstanding Novistar stock for $.01 per share. The subsidiary merged with Novistar (“New Novistar”) resulting in the acquisition of the interests of all historic shareholders of Novistar. Petroleum Place, Inc. loaned $3.2 million to New Novistar. New Novistar used the $3.2 million loan proceeds to buy-out Oracle’s debt of $10 million and interest payable of $1.1 million, resulting in an extraordinary gain of $7.9 million for the year ended December 31, 2002. The Company then forgave $23.5 million of debt with New Novistar as uncollectible and contributed the remaining $17 million of debt into New Novistar’s capital as equity. New Novistar then merged with Paradigm Technologies to create P2ES. As a result of the merger, the Company received a 40% interest in P2ES. On December 20, 2003, P2ES merged with a third party, resulting in a decrease in the Company’s interest in P2ES to 21.15%. In December 2004, P2ES was contributed to Tristone. On April 19, 2005 the Company exchanged its share of stock in P2ES for shares in Tristone. In addition, Torch exercised its option to purchase its pro rata share of common stock that Tristone acquired from certain third parties. At December 31, 2005, the Company’s fully diluted interest in Tristone is 4.86%.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

11. Torch Energy Royalty Trust

The Company serves as sponsor and operator of certain properties in which the Trust owns a net profits interest. In connection with the formation of the Trust, the Company entered into an oil and gas purchase contract (“Purchase Contract”) which expires on the termination date of the Trust, the earliest of which is March 1, 2007. The Trust will terminate upon the first to occur of: (a) an affirmative vote of the holders of not less than 66-2/3% of the outstanding units to liquidate the Trust; (b) 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; (c) 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 the estimated pre-tax future net cash flows, discounted at 10%, of proved reserves attributable to the net profits interest is equal to or less than $25.0 million; or (d) December 31, 2012. Under the Purchase Contract, the Company is obligated to purchase all net production attributable to the Trust properties for indexed prices for oil and gas. Such prices are calculated monthly and are generally based on the average spot market prices of oil and gas. The Purchase Contract also provides that the minimum price paid by the Company for gas production is $1.70 per MMBtu, adjusted annually for inflation (“Minimum Price”). When the Company 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 $2.10 per MMBtu, adjusted annually for inflation, the Company is entitled to deduct 50% of such excess (“Price Differential”) in determining the purchase price. The Company has an annual option to discontinue the Minimum Price commitment. However, if the Company 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. The Company has not exercised its option to discontinue the Minimum Price commitment. The Minimum Price and sharing price in 2005, adjusted for inflation, was $1.77 and $2.18, respectively. Total revenue recognized by the Company for the years ended December 31, 2005, 2004 and 2003 was $7.4 million, $5.6 million, and $4.4 million, respectively.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

11. Torch Energy Royalty Trust (continued)

Under the terms of the purchase contract defined above during the year ended December 31, 2005, the Company purchased 4,149 MMCF of gas and 22 Mbbls of oil at an average price of $5.26 per MCF and $48.97 per Bbl. During the year ended December 31, 2004, the Company purchased 4,542 MMCF of gas and 26 Mbbls of oil at an average price of $4.13 per MCF and $34.38 per Bbl. During the year ended December 31, 2003, the Company purchased 4,698 MMCF of gas and 24 Mbbls of oil at an average price of $3.78 per MCF and $24.94 per Bbl.

In December 2003, the Company purchased a contract which expired in December 2004 to limit its exposure in 2004 to losses under the Minimum Price obligation of the Purchase Contract. A loss of approximately $409,000 is included in revenue for the year ended December 31, 2004.

12. Debt

Total debt, including debt related to discontinued operations, at December 31, 2005 and 2004 consists of the following (amounts in thousands):


	2005		2004

Senior subordinated note payable — affiliates	$	21,200	$	23,086
Notes Payable — options		1,292		1,592
Other		1,102		3,390

	$	23,594	$	28,068

Senior Subordinated Note Payable — Affiliate

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

12. Debt (continued)

On January 1, 2005, the Note was renegotiated resulting in five $500,000 payments for principal and accrued interest being made in 2005, $5.0 million due in 2006, and $5.0 million due in 2007 and the remaining unpaid balance of principal and interest due on May 1, 2008. As a result of the renegotiation, the Company recognized an $86,000 gain on the forgiveness of debt and a gain of approximately $1.4 million on the forgiveness of accrued interest expense. Interest accrues at the prime rate plus 2% (9.25% at December 31, 2005). As of December 31, 2005, the outstanding balance is $21.2 million, of which $17.9 million has been classified as long-term.

Promissory Note — Third Party

On May 17, 2001, Milam entered into an $18 million Promissory Note with a third party, which increased to $22 million on November 18, 2003. Until the sale of the properties (see Note 10), interest accrued on the indebtedness at the sum of seven percent (7.0%) plus the three month London Inter Bank Offer Rate (“LIBOR”) plus a three percent (3.0%) default rate. Monthly principal and interest payments were due based on cash flows from certain oil and gas properties. In December 2004, proceeds from the sale of the Milam properties were used to pay down the note and the remaining principal balance was forgiven resulting in a gain of $5.6 million for the year ended December 31, 2004. This gain is included in income from discontinued operations for the year ended December 31, 2004 (see Note 3).

Note Payable — Grayson

In connection with the purchase of certain assets including rigs and real property in January 2002 (see Note 10), the Company entered into a note for $3,175,000 payable to the seller (“Grayson Note”). Principal payments on the note plus interest on the unpaid principal balance are due monthly and the note matures in February 2007. Interest accrues at the prime rate adjusted at the beginning of each quarter for increases or decreases during the previous quarter (6.75% at December 31, 2005). At December 31, 2005 and 2004, the outstanding principal balance on the Grayson Note is $0.6 million and $1.3 million, respectively, which is included in liabilities of discontinued operations (see Note 3).

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

12. Debt (continued)

Notes Payable — Options

Line of Credit

On February 6, 2004, Big Energy entered into a $50 million credit facility (the “Big Energy Facility”) with a bank. Interest accrued on indebtedness at the bank’s prime rate plus .5%, but in no event less than a per annum rate of 4.5%. The Big Energy Facility had a February 26, 2007 maturity date and contained, among other terms, provisions for the maintenance of certain financial ratios and restrictions on additional debt. The Big Energy oil and gas properties secured the Big Energy Facility. In September 2005, proceeds from the sale of the Big Energy properties were used to pay off the Big Energy Facility. At December 31, 2004, the outstanding principal balance on the Big Energy Facility is included in liabilities of discontinued operations (see Note 3).

Scheduled maturities of total debt for the next five years and thereafter as of December 31, 2005 are as follows (in thousands):


2006	$	4,266
2007		3,962
2008		14,888
2009		251
2010 and thereafter		227

	$	23,594

13. Commitments and Contingencies

Litigation

The Company is involved in certain litigation arising out of the normal course of business, none of which, in the opinion of management, will have any material adverse effect on the financial position or results of operations of the Company as a whole.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

13. Commitments and Contingencies (continued)

Lease Obligations

Rental expense for operating leases was approximately $0.5 million, $0.9 million, and $1.5 million for the years ended December 31, 2005, 2004, and 2003, respectively. Future minimum payments under all noncancelable leases, including amounts allocable to affiliates, having initial terms of one year or more consisted of the following as of December 31, 2005 (amounts in thousands):


Year ending December 31,
2006	$	572
2007		549
2008		448
2009		453
2010		173
Thereafter		120

	$	2,315

Letters of Credit

The Company has open letters of credit of approximately $199,000 at December 31, 2005, which are fully collateralized by restricted cash balances.

14. Price Risk Management and Financial Instruments

Non-Trading Activities

The Company enters into financial swap contracts for the purpose of hedging the impact of market fluctuations on production. At December 31, 2003, the Company was party to energy commodity swaps covering 60,000 MMbtus of natural gas and 13,000 barrels of crude oil that extended to May of 2004 on the Milam properties.

While notional amounts are used to express the volume of swaps and over-the-counter options, the amounts potentially subject to credit risk in the event of nonperformance by the third parties are substantially smaller. The Company does not anticipate any material impact to its financial position or results of operations as a result of nonperformance by third parties on financial instruments related to non-trading activities.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

14. Price Risk Management and Financial Instruments (continued)

The carrying amounts of the Company’s cash and cash equivalents, receivables, other current assets, and payables approximate the fair value at December 31, 2005 because of their short-term maturities.

The carrying amounts and estimated fair values of the Company’s other financial instruments, excluding trading activities, at December 31, 2005 and 2004 were as follows:


	2005				2004
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(in thousands)
Liabilities
Current debt	$	3,854	$	3,854	$	2,640	$	2,640
Long-term debt		18,961		18,961		22,598		22,512

The carrying amount of the debt approximates fair value as the interest rates approximate current market rates.

15. Subsequent Events

In January 2006, the Company entered into an agreement that provides royalty relief funds due to the drainage of certain blocks in the State of Louisiana. A third party will collect the funds on behalf of the Company by withholding the specified percentage of royalties due to the United States from payment under all leases in which it is a lessee. The funds will be distributed to the Company within five days of being withheld by the third party. The Company will set-up a long-term asset and recognize other income of approximately $4.3 million for its share of the royalty relief settlement and interest.

On March 30, 2006, the Company closed on the sale of all remaining TRS property to a third party for $10.1 million. As a result, the results of TRS are classified as discontinued operations and the consolidated financial statements for all periods presented have been adjusted to reflect this presentation (see Note 3).

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

16. SFAS 131: Disclosures about Segments of an Enterprise and Related Information

Prior to January 1, 2004, the Company had three reportable segments: service activities, the capital group and oil and gas properties. The service activities segment provided technical and administrative services to energy companies, primarily through outsourcing arrangements. The capital group segment provided growth capital to independent oil and gas companies through TEFF, a fund formed to provide small to mid-size companies with capital for acquisition and exploitation opportunities. The oil and gas properties segment consisted of revenue from interests the Company held in certain oil and gas properties. Due to the sale of TEFF in December 2003 (see Note 2), the Company has two reportable segments in 2004 and 2005: service activities and oil and gas properties.

The Company’s reportable segments are strategic business units that offer different services. Each business segment is managed separately based on the nature of the services provided to clients and based on the different technology and marketing strategies required by each of the segments. The accounting policies of the segments are the same as those described in the summary of significant accounting policies
(see Note 2).

The Company evaluates performance based on profit or loss from operations. Intersegment fees are accounted for as if the fees were to third parties.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

16. SFAS 131: Disclosures about Segments of an Enterprise and Related Information (continued)

The following tables represent reported segment profit or loss and segment assets for the years ended December 31, 2005, 2004, and 2003 (amounts in thousands).


	Service			Oil & Gas
	Activities			Properties		Totals

Year ended December 31, 2005
Revenues from external clients	$	8,766		$	5,483	$	14,249
Intersegment revenues		126			—		126
Gain on sale of gas field		—			1,158		1,158
Interest income		—			120		120
Depletion, depreciation, and amortization		108			396		504
Equity in earnings of investees		162			—		162
Income from discontinued operations		(213	)		7,093		6,880
Segment profit		3,219			12,454		15,673

Other significant items:
Segment assets		18,240			2,335		20,575
Expenditures for segment assets		811			1,133		1,944

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

16. SFAS 131: Disclosures about Segments of an Enterprise and Related Information (continued)


	Service			Oil & Gas
	Activities			Properties		Totals

Year ended December 31, 2004
Revenues from external clients	$	6,506		$	3,171	$	9,677
Intersegment revenues		177			—		177
Interest income		—			45		45
Interest expense		1			—		1
Depletion, depreciation, and amortization		73			137		210
Equity in losses of investee		2,704			—		2,704
Income from discontinued operations		(624	)		3,203		2,579
Segment profit (loss)		(687	)		4,999		4,312

Other significant items:
Segment assets		9,394			1,110		10,504
Equity in investee		9,359			—		9,359
Expenditures for segment assets		15			612		627


	Service			Oil & Gas
	Activities			Properties			Totals

Year ended December 31, 2003
Revenues from external clients	$	7,285		$	1,011		$	8,296
Intersegment revenues		45			—			45
Gain on sale of coal bed methane field		—			40,500			40,500
Interest income		—			157			157
Interest expense		—			21			21
Depletion, depreciation, and amortization		101			22			123
Equity in earnings of investees		(3,132	)		—			(3,132	)
Loss from discontinued operations		(2,936	)		(501	)		(3,437	)
Segment (loss) profit		(6,531	)		39,898			33,367

Other significant items:
Segment assets		12,122			1,016			13,138
Equity in investees		12,063			—			12,063
Expenditures for segment assets		30			239			269

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

16. SFAS 131: Disclosures about Segments of an Enterprise and Related Information (continued)

The following is a reconciliation of reportable segment revenues, expenditures, profit or loss, assets, and equity in investees to the Company’s consolidated totals for the years ended December 31, 2005, 2004, and 2003 (amounts in thousands):


	Year ended December 31
	2005			2004			2003

Revenues:
Total revenues for reportable segments	$	15,654		$	10,069		$	48,997
Other revenues		6,334			1,428			22,805
Elimination of intersegment revenues		(126	)		(187	)		(68	)

Total consolidated revenues	$	21,862		$	11,310		$	71,734


Interest expense:
Total interest expense for reportable segments	$	—		$	1		$	21
Other interest expense		1,893			2,185			2,937

Total interest expense	$	1,893		$	2,186		$	2,958


Depletion, depreciation, and amortization:
Total depletion, depreciation, and amortization for reportable segments	$	504		$	210		$	123

Total depletion, depreciation, and amortization	$	504		$	210		$	123


Equity in earnings (loss) of investees:
Total equity in earnings (loss) of investees for reportable segments	$	162		$	(2,704	)	$	(3,132	)

Total equity in earnings (loss) of investees	$	162		$	(2,704	)	$	(3,132	)


Profit or loss:
Total profit or loss for reportable segments	$	15,673		$	4,312		$	33,367
Other income (loss)		5,046			(3,463	)		13,353

Net income	$	20,719		$	849		$	46,720


Assets:
Total assets for reportable segments	$	20,575		$	10,504		$	13,138
Other assets		28,266			31,694			52,471

Total consolidated assets	$	48,841		$	42,198		$	65,609


Equity in investees:
Total equity in investees for reportable segments	$	—		$	9,359		$	12,063

Consolidated equity in investees	$	—		$	9,359		$	12,063

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

17. Supplementary Oil and Gas Data (Unaudited)

Oil and Gas Producing Activities

Included herein is information with respect to oil and gas acquisition, exploration, development, and production activities, which is based on estimates of year-end oil and gas reserve quantities and estimates of future development costs and production schedules. These reserve quantities represent interests owned by the Company located solely within the United States. At December 31, 2005, reserve quantities and future production are primarily based upon reserve reports prepared by the independent petroleum engineering firm of T.J. Smith & Company, Inc. and by in-house reserve engineers. These estimates are inherently imprecise and subject to revisions from time to time.

Estimates of future net cash flows from proved reserves of gas, oil, condensate, and natural gas liquids (“NGLs”) were made in accordance with Financial Accounting Standards Board Statement No. 69, Disclosures about Oil and Gas Producing Activities. The estimates are based on prices in effect at year-end. Estimated future cash inflows are reduced by estimated future development and production costs based on year-end cost levels, assuming continuation of existing economic conditions. Effective in 1997, the oil and gas activities of the Company fall under its S corporation status for income tax purposes and have a zero effective income tax rate (see Note 2). The results of these disclosures should not be construed to represent the fair market value of the Company’s oil and gas properties. A market value determination would include many additional factors including: (a) anticipated future increases or decreases in oil and gas prices and production and development costs; (b) an allowance for return on investment; (c) the value of additional reserves, not considered proved at the present, which may be recovered as a result of further exploration and development activities; and (d) other business risks.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

17. Supplementary Oil and Gas Data (Unaudited) (continued)

Costs Incurred

The following table sets forth the capitalized costs incurred in oil and gas activities for the years ended December 31 (amounts in thousands):


	2005		2004		2003

Property acquisition	$	813	$	2,203	$	217
Development		699		2,761		985
Asset retirement obligation costs (1)		66		264		466

Costs incurred during the year	$	1,578	$	5,228	$	1,668


(1)		Effective January 1, 2003, the Company adopted SFAS No. 143 “Asset Retirement Obligations.” The asset retirement obligation costs reflect abandonment obligations assumed during the year and related revisions.

Capitalized Costs Relating to Oil and Gas Activities

The following table sets forth the capitalized costs relating to oil and gas activities and the associated accumulated depreciation, depletion, and amortization (amounts in thousands):


				December 31,
	2005			2004			2003

Capitalized costs:
Proved properties	$	3,099		$	5,849		$	30,283
Asset retirement obligation costs (1)		66			730			466
Accumulated depreciation, depletion, and amortization		(1,444	)		(1,693	)		(8,615	)


Net capitalized costs	$	1,721		$	4,886		$	22,134


(1)		Effective January 1, 2003, the Company adopted SFAS No. 143 “Asset Retirement Obligations.”

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

17. Supplementary Oil and Gas Data (Unaudited) (continued)

Results of Operations for Producing Activities


	Year ended December 31,
	2005			2004			2003
	(amounts in thousands)

Revenues from oil and gas producing activities	$	7,678		$	11,574		$	9,152
Loss on price risk management activities		—			—			(1,161	)
Production costs		(2,333	)		(4,313	)		(4,533	)
Depreciation, depletion, and amortization		(667	)		(1,281	)		(951	)
Asset retirement obligation accretion (1)		—			(428	)		(276	)

Results of operations from producing activities (excluding corporate overhead and interest costs)	$	4,678		$	5,552		$	2,231


(1)		Effective January 1, 2003, the Company adopted SFAS No. 143 “Asset Retirement Obligations.”

No income tax provision is recorded for 2005, 2004 or 2003 as the Company has elected subchapter S corporation status.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

17. Supplementary Oil and Gas Data (Unaudited) (continued)

Reserves

The Company’s estimated total proved and proved developed oil and gas reserves for the years ended December 31, 2005, 2004, and 2003 are as follows:


	2005						2004						2003
	Oil			Gas			Oil			Gas			Oil			Gas
	(Mbbl)			(Mmcf)			(Mbbl)			(Mmcf)			(Mbbl)			(Mmcf)

Proved reserves at beginning of year		1,300			13,303			1,573			19,606			1,477			77,125
Purchases of reserves in place		—			—			604			393			429			8,404
Sales of reserves in place		(1,224	)		(10,753	)		(1,065	)		(10,083	)		—			(65,836	)
Revisions of previous estimates		41			(858	)		330			4,378			(173	)		650
Extensions and discoveries		—			—			—			—			—			—
Production		(61	)		(572	)		(142	)		(991	)		(160	)		(737	)

Proved reserves at end of year		56			1,120			1,300			13,303			1,573			19,606
	-

Proved developed reserves:
Beginning of year		801			6,029			659			8,535			172			71,195

End of year		56			1,120			801			6,029			659			8,535

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

17. Supplementary Oil and Gas Data (Unaudited) (continued)

Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows and changes therein related to proved oil and gas reserves are shown below (amounts in thousands):


	Year ended December 31,
	2005			2004			2003

Future cash inflows	$	13,311		$	127,209		$	169,126
Future production costs		(1,698	)		(35,354	)		(61,760	)
Future development costs		(73	)		(11,458	)		(21,895	)

Future net inflows before income tax		11,540			80,397			85,471
Future income taxes		—			—			—

Future net cash flows		11,540			80,397			85,471
10% discount factor		(2,421	)		(31,708	)		(28,860	)

Standardized measure of discounted future net cash flows	$	9,119		$	48,689		$	56,611

No income tax provision is recorded for 2005, 2004, or 2003 as the Company has elected subchapter S corporation status.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

17. Supplementary Oil and Gas Data (Unaudited) (continued)

The following are the principal sources of change in the standardized measure of discounted future net cash flows (amounts in thousands):


	Year ended December 31,
	2005			2004			2003
Standardized measure:
Beginning of year	$	48,689		$	56,611		$	105,866
Sales, net of production costs		(5,344	)		(7,261	)		(3,458	)
Net change in prices and production costs		3,512			18,553			6,112
Changes in estimated future development costs		(344	)		(3,394	)		(247	)
Development costs incurred during the period		699			2,663			985
Revisions of quantity estimates		(2,946	)		19,611			(1,033	)
Accretion of discount		4,869			5,661			10,587
Purchases of reserves in-place		—			7,141			8,889
Sales of reserves in-place		(36,817	)		(42,859	)		(62,729	)
Changes in production rates and other		(3,199	)		(8,037	)		(8,361	)

Standardized measure — end of year	$	9,119		$	48,689		$	56,611

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

18. Investment

In 2004 and 2003, the Company’s 21.15% owned joint venture, P2ES, was accounted for under the equity method of accounting. The investment in P2ES was $9.4 million and $11.8 million at December 31, 2004 and 2003, respectively. Summarized financial information for P2ES, which was audited by other auditors and furnished to the Company, for the years ended September 30, 2004 and 2003 is as follows (in thousands):


	September 30,
	2004		2003

Current assets	$	21,966	$	8,636
Other assets		31,868		16,858

	$	53,834	$	25,494


Current liabilities	$	22,513	$	10,393
Stockholders’ equity		31,321		15,101

	$	53,834	$	25,494


	Year Ended September 30,
	2004			2003

Net sales	$	53,320		$	30,795
Gross profit		15,582			12,559
Net loss		(15,582	)		(16,127	)


	Year Ended December 31,
	2004			2003

Company’s equity loss		(2,704	)		(3,132	)

At December 31, 2004 and 2003, the Company’s investment in P2ES exceeded its equity in its net assets of P2ES at September 30, 2004 and 2003 by approximately $2.7 million and $6.0 million, respectively, due to goodwill and timing differences.

Torch Energy Advisors Incorporated and Subsidiaries

Notes to Consolidated Financial Statements (continued)

18. Investment (continued)

In December 2004, P2ES was contributed to Tristone, and as a minority shareholder of P2ES on April 19, 2005 the Company exchanged its shares of stock in P2ES for shares in Tristone. In addition, Torch exercised its option to purchase its pro rata share of common stock that Tristone acquired from certain third parties. At December 31, 2005, the Company’s fully diluted interest in Tristone is 4.86%, resulting in the Company changing the accounting method for its investment to the cost method. The Company’s Statement of Operations for the year ended December 31, 2005 reflects the equity method for P2ES for January through March. The Company recorded equity in earnings of $162,000 for the three months ended March 31, 2005. The Company’s Consolidated Balance Sheet at December 31, 2005 reflects an investment at cost in Tristone of approximately $10.0 million.

-----END PRIVACY-ENHANCED MESSAGE-----


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

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.*


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


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


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


			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		12
	Item 4.	Submission of Matters to a Vote of Unitholders		12

PART II

	Item 5.	Market for Registrant’s Units and Related Unitholder Matters		13
	Item 6.	Selected Financial Data		13
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		13
	Item 7a.	Quantitative and Qualitative Disclosures About Market Risk		17
	Item 8.	Financial Statements and Supplementary Data		18
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		32
	Item 9A.	Controls and Procedures		32
	Item 9B.	Other Information		32

PART III

	Item 10.	Directors and Executive Officers of the Registrant		33
	Item 11.	Executive Compensation		33
	Item 12.	Security Ownership of Certain Beneficial Owners and Management		33
	Item 13.	Certain Relationships and Related Transactions		35
	Item 14.	Principal Accountant Fees and Services		36

PART IV

	Item 15.	Exhibits and Financial Statement Schedules		37

	—	Signatures		39
Consent of T.J. Smith & Company, Inc.
Netherland, Sewell and Associates, Inc.
Consent of Ryder Scott Company, L.P.
Certification pursuant to Section 302
Certification pursuant to Section 906
Financial Statements of Torch Energy Advisors Incorporated