UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2005

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

For the transition period from                      to                     

Commission File Number: 1-12474

Torch Energy Royalty Trust

(Exact Name of Registrant as Specified in Its Charter)

Delaware		74-6411424
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		Identification Number)

Rodney Square North
1100 North Market Street, Wilmington, Delaware		19890
(Address of Principal Executive Offices)		(Zip Code)

302/636-6016
(Registrant’s telephone number, including area code)

Not Applicable
(Former name, former address and former fiscal year,
if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

    Yes þ       No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).           
Yes o       No þ

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

As of September 30, 2005, 8.6 million Units of Beneficial Interest were outstanding.

 

 

TORCH ENERGY ROYALTY TRUST

PART 1 — FINANCIAL INFORMATION

Item I. Financial Statements

This document includes “forward looking statements” within the meaning of Section 27A of the Securities Act of 1993, as amended, and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts included in this document, including without limitation, statements under “Discussion and Analysis of Financial Condition and Results of Operations” regarding the financial position, reserve quantities and net present values of reserves of the Torch Energy Royalty Trust (“Trust”) and statements that include the words “believe”, “expects”, “anticipates”, “intends”, “estimates”, “projects”, “target”, “goal”, “plans”, “objectives”, “should” or similar expressions or variations are forward-looking statements. Torch Energy Advisors Incorporated (“Torch”) and the Trust can give no assurances that the assumptions upon which these statements are based will prove to be correct. Factors which could cause such forward looking statements not to be correct include, among others, the cautionary statements set forth in the Trust’s Annual Report on Form 10-K\A filed with the Securities Exchange Commission for the most recent fiscal year, cautionary statements contained in this report, the volatility of oil and gas prices, future production costs, future oil and gas production quantities, operating hazards, and environmental conditions.

Introduction

The financial statements included herein have been prepared by Torch, pursuant to an administrative service agreement between Torch and the Trust, pursuant to the rules and regulations of the Securities and Exchange Commission. Wilmington Trust Company serves as the trustee (“Trustee”) of the Trust pursuant to the trust agreement dated October 1, 1993. Certain information and footnote disclosures normally included in the annual financial statements have been omitted pursuant to such rules and regulations, although Torch believes that the disclosures are adequate to make the information presented not misleading. These financial statements should be read in conjunction with the December 31, 2004 financial statements and notes thereto included in the Trust’s annual report on Form 10-K\A for the most recent fiscal year. In the opinion of Torch, all adjustments necessary to present fairly the assets, liabilities and trust corpus of the Trust as of September 30, 2005 and December 31, 2004, the distributable income and changes in trust corpus for the three-month and nine-month periods ended September 30, 2005 and 2004 have been included. All such adjustments are of a normal recurring nature. The distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

The Trust has no officers, directors or employees. The Trustee relies solely on receiving accurate information, reports and other representations from Torch in the

TORCH ENERGY ROYALTY TRUST

ordinary course of its duties as Trustee. In executing and submitting this report on behalf of the Trust and with respect to Bruce L. Bisson in executing the certifications relating to this report, the Trustee and Bruce L. Bisson have relied upon the accuracy of such reports, information and representations of Torch.

TORCH ENERGY ROYALTY TRUST

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

ASSETS

		September 30,				December 31,
		2005				2004
		(Unaudited)
Cash		$	1			$	1
Net profits interests in oil and gas properties (Net of accumulated amortization of $158,495 and $156,800 at September 30, 2005 and December 31, 2004, respectively)			22,105				23,800
		$	22,106			$	23,801

LIABILITIES AND TRUST CORPUS

Trust expense payable		$	212			$	245
Trust corpus			21,894				23,556
		$	22,106			$	23,801

See notes to financial statements.

TORCH ENERGY ROYALTY TRUST

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

(Unaudited)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Net profits income		$	1,482			$	1,622			$	4,429			$	4,797
Infill Well Net Proceeds			22				219				465				219
			1,504				1,841				4,894				5,016
General and administrative expenses			214				271				690				697
Distributable income		$	1,290			$	1,570			$	4,204			$	4,319
Distributable income per Unit (8,600 Units)		$	.15			$	.18			$	.49			$	.50
Distributions per Unit		$	.15			$	.18			$	.49			$	.51

See notes to financial statements.

TORCH ENERGY ROYALTY TRUST

STATEMENTS OF CHANGES IN TRUST CORPUS
(In thousands)

(Unaudited)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Trust corpus, beginning of period		$	22,427			$	24,585			$	23,556			$	26,284
Amortization of Net Profits Interests			(550	)			(792	)			(1,695	)			(2,436	)
Distributable income			1,290				1,570				4,204				4,319
Distributions to Unitholders			(1,273	)			(1,582	)			(4,171	)			(4,386	)
Trust corpus, end of period		$	21,894			$	23,781			$	21,894			$	23,781

See notes to financial statements.

Notes to Financial Statements

1. Trust Organization and Nature of Operations

The Trust was formed effective October 1, 1993 under the Delaware Business Trust Act pursuant to a trust agreement (“Trust Agreement”) among Trustee, Torch Royalty Company (“TRC”), Velasco Gas Company, Ltd. (“Velasco”), and Torch as grantor. TRC and Velasco created net profits interests (“Net Profits Interests”), which burden certain oil and gas properties (“Underlying Properties”), and conveyed such interests to Torch. Torch conveyed the Net Profits Interests to the Trust in exchange for an aggregate of 8,600,000 units of beneficial interest (“Units”). Pursuant to an administrative services agreement with the Trust, Torch provides accounting, bookkeeping, informational and other services related to the Net Profits Interests.

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

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. As of September 30, 2005, the Trust has not terminated, as none of the aforementioned events have occurred. Upon termination of the Trust, the remaining assets of the Trust will be sold and the proceeds therefrom (after expenses) will be distributed to the unitholders (“Unitholders”). The sole purpose of the Trust is to hold the Net Profits Interests, to receive payments from TRC and Velasco, and to make payments to Unitholders. The Trust does not conduct any business activity.

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

Notes to Financial Statements

Profits Interests. The Net Profits Interests (other than the Net Profits Interest covering the Robinson’s Bend Field) entitle the Trust to receive 95% of the net proceeds (“Net Proceeds”) attributable to oil and gas produced and sold from wells (other than infill wells) on the Underlying Properties. Net Proceeds are generally defined as gross revenues received from the sale of production attributable to the Underlying Properties during any period less property, production, severance and similar taxes, and development, operating, and certain other costs. 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 and operating and development costs subsequent to January 1, 2003. Since the fourth quarter of 1995, production from the Underlying Properties in the Robinson’s Bend Field has been less than the Volume Limitation. See Note 2 to the financial statements for an explanation of the Trust’s method of accounting.

The Net Profits Interests also entitle the Trust to 20% of the Infill Well Net Proceeds (as defined herein) 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 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 the publicly announced base rate of Citibank, N.A. in New York.

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.

2. Basis of Accounting

The financial statements of the Trust are prepared on a modified cash basis and are not intended to present the financial position and results of operations in conformity with

Notes to Financial Statements

generally accepted accounting principles (“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 three-month and nine-month periods ended September 30, 2005 and 2004 are derived from oil and gas production sold during the three-month and nine-month periods ended June 30, 2005 and 2004, respectively. General and administrative expenses are recognized on an accrual basis.
-		Amortization of the Net Profits Interests is calculated on a unit-of-production basis and charged directly to trust corpus.
-		Distributions to Unitholders are recorded when declared by the Trustee.
-		An impairment loss is recognized when the net carrying value of the Net Profits Interests exceeds its fair market value. No impairment loss was recognized during the three-month and nine-month periods ended September 30, 2005 and 2004.
-		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.
-		Estimates and assumptions have been made in preparing the financial statements of the Trust in order for the financial statements to be in conformity with accounting principles generally accepted in the United States.

3. Federal Income Taxes

Tax counsel has advised the Trustee that, under current tax law, the Trust is classified as a grantor trust for Federal income tax purposes. 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

Notes to Financial Statements

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 resulting from such payments were allocated to the Unitholders of record on such date.

4. Distributions and Income Computations

Distributions are determined for each quarter and are based on the amount of cash available for distribution to Unitholders. Such amount (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 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 Interests, cash received by the Trust on the last day of the second month of a particular quarter from the Net Profits Interests generally represents proceeds from the sale of oil and 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 Quarterly Distribution Amount is distributed within approximately ten days after the record date to each person who was a Unitholder of record on the associated record date.

5. Related Party Transactions

Marketing Arrangements

TRC and Velasco contracted to sell the oil and gas production from the Underlying Properties to Torch Energy Marketing, Inc. (“TEMI”), a subsidiary of Torch, under a purchase contract (“Purchase Contract”). Under the Purchase Contract, TEMI is obligated to purchase all net production attributable to the Underlying Properties for an index price for oil and gas (“Index Price”), less certain gathering, treating and transportation charges, which are calculated monthly. The Index Price equals 97% of the average spot market prices of oil and gas (“Average Market Prices”) at the four locations where TEMI sells production. The Purchase Contract also provides that the minimum price paid by TEMI for gas production is $1.70 per MMBtu adjusted annually for inflation (“Minimum Price”). When

Notes to Financial Statements

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. No Price Credits were deducted in calculating the purchase price related to distributions received by Unitholders during the three-month and nine-month periods ended September 30, 2005 and 2004. As of September 30, 2005, TEMI had no accumulated Price Credits.

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 calculating the purchase price. As a result of such Sharing Price arrangement, Net Proceeds attributable to the Underlying Properties during the nine months ended September 30, 2005 and 2004 were reduced by $6.2 million and $5.0 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 for Underlying Property production during 2005 and 2004 were $1.77 per MMBtu and $1.73 per MMBtu, respectively. The Sharing Price for Underlying Property production during 2005 and 2004 was $2.18 per MMBtu and $2.13 per MMBtu, respectively.

Gross revenues (before deductions for applicable gathering, treating and transportation charges) from TEMI included in the Net Proceeds calculations attributable to the Underlying Properties during the quarters ended September 30, 2005 and 2004 were $4.6 million per period. Such gross revenues for the nine-month periods ended September 30, 2005 and 2004 were $13.8 million and $13.2 million, respectively.

Gathering, Treating and Transportation Arrangements

The Purchase Contract entitles TEMI to deduct certain gas gathering, treating and transportation costs in calculating the purchase price for gas in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields. The amounts that may be deducted in calculating the purchase price for such gas are set forth in the Purchase Contract and are not affected by the actual costs incurred by TEMI to gather, treat and transport gas. In the Robinson’s Bend Field, TEMI is entitled to deduct a gathering, treating and transportation fee of $0.26 per MMBtu adjusted for inflation ($0.298 and $0.292 per MMBtu for 2005 and 2004 production, respectively), plus fuel usage equal to 5% of revenues pursuant to a gas gathering agreement. Additionally, a fee of $0.05 per MMBtu, representing a gathering fee payable to a non-affiliate of TEMI, is deducted in

Notes to Financial Statements

calculating the purchase price for production from 68 of 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. From the purchase price for gas in the Cotton Valley Fields, TEMI deducts 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 three months ended September 30, 2005 and 2004, such fees deducted from the Net Proceeds calculations, attributable to production during the three-month periods ended June 30, 2005 and 2004, in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $0.4 million and $0.3 million, respectively. During the nine months ended September 30, 2005 and 2004, such fees deducted from the Net Proceeds calculations, attributable to production during the nine-month periods ended June 30, 2005 and 2004, in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $1.1 million and $1.0 million, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase price from the Chalkley Field.

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 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 Statistics. Administrative services during the three-month periods ended September 30, 2005 and 2004 were $100,000 and $98,000, respectively. During the nine-month periods ended September 30, 2005 and 2004, such fees were $300,000 and $294,000 respectively.

Operator Overhead Fees

A subsidiary of Torch operates certain oil and gas interests burdened by the Net Profits Interests. 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 Chalkley, Cotton Valley and Austin Chalk Fields totaled $48,000 and $47,000, respectively, for the three-month periods ended September 30, 2005 and 2004. During the nine-month periods ended September 30, 2005 and 2004, such operator overhead fees were $139,000 during each period.

Notes to Financial Statements

Compensation of the Trustee and Transfer Agent

The Trust Agreement provides that the Trustee is compensated for its administrative services, out of the Trust assets in an annual amount of $41,000, plus an hourly charge for services in excess of a combined total of 250 hours annually at its standard rate. In accordance with provisions in the Trust Agreement, the Trustee may increase its compensation for its administrative services as a result of unusual or extraordinary services rendered by the Trustee. Effective July 1, 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 for inflation 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.

Total administrative and transfer agent fees paid to the Trustee during the three-month periods ended September 30, 2005 and 2004 were $24,000 and $14,000, respectively. Such fees during the nine-month periods ended September 30, 2005 and 2004 were $52,000 and $42,000, respectively. The Trustee is also entitled to reimbursement for out-of-pocket expenses.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Results of Operations

Because a modified cash basis of accounting is utilized by the Trust, Net Proceeds attributable to the Underlying Properties for the three months ended September 30, 2005 and 2004 is derived from actual oil and gas produced during the three months ended June 30, 2005 and 2004, respectively. Net Proceeds attributable to the Underlying Properties for the nine months ended September 30, 2005 and 2004 is derived from oil and gas produced during the nine months ended June 30, 2005 and 2004, respectively. Oil and gas sales attributable to the Underlying Properties for such periods are as follows:

		Three Months Ended September 30,
		2005								2004
		Bbls				Mcf				Bbls				Mcf
		of Oil				of Gas				of Oil				of Gas
Chalkley Field			1,250				310,705				1,627				375,092
Robinson’s Bend Field			—				455,962				—				475,728
Cotton Valley Fields			519				164,928				511				204,789
Austin Chalk Fields			3,784				37,511				3,518				43,427
Total			5,553				969,106				5,656				1,099,036

		Nine Months Ended September 30,
		2005								2004
		Bbls				Mcf				Bbls				Mcf
		of Oil				of Gas				of Oil				of Gas
Chalkley Field			3,957				931,567				5,231				1,164,400
Robinson’s Bend Field			—				1,366,661				—				1,451,687
Cotton Valley Fields			1,569				521,633				1,605				643,118
Austin Chalk Fields			11,698				129,929				11,855				101,874
Total			17,224				2,949,790				18,691				3,361,079

Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004

For the three months ended September 30, 2005, net profits income was $1.5 million, down 6% from net profits income of $1.6 million for the same period in 2004. Such decrease is mainly attributable to normal production declines which were partially offset

by higher oil and gas prices paid to the Trust during the quarter ended September 30, 2005.

Gas production attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin Chalk Fields was 513,144 Mcf and 623,308 Mcf during the quarters ended June 30, 2005 and 2004, respectively. Gas production attributable to the Underlying Properties in the Robinson’s Bend Field was 455,962 Mcf and 475,728 Mcf during the quarters ended June 30, 2005 and 2004, respectively. Gas production decreased during 2005 mainly as a result of normal production declines. Oil production attributable to the Underlying Properties for the quarters ended June 30, 2005 and 2004 was 5,553 Bbls and 5,656 Bbls, respectively.

During the three months ended September 30, 2005, the average price used to calculate Net Proceeds for gas, before gathering, treating and transportation deductions, was $4.32 per MMBtu as compared to $3.89 per MMBtu for the three months ended September 30, 2004. During the quarter ended September 30, 2005, the average price used to calculate Net Proceeds for oil was $45.89 as compared to $31.72 per Bbl for the quarter ended September 30, 2004. When TEMI pays a purchase price for gas based on the Minimum Price ($1.77 per MMBtu and $1.73 per MMBtu for 2005 and 2004 production, respectively), 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. No Price Credits were deducted in calculating the purchase price related to distributions received by Unitholders during the quarters ended September 30, 2005 and 2004. As of September 30, 2005, TEMI had no accumulated Price Credits. Additionally, if the Index Price for gas exceeds the Sharing Price ($2.18 per MMBtu and $2.13 per MMBtu for 2005 and 2004 production, respectively), TEMI is entitled to deduct 50% of such excess in calculating the purchase price. The deduction of the Price Differential in calculating the purchase price had the effect of reducing distributions received by Unitholders during the three-month periods ended September 30, 2005 and 2004 by $2.0 million and $1.9 million, respectively.

During the quarters ended September 30, 2005 and 2004, the Trust distributed approximately $22,000 and $219,000, respectively, of Infill Well Net Proceeds pertaining to oil and gas sales during the quarters ended March 31, 2005 and 2004, respectively. Such Infill Wells are located in the Cotton Valley Fields and are operated by Samson Lone Star Limited Partnership.

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 each of the quarters ended September 30, 2005 and 2004 totaled $0.7 million. With respect to the Robinsons’ Bend Field, lease operating expenses and capital expenditures of $1.5 million were deducted in calculating the Net

Proceeds payable to the Trust from the Robinson’s Bend Field for each of the three-month periods ended September 30, 2005 and 2004, respectively.

General and administrative expenses amounted to $0.2 million and $0.3 million, respectively, for the three-month periods ending September 30, 2005 and 2004. These expenses primarily relate to administrative services provided by Torch and the Trustee.

The foregoing resulted in distributable income of $1.3 million, or $.15 per Unit, for the three months ended September 30, 2005, as compared to $1.6 million, or $.18 per Unit, for the same period in 2004. Cash distributions of $1.3 million, or $0.15 per Unit, were made during the quarter ended September 30, 2005 as compared to $1.6 million, or $0.18 per Unit, for the same period in 2004.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

For the nine months ended September 30, 2005, net profits income was $4.4 million, down 8% from net profits income of $4.8 million for the same period in 2004. Such decrease is mainly attributable to a decrease in gas production as a result of normal production declines which were partially offset by higher oil and gas prices paid to the Trust during the nine months ended September 30, 2005.

Gas production attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin Chalk Fields was 1,583,129 Mcf and 1,909,392 Mcf during the nine months ended June 30, 2005 and 2004, respectively. Gas production attributable to the Underlying Properties in the Robinson’s Bend Field was 1,366,661 Mcf and 1,451,687 Mcf during the nine months ended June 30, 2005 and 2004, respectively. Gas production decreased during 2005 mainly as a result of normal production declines. Oil production attributable to the Underlying Properties for the nine months ended June 30, 2005 and 2004 was 17,224 Bbls and 18,691 Bbls, respectively.

During the nine months ended September 30, 2005, the average price used to calculate Net Proceeds for gas, before gathering, treating and transportation deductions, was $4.22 per MMBtu as compared to $3.63 per MMBtu for the nine months ended September 30, 2004. During the nine months ended September 30, 2005, the average price used to calculate Net Proceeds for oil was $43.62 as compared to $28.66 per Bbl for the nine months ended September 30, 2004. When TEMI pays a purchase price for gas based on the Minimum Price ($1.77 per MMBtu and $1.73 per MMBtu for 2005 and 2004 production, respectively), 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. No Price Credits were deducted in calculating the purchase price related to distributions received by Unitholders during the nine-month periods ended September 30, 2005 and 2004. As of September 30, 2005, TEMI had no accumulated Price

Credits. Additionally, if the Index Price for gas exceeds the Sharing Price ($2.18 per MMBtu and $2.13 per MMBtu for 2005 and 2004 production, respectively), TEMI is entitled to deduct 50% of such excess in calculating the purchase price. The deduction of the Price Differential in calculating the purchase price had the effect of reducing distributions received by Unitholders during the nine months ended September 30, 2005 and 2004 by $6.2 million and $5.0 million, respectively.

During the nine months ended September 30, 2005, the Trust distributed approximately $465,000 of Infill Well Net Proceeds pertaining to oil and gas sales during the nine months ended March 31, 2005. During the nine months ended September 30, 2004, the Trust distributed approximately $219,000 of Infill Well Net Proceeds pertaining to oil and gas sales during the three months ended March 31, 2004. Prior to January 1, 2004, the Trust received no payments with respect to the Infill Wells as a result of the Infill Well’s costs and expenses exceeding the Infill Well’s gross revenues during this period. Such Infill Wells are located in the Cotton Valley Fields and are operated by Samson Lone Star Limited Partnership.

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 nine months ended September 30, 2005 and 2004 totaled $2.3 million and $2.0 million, respectively. With respect to the Robinsons’ Bend Field, lease operating expenses and capital expenditures of $5.3 million and $4.4 million were deducted in calculating the Net Proceeds payable to the Trust from the Robinson’s Bend Field during the nine-month periods ended September 30, 2005 and 2004, respectively. The increase in costs and expenses in 2005 is due to capital expenditures pertaining to certain gas well workovers performed by the operator of the Robinson’s Bend Field, Everlast Energy LLC.

General and administrative expenses amounted to $0.7 million for each period during the nine-month periods ending September 30, 2005 and 2004, respectively. These expenses primarily relate to administrative services provided by Torch and the Trustee.

The foregoing resulted in distributable income of $4.2 million, or $.49 per Unit, for the nine months ended September 30, 2005, as compared to $4.3 million, or $.50 per Unit, for the same period in 2004. Cash distributions of $4.2 million, or $0.49 per Unit, were made during the nine months ended September 30, 2005 as compared to $4.4 million, or $0.51 per Unit, for the same period in 2004.

Net profits income received by the Trust during the three and nine month periods ended September 30, 2005 and 2004, derived from production sold during the three and nine months ended June 30, 2005 and 2004, respectively, was computed as shown in the following table (in thousands):

		Three Months Ended												Three Months Ended
		September 30, 2005												September 30, 2004
		Chalkley,												Chalkley,
		Cotton Valley												Cotton Valley
		and Austin				Robinson’s								and Austin				Robinson’s
		Chalk Fields				Bend Field				Total				Chalk Fields				Bend Field				Total
Oil and gas revenues		$	2,479			$	1,746			$	4,225			$	2,609			$	1,655			$	4,264
Direct operating expenses:
Lease operating expenses and property tax			467				1,437				1,904				465				1,420				1,885
Severance tax			182				152				334				196				139				335
			649				1,589				2,238				661				1,559				2,220
Net proceeds before capital Expenditures			1,830				157				1,987				1,948				96				2,044
Capital expenditures			270				55				325				240				46				286
Net proceeds			1,560				102				1,662				1,708				50				1,758
Net profits percentage			95	%			—				—				95	%			—				—
Net profits income		$	1,482			$	—			$	1,482			$	1,622			$	—			$	1,622

		Nine Months Ended												Nine Months Ended
		September 30, 2005												September 30, 2004
		Chalkley,												Chalkley,
		Cotton Valley												Cotton Valley
		and Austin				Robinson’s								and Austin				Robinson’s
		Chalk Fields				Bend Field				Total				Chalk Fields				Bend Field				Total
Oil and gas revenues		$	7,514			$	5,171			$	12,685			$	7,545			$	4,655			$	12,200
Direct operating expenses:
Lease operating expenses and property tax			1,579				4,425				6,004				1,363				4,271				5,634
Severance tax			546				455				1,001				506				381				887
			2,125				4,880				7,005				1,869				4,652				6,521
Net proceeds before capital expenditures			5,389				291				5,680				5,676				3				5,679
Capital expenditures			727				831				1,558				627				165				792
Net proceeds			4,662				(540	)			4,122				5,049				(162	)			4,887
Net profits percentage			95	%			—				—				95	%			—				—
Net profits income		$	4,429			$	—			$	4,429			$	4,797			$	—			$	4,797

Net Proceeds Attributable to the Robinson’s Bend Field Have Declined Significantly

Prior to December 31, 2002, lease operating expenses and capital expenditures 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 of 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 received no payments with respect to the Robinson’s Bend Field during the nine-month periods ended September 30, 2005 and September 30, 2004 (pertaining to production during the nine-month periods ended June 30, 2005 and June 30, 2004). During the nine-month periods ended September 30, 2005 and September 30, 2004, Robinson’s Bend Field costs and expenses exceeded net revenues by approximately $540,000 and $162,000, respectively. The Trust will receive no payments with respect to the Robinson’s Bend Field until future proceeds exceed the sum of costs and expenses and the cumulative Robinson’s Bend Field costs and expenses including interest (“Robinson’s Bend Field Cumulative Deficit”). As of September 30, 2005 (pertaining to production through June 30, 2005), the Robinson’s Bend Field Cumulative Deficit was approximately $1.0 million. Torch does not anticipate that the Net Proceeds attributable to the Robinson’s Bend Field, if any, will be significant in the future.

Volatility of Oil and Gas Prices

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 weather conditions in the United States, the condition of the United States economy, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East and elsewhere, the risk of war and terrorist actions, the foreign supply of oil and gas, the price of foreign imports and the availability of alternate fuel sources. 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.

Uncertainty of Estimates of Reserves and Future Net Cash Flows

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 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 three-month and nine-month periods ended September 30, 2005 and 2004.

Operating Risks

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, 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.

Competition and Markets

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.

Market prices are typically volatile as a result of uncertainties caused by world events. Demand for natural gas production has historically been seasonal in nature, and prices for gas fluctuate accordingly. Such price fluctuations will directly impact Trust distributions, estimated reserve attributable to the Trust and estimated future net revenues from Trust reserves.

Regulation of 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.

Environmental Regulation

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.

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 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, 2004 was approximately $39.0 million. Such reserve report was prepared pursuant to Securities and Exchange Commission guidelines and utilized an unescalated Purchase Contract price (after gathering, treating and transportation fees) of $4.18 per Mcf. The computation of the $4.18 per Mcf Purchase Contract price was based on an unescalated Henry Hub spot price for natural gas on December 31, 2004 of $6.18 per MMBtu. The December 31, 2004 reserve value was greater than $25.0 million. Therefore, the Trust did not terminate on March 1, 2005. Based on oil and gas reserve estimates at December 31, 2004 prepared by independent reserve engineers, Torch projects that unless the Henry Hub spot price for natural gas on December 31, 2005 exceeds approximately $4.50 per MMBtu, the Trust will terminate on March 1, 2006. 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 price of the Units.

Financial Condition of the Administrative Service Provider to the Trust

Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its subsidiaries is a party to that certain Administrative Services Agreement whereby Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its subsidiaries provides certain administrative and related services to the Trust. See Item 13 – Administrative Services Agreement of the Form 10-K/A for the period ended December 31, 2004. TEMI, a subsidiary of Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its subsidiaries, is a party to the Purchase Contract. If Torch Energy Advisors Incorporated (the administrative service provider of the Trust) 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 3. 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 per MMBtu and $1.73 per MMBtu for 2005 and 2004 production, 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 per MMBtu and $2.13 per MMBtu for 2005 and 2004 production, 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 4. Controls and Procedures

Based on their evaluation as of the end of the period covered by this quarterly report on Form 10-Q, 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 were effective as of the end of the period covered by this quarterly report on Form 10-Q. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by Torch.

There were no significant changes in the Trust’s internal control over financial reporting during the Trust’s last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

          None.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

          None.

ITEM 3. Defaults upon Senior Securities

          None.

ITEM 4. Submission of Matters to a Vote of Unitholders

          None.

ITEM 5. Other Information

          None

ITEM 6. Exhibits

(a) Exhibits

4. Instruments of 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. *
	31.1		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.**
	32.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.**

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: November 10, 2005

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

INDEX TO EXHIBITS

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. *
31.1		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.**
32.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.**