UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-Q

For the quarterly period ended September 30, 2004

OR

For the transition period from                     to                    

Commission File Number: 1-12474

Torch Energy Royalty Trust

302/651-8775
( 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 (X)   No (   )

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes (   )   No (X)

As of September 30, 2004, 8.6 million Units of Beneficial Interest were outstanding.

Table of Contents

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 filed with the Securities Exchange Commission, 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, 2003 financial statements and notes thereto included in the Trust’s annual report on Form 10-K for the year ended December 31, 2003. In the opinion of Torch, all adjustments necessary to present fairly the assets, liabilities and trust corpus of the Trust as of September 30, 2004 and December 31, 2003, the distributable income and changes in trust corpus for the three-month and nine-month periods ended September 30, 2004 and 2003 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

2

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.

3

TORCH ENERGY ROYALTY TRUST

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

See notes to financial statements.

4

TORCH ENERGY ROYALTY TRUST

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

(Unaudited)

See notes to financial statements.

5

TORCH ENERGY ROYALTY TRUST

STATEMENTS OF CHANGES IN TRUST CORPUS
(In thousands)

(Unaudited)

See notes to financial statements.

6

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, 2004, 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

7

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. Commencing with the second quarter 2003 distribution, pertaining to production during the quarter ended March 31, 2003, operating and development costs have been deducted.

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 base rate of interest announced publicly by Citibank, N.A. in New York.

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.

Sales of coal seam and tight sands gas attributable to the Net Profits Interests between November 23, 1993 and January 1, 2003 resulted in the Unitholders receiving quarterly allocations of tax credits under Section 29 of the Internal Revenue Code of 1986 (“Section 29 Credits”). The right to receive the Section 29 Credits expired December 31, 2002.

8

Notes to Financial Statements

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 generally accepted accounting principles (“GAAP”). Preparation of the Trust’s financial statements on such basis includes the following:

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

9

Notes to Financial Statements

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 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

10

Notes to Financial Statements

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 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, 2004 and 2003. As of September 30, 2004, 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, 2004 and 2003 were reduced by $5.0 million and $5.3 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 2004 and 2003 was $1.73 per MMBtu and $1.71 per MMBtu, respectively. The Sharing Price for Underlying Property production during 2004 and 2003 was $2.13 per MMBtu and $2.12 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, 2004 and 2003 were $4.6 million and $4.7 million, respectively. Such gross revenues for the nine-month periods ended September 30, 2004 and 2003 were $13.2 million and $14.1 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

11

Notes to Financial Statements

transportation fee of $0.26 per MMBtu adjusted for inflation ($0.289 per MMBtu for 2004 and 2003 production), 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 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, 2004 and 2003, such fees deducted from the Net Proceeds calculations, attributable to production during each of the three-month periods ended June 30, 2004 and 2003, in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $0.3 million for each period. During the nine months ended September 30, 2004 and 2003, such fees deducted from the Net Proceeds calculations, attributable to production during the nine-month periods ended June 30, 2004 and 2003, in the Robinson’s Bend, Austin Chalk and Cotton Valley Fields, totaled $1.0 million for each period. 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 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, 2004 and 2003 were $98,000 and $97,000, respectively. During the nine-month periods ended September 30, 2004 and 2003, such fees were $294,000 and $291,000, 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. Such operator overhead fees deducted from the Net Proceeds computations for the Chalkley, Cotton Valley and Austin Chalk Fields totaled $94,000 and $91,000 during the three months ended September 30, 2004 and 2003, respectively.

12

Notes to Financial Statements

During the nine-month periods ended September 30, 2004 and 2003, such operator overhead fees were $0.3 million for each period.

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. 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 during the three-month periods ended September 30, 2004 and 2003 were $14,000 per period. Such fees during the nine month periods ending September 30, 2004 and 2003 were $42,000 per period. The Trustee is also entitled to reimbursement for out-of-pocket expenses.

13

Item 2. 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, 2004 and 2003 is derived from actual oil and gas produced during the three months ended June 30, 2004 and 2003, respectively. Net Proceeds attributable to the Underlying Properties for the nine months ended September 30, 2004 and 2003 is derived from oil and gas produced during the nine months ended June 30, 2004 and 2003, respectively. Oil and gas sales attributable to the Underlying Properties for such periods are as follows:

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003

For the three months ended September 30, 2004, net profits income was $1.6 million, down 24% from net profits income of $2.1 million for the same period in 2003. Such decrease is mainly attributable to normal production declines in 2004.

14

Gas production attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin Chalk Fields was 623,308 Mcf and 707,803 Mcf during the quarters ended June 30, 2004 and 2003, respectively. Gas production attributable to the Underlying Properties in the Robinson’s Bend Field was 475,728 Mcf and 502,452 Mcf during the quarters ended June 30, 2004 and 2003, respectively. Gas production decreased during 2004 as a result of normal production declines. Oil production attributable to the Underlying Properties for the quarters ended June 30, 2004 and June 30, 2003 was 5,656 Bbls and 5,618 Bbls, respectively.

During the three months ended September 30, 2004, the average price used to calculate Net Proceeds for gas, before gathering, treating and transportation deductions, was $3.89 per MMBtu as compared to $3.51 per MMBtu for the three months ended September 30, 2003. During the quarter ended September 30, 2004, the average price used to calculate Net Proceeds for oil was $31.72 as compared to $23.00 per Bbl for the quarter ended September 30, 2003. When TEMI pays a purchase price for gas based on the Minimum Price ($1.73 per MMBtu and $1.71 per MMBtu for 2004 and 2003 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, 2004 and 2003. As of September 30, 2004, TEMI had no accumulated Price Credits. Additionally, if the Index Price for gas exceeds the Sharing Price ($2.13 per MMBtu and $2.12 per MMBtu for 2004 and 2003 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 months ended September 30, 2004 and 2003 by $1.9 million and $1.8 million, respectively.

Cash distributions received by Unitholders during the quarter ended September 30, 2004 included approximately $219,000 of Net Proceeds from Infill Wells drilled on the Underlying Properties in the Cotton Valley Fields in East Texas. Prior to the quarter ended September 30, 2004, distributions received by Unitholders did not include proceeds from the Infill Wells as the Infill Wells’ costs and expenses exceeded the Infill Wells’ revenues prior to the quarter ended September 30, 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 quarters ended September 30, 2004 and 2003 totaled $0.7 million and $0.4 million, respectively. The increase in costs and expenses in 2004 is mainly due to workovers performed on wells in the Austin Chalk Field. With respect to the Robinson’s Bend Field, lease operating expenses and capital expenditures of $1.5 million were deducted in calculating the Net Proceeds payable to

15

the Trust from the Robinson’s Bend Field for each of the three-month periods ended September 30, 2004 and 2003.

General and administrative expenses amounted to $0.3 million and $0.2 million, respectively, for the three-month periods ending September 30, 2004 and 2003. These expenses primarily relate to administrative services provided by Torch and the Trustee, and legal fees.

The foregoing resulted in distributable income of $1.6 million, or $.18 per Unit, for the three months ended September 30, 2004, as compared to $1.8 million, or $.21 per Unit, for the same period in 2003. Cash distributions of $1.6 million, or $0.18 per Unit, were made during the quarter ended September 30, 2004 as compared to $1.7 million, or $0.20 per Unit, for the same period in 2003.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003

For the nine months ended September 30, 2004, net profits income was $4.8 million, down 37% from net profits income of $7.6 million for the same period in 2003. Such decrease is mainly attributable to the Trust receiving no payments with respect to the Robinson’s Bend Field during the nine months ended September 30, 2004 (see “Net Proceeds Attributable to the Robinson’s Bend Field Have Declined Significantly” below). In addition, normal production declines pertaining to gas production during the nine months ended June 30, 2004 reduced net profits income.

Gas production attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin Chalk Fields was 1,909,392 Mcf and 2,151,758 Mcf during the nine months ended June 30, 2004 and 2003, respectively. Gas production attributable to the Underlying Properties in the Robinson’s Bend Field was 1,451,687 Mcf and 1,511,511 Mcf during the nine months ended June 30, 2004 and 2003, respectively. Gas production decreased during 2004 as a result of normal production declines. Oil production attributable to the Underlying Properties for the nine months ended June 30, 2004 and June 30, 2003 was 18,691 Bbls and 17,200 Bbls, respectively.

During the nine months ended September 30, 2004, the average price used to calculate Net Proceeds for gas, before gathering, treating and transportation deductions, was $3.63 per MMBtu as compared to $3.56 per MMBtu for the nine months ended September 30, 2003. During the nine months ended September 30, 2004, the average price used to calculate Net Proceeds for oil was $28.66 as compared to $24.01 per Bbl for the nine months ended June 30, 2003. When TEMI pays a purchase price for gas based on the Minimum Price ($1.73 per MMBtu and $1.71 per MMBtu for 2004 and

16

2003 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, 2004 and 2003. As of September 30, 2004, TEMI had no accumulated Price Credits. Additionally, if the Index Price for gas exceeds the Sharing Price ($2.13 per MMBtu and $2.12 per MMBtu for 2004 and 2003 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, 2004 and 2003 by $5.0 million and $5.3 million, respectively.

Cash distributions received by Unitholders during the nine months ended September 30, 2004 included approximately $219,000 of Net Proceeds from Infill Wells drilled on the Underlying Properties in the Cotton Valley Fields in East Texas. Prior to 2004, distributions received by Unitholders did not include proceeds from the Infill Wells as the Infill Wells’ costs and expenses exceeded the Infill Wells’ revenues prior to 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 nine months ended September 30, 2004 and 2003 totaled $2.0 million and $1.2 million, respectively. The increase in costs and expenses in 2004 is mainly due to workovers performed on wells in the Austin Chalk Field. With respect to the Robinsons’ Bend Field, lease operating expenses and capital expenditures of $4.4 million and $3.1 million were deducted in calculating the Net Proceeds payable to the Trust from the Robinson’s Bend Field during the nine-months ended September 30, 2004 and 2003, respectively The increase in costs and expenses in 2004 is due to costs and expenses not being deducted in calculating the Net Proceeds payable to the Trust from the Robinson’s Bend Field prior to January 1, 2003 (see “Net Proceeds Attributable to the Robinson’s Bend Field Have Declined Significantly” below).

General and administrative expenses amounted to $0.7 million and $0.8 million for the nine-month periods ending September 30, 2004 and 2003, respectively. These expenses primarily relate to administrative services provided by Torch and the Trustee and legal fees.

The foregoing resulted in distributable income of $4.3 million, or $0.50 per Unit, for the nine months ended September 30, 2004, as compared to $6.8 million, or $0.79 per Unit, for the same period in 2003. Cash distributions of $4.4 million, or $0.51 per Unit, were made during the nine months ended September 30, 2004 as compared to $6.8 million, or $0.79 per Unit, for the same period in 2003.

17

Net profits income received by the Trust during the three and nine month periods ended September 30, 2004 and 2003, derived from production sold during the three and nine months ended June 30, 2004 and 2003, respectively, was computed as shown in the following table (in thousands):

(a) Commencing with the second quarter of 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. With respect to the Robinson’s Bend Field, the Trust has received no cash distributions

18

subsequent to the second quarter 2003 distribution. (See “Net Proceeds Attributable to the Robinson’s Bend Field Have Declined Significantly” for additional information.)

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 months ended September 30, 2004 (pertaining to production during the nine months ended September 30, 2004). During this period, Robinson’s Bend Field costs and expenses exceeded net revenues by approximately $162,000. 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, 2004 (pertaining to production through June 30, 2004), the Robinson’s Bend Field Cumulative Deficit was approximately $365,000. 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

19

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 nine months ended September 30, 2004 and 2003.

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 reserves attributable to the Trust and estimated future net revenues from Trust reserves.

20

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

21

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, 2003 was approximately $37.2 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 $4.11 per Mcf. The computation of the $4.11 per Mcf Purchase Contract price was based on an unescalated Henry Hub spot price for natural gas on December 31, 2003 of $5.97 per MMBtu. The December 31, 2003 reserve value was greater than $25.0 million. Therefore, the Trust did not terminate on March 1, 2004. Based on oil and gas reserve estimates at December 31, 2003 prepared by independent reserve engineers, Torch projects that unless the Henry Hub spot price for natural gas on December 31, 2004 exceeds approximately $4.50 per MMBtu, the Trust will terminate on March 1, 2005. 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.

22

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 for the year ended December 31, 2003 (“Form 10-K”). 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. Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its subsidiaries is the maker of a Senior Subordinated Note payable — affiliate which was due on September 30, 2004. The Senior Subordinated Note payable — affiliate of $23.1 million is payable to Torchmark Corporation (“Torchmark”). As of November 15, 2004, the Senior Subordinated Note had not been satisfied in full. Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its subsidiaries is currently in the discovery stage of litigation with Torchmark relating to amounts due to Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its subsidiaries from Torchmark and in a separate action with respect to the Senior Subordinated Note that may ultimately impact the final amount to be paid in the settlement of the Senior Subordinated Note. The resolution of the current disputes with Torchmark is uncertain at this time. See Note 2 to the Consolidated Financials Statements of Torch Energy Advisors Incorporated and its subsidiaries attached to the Form 10-K as Exhibit 99.1. The inability of Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its subsidiaries or TEMI to meet its obligations or to continue to be a going concern will have an adverse material effect on the Trust, its financial statements and operations.

Historically, Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its subsidiaries has relied on its ability to incur debt and obtain cash through the proceeds from the sale of assets. The inability to reach a reasonable settlement with Torchmark or to raise capital through the incurrence of new debt or the sale of assets will have a material adverse effect on Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its subsidiaries’ financial condition, ability to meet its obligations and operating needs, and results of operations. Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its subsidiaries’ financial statements in the Form 10-K have been presented on the basis that it is a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its

23

subsidiaries’ capital requirements raise a substantial doubt about its ability to continue as a going concern. Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its subsidiaries’ financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The information contained in this item updates, and should be read in conjunction with Part II, Item 7A of the Trust’s annual report on Form 10-K for the year ended December 31, 2003.

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 $1.73 per MMBtu and $1.71 per MMBtu for 2004 and 2003, 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 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 $2.13 per MMBtu and $2.12 per MMBtu for 2004 and 2003 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.

24

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures.

Based on their evaluation as of September 30, 2004, 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 (“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 Trust’s trustee in making these determinations, has relied to the extent reasonable on information provided by Torch.

(b) Changes in Internal Control over Financial Reporting.

There were no changes in the Trust’s internal control over financial reporting during the quarter ended September 30, 2004 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting.

25

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.

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

26

SIGNATURE

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

Date: November 15, 2004

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

27

Exhibit Index

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

28