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SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549



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FORM 10-K



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(Mark One)

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



For the fiscal year ended December 31, 2003



OR



| ̈ | 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



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TORCH ENERGY ROYALTY TRUST

(Exact Name of Registrant as Specified in Its Charter)



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



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



Registrants
telephone number, including area code: (302) 651-8775



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Securities registered pursuant to Section 12(b) of the Act:



|                             |  |                                          
|---------------------------- |  | -----------------------------------------
|Title of each class          |  | Name of each exchange on which registered
|Units of Beneficial Interest |  | New York Stock Exchange                  



Securities
registered pursuant to Section 12 (g) of the Act:

NONE



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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 Act).    YES ̈NO  x



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



The aggregate market values of outstanding units of beneficial interest of the registrant held by non-affiliates of the registrant at March 1, 2004 and June 30, 2003 were
approximately $56.3 million and $66.0 million, respectively.



As of March 1,
2004, 8.6 million Units of Beneficial Interest were outstanding.



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Torch Energy Royalty Trust



Annual Report on Form 10-K

For the fiscal year ended December 31, 2003



TABLE OF CONTENTS



|         |  |          |  |                                                                                      |  |           
|-------- |  | -------- |  | ------------------------------------------------------------------------------------ |  | ----------
|         |  |          |  |                                                                                      |  | PageNumber
|PART I   |  |          |  |                                                                                      |  |           
|         |  |          | 
|         |  | Item 1.  |  | Business                                                                             |  | 3         
|         |  | Item 2.  |  | Properties                                                                           |  | 9         
|         |  | Item 3.  |  | Legal Proceedings                                                                    |  | 12        
|         |  | Item 4.  |  | Submission of Matters to a Vote of Unitholders                                       |  | 12        
|         |  |          | 
|PART II  |  |          |  |                                                                                      |  |           
|         |  |          | 
|         |  | Item 5.  |  | Market for Registrants Units and Related Unitholder Matters                         |  | 13        
|         |  | Item 6.  |  | Selected Financial Data                                                              |  | 13        
|         |  | Item 7.  |  | Discussion and Analysis of Financial Condition and Results of Operations             |  | 14        
|         |  | Item 7a. |  | Quantitative and Qualitative Disclosures About Market Risk                           |  | 17        
|         |  | Item 8.  |  | Financial Statements and Supplementary Data                                          |  | 18        
|         |  | Item 9.  |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |  | 31        
|         |  | Item 9A  |  | Controls and Procedures                                                              |  | 31        
|         |  |          | 
|PART III |  |          |  |                                                                                      |  |           
|         |  |          | 
|         |  | Item 10. |  | Directors and Executive Officers of the Registrant                                   |  | 31        
|         |  | Item 11. |  | Executive Compensation                                                               |  | 31        
|         |  | Item 12. |  | Security Ownership of Certain Beneficial Owners and Management                       |  | 32        
|         |  | Item 13. |  | Certain Relationships and Related Transactions                                       |  | 32        
|         |  | Item 14. |  | Principal Accountant Fees and Services                                               |  | 34        
|         |  |          | 
|PART IV  |  |          |  |                                                                                      |  |           
|         |  |          | 
|         |  | Item 15. |  | Exhibits, Financial Statement Schedules, and Reports on Form 8-K                     |  | 35        
|         |  |          | 
|         |  |         |  | Signatures                                                                           |  | 37        



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PART I



Item 1. Business



This document includes
forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts included in this
document, including without limitation, statements under Discussion and Analysis of Financial Condition and Results of Operations regarding the financial position, estimated quantities and net present values of reserves of the Torch
Energy Royalty Trust (Trust) and statements that include the words believe, expects, anticipates, intends, estimates, projects, target, goal,
plans, objectives, should or similar expressions or variations are forward-looking statements. Torch Energy Advisors Incorporated (Torch) and the Trust can give no assurances that the assumptions upon
which these statements are based will prove to be correct. Important factors that could cause actual results to differ materially from Torchs expectations (Cautionary Statements) are disclosed under Risk Factors
elsewhere in this document. All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified by the Cautionary Statements.



General



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



The Trust will terminate upon the first to occur of (i) an affirmative vote of the holders of not less than 662/3% 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 March 30, 2004, the Trust has not terminated as none of the aforementioned events have occurred. (See Termination of Trust disclosure
on page 8 for additional information.) Upon termination of the Trust, the remaining assets of the Trust will be sold and the proceeds therefrom (after expenses) will be distributed to the unitholders (Unitholders). The sole purpose of
the Trust is to hold the Net Profits Interests, to receive payments from TRC and Velasco, and to make payments to Unitholders. The Trust does not conduct any business activity.



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



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



Sales of coal seam and tight sands gas attributable to the Net Profits Interests prior to January 1, 2003 resulted in Unitholders receiving quarterly allocations of tax credits under Section 29 of the Internal Revenue Code of 1986
(Section 29 Credit). The right to receive the Section 29 Credit expired December 31, 2002. In 2002 and 2001, the Section 29 Credit available for production from qualifying coal seam properties was approximately $1.09 and $1.08,
respectively, for each MMBtu of gas produced and sold. The Section 29 Credit available for production from qualifying tight sands properties was approximately $0.52 for each MMBtu produced and sold in 2002 and 2001.



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



Marketing Arrangements



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



The Purchase Contract also provides that TEMI pay a minimum price
(Minimum Price) for gas production. The Minimum Price is adjusted annually for inflation and was $1.71, $1.71 and $1.70 per MMBtu for 2003, 2002 and 2001, respectively. When TEMI pays a purchase price based on the Minimum Price it
receives price credits (Price Credits), equal to the difference between the Index Price and the Minimum Price, that it is entitled to deduct in determining the purchase price when the Index Price for gas exceeds the Minimum Price. In
addition, if the Index Price for gas exceeds the sharing price, which is adjusted annually for inflation (Sharing Price), TEMI is entitled to deduct 50% of such excess (Price Differential) in determining the purchase price.
The Sharing Price was $2.12, $2.12 and $2.10 per MMBtu in 2003, 2002 and 2001, 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.



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Gas production is purchased at the wellhead. Therefore, Net Proceeds do not include any amounts received in
connection with extracting natural gas liquids from such production at gas processing or treating facilities.



Gathering, Treating and Transportation Arrangements



The Purchase Contract entitles TEMI to deduct certain gas gathering, treating and transportation fees in calculating the purchase price for gas in the Robinsons Bend, Austin Chalk and Cotton Valley Fields. The
amounts that may be deducted in calculating the purchase price for such gas are set forth in the Purchase Contract and are not affected by the actual costs incurred by TEMI to gather, treat and transport gas. For the Robinsons Bend Field, TEMI
is entitled to deduct a gathering, treating and transportation fee of $0.260 per MMBtu adjusted for inflation ($0.289, $0.289 and $0.286 per MMBtu for 2003, 2002, and 2001 respectfully), plus fuel usage equal to 5% of revenues, payable to Bahia Gas
Gathering, Ltd. (Bahia), an affiliate of Torch, pursuant to a gas gathering agreement. Additionally, a fee of $.05 per MMBtu, representing a gathering fee payable to a non-affiliate of Torch, is deducted in calculating the purchase price
for production from 68 of the 394 wells in the Robinsons Bend Field. TEMI deducts $0.38 per MMBtu plus 17% of revenues in calculating the purchase price for production from the Austin Chalk Fields as a fee to gather, treat and transport gas
production. TEMI deducts from the purchase price for gas for production attributable to certain wells in the Cotton Valley Fields a transportation fee of $0.045 per MMBtu. During the years ended December 31, 2003, 2002 and 2001, gathering, treating
and transportation fees deducted from the Net Proceeds calculations pertaining to production during the twelve months ended September 30, 2003, 2002 and 2001 in the Robinsons Bend, Austin Chalk and Cotton Valley Fields, totaled $1.3 million,
$1.0 million and $1.4 million for 2003, 2002 and 2001, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase price from the Chalkley Field.



Net Profits Interests



The Net Profits Interests entitle the Trust to receive 95% of the Net Proceeds attributable to oil and gas produced and sold from wells
(other than infill wells) on the Underlying Properties. In calculating Net Proceeds from the Robinsons Bend Field, operating and development costs incurred prior to January 1, 2003 were not deducted. In addition, the amounts paid to the Trust
from the Robinsons Bend Field during any calendar quarter are subject to a volume limitation (Volume Limitation) equal to the gross proceeds from the sale of 912.5 MMcf of gas, less property, production, severance and related
taxes. The Robinsons Bend Field production attributable to the Trust did not meet the Volume Limitation during the years ended December 31, 2003, 2002 and 2001 and is not expected to do so in the future.



The Net Profits Interests also entitle the Trust to 20% of the Net Proceeds of wells drilled
on the Underlying Properties since the Trusts establishment into formations in which the Trust has an interest, other than wells drilled to replace damaged or destroyed wells (Infill Wells). Infill Well Net Proceeds represent the
aggregate gross revenues received from Infill Wells less the aggregate amount of the following Infill Well costs: i) property, production, severance and similar taxes; ii) development costs; iii) operating costs; and iv) interest on the recovered
portion, if any, of the foregoing costs computed at a rate of interest announced publicly by Citibank, N.A. in New York as its base rate.



Torch Affiliates Robinsons Bend Field Sale



On January 8, 2003, Torch and certain of its subsidiaries and subsidiaries of Torchmark Corporation, including Velasco, sold all of their oil and gas interests in the
Robinsons Bend Field to Everlast Energy LLC (Everlast). Everlast assumed operations of the properties and the water disposal and gathering facilities. The sale included the Robinsons Bend Field working interests, which are
burdened by the



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Trusts Net Profits Interests, and the water disposal and gathering systems. This transaction did not alter the
Trusts Net Profits Interest in the Robinsons Bend Field. Additionally, this transaction did not alter Torchs obligation to administer the Trust and to handle the distribution of the Trusts cash distributions.



RISK FACTORS



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 included herein are estimates only and are subject to many uncertainties. Actual quantities of oil and natural gas may differ
considerably from the amounts set forth herein. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The present value, discounted at 10%, of future net cash
flows from proved reserves attributable to the Net Profits Interests does not represent the fair market value of the proved reserves, or the price at which the Net Profits Interests could be sold. A determination of fair market value would involve
consideration of many factors in addition to the present value, discounted at 10%. An impairment loss is recognized when the net carrying value of the Net Profits Interests exceeds its fair market value. No impairment loss was recognized during the
years ended December 31, 2003, 2002 and 2001.



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



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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



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of particular environmental concern. It is anticipated that, absent the occurrence of an unanticipated event,
compliance with these laws will not have a material adverse effect upon the Trust or Unitholders. Torch has informed the Trust that it cannot predict what effect future regulation or legislation, enforcement policies thereunder, and claims for
damages to property, employees, other persons and the environment resulting from operations on the Underlying Properties could have on the Trust or Unitholders. However, pursuant to the terms of the Conveyances, any costs or expenses incurred by TRC
or Velasco in connection with environmental liabilities, to the extent arising out of or relating to activities occurring on, or in connection with, or conditions existing on or under, the Underlying Properties before October 1, 1993, will be borne
by TRC or Velasco and not the Trust and will not be deducted in calculating Net Proceeds and will, therefore, not reduce amounts payable to the Trust.



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



Prior to December 31, 2002, lease operating expenses were not deducted in calculating the Net Proceeds payable to the Trust from the
Robinsons Bend Field. In accordance with the provisions of the net profits interest conveyance covering the Robinsons Bend Field, commencing with the second quarter 2003 distribution (pertaining to the quarter ended March 31, 2003
production) lease operating expenses and capital expenditures have been deducted in calculating Net Proceeds. The Trust received no payments with respect to the Robinsons Bend Field during the six months ended December 31, 2003 (pertaining to
production during the six months ended September 30, 2003). During this period, Robinsons Bend Field costs and expenses exceeded net revenues by approximately $193,000. 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. Torch does not anticipate that the Net Proceeds attributable to the Robinsons Bend
Field, if any, will be significant in the future.



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.



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.



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Financial Condition of Torch and its Subsidiaries



Torch is the administrative service provider to the Trust and a party to
that certain Administrative Services Agreement whereby Torch provides certain administrative and related services to the Trust. See Item 13  Administrative Services Agreement. TEMI, a subsidiary of Torch, is a party to the Purchase Contract.
Torch is the maker of a Senior Subordinated Note payable  affiliate due on September 30, 2004. The Senior Subordinated Note payable  affiliate of $23.1 million is payable to Torchmark Corporation (Torchmark). As of December
31, 2003, there is insufficient working capital to satisfy this obligation, and there is uncertainty that Torch will be able to satisfy this obligation when the amount is due. Torch is currently in the discovery stage of litigation with Torchmark
relating to amounts due to Torch from Torchmark that may ultimately impact the final amount to be paid in the settlement of the Senior Subordinated Note. The resolution of the current dispute with Torchmark is uncertain at this time. See Note 2 to
the Consolidated Financials Statements of Torch attached hereto as Exhibit 99.1. The inability of Torch 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 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s financial condition, ability to meet its obligations and operating needs, and results of operations. Torchs financial statements 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s capital requirements raise a substantial doubt about its ability to continue as a going concern. Torchs financial statements do not
include any adjustments that might result from the outcome of this uncertainty.



Item 2. Properties



Description of the
Underlying Properties



Chalkley Field. The Underlying Properties in
the Chalkley Field, located in Cameron Parish, Louisiana, include an average 16.2% working interest (12.1% net revenue interest) in four unitized wells producing from the Miogyp B reservoir. The wells produce from a depth in excess of
14,000 feet. A subsidiary of ExxonMobil Corporation operates the unitized wells.



Robinsons Bend Field. The Underlying Properties include an average 42.7% working interest (30.2% net revenue interest) in 394 wells in the Robinsons Bend Field in the Black Warrior Basin of Alabama.



On January 8, 2003, certain Torch affiliates sold all of their oil and gas interests in the
Robinsons Bend Field to Everlast. All of the wells in the Robinsons Bend Field are operated by Everlast. See Torch Affiliates Robinsons Bend Field Sale disclosure on page 5 for additional information.



Cotton Valley Fields. The Underlying Properties include an average 48.7 % working
interest (34.6% net revenue interest) in 41 wells in four fields that produce from the Upper and Lower Cotton Valley formations in Texas. All of the wells in the Cotton Valley Fields are operated by a subsidiary of Torch.



Austin Chalk Fields. The Underlying Properties include an average of 16.9% working
interest (13.4% net revenue interest) in 89 wells in the Austin Chalk Fields of Central Texas. Production from these fields is derived primarily from the highly fractured Austin Chalk formation using horizontal drilling techniques. A subsidiary of
Torch operates three wells in the Ausin Chalk Fields. The remaining wells in the Austin Chalk Fields are operated by third parties.



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Well Count and Acreage Summary



The following table shows, as of December 31, 2003, the gross and net interest in oil and gas wells for the Underlying Properties:



|                      |  |           |  |           |  |       |  |    
|--------------------- |  | --------- |  | --------- |  | ----- |  | ---
|                      |  | Gas Wells |  | Oil Wells
|                      |  | Gross     |  | Net       |  | Gross |  | Net
|Chalkley Field        |  | 4         |  | .6        |  |      |  |   
|Robinsons Bend Field |  | 394       |  | 168.3     |  |      |  |   
|Cotton Valley Fields  |  | 41        |  | 20.9      |  |      |  |   
|Austin Chalk Fields   |  | 38        |  | 7.4       |  | 51    |  | 8.5
|                      |  |           |  |           |  |       |  |    
|Total                 |  | 477       |  | 197.20    |  | 51    |  | 8.5
|                      |  |           |  |           |  |       |  |    



The following table shows the gross
and net acreage for the Underlying Properties as of December 31, 2003. A gross acre in the following table refers to the number of acres in which a working interest is owned directly by the Trust. The number of net acres is the sum of the fractional
ownership of working interests owned directly by the Trust in the gross acres expressed as a whole number and percentages thereof. A net acre is deemed to exist when the sum of fractional ownership of working interests in gross acres equals one.



|                      |  |         |  |       
|--------------------- |  | ------- |  | ------
|                      |  | Acreage
|                      |  | Gross   |  | Net   
|Chalkley Field        |  | 2,152   |  | 348   
|Robinsons Bend Field |  | 33,404  |  | 14,288
|Cotton Valley Fields  |  | 4,411   |  | 2,606 
|Austin Chalk Fields   |  | 35,439  |  | 6,409 
|                      |  |         |  |       
|Total                 |  | 75,406  |  | 23,651
|                      |  |         |  |       



Drilling Activity



The following table sets forth the results of drilling activity for the Underlying
Properties during the three years ended December 31, 2003. Gross wells, as it applies to wells in the following table, refers to the number of wells in which a working interest is owned directly by the owners of the Underlying Properties and Infill
Wells (Gross Well). A net well (Net Well) represents the sum of the fractional ownership working interests in the Gross Wells expressed as whole numbers and percentages thereof.



All of the wells shown below represent Infill Wells drilled on the Underlying Properties.
Such wells are operated by Samson Lone Star Limited Partnership. The Net Profits Interest entitle the Trust to 20% of Infill Net Proceeds. Infill Net Proceeds is defined as gross proceeds from the sale of production attributable to
Infill wells less all production, drilling and completion costs of such wells. Infill Net Proceeds are calculated by aggregating the proceeds and costs from Infill Wells on a state by state basis. Because costs of Infill Wells exceed proceeds of
production, the Trust has not received any Infill Net Proceeds.



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|     |  |                   |  |          |  |       |  |            |  |          |  |      
|---- |  | ----------------- |  | -------- |  | ----- |  | ---------- |  | -------- |  | -----
|     |  | Development Wells
|     |  | Gross             |  | Net     
|     |  | Productive        |  | DryHoles |  | Total |  | Productive |  | DryHoles |  | Total
|2003 |  | 1                 |  | 0        |  | 1     |  | .2         |  | 0        |  | .2   
|2002 |  | 5                 |  | 0        |  | 5     |  | .8         |  | 0        |  | .8   
|2001 |  | 4                 |  | 0        |  | 4     |  | .7         |  | 0        |  | .7   



There was no other drilling activity
on the Underlying Properties during the three years ended December 31, 2003.



Oil and Gas Sales Prices and Production Costs



The following
table sets forth, for the Underlying Properties, the net production volumes of gas and oil, the weighted average lifting cost and taxes per Mcfe deducted in calculating Net Proceeds and the weighted average sales price per Mcf of gas and Bbl of oil
for production attributable to cash distributions received by Unitholders during years ended December 31, 2003, 2002 and 2001 (derived from production during the twelve months ended September 30, 2003, 2002 and 2001, respectively).



|                                              |  |                                                 |       |     |      |   |       |      |  |   |       |    
|--------------------------------------------- |  | ----------------------------------------------- | ----- | --- | ---- | - | ----- | ---- |  | - | ----- | ---
|                                              |  | Chalkley, Cotton Valley and Austin Chalk Fields |      
|                                              |  | 2003                                            |       |     | 2002 |   |       | 2001 | 
|Production:                                   |  |                                                 |       |     |      |   |       |      |  |   |       |    
|Gas (MMcf)                                    |  |                                                 | 2,835 |     |      |   | 3,121 |      |  |   | 3,664 |    
|Oil (Mbbl)                                    |  |                                                 | 24    |     |      |   | 26    |      |  |   | 30    |    
|                                              |  |                                                 |      
|Weighted average lifting cost per Mcfe        |  | $                                               | .53   |     |      | $ | .45   |      |  | $ | .38   |    
|Weighted average taxes on production per Mcfe |  | $                                               | .24   |     |      | $ | .20   |      |  | $ | .12   |    
|Weighted average sales price (b)              |  |                                                 |       |     |      |   |       |      |  |   |       |    
|Gas ($/Mcf)                                   |  | $                                               | 3.64  |     |      | $ | 2.41  |      |  | $ | 3.54  |    
|Oil ($/Bbl)                                   |  | $                                               | 24.00 |     |      | $ | 18.56 |      |  | $ | 23.16 |    
|                                              | 
|                                              |  | Robinsons Bend Field                           |      
|                                              |  | 2003                                            |       |     | 2002 |   |       | 2001 | 
|Production:                                   |  |                                                 |       |     |      |   |       |      |  |   |       |    
|Gas (MMcf)                                    |  |                                                 | 2,014 |     |      |   | 2,105 |      |  |   | 2,228 |    
|Oil (Mbbl)                                    |  |                                                 |      |     |      |   |      |      |  |   |      |    
|                                              |  |                                                 |      
|Weighted average lifting cost per Mcfe        |  | $                                               |       | (a) |      | $ |       | (a)  |  | $ |       | (a)
|Weighted average taxes on production per Mcfe |  | $                                               | .25   |     |      | $ | .10   |      |  | $ | .22   |    
|Weighted average sales price (b)              |  |                                                 |       |     |      |   |       |      |  |   |       |    
|Gas ($/Mcf)                                   |  | $                                               | 3.12  |     |      | $ | 1.99  |      |  | $ | 2.98  |    
|Oil ($/Bbl)                                   |  | $                                               |      |     |      | $ |      |      |  | $ |      |    

---

|(a) | Prior to December 31, 2002, lease operating expenses were not deducted in calculating the Net Proceeds payable to the Trust from the Robinsons Bend Field. Commencing with the
second quarter of 2003 distribution (pertaining to the quarter ended March 31, 2003 production) lease operating expenses and capital expenditures were deducted in calculating Net Proceeds in the Robinsons Bend Field. Average lifting costs per
Mcfe in the Robinsons Bend Field were $2.75, $2.69, and $2.79, respectively, during 2003, 2002 and 2001.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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



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Item 3. Legal Proceedings



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



Item 4. Submission of Matters to a Vote of Unitholders



During the year ended December 31, 2003, no matter was submitted to the Unitholders for a vote.



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Torch Energy Royalty Trust



PART II



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



The Units are listed and traded on the New York Stock Exchange under the symbol TRU. At March 1, 2004, there were 8,600,000 Units outstanding and approximately 471 Unitholders of record. The following
table sets forth, for the periods indicated, the high and low sales prices per Unit on the New York Stock Exchange (NYSE) and the amount of quarterly cash distributions per Unit made by the Trust:



|                                 |  |      |      |     |   |                    |  |   |    
|-------------------------------- |  | ---- | ---- | --- | - | ------------------ |  | - | ---
|                                 |  | High |      | Low |   | Cash Distributions
|Quarter ended March 31, 2002     |  | $    | 7.00 |     | $ | 5.75               |  | $ | .24
|Quarter ended June 30, 2002      |  | $    | 7.10 |     | $ | 2.70               |  | $ | .21
|Quarter ended September 30, 2002 |  | $    | 4.85 |     | $ | 2.72               |  | $ | .28
|Quarter ended December 31, 2002  |  | $    | 5.05 |     | $ | 3.60               |  | $ | .28
|                                 |  |      |     
|Quarter ended March 31, 2003     |  | $    | 5.59 |     | $ | 3.89               |  | $ | .31
|Quarter ended June 30, 2003      |  | $    | 7.40 |     | $ | 4.64               |  | $ | .28
|Quarter ended September 30, 2003 |  | $    | 9.29 |     | $ | 7.00               |  | $ | .20
|Quarter ended December 31, 2003  |  | $    | 8.03 |     | $ | 5.62               |  | $ | .14



On March 1, 2004, the high and low
sales price per unit on the NYSE was $6.65 and $6.53, respectively.



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



|                                |  |                         |        |      |   |        |  |      |        |      |   |        |  |   |       
|------------------------------- |  | ----------------------- | ------ | ---- | - | ------ |  | ---- | ------ | ---- | - | ------ |  | - | ------
|                                |  | Year Ended December 31,
|                                |  | 2003                    |        | 2002 |   | 2001   |  | 2000 |        | 1999
|Net profits income              |  | $                       | 8,969  |      | $ | 9,357  |  | $    | 16,843 |      | $ | 13,243 |  | $ | 10,174
|Distributable income            |  | $                       | 8,036  |      | $ | 8,616  |  | $    | 16,181 |      | $ | 12,674 |  | $ | 9,511 
|Distributions declared          |  | $                       | 7,989  |      | $ | 8,652  |  | $    | 16,211 |      | $ | 12,668 |  | $ | 9,520 
|Distributable income per Unit   |  | $                       | 0.93   |      | $ | 1.00   |  | $    | 1.88   |      | $ | 1.47   |  | $ | 1.11  
|Distributions per Unit          |  | $                       | 0.93   |      | $ | 1.01   |  | $    | 1.89   |      | $ | 1.47   |  | $ | 1.11  
|Total assets (at end of Period) |  | $                       | 26,458 |      | $ | 31,265 |  | $    | 36,696 |      | $ | 44,941 |  | $ | 49,143



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



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Item 7. Discussion and Analysis of Financial Condition and Results of Operations



Results of Operations



Discussion of Years Ended December 31, 2003, 2002, and 2001



Because a modified cash basis of accounting is utilized by the Trust, Net Proceeds attributable to the Underlying Properties for the years ended December 31, 2003, 2002
and 2001 are derived from actual oil and gas production from October 1, 2002 through September 30, 2003, October 1, 2001 through September 30, 2002 and October 1, 2000 through September 30, 2001, respectively. The following tables set forth oil and
gas sales attributable to the Underlying Properties during the three years ended December 31, 2003.



|                      |  |             |  |           |  |          
|--------------------- |  | ----------- |  | --------- |  | ---------
|                      |  | Bbls of Oil
|                      |  | 2003        |  | 2002      |  | 2001     
|Chalkley Field        |  | 7,887       |  | 9,494     |  | 12,479   
|Robinsons Bend Field |  |            |  |          |  |         
|Cotton Valley Fields  |  | 3,532       |  | 3,413     |  | 3,059    
|Austin Chalk Fields   |  | 12,683      |  | 12,737    |  | 14,427   
|                      |  |             |  |           |  |          
|Total                 |  | 24,102      |  | 25,644    |  | 29,965   
|                      |  |             |  |           |  |          
|                      | 
|                      |  | Mcf of Gas 
|                      |  | 2003        |  | 2002      |  | 2001     
|Chalkley Field        |  | 1,750,133   |  | 2,045,016 |  | 2,513,448
|Robinsons Bend Field |  | 2,013,653   |  | 2,104,869 |  | 2,228,005
|Cotton Valley Fields  |  | 1,004,949   |  | 1,045,196 |  | 1,041,310
|Austin Chalk Fields   |  | 79,514      |  | 30,745    |  | 109,405  
|                      |  |             |  |           |  |          
|Total                 |  | 4,848,249   |  | 5,225,826 |  | 5,892,168
|                      |  |             |  |           |  |          



For the year ended December 31, 2003,
net profits income was $9.0 million, as compared to $9.4 million and $16.8 million for the same periods in 2002 and 2001, respectively. The decrease in net profits income during 2003 as compared to 2002 is due to the Trust receiving no payments with
respect to the Robinsons Bend Field during the six months ended December 31, 2003, which was partially offset by higher average oil and gas prices paid to the Trust in 2003. The decrease in net profits income during 2002 as compared to 2001
resulted from lower average oil and gas prices paid to the Trust and normal production declines.



The Trust received approximately $1.3 million, $3.8 million and $5.8 million in 2003, 2002 and 2001, respectively, for payments for distributions to Unitholders with respect to 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 totaling $4.6 million were deducted in calculating Robinsons Bend Net
Proceeds. During the third and fourth quarters of 2003 (pertaining to production for the six months ended September 30, 2003), the Robinsons Bend Field costs and expenses exceeded revenues by approximately $193,000. The Trust will receive no
payments for distributions to Unitholders with respect to the Robinsons Bend Field until future proceeds exceed the sum of future costs and expenses and the cumulative excess of such costs and expenses including interest. The Trust and Torch
do not anticipate that there will be any Net Proceeds attributable to the Robinsons Bend Field in the future.



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Gas production attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin Chalk Fields was
2,834,596 Mcf, 3,120,957 Mcf and 3,664,163 Mcf in 2003, 2002 and 2001, respectively. Gas production attributable to the Underlying Properties in the Robinsons Bend Field was 2,013,653 Mcf, 2,104,869 Mcf and 2,228,005 Mcf in 2003, 2002 and
2001, respectively. Gas production decreased during each of the years ended December 31, 2003 as a result of normal production declines. Oil production attributable to the Underlying Properties for the year ended December 31, 2003 was 24,102 Bbls as
compared to 25,644 Bbls and 29,965 Bbls for the same periods in 2002 and 2001, respectively.



The average price used to calculate Net Proceeds for gas, before gathering, treating and transportation deductions, during the year ended December 31, 2003 was $3.56 per MMBtu as compared to $2.37 and $3.47 per MMBtu
for the years ended December 31, 2002 and 2001, respectively. The average price used to calculate Net Proceeds for oil during the years ended December 31, 2003, 2002 and 2001 was $24.00, $18.56 and $23.16 per Bbl, respectively. When TEMI pays a
purchase price for gas based on the Minimum Price, TEMI receives Price Credits which it is entitled to deduct in determining the purchase price when the Index Price for gas exceeds the Minimum Price. As of December 31, 2003, TEMI had no outstanding
Price Credits. No Price Credits were deducted in calculating the purchase price related to distributions during the three years ended December 31, 2003.



Additionally, if the Index Price for gas exceeds $2.10 per MMBtu, adjusted annually for inflation ($2.12 per MMBtu for 2003 and 2002, and $2.10 per MMBtu for 2001), TEMI
is entitled to deduct 50% of such excess in calculating the purchase price. Such price sharing arrangement reduced Net Proceeds during the years ended December 31, 2003, 2002, and 2001 by $6.9 million, $1.6 million and $7.9 million, respectively.



Lease operating expenses and capital expenditures attributable to the
Underlying Properties in the Chalkley, Cotton Valley and Austin Chalk Fields deducted in calculating distributions during the years ended December 31, 2003, 2002 and 2001 totaled $2.1 million, $1.5 million and $1.6 million, respectively. The
increase in costs and expenses for 2003 of $2.1 million as compared to costs and expenses of $1.5 million for 2002 is due mainly to capital expenditures incurred in 2003 in connection with the re-drill of a well in the Austin Chalk Field. With
respect to the Robinsons Bend Field, lease operating expenses and capital expenditures were not deducted in calculating the Net Proceeds payable to the Trust from the Robinsons Bend Field prior to January 1, 2003. In accordance with the
provisions of the net profits conveyance in the Robinsons Bend Field, commencing with the second quarter 2003 distribution (pertaining to the quarter ended March 31, 2003 production) lease operating expenses and capital expenditures of $4.6
million were deducted in calculating Net Proceeds. No lease operating expenses and capital expenditures were deducted in calculating Net Proceeds payable to the Trust from the Robinsons Bend Field in 2002 and 2001.



General and administrative expenses during the years ended December 31, 2003, 2002 and 2001
amounted to $0.9 million, $0.7 million and $0.7 million, respectively. These expenses primarily relate to administrative services provided by Torch and the Trustee and legal fees.



For the year ended December 31, 2003, distributable income was $8.0 million, or $0.93 per Unit, as compared to $8.6 million, or $1.00 per
Unit, and $16.2 million, or $1.88 per Unit, for the same periods in 2002 and 2001, respectively. Total cash distributions of $8.0 million, or $0.93 per Unit, were made during the year ended December 31, 2003 as compared to $8.7 million, or $1.01 per
Unit, and $16.2 million, or $1.89 per Unit, for the same periods in 2002 and 2001, respectively. The Section 29 Credits relating to qualifying production from coal seam and tight sands properties, during the twelve months ended September 30, 2002
and 2001 totaled approximately $0.28 and $0.29 per Unit, respectively. The right to receive the Section 29 Credits expired December 31, 2002.



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Net profits received by the Trust during the years ended December 31, 2003, 2002 and 2001, derived from production
sold during the twelve months ended September 30, 2003, 2002 and 2001, respectively, was computed as shown in the following table (in thousands):



|                                                  |  |                                                 |        |      |                       |      |       |       |  |                                                 |       |  |                       |       |   |       |   |                                                 |     |  |                       |       |  |       |        |   |  |   |       |     |  |   |       
|------------------------------------------------- |  | ----------------------------------------------- | ------ | ---- | --------------------- | ---- | ----- | ----- |  | ----------------------------------------------- | ----- |  | --------------------- | ----- | - | ----- | - | ----------------------------------------------- | --- |  | --------------------- | ----- |  | ----- | ------ | - |  | - | ----- | --- |  | - | ------
|                                                  |  | Year Ended December 31,                        
|                                                  |  | 2003                                            |        | 2002 |                       | 2001
|                                                  |  | Chalkley, Cotton Valley and Austin Chalk Fields |        |      | Robinsons Bend Field |      |       | Total |  | Chalkley, Cotton Valley and Austin Chalk Fields |       |  | Robinsons Bend Field |       |   | Total |   | Chalkley, Cotton Valley and Austin Chalk Fields |     |  | Robinsons Bend Field |       |  | Total
|Oil and gas revenues                              |  | $                                               | 10,892 |      |                       | $    | 6,283 |       |  |                                                 |       |  | $                     | 7,989 |   |       | $ | 4,182                                           |     |  |                       |       |  | $     | 13,669 |   |  | $ | 6,640 |     |  |   |       
|                                                  |  |                                                 |        |      |                       |      |       |       |  |                                                 |       |  |                       |       |   |       |   |                                                 |     |  |                       |       |  |       |        |   |  |   |       |     |  |   |       
|Direct operating expenses:                        |  |                                                 |        |      |                       |      |       |       |  |                                                 |       |  |                       |       |   |       |   |                                                 |     |  |                       |       |  |       |        |   |  |   |       |     |  |   |       
|Lease operating expenses (including property tax) |  |                                                 | 1,571  |      |                       |      | 4,181 | (a)   |  |                                                 |       |  |                       | 1,464 |   |       |   |                                                | (a) |  |                       |       |  |       | 1,452  |   |  |   |      | (a) |  |   |       
|Severance tax                                     |  |                                                 | 717    |      |                       |      | 504   |       |  |                                                 |       |  |                       | 640   |   |       |   | 215                                             |     |  |                       |       |  |       | 453    |   |  |   | 496   |     |  |   |       
|                                                  |  |                                                 |        |      |                       |      |       |       |  |                                                 |       |  |                       |       |   |       |   |                                                 |     |  |                       |       |  |       |        |   |  |   |       |     |  |   |       
|                                                  |  |                                                 | 2,288  |      |                       |      | 4,685 |       |  |                                                 |       |  |                       | 2,104 |   |       |   | 215                                             |     |  |                       |       |  |       | 1,905  |   |  |   | 496   |     |  |   |       
|                                                  |  |                                                 |        |      |                       |      |       |       |  |                                                 |       |  |                       |       |   |       |   |                                                 |     |  |                       |       |  |       |        |   |  |   |       |     |  |   |       
|Net proceeds before Capital expenditures          |  |                                                 | 8,604  |      |                       |      | 1,598 |       |  |                                                 |       |  |                       | 5,885 |   |       |   | 3,967                                           |     |  |                       |       |  |       | 11,764 |   |  |   | 6,144 |     |  |   |       
|Capital expenditures                              |  |                                                 | 513    |      |                       |      | 441   |       |  |                                                 |       |  |                       | 3     |   |       |   |                                                |     |  |                       |       |  |       | 179    |   |  |   |      |     |  |   |       
|                                                  |  |                                                 |        |      |                       |      |       |       |  |                                                 |       |  |                       |       |   |       |   |                                                 |     |  |                       |       |  |       |        |   |  |   |       |     |  |   |       
|Net proceeds                                      |  |                                                 | 8,091  |      |                       |      | 1,157 |       |  |                                                 |       |  |                       | 5,882 |   |       |   | 3,967                                           |     |  |                       |       |  |       | 11,585 |   |  |   | 6,144 |     |  |   |       
|Net profits percentage                            |  |                                                 | 95     | %    |                       |      |      | (b)   |  |                                                 |       |  |                       | 95    | % |       |   | 95                                              | %   |  |                       |       |  |       | 95     | % |  |   | 95    | %   |  |   |       
|                                                  |  |                                                 |        |      |                       |      |       |       |  |                                                 |       |  |                       |       |   |       |   |                                                 |     |  |                       |       |  |       |        |   |  |   |       |     |  |   |       
|Net profits income                                |  | $                                               | 7,686  |      |                       | $    | 1,283 |       |  | $                                               | 8,969 |  | $                     | 5,588 |   |       | $ | 3,769                                           |     |  | $                     | 9,357 |  | $     | 11,006 |   |  | $ | 5,837 |     |  | $ | 16,843
|                                                  |  |                                                 |        |      |                       |      |       |       |  |                                                 |       |  |                       |       |   |       |   |                                                 |     |  |                       |       |  |       |        |   |  |   |       |     |  |   |       

---

|(a) | Commencing with the second quarter 2003 distribution (pertaining to production during the quarter ended March 31, 2003), lease operating expenses and capital expenditures were
deducted in calculating Net Proceeds from the Robinsons Bend Field. Lease operating expenses and capital expenditures (in thousands) were $5,969, $5,573 and $6,221 during 2003, 2002 and 2001, respectively.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(b) | With respect to the Robinsons Bend Field, the Trust received no cash distributions during the six months ended December 31, 2003 (pertaining to production during the six
months ended September 30, 2003). During such period, the Robinsons Bend Field costs and expenses exceeded revenues by approximately $193,000.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Termination of the Trust



The Trust will terminate on March 1 of any year if it is determined that the pre-tax future net cash flows, discounted at 10%, attributable to estimated net proved
reserves of the Net Profits Interests on the preceding December 31 are less than $25.0 million. The pre-tax future net cash flows, discounted at 10%, attributable to estimated net proved reserves of the Net Profits Interests as of December 31, 2003
was approximately $37.2 million. Such reserve report was prepared pursuant to Securities and Exchange Commission guidelines and utilized an unescalated Henry Hub spot price for natural gas on December 31, 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 value of the Units.



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Critical Accounting Policy



Reserve Estimates



The proved reserves of the Trust are estimated quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable
in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgement. For example,
estimates are made regarding the amount and timing of future operating costs, production volumes and severance taxes, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year,
the estimate of proved reserves also change. Any variance in these assumptions could materially affect the estimated quantity and value of the Trusts reserves.



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



Modified Cash Basis



The financial statements of the Trust are
prepared on a modified cash basis although financial statements filed with the Securities and Exchange Commission are normally required to be prepared in accordance with accounting principles generally accepted in the United States. Since the
operations of the Trust are limited to the distribution of income from the Net Profits Interests, the item of primary importance to the reader of the financial statements of the Trust is the amount of cash distributions to the Unitholders for the
period reported.



Item 7a. Quantitative and Qualitative Disclosures About Market Risk



The Trust is exposed to market risk, including adverse changes in commodity prices. The Trusts assets constitute Net Profits Interests in the Underlying Properties. As a result, the Trusts operating
results can be significantly affected by fluctuations in commodity prices caused by changing market forces and the price received for production from the Underlying Properties.



All production from the Underlying Properties is sold pursuant to a Purchase Contract between TRC, Velasco, and TEMI. Pursuant to the
Purchase Contract, TEMI is obligated to purchase all net production attributable to the Underlying Properties for an Index Price, less certain other charges, which are calculated monthly. The Index Price calculation is based on market prices of oil
and gas and therefore is subject to commodity price risk. The Purchase Contract expires upon termination of the Trust and provides a Minimum Price paid by TEMI for gas. The Minimum Price is adjusted annually for inflation and was $1.71, $1.71 and
$1.70 per MMBtu for 2003, 2002 and 2001, 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 $2.12, $2.12 and $2.10 per MMBtu in 2003, 2002 and 2001,
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.



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Item 8. Financial Statements and Supplementary Data



INDEX TO FINANCIAL STATEMENTS



|                                                                                           |  |     
|------------------------------------------------------------------------------------------ |  | ----
|                                                                                           |  | Page
|Report of Independent Auditors                                                             |  | 19  
|Statements of Assets, Liabilities and Trust Corpus at December 31, 2003 and 2002           |  | 20  
|Statements of Distributable Income for the Years Ended December 31, 2003, 2001 and 2001    |  | 21  
|Statements of Changes in Trust Corpus for the Years Ended December 31, 2003, 2002 and 2001 |  | 22  
|Notes to Financial Statements                                                              |  | 23  



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REPORT OF INDEPENDENT AUDITORS



Wilmington Trust
Company

as Trustee of Torch Energy Royalty Trust

and to the
Unitholders:



We have audited the accompanying statements of assets,
liabilities and trust corpus of the Torch Energy Royalty Trust (the Trust) as of December 31, 2003 and 2002 and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended
December 31, 2003. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audit.



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



As described in Note 2, the financial statements are prepared on a modified
cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States.



In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Trust as of December 31, 2003 and 2002
and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with the accounting principles described in Note 2.



/s/ Ernst & Young LLP

Houston,
Texas

March 25, 2004



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Torch Energy Royalty Trust



STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

(In thousands)





|                                                                                                                                                       |  |                   |        |                   |   |       
|------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ----------------- | ------ | ----------------- | - | ------
|                                                                                                                                                       |  | December 31, 2003 |        | December 31, 2002
|ASSETS                                                                                                                                                 |  |                   |        |                   |   |       
|Cash                                                                                                                                                   |  | $                 | 1      |                   | $ | 2     
|Net profits interests in oil and gas properties (net of accumulated amortization of $154,143 and $149,337 at December 31, 2003 and 2002,
respectively) |  |                   | 26,457 |                   |   | 31,263
|                                                                                                                                                       |  |                   |        |                   |   |       
|                                                                                                                                                       |  | $                 | 26,458 |                   | $ | 31,265
|                                                                                                                                                       |  |                   |        |                   |   |       
|LIABILITIES AND TRUST CORPUS                                                                                                                           |  |                   |        |                   |   |       
|Trust expense payable                                                                                                                                  |  | $                 | 174    |                   | $ | 221   
|Trust corpus                                                                                                                                           |  |                   | 26,284 |                   |   | 31,044
|                                                                                                                                                       |  |                   |        |                   |   |       
|                                                                                                                                                       |  | $                 | 26,458 |                   | $ | 31,265
|                                                                                                                                                       |  |                   |        |                   |   |       



The accompanying notes
to financial statements

are an integral part of these statements.



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STATEMENTS OF DISTRIBUTABLE INCOME

(In thousands, except per Unit amounts)



|                                            |  |                         |       |      |   |       |  |   |       
|------------------------------------------- |  | ----------------------- | ----- | ---- | - | ----- |  | - | ------
|                                            |  | Year Ended December 31,
|                                            |  | 2003                    |       | 2002 |   | 2001 
|Net profits income                          |  | $                       | 8,969 |      | $ | 9,357 |  | $ | 16,843
|                                            |  |                         |      
|Interest income                             |  |                         | 2     |      |   | 4     |  |   | 20    
|                                            |  |                         |       |      |   |       |  |   |       
|                                            |  |                         | 8,971 |      |   | 9,361 |  |   | 16,863
|                                            |  |                         |      
|General and administrative expenses         |  |                         | 935   |      |   | 745   |  |   | 682   
|                                            |  |                         |       |      |   |       |  |   |       
|Distributable income                        |  | $                       | 8,036 |      | $ | 8,616 |  | $ | 16,181
|                                            |  |                         |       |      |   |       |  |   |       
|Distributable income per Unit (8,600 Units) |  | $                       | 0.93  |      | $ | 1.00  |  | $ | 1.88  
|                                            |  |                         |       |      |   |       |  |   |       
|Distributions per Unit                      |  | $                       | 0.93  |      | $ | 1.01  |  | $ | 1.89  
|                                            |  |                         |       |      |   |       |  |   |       



The accompanying notes
to financial statements

are an integral part of these statements.



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STATEMENTS OF CHANGES IN TRUST CORPUS

(In thousands)



|                                      |  |                         |        |   |      |   |        |      |  |   |         |  
|------------------------------------- |  | ----------------------- | ------ | - | ---- | - | ------ | ---- |  | - | ------- | -
|                                      |  | Year Ended December 31, |       
|                                      |  | 2003                    |        |   | 2002 |   |        | 2001 | 
|Trust corpus, beginning of year       |  | $                       | 31,044 |   |      | $ | 36,511 |      |  | $ | 44,783  |  
|Amortization of Net Profits Interests |  |                         | (4,806 | ) |      |   | (5,431 | )    |  |   | (8,242  | )
|Distributable income                  |  |                         | 8,035  |   |      |   | 8,616  |      |  |   | 16,181  |  
|Distributions to Unitholders          |  |                         | (7,989 | ) |      |   | (8,652 | )    |  |   | (16,211 | )
|                                      |  |                         |        |   |      |   |        |      |  |   |         |  
|Trust Corpus, end of year             |  | $                       | 26,284 |   |      | $ | 31,044 |      |  | $ | 36,511  |  
|                                      |  |                         |        |   |      |   |        |      |  |   |         |  



The accompanying notes
to financial statements

are an integral part of these statements.



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Torch Energy Royalty Trust



Notes to Financial Statements



1. Nature of Operations



The Torch Energy Royalty Trust
(Trust) was formed effective October 1, 1993, pursuant to a trust agreement (Trust Agreement) among Wilmington Trust Company, as trustee (Trustee), Torch Royalty Company (TRC) and Velasco Gas Company,
Ltd. (Velasco) as owners of certain oil and gas properties (Underlying Properties) and Torch Energy Advisors Incorporated (Torch) as grantor. TRC and Velasco created net profits interests (Net Profits
Interests) and conveyed such interests to Torch. Torch conveyed the Net Profits Interests to the Trust in exchange for an aggregate of 8,600,000 units of beneficial interest (Units). Such Units were sold to the public through
various underwriters in November 1993.



The Trust will terminate upon the first
to occur of: (i) an affirmative vote of the holders of not less than 662/3% of the outstanding Units to
liquidate the Trust; (ii) such time as the ratio of the cash amounts received by the Trust from the Net Profits Interests to administrative costs of the Trust is less than 1.2 to 1.0 for three consecutive quarters; (iii) March 1 of any year if it is
determined based on a reserve report as of December 31 of the prior year that the present value of estimated pre-tax future net cash flows, discounted at 10%, of proved reserves attributable to the Net Profits Interests is equal to or less than
$25.0 million; or (iv) December 31, 2012. After termination of the Trust, the remaining assets of the Trust will be sold, and the proceeds therefrom (after expenses) will be distributed to the unitholders (Unitholders). The sole purpose
of the Trust is to hold the Net Profits Interests, to receive payments from TRC and Velasco, and to make payments to Unitholders. The Trust does not conduct any business activity.



TRC and Velasco receive payments reflecting the proceeds of oil and gas sold and aggregate these payments, deduct applicable costs and make
payments to the Trustee each quarter for the amounts due to the Trust. Unitholders receive quarterly cash distributions relating to oil and gas produced and sold from the Underlying Properties. Because no additional properties will be contributed to
the Trust, the assets of the Trust deplete over time and a portion of each cash distribution made by the Trust is analogous to a return of capital.



The only assets of the Trust, other than cash and temporary investments being held for the payment of expenses and liabilities and for distribution to Unitholders, are
the Net Profits Interests. Under the Trust Agreement, the Trustee receives the payments attributable to the Net Profits Interests and pays all expenses, liabilities and obligations of the Trust. The Trustee has the discretion to establish a cash
reserve for the payment of any liability that is contingent or uncertain in amount or that otherwise is not currently due and payable. The Trustee is entitled to cause the Trust to borrow money to pay expenses, liabilities and obligations that
cannot be paid out of cash held by the Trust. The Trustee is entitled to cause the Trust to borrow from any source, including from the entity serving as Trustee, provided that the entity serving as Trustee shall not be obligated to lend to the
Trust. To secure payment of any such indebtedness (including any indebtedness to the Trustee), the Trustee is authorized to (i) mortgage and otherwise encumber the entire Trust estate or any portion thereof; (ii) carve out and convey production
payments; (iii) include all terms, powers, remedies, covenants and provisions it deems necessary or advisable, including confession of judgement and the power of sale with or without judicial proceedings; and (iv) provide for the exercise of those
and other remedies available to a secured lender in the event of a default on such loan. The terms of such indebtedness and security interest, if funds were loaned by the Trustee, must be similar to the terms which the Trustee would grant to a
similarly situated commercial customer with whom it did not have a fiduciary relationship, and the Trustee shall be entitled to enforce its rights with respect to any such indebtedness and security interest as if it were not then serving as Trustee.



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Notes to Financial Statements



The Trustee is authorized and directed to sell and convey the Net Profits Interests without Unitholder approval in
certain instances as described in the Trust Agreement, including upon termination of the Trust. The Trustee is empowered by the Trust Agreement to employ consultants and agents (including Torch) and to make payments of all fees for services or
expenses out of the assets of the Trust.



On January 8, 2003, Torch and certain
of its subsidiaries and subsidiaries of Torchmark Corporation sold all of their oil and gas interests in the Robinsons Bend Field to Everlast Energy LLC (Everlast). Everlast assumed operations of the properties and the water
disposal and gathering facilities. The sale included the Robinsons Bend Field working interests, which are burdened by the Trusts Net Profits Interests, and the water disposal and gathering systems. This transaction did not alter the
Trusts Net Profits Interest in the Robinsons Bend Field. Additionally, this transaction did not alter Torchs obligation to administer the Trust and to handle the distribution of the Trusts cash distributions.



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:



| |  | Revenues are recognized in the period in which amounts are received by the Trust. Therefore, revenues recognized during the years ended December 31, 2003, 2002 and 2001 are derived
from oil and gas production sold during the twelve-month periods ended September 30, 2003, 2002 and 2001, respectively. General and administrative expenses are recognized on an accrual basis.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Amortization of the Net Profits Interests is calculated on a unit-of-production basis and charged directly to trust corpus.
| | - | ---------------------------------------------------------------------------------------------------------------------------



| |  | Distributions to Unitholders are recorded when declared by the Trustee.
| | - | -----------------------------------------------------------------------



| |  | An impairment loss is recognized when the net carrying value of the Net Profits Interests exceeds its fair market value. No such impairment was recorded during the three years ended
December 31, 2003.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because net profits income is not accrued in the period of production and
amortization of the Net Profits Interests is not charged against operating results.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



3. Federal Income Taxes



Tax counsel has advised the Trustee that, under current tax law, the Trust is classified as a grantor trust for Federal income tax purposes and not an association taxable
as a business entity. However, the opinion of tax counsel is not binding on the Internal Revenue Service. As a grantor trust, the Trust is not subject to Federal income tax.



Because the Trust is treated as a grantor trust for Federal income tax purposes and a Unitholder is treated as directly owning an interest
in the Net Profits Interests, each Unitholder is taxed directly on such Unitholders pro rata share of income attributable to the Net Profits Interests consistent with the



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Notes to Financial Statements



Unitholders method of accounting and without regard to the taxable year or accounting method employed by the
Trust. Amounts payable with respect to the Net Profits Interests are paid to the Trust on the quarterly record date established for quarterly distributions in respect to each calendar quarter during the term of the Trust, and the income and
deductions from such payments are allocated to the Unitholders of record on such date.



4. Distributions and Income Computations



Each quarter the amount of cash available for distribution to Unitholders (the Quarterly Distribution Amount) is equal to the excess, if any, of the cash
received by the Trust, on the last day of the second month following the previous calendar quarter (or the next business day thereafter) ending prior to the dissolution of the Trust, from the Net Profits Interests then held by the Trust plus, with
certain exceptions, any other cash receipts of the Trust during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for the payment of contingent or future obligations of the
Trust. Based on the payment procedures relating to the Net Profits Interest, cash received by the Trust on the last day of the second month of a particular quarter from the Net Profits Interests generally represents proceeds from the sale of oil and
gas produced from the Underlying Properties during the preceding calendar quarter. The Quarterly Distribution Amount for each quarter is payable to Unitholders of record on the last day of the second month of the calendar quarter unless such day is
not a business day, in which case the record date is the next business day thereafter. The Trust distributes the Quarterly Distribution Amount, which is distributed within approximately 10 days after the record date to each person who was a
Unitholder of record on the associated record date.



5. Related Party Transactions



Marketing Arrangements



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



The Purchase Contract also provides that a minimum price paid by TEMI for gas production is $1.70 per MMBtu adjusted annually for inflation (Minimum Price). When TEMI pays a purchase price based on the
Minimum Price it receives price credits (Price Credits) equal to the difference between the Index Price and the Minimum Price that it is entitled to deduct in determining the purchase price when the Index Price for gas exceeds the
Minimum Price. Price Credits are computed on a monthly basis. As of December 31, 2003, TEMI had no outstanding Price Credits. No Price Credits were deducted in calculating the purchase price related to distributions received by Unitholders during
the three years ended December 31, 2003.



In addition, if the Index Price for
gas exceeds $2.10 per MMBtu adjusted annually for inflation (Sharing Price), TEMI is entitled to deduct 50% of such excess (Price Differential) in determining the purchase price. As a result of such Sharing Price arrangement,
Net Proceeds attributable to the Underlying Properties during the years ended December 31, 2003, 2002 and 2001 were reduced by $6.9 million, $1.6 million and $7.9 million, respectively. TEMI has an annual option to discontinue the Minimum Price



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Notes to Financial Statements



commitment. However, if TEMI discontinues the Minimum Price commitment, it will no longer be entitled to deduct the
Price Differential in calculating the purchase price and will forfeit all accrued Price Credits. TEMI has not exercised its option to discontinue the Minimum Price Commitment. The Minimum Price in 2003, 2002 and 2001 was approximately $1.71, $1.71
and $1.70 per MMBtu for 2003, 2002 and 2001, respectively. The Sharing Price in 2003, 2002 and 2001 was approximately $2.12, $2.12 and $2.10 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 for the years ended December 31, 2003, 2002 and 2001 were $18.5 million, $13.2 million and $21.7 million, respectively.



Gas production is purchased at the wellhead and, therefore, distributions do not include any amounts received in connection with extracting
natural gas liquids from such production at gas processing or treating facilities.



Gathering, Treating and Transportation Arrangements



The
Purchase Contract entitles TEMI to deduct certain gas gathering, treating and transportation costs in calculating the purchase price for gas in the Robinsons Bend, Austin Chalk and Cotton Valley Fields. The amounts that may be deducted in
calculating the purchase price for such gas are set forth in the Purchase Contract and are not affected by the actual costs incurred by TEMI to gather, treat and transport gas. In the Robinsons Bend Field, TEMI is entitled to deduct a
gathering, treating and transportation fee of $0.26 per MMBtu adjusted annually for inflation ($0.289, $0.289 and $0.286 per MMBtu for 2003, 2002 and 2001, respectively, plus fuel usage equal to 5% of revenues, payable to Bahia Gas Gathering, Ltd.
(Bahia), a subsidiary of Torch, pursuant to a gas gathering agreement. Additionally, a fee of $0.05 per MMBtu, representing a gathering fee payable to a non-affiliate of Torch, is deducted in calculating the purchase price for production
from 68 of the 394 wells in the Robinsons Bend Field. TEMI also deducts $0.38 per MMBtu plus 17% of revenues in calculating the purchase price for production from the Austin Chalk Fields, as a fee to gather, treat and transport gas production.
TEMI deducts from the purchase price for gas in the Cotton Valley Fields a transportation fee of $0.045 per MMBtu for production attributable to certain wells. This transportation fee is paid to a third party. During the years ended December 31,
2003, 2002 and 2001, such fees deducted from the Net Proceeds calculations, attributable to production during the twelve months ended September 30, 2003, 2002 and 2001, in the Robinsons Bend, Austin Chalk and Cotton Valley Fields, totaled $1.3
million, $1.0 million and $1.4 million, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase price from the Chalkley Field.



Operator Overhead Fees



A subsidiary of Torch operates certain oil and gas interests burdened by the Net Profits Interests. 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 $176,000,
$178,000 and $160,000 for the years ended December 31, 2003, 2002 and 2001, respectively. Commencing January 2003, the Robinsons Bend Field is operated by a third party, Everlast. See Torch Affiliates Robinsons Bend Field
Sale disclosure on page 5 for additional information.



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Notes to Financial Statements



Administrative Services Agreement



Pursuant to the Trust Agreement, Torch and the Trust entered into an administrative services agreement, effective October 1, 1993. The Trust
is obligated, throughout the term of the Trust, to pay to Torch each quarter an administrative services fee for accounting, bookkeeping, informational and other services relating to the Net Profits Interests. The administrative services fee is
$87,500 per calendar quarter commencing October 1, 1993. The amount of the administrative services fee is adjusted annually, based upon the change in the Producers Price Index as published by the Department of Labor, Bureau of Labor
Statistics. Administrative services fees of $388,000, $389,000 and $384,000 were paid by the Trust to Torch during the three years ended December 31, 2003, 2002 and 2001, respectively.



Torch is the maker of a Senior Subordinated Note payable  affiliate due on September 30, 2004. The Senior Subordinated Note payable
 affiliate of $23.1 million is payable to Torchmark Corporation (Torchmark). As of December 31, 2003, there is insufficient working capital to satisfy this obligation, and there is uncertainty that Torch will be able to satisfy
this obligation when the amount is due. Torch is currently in the discovery stage of litigation with Torchmark relating to amounts due to Torch from Torchmark that may ultimately impact the final amount to be paid in the settlement of the Senior
Subordinated Note. The resolution of the current dispute with Torchmark is uncertain at this time. See Note 2 to the Consolidated Financials Statements of Torch attached hereto as Exhibit 99.1. The inability of Torch or TEMI to meet its obligations
or continue to be a going concern will have an adverse material effect on the Trust, its financial statements and operations.



Historically, Torch 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s financial condition, ability to meet its obligations and operating needs, and results of operations.
Torchs financial statements 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s capital requirements raise
a substantial doubt about its ability to continue as a going concern. Torchs financial statements do not include any adjustments that might result from the outcome of this uncertainty.



Compensation of the Trustee and Transfer Agent



The Trust Agreement provides that the Trustee be compensated for its administrative
services, out of the Trust assets, in an annual amount of $41,000, plus an hourly charge for services in excess of a combined total of 250 hours annually at its standard rate. The Trustee receives a transfer agency fee of $5.00 annually per account
(minimum of $15,000 annually), subject to change each December, beginning December 1994, based upon the change in the Producers Price Index as published by the Department of Labor, Bureau of Labor Statistics, plus $1.00 for each certificate
issued. Total administrative and transfer agent fees charged by the Trustee were $56,000 in each of the years ended December 31, 2003, 2002 and 2001. The Trustee is also entitled to reimbursement for out-of-pocket expenses.



6. Supplemental Oil and Gas Information (Unaudited)



Total proved oil and gas reserves attributable to the Net Profits Interests
are primarily based upon reserve reports prepared by T.J. Smith & Company, Inc., Ryder Scott Company, L.P. and Netherland, Sewell & Associates, Inc. (Independent Reserve Engineers). Future net cash flows were computed by applying
end-of-period Purchase Contract prices for oil and gas to estimated future production, less the estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves.



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Notes to Financial Statements



Reserve Quantities:



The following table sets forth the estimated total proved and proved developed oil and gas reserves attributable to the Trusts Net
Profits Interests (all located in the United States) for the years ended December 31, 2003, 2002 and 2001, based on reserve reports prepared by Independent Reserve Engineers. As a net profits interest does not entitle the Trust to a specific
quantity of oil or gas, but to a portion of oil and gas sufficient to yield a specified portion of the net proceeds derived therefrom, proved reserves attributable to a net profits interest are calculated by deducting an amount of oil or gas
sufficient, if sold at the prices used in preparing the reserve estimates for the Underlying Properties, to pay an amount of applicable future estimated production expenses, development costs and taxes for such Underlying Properties. The use of this
convention to estimate reserve volumes attributable to the Net Profits Interests is standard practice in the industry.



Year-end reserves at December 31, 2003 were 20.2 billion cubic feet equivalent (Bcfe) as compared to year-end 2002 and 2001 reserves of 18.1 Bcfe and 16.5
Bcfe, respectively. In accordance with Securities and Exchange Commission reporting guidelines, year-end reserves and the related future net revenues attributable to the Trusts Net Profits Interests are estimated utilizing the Purchase
Contract Price for gas, after gathering fees ($4.11, $3.42 and $2.31 per MMBtu for 2003, 2002 and 2001). Such Purchase Contract prices were calculating utilizing the Henry Hub gas prices on the last day of the entitys fiscal year ($5.97, $4.79
and $2.57 per MMBtu for 2003, 2002 and 2001, respectively). Revisions of estimated reserves as stated in the table below during each of the three years ending December 31, 2003 are primarily due to fluctuations in the aforementioned gas prices.



|                                               |  |            |   |  |            |   |  |            |   |  |            |   |  |            |   |  |            |  
|---------------------------------------------- |  | ---------- | - |  | ---------- | - |  | ---------- | - |  | ---------- | - |  | ---------- | - |  | ---------- | -
|Description                                    |  | 2003       |   |  | 2002       |   |  | 2001       |  
|                                               |  | Oil (Mbbl) |   |  | Gas (MMcf) |   |  | Oil (Mbbl) |   |  | Gas (MMcf) |   |  | Oil (Mbbl) |   |  | Gas (MMcf) |  
|Proved reserves at beginning of year           |  | 90         |   |  | 17,592     |   |  | 67         |   |  | 16,074     |   |  | 142        |   |  | 41,806     |  
|Revisions                                      |  | 46         |   |  | 6,188      |   |  | 26         |   |  | 5,369      |   |  | (68        | ) |  | (21,299    | )
|Extensions and discoveries                     |  |           |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|Production                                     |  | (24        | ) |  | (4,246     | ) |  | (3         | ) |  | (3,851     | ) |  | (7         | ) |  | (4,433     | )
|                                               |  |            |   |  |            |   |  |            |   |  |            |   |  |            |   |  |            |  
|Proved reserves at end of year                 |  | 112        |   |  | 19,534     |   |  | 90         |   |  | 17,592     |   |  | 67         |   |  | 16,074     |  
|                                               |  |            |   |  |            |   |  |            |   |  |            |   |  |            |   |  |            |  
|Proved developed reserves at beginning of year |  | 90         |   |  | 17,592     |   |  | 67         |   |  | 16,074     |   |  | 142        |   |  | 41,806     |  
|                                               |  |            |   |  |            |   |  |            |   |  |            |   |  |            |   |  |            |  
|Proved developed reserves at end of year       |  | 105        |   |  | 17,210     |   |  | 90         |   |  | 17,592     |   |  | 67         |   |  | 16,074     |  
|                                               |  |            |   |  |            |   |  |            |   |  |            |   |  |            |   |  |            |  



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Notes to Financial Statements



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



Estimated future net cash flows from the Net Profits Interests in proved oil
and gas reserves at December 31, 2003, 2002 and 2001 are presented in the following table:



|                                                           |  |              |         |   |      |   |         |      |  |   |         |  
|---------------------------------------------------------- |  | ------------ | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                                           |  | December 31, |        
|                                                           |  | 2003         |         |   | 2002 |   |         | 2001 | 
|Future cash inflows                                        |  | $            | 83,202  |   |      | $ | 97,340  |      |  | $ | 56,762  |  
|Future costs and expenses                                  |  |              | (24,712 | ) |      |   | (34,410 | )    |  |   | (19,154 | )
|                                                           |  |              |         |   |      |   |         |      |  |   |         |  
|Net future cash flows                                      |  |              | 58,490  |   |      |   | 62,930  |      |  |   | 37,608  |  
|Discount at 10% for timing of cash flows                   |  |              | (21,318 | ) |      |   | (22,092 | )    |  |   | (10,028 | )
|                                                           |  |              |         |   |      |   |         |      |  |   |         |  
|Present value of future net cash flows for proved reserves |  | $            | 37,172  |   |      | $ | 40,838  |      |  | $ | 27,580  |  
|                                                           |  |              |         |   |      |   |         |      |  |   |         |  



The following table sets forth the
changes in the present value of estimated future net revenues from proved reserves attributable to the Trusts Net Profits Interests during the years ended December 31, 2003, 2002 and 2001:



|                                                             |  |                         |        |   |      |   |        |      |  |   |          |  
|------------------------------------------------------------ |  | ----------------------- | ------ | - | ---- | - | ------ | ---- |  | - | -------- | -
|                                                             |  | Year Ended December 31, |       
|                                                             |  | 2003                    |        |   | 2002 |   |        | 2001 | 
|Balance at beginning of year                                 |  | $                       | 40,838 |   |      | $ | 27,580 |      |  | $ | 133,589  |  
|Sales of oil and gas produced, net of production costs       |  |                         | (7,587 | ) |      |   | (9,991 | )    |  |   | (14,131  | )
|Accretion to discount                                        |  |                         | 4,084  |   |      |   | 2,758  |      |  |   | 13,359   |  
|Extensions and discoveries                                   |  |                         |       |   |      |   |       |      |  |   |         |  
|Revision of prior-year estimates, change in prices and other |  |                         | (163   | ) |      |   | 20,491 |      |  |   | (105,237 | )
|                                                             |  |                         |        |   |      |   |        |      |  |   |          |  
|Balance at end of year                                       |  | $                       | 37,172 |   |      | $ | 40,838 |      |  | $ | 27,580   |  
|                                                             |  |                         |        |   |      |   |        |      |  |   |          |  



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



The following table summarizes the estimated Section 29 Credits attributable to the Trusts Net Profits Interest for qualifying coal seam and tight sand production at December 31, 2003, 2002 and 2001. Such estimates are based upon the
production estimates set forth in the reserve reports prepared by the Independent Reserve Engineers. The qualifying tight sands Section 29 Tax Credit estimate was computed utilizing a rate of approximately $.52 per MMBtu. The qualifying coal seam
Section 29 Tax Credit estimate was computed utilizing a constant rate of approximately $1.08 per MMBtu for 2001. The right to receive the Section 29 Credit expired December 31, 2002. Therefore, such credits have no value as of December 31, 2003 and
2002.



|                                |  |              |   |      |   |      |  |   |      
|------------------------------- |  | ------------ | - | ---- | - | ---- |  | - | -----
|                                |  | December 31,
|                                |  | 2003         |   | 2002 |   | 2001
|Undiscounted                    |  | $            |  |      | $ |     |  | $ | 2,366
|                                |  |              |   |      |   |      |  |   |      
|Discounted present value at 10% |  | $            |  |      | $ |     |  | $ | 2,151
|                                |  |              |   |      |   |      |  |   |      



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Notes to Financial Statements



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



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



|                                 |  |                    |       |                      |   |                               |  |   |     
|-------------------------------- |  | ------------------ | ----- | -------------------- | - | ----------------------------- |  | - | ----
|                                 |  | Net Profits Income |       | Distributable Income |   | Distributable Income Per Unit
|Quarter ended March 31, 2003     |  | $                  | 2,868 |                      | $ | 2,665                         |  | $ | .31 
|Quarter ended June 30, 2003      |  |                    | 2,610 |                      |   | 2,282                         |  |   | .27 
|Quarter ended September 30, 2003 |  |                    | 2,075 |                      |   | 1,843                         |  |   | .21 
|Quarter ended December 31, 2003  |  |                    | 1,416 |                      |   | 1,246                         |  |   | .14 
|                                 |  |                    |       |                      |   |                               |  |   |     
|                                 |  | $                  | 8,969 |                      | $ | 8,036                         |  | $ | .93 
|                                 |  |                    |       |                      |   |                               |  |   |     
|Quarter ended March 31, 2002     |  | $                  | 2,233 |                      | $ | 2,058                         |  | $ | .24 
|Quarter ended June 30, 2002      |  |                    | 1,983 |                      |   | 1,810                         |  |   | .21 
|Quarter ended September 30, 2002 |  |                    | 2,586 |                      |   | 2,412                         |  |   | .28 
|Quarter ended December 31, 2002  |  |                    | 2,555 |                      |   | 2,336                         |  |   | .27 
|                                 |  |                    |       |                      |   |                               |  |   |     
|                                 |  | $                  | 9,357 |                      | $ | 8,616                         |  | $ | 1.00
|                                 |  |                    |       |                      |   |                               |  |   |     





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



None.



Item 9A. Controls and Procedures



(a)
Evaluation of Disclosure Controls and Procedures. Based on their evaluation as of December 31, 2003, the Trusts trustee has concluded that the Trusts disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)
under the Securities and Exchange Act of 1934 (the Exchange Act)) are effective to ensure that information required to be disclosed by the Trust in reports that it files or submits under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. The 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 December 31, 2003 that materially affected, or are reasonably likely to materially affect, the Trusts internal control over financing
reporting.



PART III



Item 10. Directors and Executive Officers of the Registrant



The Registrant has no directors or executive officers. The Trustee is a corporate trustee that may be removed as trustee under the Trust Agreement, with or without cause, at a meeting duly called and held by the
affirmative vote of Unitholders of not less than a majority of all the Units then outstanding. Any such removal of the Trustee shall be effective only at such time as a successor trustee fulfilling the requirements of Section 3807(a) of the Delaware
Business Trust Act has been appointed and has accepted such appointment.



Item 11. Executive Compensation



The
following is a description of certain fees and expenses paid or borne by the Trust, including fees paid to Torch, the Trustee, the Transfer Agent or their affiliates.



Ongoing Administrative Expenses. The Trust is responsible for paying all legal, accounting, engineering and stock exchange fees,
printing costs and other administrative and out-of-pocket expenses incurred by or at the direction of the Trustee in its capacity as Trustee and/or transfer agent.



Compensation of the Trustee and Transfer Agent. The Trust Agreement provides that the Trustee be compensated for its administrative
services, out of the Trust assets, in an annual amount of $41,000, plus an hourly charge for services in excess of a combined total of 250 hours annually at its standard rate. The Trustee receives a transfer agency fee of $5.00 annually per account
(minimum of $15,000 annually), subject to change each December, beginning December 1994, based upon the change in the Producers Price Index as published by the Department of Labor, Bureau of Labor Statistics, plus $1.00 for each certificate
issued. The Trustee is entitled to reimbursement for out-of-pocket expenses.



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



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Item 12. Security Ownership of Certain Beneficial Owners and Management



As of March 1, 2004, no person or group of persons was known by the Trust to be the beneficial owner of more than 5% of the Units. The Trust has no officers or directors. The Trust does not have an Equity
Compensation Plan.



Item 13. Certain Relationships and Related Transactions



Administrative Services Agreement



Pursuant to the Trust Agreement, Torch and the Trust entered into the Administrative Services Agreement effective October 1, 1993. The following summary of certain provisions of the Administrative Services Agreement does not purport to be
complete and is subject to, and is qualified in its entirety by reference to, the provisions of the Administrative Services Agreement.



The Trust is obligated, throughout the term of the Trust, to pay to Torch each quarter an administrative services fee for accounting, bookkeeping, informational and other
services relating to the Net Profits Interests. The administrative services fee is $87,500 per calendar quarter, adjusted annually, based upon the change in the Producers Price Index as published by the Department of Labor, Bureau of Labor
Statistics. Administrative services fees of $388,000, $389,000 and $384,000 were paid by the Trust to Torch during the years ended December 31, 2003, 2002 and 2001, respectively.



Torch is the maker of a Senior Subordinated Note payable  affiliate due on September 30, 2004. The Senior Subordinated Note payable
 affiliate of $23.1 million is payable to Torchmark Corporation (Torchmark). As of December 31, 2003, there is insufficient working capital to satisfy this obligation. Torch is currently in the discovery stage of litigation with
Torchmark relating to amounts due to Torch from Torchmark that may ultimately impact the final amount to be paid in the settlement of the Senior Subordinated Note. The resolution of the current dispute with Torchmark is uncertain at this time. See
Note 2 to the Consolidated Financials Statements of Torch attached hereto as Exhibit 99.1. The inability of Torch or TEMI to meet its obligations or continue to be a going concern will have an adverse material effect on the Trust, its financial
statements and operations.



Historically, Torch 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s financial condition, ability to meet its obligations and operating needs, and results of operations. The Companys financial statements 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s capital requirements raise a substantial doubt about its ability to continue as a going concern. Torchs financial statements do not
include any adjustments that might result from the outcome of this uncertainty.



Marketing Arrangement



TRC and Velasco contracted to sell the
oil and gas production from the Underlying Properties to TEMI under a Purchase Contract. Under the Purchase Contract, TEMI is obligated to purchase all net production attributable to the Underlying Properties for an Index Price for oil and gas less
certain gathering, treating and transportation charges, which are calculated monthly. The Purchase Contract also provides that TEMI pay the Minimum Price for gas production. When TEMI pays a purchase price based



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on the Minimum Price, it receives Price Credits equal to the difference between the Index Price and the Minimum Price
that it is entitled to deduct in determining the purchase price when the Index Price for gas exceeds the Minimum Price. Price Credits are computed on a monthly basis, and as of December 31, 2003, TEMI had no outstanding Price Credits.



In addition, if the Index Price for gas exceeds the Sharing Price, TEMI is entitled to deduct
the Price Differential in determining the purchase price. As a result of such Sharing Price arrangement, Net Proceeds attributable to the Underlying Properties during the years ended December 31, 2003, 2002 and 2001 were reduced by $6.9 million,
$1.6 million and $7.9 million, respectively. TEMI has an annual option to discontinue the Minimum Price commitment. However, if TEMI discontinues the Minimum Price commitment, it will no longer be entitled to deduct the Price Differential in
calculating the purchase price and will forfeit all accrued Price Credits. TEMI has not exercised its option to discontinue the Minimum Price Commitment. The Minimum Price in 2003, 2002 and 2001 was approximately $1.71, $1.71 and $1.70 per MMBtu,
respectively. The Sharing Price in 2003, 2002 and 2001 was approximately $2.12, $2.12 and $2.10 per MMBtu, respectively.



Gross revenues (before deductions for applicable gathering, treating and transportation charges) from TEMI included in the Net Proceeds calculation attributable to the
Underlying Properties for the years ended December 31, 2003, 2002 and 2001 were $18.5 million, $13.2 million and $21.7 million, respectively.



Gathering, Treating and Transportation Arrangements



The Purchase Contract entitles TEMI to deduct certain gas gathering, treating and transportation costs in calculating the purchase price for gas in the Robinsons
Bend, Austin Chalk and Cotton Valley Fields. The amounts that may be deducted in calculating the purchase price for such gas are set forth in the Purchase Contract and are not affected by the actual costs incurred by TEMI to gather, treat and
transport gas. In the Robinsons Bend Field, TEMI is entitled to deduct a gathering, treating and transportation fee of $0.26 per MMBtu commencing October 1, 1993 adjusted for inflation ($0.289, $0.289 and $0.286 per MMBtu for 2003, 2002 and
2001, respectively), plus fuel usage equal to 5% of revenues, payable to Bahia Gas Gathering, Ltd. (Bahia), a subsidiary of Torch, pursuant to a gas gathering agreement. Additionally, a fee of $0.05 per MMBtu, representing a gathering
fee payable to a non-affiliate of Torch, is deducted in calculating the purchase price for production from 68 of the 394 wells in the Robinsons Bend Field. TEMI also deducts $0.38 per MMBtu plus 17% of revenues in calculating the purchase
price for production from the Austin Chalk Fields, as a fee to gather, treat and transport gas production. TEMI deducts from the purchase price for gas a transportation fee of $0.045 MMBtu for production attributable to certain wells in the Cotton
Valley Fields. During the years ended December 31, 2003, 2002 and 2001, gas gathering, treating and transportation fees, deducted by TEMI from the Net Proceeds calculations attributable to production during the twelve months ended September 30,
2003, 2002 and 2001 in the Robinsons Bend, Austin Chalk and Cotton Valley Fields, totaled $1.3 million, $1.0 million and $1.4 million, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase
price from the Chalkley Field.



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Item 14. Principal Accountant Fees and Services



The Trust does not have an audit committee, and has no audit committee pre-approval policy with respect to fees paid to Ernst & Young LLP. Any pre-approval of services performed by Ernst & Young LLP and related fees is granted by
Torch and the Trustee. The outside auditors are appointed and engaged by Torch and the Trustee. Fees for services performed by Ernst & Young LLP for the years ended December 31, 2003 and 2002 are:



|                   |  |      |         |      |   |       
|------------------ |  | ---- | ------- | ---- | - | ------
|                   |  | 2003 |         | 2002
|Audit Fees         |  | $    | 128,400 |      | $ | 97,800
|Audit Related Fees |  |      | 0       |      |   | 0     
|Tax Fees           |  |      | 0       |      |   | 0     
|All Other Fees     |  |      | 0       |      |   | 0     
|                   |  |      |         |      |   |       
|                   |  | $    | 128,400 |      | $ | 97,800
|                   |  |      |         |      |   |       



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PART IV



Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K



|(a) | The following documents are filed as part of this report:
|--- | ---------------------------------------------------------



| | 1. | Financial Statements:
| | -- | ---------------------



Torch Energy Royalty Trust

Report of
Independent Auditors

Statements of Assets, Liabilities and Trust Corpus at December 31, 2003 and 2002

Statements of Distributable Income for the Years Ended December 31, 2003, 2002 and 2001

Statements of Changes in Trust Corpus for the Years Ended December 31, 2003, 2002 and 2001

Notes to Financial Statements



Torch Energy Advisors Incorporated and Subsidiaries

Report of Independent Auditors

Consolidated Balance Sheet of Torch as of December 31, 2003, and 2002 and the Related Consolidated
Statements of Operations, Stockholders Equity and Comprehensive Income, and Cash Flows for the years ended December 31, 2003, 2002 and 2001

Notes to Consolidated Financial Statements



| | 2. | Financial Statement Schedules
| | -- | -----------------------------



Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is
included in the financial statements and notes thereto.



| | 3. | Exhibits
| | -- | --------



Exhibit

Number
Exhibit



4. Instruments Defining the Rights of
Security Holders, Including Indentures.

4.1 - Form of Torch Energy Royalty Trust Agreement.*

4.2 - Form of Louisiana Trust Agreement.*

4.3 - Specimen Trust Unit Certificate.*

4.4 - Designation of Ancillary Trustee.*



10. Material Contracts.

10.1 - Purchase Agreement between TRC, Velasco and TEMI.*

10.2 - Gas Gathering Agreement between TEMI and Bahia Gas Gathering, Ltd.*

10.3 - Amendment to Gas Gathering Agreement.*

10.4 - Water Gathering and Disposal Agreement between Torch Energy Associates, Ltd. and Velasco.*

10.5 - Form of Texas Conveyance.*

10.6 - Form of Louisiana Conveyance.*

10.7 - Form of Alabama Conveyance.*

10.8 - Standby Performance Agreement between Torch and the Trust.*

10.9 - Amendment to Water Gathering Contract.*



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|       |  |                                                                                                                           
|------ |  | --------------------------------------------------------------------------------------------------------------------------
|10.10- |  | First Amendment to Oil and Gas Purchase Contract (previously filed on form 10-Q for the quarter ended September 30, 1994).



23. Consents of
Experts and Counsel.



|       |  |                                                   
|------ |  | --------------------------------------------------
|23.1 - |  | Consent of T.J. Smith & Company, Inc.             
|23.2 - |  | Consent of Netherland, Sewell and Associates, Inc.
|23.3 - |  | Consent of Ryder Scott Company, L.P.              



31. Rule
13a-14(a)/15d-14(a) Certifications.



|       |  |                                                                         
|------ |  | ------------------------------------------------------------------------
|31.1 - |  | Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.



32. Section 1350
Certifications.



|       |  |                                                                                                                                                    
|------ |  | ---------------------------------------------------------------------------------------------------------------------------------------------------
|32.1 - |  | Certification of Wilmington Trust Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.



99. Additional
Exhibits.



|     |  |                                                            
|---- |  | -----------------------------------------------------------
|99.1 |  | Financial Statements of Torch Energy Advisors Incorporated.



---

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



|(b) | Report on Form 8-K:
|--- | -------------------



None filed during the quarter ended December 31, 2003.



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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 TRUSTBy:

Wilmington Trust Company TrusteeBy:

/s/ Bruce L. BissonBruce L. Bisson, Vice President




Date: April 14, 2004



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







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