e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-Q
(Mark One)
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2005
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _________ to _________
Commission File Number: 1-12474
Torch Energy Royalty Trust
(Exact Name of Registrant as Specified in Its Charter)
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Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
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74-6411424
(I.R.S. Employer
Identification Number) |
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Rodney Square North
1100 North Market Street, Wilmington, Delaware
(Address of Principal Executive Offices)
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19890
(Zip Code) |
302/636-6016
(Registrants telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the Registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
As of June 30, 2005, 8.6 million Units of Beneficial Interest were outstanding.
TABLE OF CONTENTS
TORCH ENERGY ROYALTY TRUST
PART 1 FINANCIAL INFORMATION
Item I. Financial Statements
This document includes forward looking statements within the meaning of Section 27A of the
Securities Act of 1993, as amended, and Section 21E of the Securities Exchange Act of 1934. All
statements other than statements of historical facts included in this document, including without
limitation, statements under Discussion and Analysis of Financial Condition and Results of
Operations regarding the financial position, reserve quantities and net present values of reserves
of the Torch Energy Royalty Trust (Trust) and statements that include the words believe,
expects, anticipates, intends, estimates, projects, target, goal, plans,
objectives, should or similar expressions or variations are forward-looking statements. Torch
Energy Advisors Incorporated (Torch) and the Trust can give no assurances that the assumptions
upon which these statements are based will prove to be correct. Factors which could cause such
forward looking statements not to be correct include, among others, the cautionary statements set
forth in the Trusts Annual Report on Form 10-K\A filed with the Securities Exchange Commission for
the most recent fiscal year, cautionary statements contained in this report, the volatility of oil
and gas prices, future production costs, future oil and gas production quantities, operating
hazards, and environmental conditions.
Introduction
The financial statements included herein have been prepared by Torch, pursuant to an administrative
service agreement between Torch and the Trust, pursuant to the rules and regulations of the
Securities and Exchange Commission. Wilmington Trust Company serves as the trustee (Trustee) of
the Trust pursuant to the trust agreement dated October 1, 1993. Certain information and footnote
disclosures normally included in the annual financial statements have been omitted pursuant to such
rules and regulations, although Torch believes that the disclosures are adequate to make the
information presented not misleading. These financial statements should be read in conjunction
with the December 31, 2004 financial statements and notes thereto included in the Trusts annual
report on Form 10-K\A for the most recent fiscal year. In the opinion of Torch, all adjustments
necessary to present fairly the assets, liabilities and trust corpus of the Trust as of June 30,
2005 and December 31, 2004, the distributable income and changes in trust corpus for the
three-month and six-month periods ended June 30, 2005 and 2004 have been included. All such
adjustments are of a normal recurring nature. The distributable income for such interim periods is
not necessarily indicative of the distributable income for the full year.
The Trust has no officers, directors or employees. The Trustee relies solely on receiving accurate
information, reports and other representations from Torch in the ordinary course of its duties as Trustee. In executing and submitting this report on behalf of the
Trust and with respect to Bruce L. Bisson in executing the certifications relating to this report,
the Trustee and Bruce L. Bisson have relied upon the accuracy of such reports, information and
representations of Torch.
2
TORCH ENERGY ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
(In thousands)
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June 30, 2005 |
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December 31, 2004 |
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(Unaudited) |
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ASSETS |
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Cash |
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$ |
1 |
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$ |
1 |
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Net profits interests in oil and gas properties
(Net of accumulated amortization of $157,946 and
$156,800 at June 30, 2005 and December 31, 2004,
respectively) |
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22,654 |
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23,800 |
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$ |
22,655 |
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$ |
23,801 |
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LIABILITIES AND TRUST CORPUS |
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Trust expense payable |
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$ |
228 |
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$ |
245 |
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Trust corpus |
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22,427 |
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23,556 |
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$ |
22,655 |
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$ |
23,801 |
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See notes to financial statements.
3
TORCH ENERGY ROYALTY TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(In thousands, except per Unit amounts)
(Unaudited)
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Three Months Ended June 30, |
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Six Months Ended June 30, |
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2005 |
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2004 |
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2005 |
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2004 |
Net profits
income |
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$ |
1,110 |
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$ |
1,687 |
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$ |
2,947 |
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$ |
3,175 |
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Infill Well Net Proceeds |
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169 |
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0 |
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443 |
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0 |
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1,279 |
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1,687 |
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3,390 |
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3,175 |
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General and
administrative expenses |
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254 |
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242 |
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476 |
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426 |
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Distributable income |
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$ |
1,025 |
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$ |
1,445 |
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$ |
2,914 |
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$ |
2,749 |
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Distributable income per Unit
(8,600
Units) |
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$ |
.12 |
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$ |
.17 |
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$ |
.34 |
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$ |
.32 |
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Distributions per Unit |
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$ |
.12 |
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$ |
.17 |
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$ |
.34 |
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$ |
.33 |
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See notes to financial statements.
4
TORCH ENERGY ROYALTY TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(In thousands)
(Unaudited)
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Three Months Ended |
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Six Months Ended |
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June 30, |
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June 30, |
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2005 |
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2004 |
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2005 |
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2004 |
Trust corpus, beginning of period |
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$ |
22,972 |
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$ |
25,444 |
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$ |
23,556 |
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$ |
26,284 |
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Amortization of Net Profits Interests |
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(538 |
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(816 |
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(1,145 |
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(1,644 |
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Distributable income |
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1,025 |
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1,445 |
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2,914 |
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2,749 |
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Distributions to Unitholders |
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(1,032 |
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(1,488 |
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(2,898 |
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(2,804 |
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Trust corpus, end of period |
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$ |
22,427 |
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$ |
24,585 |
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$ |
22,427 |
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$ |
24,585 |
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See notes to financial statements.
5
Notes to Financial Statements
1. Trust Organization and Nature of Operations
The Trust was formed effective October 1, 1993 under the Delaware Business Trust Act pursuant to a
trust agreement (Trust Agreement) among Trustee, Torch Royalty Company (TRC), Velasco Gas
Company, Ltd. (Velasco), and Torch as grantor. TRC and Velasco created net profits interests
(Net Profits Interests), which burden certain oil and gas properties (Underlying Properties),
and conveyed such interests to Torch. Torch conveyed the Net Profits Interests to the Trust in
exchange for an aggregate of 8,600,000 units of beneficial interest (Units). Pursuant to an
administrative services agreement with the Trust, Torch provides accounting, bookkeeping,
informational and other services related to the Net Profits Interests.
The Underlying Properties constitute working interests in the Chalkley field in Louisiana
(Chalkley Field), the Robinsons Bend field in the Black Warrior Basin in Alabama (Robinsons
Bend Field), fields that produce from the Cotton Valley formations in Texas (Cotton Valley
Fields) and fields that produce from the Austin Chalk formation in Texas (Austin Chalk Fields).
The Underlying Properties represent interest in all productive formations from 100 feet below the
deepest productive formation in each field to the surface when the Trust was formed. The Trust
therefore has no interest in deeper formations.
The Trust will terminate upon the first to occur of (i) an affirmative vote of the holders of not
less than 66-2/3% of the outstanding Units to liquidate the Trust; (ii) such time as the ratio of
the cash amounts received by the Trust from the Net Profits Interests to administrative costs of
the Trust is less than 1.2 to 1.0 for three consecutive quarters; (iii) March 1 of any year if it
is determined based on a reserve report as of December 31 of the prior year that the present value
of estimated pre-tax future net cash flows, discounted at 10%, of proved reserves attributable to
the Net Profits Interests is equal to or less than $25.0 million; or (iv) December 31, 2012. As of
June 30, 2005, the Trust has not terminated, as none of the aforementioned events have occurred.
Upon termination of the Trust, the remaining assets of the Trust will be sold and the proceeds
therefrom (after expenses) will be distributed to the unitholders (Unitholders). The
sole purpose of the Trust is to hold the Net Profits Interests, to receive payments from TRC and
Velasco, and to make payments to Unitholders. The Trust does not conduct any business activity.
The only assets of the Trust, other than cash and temporary investments being held for the payment
of expenses and liabilities and for distribution to Unitholders, are the Net
6
Notes to Financial Statements
Profits Interests. The Net Profits Interests (other than the Net Profits Interest covering the
Robinsons Bend Field) entitle the Trust to receive 95% of the net proceeds (Net
Proceeds) attributable to oil and gas produced and sold from wells (other than infill wells) on
the Underlying Properties. Net Proceeds are generally defined as gross revenues received from the
sale of production attributable to the Underlying Properties during any period less property,
production, severance and similar taxes, and development, operating, and certain other costs. In
calculating Net Proceeds from the Robinsons 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 Robinsons Bend Field during any calendar
quarter are subject to a volume limitation (Volume Limitation) equal to the gross proceeds from
the sale of 912.5 MMcf of gas, less property, production, severance and related taxes and operating
and development costs subsequent to January 1, 2003. Since the fourth quarter of 1995, production
from the Underlying Properties in the Robinsons Bend Field has been less than the Volume
Limitation. See Note 2 to the financial statements for an explanation of the Trusts method of
accounting.
The Net Profits Interests also entitle the Trust to 20% of the Infill Well Net Proceeds (as defined
herein) of wells drilled on the Underlying Properties since the Trusts establishment into
formations in which the Trust has an interest, other than wells drilled to replace damaged or
destroyed wells (Infill Wells). Infill Well Net Proceeds represent the aggregate gross revenues
received from Infill Wells less the aggregate amount of the following Infill Well costs: (i)
property, production, severance and similar taxes; (ii) development costs; (iii) operating costs;
and (iv) interest on the recovered portion, if any, of the foregoing costs computed at the publicly
announced base rate of Citibank, N.A. in New York.
The Trusts website address is www.torchroyalty.com. The Trust provides access through this
website to its annual report on Form 10-K, quarterly reports on Form 10-Q
and any current reports on Form 8-K, and all amendments to those reports as soon as reasonably
practicable after these reports are filed or furnished electronically with the Securities and
Exchange Commission.
2. Basis of Accounting
The financial statements of the Trust are prepared on a modified cash basis and are not intended to
present the financial position and results of operations in conformity with
7
Notes to Financial Statements
generally accepted accounting principles (GAAP). Preparation of the Trusts financial statements
on such basis includes the following:
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Revenues are recognized in the period in which amounts are received by the Trust. Therefore, revenues recognized during
the three-month and six-month periods ended June 30, 2005 and 2004 are derived from oil and gas production sold during the
three-month and six-month periods ended March 31, 2005 and 2004, respectively. General and administrative expenses are
recognized on an accrual basis. |
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Amortization of the Net Profits Interests is calculated on a unit-of-production basis and charged directly to trust corpus. |
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Distributions to Unitholders are recorded when declared by the Trustee. |
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An impairment loss is recognized when the net carrying value of the Net Profits Interests exceeds its fair market value. No
impairment loss was recognized during the three-month and six-month periods ended June 30, 2005 and 2004. |
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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. |
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Estimates and assumptions have been made in preparing the financial statements of the Trust in order for the financial
statements to be in conformity with accounting principles generally accepted in the United States. |
3. Federal Income Taxes
Tax counsel has advised the Trustee that, under current tax law, the Trust is classified as a
grantor trust for Federal income tax purposes. However, the opinion of tax counsel is not binding
on the Internal Revenue Service. As a grantor trust, the Trust is not subject to Federal income
tax. Because the Trust is treated as a grantor trust for Federal income tax purposes and a
Unitholder is treated as directly owning an interest in the Net Profits Interests, each Unitholder
is taxed directly on such Unitholders pro rata share of income attributable to the Net Profits
Interests consistent with the Unitholders 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
8
Notes to Financial Statements
Interests are paid to the Trust on the quarterly record date established for quarterly
distributions in respect to each calendar quarter during the term of the Trust, and the income and
deductions resulting from such payments were allocated to the Unitholders of record on such date.
4. Distributions and Income Computations
Distributions are determined for each quarter and are based on the amount of cash available for
distribution to Unitholders. Such amount (the Quarterly Distribution Amount) is equal to the
excess, if any, of the cash received by the Trust, on the last day of the second month following
the previous calendar quarter (or the next business day thereafter) ending prior to the dissolution
of the Trust, from the Net Profits Interests then held by the Trust plus, with certain exceptions,
any other cash receipts of the Trust during such quarter, subject to adjustments for changes made
during such quarter in any cash reserves established for the payment of contingent or future
obligations of the Trust. Based on the payment procedures relating to the Net Profits Interests,
cash received by the Trust on the last day of the second month of a particular quarter from the Net
Profits Interests generally represents proceeds from the sale of oil and gas produced from the
Underlying Properties during the preceding calendar quarter. The Quarterly Distribution Amount for
each quarter is payable to Unitholders of record on the last day of the second month of the
calendar quarter unless such day is not a business day in which case the record date is the next
business day thereafter. The Quarterly Distribution Amount is distributed within approximately ten
days after the record date to each person who was a Unitholder of record on the associated record
date.
5. Related Party Transactions
Marketing Arrangements
TRC and Velasco contracted to sell the oil and gas production from the Underlying Properties to
Torch Energy Marketing, Inc. (TEMI), a subsidiary of Torch, under a purchase contract (Purchase
Contract). Under the Purchase Contract, TEMI is obligated to purchase all net production
attributable to the Underlying Properties for an index price for oil and gas (Index Price), less
certain gathering, treating and transportation charges, which are calculated monthly. The Index
Price equals 97% of the average spot market prices of oil and gas (Average Market Prices) at the
four locations where TEMI sells production.
The Purchase Contract also provides that the minimum price paid by TEMI for gas production is $1.70
per MMBtu adjusted annually for inflation (Minimum Price). When
9
Notes to Financial Statements
TEMI pays a purchase price based on the Minimum Price, it receives price credits (Price Credits),
equal to the difference between the Index Price and the Minimum Price that it is entitled to deduct
in determining the purchase price when the Index Price for gas exceeds the Minimum Price. No Price
Credits were deducted in calculating the purchase price related to distributions received by
Unitholders during the three-month and six-month periods ended June 30, 2005 and 2004. As of June
30, 2005, TEMI had no accumulated Price Credits.
In addition, if the Index Price for gas exceeds $2.10 per MMBtu adjusted annually for inflation
(Sharing Price), TEMI is entitled to deduct 50% of such excess (Price Differential) in
calculating the purchase price. As a result of such Sharing Price arrangement, Net Proceeds
attributable to the Underlying Properties during the six months ended June 30, 2005 and 2004 were
reduced by $4.2 million and $3.1 million, respectively. TEMI has an annual option to discontinue
the Minimum Price commitment. However, if TEMI discontinues the Minimum Price commitment, it will
no longer be entitled to deduct the Price Differential in calculating the purchase price and will
forfeit all accrued Price Credits. TEMI has not exercised its option to discontinue the Minimum
Price commitment. The Minimum Price for Underlying Property production during 2005 and 2004 were
$1.77 per MMBtu and $1.73 per MMBtu, respectively. The Sharing Price for Underlying Property
production during 2005 and 2004 was $2.18 per MMBtu and $2.13 per MMBtu, respectively.
Gross revenues (before deductions for applicable gathering, treating and transportation charges)
from TEMI included in the Net Proceeds calculations attributable to the Underlying Properties
during the quarters ended June 30, 2005 and 2004 were $4.2 million and $4.5 million, respectively.
Such gross revenues for the six-month periods ended June 30, 2005 and 2004 were $9.2 million and
$8.6 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 Robinsons 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 Robinsons Bend Field, TEMI is entitled to deduct a
gathering, treating and transportation fee of $0.26 per MMBtu adjusted for inflation ($0.298 and
$0.292 per MMBtu for 2005 and 2004 production, respectively), plus fuel usage equal to 5% of
revenues pursuant to a gas gathering agreement. Additionally, a fee of $0.05 per MMBtu,
representing a gathering fee payable to a non-affiliate of TEMI, is deducted in
10
Notes to Financial Statements
calculating the purchase price for production from 68 of 394 wells in the Robinsons Bend Field.
TEMI also deducts $0.38 per MMBtu plus 17% of revenues in calculating the purchase price for
production from the Austin Chalk Fields, as a fee to gather, treat and transport gas production.
From the purchase price for gas in the Cotton Valley Fields, TEMI deducts a transportation fee of
$0.045 per MMBtu for production attributable to certain wells. This transportation fee is paid to
a third party. During the three months ended June 30, 2005 and 2004, such fees deducted from the
Net Proceeds calculations, attributable to production during the three-month periods ended March
31, 2005 and 2004, in the Robinsons Bend, Austin Chalk and Cotton Valley Fields, totaled $0.4
million and $0.3 million, respectively. During the six months ended June 30, 2005 and 2004, such
fees deducted from the Net Proceeds calculations, attributable to production during the six-month
periods ended March 31, 2005 and 2004, in the Robinsons Bend, Austin Chalk and Cotton Valley
Fields, totaled $0.8 million and $0.7 million, respectively. No amounts for gathering, treating or
transportation are deducted in calculating the purchase price from the Chalkley Field.
Administrative Services Agreement
Pursuant to the Trust Agreement, Torch and the Trust entered into an administrative services
agreement effective October 1, 1993. The Trust is obligated, throughout the term of the Trust, to
pay to Torch each quarter an administrative services fee for accounting, bookkeeping, informational
and other services relating to the Net Profits Interests. The amount of the administrative services
fee is adjusted annually based upon the change in the Producers Price Index as published by the
Department of Labor, Bureau of Labor Statistics. Administrative services during the three-month
periods ended June 30, 2005 and 2004 were $100,000 and $98,000, respectively. During the six-month
periods ended June 30, 2005 and 2004, such fees were $200,000 and $196,000 respectively.
Operator Overhead Fees
A subsidiary of Torch operates certain oil and gas interests burdened by the Net Profits Interests.
The Underlying Properties are charged, on the same basis as other third parties, for all customary
expenses and costs reimbursements associated with these activities. Operator overhead fees
deducted from the Net Proceeds computations for the Chalkley, Cotton Valley and Austin Chalk Fields
totaled $46,000 and $44,000, respectively, for the three-month periods ended June 30, 2005 and
2004. During the six-month periods ended June 30, 2005 and 2004, such operator overhead fees were
$91,000 and $88,000, respectively.
11
Notes to Financial Statements
Compensation of the Trustee and Transfer Agent
The Trust Agreement provides that the Trustee is compensated for its administrative services, out
of the Trust assets, in an annual amount of $41,000, plus an hourly charge for services in excess
of a combined total of 250 hours annually at its standard rate. The Trustee receives a transfer
agency fee of $5.00 annually per account (minimum of $15,000 annually), subject to change for
inflation each December, based upon the change in the Producers Price Index as published by the
Department of Labor, Bureau of Labor Statistics, plus $1.00 for each certificate issued.
Total administrative and transfer agent fees during the three-month periods ended June 30, 2005 and
2004 were $14,000 per period. Such fees during the six-month periods ended June 30, 2005 and 2004
were $28,000 per period. The Trustee is also entitled to reimbursement for out-of-pocket expenses.
12
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
Because a modified cash basis of accounting is utilized by the Trust, Net Proceeds attributable to
the Underlying Properties for the three months ended June 30, 2005 and 2004 is derived from actual
oil and gas produced during the three months ended March 31, 2005 and 2004, respectively. Net
Proceeds attributable to the Underlying Properties for the six months ended June 30, 2005 and 2004
is derived from oil and gas produced during the six months ended March 31, 2005 and 2004,
respectively. Oil and gas sales attributable to the Underlying Properties for such periods are as
follows:
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Three Months Ended June 30, |
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2005 |
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2004 |
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Bbls |
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Mcf |
|
Bbls |
|
Mcf |
|
|
of Oil |
|
of Gas |
|
of Oil |
|
of Gas |
Chalkley Field |
|
|
1,279 |
|
|
|
287,474 |
|
|
|
1,760 |
|
|
|
384,435 |
|
Robinsons Bend Field |
|
|
|
|
|
|
442,503 |
|
|
|
|
|
|
|
477,896 |
|
Cotton Valley Fields |
|
|
736 |
|
|
|
172,568 |
|
|
|
546 |
|
|
|
221,574 |
|
Austin Chalk Fields |
|
|
3,515 |
|
|
|
43,168 |
|
|
|
4,547 |
|
|
|
30,297 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,530 |
|
|
|
945,713 |
|
|
|
6,853 |
|
|
|
1,114,202 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
2005 |
|
2004 |
|
|
Bbls |
|
Mcf |
|
Bbls |
|
Mcf |
|
|
of Oil |
|
of Gas |
|
of Oil |
|
of Gas |
Chalkley Field |
|
|
2,707 |
|
|
|
620,862 |
|
|
|
3,604 |
|
|
|
789,308 |
|
Robinsons Bend Field |
|
|
|
|
|
|
910,699 |
|
|
|
|
|
|
|
975,959 |
|
Cotton Valley Fields |
|
|
1,050 |
|
|
|
356,705 |
|
|
|
1,094 |
|
|
|
438,329 |
|
Austin Chalk Fields |
|
|
7,914 |
|
|
|
92,418 |
|
|
|
8,337 |
|
|
|
58,447 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,671 |
|
|
|
1,980,684 |
|
|
|
13,035 |
|
|
|
2,262,043 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2005 Compared to Three Months Ended June 30, 2004
For the three months ended June 30, 2005, net profits income was $1.1 million, down 35% from net
profits income of $1.7 million for the same period in 2004. Such decrease is mainly attributable
to normal production declines which were partially offset by higher oil and gas prices paid to the
Trust during the quarter ended June 30, 2005.
13
Gas production attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin
Chalk Fields was 503,210 Mcf and 636,306 Mcf during the quarters ended March 31, 2005 and 2004,
respectively. Gas production attributable to the Underlying Properties in the Robinsons Bend Field
was 442,503 Mcf and 477,896 Mcf during the quarters ended March 31, 2005 and 2004, respectively.
Gas production decreased during 2005 as a result of normal production declines. Oil production
attributable to the Underlying Properties for the quarters ended March 31, 2005 and March 31, 2004
was 5,530 Bbls and 6,853 Bbls, respectively.
During the three months ended June 30, 2005, the average price used to calculate Net Proceeds for
gas, before gathering, treating and transportation deductions, was $4.07 per MMBtu as compared to
$3.81 per MMBtu for the three months ended June 30, 2004. During the quarter ended June 30, 2005,
the average price used to calculate Net Proceeds for oil was $43.80 as compared to $29.01 per Bbl
for the quarter ended March 31, 2004. When TEMI pays a purchase price for gas based on the Minimum
Price ($1.77 per MMBtu and $1.73 per MMBtu for 2005 and 2004 production, respectively), TEMI
receives Price Credits which it is entitled to deduct in determining the purchase price when the
Index Price for gas exceeds the Minimum Price. No Price Credits were deducted in calculating the
purchase price related to distributions received by Unitholders during the quarters ended June 30,
2005 and 2004. As of June 30, 2005, TEMI had no accumulated Price Credits. Additionally, if the
Index Price for gas exceeds the Sharing Price ($2.18 per MMBtu and $2.13 per MMBtu for 2005 and
2004 production, respectively), TEMI is entitled to deduct 50% of such excess in calculating the
purchase price. The deduction of the Price Differential in calculating the purchase price had the
effect of reducing distributions received by Unitholders during each of the three-month periods
ended June 30, 2005 and 2004 by $1.8 million.
During the quarter ended June 30, 2005, the Trust distributed approximately $169,000 of Infill Well
Net Proceeds pertaining to oil and gas sales during the quarter ended December 31, 2004. Such
Infill Wells are located in the Cotton Valley Fields and are operated by Samson Lone Star Limited
Partnership. The Trust did not receive any proceeds pertaining to such wells during the quarter
ended June 30, 2004.
Lease operating expenses and capital expenditures attributable to the Underlying Properties in the
Chalkley, Cotton Valley and Austin Chalk Fields deducted in calculating distributions during the
quarters ended June 30, 2005 and 2004 totaled $1.0 million and $0.7 million, respectively. Such
increase in costs and expenses during 2005 is mainly attributable to the installation of
compressors in the Chalkley Field. With respect to the Robinsons Bend Field, lease operating
expenses and capital expenditures of $1.6 million and $1.5 million were deducted in calculating the
Net Proceeds payable to the Trust from the Robinsons Bend Field for the three-month periods ended
June 30, 2005 and 2004, respectively.
14
General and administrative expenses amounted to $0.3 million and $0.2 million, respectively, for
the three-month periods ending June 30, 2005 and 2004. These expenses primarily relate to
administrative services provided by Torch and the Trustee, and legal fees.
The foregoing resulted in distributable income of $1.0 million, or $.12 per Unit, for the three
months ended June 30, 2005, as compared to $1.4 million, or $.17 per Unit, for the same period in
2004. Cash distributions of $1.0 million, or $0.12 per Unit, were made during the quarter ended
June 30, 2005 as compared to $1.5 million, or $0.17 per Unit, for the same period in 2004.
Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004
For the six months ended June 30, 2005, net profits income was $2.9 million, down 9% from net
profits income of $3.2 million for the same period in 2004. Such decrease is mainly attributable
to a decrease in gas production as a result of normal production declines which were partially
offset by higher oil and gas prices paid to the Trust during the six months ended June 30, 2005.
Gas production attributable to the Underlying Properties in the Chalkley, Cotton Valley and Austin
Chalk Fields was 1,069,985 Mcf and 1,286,084 Mcf during the six months ended March 31, 2005 and
2004, respectively. Gas production attributable to the Underlying Properties in the Robinsons Bend
Field was 910,699 Mcf and 975,959 Mcf during the six months ended March 31, 2005 and 2004,
respectively. Gas production decreased during 2005 mainly as a result of normal production
declines. Oil production
attributable to the Underlying Properties for the six months ended March 31, 2005 and March 31,
2004 was 11,671 Bbls and 13,035 Bbls, respectively.
During the six months ended June 30, 2005, the average price used to calculate Net Proceeds for
gas, before gathering, treating and transportation deductions, was $4.18 per MMBtu as compared to
$3.52 per MMBtu for the six months ended June 30, 2004. During the six months ended June 30, 2005,
the average price used to calculate Net Proceeds for oil was $42.53 as compared to $27.33 per Bbl
for the six months ended June 30, 2004. When TEMI pays a purchase price for gas based on the
Minimum Price ($1.77 per MMBtu and $1.73 per MMBtu for 2005 and 2004 production, respectively),
TEMI receives Price Credits which it is entitled to deduct in determining the purchase price when
the Index Price for gas exceeds the Minimum Price. No Price Credits were deducted in calculating
the purchase price related to distributions received by Unitholders during the six-month periods
ended June 30, 2005 and 2004. As of June 30, 2005, TEMI had no accumulated Price Credits.
Additionally, if the Index Price for gas exceeds the Sharing Price ($2.18 per MMBtu and $2.13 per
MMBtu for 2005 and 2004 production, respectively), TEMI is entitled to deduct 50% of such excess in
calculating the purchase price. The deduction of the Price Differential in calculating the
15
purchase price had the effect of reducing distributions received by Unitholders during the six
months ended June 30, 2005 and 2004 by $4.2 million and $3.1 million, respectively.
During the six months ended June 30, 2005, the Trust distributed approximately $443,000 of Infill
Well Net Proceeds pertaining to oil and gas sales during the six months ended December 31, 2004.
Such Infill Wells are located in the Cotton Valley Fields and are operated by Samson Lone Star
Limited Partnership. The Trust did not receive any proceeds pertaining to such wells during the
quarter ended June 30, 2004.
Lease operating expenses and capital expenditures attributable to the Underlying Properties in the
Chalkley, Cotton Valley and Austin Chalk Fields deducted in calculating distributions during the
six months ended June 30, 2005 and 2004 totaled $1.6 million and $1.3 million, respectively. Such
increase in costs and expenses during 2005 is mainly attributable to the installation of
compressors in the Chalkley Field.
With respect to the Robinsons Bend Field, lease operating expenses and capital expenditures of
$3.8 million and $3.0 million were deducted in calculating the Net Proceeds payable to the Trust
from the Robinsons Bend Field during the six-month periods ended June 30, 2005 and 2004,
respectively. The increase in costs and expenses in 2005 is due to capital expenditures pertaining
to certain gas well workovers performed by the operator of the Robinsons Bend Field, Everlast
Energy LLC.
General and administrative expenses amounted to $0.5 million and $0.4 million for the six-month
periods ending June 30, 2005 and 2004, respectively. These expenses primarily relate to
administrative services provided by Torch and the Trustee and legal fees.
The foregoing resulted in distributable income of $2.9 million, or $.34 per Unit, for the six
months ended June 30, 2005, as compared to $2.7 million, or $.32 per Unit, for the same period in
2004. Cash distributions of $2.9 million, or $0.34 per Unit, were made during the six months ended
June 30, 2005 as compared to $2.8 million, or $0.33 per Unit, for the same period in 2004.
Net profits income received by the Trust during the three and six month periods ended June 30,
2005 and 2004, derived from production sold during the three and six months ended March 31, 2005
and 2004, respectively, was computed as shown in the following table (in thousands):
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2005 |
|
Three Months Ended June 30, 2004 |
|
|
Chalkley, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cotton |
|
|
|
|
|
|
|
|
|
Chalkley, |
|
|
|
|
|
|
Valley and |
|
|
|
|
|
|
|
|
|
Cotton Valley |
|
|
|
|
|
|
Austin Chalk |
|
Robinsons |
|
|
|
|
|
and Austin |
|
Robinsons |
|
|
|
|
Fields |
|
Bend Field |
|
Total |
|
Chalk Fields |
|
Bend Field |
|
Total |
Oil and gas revenues |
|
$ |
2,289 |
|
|
$ |
1,591 |
|
|
$ |
3,880 |
|
|
$ |
2,634 |
|
|
$ |
1,587 |
|
|
$ |
4,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses and
property tax |
|
|
541 |
|
|
|
1,480 |
|
|
|
2,021 |
|
|
|
469 |
|
|
|
1,453 |
|
|
|
1,922 |
|
Severance tax |
|
|
170 |
|
|
|
136 |
|
|
|
306 |
|
|
|
160 |
|
|
|
134 |
|
|
|
294 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
711 |
|
|
|
1,616 |
|
|
|
2,327 |
|
|
|
629 |
|
|
|
1,587 |
|
|
|
2,216 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds before capital
Expenditures |
|
|
1,578 |
|
|
|
(25 |
) |
|
|
1,553 |
|
|
|
2,005 |
|
|
|
0 |
|
|
|
2,005 |
|
Capital expenditures |
|
|
410 |
|
|
|
169 |
|
|
|
579 |
|
|
|
229 |
|
|
|
62 |
|
|
|
291 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds |
|
|
1,168 |
|
|
|
(194 |
) |
|
|
974 |
|
|
|
1,776 |
|
|
|
(62 |
) |
|
|
1,714 |
|
Net profits percentage |
|
|
95 |
% |
|
|
|
|
|
|
|
|
|
|
95 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net profits income |
|
$ |
1,110 |
|
|
$ |
|
|
|
$ |
1,110 |
|
|
$ |
1,687 |
|
|
$ |
|
|
|
$ |
1,687 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2005 |
|
Six Months Ended June 30, 2004 |
|
|
Chalkley, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cotton |
|
|
|
|
|
|
|
|
|
Chalkley, |
|
|
|
|
|
|
Valley and |
|
|
|
|
|
|
|
|
|
Cotton Valley |
|
|
|
|
|
|
Austin Chalk |
|
Robinsons |
|
|
|
|
|
and Austin |
|
Robinsons |
|
|
|
|
Fields |
|
Bend Field |
|
Total |
|
Chalk Fields |
|
Bend Field |
|
Total |
Oil and gas revenues |
|
$ |
5,035 |
|
|
$ |
3,425 |
|
|
$ |
8,460 |
|
|
$ |
4,937 |
|
|
$ |
3,000 |
|
|
$ |
7,937 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses and
property tax |
|
|
1,112 |
|
|
|
2,988 |
|
|
|
4,100 |
|
|
|
898 |
|
|
|
2,851 |
|
|
|
3,749 |
|
Severance tax |
|
|
363 |
|
|
|
303 |
|
|
|
666 |
|
|
|
309 |
|
|
|
242 |
|
|
|
551 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,475 |
|
|
|
3,291 |
|
|
|
4,766 |
|
|
|
1,207 |
|
|
|
3,093 |
|
|
|
4,300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds before capital
expenditures |
|
|
3,560 |
|
|
|
134 |
|
|
|
3,694 |
|
|
|
3,730 |
|
|
|
(93 |
) |
|
|
3,637 |
|
Capital expenditures |
|
|
458 |
|
|
|
776 |
|
|
|
1,234 |
|
|
|
388 |
|
|
|
119 |
|
|
|
507 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds |
|
|
3,102 |
|
|
|
(642 |
) |
|
|
2,460 |
|
|
|
3,342 |
|
|
|
(212 |
) |
|
|
3,130 |
|
Net profits percentage |
|
|
95 |
% |
|
|
|
|
|
|
|
|
|
|
95 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net profits income |
|
$ |
2,947 |
|
|
$ |
|
|
|
$ |
2,947 |
|
|
$ |
3,175 |
|
|
$ |
|
|
|
$ |
3,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proceeds Attributable to the Robinsons Bend Field Have Declined Significantly
Prior to December 31, 2002, lease operating expenses and capital expenditures were not deducted in
calculating the Net Proceeds payable to the Trust from the Robinsons Bend Field. In accordance
with the provisions of the net profits interest conveyance covering the Robinsons Bend Field,
commencing with the second quarter of 2003 distribution (pertaining to the quarter ended March 31,
2003 production) lease operating expenses and capital expenditures have been deducted in
calculating Net Proceeds. The Trust received no payments with respect to the Robinsons Bend Field
during the
17
six-month periods ended June 30, 2005 and June 30, 2004 (pertaining to production during
the six-month periods ended March 31, 2005 and March 31, 2004). During the six-month periods ended
June 30, 2005 and June 30, 2004, Robinsons Bend Field costs and expenses exceeded net revenues by
approximately $642,000 and $212,000, respectively. The Trust will receive no payments with respect
to the Robinsons Bend Field until future proceeds exceed the sum of costs and expenses and the
cumulative Robinsons Bend Field costs and expenses including interest (Robinsons Bend Field
Cumulative Deficit). As of June 30, 2005 (pertaining to production through March 31, 2005), the
Robinsons Bend Field Cumulative Deficit was approximately $1.1 million. Torch does not anticipate
that the Net Proceeds attributable to the Robinsons Bend Field, if any, will be significant in the
future.
Volatility of Oil and Gas Prices
The Trusts 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 Trusts revenues, cash distributions and value of the
Net Profits Interests.
Uncertainty of Estimates of Reserves and Future Net Cash Flows
Estimates of economically recoverable oil and gas reserves and of future net cash flows are based
upon a number of variable factors and assumptions, all of which are to some degree speculative and
may vary considerably from actual results. Therefore, actual production, revenues, taxes and
development and operation expenditures may not occur as estimated. Future results of the Trust will
depend upon the ability of the owners of the Underlying Properties to develop, produce and sell
their oil and natural gas reserves. The reserve data are estimates only and are subject to many
uncertainties. Actual quantities of oil and natural gas may differ considerably from the amounts
set forth herein. In addition, different reserve engineers may make different estimates of reserve
quantities and cash flows based upon the same available data. The present value, discounted at 10%,
of future net cash flows from proved reserves attributable to the Net Profits Interests does not
represent the fair market value of the proved reserves, or the price at which the Net Profits
Interests could be sold. A determination of fair market value would involve consideration of many
factors in
18
addition to the present value, discounted at 10%. An impairment loss is recognized when
the net carrying value of the Net Profits Interests exceeds its fair market value. No impairment
loss was recognized during the three-month and six-month periods ended June 30, 2005 and 2004.
Operating Risks
Cash payments to the Trust are derived from the production and sale of oil and gas, which
operations are subject to risk inherent in such activities, such as blowouts, cratering,
explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other
environmental risks. These risks could result in substantial losses which are deducted in
calculating the Net Proceeds paid to the Trust due to injury and loss of life, severe damage to and
destruction of property and equipment, pollution and other environmental damage and suspension of
operations.
Competition and Markets
The Trusts distributions are dependent on gas production and prices and, to a lesser extent, oil
production and prices from the Underlying Properties. The gas industry is highly competitive in all
of its phases. In marketing production from the Underlying Properties, TEMI encounters competition
from major gas companies, independent gas concerns, and individual producers and operators. Many of
these competitors have greater financial and other resources than TEMI. Competition may also be
presented by alternative fuel sources, including heating oil and other fossil fuels.
Market prices are typically volatile as a result of uncertainties caused by world events. Demand
for natural gas production has historically been seasonal in nature, and prices for gas fluctuate
accordingly. Such price fluctuations will directly impact Trust distributions, estimated reserve
attributable to the Trust and estimated future net revenues from Trust reserves.
Regulation of Natural Gas
The production, transportation and sale of natural gas from the Underlying Properties are subject
to Federal and state governmental regulation, including regulation of tariffs charged by pipelines,
taxes, the prevention of waste, the conservation of gas, pollution controls and various other
matters. The United States has governmental power to impose pollution control measures.
19
Federal Regulation
The Underlying Properties will be subject to the jurisdiction of FERC with respect to various
aspects of gas operations including the marketing and production of gas. The Natural Gas Act and
the Natural Gas Policy Act (collectively, the Acts) mandate Federal regulation of interstate
transportation of gas. The Natural Gas Wellhead Decontrol Act of 1989 terminated wellhead price
controls on all domestic gas on January 1, 1993. Numerous questions have been raised concerning the
interpretation and implementation of several significant provisions of the Acts and of the
regulations and policies promulgated by FERC thereunder. A number of lawsuits and administrative
proceedings have been instituted which challenge the validity of regulations implementing the Acts.
In addition, FERC currently has under consideration various policies and proposals that may affect
the marketing of gas under new and existing contracts. Accordingly, Torch is unable to predict the
impact of any such government regulation.
In the past, Congress has been very active in the area of gas regulation. Recently enacted
legislation repeals incremental pricing requirements and gas use restraints previously applicable.
At the present time, it is impossible to predict what proposals, if any, might actually be enacted
by Congress or the various state legislatures and what effect, if any, such proposals might have on
the Underlying Properties and the Trust.
State Regulation
Many state jurisdictions have at times imposed limitations on the production of gas by restricting
the rate of flow for gas wells below their actual capacity to produce and by imposing acreage
limitations for the drilling of a well. States may also impose additional regulations of these
matters. Most states regulate the production of gas, including requirements for obtaining drilling
permits, the method of developing new fields, provisions for the unitization or pooling of gas
properties, the spacing, operation, plugging and abandonment of wells and the prevention of waste
of gas resources. The rate of production may be regulated and the maximum daily production
allowable from gas wells may be established on a market demand or conservation basis or both.
Environmental Regulation
Activities on the Underlying Properties are subject to existing Federal, state and local laws,
rules and regulations relating to the protection of public health and welfare, safety and the
environment, including, without limitation, laws regulating the release of materials into the
environment and laws protecting areas of particular environmental concern. It is anticipated that,
absent the occurrence of an unanticipated event, compliance with these laws will not have a
material adverse effect upon the Trust or Unitholders. Torch has informed the Trust that it cannot
predict what effect future regulation or legislation, enforcement policies thereunder, and claims
for damages to property, employees, other persons and the environment resulting from operations on
20
the Underlying Properties could have on the Trust or Unitholders. However, pursuant to the terms of
the Conveyances, any costs or expenses incurred by TRC or Velasco in connection with environmental
liabilities, to the extent arising out of or relating to activities occurring on, or in connection
with, or conditions existing on or under, the Underlying Properties before October 1, 1993, will be
borne by TRC or Velasco and not the Trust and will not be deducted in calculating Net Proceeds and
will, therefore, not reduce amounts payable to the Trust.
Termination of the Trust
The Trust will terminate on March 1 of any year if it is determined that the pre-tax future net
cash flows, discounted at 10%, attributable to the estimated net proved reserves of the Net Profits
Interests on the preceding December 31 are less than $25.0 million. The
pre-tax future net cash flows, discounted at 10%, attributable to estimated net proved reserves of
the Net Profits Interests as of December 31, 2004 was approximately $39.0 million. Such reserve
report was prepared pursuant to Securities and Exchange Commission guidelines and utilized an
unescalated Purchase Contract price (after gathering, treating and transportation fees) of $4.18
per Mcf. The computation of the $4.18 per Mcf Purchase Contract price was based on an unescalated
Henry Hub spot price for natural gas on December 31, 2004 of $6.18 per MMBtu. The December 31, 2004
reserve value was greater than $25.0 million. Therefore, the Trust did not terminate on March 1,
2005. Based on oil and gas reserve estimates at December 31, 2004 prepared by independent reserve
engineers, Torch projects that unless the Henry Hub spot price for natural gas on December 31, 2005
exceeds approximately $4.50 per MMBtu, the Trust will terminate on March 1, 2006. Upon termination
of the Trust, the Trustee is required to sell the Net Profits Interests. No assurances can be given
that the Trustee will be able to sell the Net Profits Interests, or the price that will be
distributed to Unitholders following such a sale. Such distributions could be below the market
price of the Units.
Financial Condition of the Administrative Service Provider to the Trust
Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its
subsidiaries is a party to that certain Administrative Services Agreement whereby Torch Energy
Advisors Incorporated (the administrative service provider of the Trust) and its subsidiaries
provides certain administrative and related services to the Trust. See Item 13 Administrative
Services Agreement of the Form 10-K/A for the period ended December 31, 2004. TEMI, a subsidiary of
Torch Energy Advisors Incorporated (the administrative service provider of the Trust) and its
subsidiaries, is a party to the Purchase Contract. If Torch Energy Advisors Incorporated (the
administrative service provider of the Trust) and its subsidiaries or TEMI were to become unable to
meet their obligations to the Trust, such inability might have a material adverse effect on the
operations of the Trust.
21
Item 3. Quantitative and Qualitative Disclosures about Market Risk
The Trust is exposed to market risk, including adverse changes in commodity prices. The Trusts
assets constitute Net Profits Interests in the Underlying Properties. As a result, the Trusts
operating results can be significantly affected by fluctuations in commodity prices caused by
changing market forces and the price received for production from the Underlying Properties.
All production from the Underlying Properties is sold pursuant to a Purchase Contract between TRC,
Velasco and TEMI. Pursuant to the Purchase Contract, TEMI is obligated to purchase all net
production attributable to the Underlying Properties for an
Index Price, less certain other charges, which are calculated monthly. The Index Price calculation
is based on market prices of oil and gas and therefore is subject to commodity price risk. The
Purchase Contract expires upon termination of the Trust and provides a Minimum Price paid by TEMI
for gas. The Minimum Price is adjusted annually for inflation and was $1.77 per MMBtu and $1.73 per
MMBtu for 2005 and 2004 production, respectively. When TEMI pays a purchase price based on the
Minimum Price, it receives Price Credits equal to the difference between the Index Price and the
Minimum Price that it is entitled to deduct when the Index Price exceeds the Minimum Price.
Additionally, if the Index Price exceeds the Sharing Price, TEMI is entitled to deduct such excess,
the Price Differential. The Sharing Price was $2.18 per MMBtu and $2.13 per MMBtu for 2005 and
2004 production, respectively. TEMI has an annual option to discontinue the Minimum Price
commitment. However, if TEMI discontinues the Minimum Price commitment, it will no longer be
entitled to deduct the Price Differential and will forfeit all accrued Price Credits. TEMI has not
exercised its option to discontinue the Minimum Price Commitment.
22
Item 4. Controls and Procedures
Based on their evaluation as of the end of the period covered by this quarterly report on Form
10-Q, the Trustee has concluded that the Trusts disclosure controls and procedures (as defined in
Rules 13a-15(e) and 15d-15(e) under the Securities and Exchange Act of 1934 were effective as of
the end of the period covered by this quarterly report on Form 10-Q. In its evaluation of
disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on
information provided by Torch.
There were no significant changes in the Trusts internal control over financial reporting during
the Trusts last fiscal quarter that have materially affected, or are reasonably likely to
materially affect, the Trusts internal control over financial reporting.
23
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
None.
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
ITEM 3. Defaults upon Senior Securities
None.
ITEM 4. Submission of Matters to a Vote of Unitholders
None.
ITEM 5. Other Information
None
ITEM 6. Exhibits
(a) Exhibits
4. Instruments of defining the rights of security holders, including indentures.
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4.1 |
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Form of Torch Energy Royalty Trust Agreement. * |
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4.2 |
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Form of Louisiana Trust Agreement. * |
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4.3 |
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Specimen Trust Unit Certificate. * |
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4.4 |
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Designation of Ancillary Trustee. * |
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31.1 |
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Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.** |
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32.1 |
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Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.** |
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* |
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Incorporated by reference from Registration Statements on Form S-1 of Torch Energy
Advisors Incorporated (Registration No. 33-68688) dated November 16, 1993. |
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** |
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Furnished herewith. |
24
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.
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TORCH ENERGY ROYALTY TRUST |
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By: Wilmington Trust Company, not in its |
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individual capacity but solely as Trustee |
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for the Trust |
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By:
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/s/ Bruce L. Bisson |
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Bruce L. Bisson |
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Vice President |
Date: August 12, 2005
(The Trust has no employees, directors or executive officers.)
25
Index to Exhibit
|
4.1 |
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Form of Torch Energy Royalty Trust Agreement. * |
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4.2 |
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Form of Louisiana Trust Agreement. * |
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4.3 |
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Specimen Trust Unit Certificate. * |
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4.4 |
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Designation of Ancillary Trustee. * |
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31.1 |
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Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.** |
|
|
32.1 |
|
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.** |
|
|
|
* |
|
Incorporated by reference from Registration Statements on Form S-1 of Torch Energy
Advisors Incorporated (Registration No. 33-68688) dated November 16, 1993. |
|
** |
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Furnished herewith. |
26