<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(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, 1998
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
TORCH ENERGY ROYALTY TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
Delaware 74-6411424
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1100 North Market Street, Wilmington, Delaware 19890
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (302) 651-8775
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
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 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 value of outstanding units of beneficial interest of the
registrant held by non-affiliates of the registrant at March 10, 1999 was
approximately $39,237,500.
<PAGE>
TORCH ENERGY ROYALTY TRUST
Annual Report on Form 10-K
For the fiscal year ended December 31, 1998
TABLE OF CONTENTS
Page
Number
------
PART I
Item 1. Business............................................... 3
Item 2. Properties............................................. 8
Item 3. Legal Proceedings...................................... 11
Item 4. Submission of Matters to a Vote of Unitholders......... 11
PART II
Item 5. Market for Registrant's Units and Related
Unitholder Matters..................................... 12
Item 6. Selected Financial Data................................ 12
Item 7. Discussion and Analysis of Financial Condition and
Results of Operations.................................. 12
Item 7a. Quantitative and Qualitative Disclosures About
Market Risk............................................ 18
Item 8. Financial Statements and Supplementary Data............ 19
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................... 33
PART III
Item 10. Directors and Executive Officers of the Registrant..... 33
Item 11. Executive Compensation................................. 33
Item 12. Security Ownership of Certain Beneficial Owners
and Management......................................... 33
Item 13. Certain Relationships and Related Transactions......... 34
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K.................................... 36
--- Signatures
2
<PAGE>
TORCH ENERGY ROYALTY TRUST
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 (the "Securities Act"),
and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"). 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
and estimated quantities and net present values of reserves of the Torch Energy
Royalty Trust ("Trust") 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") and Velasco Gas
Company Ltd. ("Velasco") as owners of certain oil and gas properties
("Underlying Properties") and 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. 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 not terminate prior to January 1, 2003, except upon the
affirmative vote of the holders of not less than 80% of the outstanding Units.
Thereafter, 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 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, as owners of the Underlying Properties subject to and burdened
by the Net Profits Interests, contracted to sell the oil and gas production from
such 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.
3
<PAGE>
TORCH ENERGY ROYALTY TRUST
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.
Other clients of Torch also own interests in oil and gas properties located in
the same geographic areas as the Underlying Properties and own interests in
certain of the same wells, which interests are not burdened by the Net Profits
Interests.
Sales of coal seam and tight sands gas attributable to the Net Profits Interests
prior to January 1, 2003 result in Unitholders receiving quarterly allocations
of tax credits under Section 29 of the Internal Revenue Code of 1986 ("Section
29 Credit"). In 1998, 1997, and 1996, the Section 29 Credit available for
production from qualifying coal seam properties was approximately $1.06, $1.05
and $1.03, respectively, for each MMBtu of gas produced and sold. This rate is
adjusted annually for inflation. The Section 29 Credit available for production
from qualifying tight sands properties is approximately $0.52 for each MMBtu of
gas produced and sold and such amount is not adjusted for inflation.
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 until 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. Because
development and operating costs generally are deducted in computing Net
Proceeds, such costs will affect the amounts paid to the Trust from the Net
Profits Interests. 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 97% of the average spot
market prices of oil and gas ("Average Market Prices") at the four locations
where TEMI sells production, which, prior to September 1, 2000, is adjusted to
reflect the terms of a hedge contract ("Hedge Contract") to which TEMI is a
party. Under the Hedge Contract, TEMI receives prices specified in the Hedge
Contract ("Specified Prices") for quantities of oil and gas specified therein
("Specified Quantities"). In calculating the Index Price for gas (which
represents approximately 97% of the estimated reserves as of January 1, 1999, on
a net equivalent Mcf of gas ("Mcfe") basis), the Specified Prices received
weightings ranging from approximately 40% to 70% pertaining to production prior
to August 31, 1997. Thereafter, the Specified Prices receive a weighting of
approximately 10% and less. The Average Market Prices receive the balance of the
weighting. The Specified Prices for gas increase each year from $1.83 per MMBtu
in 1996 to $1.89 per MMBtu in 2000 and are adjusted to reflect the difference
between the settlement prices for oil and gas in the futures markets and the
Average Market Prices.
4
<PAGE>
TORCH ENERGY ROYALTY TRUST
The Purchase Contract also provides that the minimum price paid by TEMI for gas
production is $1.70 per MMBtu ("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. In addition, if the Index Price for gas exceeds
$2.10 per MMBtu, TEMI is entitled to deduct 50% of such excess ("Price
Differential") in determining the purchase price. Beginning January 1, 2001,
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 purchased contracts granting TEMI
the right to sell estimated gas production in excess of the Specified Quantities
at a price intended to limit TEMI's losses in the event the Index Price falls
below the Minimum Price.
Gas production is purchased at the wellhead and, 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 ($0.274 for 1998 and 1997, and $0.272 per MMBtu for
1996, 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, 1998, 1997 and 1996,
gathering, treating and transportation fees charged to the Trust by TEMI,
attributable to production during the twelve months ended September 30, 1998,
1997 and 1996 in the Robinson's Bend, Austin Chalk and Cotton Valley Fields,
totaled $1,650,000, $1,965,000 and $2,137,000, 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 are 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 three years ended December 31, 1998 and is not
expected to do so in the future.
The Net Profits Interests also entitle the Trust to 20% of the Net Proceeds
(defined below) of wells drilled on the Underlying Properties since the Trust's
establishment into formations in which the Trust has an
5
<PAGE>
TORCH ENERGY ROYALTY TRUST
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.
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 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 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. An impairment loss is recognized when the net carrying value of
the Net Profits Interests exceeds the sum of the estimated undiscounted future
cash flows attributable to the Trust's oil and gas reserves plus the estimated
future tax credits under Section 29 of the Internal Revenue Code of 1986
("Section 29 Credit") for Federal income tax purposes. The impairment loss is
equal to the difference between the carrying value of the Net Profits Interest
and the fair value of the Net Profits Interest. An impairment of $29.1 million
in the carrying value of the Net Profits Interest was recorded during the fourth
quarter of 1998. No impairment was recorded for 1997 or 1996.
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.
6
<PAGE>
TORCH ENERGY ROYALTY TRUST
COMPETITION AND MARKETS
The Trust's distributions are dependent on gas production and prices and, to a
lesser extent, oil production and prices from the Underlying Properties. The
gas industry is highly competitive in all of its phases. In marketing
production from the Underlying Properties, TEMI encounters competition from
major gas companies, independent gas concerns, and individual producers and
operators. Many of these competitors have greater financial and other resources
than TEMI. Competition may also be presented by alternative fuel sources,
including heating oil and other fossil fuels.
Crude oil and natural gas supplies are currently abundant relative to demand in
the worldwide markets for those commodities. 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.
7
<PAGE>
TORCH ENERGY ROYALTY TRUST
ENVIRONMENTAL REGULATION
Activities on the Underlying Properties are subject to existing Federal, state
and local laws, rules and regulations which govern health, safety, environmental
quality and pollution control. It is anticipated that, absent the occurrence of
an unanticipated event, compliance with existing Federal, state and local laws,
rules and regulations regulating health, safety, the release of materials into
the environment or otherwise relating to the protection of the environment will
not have a material adverse effect upon the Trust or Unitholders. Torch has
informed the Trust that it cannot predict what effect additional 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.
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 five unitized wells producing from the Miogyp "B" reservoir
and one well producing from the Lower Miogyp reservoir. The wells produce from
a depth in excess of 14,000 feet. The working interest in the well producing in
the Lower Miogyp reservoir is 64.4% (48.3% net revenue interest). A subsidiary
of Exxon Corporation operates the five wells in the Miogyp "B" reservoir, and a
subsidiary of Torch operates the well producing from the Lower Miogyp formation.
Robinson's Bend Field. The Underlying Properties include an average 42.7%
working interest (31.9% net revenue interest) in 394 wells in the Robinson's
Bend Field in the Black Warrior Basin of Alabama. Sales of production of coal
seam gas from the Robinson's Bend Field prior to January 1, 2003 entitle
Unitholders to Section 29 Credits, provided certain requirements are met. The
Section 29 Credit for qualifying coal seam gas production was approximately
$1.06, $1.05 and $1.03 per MMBtu in 1998, 1997 and 1996, respectively. This
rate is adjusted annually for inflation. All of the wells in the Robinson's
Bend Field are operated by an affiliate of Torch.
The amounts paid to the Trust from the Robinson's Bend Field in any calendar
quarter are subject to a Volume Limitation equal to the gross proceeds from the
sale of 912.5 MMcf, less property, production, severance and similar taxes, and
development, operating, and certain other costs (excluding operating and
development costs until January 1, 2003). Gross production during 1998, 1997 and
1996 attributable to distributions from the Underlying Properties in the
Robinson's Bend Field averaged 719 MMcf, 787 MMcf and 853 MMcf per quarter,
respectively, and was therefore 25%, 18% and 11%, respectively, less than the
Volume Limitation for the year.
In calculating amounts paid to the Trust, lease operating expenses in the
Robinson's Bend field are not deducted until after 2002. When these amounts are
deducted, the amounts paid to the Trust attributable to the Robinson's Bend
field will be reduced substantially. If average prices following 2002 are not
substantially greater than gas prices in December 1998, the Trust's current
reserve reports indicate that the Trust will not receive any payments
attributable to the Robinson's Bend field.
8
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TORCH ENERGY ROYALTY TRUST
Cotton Valley Fields. The Underlying Properties include an average 52.91%
working interest (40.17% net revenue interest) in 45 wells in four fields that
produce from the Upper and Lower Cotton Valley formations in Texas. A
substantial portion of the gas produced and sold from the Cotton Valley Fields
prior to January 1, 2003 will qualify for the Section 29 Tax Credits for
productions of tight sands gas. The Section 29 Credit for qualifying tight sands
gas production is approximately $0.52 per MMBtu and is not adjusted for
inflation. 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 18.16%
working interest (14.25% net revenue interest) in 90 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 substantial portion of the gas produced and sold from these fields
prior to January 1, 2003 will qualify for the Section 29 Credits for tight sands
gas. A subsidiary of Torch operates eight wells in the Austin Chalk Fields. A
majority of the wells in the Austin Chalk Fields are operated by Union Pacific
Resources Corporation.
WELL COUNT AND ACREAGE SUMMARY
The following table shows, as of December 31, 1998, the gross and net interest
in oil and gas wells for the Underlying Properties:
<TABLE>
<CAPTION>
Gas Wells Oil Wells
---------------------------- ----------------------------
Gross Net Gross Net
------------ ---------- ------------ ----------
<S> <C> <C> <C> <C>
Chalkley Field...................... 6 1.5 --- ---
Robinson's Bend Field............... 394 168.3 --- ---
Cotton Valley Fields................ 45 23.6 --- ---
Austin Chalk Fields................. 41 7.8 49 8.6
------------ ----------- ------------ ----------
Total............................. 486 201.2 49 8.6
============ =========== ============ ==========
</TABLE>
The following table shows the gross and net acreage for the Underlying
Properties as of December 31, 1998. 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...................... 2,152 425
Robinson's Bend Field............... 33,404 14,288
Cotton Valley Fields................ 6,650 4,162
Austin Chalk Fields................. 34,642 6,414
-------- --------
Total............................. 76,848 25,289
======== ========
DRILLING ACTIVITY
The following table sets forth the results of drilling activity for the
Underlying Properties during the three years ended December 31, 1998. 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 TRC and Velasco ("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.
9
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TORCH ENERGY ROYALTY TRUST
All of the wells shown below represent Infill Wells drilled on the Underlying
Properties. The Net Profits Interest entitle the Trust to 20% of an infill
well's cash flows after gross proceeds have exceeded costs and expenses
("Payout"). As Payout has not occurred on any of these wells, distributions to
Unitholders have not been impacted by the Infill Wells as of December 31, 1998.
Development Wells
Gross Net
--------------------------- --------------------------
Dry Dry
Productive Holes Total Productive Holes Total
---------- ----- ----- ---------- ----- -----
1996 0 0 0 0 0 0
1997 6 0 6 2.8 0 2.8
1998 0 0 0 0 0 0
There was no other drilling activity on the Underlying Properties during the
three years ended December 31, 1998.
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 profits income and the weighted average
sales price per Mcf of gas and Bbl of oil for production attributable to 1998,
1997 and 1996 cash distributions received by Unitholders (derived from
production during the twelve months ended September 30, 1998, 1997 and 1996,
respectively).
<TABLE>
<CAPTION>
Chalkley, Cotton Valley
and Austin Chalk Fields
--------------------------------------
1998 1997 1996
-------- --------- --------
<S> <C> <C> <C>
Production:
Gas (MMcf)................................................... 5,135 6,186 8,217
Oil (Mbbl)................................................... 74 107 149
Weighted average lifting cost per Mcfe......................... $ .34 $ 0.26 $ 0.20
Weighted average taxes on production per Mcfe.................. $ 0.09 $ 0.09 $ 0.07
Weighted average sales price (b)
Gas ($/Mcf).................................................. $ 2.12 $ 1.92 $ 1.71
Oil ($/Bbl).................................................. $12.71 $17.06 $17.10
Robinson's Bend Field
--------------------------------------
1998 1997 1996
-------- --------- --------
Production:
Gas (MMcf)................................................... 2,879 3,149 3,415
Oil (Mbbl)................................................... --- --- ---
Weighted average lifting cost per Mcfe......................... $ ---(a) $ ---(a) $ ---(a)
Weighted average taxes on production per Mcfe.................. $ 0.07 $ 0.09 $ 0.11
Weighted average sales price (b)
Gas ($/Mcf).................................................. $ 1.80 $ 1.61 $ 1.40
Oil ($/Bbl).................................................. $ --- $ --- $ ---
</TABLE>
(a) No operating costs will be deducted from the Net Profits Interest in the
Robinson's Bend Field until January 1, 2003. Average lifting costs per
Mcfe were $2.45, $2.27 and $2.35, respectively, during 1998, 1997 and 1996,
in the Robinson's Bend Field.
(b) Average sales prices are reflective of purchase prices paid by TEMI,
pursuant to the Purchase Contract, less certain gathering, treating and
transportation charges.
10
<PAGE>
TORCH ENERGY ROYALTY TRUST
ITEM 3. LEGAL PROCEEDINGS
There are no material pending legal proceedings to which the Trust is a party.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNITHOLDERS
No matter was submitted to the Unitholders for a vote in 1998.
11
<PAGE>
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 26, 1999, there were 8,600,000 Units outstanding and
approximately 694 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:
<TABLE>
<CAPTION>
Cash
High Low Distributions
------- ------- -------------
<S> <C> <C> <C>
Quarter ended March 31, 1997....................... $11.625 $10.250 $.514
Quarter ended June 30, 1997........................ $10.875 $10.250 $.465
Quarter ended September 30, 1997................... $10.750 $ 8.750 $.359
Quarter ended December 31, 1997.................... $ 9.125 $ 5.500 $.352
Quarter ended March 31, 1998....................... $ 9.125 $ 6.250 $.464
Quarter ended June 30, 1998........................ $ 7.938 $ 6.688 $.390
Quarter ended September 30, 1998................... $ 6.813 $ 5.250 $.360
Quarter ended December 31, 1998.................... $ 6.375 $ 4.250 $.288
</TABLE>
On March 26, 1999, the high sales price per unit on the NYSE was $4.813 and the
low sales price on the NYSE was $4.689.
ITEM 6. SELECTED FINANCIAL DATA (In thousands, except per Unit amounts)
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------
1998 1997 1996 1995 1994
------- ------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Net profits income........ $13,615 $ 15,183 $ 17,381 $ 22,427 $ 30,039
Distributable income...... $12,936 $ 14,525 $ 16,722 $ 21,787 $ 29,282
Distributions declared.... $12,917 $ 14,534 $ 16,727 $ 21,758 $ 29,300
Distributable income
per Unit.................. $ 1.50 $ 1.69 $ 1.94 $ 2.53 $ 3.40
Distributions per Unit.... $ 1.50 $ 1.69 $ 1.95 $ 2.53 $ 3.41
Total assets (at end of
period).................. $57,015 $100,845 $121,526 $137,179 $157,593
</TABLE>
Distributable income of the Trust consists of the excess of net profits income
plus interest income less general and administrative expenses of the Trust. The
Trust recognizes net profits income during the period in which amounts are
received by the Trust.
ITEM 7. DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
YEAR 2000 ISSUES
The Year 2000 problem ("Y2k") refers to the inability of computer and other
information technology systems to properly process date and time information.
The problem was caused, in part, by the outdated programming practice of using
two digits rather than four to represent the year in a date. The consequence of
the Y2k problem is that information technology and embedded processing systems
are at risk of malfunction, particularly during the transition between 1999 to
2000.
12
<PAGE>
TORCH ENERGY ROYALTY TRUST
The effects of the Y2k problem are exacerbated by the interdependence of
computer and telecommunication systems throughout the world. This
interdependence affects the Trust, the Trust's administrative services provider,
Torch, and their vendors, customers, business partners, as well as government
agencies.
The risks of Y2k fall into three general areas: 1) Corporate Systems, 2) Field
Systems and 3) Third Party Exposure. Torch has formed a Y2k Team comprised of
representatives from senior management, exploration, exploitation, accounting,
legal and internal audit. The costs of these assessments will not impact the
Trust's distributions as such costs are borne by Torch pursuant to the
Administrative Services Agreement between Torch and the Trust. Torch intends
to address each of these areas through a readiness process as described below:
a) Planning and Awareness
b) Inventory and Assessment
c) Identify Potential Problems and their Business Impact
d) Identify/Approve Solutions
e) Test and Implement Solutions
f) Contingency Planning
CORPORATE SYSTEMS
1. Planning and Awareness. All Torch employees have attended Y2k informational
programs including a general discussion of what Y2k is and how it could
affect the business. Employees of all levels of the organization have been
asked to participate in the identification of potential Y2k risks including
routine Excel and Word documents. Awareness of the issue is extremely high.
Overall planning of the Y2k function has been delegated to the Y2k Team
mentioned above.
2. Inventory and Assessment. The Company has completed an inventory of the
traditional computing platforms including client/server systems, LAN systems
and PC systems, as well as an inventory of all systems software and operating
systems for each computing system. In addition, third party service
interfaces, banking/treasury interfaces and telecommunications have been
cataloged.
Assessment of component compliance (compliant, non-compliant, expected date
of compliance, etc.) has been completed and included research of product
information on the Internet, contacting peer group companies and accessing
information that peer group companies have already found.
3. Identification. The failure to identify and correct a material Y2k problem
in the Corporate Systems could result in inaccurate or untimely financial
information provided to the Trustee and Unitholders. At this time, Torch
believes that any Y2k disruptions associated with its financial and
administration systems will not have a material effect on the Trust.
4. Identify/Approve Solutions. Based upon the assessments of components'
compliance, solutions are determined. These solutions include: 1) fix or
replace the non-compliant component, 2) buy patches or replacement items, 3)
develop workarounds, 4) identify alternate automated processes, 5) design
manual procedures and 6) develop business continuity plans for specific items
or systems.
5. Test and Implement Solution. Since April 1998 Torch has been working on an
upgrade to its accounting software and is expected to achieve full Y2k
compliance in the first half of 1999. In addition, all network and desktop
applications used by Torch have been inventoried and are generally Y2k
compliant.
13
<PAGE>
TORCH ENERGY ROYALTY TRUST
6. Contingency Planning. Notwithstanding the foregoing, should there be
significant unanticipated disruptions in Torch's financial and administrative
systems, a number of accounting processes that are currently automated will
need to be performed manually. Torch is currently considering its options
with respect to contingency arrangement for temporary staffing to accommodate
such situations.
FIELD SYSTEMS
1. Planning and Awareness. Employees at all levels of the organization have
been asked to participate in the identification of potential Y2k risk
impacting Torch's field systems, including management of field and facility
assets.
2. Inventory and Assessment. All embedded chip technology used in the field
operations including safety systems, measurement devices, overflow valves,
SCADA systems and other field processes that are date-or-time sensitive were
located. During the assessment stage a list of assets to be tested was
assembled. Consideration was given to 1) issues of health and safety, 2)
environmental concerns, 3) economic factors and 4) other business risks.
Vendors and manufacturers have been contacted as well as product research
through the Internet and the use of peer group company shared information. To
date, the majority of embedded components researched have been deemed either
date-insensitive or Y2k compliant. However, the complexity of embedded
systems is such that a small minority of non-compliant components, even a
single non-compliant component, can corrupt an entire system. The component
level evaluation is substantially complete and a broader evaluation at the
system level has commenced. Torch anticipates that the system level
evaluation will be completed by the end of the second quarter 1999.
3. Identification. The failure to identify and correct a material Y2k problem
could result in outcomes ranging from errors in data reporting to
curtailments or shutdowns in production. Torch is actively engaged in a
program to prioritize the remediation of embedded components and systems
which are either known to be Y2k non-compliant or which have higher risk of
Y2k failures, and to further prioritize remediation targets by the
anticipated financial impact of any such failures on the Trust. To assist in
this effort, Torch has retained consultants who are knowledgeable and
experienced in the assessment of Y2k issues impacting field operations.
Torch intends to give extremely high priority to the remediation of any
situation that impacts employee health and safety or environmental security.
At this time, Torch is unable to express any degree of confidence that there
will not be material production disruptions associated with Y2k compliance.
Depending on the magnitude of any such disruptions and the time required to
correct them, such failures could materially and adversely impact
distributions, depletion deductions and Section 29 credits available for
allocation by the Trust to the Unitholders.
4. Identify/Approve Solutions. Based upon the assessment of field systems,
regarding compliance or non-compliance, solutions are determined. These
potential solutions include 1) fix or replace non-compliant items, 2) buy
patches or replacement items, 3) develop workarounds, 4) identify alternative
automated processes, 5) design manual procedures and 6) develop business
continuity plans for specific items or systems.
5. Test and Implement Solutions. Once identified, assessed and prioritized,
Torch intends to test, upgrade and certify embedded components and
systems in field process control units deemed to pose the greatest risk of
significant non-compliance. It is important to note that in some
circumstances, the procedures used to test embedded components for Y2k
compliance themselves pose a risk of damaging the component or corrupting the
system. Accordingly, there may be situations in which a decision not to test
may be deemed the most prudent.
14
<PAGE>
TORCH ENERGY ROYALTY TRUST
6. Contingency Planning. Should material production disruptions occur as a
result of Y2k failures in the field operations, the Trust's financial
condition will be impacted. This contingency is being factored into
capital budgeting and liquidity planning.
THIRD PARTY EXPOSURES
1. Planning and Awareness. Torch has been involved in informational programs
with its employees who have significant interaction with outside vendors,
customers and business partners which may have an impact on the Trust's
financial condition. All levels of employees in the organization have
participated in the identification of potential third party Y2k risk.
2. Inventory and Assessment. Surveys of general Y2k readiness have been sent to
third parties such as vendors, customers and business partners which impact
the Trust's financial condition. An assessment has been made regarding the
impact associated with such third parties' Y2k compliance on the Trust.
3. Identification. Certain third parties' failure to identify Y2k problems can
have significant adverse effects on the Trust. For example, an Underlying
Property third party operator's failure to identify Y2k problems may result
in adverse outcomes such as data reporting errors, curtailments and
production shutdowns. Additionally, Y2k problems in connection with the
possible interruption of TEMI's third party gathering, treating, processing
or transportation arrangements relating to the Underlying Properties can
affect TEMI's obligation under the Purchase Contract. Other significant
concerns include the integrity of global telecommunication systems, the
readiness of commercial banks to execute electronic fund transfers and the
financial community's ability to maintain an orderly market of the Trust's
Units. All such events could materially or entirely eliminate distributions,
depletion deductions and Section 29 Credits available for allocation by the
Trust to the Unitholders.
4. Identify/Approve Solutions. By prioritizing the various third party risks
mentioned above, a list of critical third party vendors, customers and
business partners has been determined. By cross-referencing the results of
the aforementioned Y2k readiness survey with this list of critical third
parties, solutions can be determined. Field visits, office visits and
additional meetings to access the third party's Y2k compliance may be
necessary.
5. Test and Implement Solutions. Where Torch perceives significant risk of Y2k
non-compliance of a third party that may have a material impact on the
financial condition of the Trust, joint testing may be undertaken during
1999. Joint testing would occur following upgrades and other remediation to
hardware, software and communications links, as applicable, with the intent
of determining that the remediation system being tested will perform as
expected after December 31, 1999.
6. Contingency Planning. Should material production disruptions occur as a
result of Y2k failures of third parties, the distributions, depletion
deductions and Section 29 Credits available for allocation by the Trust to
the Unitholders will be impacted. The Company and the Trust do not believe
it is economically feasible to provide for this contingency.
15
<PAGE>
TORCH ENERGY ROYALTY TRUST
RESULTS OF OPERATIONS
DISCUSSION OF YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Because a modified cash basis of accounting is utilized by the Trust, Net
Proceeds to the Trust for the years ended December 31, 1998, 1997 and 1996 is
derived from actual oil and gas production from October 1, 1997 through
September 30, 1998, October 1, 1996 through September 30, 1997 and October 1,
1995 through September 30, 1996, respectively. The following tables set forth,
for the Underlying Properties, oil and gas sales attributable to distributions
received by Unitholders during the three years ended December 31, 1998.
Bbls of Oil
-----------------------------------
1998 1997 1996
------- ------- --------
Chalkley Field................ 26,736 40,260 61,694
Robinson's Bend Field......... --- --- ---
Cotton Valley Fields.......... 6,481 6,157 7,607
Austin Chalk Fields........... 41,174 60,236 79,289
------- ------- --------
Total......................... 74,391 106,653 148,590
======= ======== ========
Mcf of Gas
-----------------------------------
1998 1997 1996
------- ------- --------
Chalkley Field................ 3,219,550 4,195,263 5,713,920
Robinson's Bend Field......... 2,879,422 3,148,834 3,415,346
Cotton Valley Fields.......... 1,469,645 1,385,461 1,734,783
Austin Chalk Fields........... 445,443 605,455 768,023
---------- ---------- ----------
Total......................... 8,014,060 9,335,013 11,632,072
========== ========== ==========
For the year ended December 31, 1998, net profits income was $13,615,000, as
compared to $15,183,000 and $17,381,000 for the same periods in 1997 and 1996,
respectively. Such decreases are primarily due to normal declines in oil and
gas production attributable to the Underlying Properties, partially offset by
higher average gas prices paid to the Trust during 1998 and 1997.
Gas production attributable to the distributions received by Unitholders during
the year ended December 31, 1998 was 8,014,060 Mcf, as compared to gas
production of 9,335,013 Mcf and 11,632,072 Mcf for the same periods in 1997 and
1996, respectively. Oil production attributable to the Underlying Properties
for the year ended December 31, 1998 was 74,391 Bbls as compared to 106,653 Bbls
and 148,590 Bbls for the same periods in 1997 and 1996, respectively.
As of December 31, 1998, six infill wells were drilled and commenced production.
Infill well production totaled 1,700 bbls of oil and 344,458 Mcf of gas during
the year ended December 31, 1998 and 2,075 bbls of oil and 274,577 Mcf of gas
during the year ended December 31, 1997. Distributions received by Unitholders
have not been impacted by these wells as gross proceeds have not exceeded costs
and expenses for each of the infill wells.
The average price used to calculate Net Proceeds for gas during the year ended
December 31, 1998 was $2.10 per MMBtu as compared to $1.91 per MMBtu and $1.70
per MMBtu for the years ended December 31, 1997 and 1996, respectively. The
average price used to calculate Net Proceeds for oil during the years ended
December 31, 1998, 1997 and 1996 was $12.71, $17.06 and $17.10 per Bbl,
respectively. When TEMI pays a purchase price for gas based on the Minimum
Price of $1.70 per MMBtu, TEMI
16
<PAGE>
TORCH ENERGY ROYALTY TRUST
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, 1998, TEMI's outstanding Price Credits will reduce future
distributions by $97,000. All such Price Credits, computed on a monthly basis,
are attributable to September 1998 production and may be entitled to be deducted
by TEMI in calculating the purchase price in the future when the Index Price for
gas exceeds the Minimum Price. Net Price Credits in the amount of $317,000 and
$2,305,000 were deducted in calculating the purchase price related to
distributions during 1997 and 1996, respectively.
Lease operating expenses and capital expenditures deducted in calculating
distributions during the years ended December 31, 1998, 1997 and 1996 totaled
$1,947,000, $1,898,000 and $2,081,000, respectively. In accordance with the
Conveyance, no operating or development costs will be deducted in calculating
the Net Proceeds from the Robinson's Bend Field prior to January 1, 2003.
Severance tax deducted in calculating distributions during the years ended
December 31, 1998, 1997 and 1996 totaled $710,000, $874,000 and $1,018,000,
respectively, for all four fields.
General and administrative expenses during the years ended December 31, 1998,
1997 and 1996 amounted to $700,000, $678,000 and $684,000, respectively. These
expenses primarily relate to administrative services provided by Torch and the
Trustee.
During the year ended December 31, 1998, an impairment of $29.1 million was
recorded to the financial statement line item titled "Amortization of Net
Profits Interest" on the Statement of Changes in Trust Corpus to reduce the
carrying value of the Net Profits Interest in accordance with Financial
Accounting Standards Board Statement No. 121. Such impairment was mainly
attributable to depressed gas prices. This impairment did not impact current
year cash distributions nor Section 29 Credits allocated to Unitholders and
additionally will not affect future cash distributions and Section 29 Credits.
No such impairment was recorded during the years ended December 31, 1997 and
1996.
For the year ended December 31, 1998, distributable income was $12,936,000, or
$1.50 per Unit, as compared to $14,525,000, or $1.69 per Unit, and $16,722,000,
or $1.94 per Unit, for the same periods in 1997 and 1996, respectively. Total
cash distributions of $12,917,000, or $1.50 per Unit, were made during the year
ended December 31, 1998 as compared to $14,534,000, or $1.69 per Unit, and
$16,727,000, or $1.95 per Unit, for the same periods in 1997 and 1996,
respectively. The Section 29 Credits relating to qualifying production from
coal seam and tight sands properties, during the twelve months ended September
30, 1998, 1997 and 1996, totaled approximately $0.38, $0.41 and $0.44 per Unit,
respectively.
17
<PAGE>
TORCH ENERGY ROYALTY TRUST
Net profits received by the Trust during the years ended December 31, 1998,
1997, and 1996, derived from production sold during the twelve months ended
September 30, 1998, 1997 and 1996, respectively, was computed as shown in the
following table (in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------------------------------------------------
1998 1997 1996
--------------------------------- ------------------------------- ------------------------------
Chalkley, Chalkley, Chalkley,
Cotton Cotton Cotton
Valley and Valley and Valley and
Austin Robinson's Austin Robinson's Austin Robinson's
Chalk Bend Chalk Bend Chalk Bend
Fields Field Total Fields Field Total Fields Field Total
------- ---------- ------- -------- ---------- ----- -------- --------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Oil and gas revenues........... $11,812 $5,176 $13,694 $ 5,060 $ 16,601 $ 4,793
------- ------ ------- ------- -------- -------
Direct operating expenses:
Lease operating expenses
and property tax............ 1,876 (a) 1,801 (a) 1,778 (a)
Severance tax................ 498 212 593 281 653 365
------- ------ ------- ------- -------- -------
2,374 212 2,394 281 2,431 365
------- ------ ------- ------- -------- -------
Net proceeds before
capital expenditures........ 9,438 4,964 11,300 4,779 14,170 4,428
Capital expenditures........... 71 --- 97 --- 303 ---
------- ------ ------- ------- -------- -------
Net proceeds................... 9,367 4,964 11,203 4,779 13,867 4,428
Net profits percentage......... 95% 95% 95% 95% 95% 95%
------- ------ ------- ------- -------- -------
Net profits income............. $ 8,899 $4,716 $13,615 $10,643 $ 4,540 $15,183 $ 13,174 $ 4,207 $17,381
======= ====== ======= ======= ======= ======= ======== ======= =======
</TABLE>
(a) Lease operating expenses are not deducted in calculating Net Proceeds until
January 1, 2003. Lease operating expenses and property taxes were $7,041,
$7,163 and $8,024 during 1998, 1997 and 1996, respectively.
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 and Velasco, as the owners of the Underlying
Properties, 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. Substantially all of the
Index Price is calculated based on market prices of oil and gas and
therefor is subject to commodity price risk. The Purchase Contract expires
upon termination of the Trust and provides a Minimum Price of $1.70 per
MMBtu paid by TEMI for gas until December 31, 2000. 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 $2.10 per MMBtu, TEMI is entitled
to deduct such excess, the Price Differential. Beginning January 1, 2001,
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.
18
<PAGE>
TORCH ENERGY ROYALTY TRUST
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Independent Auditors' Reports................................................................ 20
Statements of Assets, Liabilities and Trust Corpus at December 31, 1998 and 1997............. 22
Statements of Distributable Income for the Years Ended December 31, 1998, 1997 and 1996...... 23
Statements of Changes in Trust Corpus for the Years Ended December 31, 1998, 1997 and 1996... 24
Notes to Financial Statements................................................................ 25
</TABLE>
19
<PAGE>
INDEPENDENT AUDITORS' REPORT
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, 1998
and 1997, and the related statements of distributable income and changes in
trust corpus for each of the years then ended. These financial statements are
the responsibility of the Trustee. Our responsibility is to express an opinion
on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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
generally accepted accounting principles.
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,
1998 and 1997, and the results of its operations and its cash flows for each of
the years then ended, on the basis of accounting described in Note 2.
/s/ KPMG LLP
Houston, Texas
March 26, 1999
20
<PAGE>
INDEPENDENT AUDITORS' REPORT
Wilmington Trust Company
as Trustee of Torch Energy Royalty Trust
and to the Unitholders:
We have audited the statements of distributable income and changes in trust
corpus of the Torch Energy Royalty Trust (the "Trust") for the year ended
December 31, 1996. These financial statements are the responsibility of the
Trustee. Our responsibility is to express an opinion on the financial
statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards.
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 the
Trustee, as well as evaluating the overall financial statement presentation. We
believe that our audit provides a reasonable basis for our opinion.
As described in Note 2 to the financial statements, these financial statements
have been prepared on a modified cash basis of accounting, which is a
comprehensive basis of accounting other than generally accepted accounting
principles.
In our opinion, such financial statements present fairly, in all material
respects, the distributable income and changes in trust corpus of the Trust for
the year ended December 31, 1996 on the basis of accounting described in Note 2.
/s/ Deloitte & Touche LLP
- - --------------------------
Houston, Texas
March 18, 1997
21
<PAGE>
TORCH ENERGY ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
(In thousands)
ASSETS
<TABLE>
<CAPTION>
December 31, 1998 December 31, 1997
----------------- -----------------
<S> <C> <C>
Cash................................................................. $ 4 $ 7
Net profits interests in oil and gas properties (net of accumulated
amortization of $123,589 and $79,762 at December 31, 1998
and 1997, respectively)............................................. 57,011 100,838
--------- ---------
$ 57,015 $ 100,845
========= =========
LIABILITIES AND TRUST CORPUS
Trust expense payable................................................ $ 155 $ 177
Trust corpus......................................................... 56,860 100,668
--------- ---------
$ 57,015 $ 100,845
========= =========
</TABLE>
The accompanying notes to financial statements
are an integral part of these statements.
22
<PAGE>
TORCH ENERGY ROYALTY TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(In thousands, except per Unit amounts)
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------------------
1998 1997 1996
------------------- -------------------- -------------------
<S> <C> <C> <C>
Net profits income................................. $13,615 $15,183 $17,381
Interest income.................................... 21 20 25
------------------- -------------------- -------------------
13,636 15,203 17,406
General and administrative expenses................ 700 678 684
------------------- -------------------- -------------------
Distributable income............................... $12,936 $14,525 $16,722
=================== ==================== ===================
Distributable income per Unit (8,600 Units)........ $ 1.50 $ 1.69 $ 1.94
=================== ==================== ===================
Distributions per Unit............................. $ 1.50 $ 1.69 $ 1.95
=================== ==================== ===================
</TABLE>
The accompanying notes to financial statements
are an integral part of these statements.
23
<PAGE>
TORCH ENERGY ROYALTY TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(In thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------------------
1998 1997 1996
-------------------- ------------------- -------------------
<S> <C> <C> <C>
Trust corpus, beginning of year...................... $100,668 $121,362 $137,014
Amortization of Net Profits Interests................ (43,827) (20,685) (15,647)
Distributable income................................. 12,936 14,525 16,722
Distributions to Unitholders......................... (12,917) (14,534) (16,727)
-------------------- ------------------- -------------------
Trust Corpus, end of year............................ $ 56,860 $100,668 $121,362
==================== =================== ===================
</TABLE>
The accompanying notes to financial statements
are an integral part of these statements.
24
<PAGE>
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 not terminate prior to January 1, 2003, except upon the
affirmative vote of the holders of not less than 80% of the outstanding Units.
Thereafter, 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 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 by entitled to enforce
25
<PAGE>
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
its rights with respect to any such indebtedness and security interest as if it
were not then serving as Trustee.
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.
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,
1998, 1997 and 1996 are derived from oil and gas production sold during the
twelve-month periods ended September 30, 1998, 1997 and 1996, 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 the sum of the estimated undiscounted future cash
flows attributable to the Trust's oil and gas reserves plus the estimated
future tax credits under Section 29 of the Internal Revenue Code of 1986
("Section 29 Credit") for Federal income tax purposes. The impairment loss is
equal to the difference between the carrying value of the Net Profits
Interest and the fair value of the Net Profits Interest.
In computing the estimated undiscounted future cash flows, estimated future
oil and gas prices as determined by Torch management, are applied to
estimated future production of oil and gas reserves over the economic lives
of the reserves and pursuant to the Trust Agreement. If the aforementioned
undiscounted future cash flows and Section 29 Credits are less than the
carrying value of the Net Profits Interest, an impairment provision is
recognized. The fair value of the Net Profits Interest is computed by
discounting the aforementioned cash flows and Section 29 Credits by 10%.
Additionally, it is assumed for these computations that TEMI continues its
Minimum Price commitment, pursuant to the Purchase Contract, until the Trust
dissolves. Based on Torch management's pricing assumptions and production
estimates by T.J. Smith & Company, Inc., Ryder Scott Company and H.J. Gruy
and Associates ("Independent Reserve Engineers") at December 31, 1998, the
present value of the estimated pre-tax future net cash flow, discounted at
10%, for the proved reserves attributable to the Net Profits Interest will be
less than $25 million in 2003. Pursuant to the Trust Agreement, it was
assumed that the Trust would then dissolve and the remaining assets of the
Trust would be sold and the proceeds therefrom would be distributed to the
Unitholders. The aforementioned impairment test resulted in a $29.1 million
write-down in the carrying value of the Net Profits Interest during the
fourth quarter of 1998.
26
<PAGE>
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
- - - 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
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, deductions and income tax credits
relating to Section 29 Credits resulting 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, as owners of the Underlying Properties subject to and burdened
by the Net Profits Interests, contracted to sell the oil and gas production from
such 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,
which, prior to September 1, 2000, is adjusted to reflect the terms of a hedge
contract
27
<PAGE>
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
("Hedge Contract") to which TEMI is a party. Under the Hedge Contract,
TEMI receives prices specified in the Hedge Contract ("Specified Prices") for
quantities of oil and gas specified therein ("Specified Quantities"). While the
Index Price calculation reflects the terms of the Hedge Contract, the Trust's
net profits income is not impacted by payments or receipts made by or received
by TEMI in connection with its participation in the Hedge Contract. In
calculating the Index Price for gas (which represents approximately 97% of the
estimated reserves as of January 1, 1999, on an Mcfe basis), the Specified
Prices received weightings ranging from approximately 40% to 70% pertaining to
production prior to August 31, 1997. Thereafter, the Specified Prices receive a
weighting of approximately 10% and less. The Average Market Prices receive the
balance of the weighting. The Specified Prices for gas increase each year from
$1.83 per MMBtu in 1996 to $1.89 per MMBtu in 2000 and are adjusted to reflect
the difference between the settlement prices for oil and gas in the futures
markets and the Average Market Prices.
The Purchase Contract also provides that the minimum price paid by TEMI for gas
production is $1.70 per MMBtu ("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,
and as of December 31, 1998, TEMI's outstanding Price Credits, net to the Trust,
were $97,000. All such Price Credits were attributable to September 1998
production. TEMI may be entitled to deduct these Price Credits in calculating
the purchase price in the future when the Index Price for gas exceeds the
Minimum Price. Net Price Credits in the amount of $317,000 and $2,305,000 were
deducted in calculating the purchase price related to distributions during 1997
and 1996, respectively. In addition, if the Index Price for gas exceeds $2.10
per MMBtu ("Sharing Price"), TEMI is entitled to deduct 50% of such excess
("Price Differential") in determining the purchase price. Beginning January 1,
2001, 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 purchased contracts granting
TEMI the right to sell estimated gas production in excess of the Specified
Quantities at a price intended to limit TEMI's losses in the event the Index
Price falls below the Minimum Price.
Gross revenues (before deductions for applicable gathering, treating and
transportation charges) from TEMI included in net profits income for the years
ended December 31, 1998, 1997 and 1996 were $18,638,000, $20,719,000 and
$23,531,000, 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 ($0.274 for 1998 and 1997 and $0.272 per MMBtu
for 1996), 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 $0.05 per MMBtu,
28
<PAGE>
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
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,
1998, 1997 and 1996, gathering, treating and transportation fees charged to the
Trust by TEMI, attributable to production during the twelve months ended
September 30, 1998, 1997 and 1996 in the Robinson's Bend, Austin Chalk and
Cotton Valley Fields, totaled $1,650,000, $1,965,000 and $2,137,000,
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 $196,000, $182,000, and $181,000 for the years ended December 31, 1998,
1997 and 1996, respectively. In accordance with the Conveyance, no overhead
fees were deducted in calculating the Net Proceeds from the Robinson Bend
properties.
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 $368,000 were paid by the Trust to
Torch during the year ended December 31, 1998. Such fees were $366,000 during
each of the years ended December 31, 1997 and 1996.
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,
1998, 1997 and 1996. 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 Independent Reserve Engineers.
Future net cash flows were computed by applying
29
<PAGE>
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
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. In accordance with terms
of the Robinson's Bend Field Conveyance, no operating or developing costs prior
to January 1, 2003 were deducted from the Robinson's Bend Field future net
revenues.
Reserve Quantities:
The following table sets forth the estimated total 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, 1998, 1997 and 1996, based
on reserve reports prepared by the 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, 1998 were 33.6 billion cubic feet equivalent
("Bcfe") as compared to 1997 year-end reserves of 42.0 Bcfe. The reduction in
reported reserves includes 1998 production of 6.3 Bcfe and a negative reserve
revision of 2.1 Bcfe. Such reserve revision was primarily a result of a decline
in natural gas prices in 1998 as compared to 1997.
<TABLE>
<CAPTION>
Description 1998 1997 1996
- - --------------------------------- --------------------- ---------------------- ---------------------
Oil Gas Oil Gas Oil Gas
(Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) (MMcf)
------- ------- ------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves at beginning of year............... 202 40,804 293 56,455 349 63,725
Revisions.......................................... (36) (1,860) (42) (8,474) 35 428
Extensions and discoveries......................... --- --- --- --- 4 1,500
Production......................................... (30) (6,144) (49) (7,177) (95) (9,198)
------- ------- ------- ------- ------- --------
Proved reserves at end of year..................... 136 32,800 202 40,804 293 56,455
======= ======= ======= ======= ======= ========
Proved developed reserves at beginning of year...... 191 38,359 270 51,027 332 60,342
======= ======= ======= ======= ======= ========
Proved developed reserves at end of year............ 124 29,190 191 38,359 270 51,027
======= ======= ======= ======= ======= ========
</TABLE>
30
<PAGE>
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves (in thousands):
Estimated future net cash flows from the Net Profits Interests in proved oil and
gas reserves at December 31, 1998, 1997 and 1996 are presented in the following
table:
<TABLE>
<CAPTION>
December 31,
-------------------------------------
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Future cash inflows........................................ $ 80,970 $121,836 $241,221
Future costs and expenses.................................. (22,268) (27,536) (81,239)
-------- --------- --------
Net future cash flows...................................... 58,702 94,300 159,982
Discount at 10% for timing of cash flows................... (16,818) (29,671) (63,957)
-------- --------- --------
Present value of future net cash flows for proved reserves. $ 41,884 $ 64,629 $ 96,025
======== ======== ========
</TABLE>
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, 1998, 1997 and 1996:
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Balance at beginning of year............................... $ 64,629 $ 96,025 $ 83,761
Production................................................. (11,933) (14,756) (17,213)
Accretion to discount...................................... 642 9,603 8,376
Extensions and discoveries................................. --- --- 1,773
Revision of prior-year estimates, change in prices
and other................................................. (11,454) (26,243) 19,328
-------- --------- --------
Balance at end of year..................................... $ 41,884 $ 64,629 $ 96,025
======== ======== ========
</TABLE>
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, 1998, 1997, and 1996. 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 $1.06, $1.05 and $1.03 per MMBtu for 1998, 1997
and 1996, respectively.
<TABLE>
<CAPTION>
December 31,
-------------------------------------
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Undiscounted............................................... $ 10,557 $ 13,974 $ 17,391
======== ======== ========
Discounted present value at 10%............................ $ 8,436 $ 10,739 $ 12,863
======== ======== ========
</TABLE>
31
<PAGE>
TORCH ENERGY ROYALTY TRUST
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:
<TABLE>
<CAPTION>
Distributable
Net Profits Distributable Income
Income Income Per Unit
----------- ------------- --------
<S> <C> <C> <C>
Quarter ended March 31, 1998.................... $ 4,152 $ 3,983 $0.46
Quarter ended June 30, 1998..................... 3,518 3,326 0.39
Quarter ended September 30, 1998................ 3,299 3,128 0.36
Quarter ended December 31, 1998................. 2,646 2,499 0.29
------- ------- -----
$13,615 $12,936 $1.50
======= ======= =====
Quarter ended March 31, 1997.................... $ 4,579 $ 4,417 $0.51
Quarter ended June 30, 1997..................... 4,162 3,994 0.46
Quarter ended September 30, 1997................ 3,252 3,087 0.36
Quarter ended December 31, 1997................. 3,190 3,027 0.36
------- ------- -----
$15,183 $14,525 $1.69
======= ======= =====
</TABLE>
32
<PAGE>
TORCH ENERGY ROYALTY TRUST
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
During February 1998 the firm of Deloitte & Touche LLP was replaced as the
Trust's principal independent accountant and auditors to audit all the Trust's
financial statements with the firm of KPMG LLP. The Trust had no disagreements
with Deloitte & Touche LLP concerning their audit or the application of
accounting principles.
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."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
As of March 25, 1999, 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.
33
<PAGE>
TORCH ENERGY ROYALTY TRUST
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 $368,000 were paid by the Trust to Torch during the year ended December 31,
1998. Such fees were $366,000 in each of the years ended 1997 and 1996.
Marketing Arrangement
TRC and Velasco, as owners of the Underlying Properties subject to and burdened
by the Net Profits Interests, contracted to sell the oil and gas production from
such 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 the Minimum Price paid by TEMI for gas production is $1.70
per MMBtu. When TEMI pays a purchase price based on the Minimum Price, it
receives Price Credits equal to the difference between the Index Price and the
Minimum Price that it is entitled to deduct in determining the purchase price
when the Index Price for gas exceeds the Minimum Price. As of December 31,
1998, TEMI had accumulated Price Credits of $97,000, net to the Trust. TEMI may
be entitled to deduct such Price Credits in calculating the purchase price in
the future. Net Price Credits in the amount of $317,000 and $2,305,000 were
deducted in calculating the purchase price related to distributions during 1997
and 1996, respectively.
Gross revenues (before deductions for applicable gathering, treating and
transportation charges) from TEMI included in net profits income for the years
ended December 31, 1998, 1997 and 1996 were $18,638,000, $20,719,000 and
$23,531,000, 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 ($0.274 for 1998 and 1997 and
$0.265 per MMBtu for 1996), 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 $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
34
<PAGE>
TORCH ENERGY ROYALTY TRUST
Valley Fields. During the years ended December 31, 1998, 1997 and 1996, gas
gathering, treating and transportation fees charged to the Trust by TEMI,
attributable to production during the 12 months ended September 30, 1998, 1997
and 1996 in the Robinson's Bend, Austin Chalk and Cotton Valley Fields, totaled
$1,650,000, $1,965,000 and $2,137,000, respectively. No amounts for gathering,
treating or transportation are deducted in calculating the purchase price from
the Chalkley Field.
35
<PAGE>
TORCH ENERGY ROYALTY TRUST
PART IV
ITEM 14. 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
Independent Auditors' Reports
Statements of Assets, Liabilities and Trust Corpus at December 31,
1998 and 1997
Statements of Distributable Income for the Years Ended December 31,
1998, 1997 and 1996
Statements of Changes in Trust Corpus for the Years Ended December
31, 1998, 1997 and 1996
Notes to Financial Statements
Torch Energy Advisors Incorporated and Subsidiaries ("Torch") and
Torch's Predecessor ("Predecessor")
Independent Auditors' Report
Consolidated Balance Sheet of Torch as of December 31, 1998 and 1997
and the Related Consolidated Statements of Operations, Stockholders'
Equity and Comprehensive Income, and Cash Flows for the years ended
December 31, 1998 and 1997 and for the Period October 1, 1996 through
December 31, 1996
Predecessor's Consolidated Statement of Operations, Predecessor's
Equity and Comprehensive Income and Cash Flows for the Period
January 1, 1996 through September 30, 1996
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 of defining the rights of security holders, including
indentures.
4.1 - Form of Torch Energy Royalty Trust Agreement.*
4.2 - Form of Louisiana Trust Agreement.*
4.3 - Specimen Trust Unit Certificate.*
4.4 - Designation of Ancillary Trustee.*
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.*
36
<PAGE>
TORCH ENERGY ROYALTY TRUST
10.5 - Form of Texas Conveyance.*
10.6 - Form of Louisiana Conveyance.*
10.7 - Form of Alabama Conveyance.*
10.8 - Standby Performance Agreement between Torch and the Trust.*
10.9 - Amendment to Water Gathering Contract.*
10.10 - First Amendment to Oil and Gas Purchase Contract (previously
filed on form 10-Q for the quarter ended September 30, 1994).
23. Consents of experts and counsel.
23.1 - Consent of T.J. Smith and Company, Inc.
23.2 - Consent of H.J. Gruy and Associates, Inc.
23.3 - Consent of Ryder Scott Company
27. Financial Data Schedule
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, 1998.
37
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
TORCH ENERGY ROYALTY TRUST
By: Wilmington Trust Company
Trustee
By: /s/ Bruce L. Bisson
-------------------------------
Bruce L. Bisson, Vice President
Date: March 29, 1999
(The Trust has no directors or executive officers.)
38
<PAGE>
TORCH ENERGY ROYALTY TRUST
Torch Energy Royalty Trust
Rodney Square North
1100 North Market Street
Wilmington, Delaware 19890
Attention: Corporate Trust Administration
Legal Counsel
Butler & Binion, L.L.P.
Houston, Texas
Tax Counsel
Butler & Binion, L.L.P.
Houston, Texas
Auditors
KPMG LLP
Houston, Texas
Transfer Agent and Registrar
Wilmington Trust Company
1100 North Market Street
Wilmington, Delaware 19890
Attention: Corporate Trust Administration
39
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Torch Energy Advisors Incorporated:
We have audited the accompanying consolidated balance sheets of Torch Energy
Advisors Incorporated and subsidiaries as of December 31, 1998 and 1997 and the
related consolidated statements of operations, stockholders' equity and
comprehensive income and cash flows for the years ended December 31, 1998 and
1997 and the period October 1, 1996 through December 31, 1996 and the related
Predecessor's consolidated statements of operations, predecessor's equity and
comprehensive income and cash flows for the period January 1, 1996 through
September 30, 1996. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of Torch
Energy Advisors Incorporated and subsidiaries as of December 31, 1998 and 1997
and the results of their operations and their cash flows and those of their
Predecessors for the years ended December 31, 1998 and 1997, the period October
1, 1996 through December 31, 1996 and the period January 1, 1996 through
September 30, 1996, in conformity with generally accepted accounting principles.
As discussed in Notes 1 and 8, on September 30, 1996, certain members of the
Predecessor's management purchased the Predecessor. The consolidated financial
statements of the Company reflect assets and liabilities at fair value at the
date of the purchase. As a result, the consolidated financial statements of the
Company are presented on a different basis than those of the Predecessor and,
therefore, are not comparable in all respects.
March 30, 1999
Houston, Texas
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in Thousands)
ASSETS
December 31,
-----------------
1998 1997
-------- --------
CURRENT ASSETS:
Cash and cash equivalents.............................. $ 35,923 $ 49,900
Accounts receivable - product marketing................ 45,636 55,588
Accounts receivable - joint interest billing........... 10,692 7,903
Accounts receivable - oil and gas and other............ 23,357 23,840
Due from affiliates.................................... 7,856 3,405
Other current assets................................... 5,118 3,154
-------- --------
Total current assets................................. 128,582 143,790
-------- --------
PROPERTY AND EQUIPMENT, AT COST:
Oil and gas (successful efforts method)................ 8,106 6,354
Other fixed assets..................................... 10,363 5,543
-------- --------
18,469 11,897
Accumulated depreciation, depletion and amortization... (5,574) (2,179)
-------- --------
12,895 9,718
-------- --------
DUE FROM AFFILIATES........................................ 2,967 1,850
NOTES RECEIVABLE........................................... 37,001 13,363
INVESTMENT IN MARKETABLE SECURITIES........................ 741 1,650
EQUITY INVESTMENTS......................................... 5,735 4,049
INVESTMENTS AT COST........................................ 400 400
OTHER ASSETS............................................... 1,753 1,142
-------- --------
$190,074 $175,962
======== ========
See accompanying notes to consolidated financial statements.
2
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Amounts in Thousands, except Share Data)
LIABILITIES AND STOCKHOLDERS' EQUITY
December 31,
-------------------
1998 1997
-------- --------
CURRENT LIABILITIES:
Accounts payable - product marketing $ 46,519 $ 56,957
Accounts payable - joint interest billing 7,445 3,865
Accrued liabilities 21,221 24,933
Note payable to bank --- 60
Revenue, royalty and production taxes payable 31,917 30,516
-------- --------
Total current liabilities 107,102 116,331
-------- --------
OTHER LIABILITIES 7,618 7,216
-------- --------
NOTE PAYABLE TO BANK 36,277 10,614
-------- --------
SENIOR SUBORDINATED
NOTE PAYABLE - AFFILIATE 25,500 25,500
-------- --------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Common stock, par value $1.00, 1,000 shares
authorized, issued and outstanding 1 1
Additional paid-in capital 1,999 1,999
Accumulated comprehensive income - unrealized
gain (loss) in value of investment in equity
securities, net (516) 394
Retained earnings 12,093 13,907
-------- --------
Total stockholders' equity 13,577 16,301
-------- --------
$190,074 $175,962
======== ========
See accompanying notes to consolidated financial statements.
3
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in Thousands)
<TABLE>
<CAPTION>
Year Year October 1, January 1,
Ended Ended through through
December 31, December 31, December 31, September 30,
1998 1997 1996 1996
--------- --------- --------- -------------
(Company) (Company) (Company) (Predecessor)
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas revenues....................... $15,064 $18,522 $ 6,327 $ 9,942
Product marketing, net..................... 4,424 5,333 1,726 8,063
Service fees............................... 23,125 26,034 7,110 23,651
Overhead fees.............................. 8,485 8,962 2,356 9,028
Interest and other income.................. 5,559 5,328 841 1,803
Net gain on sale of assets................. 343 --- --- 5,787
------- ------- ------- -------
Total revenues............................ 57,000 64,179 18,360 58,274
------- ------- ------- -------
COSTS AND EXPENSES:
Oil and gas operating expenses............. 8,272 8,936 2,678 4,188
Depreciation, depletion and amortization... 3,567 2,307 847 6,553
General and administrative expenses........ 38,963 37,062 10,116 27,795
Interest expense........................... 3,683 2,816 588 1,033
Other expense.............................. 490 701 16 3,120
------- ------- ------- -------
Total costs and expenses................. 54,975 51,822 14,245 42,689
------- ------- ------- -------
Equity in loss of affiliates
and investees.............................. (2,174) (159) (135) (179)
------- ------- ------- -------
INCOME BEFORE INCOME TAXES AND
MINORITY INTEREST.......................... (149) 12,198 3,980 15,406
Income taxes..................................... --- 115 1,267 2,277
Minority interest................................ 1,038 426 463 ---
------- ------- ------- -------
NET INCOME (LOSS)................................ $(1,187) $11,657 $ 2,250 $13,129
======= ======= ======= =======
</TABLE>
See accompanying notes to consolidated financial statements.
4
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' AND PREDECESSOR'S
EQUITY AND COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31, 1998 AND 1997 AND OCTOBER 1, 1996
THROUGH DECEMBER 31, 1996 AND
JANUARY 1, 1996 THROUGH SEPTEMBER 30, 1996
(Amounts in Thousands)
<TABLE>
<CAPTION>
UNREALIZED GAIN TOTAL
(LOSS) IN VALUE OF STOCKHOLDERS' AND
COMMON STOCK INVESTMENT IN EQUITY RETAINED PREDECESSOR'S
SHARES AMOUNT PAID-IN CAPITAL SECURITIES, NET EARNINGS EQUITY
------ -------- --------------- --------------- -------- -----------------
<S> <C> <C> <C> <C> <C> <C>
Balance, January 1, 1996 (Predecessor) 1 $ 1 $ 32,142 $ (67) $ 45,518 $ 77,594
Comprehensive income:
Unrealized gain in value of investment
in equity securities (net of deferred
income tax expense of $6,265) --- --- --- 11,635 --- 11,635
Net income --- --- --- --- 13,129 13,129
----------------
Total comprehensive income 24,764
Parent contribution --- --- 10,105 --- --- 10,105
Cash dividend to Torchmark --- --- --- --- (35,625) (35,625)
Distribution of investment in securities --- --- --- (11,568) (58,212) (69,780)
------ -------- --------------- --------------- -------- -----------------
Balance, September 30, 1996 (Predecessor) 1 1 42,247 --- (35,190) 7,058
Transfer of equity of Predecessor (1) (1) (42,247) --- 35,190 (7,058)
Issuance of common stock pursuant to
Management Buyout 1 1 1,999 --- --- 2,000
Net income --- --- --- --- 2,250 2,250
------ -------- --------------- --------------- -------- -----------------
Balance, December 31, 1996 (Company) 1 1 1,999 --- 2,250 4,250
Comprehensive income:
Unrealized gain in value of investment in
equity securities --- --- --- 394 --- 394
Net income --- --- --- --- 11,657 11,657
----------------
Total comprehensive income 12,051
------ -------- --------------- --------------- -------- -----------------
Balance, December 31, 1997 (Company) 1 1 1,999 394 13,907 16,301
Dividends paid --- --- --- --- (627) (627)
Comprehensive loss:
Unrealized loss in value of investment in
equity securities --- --- --- (910) --- (910)
Net loss --- --- --- --- (1,187) (1,187)
----------------
Total comprehensive loss (2,097)
------ -------- --------------- --------------- -------- -----------------
Balance, December 31, 1998 (Company) 1 $ 1 $ 1,999 $ (516) $ 12,093 $ 13,577
====== ======== =============== =============== ======== =================
</TABLE>
See accompanying notes to consolidated financial statements.
5
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in Thousands)
<TABLE>
<CAPTION>
Year Year October 1, January 1,
Ended Ended through through
December 31, December 31, December 31, September 30,
1998 1997 1996 1996
------------ ------------ ------------ -------------
(Company) (Company) (Company) (Predecessor)
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (1,187) $ 11,657 $ 2,250 $ 13,129
Adjustments to reconcile net income (loss)
to net cash provided by (used in)
operating activities:
Depreciation, depletion and
amortization and impairment provision 3,567 2,307 847 6,553
Amortization of deferred revenues --- --- --- (2,161)
Equity in loss of affiliates and investees 2,174 159 135 179
Transaction fee --- (1,256) --- ---
Minority interest 1,038 426 463 ---
Deferred income taxes --- (908) 908 6,315
Gain on sale of oil and gas properties (343) --- --- (3,271)
Gain on sale of marketable securities --- --- --- (2,516)
Changes in assets and liabilities net of effects
of acquisitions accounted for under the
purchase method of accounting:
Accounts receivable 8,766 28,627 (43,896) 13,589
Due from affiliates (6,222) 2,908 24,064 (19,657)
Other current assets (1,950) (1,471) 4,895 (885)
Accounts payable and accrued liabilities (9,572) (15,846) 13,846 (19,021)
Due to affiliates --- (5,589) (5,567) 12,069
Revenue, royalty and production
taxes payable 1,401 (11,764) 333 17,006
Other (1,445) (2,496) (532) (11,482)
-------- -------- --------- --------
Net cash flows provided by (used in) operating
activities $ (3,773) $ 6,754 $ (2,254) $ 9,847
======== ======== ========= ========
</TABLE>
See accompanying notes to consolidated financial statements.
6
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
(Amounts in Thousands)
<TABLE>
<CAPTION>
Year Year October 1, January 1,
Ended Ended through through
December 31, December 31, December 31, September 30,
1998 1997 1996 1996
------------ ------------ ------------ -------------
(Company) (Company) (Company) (Predecessor)
<S> <C> <C> <C> <C>
CASH FLOWS FROM INVESTING ACTIVITIES:
Time deposits.................................. $ --- $ --- $ $ 36,066
Note receivable from officers.................. 567 826 (2,000) ---
Notes receivable............................... (24,609) (11,389) --- ---
Proceeds from sale of assets held for sale..... --- --- --- 9,248
Proceeds from the sale of assets............... 408 25,353 1,200 16,335
Proceeds from the sale of equity investments... --- --- --- 4,208
Investment in property and equipment........... (6,535) (5,572) (816) (13,982)
Investment in equity interests................. (3,679) (3,252) (389) (4,448)
Investments at cost............................ --- (400) --- ---
Payment for purchase of Petroleum Financial
Inc. (net of cash acquired)................... (1,207) --- --- ---
Distributions from investments in affiliates... 16 644 --- ---
Cash acquired in Management Buyout............. --- --- 6,502 ---
Cash paid to Torchmark in Management Buyout.... --- --- (15,500) ---
-------- -------- -------- --------
Net cash flows provided by (used in)
investing activities............................... $(35,039) $ 6,210 $(11,003) $ 47,427
-------- -------- -------- --------
</TABLE>
See accompanying notes to consolidated financial statements.
7
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
(Amounts in Thousands)
<TABLE>
<CAPTION>
Year Year October 1, January 1,
Ended Ended through through
December 31, December 31, December 31, September 30,
1998 1997 1996 1996
------------ ------------ ------------ -------------
(Company) (Company) (Company) (Predecessor)
<S> <C> <C> <C> <C>
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from note payable to bank..... $ 25,663 $10,674 $ --- $ ---
Repayment of note payable to bank...... (60) --- --- ---
Repayment of note payable.............. (141) --- --- ---
Payment of dividend.................... (627) --- --- (35,625)
Parent contribution.................... --- --- --- 10,105
Repayment of line of credit to bank.... --- --- --- (3,400)
-------- ------- -------- --------
Net cash flows provided by (used in)
financing activities 24,835 10,674 --- (28,920)
-------- ------- -------- --------
Net increase (decrease) in cash and
cash equivalents (13,977) 23,638 (13,257) 28,354
Cash and cash equivalents at beginning
of period 49,900 26,262 39,519 11,165
-------- ------- -------- --------
Cash and cash equivalents at end of period $ 35,923 $49,900 $ 26,262 $ 39,519
======== ======= ======== ========
Supplemental disclosures of cash flow
information:
Cash paid during the period for:
Interest $ 2,330 $ 2,338 $ 168 $ 985
======== ======= ======== ========
Income taxes $ 454 $ 797 $ --- $ 5,026
======== ======= ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
8
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
1. ORGANIZATION
Torch Energy Advisors Incorporated ("TEAI" or the "Company") provides an
extensive array of specialized outsourcing services to companies primarily
in the energy industry. Services include accounting and finance,
information technology, procurement, oil and gas operations, hydrocarbon
marketing, and property acquisitions and divestitures. TEAI also provides
growth capital, in the form of mezzanine finance and equity capital, to
independent oil and gas producers. Since 1981, the Company's clients have
included insurance companies, corporate and public pension funds,
foundations, endowments, foreign investors and public oil and gas
companies. Since inception, the Company has invested approximately $1.6
billion on behalf of the Company and its clients. The Company is
headquartered in Houston, Texas, and maintains operational district offices
in Texas, Oklahoma, California and Alabama.
Until September 1996, TEAI (the "Predecessor" when discussing periods prior
to September 30, 1996) operated as a single business segment and was a
wholly owned subsidiary of Torchmark Corporation ("Torchmark"), an
insurance and financial services holding company headquartered in
Birmingham, Alabama. On September 30, 1996, certain members of the
Predecessor's executive management, through the formation of Management
Holding Company ("MHC") and Torch Acquisition Company ("TAC"), purchased
TEAI from Torchmark ("the Management Buyout") (See Note 8). Torchmark
retained a warrant for 10% of TAC's common stock on a fully diluted basis.
The Management Buyout was recorded using the purchase method of accounting
as TEAI's executive management had no ownership in the Predecessor. During
1997, MHC was merged into TAC.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION -
The consolidated financial statements include the accounts of the Company,
its wholly owned subsidiaries and its majority owned subsidiaries. The
Company's investments in 15 oil and gas partnerships ("partnerships") were
accounted for under the equity method due to the Company's ability to
exercise significant influence over operating and financial policies of the
investees until April 1997 at which time the partnerships were sold to
Bellwether Exploration Company ("Bellwether"). All significant
intercompany accounts and transactions have been eliminated.
Effective November 1, 1996 Torch Energy Marketing, Inc. ("TEMI"), a wholly
owned subsidiary, formed a limited liability company with an unaffiliated
party to conduct gas marketing activities. TEMI acts as a manager and owns
a 50% interest in this venture. As the Company effectively controls the
venture through management contracts and execution of the day-to-day
operating and financial decisions, the activities for this venture are
included in the financial statements with the unaffiliated party's interest
reflected as minority interest. During 1996, the Company formed two limited
liability companies with an unaffiliated party to provide certain
management, administrative and support services to a foreign party. The
Company owned a 50% interest in both limited liability companies until
March 1997 at which time the companies were sold. Prior to March 1997, the
activities are consolidated in the financial statements with the
unaffiliated parties' interest reflected as minority interest. Effective
June 30, 1997, the Company purchased The Procurement Centre ("TPC") to
obtain the benefit of TPC's experience and expertise in providing
consulting and outsourcing services for the procurement of materials and
services,
9
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
inventory management, logistics and other administrative services. The
Company paid $375,000 to obtain a 75% interest in TPC. The activities of
TPC subsequent to the acquisition are consolidated in the financial
statements with the unaffiliated parties' interest reflected as a minority
interest. Prior activities of TPC are not material.
Torch Energy Finance Fund LPI ("TEFF"), a Texas limited liability
partnership, was formed on September 6, 1995 and amended on July 14, 1997
for the purpose of providing growth capital to small and mid-size oil and
gas companies for use in acquisition and exploitation opportunities. Torch
Energy Finance Company ("TEFC"), a wholly owned subsidiary, serves as the
sole general partner (10%) and the Company serves as the sole limited
partner (90%). Activities for TEFF are consolidated in the Company's
financial statements. Advances to third party oil and gas companies are
recorded as notes receivable. Equity investees, owned 20% through 50%, and
over which the Company exercises significant influence, are accounted for
by the equity method. All other unconsolidated investees are accounted for
by the cost method.
The Company has a limited partnership interest in Southern Missouri Gas
Company, L.P. ("SMGC"), a local natural gas distribution company located in
Missouri. This investment of $2.7 million at December 31, 1998 is
accounted for under the equity method.
Novistar, a wholly owned subsidiary, was formed on April 24, 1998 for the
purpose of providing state-of-the-art business process services including
transaction processing, information management and process reengineering in
three principal areas: oil and gas property administration, information
technology and procurement and inventory management. Activities for
Novistar are consolidated in the Company's financial statements.
Effective June 3, 1998, the Company formed a limited liability company,
Torch Drilling Services, L.L.C. ("Torch Drilling"), for the purpose of
acquiring a license to conduct short radius drilling technology on a pilot
project. Activities for Torch Drilling are consolidated in the Company's
financial statements. Effective December 15, 1998, the Company purchased
Petroleum Financial, Inc. ("PFI"), a privately held provider of accounting
and information technology outsourcing services to mid-market oil and gas
companies. The company paid $1.25 million to obtain PFI's existing client
base and to expand the Company's ability to reach new clients. The
activities of PFI subsequent to the acquisition are consolidated in the
financial statements. Prior activities of PFI are not material.
CASH AND CASH EQUIVALENTS -
Cash in excess of the Company's daily requirements is generally invested in
short-term, highly liquid investments with original maturities of six
months or less. Such investments are carried at cost, which approximates
fair value and, for purposes of reporting cash flows, are considered to be
cash equivalents.
INVESTMENT IN MARKETABLE SECURITIES -
Marketable investment securities are classified in three categories:
trading, available-for-sale, or held-to-maturity. Trading securities are
bought and held principally for the purpose of selling such securities in
the near term. Held-to-maturity securities are those securities in which
the Company has the ability and intent to hold the security until maturity.
All other securities not included in trading or held-to-maturity are
classified as available-for-sale.
10
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
The Company has no held-to-maturity or trading securities at December 31,
1998. The Company has available-for-sale securities which are recorded at
fair value, with unrealized gains and losses, excluded from earnings and
reported as accumulated comprehensive income, a separate component of the
stockholders' equity, net of deferred income taxes.
Dividend and interest income are recognized when earned. Realized gains
and losses for securities classified as available-for-sale were included in
earnings and were derived using the specific identification method for
determining the cost of securities sold.
PROPERTY AND EQUIPMENT -
Oil and gas properties are accounted for on the successful efforts method
whereby costs, including lease acquisition and intangible drilling costs
associated with exploration efforts which result in the discovery of proved
reserves and costs associated with development wells, whether or not
productive, are capitalized. Gain or loss is recognized when a property is
sold or ceases to produce and is abandoned. Capitalized costs of producing
oil and gas properties are amortized using the unit-of-production method
based on units of proved reserves as estimated by independent petroleum
engineers.
The Company recognizes an impairment loss when the carrying amount of a
long-lived asset exceeds the sum of the estimated undiscounted future cash
flow of the asset. For each long-lived asset determined to be impaired, an
impairment loss equal to the difference between the carrying value and the
fair value of the depletable unit was recognized. Fair value, on a
depletable unit basis, is estimated to be the present value of expected
future cash flows computed by applying estimated future oil and gas prices,
as determined by management, to estimated future production of oil and gas
reserves over the economic lives of the reserves. The Company incurred no
such writedown during the years ended December 31, 1998 and 1997 or the
periods October 1, 1996 to December 31, 1996 and January 1, 1996 to
September 30, 1996.
Costs of acquiring undeveloped oil and gas leases are capitalized and
assessed periodically to determine whether an impairment has occurred;
appropriate valuation allowances are established when necessary. No such
allowance was required during the years ended December 31, 1998 and 1997
and the periods October 1, 1996 to December 31, 1996 and January 1, 1996 to
September 30, 1996.
Fixed assets are depreciated on a straight-line basis over their estimated
useful lives. Leasehold improvements, which are recorded at cost, are
amortized on a straight-line basis over their estimated useful lives or the
life of the lease, whichever is shorter.
GAS BALANCING -
The Company uses the entitlement method for recording sales of natural gas.
Under the entitlement method of accounting, revenue is recorded based on
the Company's net revenue interest in production. Deliveries of natural gas
in excess of the Company's net revenue interest are recorded as liabilities
and under-deliveries are recorded as assets. Production imbalances are
recorded at the lower of the sales price in effect at the time of
production or the current market value. At December 31, 1998 and 1997, the
Company's liabilities due to gas sales in excess of
11
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
its entitled share were approximately $.67 million and $.47 million,
respectively, and the receivables for gas sales less than the Company's
entitled share were approximately $.56 million and $.53 million,
respectively.
DERIVATIVES -
The Company entered into a variety of commodity derivative financial
instruments (futures, swaps and option contracts) for non-trading purposes.
The Company made use of these derivative financial instruments as a hedging
strategy to manage commodity prices associated with gas sales and purchases
and to reduce the risk of price fluctuations. The Company uses the hedge
method of accounting for these instruments and, as a result, gains and
losses related to commodity derivatives that qualify as hedges of commodity
commitments are recognized in income when the underlying hedged physical
transaction closes. To qualify as hedges, these instruments must highly
correlate to anticipated future natural gas sales and purchases and crude
oil sales, such that the Company's exposure to the effects of price changes
is reduced. Gains and losses related to such instruments, to the extent
settled in cash and for which the physical transaction has not yet closed,
are reported in other current liabilities or other current assets as
deferred gains or losses. The Company had deferred gains of $.4 million and
$.3 million at December 31, 1998 and December 31, 1997, respectively.
There were no deferred gains or losses at December 31, 1996. Gains or
losses on derivative financial instruments that do not qualify as a hedge
are immediately recognized in income. Oil and gas revenues and product
marketing margin were increased by a total of $1.8 million in 1998,
decreased by a total of $2.3 million in 1997, decreased by $.1 million for
the period October 1, 1996 through December 31, 1996, and increased by $.8
million for the period January 1, 1996 through September 30, 1996 as a
result of such derivative activity.
INCOME TAXES -
Effective in 1997, TEAI and its subsidiaries elected to be treated as
qualified subchapter S corporations under Section 1361 (b) (3) of the
Internal Revenue Code of 1986. The effect of the election is that TAC will
file an S corporation tax return that includes TEAI and subsidiaries. Each
TAC stockholder is responsible for reporting its share of taxable income or
loss and no federal income taxes are recorded by the Company, except for a
tax on excess net passive income and certain built-in gains, if applicable.
Prior to the consummation of the Management Buyout, the Predecessor and its
subsidiaries were included in Torchmark's consolidated Federal income tax
return. Income taxes were recorded as if the Predecessor and its
subsidiaries filed a separate return and the Predecessor and its
subsidiaries received a current benefit to the extent their losses were
used in Torchmark's consolidated tax return. Taxes on income were reduced
by utilizable tax credits in Torchmark's consolidated tax return. For the
period January 1, 1996 through September 30, 1996, deferred income taxes
were accounted for using the asset and liability method of accounting for
income taxes. Under this method, deferred income taxes are recognized for
the tax consequences of "temporary differences" by applying enacted
statutory tax rates applicable to future years to differences between the
financial statement carrying amounts and the tax basis of existing assets
and liabilities. The effect on deferred income taxes of a change in tax
rates is recognized in income in the period the change occurs.
12
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
RECLASSIFICATIONS -
Certain reclassifications of prior period statements have been made to
conform with current reporting practices.
USE OF ESTIMATES -
Management of the Company has made a number of estimates and assumptions
relating to the reporting of assets and liabilities and the disclosure of
contingent assets and liabilities to prepare these financial statements in
conformity with generally accepted accounting principles. Actual results
could differ from those estimates.
3. RELATED PARTY TRANSACTIONS
ACCOUNTS RECEIVABLE -
On October 9, 1998, the Company was issued a promissory note from one of
the Company's officers for $1.8 million. Principal and interest is due on
July 1, 1999.
NOTE RECEIVABLES -
On December 31, 1995, the Predecessor was issued a non-interest bearing
note of approximately $18 million from Torchmark to replace an intercompany
obligation of an affiliate. The note was forgiven by the Predecessor as a
result of the Management Buyout.
ASSET MANAGEMENT -
The Company provides management services relating to oil and gas operations
for affiliated entities and investees, including oil and gas limited
partnerships. Bellwether and Nuevo Energy Company ("Nuevo") were
affiliates of the Predecessor. In accordance with the management
agreements, the Company provides various accounting and administrative
services for a fixed or variable fee. In addition, the Company receives
additional compensation for services related to property or corporate
acquisitions or divestitures. The Company's total management fees received
from related parties amounted to $1.0 million, $1.8 million and $2.8
million for the years ended December 31, 1998 and 1997 and the period
October 1, 1996 through December 31, 1996, respectively. The Predecessor's
total management fees received from related parties amounted to $23.7
million (includes $8 million related to Nuevo's purchase of Unocal
California properties) for the period January 1, 1996 through September 30,
1996.
In the ordinary course of business, the Company incurs intercompany
balances resulting from the payment of costs and expenses on behalf of
related parties and from charging management fees under the terms of the
respective management and administrative agreements. Such amounts are
settled on a regular basis, generally monthly.
PRODUCT MARKETING -
The Company markets oil and natural gas production for properties in which
related parties own interests. The Company's marketing fee ranges from .5%
to 3% of revenues; such charge is
13
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
customary within the oil and gas industry. Such revenues for the Company
amounted to $.3 million, $1.2 million and $.3 million for the years ended
December 31, 1998 and 1997 and the period October 1,1996 through December
31, 1996, respectively. Marketing fees for the Predecessor amounted to $4.0
million for the period January 1, 1996 through September 30, 1996.
WELL OPERATIONS -
The Company operates properties in which related parties own interests.
These entities are charged for all customary expenses and cost
reimbursements associated with such activities on the same basis as third
parties. Operators' overhead charged to affiliates by the Company for the
years ended December 31, 1998 and 1997 and the period October 1, 1996
through December 31, 1996 for these activities was $.5 million, $.5 million
and $.4 million, respectively. Operators' overhead charged to affiliates
by the Predecessor for the period January 1, 1996 through September 30,
1996 was $5.7 million.
OTHER -
Interest expense paid to Torchmark totaled $.6 million for the period
January 1, 1996 through September 30, 1996. No interest expense was paid
to related entities for the years ended December 31, 1998 and 1997 and the
period October 1, 1996 through December 31, 1996.
4. INCOME TAXES
The Company's and Predecessor's income tax provision for the years ended
December 31, 1998 and 1997 and the periods October 1, 1996 through December
31, 1996 and January 1, 1996 through September 30, 1996, is comprised of
the following (amounts in thousands):
<TABLE>
<CAPTION>
Year Year October 1, January 1,
Ended Ended through through
December 31, December 31, December 31, September 30,
1998 1997 1996 1996
----------- ----------- ----------- -------------
(Company) (Company) (Company) (Predecessor)
<S> <C> <C> <C> <C>
Current income tax expense (benefit)
Federal (1) $--- $ 548 $ 307 $(4,248)
State --- 475 52 210
---- ----- ------ -------
--- 1,023 359 (4,038)
---- ----- ------ -------
Deferred income tax expense (benefit)
Federal --- (809) 809 5,747
State --- (99) 99 568
---- ----- ------ -------
--- (908) 908 6,315
---- ----- ------ -------
$--- $ 115 $1,267 $ 2,277
==== ===== ====== =======
</TABLE>
(1) The 1997 amount relates to revisions of 1996 tax expense estimates.
14
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
The Company's effective income tax rate differed from the statutory tax
rate as follows:
<TABLE>
<CAPTION>
Year Year October 1, January 1,
Ended Ended through through
December 31, December 31, December 31, September 30,
1998 1997 1996 1996
------------ ------------ ------------ -------------
(Company) (Company) (Company) (Predecessor)
<S> <C> <C> <C> <C>
Statutory tax rate........... ---% ---% 34% 35%
State........................ --- 3 3 3
Section 29 tax credits....... --- --- (1) (23)
Other........................ --- (2) --- ---
------------ ------------ ------------ -------------
Effective tax rate........... ---% 1% 36% 15%
============ ============ ============ =============
</TABLE>
5. INVESTMENTS IN EQUITY SECURITIES
In March 1996, the Predecessor sold 17 million shares of Gulf Canada
Resources Ltd. ("Gulf Canada") shares (See Note 9), generating a pre-tax
gain of approximately $2.5 million. In April 1996, the Predecessor
received 1.3 million Nuevo shares (See Note 9) in exchange for certain
California offshore oil properties. In September 1996, the Predecessor's
interest in Gulf Canada (consisting of .9 million shares and 5.6 million
warrants), Nuevo, and an approximate 1% common stock interest in Bellwether
was transferred to Torchmark in connection with the Management Buyout (See
Note 8). In April 1997, the Company received 150,000 Bellwether shares and
a warrant to purchase 100,000 shares for the sale of certain partnerships
(See Note 9).
At December 31, 1998, the Company recorded $.5 million in unrealized losses
due to the difference between cost and market value in its investment in
Bellwether, resulting in a carrying value of $.7 million. At December 31,
1997, the Company recorded $.4 million in unrealized gains due to the
difference between cost and market value in its investment in Bellwether,
resulting in a carrying value of $1.7 million. During the period January
1, 1996 through September 30, 1996, the Company recorded $16.1 million and
$1.8 million in unrealized gains in Nuevo and Gulf Canada, resulting in a
carrying value at the time of the Management Buyout of $51.8 million and
$6.0 million, respectively. Carrying value of the investment in Bellwether
approximated fair value for the period January 1, 1996 through September
30, 1996. There were no equity securities for the period October 1, 1996
through December 31, 1996.
6. NOTES RECEIVABLE
On April 29, 1997, TEFF was issued a promissory note for up to $12.5
million from TEC Resources, LLC ("TEC") as evidence of TEFF's loan
agreement entered into on April 29, 1997 with TEC. An initial advance of
the loan was made to TEC on April 29, 1997 for costs and expenses
associated with certain oil and gas properties. The loan agreement
provides that additional advances be made upon TEC's request at TEFF's sole
discretion. On September 14, 1998, the maximum principal amount of the
promissory note was increased to $30 million. Certain oil and gas
property, other properties and all subsequently acquired assets of TEC
secure the promissory note, which matures on April 28, 2001. At December
31, 1998 and 1997, the outstanding balance under the loan agreement was
$16.6 million and $6.8 million, respectively.
15
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
Interest accrues on indebtedness at 10% and is payable quarterly to the
extent that there is positive cash flow from TEC's operations for the
quarter then ended.
On July 17, 1997, TEFF was issued a promissory note for up to $5.25 million
from NRC Development, LLC ("NRC") and NRC Pipeline, LLC as evidence of
TEFF's loan agreement entered into on July 17, 1997 with NRC and NRC
Pipeline, LLC. An initial advance of the loan was made to NRC on July 17,
1997 for costs and expenses associated with certain oil and gas properties.
The loan agreement provides that additional advances be made upon NRC's
request at TEFF's sole discretion. Certain oil and gas property, other
properties and all subsequently acquired assets of NRC or NRC Pipeline, LLC
secure the promissory note, which matures on July 17, 2002. At December
31, 1998 and 1997, the outstanding balance under the loan agreement was $4
million. Interest accrues on indebtedness at 15% and is payable quarterly
to the extent that there is positive cash flow from NRC's operations for
the quarter then ended.
On December 21, 1998, TEFF was issued a promissory note for up to $30
million from ARI Development, LLC ("ARI") as evidence of TEFF's loan
agreement entered into on December 21, 1998 with ARI. An additional
advance of the loan was made to ARI on December 21, 1998 for costs and
expenses associated with certain oil and gas properties. The loan
agreement provides that additional advances by made upon ARI's request at
TEFF's sole discretion. Certain oil and gas property, other properties and
all subsequently acquired assets of ARI secure the promissory note, which
matures on December 31, 2003. At December 31, 1998, the outstanding
balance under the loan agreement is $14.2 million. Interest accrues on
indebtedness at 10% and is payable quarterly to the extent that there is a
positive cash flow from ARI's operations for the quarter then ended.
The Company advanced $.7 million during 1998 to Carpatsky Petroleum, Inc.
("Carpatsky"), a Canadian publicly traded company, in exchange for a
promissory note bearing interest at 12% per annum. A further $.5 million
was advanced to Carpatsky under similar terms which was guaranteed by a
third party. Both notes plus accrued interest were due on June 30, 1998.
Since Carpatsky's default on its promissory notes, the Company has been
seeking repayment by various means. The Company has reached an agreement
in principle with Carpatsky to convert the promissory notes into equity in
Carpatsky. Under the agreement, the Company will convert the $.7 million
note into approximately 6.6 million common shares of Carpatsky with a
current market value of approximately $.65 million and a warrant to acquire
an additional number of common shares to be determined. The $.5 million
promissory note will be transferred to the guarantor at its face value plus
accrued interest.
In December 1996, the Company was issued promissory notes from the
Company's officers totaling $2 million. Interest accrues on indebtedness at
8%. Principal and interest payments are due annually through December 31,
2002.
7. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS
During the year ended December 31, 1995, employees of the Predecessor were
covered by Torchmark's retirement plans, including a defined benefit
pension plan and a defined contribution savings plan. Net periodic pension
costs for the defined benefit plan were calculated on the projected unit
credit actuarial cost method.
16
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
Effective January 1, 1996, the Predecessor terminated its participation in
the above plans and established a 401(k) retirement plan. During the
period January 1, 1996 to September 30, 1996, the Predecessor contributed
$1.3 million to the terminated plan leaving a balance of $2.1 million in
related accrued pension liabilities. This accrual was reversed into income
as the Company has no requirements to contribute future fundings to the
terminated plan. The 401(k) retirement plan is funded by employee and
Company contributions. Employees may contribute up to 12% of their
salaries and the Company matches 50% of employee contributions up to 6%.
The Company's contributions to this plan total $1.1 million and $.9 million
for the years ended December 31, 1998 and 1997 and $.2 million and $.6
million for the periods October 1, 1996 through December 31, 1996 and
January 1, 1996 through September 30, 1996, respectively. In addition, the
Company established a discretionary 401(k) retirement plan. During the
first quarter of the year, the Company has the option of contributing up to
an additional 3% of each employee's salary for the previous year to the
plan. The Company's contributions to this plan total $.6 million and $1
million for the years ended December 31, 1998 and 1997 and $.3 million and
$.9 million for the periods October 1, 1996 through December 31, 1996 and
January 1, 1996 through September 30, 1996, respectively. For both plans,
an employee is required to have been employed a minimum of one year by the
Company prior to participation. Effective January 1, 1998, the Company
waived the minimum one year employment requirement for 401(k) retirement
plan participation.
8. MANAGEMENT BUYOUT
On September 30, 1996, the Management Buyout occurred whereby certain
members of the Company's executive management purchased the Company from
Torchmark for $41 million; $25.5 million in the form of a senior
subordinated note payable (See Note 12) and $15.5 million in cash.
Immediately prior to the Management Buyout, the Predecessor dividended its
investments in Nuevo, Gulf Canada and Bellwether and certain other assets
to Torchmark (See Note 9) and received a cash contribution from Torchmark
for $10.5 million. As a result of this transaction, the Company received
working and other interests in oil and gas properties. Predecessor
management fees related to the properties conveyed to TEAI were $1.9
million for the period January 1, 1996 through September 30, 1996. In
addition, the Company received interests in certain properties in exchange
for consideration of up to $7 million, which is payable solely out of
production and is contingent upon the properties achieving pricing and
profitability thresholds. Based upon current pricing and profitability
projections, no such liability was recorded at December 31, 1998. A
liability of $.3 million is recorded at December 31, 1997.
9. ACQUISITIONS AND DISPOSITIONS OF ASSETS
In December 1995, the Predecessor entered into a series of transactions
which resulted in the sale of 17 million ordinary shares of Gulf Canada to
an affiliate of the Predecessor's principal lender for $68 million. In
connection with the transaction, the Predecessor had certain performance
obligations; $36.1 million of time deposits collaterized the transaction
until such obligations were satisfied. In March 1996, the performance
obligations were satisfied and the Predecessor recognized a pre-tax gain of
approximately $2.5 million upon the sale of the Gulf Canada stock. In
September 1996, the Predecessor's remaining .9 million Gulf Canada shares
were transferred to Torchmark in conjunction with the Management Buyout.
17
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
In April 1996, the Predecessor received 1.3 million Nuevo shares at $28 per
share in exchange for certain California offshore oil properties. A loss
of $1.7 million was recognized on this disposition. In September 1996,
these shares were transferred to Torchmark in conjunction with the
Management Buyout.
In April 1997, the Company sold its interest in oil and gas properties of
certain partnerships, under which the Company was a general partner and
provided management services, to Bellwether, a publicly traded oil and gas
company for which the Company acts as manager pursuant to a management
agreement, and a third party for $18.4 million and $3 million,
respectively. In addition, the Company received 150,000 shares of
Bellwether common stock valued at $8.375 per share and a warrant to
purchase 100,000 shares at $9.90 per share as a fee for advisory services
rendered in connection with the sale. During 1997, the Company sold its
interest in a gathering company to a third party for $1.8 million.
During the period January 1, 1996 through September 30, 1996, the
Predecessor sold its interest in certain oil and gas properties to a third
party for $16.3 million, generating a pre-tax gain of $4.9 million.
10. OTHER LONG-TERM LIABILITIES
Other long-term liabilities at December 31, 1998 and 1997 consist of the
following (amounts in thousands):
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Royalties payable............................ $2,086 $2,086
Litigation provision......................... 746 1,107
Minority interest............................ 2,551 1,556
Other........................................ 2,235 2,786
------ ------
$7,618 $7,535
====== ======
</TABLE>
11. TORCH ENERGY ROYALTY TRUST
The Company serves as sponsor and operator of a majority of the properties
in which the Torch Energy Royalty Trust (the "Trust") owns a net profits
interest. In connection with the formation of the Trust, the Company
entered into an oil and gas purchase contract ("Purchase Contract") which
expires on the termination date of the Trust, the earliest of which is
January 1, 2003. Under the Purchase Contract, the Company is obligated to
purchase all net production attributable to the Trust properties for
indexed prices for oil and gas. Such prices are calculated monthly and are
generally based on the average spot market prices of oil and gas, adjusted
to reflect the terms of a hedge contract ("Hedge Contract"), which expires
in the year 2000, to which the Company is a party. The Purchase Contract
also provides that a minimum price of $1.70 per MMbtu will be paid by the
Company for gas production. During the year ended December 31, 1998, the
Company purchased 8,051 MMCF of gas and 71 Mbbls of oil at an average price
of $2.06 per MCF and $11.09 per Bbl. During the year ended December 31,
1997, the Company purchased 9,085 MMCF of gas and 93 Mbbls of oil at an
average of $2.13 per MCF and $16.40 per Bbl. During the periods October 1,
1996 to December 31, 1996 and
18
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
January 1, 1996 to September 30, 1996, the Company purchased 2,604 MMCF and
8,488 MMCF of gas, respectively, and 35 Mbbls and 109 Mbbls of oil,
respectively, at an average price of $2.06 and $1.80 per MCF, respectively,
and $18.17 and $17.40 per Bbl, respectively. Under the Hedge Contract,
monthly quantities of gas hedged decreased from 531,167 MMbtus of gas in
1996 to 17,250 MMbtus of gas in 2000 and monthly quantities of oil hedged
decrease from 6,333 Bbls in 1996 to 167 Bbls in 2000. The price received
for gas under the Hedge Contract increases from $1.84 per MMbtu in 1996 to
$1.89 per MMbtu in 2000. The price received for oil under the Hedge
Contract increases from $19.94 per Bbl in 1996 to $20.20 per Bbl in 2000.
Additionally, the Company has purchased contracts expiring December 2001 to
further limit its exposure to losses under the minimum price obligation
Purchase Contract. Under these contracts, monthly quantities hedged
increase from 16,482 MMbtus per day in 1996 to 16,989 MMbtus per day in
2001 with floor pricing ranging from $1.83 to $1.81 per MMbtu.
12. DEBT
SENIOR SUBORDINATED NOTE PAYABLE - AFFILIATE -
On September 30, 1996, the Company recorded TAC's $25.5 million Senior
Subordinated Note (the "Note") payable to Torchmark as part of the purchase
price for the Management Buyout. The Note accrues interest at 9% per
annum, payable semiannually, and the principal is due and payable on
September 30, 2004.
LINE OF CREDIT -
The Company maintains a $13 million credit facility (the "Credit Facility")
with a bank. Interest accrues on indebtedness, at the Company's option, at
the bank's prime rate (6.6% at December 31, 1998) if less than 50% of
revolver borrowing base is outstanding ($5 million at December 31, 1998),
prime plus .25% if 50% or more, but less than 75% of revolver borrowing
base is outstanding or prime plus .50% if 75% or more of revolver borrowing
base is outstanding; or the 1 year London Interbank Offered Rate ("LIBOR")
(5.1% at December 31, 1998) plus 1.5% if less than 50% of revolver
borrowing base is outstanding, libor plus 1.75% if 50% or more, but less
than 75% of revolver borrowing base is outstanding or libor plus 2% if 75%
or more of revolver borrowing base is outstanding. The Credit Facility
contains, among other terms, provisions for the maintenance of certain
financial ratios and restrictions on additional debt. As of December 31,
1998, the Company was not in compliance with one of its financial ratios.
The Company has received a waiver on the consolidated interest coverage
ratio as of December 31, 1998. Certain oil and gas properties, stock and
fixed assets secure the Credit Facility which matures on September 30,
1999. At December 31, 1998 and 1997, there was no outstanding balance under
the line of credit.
On July 16, 1997, TEFF entered into a $90 million credit facility the "TEFF
Facility") with a bank. Ordinary interest accrues on indebtedness, at
TEFF's option, at the bank's prime rate plus 0.5% (8.25% at December 31,
1998) or LIBOR plus 2.0% (7.10% at December 31, 1998) if the loans
outstanding are less than or equal to the portfolio base ($20.1 million at
December 31, 1998); and at the bank's prime rate plus 5.5% (13.25% at
December 31, 1998) or LIBOR plus 7.0% (12.10% at December 31, 1998) of the
portion of loans outstanding in excess of the portfolio base. If the
outstanding balance under the TEFF Facility exceeds $75 million, then the
ordinary interest rate shall be reduced by 0.5%. Principal and interest on
the loan will be repaid from cash flow from TEFF's underlying investments.
The amount of such repayments will vary
19
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
between 70% to 100% of the cash flow, depending on the ratio of portfolio
base to the outstanding principal balance of the loan. The TEFF Facility
contains, among other terms, provisions for the maintenance of certain
financial ratios and restrictions on additional debt. All security in the
investments currently owned by TEFF or hereafter acquired and proceeds
thereof, secure the TEFF Facility, which matures on December 31, 2003. At
December 31, 1998, the outstanding balance under the TEFF Facility was
$36.3 million at a weighted average interest rate of 9.7%. At December 31,
1997 the outstanding balance under the TEFF facility was $10.6 million. In
addition the principle and interest payments mentioned above, the bank will
receive 50% of the remaining cash flow after deduction of such principle
and interest payments (NCFI). Until such time as the NCFI payments are
equal to TEFF's partners' contributions, these amounts will be considered
additional principle repayments. After that time, the payments will be
considered additional expense. The TEFF Facility provides that NCFI be paid
through December 31, 2011 at which time the bank's right to receive NCFI
shall terminate. No such interest was incurred for the years ended December
31, 1998 and 1997.
On November 14, 1997, TPC entered into a $200,000 credit facility (the "TPC
Facility") with a bank. Interest accrued on indebtedness at the bank's
prime rate. All accounts receivable then owned by TPC or thereafter
acquired and proceeds thereof, but not the contracts themselves, secured
the TPC Facility which matured on November 2, 1998. At December 31, 1997,
the outstanding balance under the TPC Facility was $60,000. There is no
credit facility for TPC at December 31, 1998.
13. COMMITMENTS AND CONTINGENCIES
LITIGATION -
The Company is involved in certain litigation arising out of the normal
course of business, none of which, in the opinion of the Company, will have
any material adverse effect on the financial position or results of
operations of the Company as a whole. Certain lawsuits to which the
Company was a party were assumed by Torchmark as a result of the Management
Buyout.
SMGC -
SMGC has a $29 million bank loan due on June 30, 1999. This loan is
guaranteed by the general partner of SMGC. TEMI has guaranteed the general
partner that it will share proportionally (50%) if any payments are
required by the general partner for repayment of SMGC's loan. The current
financial position of SMGC would not enable it to repay the loan when due.
SMGC is attempting to either renegotiate the terms of the loan or seek
other financing options. While the Company does not expect to be required
to perform under the TEMI guarantee, the carrying value of the Company's
investment in SMGC, in the opinion of the Company, would not result in an
impairment to its investment should TEMI be required to repay its portion
of the loan.
20
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
LEASE OBLIGATIONS -
Rental expense for operating leases was approximately $1.7 million, $1.7
million, $.6 million and $1.6 million for the years ended December 31, 1998
and 1997 and the periods October 1, 1996 through December 31, 1996 and
January 1, 1996 through September 30, 1996, respectively. Future minimum
payments under all noncancellable leases, including amounts allocable to
affiliates, having initial terms of one year or more consisted of the
following as of December 31, 1997 (amounts in thousands):
Operating
Year Ending December 31, Leases
------------------------ ----------
1999.............................. $ 1,970
2000.............................. 1,886
2001.............................. 1,812
2002.............................. 1,980
2003.............................. 1,889
Thereafter........................ 5,690
-------
$15,227
=======
14. FINANCIAL DERIVATIVES
The Company uses futures, swap and option contracts to hedge anticipated
sales and purchases for pricing commitments of natural gas and crude oil,
to reduce the Company's exposure to changes in the market price of natural
gas and crude oil, and to fix the price for natural gas and crude oil
independently of the physical purchase or sale. Futures involves buying
the underlying commodity at fixed prices. Over-the-counter swap contracts
require the Company to receive or make payments based on the price of the
underlying commodity and are used to manage price and location risk. The
Company uses futures, swaps and options to manage margins on underlying
fixed-price purchase or sales commitments for physical quantities of the
underlying commodity. The Company holds one natural gas option which
provides the right, but not the requirement, for the counterparty to sell
natural gas to the Company at a fixed price. The Company also holds one
natural gas option to limit its exposure to losses under the minimum price
obligation to the "Trust" (see Note 11) risk which provides the right, but
not the requirement, for the Company to sell natural gas to the
counterparty at a fixed price. At December 31, 1998, the Company had
natural gas basis swap agreements with broker-dealers to exchange monthly
payments on notional quantities amounting to 98 million MMBTU over the
ensuing 3 years. At December 31, 1998, the Company had natural gas price
swap agreements with broker-dealers to exchange monthly payments on
notional quantities amounting to 32 million MMBTU over the ensuing 3 years.
Under the price swap agreements, the Company will realize an average price
of $2.16 per MMBTU. Under a 6 Mbbl oil price swap agreement, the Company
will realize a floor price of $20.17 per barrel.
21
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
Determination of Fair Values of Financial Instruments
-----------------------------------------------------
Fair value for cash, short-term investments, receivables, other assets and
payables approximates carrying value. The following tables detail the
carrying values and approximate fair values of the Company's other
investments and derivative financial instruments at December 31, 1998 and
1997.
<TABLE>
<CAPTION>
1998
(Amounts in thousands) Carrying Approximate
Value Fair Value
-------- -----------
<S> <C> <C>
Derivative assets:
Crude Oil price swaps $ --- $ 41
Natural gas price swaps --- 929
Natural gas basis swaps --- 266
Natural gas options --- 162
Derivative liabilities:
Long-term debt 25,500 25,500
Line of credit - TEFF 36,277 36,277
1997
(Amounts in thousands) Carrying Approximate
Value Fair Value
-------- -----------
Derivative assets:
Crude Oil price swaps $ --- $ 67
Natural gas price swaps --- 129
Derivative liabilities:
Long-term debt 25,500 25,500
Line of credit TEFF 10,614 10,614
Line of credit TPC 60 60
</TABLE>
The Company is exposed to credit losses in the event of nonperformance by
the counterparties to its derivative financial assets but has no off-
balance-sheet credit risk of accounting loss. The Company anticipates,
however, that counterparties will be able to fully satisfy their
obligations under the contracts. Futures contracts are guaranteed
settlement by the NYMEX and have nominal credit risk.
15. DEFERRED REVENUE RECOGNITION
In conjunction with the formation of the Trust and a commmission related to
the Gulf Canada transaction, deferred revenue was being recognized as
earned for prepaid management fees. For the Trust fees, deferred revenue
was being amortized, based on estimated production presented in reserve
reports, through 2003. For Gulf Canada fees, deferred revenue was being
amortized over three years as the Predecessor maintained certain
responsibilities under a participation agreement (See Note 9). In
conjunction with the Management Buyout, Torchmark was distributed the Gulf
Canada stock and assumed the responsibilities under the participation
22
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
agreement. No deferred revenue was recorded in conjunction with the
Management Buyout. Predecessor management fees related to these properties
were $2.5 million for the period January 1, 1996 through September 30,
1996.
16. SFAS 131: DISCLOSURES ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED
INFORMATION
In June 1997, the FASB issued Statement of Financial Accounting Standards
No. 131, "Disclosures about Segments of an Enterprise and Related
Information" ("SFAS 131"). SFAS 131 establishes standards for the manner
public enterprises are required to report information about operating
segments in annual financial statements and requires the reporting of
selected information about operating segments in interim financial reports
to shareholders. SFAS 131 also establishes standards for related
disclosures about products and services, geographic areas, and major
customers. The Company adopted SFAS 131 at December 31, 1998.
The Company has four reportable segments: service activities, the capital
group, the trading group and oil and gas properties. The service
activities segment provides technical and administrative services to energy
companies, primarily through outsourcing arrangements. The capital group
segment provides growth capital to independent oil and gas companies
through TEFF, a fund formed to provide small to mid-size companies with
capital for acquisition and exploitation opportunities. The trading group
segment engages in various hydrocarbon marketing and trading activities.
The oil and gas properties segment consists of revenue from interests the
Company holds in certain oil and gas properties.
The Company's reportable segments are strategic business units that offer
different services. Each business segment is managed separately based on
the nature of the services provided to clients and based on the different
technology and marketing strategies required by each of the segments. The
accounting policies of the segments are the same as those described in the
summary of significant accounting policies (see Note 2 of the Notes to
Consolidated Financial Statements). The Company evaluates performance based
on profit or loss from operations. Intersegment fees are accounted for as
if the fees were to third parties.
23
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
The following tables represent reported segment profit or loss and segment
assets for the years ended December 31, 1998 and 1997 and for the period October
1, 1996 through December 31, 1996 (amounts in thousands). Such information is
not included for the period January 1, 1996 through September 30, 1996 as this
information would be impracticable to include as a result of the Management
Buyout on September 30, 1996 (see Note 8 of the Notes to Consolidated Financial
Statements).
<TABLE>
<CAPTION>
Year Ended December 31, 1998
---------------------------------------------------------------------------------
Service Capital Trading Oil & Gas
Activities Group Group Properties Totals
---------- ----- ----- ---------- ------
<S> <C> <C> <C> <C> <C>
Revenues from external clients............ $ 30,984 $ --- $ 5,092 $ 15,064 $ 51,140
Intersegment revenues..................... 3,636 --- --- --- 3,636
Interest revenue.......................... --- 1,783 1,229 --- 3,012
Interest expense.......................... --- 1,353 --- --- 1,353
Depletion, depreciation and
Amortization.............................. 1,838 --- --- 1,223 3,061
Equity in loss of investees............... --- 862 --- --- 862
Segment profit (loss)..................... 1,804 (970) 1,116 2,080 4,030
Other significant non-cash items:
Segment assets............................ 5,221 38,186 --- 5,735 49,142
Equity in investees....................... --- 2,988 --- --- 2,988
Expenditures for segment assets........... 5,611 --- --- 1,752 7,363
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1997
---------------------------------------------------------------------------------
Service Capital Trading Oil & Gas
Activities Group Group Properties Totals
---------- ----- ----- ---------- ------
<S> <C> <C> <C> <C> <C>
Revenues from external customers.......... $ 34,260 $ --- $ 6,068 $ 18,522 $ 58,850
Intersegment revenues..................... 3,186 --- --- --- 3,186
Interest revenue.......................... --- 675 862 --- 1,537
Interest expense.......................... --- 476 --- --- 476
Depletion, depreciation and
amortization.............................. 604 --- --- 1,380 1,984
Segment profit (loss)..................... 6,881 (200) 2,312 5,020 14,013
Other significant non-cash items:
Segment assets............................ 2,653 13,310 --- 5,206 21,169
Equity in investees....................... --- 2,121 --- --- 2,121
Expenditures for segment assets........... 2,655 --- --- 2,362 5,017
</TABLE>
<TABLE>
<CAPTION>
Period October 1, 1996 through December 31, 1996
--------------------------------------------------------------------------------
Service Capital Trading Oil & Gas
Activities Group Group Properties Totals
---------- ----- ----- ---------- ------
<S> <C> <C> <C> <C> <C>
Revenues from external customers.......... $ 9,187 $ --- $ 2,005 $ 6,327 $ 17,519
Intersegment revenues..................... 819 --- --- --- 819
Interest revenue.......................... --- --- 187 --- 187
Interest expense.......................... --- --- --- --- ---
Depletion, depreciation and
amortization.............................. 65 --- --- 698 763
Segment profit (loss)..................... 1,403 --- 1,564 2,132 5,099
Other significant non-cash items:
Segment assets............................ 716 --- --- 17,466 18,182
Expenditures for segment assets........... 343 --- --- 311 654
</TABLE>
24
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
The following is a reconciliation of reportable segment revenues,
expenditures, profit or loss, assets and equity in investees to the
Company's consolidated totals for the years ended December 31, 1998 and
1997 and for the period October 1, 1996 through December 31, 1996 (amounts
in thousands):
<TABLE>
<CAPTION>
Year Ended Year Ended October 1, through
December 31, 1998 December 31, 1997 December 31, 1996
-------------------- -------------------- ---------------------
<S> <C> <C> <C>
Revenues
Total revenues for reportable segments............ $ 57,788 $ 63,573 $ 18,525
Other revenues.................................... 2,848 3,792 654
Elimination of intersegment revenues.............. (3,636) (3,186) (819)
-------------------- -------------------- ---------------------
Total consolidated revenues....................... $ 57,000 $ 64,179 $ 18,360
==================== ==================== =====================
Interest Expense
Total interest expense for reportable segments.... $ 1,353 $ 476 $ ---
Other interest expense............................ 2,330 2,340 588
-------------------- -------------------- ---------------------
Total interest expense............................ $ 3,683 $ 2,816 $ 588
==================== ==================== =====================
Depletion, Depreciation and Amortization:
Total depletion, depreciation and amortization
for reportable segments........................... $ 3,061 $ 1,984 $ 763
Other depletion, depreciation and amortization.... 506 323 84
-------------------- -------------------- ---------------------
Total depletion, depreciation and Amortization.... $ 3,567 $ 2,307 $ 847
==================== ==================== =====================
Equity in Loss of Investees:
Total equity in loss of investees for reportable
Segments.......................................... $ 862 $ --- $ ---
Other equity in loss of investees................. 1,312 159 135
-------------------- -------------------- ---------------------
Total equity in loss of investees................. $ 2,174 $ 159 $ 135
==================== ==================== =====================
Profit or Loss
Total profit or loss for reportable segments...... $ 4,030 $ 14,013 $ 5,099
Other profit or loss.............................. (5,217) (2,356) (2,849)
-------------------- -------------------- ---------------------
Net income (loss)................................. $ (1,187) $ 11,657 $ 2,250
==================== ==================== =====================
Assets
Total assets for reportable segments.............. $ 49,142 $ 21,169 $ 18,182
Other assets...................................... 140,932 154,793 171,957
-------------------- -------------------- ---------------------
Consolidated total................................ $ 190,074 $ 175,962 $ 190,139
==================== ==================== =====================
Equity in Investees
Total equity in investees for reportable segments. $ 2,988 $ 2,121 $ ---
Other equity in investees......................... 2,747 1,928 12,812
-------------------- -------------------- ---------------------
Consolidated equity in investees.................. $ 5,735 $ 4,049 $ 12,812
==================== ==================== =====================
</TABLE>
25
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MAJOR CUSTOMER -
One customer accounted for 13.6% and 26% and a different customer accounted
for 18.5% of the gross gas marketing revenues during the years ended
December 31, 1998 and 1997 and the period October 1, 1996 through December
31, 1996, respectively. There were no customers that accounted for more
than 10% of the Company's gross gas marketing revenues for the period
January 1, 1996 through September 30, 1996. Revenues from two customers,
Bellwether and Nuevo, totaled $25 million, $29 million and $6.6 million in
service and overhead fees for the years ended December 31, 1998 and 1997
and the period October 1, 1996 through December 31, 1996, respectively. The
Company does not believe that it is dependent upon any particular customer
for sales of oil and gas. The management service contract with Nuevo was
renegotiated and effective 1999, consists of seven separate service
contracts with terms that very between one to four years. The management
service agreement with Bellwether extends through the end of 2000. The
loss of one or both of these customers would have a material effect on the
Company.
17. SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED)
OIL AND GAS PRODUCING ACTIVITIES -
Included herein is information with respect to oil and gas acquisition,
exploration, development and production activities, which is based on
estimates of year-end oil and gas reserve quantities and estimates of
future development costs and production schedules. Reserve quantities and
future production are primarily based upon reserve reports prepared by
independent petroleum engineering firms of Gruy Engineering Corporation,
H.J. Gruy and Associates, Inc., Ryder Scott Company, and T.J. Smith &
Company, Inc. and by in-house reserve engineers. These estimates are
inherently imprecise and subject to revisions from time to time.
Estimates of future net cash flows from proved reserves of gas, oil,
condensate and natural gas liquids (NGL's) were made in accordance with
Financial Accounting Standards Board Statement No. 69, "Disclosures about
Oil and Gas Producing Activities." The estimates are based on prices in
effect at year-end. Estimated future cash inflows are reduced by estimated
future development and production costs based on year-end cost levels,
assuming continuation of existing economic conditions, and by estimated
future income tax expense. Prior to 1997, tax expense was calculated by
applying the existing statutory tax rates, including any known future
changes, to the pre-tax net cash flows, less depreciation of the tax basis
of the properties and depletion allowances applicable to the gas, oil,
condensate and NGL's production. Effective in 1997, the Company is an S-
Corporation for income tax purposes and has a zero effective income tax
rate (See Note 2). The results of these disclosures should not be construed
to represent the fair market value of the Company's oil and gas properties.
A market value determination would include many additional factors
including: (i) anticipated future increases or decreases in oil and gas
prices and production and development costs; (ii) an allowance for return
on investment; (iii) the value of additional reserves, not considered
proved at the present, which may be recovered as a result of further
exploration and development activities; and (iv) other business risks.
26
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
Costs incurred -
The following table sets forth the capitalized costs incurred in oil and
gas activities for the years ended December 31, 1998, 1997 and 1996
(amounts in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Cost incurred during the year
Property acquisition............ $ --- $ --- $ ---
Exploration..................... --- --- ---
Development..................... 1,752 2,739 9,078
------ ------ ------
$1,752 $2,739 $9,078
====== ====== ======
</TABLE>
CAPITALIZED COSTS RELATING TO OIL AND GAS ACTIVITIES -
The following table sets forth the capitalized costs relating to oil and
gas activities and the associated accumulated depreciation, depletion and
amortization (amounts in thousands):
<TABLE>
<CAPTION>
December 31,
1998 1997
---- ----
<S> <C> <C>
Capitalized costs:
Proved properties........................................ $ 8,106 $ 6,354
Accumulated depreciation, depletion and
amortization............................................. (2,371) (1,148)
------- -------
Net capitalized costs................................... $ 5,735 $ 5,206
======= =======
</TABLE>
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (AMOUNTS IN THOUSANDS) -
<TABLE>
<CAPTION>
Year Year October 1, January 1,
Ended Ended through through
December 31, December 31, December 31, September 30,
1998 1997 1996 1996
------------ ------------ ------------ -------------
(Company) (Company) (Company) (Predecessor)
<S> <C> <C> <C> <C>
Revenues from oil and gas producing
activities........................... $15,064 $18,522 $ 6,327 $ 9,942
Production costs.................... (8,272) (8,936) (2,678) (4,188)
Depreciation, depletion and
amortization........................ (1,223) (1,380) (698) (3,922)
Income tax provision *.............. --- --- (1,003) (641)
------- ------- ------- ------
Results of operations from producing
activities (excluding corporate
overhead and interest costs)......... $ 5,569 $ 8,206 $ 1,948 $ 1,191
======= ======= ======= ======
</TABLE>
27
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
* No income tax provision is recorded in 1998 or 1997 as the Company elected
subchapter S corporation status effective January 1, 1997 (See Note 2).
RESERVES-
The Company's estimated total proved and proved developed reserves of oil and
gas for the years ended December 31, 1998, 1997 and 1996 are as follows:
<TABLE>
<CAPTION>
1998 1997 1996
-------------- --------------- ---------------
Oil Gas Oil Gas Oil Gas
(Mbbl) (Mmcf) (Mbbl) (Mmcf) (Mbbl) (Mmcf)
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves at
beginning of year.................................................... 47 120,105 1,430 122,801 1,294 11,158
Purchases of reserves
in place............................................................. --- --- --- --- 226 94,272
Sales of reserves in place............................................ --- --- (1,312) (10,261) (2,740) (2,091)
Revisions of previous
estimates............................................................ 4 (51,681) (4) 14,539 (75) (1,609)
Transfer (to)/from assets held
for sale............................................................. --- --- --- --- 3,054 15,556
Extensions and discoveries............................................ --- 10,408 --- --- 41 10,714
Production............................................................ (11) (6,640) (67) (6,974) (370) (5,199)
------ ------- ------ ------- ------ -------
Proved reserves at end
of year.............................................................. 40 72,192 47 120,105 1,430 122,801
====== ======= ====== ======= ====== =======
Proved developed reserves -
Beginning of year..................................................... 38 115,540 1,141 111,166 992 9,583
====== ======= ====== ======= ====== =======
End of year........................................................... 31 55,997 38 115,540 1,141 111,166
====== ======= ====== ======= ====== =======
</TABLE>
28
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
DISCOUNTED FUTURE NET CASH FLOWS -
The standardized measure of discounted future net cash flows and changes therein
related to proved oil and gas reserves are shown below (amounts in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------
1998 1997 1996
--------- --------- ----------
<S> <C> <C> <C>
Future cash inflows.................... $131,717 $ 296,161 $ 499,396
Future production costs................ (99,736) (213,799) (274,243)
Future development costs............... (5,998) (3,715) (8,390)
-------- --------- ---------
Future net inflows before income tax... 25,983 78,647 216,763
Future income taxes*................... --- --- (68,539)
-------- --------- ---------
Future net cash flows.................. 25,983 78,647 148,224
10% discount factor.................... (10,366) (40,760) (75,345)
-------- --------- ---------
Standardized measure of discounted
future net cash flows................. $ 15,617 $ 37,887 $ 72,879
========= ========= =========
</TABLE>
* No income tax provision is recorded in 1998 or 1997 as the Company elected
subchapter S corporation status effective January 1, 1997 (See Note 2).
The following are the principal sources of change in the standardized measure of
discounted future net cash flows (amounts in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1998 1997 1996
-------- --------- ---------
<S> <C> <C> <C>
Standardized measure -
Beginning of year......................... $ 37,887 $ 72,879 $ 14,668
Sales, net of production costs............ (6,792) (9,586) (9,403)
Transfer (to)/from assets held for sale... --- --- 23,445
Purchases of reserves in-place............ --- --- 68,698
Net change in prices and
production costs......................... (17,591) (46,379) 406
Extensions, discoveries and
improved recovery, net of future
production and development costs......... 6,909 --- 8,008
Changes in estimated future
development costs........................ (1,593) (930) (786)
Development costs incurred during
the period............................... 1,752 2,739 9,078
Revisions of quantity estimates........... (7,718) 4,700 (349)
Accretion of discount..................... 3,789 10,260 1,692
Net change in income taxes................ --- 29,724 (27,467)
Sales of reserves in-place................ --- (26,810) (18,686)
Changes in production rates and
other.................................... (1,026) 1,290 3,575
-------- -------- --------
Standardized measure -
end of year............................... $ 15,617 $ 37,887 $ 72,879
======== ======== ========
</TABLE>
29
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED
(Unaudited)
The following should be read in conjunction with the consolidated financial
statements, and the related notes thereto, of Torch Energy Advisors Incorporated
and its subsidiaries (the "Company").
DISCUSSION OF YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Revenues
The Company engages in two principal lines of business: providing technical and
administrative services to energy companies, primarily through outsourcing
arrangements; and providing growth capital to independent oil and gas companies.
In addition, the Company also engages in various hydrocarbon marketing and
trading activities and receives revenue from interests it holds in oil and gas
properties, most of which were acquired in conjunction with the Management
Buyout.
The Company's service activities, which include accounting and finance,
information technology, oil and gas operations and engineering, hydrocarbon
marketing, acquisitions and divestitures, and various administrative services,
accounted for over 60% of revenues in 1998. Revenues for such service
activities are received under various outsourcing and management contracts and
are classified primarily as Service Fees or Overhead Fees. Service Fees include
payments for management and administrative services, certain hydrocarbon
marketing activities, and consulting services as well as transaction fees
received for arranging or advising clients on acquisitions, divestitures or
financings. The Company also receives substantial fees related to oil and gas
field operations and gas plant operations, which it classifies as Overhead Fees.
Overhead Fees are a combination of fees paid by clients and reimbursements
received from working interest owners customarily paid to the operator of oil
and gas properties.
The Company's contracts for outsourcing and management services differ from
contract to contract in how the Company is paid for its services. Certain
contracts contain provisions whereby the Company is paid based upon the amount
of book assets and operating cash flow of its clients. Others are based upon a
set fee or a pricing formula related to the activities performed. As such,
Service Fees may fluctuate from year to year based on the level of activity of
the Company's clients or other industry and economic factors, such as the level
of oil and gas prices. The Company expects to grow Service Fees in future years
by adding additional outsourcing contracts with new clients and expanding the
level of activities for existing clients.
Service Fees totaled $23.1 million in 1998, down 11.2% from the 1997 figure of
$26.0 million primarily due to a decrease in total assets and operating cash
flow on Nuevo Energy Company ("Nuevo"). Fees were down 15.6% in 1997 from the
1996 high of $30.8 million due primarily to the $8.0 million transaction fee
recorded in 1996 for arranging and advising Nuevo on its nearly $500 million
purchase of Unocal's California properties.
Overhead Fees equaled $8.5 million in 1998, down from $9.0 million and $11.4
million in 1997, and 1996, respectively. The 1998 decrease is related to the
sale of various non-core properties by clients. The reduction in 1997 is
primarily due to the acquisition of certain oil and gas property interests in
September 1996 for which the Company previously received
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED
(Unaudited)
Overhead Fees from Torchmark. The Company no longer records Overhead Fees
related to its management of these properties.
The Company's principal oil and gas properties relate to production payments
obtained in conjunction with the Management Buyout in September 1996. The
Company's major properties are coal-seam gas fields located in Alabama and
Wyoming. The Company also holds interests in gas fields in Texas and Louisiana.
Oil and gas revenues for 1998 were $15.1 million, down 18.4% from 1997 oil and
gas revenues of $18.5 million. This decrease is mainly attributable to 1997
including a partial year of revenues prior to the sale of certain oil and gas
properties in April 1997 (See Note 9 of the Notes to Consolidated Financial
Statements). Oil and gas revenues for 1997 were $18.5 million, up 13.5% from
1996 oil and gas revenues of $16.3 million. This increase is mainly
attributable to the acquisition of property interests in the Management Buyout,
which more than offset the sale of certain oil and gas properties in September
1996 (See Notes 8 and 9 of the Notes to Consolidated Financial Statements).
In 1997, the Company began to provide growth capital to oil and gas companies
through Torch Energy Finance Fund LPI ("TEFF"), a fund formed to provide small
to mid-size companies with capital for acquisition and exploitation
opportunities. TEFF was formed in September 1995, but its resources were
expanded in July 1997, when the Company reached an agreement with the Bank of
Montreal ("BMO") to provide additional capital for TEFF. The Company records
interest income from parties financed by TEFF. In 1998 and 1997, such revenues
totaled $1.8 million and $.7 million, respectively.
The Company also engages in various hydrocarbon marketing and trading
activities. Revenues for these activities are recorded net of the cost of goods
purchased for trading purposes. Net product marketing revenues decreased to
$4.4 million in 1998 from $5.3 million and $9.8 million in 1997 and 1996,
respectively.
From time to time, the Company has sold interests in various oil and gas
properties and securities. In March 1996, the Company sold 17 million Gulf
Canada shares, generating a pre-tax gain of approximately $2.5 million. In
April 1996, the Company received 1.3 million Nuevo shares in exchange for
certain California offshore oil properties. A loss of $1.7 million was
recognized on this disposition. In September 1996, the Company's interest in
Gulf Canada and Nuevo was transferred to Torchmark in connection with the
Management Buyout. In August 1996 and September 1996, the Company sold its
interest in certain oil and gas properties to a third party for $16.3 million,
generating a pre-tax gain of $4.9 million. In April 1997, the Company sold its
interest in oil and gas properties of certain partnerships to Bellwether for
$18.4 million. As a fee for advisory services rendered in connection with the
sale, the Company received .15 million shares of Bellwether common stock at
$8.375 per share and a warrant to purchase .1 million shares at $9.90 per share.
(See Notes 1, 5 and 9 of the Notes to Consolidated Financial Statements).
Expenses
The Company includes in general and administrative expense all of the personnel
and administrative costs of providing services to its clients pursuant to its
outsourcing agreements, with the exception of field operating personnel, which
are charged directly to the clients' operations. Because general and
administrative expense includes the cost of
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED
(Unaudited)
client service, the level of expense recorded by the Company from year to year
is subject to variability related to client activity level.
General and administrative expenses totaled $39.0 million, $37.1 million and
$37.9 million in 1998, 1997 and 1996, respectively.
Oil and gas expenses for 1998 totaled $8.3 million, down 6.7% from $8.9 million
in 1997. Such decrease is mainly due to 1997 including a partial year of
expenses prior to the sale of certain oil and gas properties in April 1997 (see
Note 9 of the Notes to Consolidated Financial Statements). The average unit
production cost per Mcfe in 1998 was $1.23 as compared to an average unit
production cost per Mcfe in 1997 of $1.21. Oil and gas expenses for 1997
totaled $8.9 million, up 29% from $6.9 million in 1996. Such increase is mainly
attributable to the receipt of certain oil and gas properties in September 1996
(see Note 8 of the Notes to Consolidated Financial Statements). The average
unit production cost per Mcfe in 1997 was $1.21 as compared to an average unit
production cost per Mcfe in 1996 of $.92.
Interest expense increased by 32.1% to $3.7 million in 1998 from $2.8 million in
1997. Such increase is primarily due to additional funds advanced to TEFF by
the Bank of Montreal. Interest expense increased by 75% to $2.8 million in 1997
from $1.6 million in 1996. Such increase is primarily due to 9% in interest
recorded on the $25.5 million Senior Subordinated Note payable to Torchmark
issued in conjunction with the Management Buyout in September 1996.
Equity in Earnings of Affiliates and Investees
Equity in earnings of affiliates and investees consists of oil and gas
partnership interests and other investments including TEFF's 50% interest in TEC
Resources, LLC ("TEC"). The Company recorded an equity loss of $.9 million in
TEC for the year ended December 31, 1998.
Minority Interests
Effective November 1, 1996 Torch Energy Marketing, Inc. (TEMI), a wholly owned
subsidiary, formed a limited liability company with an unaffiliated party to
conduct gas marketing activities. TEMI acts as a manager and owns a 50%
interest in this venture. As the Company effectively controls the venture, the
activities are included in the financial statements with the unaffiliated
parties interest reflected as minority interest.
During 1996, the Company formed two limited liability companies with an
unaffiliated party to provide certain management, administrative and support
services to a foreign party. The Company owned a 50% interest in both limited
liability companies until March 1997 at which time the companies were sold.
Prior to March 1997, the activities for these ventures were included in the
financial statements with the unaffiliated parties interest reflected as
minority interest.
Effective June 30, 1997, the Company purchased The Procurement Centre ("TPC") to
obtain the benefit of TPC's experience and expertise in providing consulting and
outsourcing services for the procurement of materials and services, inventory
management, logistics and
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED
(Unaudited)
other administrative services. The Company owns a 75% interest in TPC and the
activities are included in the financial statements with the unaffiliated
parties interest reflected as minority interest.
Net Income
The foregoing activities resulted in the following net income (amounts in
thousands):
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Income before income taxes and minority
interest.......................................... $ (148) $12,198 $19,386
Net income (loss)................................. $(1,187) $11,657 $15,379
</TABLE>
LIQUIDITY AND CAPITAL RESOURCES
Net cash used in operating activities was $3.8 million for the year ended
December 31, 1998. Net cash provided by operating activities was $6.8 million
and $7.6 million for the years ended December 31, 1997 and 1996, respectively.
In each of the years considered, operating cash flows were affected by
significant changes in assets and liabilities due to the Company incurring
costs, in the ordinary course of business, on behalf of its clients. The
Company spent $6.5 million, $5.6 million and $14.8 million on investments in
property and equipment in 1998, 1997, and 1996, respectively. In April 1997,
the Company sold its interest in certain oil and gas properties of certain
partnerships to Bellwether and a third party generating $18.4 and $3.0 million,
respectively, in cash (See Note 9 of the Notes to Consolidated Financial
Statements). In August 1996 and September 1996, the Company sold its interest
in certain oil and gas properties to a third party generating $16.3 million in
cash (See Note 9 of the Notes to Consolidated Financial Statements).
Financing Activities
The Company maintains a $13 million credit facility (the "Credit Facility") with
a bank. Interest accrues on indebtedness, at the Company's option, at the
bank's prime rate (6.6% at December 31, 1998) if less than 50% of revolver
borrowing base is outstanding ($5 million at December 31, 1998), prime plus .25%
if 50% or more, but less than 75% of revolver borrowing base is outstanding or
prime plus .50% if 75% or more of revolver borrowing base is outstanding; or the
1 year London Interbank Offered Rate ("LIBOR") (5.1% at December 31, 1998) plus
1.5% if less than 50% of revolver borrowing base is outstanding, libor plus
1.75% if 50% or more, but less than 75% of revolver borrowing base is
outstanding or libor plus 2% if 75% or more of revolver borrowing base is
outstanding. The Credit Facility contains, among other terms, provisions for
the maintenance of certain financial ratios and restrictions on additional debt.
As of December 31, 1998, the Company was not in compliance with one of its
financial ratios. The Company has received a waiver on the consolidated interest
coverage ratio as of December 31, 1998. Certain oil and gas properties, stock
and fixed assets secure the Credit Facility which matures on September 30, 1999.
At December 31, 1998 and 1997, there was no outstanding balance under the line
of credit.
On July 16, 1997, TEFF entered into a $90 million credit facility (the "TEFF
Facility") with BMO. Ordinary interest accrues on indebtedness, at TEFF's
option, at the bank's prime rate plus 0.5% (8.25% at December 31, 1998) or LIBOR
plus 2.0% (7.10% at December 31, 1998)
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED
(Unaudited)
if the loans outstanding are less than or equal to the portfolio base ($20.1
million at December 31, 1998); and at the bank's prime rate plus 5.5% (13.25% at
December 31, 1998) or LIBOR plus 7.0% (12.10% at December 31, 1998) of the
portion of loans outstanding in excess of the portfolio base. If the outstanding
balance under the TEFF Facility exceeds $75 million, then the ordinary interest
rate shall be reduced by .5%. Principal and interest on the loan will be repaid
from cash flow from TEFF's underlying investments. The amount of such repayments
will vary from between 70% to 100% of the cash flow, depending on the ratio of
portfolio base to the outstanding principal balance of the loan. The TEFF
Facility contains, among other terms, provisions for the maintenance of certain
financial ratios and restrictions on additional debt. All security in the
investments currently owned by TEFF or hereafter acquired and proceeds thereof,
secure the TEFF Facility, which matures on December 31, 2003. At December 31,
1998, the outstanding balance under the TEFF Facility was $36.3 million at a
weighted average interest rate of 9.7%. At December 31, 1997, the outstanding
balance under the TEFF Facility was $10.6 million. In addition to the principle
and interest payments mentioned above, the bank will receive 50% of the
remaining cash flow after deduction of such principle and interest payments
(NCFI). Until such time as the NCFI payments are equal to TEFF's partners'
contributions, these amounts will be considered additional principle repayments.
After that time, the payments will be considered additional expense. The TEFF
Facility provides that NCFI be paid through December 31, 2011 at which time the
bank's right to receive NCFI shall terminate. No such interest was incurred for
the years ended December 31, 1998 and 1997.
On November 14, 1997, TPC entered into a $200,000 credit facility (the "TPC
Facility") with a bank. Interest accrued on indebtedness at the bank's prime
rate. All accounts receivable currently owned by TPC or thereafter acquired and
proceeds thereof, but not contracts themselves, secured the TPC Facility which
matured on November 2, 1998. At December 31, 1997, the outstanding balance
under the TPC Facility was $60,000.
On September 30, 1996, the Company recorded a $25.5 million Senior Subordinated
Note payable to Torchmark as part of the purchase price for the Management
Buyout. This note accrues interest at 9% per annum, payable semiannually, and
the principal is due and payable on September 30, 2004.
The Company has an investment in Southern Missouri Gas Company, L.P. ("SMGC")
which has a $29 million bank loan due on June 30, 1999. This loan is guaranteed
by the general partner of SMGC. TEMI has guaranteed the general partner that it
will share proportionally (50%) if any payments are required by the general
partner for repayment of SMGC's loan. SMGC is planning to either renegotiate
the terms of the loan or seek other financing options.
Crude Oil and Natural Gas Price Swaps
The Company uses futures, swap and option contracts to hedge anticipated sales
and purchases for pricing commitments of natural gas and crude oil, to reduce
the Company's exposure to changes in the market price of natural gas and crude
oil, and to fix the price for natural gas and crude oil independently of the
physical purchase or sale. Futures involves buying the underlying commodity at
fixed prices. Over-the-counter swap contracts require
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED
(Unaudited)
the Company to receive or make payments based on the price of the underlying
commodity and are used to manage price and location risk. The Company uses
futures, swaps and options to manage margins on underlying fixed-price purchase
or sales commitments for physical quantities of the underlying commodity. The
Company holds one natural gas option to mitigate price risk which provides the
right, but not the requirement, for the counterparty to sell natural gas to the
Company at a fixed price. The Company also holds one natural gas option to limit
its exposure to losses under the minimum price obligation to the "Trust" (see
Note 11) risk which provides the right, but not the requirement, for the Company
to sell natural gas to the counterparty at a fixed price. At December 31, 1998,
the Company had natural gas basis swap agreements with broker-dealers to
exchange monthly payments on notional quantities amounting to 98 million MMBTU
over the ensuing 3 years. At December 31, 1998, the Company had natural gas
price swap agreements with broker-dealers to exchange monthly payments on
notional quantities amounting to 32 million MMBTU over the ensuing 3 years.
Under the price swap agreements, the Company will realize an average price of
$2.16 per MMBTU. Under a 6 Mbbl oil price swap agreement, the Company will
realize a floor price of $20.17 per barrel.
Market Risk
Comodity Price Risk - The Company's major market risk exposure is in the pricing
applicable to its oil and gas production. Realized pricing is primarily driven
by the prevailing worldwide price for crude oil and spot prices applicable to
its natural gas production. Historically, prices received for oil and gas
production have been volatile and unpredictable. Pricing volatility is expected
to continue. The Company periodically seeks to reduce its exposure to price
volatility by hedging its productions through swaps, options and other commodity
derivative instruments. The Company uses hedge accounting for these instruments,
and settlements of gains or losses on these contracts are reported as a
component of oil and gas revenues and operating cash flows in the period
realized. Gains or losses on natural gas price swaps are expected to be offset
by sales at the spot market price or to preserve the margin on existing physical
contracts. A 10 percent improvement in year-end spot market prices would
increase the fair value of derivative contracts in effect at December 31, 1998
by $1.9 million, while a 10 percent drop in spot prices would decrease the fair
value of these instruments by $1.9 million. These agreements expose the Company
to counterparty credit risk to the extent that the counterparty is unable to
meet its settlement commitments to the Company.
Interest Rate Risk - The Company's exposure to changes in interest rates
primarily results from short term changes in the LIBOR rates. A 10% increase in
the floating LIBOR rates would have the effect of increasing interest costs to
the Company by $.35 million per year.
Outlook
The Company has adopted a $10.9 million capital budget for the year ending
December 31, 1999 primarily for the recompletion of certain oil and gas
properties, information technology and additional investments in current
affiliates. The Company believes its working capital and cash flows from
operating activities will be sufficient to meet these capital commitments.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This statement establishes standards of
accounting for and disclosures of derivative instruments and hedging activities.
This statement is effective for fiscal years beginning after June 15, 1999. The
Company has not yet determined the impact of this statement on the Company's
financial condition or results of operations.
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED
(Unaudited)
Year 2000 Issues
The Year 2000 problem ("Y2K") refers to the inability of computer and other
information technology systems to properly process date and time information.
The problem was caused, in part, by the outdated programming practice of using
two digits rather than four to represent the year in a date. The consequence of
the Y2K problem is that information technology and embedded processing systems
are at risk of malfunction, particularly during the transition between 1999 to
2000.
The effects of the Y2K are exacerbated by the interdependence of computer and
telecommunication systems throughout the world. This interdependence also
exists among the Company and its vendors, customers and business partners, as
well as with government agencies.
The risks of Y2K fall into three general areas: 1) Corporate Systems, 2) Field
Systems and 3) Third Party Exposure. The Company intends to address each of
these areas through a readiness process that follows the steps below:
a) Planning and Awareness
b) Inventory and Assessment
c) Identify Potential Problems and their Business Impact
d) Identify/Approve Solutions
e) Test and Implement Solutions
f) Contingency Planning
The Company has formed a Y2K Team comprised of representatives from senior
management, exploration, exploitation, accounting, legal and internal audit.
The continuing progress of this Y2K Team is reported regularly to the Company's
Board of Directors. The Company is responsible for a substantial portion of its
clients' information technology and field operations due to the existing
contracts for outsourcing and management services. As a result, the Company and
its clients have jointly developed a plan to address the Company's Y2K issues.
The estimated total costs for Y2K readiness have been nominal and it is
anticipated that such costs will continue to be nominal through completion. The
Company expensed $132,000 related to Y2K for the year ended December 31, 1998
and anticipates an additional $128,000 to be expensed during 1999. In addition,
there have been no material capital expenditures for Y2K and there is not
anticipated to be material capital expenditures as most major critical field
operations do not have date sensitive equipment. Remediation and testing is
scheduled to be completed by June 30, 1999.
CORPORATE SYSTEMS
1. Planning and Awareness. All employees have attended Y2K informational
programs including a general discussion of what Y2K is and how it could
affect the business. Employees of all levels of the organization have been
asked to participate in the identification of potential Y2K risks including
routine Excel and Word documents.
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED
(Unaudited)
Awareness of the issue is extremely high. Overall planning of the Y2K
function has been delegated to the Y2K Team mentioned above.
2. Inventory and Assessment. The Company has completed an inventory of the
traditional computing platforms including client/server systems, LAN systems
and PC systems, as well as an inventory of all systems software and
operating systems for each computing system. In addition, third party
service interfaces, banking/treasury interfaces and telecommunications have
been cataloged.
Assessment of component compliance (compliant, not-compliant, expected date
of compliance, etc.) has been completed and included research of product
information on the Internet, contacting peer group companies and accessing
information that peer group companies have already found.
3. Identification. The failure to identify and correct a material Y2K problem
in the Corporate Systems could result in inaccurate or untimely financial
information for management decision-making or financial reporting purposes.
The severity of such problems may impact the duration during which quality
information is available to management. At this time, management believes
that any Y2K disruptions associated with its financial and administration
systems will not have a material effect on the Company.
4. Identify/Approve Solutions. Based upon the assessments of components'
compliance, solutions are determined. These solutions include: 1) fix or
replace the non-compliant component, 2) buy patches or replacement items, 3)
develop workarounds, 4) identify alternate automated processes, 5) design
manual procedures and 6) develop business continuity plans for specific
items or systems.
5. Test and Implement Solutions. Since April 1998 Torch has been working on an
upgrade to its accounting software and is expected to achieve full Y2K
compliance in the first half of 1999. In addition, all network and desktop
applications used by the Company have been inventoried and are generally Y2K
compliant. No software or hardware can be purchased and placed into service
after June 30, 1999 without express Y2K compliance assurance.
6. Contingency Planning. Notwithstanding the foregoing, should there be
significant unanticipated disruptions in the Company's financial and
administrative systems, a number of accounting processes that are currently
automated will need to be performed manually. The Company is currently
considering its options with respect to contingency arrangements for
temporary staffing to accommodate such situations.
FIELD SYSTEMS
1. Planning and Awareness. The Company's Y2K program has involved all levels
of management of field and facility assets from production foremen and
higher. Employees at all levels of the organization have been asked to
participate in the identification of potential Y2K risk, which might
otherwise go unnoticed by higher level employees and directors, and as a
result, awareness of the issue is high.
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED
(Unaudited)
2. Inventory and Assessment. This step entailed locating all embedded chip
technology used in the field operations including safety systems,
measurement devices, overflow valves, SCADA systems and other field
processes that are date-or-time-sensitive. During the assessment stage a
list of assets to be tested was assembled. Consideration was given to 1)
issues of health and safety, 2) environmental concerns, 3) economic factors
and 4) other business risks as appropriate. Vendors and manufacturers have
been contacted as well as product research through the Internet and the use
of peer group company shared information. To date, the majority of embedded
components researched have been deemed either date-insensitive or Y2K
compliant. However, the complexity of embedded systems is such that a small
minority of non-compliant components, even a single non-compliant component,
can corrupt an entire system. Now that the component level evaluation is
substantially complete, a broader evaluation at the system level has
commenced. The Company anticipates that the system level evaluation will be
completed by the end of the second quarter 1999.
3. Identification. The failure to identify and correct a material Y2K problem
could result in outcomes ranging from errors in data reporting to
curtailments or shutdowns in production. The Company is actively engaged in
a program to prioritize the remediation of embedded components and systems
which are either known to be Y2K non-compliant or which have higher risk of
Y2K failures, and to further prioritize remediation targets by the
anticipated financial impact of any such failures on the Company. To assist
in this effort, the Company has retained consultants who are knowledgeable
and experienced in the assessment of Y2K issues impacting field operations.
The Company intends to give extremely high priority to the remediation of
any situation that impacts employee health and safety or environmental
security. The cost of the assessment is not expected to be material to the
Company's financial results. At this time management is unable to express
any degree of confidence that there will not be material production
disruptions associated with Y2K non-compliance. Depending on the magnitude
of any such disruptions and the time required to correct them, such failures
could materially and adversely impact the Company's results of operations,
liquidity and financial condition.
4. Identify/Approve Solutions. Based upon the assessment of field systems,
regarding compliance or non-compliance, solutions are determined. These
potential solutions include 1) fix or replace non-compliant items, 2) buy
patches or replacement items, 3) develop workarounds, 4) identify
alternative automated processes, 5) design manual procedures and 6) develop
business continuity plans for specific items or systems.
5. Test and Implement Solutions. Once identified, assessed and prioritized,
the Company intends to test, upgrade and certify those embedded components
and systems in field process control units deemed to pose the greatest risk
of significant non-compliance. It is important to note that in some
circumstances, the procedures used to test embedded components for Y2K
compliance themselves pose a risk of damaging the component or corrupting
the system. Accordingly, there may be situations in which a decision not to
test may be deemed the most prudent.
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED
(Unaudited)
The Company does not expect the cost of testing and upgrading its embedded
chips to be material due to the number of components and the low cost of
such components. If this assumption is incorrect, the Company may incur
material costs in connection with testing and remedying Y2K problems. In
addition, if the Company is not successful and ultimately experiences Y2K
related failures, the costs attributable to lost production, damages to
facilities and environmental damages may be material. The effort to address
the Y2K situation is dynamic and may likely not be fully completed by
December 31, 1999.
6. Contingency Planning. Should material production disruptions occur as a
result of Y2K failures in the field operations, the Company's operating cash
flow will be impacted. This contingency is being factored into deliberations
on capital budgeting, liquidity and capital adequacy. It is management's
intention to maintain adequate financial flexibility to sustain the Company
during any such period of cash flow disruption.
THIRD PARTY EXPOSURES
1. Planning and Awareness. The Company has been involved in informational
programs with its employees who have significant interaction with outside
vendors, customers and business partners of the Company. All levels of
employees in the organization have been asked to participate in the
identification of potential third party Y2K risk, which might otherwise go
unnoticed by higher level employees and directors of the Company, and as a
result, awareness of the issue is considered high.
2. Inventory and Assessment. Surveys of general Y2K readiness have been sent
to all vendors, customers and business partners of the Company. An
assessment is made regarding the priority of risk associated with each third
party, and how the third party's level of compliance directly affects
day-to-day business. The Company's most critical customers are outside
operators of wells, gas plants, refineries, natural gas marketers and
pipelines.
3. Identification. Refineries are extremely complex operations containing
hundreds or thousands of computerized processes. The failure on the part of
a refinery customer to identify and correct a material Y2K problem could
result in material disruptions in the sale of the production to that
refinery. In many cases, affected production may not be easily shifted to
other markets, and the result can range from reduced realizations on crude
oil produced, curtailed production or even shut-in production. Failures of
natural gas marketers and the pipelines that connect production to markets
may have similar effects. Although the Company has made inquiries to key
third parties on the subject of Y2K readiness and will continue to do so, it
has no ability to require responses to such inquiries or to independently
verify their accuracy. Accordingly, management is unable to express any
degree of confidence that there will not be material production disruptions
associated with third party Y2K non-compliance. Depending on the magnitude
of any such disruptions and the time required to correct them, such failures
could materially and adversely impact the Company's results of operations,
liquidity and financial condition.
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED
(Unaudited)
Other significant concerns include the integrity of global telecommunication
systems, the readiness of commercial banks to execute electronic fund
transfers and of the ability of the financial community to maintain an
orderly market.
4. Identify/Approve Solutions. By prioritizing the various third party risks
mentioned above, a list of most critical third party vendor, customer and
business partners has been determined. By cross-referencing the results of
the Y2K readiness survey with the Company's priority list of third parties
solutions can be determined. These may involve field and/or office visits
and more detailed meetings to access the third party's Y2K compliance.
5. Test and Implement Solutions. Where the Company perceives significant risk
of Y2K non-compliance that may have a material impact on the Company, and
where the relationship between the Company and a vendor, customer or
business partner permits, joint testing may be undertaken during 1999. Joint
testing would occur following upgrades and other remediation to hardware,
software and communications links, as applicable, with the intent of
determining that the remediated system being tested will perform as expected
after December 31, 1999.
6. Contingency Planning. Should material production disruptions occur as a
result of Y2K failures of third parties, the Company's operating cash flow
will be impacted. This contingency is being factored into deliberations on
capital budgeting, liquidity and capital adequacy. It is management's
intention to maintain adequate financial flexibility to sustain the Company
during any such period of cash flow disruption.
<PAGE>
EXHIBIT 23.1
CONSENT OF T.J. SMITH & COMPANY, INC.
We hereby consent to the use of our report dated February 16, 1999
regarding Torch Energy Royalty Trust and to reference to our firm included in
this Form 10-K.
T.J. SMITH & COMPANY, INC.
By: /s/ Timothy Smith, P.E.
----------------------------------
Houston, Texas
March 25, 1999
<PAGE>
EXHIBIT 23.2
CONSENT OF H.J. GRUY AND ASSOCIATES, INC.
We hereby consent to the use of the name H.J. Gruy and Associates, Inc.
and of references to H.J. Gruy and Associates, Inc. and the inclusion of and
references to our report dated February 19, 1999, prepared for Torch Energy
Royalty Trust in the Torch Energy Royalty Trust Annual Report on Form 10-K for
the year ended December 31, 1998.
H.J. GRUY AND ASSOCIATES, INC.
By: /s/ H.J. Gruy and Associates, Inc.
----------------------------------
Houston, Texas
March 26, 1999
<PAGE>
EXHIBIT 23.3
CONSENT OF RYDER SCOTT COMPANY
We hereby consent to the use of our report dated February 17, 1999
regarding Torch Energy Royalty Trust interest and to reference to our firm
included in this Form 10-K.
RYDER SCOTT COMPANY
By: /s/ Ryder Scott Company
----------------------------------
Houston, Texas
March 29, 1999
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 4
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 0
<PP&E> 57,011
<DEPRECIATION> 0
<TOTAL-ASSETS> 57,015
<CURRENT-LIABILITIES> 155
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 56,860
<TOTAL-LIABILITY-AND-EQUITY> 57,015
<SALES> 0
<TOTAL-REVENUES> 13,636
<CGS> 0
<TOTAL-COSTS> 700
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 12,936
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 12,936
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
<PAGE>
EXHIBIT 99.1
In view of the possible materiality of the financial condition of Torch Energy
Advisors Incorporated ("Torch") financial condition to the Minimum Price
commitment, which relates to the Purchase Contract between the Trust and Torch,
Torch's financial statements are provided as an exhibit to the Trust's annual
report on Form 10-K. Upon the termination of the Minimum Price commitment, such
financial statements will not be included in this annual filing.
