<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, 1999
-----------------
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 7, 2000 was
approximately $ 34,937,500.
<PAGE>
TORCH ENERGY ROYALTY TRUST
Annual Report on Form 10-K
For the fiscal year ended December 31, 1999
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
Number
----------
PART I
<S> <C> <C> <C>
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........................................ 16
Item 8. Financial Statements and Supplementary Data........ 17
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................ 31
PART III
Item 10. Directors and Executive Officers of the Registrant. 31
Item 11. Executive Compensation............................. 31
Item 12. Security Ownership of Certain Beneficial Owners
and Management..................................... 31
Item 13. Certain Relationships and Related Transactions..... 32
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K................................ 34
--- Signatures
</TABLE>
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, and Section 21E of the
Securities Exchange Act of 1934. All statements other than statements of
historical facts included in this document, including without limitation,
statements under "Discussion and Analysis of Financial Condition and Results of
Operations" regarding the financial position 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 1999, 1998, and 1997, the Section 29 Credit available for
production from qualifying coal seam properties was approximately $1.07, $1.06
and $1.05, 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, 2000, 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 $1.84 per
MMBtu in 1997 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, 2002,
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 ($0.281 per MMBtu for 1999, and $0.274 per MMBtu
for 1998 and 1997, 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,
1999, 1998 and 1997, gathering, treating and transportation fees charged to the
Trust by TEMI, attributable to production during the twelve months ended
September 30, 1999, 1998 and 1997 in the Robinson's Bend, Austin Chalk and
Cotton Valley Fields, totaled $1,308,000, $1,650,000 and $1,965,000,
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, 1999 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 interest, other than
wells drilled to replace damaged or destroyed wells ("Infill Wells"). Infill
Well Net
5
<PAGE>
TORCH ENERGY ROYALTY TRUST
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 1999 or 1997.
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.
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 (31.6% 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
$ 1.07, $1.06 and $1.05 per MMBtu in 1999, 1998 and 1997, 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 1999, 1998 and
1997 attributable to distributions from the Underlying Properties in the
Robinson's Bend Field averaged 652 MMcf, 719 MMcf and 787 MMcf per quarter,
respectively, and was therefore 32%, 25% and 18%, 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 1999, the Trust's current
reserve reports indicate that the Trust will not receive any payments
attributable to the Robinson's Bend field.
8
<PAGE>
TORCH ENERGY ROYALTY TRUST
Cotton Valley Fields. The Underlying Properties include an average 54.5%
working interest (41.5% net revenue interest) in 41 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 qualifies 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 17.4%
working interest (13.6% 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 qualifies 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, 1999, 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................ 41 20.9 --- ---
Austin Chalk Fields................. 39 8.7 51 7.6
----- ------ --- -----
Total............................. 480 199.40 51 7.6
===== ====== === =====
</TABLE>
The following table shows the gross and net acreage for the Underlying
Properties as of December 31, 1999. 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.
<TABLE>
<CAPTION>
Acreage
------------------
Gross Net
------- ------
<S> <C> <C>
Chalkley Field...................... 2,152 425
Robinson's Bend Field............... 33,404 14,288
Cotton Valley Fields................ 4,411 2,606
Austin Chalk Fields................. 35,439 6,507
------- ------
Total............................. 75,406 23,826
======= ======
</TABLE>
DRILLING ACTIVITY
The following table sets forth the results of drilling activity for the
Underlying Properties during the three years ended December 31, 1999. 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.
All of the wells shown below represent Infill Wells drilled on the Underlying
Properties. The Net Profits Interest entitle the Trust to 20% of "Infill Net
Proceeds." Infill Net Proceeds is defined as gross proceeds from the sale of
production attributable to infill wells less all produciton, drilling and
completion costs of such wells.
9
<PAGE>
TORCH ENERGY ROYALTY TRUST
Infill Net Proceeds are calculated by aggregating the proceeds and costs from
Infill Wells on a state by state basis. Because costs of Infill Wells exceed
proceeds of production, the Trust has not received any Infill Net Proceeds.
<TABLE>
<CAPTION>
Development Wells
-------------------------------------------------------------------------
Gross Net
----------------------------------- ---------------------------------
Dry Dry
Productive Holes Total Productive Holes Total
------------- --------- ----------- ------------ ------- ---------
<S> <C> <C> <C> <C> <C> <C>
1997 6 0 6 2.8 0 2.8
1998 0 0 0 0 0 0
1999 1 0 1 .9 0 .9
</TABLE>
There was no other drilling activity on the Underlying Properties during the
three years ended December 31, 1999.
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 cash
distributions received by Unitholders during the three years ended December 31,
1999 (derived from production during the twelve months ended September 30, 1999,
1998 and 1997, respectively).
<TABLE>
<CAPTION>
Chalkley, Cotton Valley
and Austin Chalk Fields
---------------------------------------------
1999 1998 1997
-------------------- ---------- -----------
<S> <C> <C> <C>
Production:
Gas (MMcf)................................................... 4,171 5,135 6,186
Oil (Mbbl)................................................... 54 74 107
Weighted average lifting cost per Mcfe......................... $ .39 $ .34 $ 0.26
Weighted average taxes on production per Mcfe.................. $ .08 $ 0.09 $ 0.09
Weighted average sales price (b)
Gas ($/Mcf).................................................. $ 1.96 $ 2.12 $ 1.92
Oil ($/Bbl).................................................. $11.93 $12.71 $17.06
Robinson's Bend Field
---------------------------------------------
1999 1998 1997
------------------ -------------- ---------
Production:
Gas (MMcf)................................................... 2,607 2,879 3,149
Oil (Mbbl)................................................... --- --- ---
Weighted average lifting cost per Mcfe......................... $ ---(a) $ ---(a) $ ---(a)
Weighted average taxes on production per Mcfe.................. $ .06 $ 0.07 $ 0.09
Weighted average sales price (b)
Gas ($/Mcf).................................................. $ 1.63 $ 1.80 $ 1.61
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 $2.47, $2.45 and $2.27, respectively, during 1999, 1998 and 1997,
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 1999.
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 1, 2000, there were 8,600,000 Units outstanding and
approximately 645 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, 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
Quarter ended March 31, 1999....................... $5.063 $4.375 $.270
Quarter ended June 30, 1999........................ $6.250 $4.750 $.237
Quarter ended September 30, 1999................... $5.938 $5.125 $.268
Quarter ended December 31, 1999.................... $5.375 $3.750 $.332
</TABLE>
On March 17, 2000, the high and low sales price per unit on the NYSE was $4.188
and $4.000, respectively.
ITEM 6. SELECTED FINANCIAL DATA (In thousands, except per Unit amounts)
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------
1999 1998 1997 1996 1995
------- ------- -------- -------- ---------
<S> <C> <C> <C> <C> <C>
Net profits income........ $10,174 $13,615 $ 15,183 $ 17,381 $ 22,427
Distributable income...... $ 9,511 $12,936 $ 14,525 $ 16,722 $ 21,787
Distributions declared.... $ 9,520 $12,917 $ 14,534 $ 16,727 $ 21,758
Distributable income
per Unit.................. $ 1.11 $ 1.50 $ 1.69 $ 1.94 $ 2.53
Distributions per Unit.... $ 1.11 $ 1.50 $ 1.69 $ 1.95 $ 2.53
Total assets (at end of
period).................. $49,143 $57,015 $100,845 $121,526 $137,179
</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 ISSUE
The Year 2000 problem ("Y2k") referred 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 was that information technology and embedded processing systems
were at risk of malfunction, particularly during the transition between 1999 to
2000. Due to the inter-dependence of computer and telecommunications systems
throughout the world, the Trust, the Trust's
12
<PAGE>
TORCH ENERGY ROYALTY TRUST
administrative services provider, Torch, their vendors, customers, business
partners and government agencies were exposed to the possible adverse effects of
the Y2k problem. Torch categorized Y2k risks into three general areas: 1)
Corporate Systems, 2) Field Systems and 3) Third Party Exposure.
The Trust and Torch have not been impacted by the Y2k problem. Torch's
corporate and field computer systems have operated and expect to continue
operating with no Y2k-related disruptions. Additionally, the Trust and Torch
have not been impacted by third parties' Y2k issues.
13
<PAGE>
TORCH ENERGY ROYALTY TRUST
RESULTS OF OPERATIONS
Discussion of Years Ended December 31, 1999, 1998 and 1997
Because a modified cash basis of accounting is utilized by the Trust, Net
Proceeds to the Trust for the years ended December 31, 1999, 1998 and 1997 is
derived from actual oil and gas production from October 1, 1998 through
September 30, 1999, October 1, 1997 through September 30, 1998 and October 1,
1996 through September 30, 1997, 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, 1999.
<TABLE>
<CAPTION>
Bbls of Oil
---------------------------------------
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
Chalkley Field................ 20,881 26,736 40,260
Robinson's Bend Field......... --- --- ---
Cotton Valley Fields.......... 4,841 6,481 6,157
Austin Chalk Fields........... 27,797 41,174 60,236
--------- --------- ---------
Total......................... 53,519 74,391 106,653
========= ========= =========
Mcf of Gas
---------------------------------------
1999 1998 1997
--------- --------- ---------
Chalkley Field................ 2,683,448 3,219,550 4,195,263
Robinson's Bend Field......... 2,606,750 2,879,422 3,148,834
Cotton Valley Fields.......... 1,234,693 1,469,645 1,385,461
Austin Chalk Fields........... 253,251 445,443 605,455
--------- --------- ---------
Total......................... 6,778,142 8,014,060 9,335,013
========= ========= =========
</TABLE>
For the year ended December 31, 1999, net profits income was $10,174,000, as
compared to $13,615,000 and $15,183,000 for the same periods in 1998 and 1997,
respectively. The decline in net profits income from 1998 resulted from normal
production declines combined with lower average oil and gas prices paid to the
Trust during 1999. The decline in net profits income from 1997 to 1998 was due
to normal production declines offset by higher average gas prices to the
Trust in 1998.
Gas production attributable to the distributions received by Unitholders during
the year ended December 31, 1999 was 6,778,142 Mcf, as compared to gas
production of 8,014,060 Mcf and 9,335,013 Mcf for the same periods in 1998 and
1997, respectively. Oil production attributable to the Underlying Properties for
the year ended December 31, 1999 was 53,519 Bbls as compared to 74,391 Bbls and
106,653 Bbls for the same periods in 1997 and 1996, respectively.
As of December 31, 1999, seven infill wells were drilled and commenced
production. Infill well oil production totaled 2,010, 1,700 and 2,075 Bbls
during the years ended December 31, 1999, 1998 and 1997, respectively. Infill
well gas production totaled 412,345, 344,458 and 274,577 Mcf during the three
years ended December 31, 1999, 1998 and 1997, respectively. Distributions
received by Unitholders have not been impacted by these wells as gross proceeds
have not exceeded costs and expenses for such infill wells.
The average price used to calculate Net Proceeds for gas during the year ended
December 31, 1999 was $1.95 per MMBtu as compared to $2.10 per MMBtu and $1.91
per MMBtu for the years ended December 31, 1998 and 1997, respectively. The
average price used to calculate Net Proceeds for oil during the
14
<PAGE>
TORCH ENERGY ROYALTY TRUST
years ended December 31, 1999, 1998 and 1997 was $11.93, $12.71 and $17.06 per
Bbl, respectively. When TEMI pays a purchase price for gas based on the Minimum
Price of $1.70 per MMBtu, TEMI receives Price Credits which it is entitled to
deduct in determining the purchase price when the Index Price for gas exceeds
the Minimum Price. As of December 31, 1999, TEMI had no outstanding Price
Credits. Net Price Credits in the amount of $97,000 and $317,000 were deducted
in calculating the purchase price related to distributions during 1999 and 1997,
respectively. TEMI accrued Price Credits in the amount of $97,000, net to Trust,
in connection with distributions received by Unitholders during the year ended
December 31, 1998.
Additionally, if the Index Price for gas exceeds $2.10 per MMBtu, TEMI is
entitled to deduct 50% of such excess in calculating the purchase price.
Distributions received by Unitholders during the years ended December 31, 1999,
1998 and 1997 were reduced by $280,000, $650,000 and $406,000, respectively, as
a result of such Sharing Price arrangement.
Lease operating expenses and capital expenditures deducted in calculating
distributions during the years ended December 31, 1999, 1998 and 1997 totaled
$1,849,000, $1,947,000 and $1,898,000, 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, 1999, 1998 and 1997 totaled $498,000, $710,000 and $874,000,
respectively, for all four fields.
General and administrative expenses during the years ended December 31, 1999,
1998 and 1997 amounted to $674,000, $700,000 and $678,000, 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, 1999 and
1997.
For the year ended December 31, 1999, distributable income was $9,511,000, or
$1.11 per Unit, as compared to $12,936,000, or $1.50 per Unit, and $14,525,000,
or $1.69 per Unit, for the same periods in 1998 and 1997, respectively. Total
cash distributions of $9,520,000 , or $1.11 per Unit, were made during the year
ended December 31, 1999 as compared to $12,917,000, or $1.50 per Unit, and
$14,534,000, or $1.69 per Unit, for the same periods in 1998 and 1997,
respectively. The Section 29 Credits relating to qualifying production from
coal seam and tight sands properties, during the twelve months ended September
30, 1999, 1998 and 1997, totaled approximately $0.36, $0.38 and $0.41 per Unit,
respectively.
15
<PAGE>
TORCH ENERGY ROYALTY TRUST
Net profits received by the Trust during the years ended December 31, 1999,
1998, and 1997, derived from production sold during the twelve months ended
September 30, 1999, 1998 and 1997, respectively, was computed as shown in the
following table (in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------------------------------------------
1999 1998 1997
------------------------------- --------------------------------- ---------------------------
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........... $8,817 $4,239 $11,812 $5,176 $13,694 $5,060
Direct operating expenses:
Lease operating expenses
and property tax............ 1,727 ---(a) 1,876 ---(a) 1,801 ---(a)
Severance tax................ 341 157 498 212 593 281
------ ------ ------- ------ ------- ------
2,068 157 2,374 212 2,394 281
------ ------ ------- ------ ------- ------
Net proceeds before
capital expenditures........ 6,749 4,082 9,438 4,964 11,300 4,779
Capital expenditures........... 122 --- 71 --- 97 ---
------ ------ ------- ------ ------- ------
Net proceeds................... 6,627 4,082 9,367 4,964 11,203 4,779
Net profits percentage......... 95% 95% 95% 95% 95% 95%
------ ------ ------- ------ ------- ------
Net profits income............. $6,296 $3,878 $10,174 $ 8,899 $4,716 $13,615 $10,643 $4,540 $15,183
====== ====== ======= ======= ====== ======= ======= ====== =======
</TABLE>
- ------------
(a) Lease operating expenses are not deducted in calculating Net Proceeds until
January 1, 2003. Lease operating expenses and property taxes were $ 6,438,
$7,041 and $7,163 during 1999, 1998 and 1997, 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, 2001.
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, 2002, 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.
16
<PAGE>
TORCH ENERGY ROYALTY TRUST
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
-----
<S> <C>
Independent Auditors' Reports................................................................ 18
Statements of Assets, Liabilities and Trust Corpus at December 31, 1999 and 1998............. 20
Statements of Distributable Income for the Years Ended December 31, 1999, 1998 and 1997...... 21
Statements of Changes in Trust Corpus for the Years Ended December 31, 1999, 1998 and 1997... 22
Notes to Financial Statements................................................................ 23
</TABLE>
17
<PAGE>
INDEPENDENT AUDITORS' REPORT
Wilmington Trust Company
as Trustee of Torch Energy Royalty Trust
and to the Unitholders:
We have audited the accompanying statement of assets, liabilities and trust
corpus of the Torch Energy Royalty Trust (the "Trust") as of December 31, 1999,
and the related statement of distributable income and changes in trust corpus
for the year 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 audit.
We conducted our audit in accordance with generally accepted auditing standards
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audit provides 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 the United States.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of the Trust as of December 31,
1999, and the results of its operations and its cash flows for the year then
ended, on the basis of accounting described in Note 2.
/s/ Ernst & Young LLP
- ----------------------
Houston, Texas
March 17, 2000
18
<PAGE>
INDEPENDENT AUDITORS' REPORT
Wilmington Trust Company
as Trustee of Torch Energy Royalty Trust
and to the Unitholders:
We have audited the accompanying statement of assets, liabilities and trust
corpus of the Torch Energy Royalty Trust (the "Trust") as of December 31, 1998
and the related statements of distributable income and changes in trust corpus
for the years ended December 31, 1998 and 1997. These financial statements are
the responsibility of the Trustee. Our responsibility is to express an opinion
on the financial statements based on our audits.
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 audits provide 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 financial position of the Trust as of December 31, 1998, and the
results of its operations and its cash flows for the years ended December 31,
1998 and 1997 on the basis of accounting described in Note 2.
/s/ KPMG LLP
- ------------
Houston, Texas
March 26, 1999
19
<PAGE>
TORCH ENERGY ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
(In thousands)
ASSETS
<TABLE>
<CAPTION>
December 31, December 31,
1999 1998
------------ ------------
<S> <C> <C>
Cash................................................................. $ 2 $ 4
Net profits interests in oil and gas properties (net of accumulated
amortization of $131,459 and $123,589 at December 31, 1999
and 1998, respectively)............................................. 49,141 57,011
------- -------
$49,143 $57,015
======= =======
LIABILITIES AND TRUST CORPUS
Trust expense payable................................................ $ 161 $ 155
Trust corpus......................................................... 48,982 56,860
------- -------
$49,143 $57,015
======= =======
</TABLE>
The accompanying notes to financial statements
are an integral part of these statements.
20
<PAGE>
TORCH ENERGY ROYALTY TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(In thousands, except per Unit amounts)
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------
1999 1998 1997
------- -------- -------
<S> <C> <C> <C>
Net profits income................................. $10,174 $13,615 $15,183
Interest income.................................... 11 21 20
------- -------- -------
10,185 13,636 15,203
General and administrative expenses................ 674 700 678
------- -------- -------
Distributable income............................... $ 9,511 $12,936 $14,525
======= ======== =======
Distributable income per Unit (8,600 Units)........ $ 1.11 $ 1.50 $ 1.69
======= ======== =======
Distributions per Unit............................. $ 1.11 $ 1.50 $ 1.69
======= ======== =======
</TABLE>
The accompanying notes to financial statements
are an integral part of these statements.
21
<PAGE>
TORCH ENERGY ROYALTY TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(In thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------
1999 1998 1997
------- -------- --------
<S> <C> <C> <C>
Trust corpus, beginning of year...................... $56,860 $100,668 $121,362
Amortization of Net Profits Interests................ (7,869) (43,827) (20,685)
Distributable income................................. 9,511 12,936 14,525
Distributions to Unitholders......................... (9,520) (12,917) (14,534)
------- -------- --------
Trust Corpus, end of year............................ $48,982 $ 56,860 $100,668
======= ======== ========
</TABLE>
The accompanying notes to financial statements
are an integral part of these statements.
22
<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
23
<PAGE>
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,
1999, 1998 and 1997 are derived from oil and gas production sold during the
twelve-month periods ended September 30, 1999, 1998 and 1997, 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, 1999, 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.
24
<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
25
<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, 2000, 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
$1.84 per MMBtu in 1997 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, 1999, TEMI had no outstanding Price Credits. Net Price Credits in
the amount of $97,000 and $317,000 were deducted in calculating the purchase
price related to distributions during 1999 and 1997, respectively. TEMI accrued
Price Credits in the amount of $97,000, net to the Trust, in connection with
distributions received by Unitholders during the year ended December 31, 1998.
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. Distributions received by Unitholders during
the years ended December 31, 1999, 1998 and 1997 were reduced by $280,000,
$650,000 and $406,000, respectively, as a result of such Sharing Price
arrangement. Beginning January 1, 2002, 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, 1999, 1998 and 1997 were $14,365,000, $18,638,000 and
$20,719,000, 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
26
<PAGE>
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
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 ($0.281 per MMBtu for 1999 and $0.274 per MMBtu
for 1998 and 1997), 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 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, 1999, 1998 and 1997, gathering, treating and transportation fees charged to
the Trust by TEMI, attributable to production during the twelve months ended
September 30, 1999, 1998 and 1997 in the Robinson's Bend, Austin Chalk and
Cotton Valley Fields, totaled $1,309,000, $1,650,000 and $1,965,000,
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 $197,000, $196,000, and $182,000 for the years ended December 31, 1999,
1998 and 1997, 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 $377,000, $368,000 and $366,000
were paid by the Trust to Torch during the three years ended December 31, 1999,
1998 and 1997, respectively.
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,
1999, 1998 and 1997. The Trustee is also entitled to reimbursement for out-of-
pocket expenses.
27
<PAGE>
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
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 the Independent Reserve
Engineers. Future net cash flows were computed by applying end-of-period
Purchase Contract prices for oil and gas to estimated future production, less
the estimated future expenditures (based on current costs) to be incurred in
developing and producing the reserves. 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 proved and proved developed
oil and gas reserves attributable to the Trust's Net Profits Interests (all
located in the United States) for the years ended December 31, 1999, 1998 and
1997, 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, 1999 were 28.7 billion cubic feet equivalent
to ("Bcfe") as compared to 1998 year-end reserves of 33.6 Bcfe. The 1999
reserve decline is primarily due to 1999 production of 5.4 Bcfe. Year-end
reserves at December 31, 1997 were 42.0 Bcfe as compared to 1998 year-end
reserves of 33.6 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 1999 1998 1997
- --------------------------------- ----------------- ------------------- -----------------
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............................ 136 32,800 202 40,804 293 56,455
Revisions........................ 34 360 (36) (1,860) (42) (8,474)
Extensions and discoveries....... --- --- --- --- --- ---
Production....................... (28) (5,275) (30) (6,144) (49) (7,177)
----- ------ --- ------ --- ------
Proved reserves at end of year... 142 27,885 136 32,800 202 40,804
===== ====== === ====== === ======
Proved developed reserves at
beginning of year............... 124 29,190 191 38,359 270 51,027
===== ====== === ====== === ======
Proved developed reserves at end
of year......................... 141 27,414 124 29,190 191 38,359
===== ====== === ====== === ======
</TABLE>
28
<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, 1999, 1998 and 1997 are presented in the following
table:
<TABLE>
<CAPTION>
December 31,
---------------------------------
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Future cash inflows......................................... $ 85,450 $ 80,970 $121,836
Future costs and expenses................................... (25,654) (22,268) (27,536)
-------- -------- --------
Net future cash flows....................................... 59,796 58,702 94,300
Discount at 10% for timing of cash flows.................... (18,025) (16,818) (29,671)
-------- -------- --------
Present value of future net cash flows for proved reserves.. $ 41,771 $ 41,884 $ 64,629
======== ======== ========
</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, 1999, 1998 and 1997:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Balance at beginning of year............................... $ 41,884 $ 64,629 $ 96,025
Production................................................. (10,523) (11,933) (14,756)
Accretion to discount...................................... (419) 642 9,603
Extensions and discoveries................................. ---- ---- ----
Revision of prior-year estimates, change in prices
and other................................................. 10,829 (11,454) (26,243)
-------- -------- --------
Balance at end of year..................................... $ 41,771 $ 41,884 $ 64,629
======== ======== ========
</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, 1999, 1998, and 1997. 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 $1.07, $1.06 and $1.05 per MMBtu for 1999, 1998
and 1997, respectively.
<TABLE>
<CAPTION>
December 31,
-----------------------------
1999 1998 1997
------ ------- -------
<S> <C> <C> <C>
Undiscounted............................................... $7,575 $10,557 $13,974
====== ======= =======
Discounted present value at 10%............................ $6,308 $ 8,436 $10,739
====== ======= =======
</TABLE>
29
<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, 1999.................... $ 2,470 $ 2,294 $ .27
Quarter ended June 30, 1999..................... 2,213 2,043 .24
Quarter ended September 30, 1999................ 2,471 2,307 .27
Quarter ended December 31, 1999................. 3,020 2,867 .33
------- ------- -----
$10,174 $9,511 $1.11
======= ======= =====
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
======= ======= =====
</TABLE>
30
<PAGE>
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
On August 20, 1999 the firm of KPMG LLP was replaced as the Trust's principal
independent accountant and auditors to audit all the Trust's financial
statements with the firm of Ernst & Young LLP. The Trust had no disagreements
with KPMG 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 1, 2000, 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.
31
<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 $377,000, $368,000 and $366,000 were paid by the Trust to Torch during the
years ended December 31, 1999, 1998 and 1997, respectively.
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. Price Credits are
computed on a monthly basis, and as of December 31, 1999, TEMI had no
outstanding Price Credits. TEMI may be entitled to deduct 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 $97,000 and
$317,000 were deducted in calculating the purchase price related to
distributions received by Unitholders during 1999 and 1997, respectively. TEMI
accrued Price Credits in the amount of $97,000, net to the Trust, in connection
with distributions received by Unitholders during the year ended December 31,
1998.
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. Distributions received by Unitholders during
the years ended December 31, 1999, 1998 and 1997 were reduced by $280,000,
$650,000 and $406,000, respectively, as a result of such Sharing Price
arrangement. 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, 1999, 1998 and 1997 were $14,365,000, $18,638,000 and
$20,719,000, respectively.
32
<PAGE>
TORCH ENERGY ROYALTY TRUST
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 $0.26 per MMBtu
commencing October 1, 1993 adjusted for inflation ($.281 per MMBtu for 1999 and
$0.274 per MMBtu for 1998 and 1997), 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 Valley Fields. During the years
ended December 31, 1999, 1998 and 1997, gas gathering, treating and
transportation fees charged to the Trust by TEMI, attributable to production
during the 12 months ended September 30, 1999, 1998 and 1997 in the Robinson's
Bend, Austin Chalk and Cotton Valley Fields, totaled $1,309,000, $1,650,000 and
$1,965,000, respectively. No amounts for gathering, treating or transportation
are deducted in calculating the purchase price from the Chalkley Field.
33
<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,
1999 and 1998
Statements of Distributable Income for the Years Ended December 31,
1999, 1998 and 1997
Statements of Changes in Trust Corpus for the Years Ended December
31, 1999, 1998 and 1997
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, 1999 and 1998
and the Related Consolidated Statements of Operations,
Stockholders' Equity and Comprehensive Income, and Cash Flows for
the years ended December 31, 1999, 1998 and 1997
Predecessor's Consolidated Statement of Operations, Predecessor's
Equity and 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.*
10.5 - Form of Texas Conveyance.*
10.6 - Form of Louisiana Conveyance.*
10.7 - Form of Alabama Conveyance.*
34
<PAGE>
TORCH ENERGY ROYALTY TRUST
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 & 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, 1999.
35
<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 24, 2000
(The Trust has no directors or executive officers.)
36
<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
Haynes and Boone, L.L.P.
Houston, Texas
Tax Counsel
Haynes and Boone, L.L.P.
Houston, Texas
Auditors
Ernst & Young L.L.P.
Houston, Texas
Transfer Agent and Registrar
Wilmington Trust Company
1100 North Market Street
Wilmington, Delaware 19890
Attention: Corporate Trust Administration
37
<PAGE>
EXHIBIT 23.1
CONSENT OF T.J. SMITH & COMPANY, INC.
We hereby consent to the use of our report dated February 16, 2000 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 27, 2000
<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 to the inclusion of and
references to our report dated February 16, 2000, prepared for Torch Energy
Advisors Incorporated in the Torch Energy Royalty Trust Annual report on
Form 10-K for the year ended December 31, 1999.
H.J. GRUY AND ASSOCIATES, INC.
By: /s/ H.J. Gruy and Associates, Inc.
----------------------------------
Houston, Texas
March 28, 2000
<PAGE>
EXHIBIT 23.3
CONSENT OF RYDER SCOTT COMPANY
We hereby consent to the use of our report dated February 17, 2000 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 27, 2000
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 2
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 0
<PP&E> 49,141
<DEPRECIATION> 0
<TOTAL-ASSETS> 49,143
<CURRENT-LIABILITIES> 161
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 48,982
<TOTAL-LIABILITY-AND-EQUITY> 49,143
<SALES> 0
<TOTAL-REVENUES> 10,185
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 674
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 9,511
<INCOME-TAX> 0
<INCOME-CONTINUING> 9,511
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 9,511
<EPS-BASIC> 1.11
<EPS-DILUTED> 1.11
</TABLE>
<PAGE>
EXHIBIT 99.1
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Torch Energy Advisors Incorporated:
We have audited the accompanying consolidated balance sheet of Torch Energy
Advisors Incorporated and subsidiaries (the "Company") as of December 31, 1999
and the related consolidated statements of operations, stockholder's deficit and
comprehensive income and cash flows for the year then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audit provides a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Torch Energy
Advisors Incorporated and subsidiaries at December 31, 1999 and the consolidated
results of their operations and their cash flows for the year then ended, in
conformity with accounting principles generally accepted in the United States.
/s/ ERNST & YOUNG LLP
- -----------------------
Houston, Texas
March 17, 2000
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Torch Energy Advisors Incorporated:
We have audited the accompanying consolidated balance sheet of Torch Energy
Advisors Incorporated and subsidiaries as of December 31, 1998, and the related
statements of operations, stockholders' equity and cash flows for each of the
years in the two-year period then ended. 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 included 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 the
results of their operations and their cash flows for each of the years in the
two-year period then ended in conformity with generally accepted accounting
principles.
/s/ KPMG LLP
- -------------------
Houston, Texas
March 30, 1999
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in Thousands)
ASSETS
------
<TABLE>
<CAPTION>
December 31,
---------------------------------------------------
1999 1998
--------------------- ---------------------
CURRENT ASSETS:
<S> <C> <C>
Cash and cash equivalents....................................... $ 6,530 $ 35,923
Accounts receivable - product marketing......................... 51,702 45,636
Accounts receivable - joint interest billing.................... 4,307 10,692
Accounts receivable - oil and gas and other..................... 17,736 23,357
Notes receivable................................................ 38,812 ---
Assets from price risk management activities.................... 7,237 ---
Due from affiliates............................................. 5,739 7,856
Other current assets............................................ 7,580 5,118
----------------- -----------------
Total current assets........................................ 139,643 128,582
----------------- -----------------
PROPERTY AND EQUIPMENT, at cost:
Oil and gas (successful efforts method)......................... 12,353 8,106
Other fixed assets.............................................. 13,435 10,363
----------------- -----------------
25,788 18,469
Accumulated depreciation, depletion and amortization............ (10,913) (5,574)
----------------- -----------------
14,875 12,895
----------------- -----------------
NOTES RECEIVABLE.................................................. 1,908 37,001
INVESTMENT IN MARKETABLE SECURITIES............................... 1,489 741
EQUITY INVESTMENTS................................................ 2,038 5,735
INVESTMENTS AT COST............................................... 245 400
OTHER ASSETS...................................................... 1,932 1,753
----------------- -----------------
$ 162,130 $ 187,107
================== =================
</TABLE>
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 STOCKHOLDER'S EQUITY (DEFICIT)
<TABLE>
<CAPTION>
December 31,
-------------------------------------------------
1999 1998
--------------------- ---------------------
CURRENT LIABILITIES:
<S> <C> <C>
Accounts payable - product marketing.................... $ 55,806 $ 46,519
Accounts payable - joint interest billing............... --- 7,445
Accounts payable and accrued liabilities................ 13,490 21,221
Liabilities from price risk management activities....... 7,666 ---
Note payable to bank.................................... 41,689 ---
Revenue, royalty and production taxes payable........... 12,565 31,917
----------- -----------
Total current liabilities............................. 131,216 107,102
----------- -----------
OTHER LIABILITIES......................................... 7,388 7,618
-----------
NOTE PAYABLE TO BANK...................................... 8,200 36,277
----------- -----------
SENIOR SUBORDINATED
NOTE PAYABLE - AFFILIATE.................................. 25,500 25,500
----------- -----------
COMMITMENTS AND CONTINGENCIES.............................
STOCKHOLDER'S EQUITY (DEFICIT):
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........................................... (779) (516)
Retained earnings (deficit)............................... (7,101) 12,093
Due from stockholder...................................... (4,294) (2,967)
----------- -----------
Total stockholder's equity (deficit).................. (10,174) 10,610
----------- -----------
$ 162,130 $ 187,107
=========== ============
</TABLE>
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 Year
Ended Ended Ended
December 31, December 31, December 31,
1999 1998 1997
------------------------------- -----------
<S> <C> <C> <C>
REVENUES:
Oil and gas revenues................................................. $ 13,528 $ 15,064 $ 18,522
Product marketing and other trading, net............................. 1,627 4,424 5,333
Service fees......................................................... 23,574 23,125 26,034
Operating fees....................................................... 13,234 8,485 8,962
Interest and other income............................................ 7,280 5,559 5,328
Gain on sale of assets............................................... 234 343 ---
----------- --------- ----------
Total revenues..................................................... 59,477 57,000 64,179
----------- --------- ----------
COSTS AND EXPENSES:
Oil and gas operating expenses....................................... 8,018 8,272 8,936
Depreciation, depletion and amortization............................. 5,687 3,567 2,307
General and administrative expenses.................................. 44,617 38,963 37,062
Provision for credit losses.......................................... 4,530 --- ---
Interest expense..................................................... 6,676 3,683 2,816
Other expense........................................................ 437 490 701
----------- --------- ----------
Total costs and expenses......................................... 69,965 54,975 51,822
----------- --------- ----------
Impairment and equity losses of investees.............................. (7,379) (2,174) (159)
----------- --------- ----------
INCOME (LOSS) BEFORE MINORITY INTEREST, INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES............................. (17,867) (149) 12,198
Minority interest...................................................... 1,014 1,038 426
Income taxes........................................................... --- --- 115
----------- --------- ----------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLES............................................................ (16,853) (1,187) 11,657
Cumulative Effect of Change In Accounting Principles
For Energy Trading And Risk Management
Activities........................................................... 323 --- ---
----------- --------- ----------
NET INCOME (LOSS)...................................................... $ (16,530) $ (1,187) $ 11,657
=========== ========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
4
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF
STOCKHOLDER'S EQUITY (DEFICIT) AND COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(Amounts in Thousands)
<TABLE>
<CAPTION>
UNREALIZED GAIN
(LOSS) IN VALUE OF TOTAL
COMMON STOCK INVESTMENT IN EQUITY RETAINED DUE FROM STOCKHOLDER'S
SHARES AMOUNT PAID-IN CAPITAL SECURITIES, NET EARNINGS STOCKHOLDER EQUITY
------ ------ ---------------- -------------------- --------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, January 1, 1997... 1 $ 1 $1,999 $ -- $ 2,250 -- $ 4,250
Advances to stockholder.... -- -- -- -- -- (1,850) (1,850)
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 1 1 1,999 394 13,907 (1,850) 14,451
Dividends paid............. -- -- -- -- (627) -- (627)
Advances to stockholder.... -- -- -- -- -- (1,117) (1,117)
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. 1 1 1,999 (516) 12,093 (2,967) 10,610
Dividends paid............. -- -- -- -- (2,664) -- (2,664)
Advances to stockholder.... -- -- -- -- -- (1,327) (1,327)
Comprehensive loss:
Unrealized loss in value
of investment in
equity securities...... -- -- -- (263) -- -- (263)
Net loss................. -- -- -- -- (16,530) -- (16,530)
--------
Total comprehensive loss... (16,793)
----- --- ------ ------- ---------- ------- --------
Balance, December 31, 1999. 1 $ 1 $1,999 $ (779) $ (7,101) $(4,294) $(10,174)
===== === ====== ======= ========== ======= ========
</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 Year
Ended Ended Ended
December 31, December 31, December 31,
1999 1998 1997
------------------- ------------------ ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
<S> <C> <C> <C>
Net income (loss).............................................. $(16,530) $(1,187) $ 11,657
Adjustments to reconcile net income (loss)
to net cash provided by (used in)
operating activities:
Depreciation, depletion and
amortization............................................... 5,687 3,567 2,307
Impairment and equity losses in investees.................... 7,379 2,174 159
Transaction fee.............................................. --- --- (1,256)
Minority interest............................................ (1,014) 1,038 426
Provision for credit losses.................................. 4,530 --- ---
Price risk management activities............................. 1,118 --- ---
Deferred income taxes........................................ --- --- (908)
Gain on sale of assets....................................... (234) (343) ---
Changes in assets and liabilities net of effects
of acquisitions accounted for under the
purchase method of accounting:
Accounts receivable..................................... 4,224 8,766 28,627
Due from affiliates..................................... 2,259 (5,105) 4,758
Other current assets.................................... (2,486) (1,950) (1,471)
Accounts payable and accrued liabilities................ (5,793) (9,572) (15,846)
Due to affiliates....................................... --- --- (5,589)
Revenue, royalty and production taxes payable........... (19,352) 1,401 (11,764)
Other................................................... (517) (1,445) (2,496)
-------- ------ -------
Net cash flows provided by (used in) operating
activities..................................................... $(20,729) $(2,656) $ 8,604
-------- ------ -------
</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 Year
Ended Ended Ended
December 31, December 31, December 31,
1999 1998 1997
------------------ ------------------ -----------------
CASH FLOWS FROM INVESTING ACTIVITIES:
<S> <C> <C> <C>
Notes receivable from officers............................ $ 461 $ 567 $ 826
Notes receivable.......................................... (8,044) (24,609) (11,389)
Proceeds from the sale of assets.......................... 318 408 25,353
Investment in property and equipment...................... (7,706) (6,535) (5,572)
Investment in equity investees............................ (2,950) (3,679) (3,252)
Investments at cost....................................... (250) --- (400)
Investments in available for sale securities.............. (114) --- ---
Payment for purchase of Petroleum Financial
Inc. (net of cash acquired)............................. --- (1,207) ---
Distributions from investments in affiliates.............. --- 16 644
------------------- ------------------ ----------------
Net cash flows provided by (used in)
investing activities.................................. $(18,285) $(35,039) $ 6,210
------------------ ------------------ ------------------
</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 Year
Ended Ended Ended
December 31, December 31, December 31,
1999 1998 1997
-------------- ------------- -------------
<S> <C> <C> <C>
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from note payable to bank.................... $ 5,412 $ 25,663 $ 10,674
Proceeds from line of credit with bank................ 9,200 --- ---
Repayment of line of credit with bank................. (1,000) --- ---
Repayment of note payable to bank..................... --- (60) ---
Repayment of note payable............................. --- (141) ---
Payment of dividend................................... (2,664) (627) ---
Advances to stockholder (net)......................... (1,327) (1,117) (1,850)
------------ ------------- -------------
Net cash flows provided by financing activities......... 9,621 23,718 8,824
------------ ------------- -------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS...................................... (29,393) (13,977) 23,638
CASH AND CASH EQUIVALENTS AT BEGINNING
OF YEAR.............................................. 35,923 49,900 26,262
------------ ------------- -------------
CASH AND CASH EQUIVALENTS AT END OF YEAR............... $ 6,530 $ 35,923 $ 49,900
============ ============= =============
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest............................................ $ 2,207 $ 2,330 $ 2,338
============ ============= =============
Income taxes........................................ $ 84 $ 454 $ 797
============ ============= =============
</TABLE>
See accompanying notes to consolidated financial statements.
8
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
1. ORGANIZATION
Torch Energy Advisors Incorporated and its subsidiaries ("TEAI" or the
"Company") provide 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, energy price risk management, 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 TEAI, 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.
SUBSIDIARIES AND INVESTEES
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
9
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
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 other administrative services. The Company paid
$375,000 to obtain a 75% interest in TPC. The activities of TPC subsequent
to the acquisition were consolidated in the financial statements with the
unaffiliated parties' interest reflected as a minority interest. In January
1999 the Company sold a 25% interest in TPC resulting in the Company
changing its investment in TPC to be accounted for under the equity method.
Prior activities of TPC are not material.
Torch Energy Finance Fund LPI ("TEFF"), a Texas limited liability
partnership, was formed on September 6, 1995. The partnership agreement was
amended on July 14, 1997 for the purpose of allowing TEFF to provide growth
capital through loans and equity investments 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. TEFF's equity investees, owned 20% through
50%, and over which TEFF exercises significant influence, include TEC
Resources, LLC and ARI Development, LLC, which 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 which is accounted for under the equity method.
The Company evaluates its loans and equity investments for impairment and
if indicated records a valuation allowance or a write down as appropriate.
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. Activities for Torch
Drilling are consolidated in the Company's financial statements. Aeicon
Torch Capital Corporation ("ATCC") was formed on October 23, 1998 to
provide project finance advisory services to clients with projects that are
not in the upstream sector of the energy industry. The Company owns a 66.7%
interest and the activities of ATCC are consolidated in the financial
statements with the unaffiliated parties' interest reflected as a minority
interest. 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.
Torch Capital Corporation, a wholly owned subsidiary incorporated in
Delaware, was formed on January 21, 1999 as a licensed broker dealer.
Torch Capital Corporation, a wholly owned
10
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
subsidiary, incorporated in the Cayman Islands, was formed on October 21,
1999 to own non U.S. assets of the Company. Activities for both Torch
Capital Corporations are consolidated in the Company's financial
statements. Torch Rig Services, Inc., a wholly owned subsidiary, was formed
on June 11, 1999 for the purpose of providing drilling rig crew services to
third parties. Activities for Torch Rig Services, Inc. are consolidated in
the Company's financial statements.
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 three
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.
The Company has no held-to-maturity or trading securities at December 31,
1999. 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 is 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
11
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
incurred a write-down of $0.35 million during the year ended December 31,
1999. No such write-down was incurred during the years ended December 31,
1998 and 1997.
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, 1999, 1998 and
1997.
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.
REVENUE RECOGNITION
Revenues associated with service and operating fees are recognized when
earned.
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, 1999 and 1998, the
Company's liabilities due to gas sales in excess of its entitled share were
approximately $0.4 million and $0.67 million, respectively, and the
receivable for gas sales less than the Company's entitled share was
approximately $0.56 million at December 31, 1998.
ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES
The Company, through its subsidiaries, engages in price risk management
activities for both trading and non-trading purposes. In November of 1998,
the Financial Accounting Standard Board's Emerging Issues Task Force
("EITF") reached a consensus on EITF Issue No. 98-10 ("EITF 98-10"),
"Accounting for Energy Trading and Risk Management Activities." EITF 98-10
is effective for fiscal years beginning after December 15, 1998 and
requires that energy trading contracts be marked to market with the gains
and losses included in earnings. Effective January 1, 1999, the Company
adopted mark-to-market accounting for its energy trading activities as
defined by EITF 98-10. The cumulative effect of this change in accounting
principle is reflected as a separate line item in the Consolidated
Statement of Operations for the year ended December 31, 1999.
To conduct its trading activities, the Company uses futures, forwards,
swaps and options. Under the mark-to-market method of accounting used to
account for trading activities, the related outstanding physical and
financial instruments are reflected at fair value, inclusive of reserves,
with resulting unrealized gains and losses recorded as "Assets from price
risk management activities," "Other Assets," "Liabilities from price risk
management activities," and "Other Liabilities," respectively, on the
Consolidated Balance Sheet. Current period changes in the assets and
liabilities from price risk management activities are recognized as net
gains or
12
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
losses in "Product marketing and other trading, net" on the Consolidated
Statements of Operations. The market prices used to value these
transactions reflect management's best estimate considering various factors
including closing exchange and over-the-counter quotations, time value and
volatility factors. The values are adjusted to reflect the potential impact
of liquidating the Company's position in an orderly manner over a
reasonable period of time under present market conditions.
Certain financial derivative contracts are also utilized for non-trading
purposes to hedge the impact of market fluctuations on oil and gas
production. The Company uses the hedge method of accounting for non-
trading activity and, as a result, gains and losses related to derivatives
that qualify as hedges are recognized in income in the same manner as the
hedged item. To qualify as hedges, there must be a high degree of
correlation between the price movements in the instruments and the item
designated as being hedged, 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 $0.4
million at December 31, 1998. In instances where the anticipated
correlation of price movements does not occur, hedge accounting is
terminated and future changes in the value of the instruments are
recognized in income. Upon completion of the associated hedged
transaction, the realized gains and losses are recognized in "Oil and gas
revenues."
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for
Derivative Instruments and Hedging Activities, which establishes accounting
and reporting standards for derivative instruments and hedging activities.
SFAS 133 requires that every derivative instrument be recorded in the
balance sheet as either an asset or liability at its fair value. Changes
in the derivative's fair value must be recognized in earnings unless
specific hedge accounting criteria are met. Adoption of SFAS 133 is
required for fiscal years beginning after June 15, 2000 and will be adopted
by the Company in year 2001. The Company has not yet quantified the effect
of adopting SFAS 133 on the consolidated financial statements.
CONCENTRATIONS OF CREDIT RISK-
Credit risk is the risk of loss from nonperformance by suppliers, customers
or financial counterparties to a contract. Financial instruments, which
subject the Company to credit risk, consist principally of trade
receivables, forwards, over-the-counter options and swaps. Prospective and
existing customers are reviewed for creditworthiness based upon pre-
established standards. Customers not meeting the Company's credit standards
are required to provide an acceptable form of payment security. At
December 31, 1999, accounts receivables and other financial instruments
were predominantly with energy related and energy trading companies in the
United States.
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.
13
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
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.
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
DUE FROM STOCKHOLDER -
The company has advanced approximately $4.3 million to TAC ($1.3 million
in 1999, $1.1 million in 1998, and $1.9 million in 1997) which was used to
repurchase common stock and options awarded to former shareholders and
directors. The related amount due from stockholder is reflected as a
contra-equity account in the accompanying financial statements.
NOTES RECEIVABLE -
On October 9, 1998, the Company was issued a promissory note from one of
the Company's officers for $1.8 million. On June 25, 1999, a payment for
$0.4 million was received on the note and a new promissory note was issued
for $1.4 million. The Company also has other outstanding notes receivable
from five of its officers amounting to $.5 million. (See Note 6.)
ASSET MANAGEMENT -
The Company provides management services relating to oil and gas operations
for affiliated entities and investees, including Bellwether, a major
customer, whose principal officer is also the principal stockholder of TAC.
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 $3.0 million,
$1.0 million and $1.8 million for the years ended December 31, 1999, 1998
and 1997, respectively.
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.
14
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
PRODUCT MARKETING AND OTHER TRADING INCOME -
The Company markets oil and natural gas production from properties in which
related parties own interests. The Company's marketing fee ranges from 0.5%
to 3% of revenues; such charge is customary within the oil and gas
industry. Such revenues for the Company amounted to $2.0 million, $0.3
million and $1.2 million for the years ended December 31, 1999, 1998 and
1997, respectively.
In the normal course of business, the Company purchases natural gas from
and sells natural gas to affiliates. In 1999, 1998 and 1997 such purchases
amounted to $21.7 million, $18.0 million and $6.0 million, respectively.
Sales amounted to $85.2 million, $66.0 million and $112.0 million in 1999,
1998 and 1997, respectively.
In August of 1998, the Company bought a twelve month natural gas
option from an unconsolidated affiliate. The aggregate absolute notional
volume of the option was 6 bcf. At December 31, 1998, the Company
recognized a gain of approximately $800,000 ($400,000 net of minority
interest) related to this option.
WELL OPERATIONS -
The Company operates properties in which related parties have an ownership
interest. These related parties are charged for all customary expenses and
cost reimbursements associated with such activities on the same basis as
third parties. Operators' fees charged to affiliates by the Company for
the years ended December 31, 1999, 1998 and 1997 for these activities were
$0.5 million, $0.5 million and $0.5 million, respectively.
4. INCOME TAXES
The Company's income tax provision for the year ended December 31,1997, is
comprised of the following (amounts in thousands):
<TABLE>
<CAPTION>
<S> <C>
Current income tax expense (benefit)
Federal (1)............................................... $ 548
State..................................................... 475
-------------------------
1,023
-------------------------
Deferred income tax expense (benefit)
Federal.................................................. (809)
State.................................................... (99)
-------------------------
(908)
-------------------------
$ 115
=========================
</TABLE>
(1) The 1997 amount relates to revisions of 1996 tax expense estimates.
15
<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
Ended
December 31,
1997
-----------------------
<S> <C>
Statutory tax rate ---%
State........................................................ 3
Section 29 tax credits....................................... ---
Other........................................................ (2)
-----------------------
Effective tax rate........................................... 1%
=======================
</TABLE>
5. INVESTMENTS
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). The market value of the Company's investment in Bellwether at December
31, 1999, 1998 and 1997,was $0.7 million, $0.7 million and $1.7 million,
respectively.
In September 1999, the Company received 800,000 common shares of Carpatsky
Petroleum, Inc. ("Carpatsky"), a Canadian publicly traded company, valued
at $0.1 million, for operational technical services provided by the
Company. In October 1999, the Company received 6,597,720 Carpatsky shares
valued at $0.9 million and a warrant to acquire an additional 6,207,808
shares in full satisfaction of a $0.7 million note and related interest due
from Carpatsky. At December 31, 1999, the Company recorded $0.2 million in
unrealized losses due to the difference between cost and market value in
its investment in Carpatsky, resulting in a carrying value of $.8 million.
During 1999, the Company recognized an impairment loss of $3.1 million on
its investment in SMGC, as it was determined that the carrying value
exceeded the fair value of the investment.
The Company has permanently impaired TEFF's investments due to its
anticipated inability to recover their underlying carrying value (see Note
6). Accordingly, an investment writedown of $2.1 million has been recorded
in the accompanying financial statements.
6. NOTES RECEIVABLE
TEFF was issued promissory notes by three entities in connection with the
collateralized financing it provides to exploration and production
companies. As its source of funding for the notes TEFF uses proceeds
received from a credit facility with a bank (see Note 12). Under the terms
of this credit facility, the bank reviews on a portfolio basis the value of
all collateral on the notes held by TEFF to determine the amount of funds
to be made available from the credit facility. The bank's collateral for
the TEFF outstanding loan amounts, is the assigned mortgages of the oil and
gas properties which TEFF has as collateral from its notes receivable and
all other assets of TEFF.
16
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
Consistent with the terms of TEFF's credit facility with the bank, notes
receivable are carried at their unpaid principal balance subject to an
impairment adjustment. The impairment of the notes receivable balance is
measured on an aggregate portfolio basis. At December 31, 1999 and 1998,
the total recorded investments in the receivables including accrued
interest was approximately $47.6 million and $37.2 million, respectively.
A reserve for credit losses of approximately $4.5 million has been
established as of December 31, 1999. At December 31, 1998 there was no
reserve for credit losses. The Company has suspended interest income
recognition as a result of the impairment of the notes receivable. (See
Note 12)
In December 1996, the Company was issued promissory notes from the
Company's officers totaling $2 million. Interest accrues on these notes at
8% with principal and interest payments due annually through December 31,
2002. In June 1999, the Company was issued a promissory note from one of
the Company's officers for $1.4 million. Interest accrues on this note at
8% with principal and interest payments due annually through December 31,
2005.
7. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS
Effective January 1, 1996, the Company established a 401(k) retirement
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 $1.0 million, $1.1 million and $.9 million
for the years ended December 31, 1999, 1998 and 1997, 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. No such contributions were made for the year
ended December 31, 1999. The Company's contributions to the discretionary
plan total $.6 million and $1 million for the years ended December 31, 1998
and 1997, respectively.
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 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. 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, 1999 or 1998.
9. ACQUISITIONS AND DISPOSITIONS OF ASSETS
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,
17
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
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.
10. OTHER LONG-TERM LIABILITIES
Other long-term liabilities at December 31, 1999 and 1998 consist of the
following (amounts in thousands):
<TABLE>
<CAPTION>
1999 1998
---------------------- -----------------------
<S> <C> <C>
Royalties payable.................................................. $1,962 $2,086
Liabilities from price risk management activities ................. 1,670 ---
Minority interest.................................................. 1,345 2,551
Other.............................................................. 2,411 2,981
---------------------- -----------------------
$7,388 $7,618
====================== =======================
</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, 1999, the
Company purchased 6,972 MMCF of gas and 52 Mbbls of oil at an average price
of $2.11 per MCF and $14.13 per Bbl. 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. Under the Hedge
Contract, monthly quantities of gas hedged decrease from 531,167 MMbtus of
gas in 1997 to 17,250 MMbtus of gas in 2000 and monthly quantities of oil
hedged decrease from 6,333 Bbls in 1997 to 167 Bbls in 2000. The price
received for gas under the Hedge Contract increases from $1.84 per MMbtu in
1997 to $1.89 per MMbtu in 2000. The price received for oil under the
Hedge Contract increases from $19.94 per Bbl in 1997 to $20.20 per Bbl in
2000.
Additionally, the Company has purchased contracts expiring December 2002 to
further limit its exposure to losses under the minimum price obligation
Purchase Contract. Under these contracts, monthly quantities hedged range
from 16,989 MMbtus per day to 24,765 MMbtus
18
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
per day with floor pricing ranging from $1.81 to $1.82 per MMbtu during the
six-year period ending December 31, 2002.
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 -
Until August 31, 1999, the Company maintained a $13 million credit facility
(the "Credit Facility") with a bank. Interest accrued on indebtedness, at
the Company's option, at the bank's prime rate if less than 50% of revolver
borrowing base was outstanding, prime plus .25% if 50% or more, but less
than 75% of revolver borrowing base was outstanding or prime plus .50% if
75% or more of revolver borrowing base was outstanding; or the 1 year
London Interbank Offered Rate ("LIBOR") plus 1.5% if less than 50% of
revolver borrowing base was outstanding, LIBOR plus 1.75% if 50% or more,
but less than 75% of revolver borrowing base was outstanding or LIBOR plus
2% if 75% or more of revolver borrowing base was outstanding. The Credit
Facility contained, 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 received a waiver on the consolidated
interest coverage ratio as of December 31, 1998. Certain oil and gas
properties, stock and fixed assets secured the Credit Facility. At
December 31, 1998, there was no outstanding balance under the line of
credit.
On August 31, 1999, the Company entered into a new $50 million credit
facility (the "new Credit Facility") with a bank. Interest accrues on
indebtedness, at the Company's option, at the bank's prime rate less .75%
if less than 50% or more of the borrowing base is outstanding ($17.5
million at December 31, 1999), prime less .375% if 50% or more of the
borrowing base is outstanding; or the LIBOR rate (7.75% at December 31,
1999). The new Credit Facility has a September 1, 2002 maturity date and
contains, among other terms, provisions for the maintenance of certain
financial ratios and restrictions on additional debt. Certain oil and gas
properties secure the new Credit Facility. At December 31, 1999, the
outstanding balance under the new Credit Facility is $8.2 million and the
borrowing base was set at $17.5 million.
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% (9.5% and 8.25% at
December 31, 1999 and 1998, respectively) or LIBOR plus 2.0% (8.5% and
7.10% at December 31, 1999 and 1998, respectively) if the loans outstanding
are less than or equal to the portfolio base ($20.1 million at December 31,
1999 and 1998); and at the bank's prime rate plus 5.5% (14.5% and 13.25% at
December 31, 1999 and 1998, respectively) or LIBOR plus 7.0% (13.5% and
12.10% at December 31, 1999 and 1998, respectively) 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, 1999 and 1998, the outstanding balances under the TEFF
Facility were $41.7 million and $36.3 million, respectively, at a weighted
average interest rate of 11.1% and 9.7%, respectively. In addition the
principal 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
principal 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 payments were made for the years ended December 31, 1999
and 1998.
Effective March 9, 2000 TEFF amended the TEFF facility with a bank. The
amendment changed the maturity date to June 30, 2000. In addition, the
interest rate changed to the bank's prime rate plus 1% or LIBOR plus 4%
regardless of the portfolio base, and changed the allocation of gross sales
proceeds between debt repayment and funds available for distribution in the
event of a sale of TEFF's investments
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.
During 1998, TEMI assumed a $1.6 million liability related to litigation
activity between its 50% owned gas marketing limited liability company and
a trading partner arising out of commitments made for financial
transactions and price disputes. During 1999, the litigation was settled
resulting in a favorable impact of approximately $0.7 million to TEMI's
income.
SMGC -
SMGC has a $29 million bank loan due on October 31, 2000. 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. The Company does not expect to incur any losses
in connection with the required performance, if any, on the TEMI guaranty.
20
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
LEASE OBLIGATIONS -
Rental expense for operating leases was approximately $2.1 million, $1.7
million and $1.7 million for the years ended December 31, 1999, 1998 and
1997, 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, 1999
(amounts in thousands):
Operating
Year Ending December 31, Leases
------------------------ ---------------
<TABLE>
<CAPTION>
<S> <C>
2000................ $ 2,031
2001................ 1,966
2002................ 2,120
2003................ 1,905
2004................ 1,908
Thereafter.......... 3,828
-------
$13,758
=======
</TABLE>
LETTERS OF CREDIT -
The Company has open letters of credit of approximately $2.5 million at
December 31, 1999.
14. PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
TRADING ACTIVITIES -
The Company, through its subsidiaries, offers price risk management
services to energy-related businesses through a variety of financial and
other instruments including forward contracts involving physical delivery
of an energy commodity, swap agreements, which require payments to (or
receipt of payments from) counterparties based on the differential between
a fixed and variable price for the commodity, options contracts requiring
payments to (or receipt of payments from) counterparties based on the
difference between the options' strike and market prices for the commodity
and other contractual arrangements. The Company attempts to balance its
contractual portfolio in terms of notional amounts and the timing of
performance and delivery obligations. However, net unbalanced positions
can exist or are established based upon assessment of anticipated market
movements.
At December 31, 1999, the Company's natural gas and crude oil swaps had
notional volumes of 188 bcf and .9 million barrels, respectively. The
Company's natural gas and crude oil over-the-counter options had notional
volumes of 25 bcf and 3 million barrels, respectively. Notional amounts
reflect the volume of transactions but do not represent the amounts
exchanged by the parties to the financial instruments. Accordingly,
notional amounts do not accurately measure TEAI's exposure to market or
credit risks.
21
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
At December 31, 1999, the fair value of the Company's natural gas swaps and
over-the-counter options, extending to 2002, was a liability of $1.1
million. The average fair values of the natural gas swaps and over-the-
counter options was a liability of approximately $430,000.
At December 31, 1999, the fair value of the Company's crude oil swaps and
over-the-counter options, extending to 2001, was a liability of $31,000.
The average fair values of the crude oil swaps and over-the-counter options
during 1999 was an asset of approximately $30,000.
Inherent in the resulting contractual portfolio are certain business risks,
including market risk and credit risk. Market risk is the risk that the
value of the portfolio will change, either favorably or unfavorably, in
response to changing market conditions. Credit risk is the risk of loss
from nonperformance by suppliers, customers, or financial counterparties to
a contract. The Company monitors and manages market risk and credit risk
through a variety of techniques, including periodic reporting of the
portfolio's value to senior management.
NON-TRADING ACTIVITIES -
The Company also enters into financial swap contracts for the purpose of
hedging the impact of market fluctuations on production. At December 31,
1999, the Company was party to energy commodity swaps covering 3.7 bcf of
natural gas extending to 2001.
While notional amounts are used to express the volume of swaps and over-
the-counter options, the amounts potentially subject to credit risk, in the
event of nonperformance by the third parties, are substantially smaller.
The Company does not anticipate any material impact to its financial
position or results of operations as a result of nonperformance by third
parties on financial instruments related to non-trading activities.
The carrying amounts of the Company's cash, and cash equivalents,
receivables, other current assets and payables approximates the fair value
at December 31, 1999 and 1998 because of their short maturities.
22
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
The carrying amounts and estimated fair values of the Company's other
financial instruments, excluding trading activities which are marked to
market, at December 31, 1999 and 1998 were as follows:
<TABLE>
<CAPTION>
1999 1998 (1)
- --------------------------------------------------------------------------------------------------------------------------------
Carrying Amount Estimated Fair Carrying Amount Estimated Fair
(In Thousands) Value Value
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
ASSETS
Crude Oil swaps --- --- --- $ 41
- --------------------------------------------------------------------------------------------------------------------------------
Natural gas swaps and options --- --- --- $ 1,357
- --------------------------------------------------------------------------------------------------------------------------------
LIABILITIES
Natural gas swaps --- $ (754) --- ---
- --------------------------------------------------------------------------------------------------------------------------------
Long-term debt $33,700 $33,700 $25,500 $25,500
- --------------------------------------------------------------------------------------------------------------------------------
Line of credit - TEFF $41,689 $41,689 $36,277 $36,277
- --------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The Company uses the following methods and assumptions in estimating fair
values: (a) energy commodity swaps and over-the-counter options estimated
fair values have been determined using available market data and valuation
methodologies and (b) the carrying amounts of the Senior Subordinated Rate
Payable-Affiliate and Notes Payable to Bank approximate fair value.
Judgement is necessarily required in interpreting market data and the use
of different market assumptions or estimation methodologies may affect the
estimated fair value amounts.
(1) Includes trading activities for which hedge accounting was used in
1998.
15. 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 and marketing 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
23
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
and exploitation opportunities. The trading and marketing 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.
24
<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, 1999, 1998 and 1997 (amounts in
thousands).
<TABLE>
<CAPTION>
Year Ended December 31, 1999
-------------------------------------------------------------------
Trading &
Service Capital Marketing Oil & Gas
Activities Group Group Properties Totals
----------- ----------- --------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues from external clients......... $ 35,912 $ --- $ 2,523 $ 13,528 $ 51,963
Intersegment revenues.................. 4,088 --- --- --- 4,088
Interest revenue....................... --- 4,441 617 --- 5,058
Interest expense....................... --- 4,051 --- --- 4,051
Depletion, depreciation and
amortization........................... 3,265 --- --- 1,831 5,096
Equity in loss of investees............ --- (3,388) --- --- (3,388)
Segment profit (loss).................. (567) (8,453) 530 (409) (8,899)
Other significant non-cash items:
--------------------------------
Segment assets......................... 5,173 43,342 51,702 8,151 108,368
Equity in investees.................... --- --- --- --- ---
Expenditures for segment assets........ 3,324 --- --- 4,247 7,571
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1998
---------------------------------------------------------------------------------
Trading &
Service Capital Marketing Oil & Gas
Activities Group Group Properties Totals
------------- -------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <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 45,636 5,735 94,778
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
---------------------------------------------------------------------------------
Trading &
Service Capital Marketing Oil & Gas
Activities Group Group Properties Totals
------------- -------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <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 55,588 5,206 76,757
Equity in investees.................... --- 2,121 --- --- 2,121
Expenditures for segment assets...... 2,655 --- --- 2,362 5,017
</TABLE>
25
<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, 1999, 1998
and 1997 (amounts in thousands):
<TABLE>
<CAPTION>
Year Ended Year Ended Year Ended
December 31, 1999 December 31, 1998 December 31, 1997
-------------------- -------------------- --------------------
Revenues
- --------
<S> <C> <C> <C>
dTotal revenues for reportable segments.......... $ 61,109 $ 57,788 $ 63,573
Other revenues.................................. 2,456 2,848 3,792
Elimination of intersegment revenues............ (4,088) (3,636) (3,186)
-------------------- -------------------- --------------------
Total consolidated revenues..................... $ 59,477 $ 57,000 $ 64,179
==================== ==================== ====================
Interest Expense
- ----------------
Total interest expense for reportable
segments........................................ $ 4,051 $ 1,353 $ 476
Other interest expense.......................... 2,625 2,330 2,340
-------------------- -------------------- --------------------
Total interest expense.......................... $ 6,676 $ 3,683 $ 2,816
==================== ==================== ====================
Depletion, Depreciation and Amortization:
- ------------------------------------------
Total depletion, depreciation and amortization
for reportable segments......................... $ 5,096 $ 3,061 $ 1,984
Other depletion, depreciation and amortization.. 591 506 323
Total depletion, depreciation and -------------------- -------------------- --------------------
amortization.................................... $ 5,687 $ 3,567 $ 2,307
==================== ==================== ====================
Equity in Loss of Investees:
- ----------------------------
Total equity in loss of investees for reportable
segments........................................ $ 3,388 $ 862 $ ---
Other equity in loss of investees............... 3,991 1,312 159
-------------------- -------------------- --------------------
Total equity in loss of investees............... $ 7,379 $ 2,174 $ 159
==================== ==================== ====================
Profit or Loss
- --------------
Total profit or loss for reportable segments.... $ (8,899) $ 4,030 $ 14,013
Other profit or loss............................ (7,954) (5,217) (2,356)
-------------------- -------------------- --------------------
Net income (loss)............................... $ (16,853) $ (1,187) $ 11,657
==================== ==================== ====================
Assets
- ------
Total assets for reportable segments............ $ 108,368 $ 94,778 $ 76,757
Other assets.................................... 53,762 92,329 97,355
-------------------- -------------------- --------------------
Consolidated total.............................. $ 162,130 $ 187,107 $ 174,112
==================== ==================== ====================
Equity in Investees
- -------------------
Total equity in investees for reportable
segments........................................ $ --- $ 2,988 $ 2,121
Other equity in investees....................... 2,038 2,747 1,928
-------------------- -------------------- --------------------
Consolidated equity in investees................ $ 2,038 $ 5,735 $ 4,049
==================== ==================== ====================
</TABLE>
26
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MAJOR CUSTOMER -
One customer accounted for 13.6% and 26% of the gross marketing revenues
during the years ended December 31, 1998 and 1997, respectively. No
customer accounted for more than 10% of the gross marketing revenues for
the year ended December 31, 1999. Revenues from two customers, Bellwether
and Nuevo, totaled $26 million, $25 million and $29 million in service and
overhead fees for the years ended December 31, 1999, 1998 and 1997,
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, effective January 1999 and consists
of seven separate service contracts with terms that vary between one to
four years. The management service agreement with Bellwether was
renegotiated and effective October 1999, consists of six separate service
contracts with terms that vary between two and five years. Under the
renegotiated contracts with Nuevo and Bellwether, cash management
aggregation services are no longer provided by the Company. The loss of
one or both of these customers would have a material effect on the Company.
17. SUBSEQUENT EVENT
Effective February 16, 2000, Novistar entered into an asset purchase
agreement with Oracle Corporation to purchase certain assets of Oracle
Energy Upstream for a combination of cash, equity and a subordinated note.
The transaction closed on February 18, 2000.
18. 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. These reserve quantities
represent interests owned by the Company located solely within the United
States. Reserve quantities and future production are primarily based upon
reserve reports prepared by the 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. 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
27
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBIDIARIES
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.
28
<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, 1999, 1998 and 1997
(amounts in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------------------------------------
1999 1998 1997
------------------ ------------------ ------------------
<S> <C> <C> <C>
Cost incurred during the year
Property acquisition..................... $ --- $ --- $ ---
Exploration............................. --- --- ---
Development.............................. 4,120 1,752 2,739
------- ---------- ---------
$ 4,120 $ 1,752 $ 2,739
======== ========== =========
</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,
---------------------------------------
1999 1998 1997
---------------------------------------
Capitalized costs:
<S> <C> <C> <C>
Proved properties..................... $12,353 $ 8,106 $ 6,354
Accumulated depreciation,
depletion and amortization...... (4,552) (2,371) (1,148)
--------------- ---------- ----------
Net capitalized costs................ $ 7,801 $ 5,735 $ 5,206
============== ========== ==========
</TABLE>
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (AMOUNTS IN THOUSANDS) -
<TABLE>
<CAPTION>
Year Year Year
Ended Ended Ended
December 31, December 31, December 31,
1999 1998 1997
------------- ------------- -------------
<S> <C> <C> <C>
Revenues from oil and gas
producing activities............................... $ 13,528 $ 15,064 $ 18.522
Production costs.................................... (8,018) (8,272) (8,936)
Depreciation, depletion and
amortization....................................... (2,181) (1,223) (1,380)
Income tax provision *.............................. --- --- ---
------------- ------------- ------------
Results of operations from
producing activities (excluding
corporate overhead and interest costs)............. $ 3,329 $ 5,569 $ 8,206
============ ============ ============
</TABLE>
29
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
* No income tax provision is recorded in 1999, 1998 or 1997 as the Company
elected subchapter S corporation status effective January 1, 1997
(See Note 2).
<TABLE>
<CAPTION>
RESERVES-
<S> <C> <C> <C> <C> <C> <C>
The Company's estimated total proved and proved developed reserves of
oil and gas for the years ended
December 31, 1999, 1998 and 1997 are as follows:
1999 1998 1997
------------- --------------- ---------------
Oil Gas Oil Gas Oil Gas
(Mbbl) (Mmcf) (Mbbl) (Mmcf) (Mbbl) (Mmcf)
----- ------ ----- ------- ------ -------
Proved reserves at
beginning of year...................................................... 40 72,192 47 120,105 1,430 122,801
Sales of reserves in place.............................................. --- --- --- --- (1,312) (10,261)
Revisions of previous
estimates.............................................................. 20 (6,200) 4 (51,681) (4) 14,539
Extensions and discoveries.............................................. --- 2,605 --- 10,408 --- ---
Production.............................................................. (11) (5,736) (11) (6,640) (67) (6,974)
---- ------ --- ------- ------ -------
Proved reserves at end
of year................................................................ 49 62,861 40 72,192 47 120,105
==== ====== === ======= ====== =======
Proved developed reserves -
Beginning of year....................................................... 31 55,997 38 115,540 1,141 111,166
==== ====== === ======= ====== =======
End of year............................................................. 40 55,602 31 55,997 38 115,540
==== ====== === ======= ====== =======
</TABLE>
30
<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,
-----------------------------------
1999 1998 1997
---------- --------- ----------
<S> <C> <C> <C>
Future cash inflows.................... $ 139,272 $131,717 $ 296,161
Future production costs................ (111,452) (99,736) (213,799)
Future development costs............... (3,860) (5,998) (3,715)
--------- -------- ---------
Future net inflows before income tax... 23,960 25,983 78,647
Future income taxes*................... --- --- ---
--------- -------- ---------
Future net cash flows.................. 23,960 25,983 78,647
10% discount factor.................... (9,078) (10,366) (40,760)
--------- -------- ---------
Standardized measure of discounted
future net cash flows................. $ 14,882 $ 15,617 $ 37,887
========= ======== =========
</TABLE>
* No income tax provision is recorded in 1999, 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,
--------------------------------
1999 1998 1997
-------- --------- ---------
<S> <C> <C> <C>
Standardized measure -
Beginning of year................... $15,617 $ 37,887 $ 72,879
Sales, net of production costs...... (5,521) (6,792) (9,586)
Net change in prices and
production costs................... 906 (17,591) (46,379)
Extensions, discoveries and
improved recovery, net of future
production and development costs... 968 6,909 ---
Changes in estimated future
development costs.................. (469) (1,593) (930)
Development costs incurred during
the period......................... 4,120 1,752 2,739
Revisions of quantity estimates..... (1,518) (7,718) 4,700
Accretion of discount............... 1,562 3,789 10,260
Net change in income taxes.......... --- --- 29,724
Sales of reserves in-place.......... --- --- (26,810)
Changes in production rates and
other.............................. (783) (1,026) 1,290
------- -------- --------
Standardized measure -
end of year......................... $14,882 $ 15,617 $ 37,887
======= ======== ========
</TABLE>
31
<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, 1999, 1998 AND 1997
Revenues
The Company provides a broad range of technical and administrative services to
energy companies, often through outsourcing arrangements. In addition, the
Company provides development growth capital to independent oil and gas
companies, 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 1999. Revenues for such service
activities are received under various outsourcing and management contracts and
are classified primarily as Service Fees or Operating 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 Operating
Fees. Operating 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 historically contain provisions whereby the Company is paid based
upon the amount of book assets and operating cash flow of its clients. As of
October 1, 1999 such contracts had all been terminated and replaced with new
outsourcing agreements. Under the new agreements revenues are derived from a
combination of fixed and variable fees 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 and in particular the number and complexity of
the clients' oil and gas properties. 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 $23.6 million and $23.1 million in 1999 and 1998,
respectively. Fees were down 11.2% in 1998 from the 1997 figure of $26.0
million primarily due to a decrease in total assets and operating cash flow of
Nuevo Energy Company ("Nuevo").
Operating fees totaled $13.2 million in 1999, up 55.3% from the 1998 figure of
$8.5 million primarily due to the new Nuevo contract effective 1999. Beginning
in 1999, district operating expenses, which were previously reimbursed directly
by Nuevo, are now the responsibility of the Company and are to be recovered out
of the increased operating fees. (See Note 16 of the Notes to Consolidated
Financial Statements). Fees were down in 1998 from the 1997 figure of $9.0
million due to the sale of various non-core properties by clients.
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 1999 were $13.5 million, down 10.6% from 1998 oil and
gas revenues of $15.1 million. This decrease is mainly due to decreased
1
<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)
production in the coal-seam gas fields in Alabama and Wyoming. 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).
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 1999, 1998 and 1997, such
revenues totaled $4.4 million, $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
$1.6 million in 1999 from $4.4 million and $5.3 million in 1998 and 1997,
respectively. The Company's net product marketing revenues in 1999 includes a
net loss of $1.1 million related to the adoption of mark to market accounting
for trading activities.
From time to time, the Company has sold interests in various oil and gas
properties and securities. 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). During 1997, the Company
sold its interest in a gathering company to a third party for $1.8 million.
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 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 $43.5 million, $39.0 million and
$37.1 million in 1999, 1998 and 1997, respectively.
Oil and gas operating expenses for 1999 totaled $8.0 million, down 3.6% from
$8.3 million in 1998. Such decrease is mainly due to decreased production on
the coal-seam gas field in Alabama. The average unit production cost per Mcfe
in 1999 was $1.38 as compared to an average unit production cost per Mcfe in
1998 of $1.23. Oil and gas operating 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.
2
<PAGE>
TORCH ENERGY ADVISORS INCORPORATED
AND SUBSIDIARIES
MANAGEMENT'S DISCUSSI0N AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS OF
TORCH ENERGY ADVISORS INCORPORATED
(Unaudited)
Interest expense increased by 81.1% and 32.1% to $6.7 million and $3.7 million
in 1999 and 1998, respectively, from $2.8 million in 1997. Such increase is
primarily due to additional funds advanced to TEFF by the Bank of Montreal.
During 1999, consistent with TEFF's notes payable terms, an impairment of the
TEFF notes receivable balance of $4.3 million was recorded. No impairment was
recorded in 1998 or 1997.
Equity in Earnings of Affiliates and Investees
Equity in earnings of affiliates and investees consists of oil and gas
partnership interests and other investments. The Company recorded equity losses
of $7.4 million, $2.1 million, and $0.2 million for the years ended December 31,
1999, 1998, and 1997, respectively. The increase in equity losses in 1999 is
mainly due to the Companies anticipated inability to recover the underlying
carrying value of the investments and the resulting writedowns of the
investments of $5.1 million.
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 other administrative services. The Company owned a
75% interest in TPC and the activities were included in the financial statements
with the unaffiliated parties interest reflected as minority interest. In
January 1999, the Company sold a 25% interest in TPC resulting in the Company
changing its investment in TPC to be accounted for under the equity method.
Aeicon Torch Capital Corporation ("ATCC") was formed on October 23, 1998 to
provide project finance advisory services to clients with projects that are not
in the upstream sector of the energy industry. The Company owns a 66.7%
interest and the activities of ATCC are consolidated in the financial statements
with the unaffiliated parties' interest reflected as a minority interest.
3
<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)
Net Income
The foregoing activities resulted in the following net income (loss) (amounts in
thousands):
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
Income (Loss) before minority interest,
income taxes, and cumulative effect of
change in accounting principles $ (17,379) $ (149) $ 12,198
Net income (loss) $ (16,530) $ (1,187) $ 11,657
</TABLE>
LIQUIDITY AND CAPITAL RESOURCES
Net cash used in operating activities was $20.7 million and $2.7 million for the
years ended December 31, 1999 and 1998, respectively. Net cash provided by
operating activities was $8.6 million for the year ended December 31, 1997. 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 $7.7
million, $6.5 million and $5.6 million on investments in property and equipment
in 1999, 1998, and 1997, 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).
Financing Activities
Until August 31, 1999, the Company maintained a $13 million credit facility (the
"Credit Facility") with a bank. Interest accrued on indebtedness, at the
Company's option, at the bank's prime rate if less than 50% of revolver
borrowing base was outstanding, prime plus .25% if 50% or more, but less than
75% of revolver borrowing base was outstanding or prime plus .50% if 75% or more
of revolver borrowing base was outstanding; or the 1 year London Interbank
Offered Rate ("LIBOR") plus 1.5% if less than 50% of revolver borrowing base was
outstanding, LIBOR plus 1.75% if 50% or more, but less than 75% of revolver
borrowing base was outstanding or LIBOR plus 2% if 75% or more of revolver
borrowing base was outstanding. The Credit Facility contained, 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 received a waiver
on the consolidated interest coverage ratio as of December 31, 1998. Certain
oil and gas properties, stock and fixed assets secured the Credit Facility. At
December 31, 1998 and 1997, there was no outstanding balance under the line of
credit.
On August 31, 1999, the Company entered into a new $50 million credit facility
(the "new Credit Facility") with a bank. Interest accrues on indebtedness, at
the Company's option, at the bank's prime rate less .75% if less than 50% or
more of the borrowing base is outstanding ($17.5 million at December 31, 1999),
prime less .375% if 50% or more of the borrowing base is outstanding; or the
LIBOR rate (7.75% at December 31, 1999). The new Credit Facility contains,
among other terms, provisions for the maintenance of certain financial ratios
and restrictions on additional debt. Certain oil and gas properties secure the
new Credit Facility. At December 31, 1999, the outstanding balance under the
new Credit Facility is $8.2 million.
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% (9.5% and 8.25% at December 31, 1999
and 1998, respectively) or LIBOR plus 2.0% (8.5% and 7.10% at December 31, 1999
and 1998, respectively) if the loans outstanding are less than or equal to the
portfolio base ($20.1 million at December 31, 1999 and 1998); and at the bank's
prime rate plus 5.5% (14.5% and 13.25% at December 31, 1999 and 1998,
respectively) or LIBOR plus 7.0% (13.5% and 12.10% at December 31, 1999 and
1998, respectively) of the portion of loans outstanding in excess of the
portfolio base. If the
4
<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)
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 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, 1999 and 1998, the outstanding balances under the TEFF Facility
were $41.7 million and $36.3 million, respectively at a weighted average
interest rate of 11.1% and 9.7%, respectively. In addition the principal and
interest payments mentioned above, the bank will receive 50% of the remaining
cash flow after deduction of such principal and interest payments (NCFI). Until
such time as the NCFI payments are equal to TEFF's partners' contributions,
these amounts will be considered additional principal 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 payments were made for the years
ended December 31, 1999 and 1998.
Effective March 9, 2000 TEFF amended the TEFF facility with a bank. The
amendment changed the maturity date to June 30, 2000. In addition, the interest
rate changed to the bank's prime rate plus 1% or LIBOR plus 4% regardless of the
portfolio base, and changed the allocation of gross sales proceeds between debt
repayment and funds available for distribution in the event of a sale of TEFF's
investments
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 October 31, 2000. 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.
Financial Risk Mangement
The Company, through its subsidiaries offers price risk management services to
energy-related businesses (natural gas and crude oil) through a variety of
financial and other instruments including forward contracts involving physical
delivery of an energy commodity, swap agreements, which require payments to (or
receipt of payments from) counterparties based on the differential between a
fixed and variable price for the commodity, options contracts requiring payments
to (or receipt of payments from) counterparties based on the difference between
the options' strike and market prices for the commodity and other contractual
arrangements.
In order to mitigate the risk associated with its price risk management
services, the Company monitors and manages the inherent market risks through a
variety of techniques including periodic reporting of the portfolio's value to
senior management. The Company attempts to balance its
5
<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)
contractual portfolio in terms of notional amounts and the timing of performance
and delivery obligations. However, net unbalanced positions can exist or are
established based upon assessment of anticipated market movements.
The counterparties to these contractual arrangements are limited to the major
financial institutions and other established companies in the petroleum
industry. Although the Company is exposed to credit loss in the event of
nonperformance by these counterparties, this exposure is managed through credit
approvals, limits and monitoring procedures, and limits to the period over which
unpaid balances are allowed to accumulate. The Company has not experienced
nonperformance by counterparties to these contracts, and no material loss would
be expected from any such nonperformance.
The Company has major market risk exposure in the pricing applicable to its oil
and gas production. The Company enters into financial derivative contracts for
the purpose of hedging the impact of market fluctuations on its oil and gas
production. Changes in the market value of these hedge transactions are
deferred until the gain or loss is recognized on the hedged item.
6
<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)
Market Risk
Market risk is the risk that the value of the contractual portfolio will change,
either favorably or unfavorably, in response to changes in prices. The Company's
major market risk is commodity price risk related to natural gas and crude oil
price risk management services and its oil and gas production. Historically,
market prices for oil and gas productions and related financial derivative
contracts have been volatile and unpredictable. Pricing volatility is expected
to continue.
Effective January 1, 1999, the Company adopted mark to market accounting for
contracts related to its price risk management services in accordance with the
provisions of the Financial Accounting Standard Board's Emerging Issues Task
Force Issue No.98-10, "Accounting for Energy Trading and Risk Management
Activities." In connection with this, the Company has elected to present the
quantitative disclosures relative to market risk for option contracts in tabular
form and all other financial derivative contracts using a sensitivity analysis.
The following tables present the notional amounts, the weighted average strike
price, and the fair values by expected maturity dates for option contracts
related to price risk management activities during the years ended December 31,
1999 and 1998 (amounts in thousands).
December 31, 1999
----------------------------------------------------
Contract Weighted
Volumes Average Price Maturity Fair Value
-------- ------------- -------- ----------
Natural Gas Options
Held 6.4 bcf $1.81 2000 $ 128
6.2 bcf 1.81 2001 157
6.5 bcf 1.81 2002 (91)
Written 1.6 bcf $2.23 2000 $(468)
1.6 bcf 2.22 2001 (555)
3.2 bcf 2.49 2002 19
- -------------------------------------------------------------------------------
Crude Oil Options
Held .9 million barrels $20.53 2000 $(13)
.5 million barrels 18.79 2001 (7)
Written .9 million barrels $20.53 2000 $(13)
.5 million barrels 18.79 2001 (7)
7
<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)
December 31, 1998
-----------------------------------------------------
Contract Average Fair
Volumes Weighted Price Maturity Value
-------- -------------- -------- -----
Natural Gas Options
Held 6.8 bcf $1.81 1999 $ 516
6.4 bcf 1.81 2000 851
6.2 bcf 1.81 2001 532
Written 3.5 bcf $2.01 1999 $ (51)
1.6 bcf 2.23 2000 (470)
1.6 bcf 2.22 2001 (389)
8
<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 tables present the hypothetical changes in fair values of
outstanding swap agreements at December 31, 1999 and 1998 based on a 10%
favorable and adverse change in quoted market prices (amounts in thousands)
<TABLE>
<CAPTION>
December 31, 1998
---------------------------------------------------------------
Change in Fair Value Change in Fair
From 10% Adverse Value From 10% Favorable
Fair Value Price Change Price Change
---------- -------------------- -------------------------
<S> <C> <C> <C>
Natural Gas Swaps
Trading $ (279) $ (140) $ 140
Non-trading 968 $ 892 (892)
Crude Oil Swaps
Trading $ 71 $ (66) $ 73
Non-trading -- -- --
December 31, 1998
---------------------------------------------------------------
Change in Fair Value Change in Fair
From 10% Adverse Value From 10% Favorable
Fair Value Price Change Price Change
---------- -------------------- -------------------------
Natural Gas Swaps
Trading $227 $ (37) $ 37
Non-trading 968 1,900 (1,900)
Crude Oil Swaps
Trading $ 27 $ -- --
Non-trading 43 7 (7)
</TABLE>
The market prices used to calculate the fair value reflect management's best
estimate considering various factors including closing exchange and over-the-
counter quotations, time value and volatility factors at December 31, 1999 and
1998. The values are adjusted to reflect the potential impact of liquidating
the Company's position in an orderly manner over a reasonable period of time
under market conditions at December 31, 1999 and 1998.
The Company also holds certain equity securities that expose the Company to
price risk associated with equity security markets. These securities are
carried at their fair value of $1,489 at December 31, 1999. An immediate
decrease in the market prices of these securities of 10% would result in a fair
value of approximately $1,340.
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 $.53 million per year.
9
<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)
Outlook
The Company has adopted a $12.2 million capital budget for the year ending
December 31, 2000 primarily for the recompletion of certain oil and gas
properties, infill drilling to further develop acreage, 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.
Year 2000 Issues
In prior years, the Company discussed the nature and progress of its plans to
become Year 2000 ready. In late 1999, the Company completed its remediation and
testing of systems. As a result of those planning and implementation efforts,
the Company experienced no significant disruptions in mission critical
information technology and non-information technology systems and believes those
systems successfully responded to the Year 2000 date change. The Company
expensed approximately $.3 million during 1999 in connection with remediating
its systems. The Company is not aware of any material problems resulting from
Year 2000 issues, either with its products, its internal systems, or the
products and services of third parties. The Company will continue to monitor
its mission critical computer applications and those of its suppliers and
vendors throughout the year 2000 to ensure that any latent Year 2000 matters
that may arise are addressed promptly.
10
