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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
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 1-12108.
GulfWest Oil Company
(Exact name of registrant as specified in its charter)
Texas 87-0444770
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
397 N. Sam Houston Parkway East, Suite 375
Houston, Texas 77060
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (281) 820-1919.
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Class A Common Stock, par value of $.001 per share
Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class
Class A Common Stock, par value of $.001 per share
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 informational 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 voting stock of the Registrant held by
non-affiliates (excluding voting shares held by officers and directors) was
$3,124,824 on March 20, 2001.
Indicate the number of shares outstanding of each of the Registrant's
classes of common stock: Class A Common Stock $.001 par value: 18,445,041 shares
on March 20, 2001.
DOCUMENTS INCORPORATED BY REFERENCE:
The registrant's definitive Proxy Statement pertaining to the 2001 Annual
Meeting of Shareholders (the "Proxy Statement") and filed or to be filed not
later than 120 days after the end of the fiscal year pursuant to Regulation 14A
is incorporated herein by reference into Part III.
1
PART I
ITEM 1. Business.
Our Business
We are primarily engaged in the acquisition, development, exploitation
and production of crude oil and natural gas. Our focus is on increasing
production from our existing properties through further exploitation,
development and exploration, and on acquiring additional interests in crude oil
and natural gas properties.
Since we made our first significant acquisition in 1993, we have
substantially increased our ownership in producing properties and the value of
our crude oil and natural gas reserves through a combination of acquisitions and
the further exploitation and development of our properties. At December 31,
2000, our part of the estimated proved reserves these properties contain was
approximately 4.6 million barrels (MBbl) of oil and 24.8 billion cubic feet
(Bcf) of natural gas with a Present Value discounted 10% (PV-10) of $124.1
million. At present, substantially all of our properties are located on land in
Texas, Colorado and Oklahoma. In the future, we plan to expand by acquiring
additional properties in those areas, and in similar properties located in other
areas of the United States.
Our gross revenues are derived from the following sources:
1. Oil and gas sales that are proceeds from the sale of crude oil and
natural gas production to midstream purchasers;
2. Operating overhead and other income that consists of earnings from
operating crude oil and natural gas properties for other working
interest owners, and marketing and transporting natural gas. This also
includes earnings from other miscellaneous activities.
3. Well servicing revenues that are earnings from the operation of well
servicing equipment under contract to other operators.
Our operations are considered to fall within a single industry
segment, which is the acquisition, development, production and servicing of
crude oil and natural gas properties. See Item 7. " Management's Discussion
and Analysis of Financial Condition and Results of Operations." Certain
industry terms are italicized and defined in the Glossary beginning on page 27.
Our common stock is traded over-the-counter (OTC) under the symbol
"GULF".
Our Company
We were formed as a corporation under the laws of the State of Utah in
1987 as Gallup Acquisitions, Inc., and subsequently changed our name to First
Preference Fund, Inc. and then to GulfWest Energy, Inc. We became a Texas
corporation by a merger effected in July 1992, in which our name became GulfWest
Oil Company.
Our principal office is located at 397 North Sam Houston Parkway East,
Suite 375, Houston, Texas 77060 and our telephone number is (281) 820-1919.
2
GulfWest Oil Company has eight wholly owned subsidiaries, all Texas corporations
or companies:
1. GulfWest Oil & Gas Company was organized February 18, 1999 and
is the owner of record of interests in certain crude oil and
natural gas properties located in Colorado and Texas.
2. SETEX Oil and Gas Company was organized August 11, 1998 and is
the operator of crude oil and natural gas properties in which
we own the majority working interest.
3. LTW Pipeline Co. was organized April 19, 1999, is the owner
and operator of certain natural gas gathering systems
and pipelines that we own, and markets the natural gas
produced from our properties.
4. RigWest Well Service, Inc. was organized September 5, 1996
and operates well servicing equipment for us and under
contract for other operators.
5. Southeast Texas Oil and Gas Company, L.L.C. was acquired
by us on September 1, 1998 and is the owner of record of
interests in certain crude oil and natural gas properties
located in three Texas counties.
6. DutchWest Oil Company was organized July 28, 1997 and is the
owner of record of interests in certain crude oil and natural
gas properties located in Hardin and Polk Counties, Texas.
7. GulfWest Development Company was organized November 9, 2000
and is the owner of record of interests in certain crude oil
and natural gas properties located in Texas, Oklahoma and
Mississippi.
8. GulfWest Texas Company was organized September 23, 1996 and was
the owner of interests in certain crude oil and natural gas
properties located in the Vaughn Field, Crockett County, Texas.
Effective April 1, 2000, these properties were assigned to
GulfWest Oil & Gas Company to facilitate financing.
Our Business Strategy
We have pursued a business strategy of acquiring interests in crude oil
and natural gas producing properties where production and reserves can be
increased through engineering and development activities. Such activities
include workovers, development drilling, recompletions, replacement or addition
of equipment and waterflood or other secondary recovery techniques. We have
expanded our business plan to include an increased but controlled emphasis on
development drilling for additional crude oil and natural gas reserves. Key
elements of our business strategy include:
Continued Acquisition Program. We acquired six crude oil and natural
gas fields in two transactions in the year 2000. We intend to continue to
aggressively pursue interests in crude oil and natural gas properties (i) held
by small, under-capitalized operators and (ii) being divested by larger
independent and major oil and gas companies.
Development and Exploitation of Existing Properties. We intend to
increase the development of properties in which we currently own interest by
expanding our engineering and geological field studies. Our intent is to
increase crude oil and natural gas production and reserves of our existing
assets through relatively low-risk development activities, such as workovers,
recompletions, horizontal drilling from existing wellbores and infield drilling,
as well as the more efficient use of production facilities and the expansion of
existing waterflood operations.
3
Significant Operating Control. Currently, we are the operator of all
the wells in which we own working interests. This operating control enables us
to better manage the nature, timing and costs of development of such wells, and
the marketing of the resulting production.
Ownership of Workover Rigs. We currently own four workover service rigs
and one swabbing unit that we operate for our own account and under contract for
other parties. By owning and operating this equipment, we are better able to
control costs, quality of operations and availability of equipment and services.
We intend to purchase additional service rigs as needed to accommodate our
acquisition and development programs.
Greater Natural Gas Ownership. At December 31, 2000, our reserves were
comprised of 52% crude oil and 48% natural gas. We will continue to expand our
role in the domestic natural gas industry by (i) acquiring additional interests
in natural gas properties, (ii) increasing the production and reserve base of
our existing natural gas properties, and (iii) acquiring ownership of more
natural gas gathering systems and pipelines. We are presently focusing our
workover and development efforts on both crude oil and natural gas reserves to
take advantage of the higher prices of both commodities. We are also seeking to
expand our ownership of gas gathering systems and pipelines located in our main
field areas. Our goal is to have greater control of our natural gas
transportation and marketing, and an expanded role in the transportation of
natural gas produced by other parties in our area of operations.
Expanded Exploration and Exploitation Role. Historically, we have not
drilled exploratory wells due to the cost and risk associated with drilling
prospective locations. However, since the end of 1998, we have acquired
producing properties that have also included significant acreage for prospective
oil and gas exploration. These include producing wells and acreage in Kimble,
Sutton, Zavala, Refugio, Victoria, Wharton and Upshur Counties, Texas, and in
Adams, Arapaho, Elbert and Weld Counties, Colorado. These acquisitions have
added existing natural gas and crude oil production to our asset base and, as
importantly, have provided us with immediate geological databases for drilling
opportunities. We have expanded our evaluation efforts in these fields and
intend to increase our development of reserves, not only through workovers of
existing wells, but by drilling additional wells.
Our Employees
At March 20, 2001, we had 59 full time salaried and contract employees,
of whom 46 were field personnel.
Our Executive OfficersExecutive Officers
See Item 10 of this report, which information is incorporated herein by
reference.
4
ITEM 2. Our Properties.
At December 31, 2000, we owned an average 93% working interest in 304
gross wells (282 net wells). Gross wells are the total wells in which we own a
working interest. Net wells are the sum of the fractional working interests we
own in gross wells. Our part of the estimated proved reserves these properties
contain was approximately 4.6 million barrels (MBbl) of oil and 24.8 billion
cubic feet (Bcf) of natural gas. Substantially all of properties are located in
Texas, Colorado and Oklahoma.
Proved Reserves. The following table reflects our estimated proved
reserves at December 31 for each of the preceding three years.
2000 1999 1998
---- ---- ----
Crude Oil (MBbl)
Developed 2,884 1,570 770
Undeveloped 1,692 1,745 314
----- ----- -----
Total 4,576 3,315 1,084
===== ===== =====
Natural Gas (Bcf)
Developed 15,142 9,317 3,866
Undeveloped 9,670 9,870 2,789
------ ----- -----
Total 24,812 19,187 6,655
====== ====== =====
Total (MBOE) 8,711 6,513 2,193
====== ====== =====
(a) The above table does not include reserves for our interests in wells in
Louisiana, which represent less than 1% of our reserves.
(b) Approximately 62% of our total proved reserves were classified as
proved developed at December 31, 2000.
(c) Barrel of Oil Equivalent (BOE) is based on a ratio of 6,000 cubic feet
of natural gas for each barrel of oil.
5
Standardized Measure of Discounted Future Net Cash Flows.
The following table sets forth as of December 31 for each of the
preceding three years, the estimated future net cash flow from and standardized
measure of discounted future net cash flows of our proved reserves, which were
prepared in accordance with the rules and regulations of the SEC. Future net
cash flow represents future gross cash flow from the production and sale of
proved reserves, net of crude oil and natural gas production costs (including
production taxes, ad valorem taxes and operating expenses) and future
development costs. The calculations used to produce the figures in this table
are based on current cost and price factors at December 31 for each year. We
cannot assure you that the proved reserves will all be developed within the
periods used in the calculations or that prices and costs will remain constant.
2000 1999 1998
Future cash inflows $318,504,931 $119,006,567 $ 22,260,688
Future production and development costs-
Production 97,465,972 42,544,454 10,379,070
Development 13,400,359 9,903,729 2,935,160
----------- ------------ ------------
Future net cash flows before income taxes 207,638,600 66,558,384 8,946,458
Future income taxes (56,466,527) (11,847,076) ( - )
----------- ----------- -------------
Future net cash flows after income taxes 151,172,073 54,711,308 8,946,458
10% annual discount for estimated timing
of cash flows (60,790,946) (23,755,909) (3,756,850)
----------- ------------ ------------
Standardized measure of discounted
Future net cash flows(1) $ 90,381,127 $30,955,399 $ 5,189,608
============ =========== ===========
(1) The average prices of our proved reserves were $23.81 per Bbl and $8.45
per Mcf, $22.80 per Bbl and $2.19 per Mcf and $8.91 per Bbl and $1.89 per
Mcf at December 31, 2000, 1999 and 1998, respectively.
Significant Properties. Summary information on our properties with proved
reserves is set forth below as of December 31, 2000.
Productive Wells Proved Reserves (1) Present
----------------------- ------------------------- --------
Gross Net Value (2)
---------
Productive Productive Crude Natural
Wells Wells Oil Gas Total Amount
---------- ---------- ----- ------- ----- ------
(MBbl) (MMcf) (MBOE) ($M)
Texas 231 222.6 3,923 15,075 6,414 $ 88,369
Colorado 37 24.8 543 9,296 2,093 32,487
Oklahoma 34 34.0 94 441 188 3,141
Other 2 .5 16 - 16 144
---- ----- ----- ------ ----- --------
Total 304 281.9 4,576 24,812 8,711 $124,141
==== ===== ===== ====== ===== ========
(1) The above table does not include reserves for our interests in wells in
Louisiana, which represent less than 1% of our reserves.
(2) The average prices of our proved reserves were $23.81 per Bbl and $8.45
per Mcf at December 31, 2000.
6
All information set forth herein relating to our proved reserves,
estimated future net cash flows and present values is taken from reports
prepared by Pressler Petroleum Consultants, Garb, Grubs, Harris and Associates,
Cawley, Gillespie and Associates, Inc. and Nguyen Consultants, independent
petroleum engineers. The estimates of these engineers were based upon their
review of production histories and other geological, economic, ownership and
engineering data provided by and relating to us. No reports on our reserves have
been filed with any federal agency. In accordance with the SEC's guidelines, our
estimates of proved reserves and the future net revenues from which present
values are derived are made using year end crude oil and natural gas sales
prices held constant throughout the life of the properties (except to the extent
a contract specifically provides otherwise). Operating costs, development costs
and certain production-related taxes were deducted in arriving at estimated
future net revenues, but such costs do not include debt service, general and
administrative expenses and income taxes.
There are numerous uncertainties inherent in estimating crude oil and
natural gas reserves and their values, including many factors beyond our
control. The reserve data set forth in this report are based upon estimates.
Reservoir engineering is a subjective process, which involves estimating the
sizes of underground accumulations of crude oil and natural gas that cannot be
measured in an exact manner. The accuracy of any reserve estimate is a function
of the quality of available data, engineering and geological interpretation of
that data, and judgment. As a result, estimates of different engineers,
including those used by us, may vary. In addition, estimates of reserves are
subject to revision based upon actual production, results of future development,
exploitation and exploration activities, prevailing crude oil and natural gas
prices, operating costs and other factors. Such revisions may be material.
Accordingly, reserve estimates are often different from the quantities of crude
oil and natural gas that are ultimately recovered and are highly dependent upon
the accuracy of the assumptions upon which they are based. We cannot assure you
that the estimates contained in this report are accurate predictions of our
crude oil and natural gas reserves or their values. Estimates with respect to
proved reserves that may be developed and produced in the future are often based
upon volumetric calculations and upon analogy to similar types of reserves
rather than upon actual production history. Estimates based on these methods are
generally less reliable than those based on actual production history.
Subsequent evaluation of the same reserves based upon production history will
result in potentially substantial variations in the estimated reserves.
7
Production, Revenue and Price History
The following table sets forth information (associated with our proved
reserves) regarding production volumes of crude oil and natural gas, revenues
and expenses attributable to such production (all net to our interests) and
certain price and cost information for the years ended December 31, 2000, 1999
and 1998.
2000 1999 1998
---------- --------- ---------
Production
Oil (Bbl) 165,031 79,661 98,157
Natural gas (Mcf) 1,111,639 467,350 200,225
--------- ------- -------
Total (BOE) 350,304 157,553 131,528
Revenue
Oil production $4,320,943 $1,565,200 $1,358,767
Natural gas production 4,124,989 968,104 445,380
--------- ------- -------
Total $8,445,932 $2,533,304 $1,804,147
Operating Expenses $3,377,583 $1,399,710 $1,647,329
Production DataProduction Data
Average sales price
Per barrel of oil $26.18 $19.65 $13.84
Per Mcf of natural gas 3.71 2.07 2.22
Per BOE 24.11 16.08 13.71
Average expenses per BOE
Lease operating 9.64 8.88 12.52
Depreciation, depletion and
amortization 3.83 4.47 17.66
General and administrative $4.53 $12.59 $15.69
Productive Wells at December 31, 2000:
The following table shows the number of productive wells we own by
location:
Gross Net Gross Net
Oil Wells Oil Wells Gas Wells Gas Wells
--------- --------- --------- ---------
Texas 149 146.2 82 76.4
Colorado 17 10.4 20 14.4
Oklahoma 34 34.0 - -
Mississippi 1 .4 - -
Louisiana 1 .1 - -
--------- --------- --------- ---------
Total 202 191.1 102 90.8
=== ===== === ====
8
Developed Acreage at December 31, 2000
The following table shows the developed acreage that we own, by
location, which is acreage spaced or assigned to productive wells. Gross acres
are the total acres in which we own a working interest. Net acres are the sum of
the fractional working interests we own in gross acres.
Gross Acres Net Acres
----------- ---------
Texas 20,000 15,316
Colorado 5,000 2,700
Oklahoma 1,200 912
------ ------
Total 26,200 18,928
====== =======
Undeveloped Acreage at December 31, 2000
The following table shows the undeveloped acreage that we own, by
location. Undeveloped acreage is acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of crude oil and natural gas.
Gross Acres Net Acres
----------- ---------
Texas 23,940 18,625
Colorado 20,000 14,175
------ ------
Total 43,940 32,800
====== ======
Drilling Results.
We have not drilled any exploratory wells in the past three years. We
drilled six development wells in 2000, all of which are productive wells. These
include three horizontal wells drilled by sidetracking from existing wellbores
in the Madisonville Field, Texas; two new wells drilled on our Colorado acreage;
and, one well that was deepened in our Leona River Field, Texas.
We did not drill any wells in 1999. We drilled seven development wells
in 1998, including one horizontal well drilled by sidetracking an existing
wellbore in the Madisonville Field, Texas that is productive; one well drilled
in the Village Mills Field, Texas that has not been productive to date but will
be recompleted to deeper zones in 2001; and, five wells drilled in the Vaughn
Field, Texas, of which three are productive, one was converted to a water
injection well and one was plugged for mechanical reasons.
Risk Factors
Our success depends heavily upon our ability to market our crude oil and natural
gas production at favorable prices.
In recent decades, there have been both periods of worldwide
overproduction and underproduction of crude oil and natural gas, and periods of
increased and relaxed energy conservation efforts. Such conditions have resulted
in excess supply of, and reduced demand for, crude oil on a worldwide basis and
for natural gas on a domestic basis. At other times, there has been short supply
of, and increased demand for, crude oil and, to a lesser extent, natural gas.
These changes have resulted in dramatic price fluctuations.
9
The degree to which we are leveraged could possibly have important consequences
to our shareholders, including the following:
(i) Our indebtedness, acquisitions, working capital, capital expenditures
or other purposes may be impaired;
(ii) Funds available for our operations and general corporate purposes or
for capital expenditures will be reduced as a result of the dedication of a
substantial portion of our consolidated cash flow from operations to the payment
of the principal and interest on our indebtedness;
(iii) We may be more highly leveraged than certain of our competitors,
which may place us at a competitive disadvantage;
(iv) The agreements governing our long-term indebtedness and bank loans may
contain restrictive financial and operating covenants;
(v) An event of default (not cured or waived) under financial and operating
covenants contained in our debt instruments could occur and have a material
adverse effect;
(vi) Certain of the borrowings under our debt agreements have floating
rates of interest, which causes us to be vulnerable to increases in interest
rates; and,
(vii) Our substantial degree of leverage could make us more vulnerable to a
downturn in general economic conditions.
Our ability to make principal and interest payments under long-term indebtedness
and bank loans will be dependent upon our future performance, which is subject
to financial, economic and other factors, some of which are beyond our control.
We cannot assure you that our current level of operating results will
continue or improve. We believe that we will need to access capital markets in
the future in order to provide the funds necessary to repay a significant
portion of our indebtedness. We cannot assure you that any such refinancing will
be possible or that we can obtain any additional financing, particularly in view
of our anticipated high levels of debt. If no such refinancing or additional
financing were available, we could default on our debt obligations.
We were profitable for the year 2000, however we have incurred net losses in the
past and there can be no assurance that we will continue to be profitable in the
future.
Our future operating results may fluctuate significantly depending upon
a number of factors, including industry conditions, prices of crude oil and
natural gas, rates of production, timing of capital expenditures and drilling
success. These variables could have a material adverse effect on our business,
financial condition, results of operations and the market price of our common
stock.
Estimates of crude oil and natural gas reserves depend on many assumptions that
may turn our to be inaccurate.
Estimates of our proved reserves for crude oil and natural gas and the
estimated future net revenues from the production of such reserves rely upon
various assumptions, including assumptions as to crude oil and natural gas
prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds. The process of estimating crude oil and natural gas
reserves is complex and imprecise.
10
Actual future production, crude oil and natural gas prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable crude oil and natural gas reserves may vary substantially from the
estimates we obtain from reserve engineers. Any significant variance in these
assumptions could materially affect the estimated quantities and present value
of reserves we have set forth. In addition, our proved reserves may be subject
to downward or upward revision due to factors that are beyond our control, such
as production history, results of future exploration and development, prevailing
crude oil and natural gas prices and other factors.
Approximately 38% of our total estimated proved reserves at December 31, 2000
were proved undeveloped reserves, which are by their nature less certain.
Recovery of such reserves requires significant capital expenditures and
successful drilling operations. The reserve data set forth in the reserve
engineer reports assumes that substantial capital expenditures are required to
develop such reserves. Although cost and reserve estimates attributable to our
crude oil and natural gas reserves have been prepared in accordance with
industry standards, we cannot be sure that the estimated costs are accurate,
that development will occur as scheduled or that the results of such development
will be as estimated.
You should not interpret the present value referred to in this report or
documents incorporated herein by reference as the current market value of our
estimated crude oil and natural gas reserves.
In accordance with SEC requirements, the estimated discounted future
net cash flows from proved reserves are generally based on prices and costs as
of the date of the estimate. Actual future prices and costs may be materially
higher or lower.
The estimates of our proved reserves and the future net revenues from
which the present value of our properties is derived were calculated based on
the actual prices of our various properties on a property-by-property basis at
December 31, 2000. The average prices of all properties were $23.81 per barrel
of oil and $8.45 per thousand cubic feet (Mcf) of natural gas at that date.
Actual future net cash flows will also be affected by increases or
decreases in consumption by crude oil and natural gas purchasers and changes in
governmental regulations or taxation. The timing of both the production and the
incurring of expenses in connection with the development and production of crude
oil and natural gas properties affect the timing of actual future net cash flows
from proved reserves. In addition, the 10% discount factor, which is required by
the SEC to be used in calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor. The effective
interest rate at various times and the risks associated with our business or the
oil and gas industry in general will affect the accuracy of the 10% discount
factor.
Except to the extent that we acquire properties containing proved reserves or
conduct successful development or exploitation activities, our proved reserves
will decline as they are produced.
In general, the volume of production from crude oil and natural gas
properties declines as reserves are depleted. Our future crude oil and natural
gas production is highly dependent upon our success in finding or acquiring
additional reserves.
11
The business of acquiring, enhancing or developing reserves requires
considerable capital.
Our ability to make the necessary capital investment to maintain or
expand our asset base of crude oil and natural gas reserves could be impaired to
the extent that cash flow from operations is reduced and external sources of
capital become limited or unavailable. In addition, we cannot be sure that our
future acquisition and development activities will result in additional proved
reserves or that we will be able to drill productive wells at acceptable costs.
Crude oil and natural gas drilling and production activities are subject to
numerous risks, many of which are beyond our control.
These risks include (i) the possibility that no commercially productive
oil or gas reservoirs will be encountered; and, (ii) that operations may be
curtailed, delayed or canceled due to title problems, weather conditions,
governmental requirements, mechanical difficulties, or delays in the delivery of
drilling rigs and other equipment that may limit our ability to develop, produce
and market our reserves. We cannot assure you that new wells we drill will be
productive or that we will recover all or any portion of our investment in such
new wells.
Drilling for crude oil and natural gas may not be profitable.
Any wells that we drill may be dry wells or wells that are not
sufficiently productive to be profitable after drilling. Such wells will have a
negative impact on our profitability. In addition, our properties may be
susceptible to drainage from production by other operators on adjacent
properties.
Our industry experiences numerous operating risks that could cause us to suffer
substantial losses.
Such risks include fire, explosions, blowouts, pipe failure and
environmental hazards, such as oil spills, natural gas leaks, ruptures or
discharges of toxic gases. We could also suffer losses due to personnel injury
or loss of life; severe damage to or destruction of property; or environmental
damage that could result in clean-up responsibilities, regulatory investigation,
penalties or suspension of our operations. In accordance with customary industry
practice, we maintain insurance policies against some, but not all, of the risks
described above. Our insurance policies may not adequately protect us against
loss or liability. There is no guarantee that insurance policies that protect us
against the many risks we face will continue to be available at justifiable
premium levels.
As owners and operators of crude oil and natural gas properties, we may
be liable under federal, state and local environmental regulations for
activities involving water pollution, hazardous waste transport, storage,
disposal or other activities.
Our past growth has been attributable to acquisitions of producing crude oil and
natural gas properties with proved reserves. There are risks involved with such
acquisitions.
The successful acquisition of properties requires an assessment of
recoverable reserves, future crude oil and natural gas prices, operating costs,
potential environmental and other liabilities, and other factors beyond our
control. Such assessments are necessarily inexact and their accuracy uncertain.
In connection with such an assessment, we perform a review of the subject
properties that we believe to be generally consistent with industry practices.
Such a review, however, will not reveal all existing or potential problems, nor
will it permit us, as the buyer, to become sufficiently familiar with the
properties to fully assess their capabilities or deficiencies. We may not
inspect every well and, even when an inspection is undertaken, structural and
environmental problems may not necessarily be observable.
12
When we acquire properties, in most cases, we are not entitled to contractual
indemnification for pre-closing liabilities, including environmental
liabilities.
We generally acquire interests in properties on an "as is" basis with
limited remedies for breaches of representations and warranties. In those
circumstances in which we have contractual indemnification rights for
pre-closing liabilities, we cannot assure you that the seller will be able to
fulfill its contractual obligations. In addition, the competition to acquire
producing crude oil and natural gas properties is intense and many of our larger
competitors have financial and other resources substantially greater than ours.
We cannot assure you that we will be able to acquire producing crude oil and
natural gas properties that have economically recoverable reserves for
acceptable prices.
We may acquire royalty, overriding royalty or working interests in properties
that are less than the controlling interest.
In such cases, it is likely that we will not operate, nor control the
decisions affecting the operations, of such properties. We intend to limit such
acquisitions to properties operated by competent parties with whom we have
discussed their plans for operation of the properties.
We will need additional financing in the future to continue to fund our
developmental and exploitation activities.
We have made and will continue to make substantial capital expenditures
in our exploitation and development projects. We intend to finance these capital
expenditures with cash flow from operations, existing financing arrangements or
new financing. We cannot assure you that such additional financing will be
available. If it is not available, our development and exploitation activities
may have to be curtailed, which could adversely affect our business, financial
condition and results of operations.
The marketing of our natural gas production depends, in part, upon the
availability, proximity and capacity of natural gas gathering systems, pipelines
and processing facilities.
We could be adversely affected by changes in existing arrangements with
transporters of our natural gas since we do not own most of the gathering
systems and pipelines through which our natural gas is delivered to purchasers.
Our ability to produce and market our natural gas could also be adversely
affected by federal, state and local regulation of production and
transportation.
The crude oil and natural gas industry is highly competitive in all of its
phases.
Competition is particularly intense with respect to the acquisition of
desirable producing properties, the acquisition of crude oil and natural gas
prospects suitable for enhanced production efforts, and the hiring of
experienced personnel. Our competitors in crude oil and natural gas acquisition,
development, and production include the major oil companies, in addition to
numerous independent crude oil and natural gas companies, individual proprietors
and drilling programs.
Many of these competitors possess and employ financial and personnel
resources substantially in excess of those which are available to us and may,
therefore, be able to pay more for desirable producing properties and prospects
and to define, evaluate, bid for, and purchase a greater number of producing
properties and prospects than our financial or personnel resources will permit.
Our ability to generate reserves in the future will be dependent on our ability
to select and acquire suitable producing properties and prospects while
competing with these companies.
13
The domestic oil industry is extensively regulated at both the federal and state
levels. Although we believe we are presently in compliance with all laws, rules
and regulations, we cannot assure you that changes in such laws, rules or
regulations, or the interpretation thereof, will not have a material adverse
effect on our financial condition or the results of our operations.
Legislation affecting the oil and gas industry is under constant review
for amendment or expansion, frequently increasing the regulatory burden on the
industry. There are numerous federal and state agencies authorized to issue
rules and regulations affecting the oil and gas industry. These rules and
regulations are often difficult and costly to comply with and carry substantial
penalties for noncompliance.
State statutes and regulations require permits for drilling operations,
drilling bonds, and reports concerning operations. Most states also have
statutes and regulations governing conservation matters, including the
unitization or pooling of properties, and the establishment of maximum rates of
production from wells. Some states have also enacted statutes prescribing price
ceilings for natural gas sold within their states.
Our industry is also subject to numerous laws and regulations governing
plugging and abandonment of wells, discharge of materials into the environment
and other matters relating to environmental protection. The heavy regulatory
burden on the oil and gas industry increases the costs of our doing business as
an oil and gas company, consequently affecting our profitability.
Our board of directors is authorized, without further shareholder action, to
issue preferred stock in one or more series and to designate the dividend rate,
voting rights and other rights, preferences and restrictions of each such
series.
As of March 20, 2001, we had a total of 8,000 shares of convertible
preferred stock issued and outstanding, all in our Series D Preferred Stock, par
value $.01 and liquidation value $500 per share. The Series D Preferred Stock is
senior to our common stock regarding liquidation. The holders of the preferred
stock do not have voting rights or preemptive rights, nor are they entitled to
receive dividends or to the benefits of any retirement or sinking fund.
The Series D Preferred Stock is not redeemable, however it is
convertible to Common Stock at anytime following the third anniversary of the
date of issuance, December 31, 1999. Thereafter, the holder may convert any or
all of the shares of the Series D Preferred Stock to Common Stock. The total
number of shares of Common Stock to be issued upon such conversion shall be
500,000.
We do not pay dividends on our common stock.
Our board of directors presently intends to retain all of our earnings
for the expansion of our business, therefore we do not anticipate distributing
cash dividends on our common stock in the foreseeable future. Any decision of
our board of directors to pay cash dividends will depend upon our earnings,
financial position, cash requirements and other factors.
The holders of our common stock do not have cumulative voting rights, preemptive
rights or rights to convert their common stock to other securities.
We are authorized to issue 40,000,000 shares of common stock, $.001 par
value per share. As of March 20, 2001, there were 18,445,041 shares of common
stock issued and outstanding. Since the holders of our common stock do not have
cumulative voting rights, the holder(s) of a majority of the shares of common
stock present, in person or by proxy, will be able to elect all of the members
of our board of directors. The holders of shares of our common stock do not have
preemptive rights or rights to convert their common stock into other securities.
At March 20, 2001, we had outstanding warrants and options for the purchase of
14
2,315,254 shares of common stock at prices ranging from $.75 to $6.00 per share,
including employee stock options to purchase 923,000 shares at prices ranging
from $.75 to $3.00 per share. If we issue additional shares, the existing
shareholders' percentage ownership of the Company may be further diluted.
Actual Results May Differ From Forward-Looking Statements
We make forward-looking statements throughout this report. Whenever you
read a statement that is not simply a statement of historical fact, such as when
we describe what we "believe," "expect" or "anticipate" will occur, and other
similar statements, you must remember that our expectations may not be correct,
even though we believe they are reasonable. These forward-looking statements
generally relate to our plans and objectives for future operations and are based
upon our management's reasonable estimates of future results and trends. We do
not guarantee that the transactions and events described will happen as
described (or that they will happen at all). In connection with forward-looking
statements, you should carefully review the factors set forth in this report
under "Risk Factors."
ITEM 3. Legal Proceedings.
General. From time to time, we are involved in litigation relating to
claims arising out of our operations or from disputes with vendors in the normal
course of business. As of March 20, 2000, we were not engaged in any legal
proceedings that are expected, individually or in the aggregate, to have a
material adverse effect on us.
ITEM 4. Submission of Matters to a Vote of Security Holders
We did not submit any matters to a vote of our security holders during
the fourth quarter of the fiscal year ended December 31, 2000.
15
PART II
ITEM 5. Market for Our Common Stock and Related Stockholder Matters.
Our common stock is traded over-the-counter under the symbol "GULF".
The high and low trading prices for the common stock for each quarter in 1998,
1999 and 2000 are set forth below. The trading prices represent prices between
dealers, without retail mark-ups, mark-downs, or commissions, and may not
necessarily represent actual transactions.
High Low
---- ---
1998
----
First Quarter 2.63 1.88
Second Quarter 2.25 1.50
Third Quarter 2.00 .88
Fourth Quarter 1.06 .50
1999
----
First Quarter 2.63 1.88
Second Quarter 1.00 .38
Third Quarter .75 .38
Fourth Quarter .94 .63
2000
----
First Quarter 1.81 .75
Second Quarter 2.00 1.25
Third Quarter 1.63 1.13
Fourth Quarter 1.69 .88
We are authorized to issue 40,000,000 shares of Class A common stock,
par value $.001 per share (the "common stock"). As of March 20, 2001, there were
18,445,041 shares of Class A common stock issued and outstanding and held by
approximately 580 beneficial owners. Our common stock is traded over-the-counter
(OTC) under the symbol "GULF". Fidelity Transfer Company, 1800 South West
Temple, Suite 301, Box 53, Salt Lake City, Utah 84115, (801) 484-7222 is the
transfer agent for the common stock.
Holders of common stock are entitled, among other things, to one vote
per share on each matter submitted to a vote of shareholders and, in the event
of liquidation, to share ratably in the distribution of assets remaining after
payment of liabilities (including preferential distribution and dividend rights
of holders of preferred stock). Holders of common stock have no cumulative
rights, and, accordingly, the holders of a majority of the outstanding shares of
the common stock have the ability to elect all of the directors.
Holders of common stock have no preemptive or other rights to subscribe
for shares. Holders of common stock are entitled to such dividends as may be
declared by the Board out of funds legally available therefore. We have never
paid cash dividends on the common stock and do not anticipate paying any cash
dividends in the foreseeable future.
Preferred Stock
Our board of directors is authorized, without further shareholder
action, to issue preferred stock in one or more series and to designate the
16
dividend rate, voting rights and other rights, preferences and restrictions of
each such series. As of March 20, 2001, we had a total of 8,000 shares of
preferred stock issued and outstanding, all in our Series D Preferred Stock.
The Series D Preferred Stock, par value $.01 and liquidation value
$500 per share, is equal in preference and senior to our common stock regarding
liquidation. The holders of the Series D Preferred Stock have no voting rights,
preemptive rights nor are they entitled to the benefits of any retirement or
sinking fund. The Series D Preferred Stock is not entitled to dividends, nor is
it redeemable. It is convertible to Common Stock at anytime following the third
anniversary of the date of issuance, which was December 31, 1999. The total
number of shares of Common Stock to be issued upon such conversion shall be
500,000.
Outstanding Options and Warrants
At March 20, 2001, we had outstanding warrants and options for the
purchase of 2,315,254 shares of common stock at prices ranging from $.75 to
$6.00 per share, including employee stock options to purchase 923,000 shares at
prices ranging from $.75 to $3.00 per share.
Recent Sales of Unregistered Securities
During 2000, we sold and issued the following shares of common stock in
private offerings not registered under the Securities Act of 1933, as amended,
and exempt under Section 4(2) of the Act. All the purchasers were current
officers, directors or accredited investors not affiliated with the company. No
underwriters were used, and no underwriting discounts or commissions were paid
in any of the sales.
Date Purchaser Amount Consideration
3/30/00 Director 500,000 $750,000 debt conversion
4/20/00 Property Sellers 200,000 Exchange for oil and gas properties
5/18/00 Accredited Investors 200,000 $150,000 debt conversion
6/06/00 Accredited Investor 400,000 $300,000 cash
6/08/00 Officers 10,504 $7,878 cash
6/13/00 Accredited Investor 6,000 $4,500 debt conversion
6/19/00 Accredited Investor 133,333 $100,000 debt conversion
6/22/00 Accredited Investor 200,000 $150,000 cash
8/23/00 Accredited Investor 200,000 $150,000 cash
9/01/00 Accredited Investor 100,000 $75,000 debt conversion
9/07/00 Accredited Investor 60,000 $45,000 debt conversion
9/25/00 Accredited Investor 200,000 $150,000 cash
We also granted warrants or options exercisable for shares of common
stock not registered under the Securities Act of 1933, as amended, and exempt
under Section 4(2) of the Act. All the grantees were current employees or
accredited investors not affiliated with the company. No underwriters were used,
and no underwriting discounts or commissions were paid in connection with the
grants.
Exercisable Exercise
Date Grantee(s) Shares Price Consideration
1/06/00 Employees 150,000 $ .875 Compensation
1/03/00 Accredited Investor 10,000 $ .75 Loan transaction
3/03/00 Accredited Investor 10,000 $ .75 Loan transaction
8/16/00 Employees 106,000 $ 1.20 Compensation
10/17/00 Employee 100,000 $ 1.13 Compensation
17
ITEM 6. Selected Financial Data.
The following table sets forth selected historical financial data of
our company as of December 31, 2000, 1999, 1998, 1997 and 1996, and for each of
the periods then ended. See "Item 1. Business" and "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations." The
income statement data for the years ended December 31, 2000, 1999 and 1998 and
the balance sheet data at December 31, 2000 and 1999 are derived from our
audited financial statements contained elsewhere herein. The income statement
data for the years ended December 31, 1997 and 1996and the balance sheet data at
December 31, 1998, 1997 and 1996 are derived from our Annual Report on Form 10-K
for those periods. You should read this data in conjunction with our
consolidated financial statements and the notes thereto included elsewhere
herein.
Year Ended December 31,
------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Income Statement Data
- ---------------------
Operating Revenues $ 8,984,175 $ 2,812,639 $ 2,403,553 $ 4,960,966 $ 1,966,012
Net income (loss) from
operations 2,464,017 (1,464,094) (6,329,884) (598,320) (485,588)
Net income (loss) 352,774 (2,269,506) (8,387,060) (1,676,681) (1,519,764)
Dividends on preferred stock - (450,684) (427,173) (380,928) (1,363,677)
Net income (loss) available to
Common Shareholders 352,774 (2,720,190) (8,814,233) (2,057,609) (2,883,441)
Net income (loss), per share
of common stock $ .02 $ (.34) $ (3.68) $ (1.19) $ (2.28)
Weighted average number of
shares of common stock
outstanding 17,293,848 7,953,147 2,394,866 1,725,926 1,266,974
Balance Sheet Data
- ------------------
Current assets $ 2,934,804 $ 1,357,465 $ 820,984 $ 1,536,396 $ 699,259
Total assets 32,374,128 20,009,793 8,058,827 17,089,855 15,046,765
Current liabilities 7,594,986 4,650,691 6,559,393 2,879,256 2,877,290
Long-term obligations 18,077,371 11,304,318 3,401,371 12,185,055 8,877,941
Stockholders' Equity
(Deficit) 6,701,771 4,054,784 (1,901,937) 2,025,544 3,291,534
18
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Overview
We are engaged primarily in the acquisition, development, exploitation,
exploration and production of crude oil and natural gas. Our focus is on
increasing production from our existing crude oil and natural gas properties
through the further exploitation, development and exploration of those
properties, and on acquiring additional interests in crude oil and natural gas
properties. Our gross revenues are derived from the following sources:
1. Oil and gas sales that are proceeds from the sale of crude oil and
natural gas production to midstream purchasers;
2. Operating overhead and other income that consists of earnings from
operating crude oil and natural gas properties for other working
interest owners, and marketing and transporting natural gas. This also
includes earnings from other miscellaneous activities.
3. Well servicing revenues that are earnings from the operation of well
servicing equipment under contract to other operators.
The following is a discussion of our consolidated financial condition,
results of operations, liquidity and capital resources. You should read this
discussion in conjunction with the Consolidated Financial Statements of the
Company and the Notes thereto contained elsewhere herein. See "Financial
Statements."
Results of Operations
The factors which most significantly affect our results of operations
are (1) the sales price of crude oil and natural gas, (2) the level of total
sales volumes of crude oil and natural gas, (3) the level of and interest rates
on borrowings and, (4) the level and success of new acquisitions and development
of existing properties.
Comparative results of operations for the periods indicated are
discussed below.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Revenues
Oil and Gas Sales. Our operating revenues from the sale of crude oil
and natural gas increased by 233% from $2,533,000 in 1999 to $8,446,000 in 2000,
due to increased oil and gas production from development projects, higher oil
and gas prices, and acquisitions of additional properties.
Well Servicing Revenues. Revenues from our well servicing operations
increased by 61% from $117,000 in 1999 to $188,000 in 2000. This increase was
due to higher rig utilization on operated properties where the Company has
working interest partners and increased work for third parties.
Operating Overhead and Other Income. Revenues from these activities
increased 115% from $163,000 in 1999 to $350,000 in 2000. Major components of
the change included a decrease of $38,000 in revenues we received for operating
properties for other parties (due to our acquiring additional working interests
in the operated properties); an increase of $117,000 in natural gas marketing
and transportation; $52,000 received in damages from a drilling contractor; and,
$20,000 received for the assignment of certain deep drilling rights on one of
our leases.
19
Costs and Expenses
Lease Operating Expenses. Lease operating expenses increased 141% from
$1,400,000 in 1999 to $3,378,000 in 2000. This increase in operating expenses
was due to the acquisitions of additional properties, expanded oil and gas
production, and the costs related to such production.
Cost of Well Servicing Operations. Well servicing expenses increased
12% from $190,000 in 1999 to $212,000 in 2000. This increase in expenses was due
to higher utilization of our equipment under contract to third parties.
Depreciation, Depletion and Amortization (DD&A). DD&A increased 91%
from $704,000 in 1999 to $1,342,000 in 2000, due to significantly higher
production resulting from successful field development activities and
acquisitions.
General and Administrative (G&A) Expenses. G&A expenses decreased 20%
from $1,983,000 for 1999 to $1,588,000 in 2000. The Company had non-recurring
expenses consisting of costs associated with the consolidation of its offices to
Houston and non-cash charges of $232,000 related to the issuance of stocks and
warrants in 1999 compared to $2,000 in 2000.
Interest Expense and Dividends on Preferred Stock. Interest expense
increased 140% from $890,000 in 1999 to $2,135,000 in 2000 due to increased debt
associated with additional acquisitions and our capital development program, and
higher borrowing rates.
Preferred dividends decreased $451,000 from year-end 1999, since all of
the preferred stock entitled to receive dividends had been converted to common
stock.
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
Revenues
Oil and Gas Sales. Operating revenues from the sale of crude oil and
natural gas increased by 40% from $1,804,000 in 1998 to $2,533,000 in 1999. This
was due to increased crude oil and natural gas production, and higher crude oil
and natural gas prices.
Well Servicing Revenues. Revenues from well servicing operations
decreased by 73% from $432,000 in 1998 to $117,000 in 1999. This decrease was
due to fewer rig utilization contracts with third parties as a result of
significantly lower industry activity.
Operating Overhead Revenues. Revenues from the operating of properties
decreased 2% from $167,000 in 1998 to $163,000 in 1999. This decrease was due to
the fact that we operated fewer wells for other working interest owners.
Costs and Expenses
Lease Operating Expenses. Lease operating expenses decreased 15% from
$1,647,000 in 1998 to $1,400,000 in 1999. This decrease in operating expenses
was due to the sale of GulfWest Permian assets, effective October 1, 1998, and
the overall reduction in operating expenses.
Cost of Well Servicing Operations. Well servicing expenses decreased
55% from $421,000 in 1998 to $190,000 in 1999. This decrease in expenses was due
to the reduced utilization of our equipment under contract to third parties.
20
Impairment of Assets. Impairment of assets decreased to $0 in 1999 from
$2,279,000 in 1998. The decrease was due to our not being required to write down
the carrying values of crude oil and natural gas properties (whose future
estimated undiscounted net cash inflows are less than such carrying value) to
fair value. An impairment of assets write-down is a charge to earnings, which
does not impact cash flow from operating activities. However, such write-downs
do impact the amount of our stockholders' equity. The risk that we will be
required to write down the carrying value of our crude oil and natural gas
reserves increases when crude oil and natural gas prices are depressed or
volatile as they were at December 31, 1998. No assurance can be given that we
will not experience additional write-downs in the future if commodity prices
decline.
General and Administrative (G&A) Expenses. G&A expenses decreased 4%
from $2,064,000 for the year ended December 31, 1998 to $1,983,000 for the year
ended December 31, 1999, as a result of a consolidation of offices to Houston,
Texas. This reduction was achieved despite the cost of relocating the office and
our staff from Dallas, Texas and Baton Rouge, Louisiana to Houston, Texas.
Depreciation, Depletion and Amortization (DD&A). DD&A decreased 70%
from $2,322,000 in 1998 to $704,000 in 1999. The decrease was due to the
significant write-down of the crude oil and natural gas property book values in
1998 and the increased reserves booked in 1999.
Interest Expense and Dividends on Preferred Stock. Interest expense
decreased 32% from $1,303,000 in 1998 to $890,000 in 1999. This decrease was due
to the sale of our subsidiary, GulfWest Permian Company, in 1998 and the
resulting significant debt reduction. Preferred dividends increased $19,000 due
to the increase in the amount of preferred stock issued; however, by year-end
1999, the majority of the preferred stock had been converted to common stock.
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997
Revenues
Oil and Gas Sales. During the period ended December 31, 1998, operating
revenues from the sale of crude oil and natural gas decreased by 58% from
$4,269,000 in 1997 to $1,804,000 in 1998. This decrease was primarily
attributable to a decline in commodity prices and, to a lesser extent, the sale
of GulfWest Permian and its oil assets, effective October 1, 1998.
Well Servicing Revenues. Earnings from well servicing operations
decreased by 10% from $482,000 in 1997 to $432,000 in 1998. This decrease was
due to fewer rig utilization contracts with third parties as a result of the
decline in commodity prices.
Operating Overhead Revenues. Revenues from the operating of
properties increased 22% from $137,000 in 1997 to $167,000 in 1998. This
increase was due to the acquisition of Setex LLC,which generates overhead fees
through the management of a oil and gas limited partnership.
Costs and Expenses
Lease Operating Expenses. Lease operating expenses decreased 23% from
$2,139,000 in 1997 to $1,647,000 in 1998. This decrease in operating expenses
was primarily due to our management's decision to shut-in a number of crude oil
wells because of the lower oil prices in 1998 and the sale of GulfWest Permian.
Cost of Well Servicing Operations. Well servicing expenses increased
51% from $279,000 in 1997 to $421,000 in 1998. This increase in expenses was due
to the reduced utilization of our equipment under contract to third parties. We
incurred additional expenses to secure the rigs in order to protect our
investment.
21
Impairment of Assets. Impairment of assets increased to $2,279,000 in
1998 from -0- in 1997. The increase was due to our requirement to write down the
carrying values of crude oil and natural gas properties (whose future estimated
undiscounted net cash inflows are less than such carrying value) to fair value.
An impairment of assets write down is a charge to earnings, which does not
impact cash flow from operating activities. However, such write downs do impact
the amount of our stockholders' equity. The risk that we will be required to
write down the carrying value of our crude oil and natural gas reserves
increases when crude oil and natural gas prices are depressed or volatile as we
experienced at December 31, 1998. No assurance can be given that we will not
experience additional write downs in the future should commodity prices decline.
General and Administrative (G&A) Expenses. G&A expenses increased 40%
from $1,478,000 for the year ended December 31, 1997 to $2,064,000 for the year
ended December 31, 1998, as a result of our unsuccessful attempts to close two
equity offerings.
Depreciation, Depletion and Amortization (DD&A). DD&A increased 43%
from $1,625,000 in 1997 to $2,322,000 in 1998. The increase was due primarily to
lower oil prices, which caused depletion to accelerate.
Interest Expense and Dividends on Preferred Stock. Interest expense
increased 20% from $1,087,000 in 1997 to $1,303,000 in 1998. This increase was
due to the borrowing of funds needed for operating capital. Preferred dividends
increased $46,000 due to the issuance of warrants with the preferred stock in
conjunction with the purchase of Setex LLC, and additional dividends due the
Class AAA preferred stockholders under a penalty provision. In a subsequent
event, on July 7, 1999, the Class AAA preferred stockholders agreed to convert
their preferred stock to common stock at a rate based upon the purchase price
per share ($500), plus accrued and unpaid dividends, divided by $.90 per share
of common stock.
Financial Condition and Capital Resources
At December 31, 2000, our current liabilities exceeded our current
assets by $4,660,182. We had a profit of $352,774 compared to a loss of
$2,269,506 at December 31, 1999. The profit in the year 2000 can be attributed
to increased production from development projects and additional acquisitions,
and more favorable crude oil and natural gas prices, as the table on the
following page illustrates.
On April 5, 2000, we entered into an agreement with Aquila Energy
Capital, an energy lender, to provide $19,302,000 in financing, of which
$13,302,000, less closing costs of $402,000, was funded at closing and
$6,000,000 was for future development capital. We used the net proceeds to (i)
retire existing debt, including accrued interest of $10,234,977; (ii) acquire
crude oil and natural gas properties in Zavala County, Texas for $2,300,000,
including $3,266 in cash and 200,000 shares of common stock; and, (iii) acquire
additional interests in the Madisonville Field, Texas. The loan is secured by
substantially all of the Company's interests in oil and gas properties, bears
interest at prime plus 3.5% and matures May 29, 2004. Monthly payments as to
principal and interest are from an 85% net revenue interest in the secured
properties. The lender retains a 7% overriding royalty interest with payments
commencing after the loan is paid in full.
The development capital included in the Aquila financing was designated
for projects to increase production on our existing properties, as identified by
us and approved by the lender. We used approximately $3,400,000 for such
projects in the year 2000 and will continue our development plans in 2001 with
the remaining $2,600,000. We will also continue to identify and evaluate
opportunities for growth through acquisitions. We believe our profits will
increase in the future; however adverse changes in the prices of crude oil and
natural gas would have a severe impact on our plans.
22
Inflation and Changes in Prices
While the general level of inflation affects certain costs associated with
the petroleum industry, factors unique to the industry result in independent
price fluctuations. Such price changes have had, and will continue to have a
material effect on our operations; however, we cannot predict these
fluctuations. The following table indicates the average crude oil and natural
gas prices received over the last three years by quarter. Average prices per
barrel of oil equivalent, computed by converting natural gas production to crude
oil equivalents at the rate of 6 Mcf per barrel, indicate the composite impact
of changes in crude oil and natural gas prices.
Average Prices
--------------------------------
Crude Oil Per
and Natural Equivalent
Liquids Gas Barrel
--------- ------- ----------
(per Bbl) (Per Mcf)
1998
First $13.51 $1.75 $13.00
Second 11.13 2.05 11.33
Third 13.05 1.78 12.62
Fourth 9.92 2.25 12.36
1999
First $ 9.72 $1.63 $ 9.84
Second 14.28 2.17 13.71
Third 19.77 2.77 18.52
Fourth 20.27 2.71 18.64
2000
First $26.06 $2.73 $21.23
Second 25.14 3.19 21.89
Third 25.79 3.90 24.42
Fourth 27.38 4.68 27.74
ITEM 8. Financial Statements and Supplementary Data.
Information with respect to this Item 8 is contained in our financial
statements beginning on Page F-1 of this Annual Report.
ITEM 9. Changes In and Disagreements With Accountants and Accounting and
Financial Disclosure.
None
23
PART III
ITEM 10. Directors and Executive Officers of the Registrant.
The following table sets forth information on our directors and executive
officers:
Year First Elected
Name Age Position Director or Officer
Marshall A. Smith III(3) 53 Chairman of the Board 1989
Thomas R. Kaetzer(3) 42 Chief Executive Officer 1998
President and Director
Jim C. Bigham 65 Executive Vice President, 1991
Secretary and Director
Richard L. Creel 52 Vice President of Finance 1998
and Controller
William T. Winston 34 Vice President 2000
John E. Loehr(1)(2)(3) 55 Director 1992
Anthony P. Towell(1)(2)(3) 69 Director 1997
J. Virgil Waggoner(1)(2)(3) 73 Director 1997
Steven M. Morris(1) 49 Director 2000
(1) Member of the Audit Committee.
(2) Member of the Compensation Committee.
(3) Member of the Executive Committee.
Marshall A. Smith III has served as an officer and a director of
GulfWest since July 1989. From July 1989 to November 20, 1992, he served as
president and chairman of the Board. On November 20, 1992, he resigned as
president but continued as chief executive officer and chairman of the board. On
September 1, 1993, Mr. Smith reassumed the duties of president and resigned as
chairman of the board. On December 21, 1998, he resigned as president but
remained chief executive officer. On March 20, 2001, he resigned as chief
executive officer and was elected chairman of the board.
Thomas R. Kaetzer was appointed senior vice president and chief
operating officer of GulfWest on September 15, 1998 and on December 21, 1998
became president and a director. On March 20, 2001, he was appointed chief
executive officer. Mr. Kaetzer has 17 years experience in the oil and gas
industry, including 14 years with Texaco Inc., which involved the evaluation,
exploitation and management of oil and gas assets. He has both onshore and
offshore experience in operations and production management, asset acquisition,
development, drilling and workovers in the continental U.S., Gulf of Mexico,
North Sea, Colombia, Saudi Arabia, China and West Africa. Mr. Kaetzer has a
Masters Degree in Petroleum Engineering from Tulane University and a Bachelor of
Science Degree in Civil Engineering from the University of Illinois.
24
Jim C. Bigham has served as executive vice president of GulfWest since
1996 and as secretary and a director since 1991. Prior to joining GulfWest, he
held management and sales positions in the real estate and printing industries.
Mr. Bigham is also a retired United States Air Force Major. During his military
career, he served in both command and staff officer positions in the
operational, intelligence and planning areas.
Richard L. Creel has served as controller of GulfWest since May 1, 1997
and was elected vice president of finance on May 28, 1998. Prior to joining
GulfWest, Mr. Creel served as Branch Manager of the Nashville, Tennessee office
of Management Reports and Services, Inc. He has also served as controller of TLO
Energy Corp. He has extensive experience in general accounting, petroleum
accounting, and financial consulting and income tax preparation.
William T. Winston joined GulfWest in April 1999 and was appointed vice
president in May 2000. He is responsible for business development, including
identifying and evaluating pipeline and gathering system acquisitions, and
assisting in the evaluation for production acquisitions. Before joining
GulfWest, Mr. Winston was in charge of field operations and project planning for
Eagle Natural Gas Co., a privately held natural gas gathering company based in
Houston. He served six years in the United States Army and Texas National Guard
and holds a Bachelor of Arts Degree in Government from the University of Texas
at Austin.
John E. Loehr has served as a director of GulfWest since 1992, as
chairman of the board from September 1, 1993 to July 8, 1998 and as chief
financial officer from November 22, 1996 to May 28, 1998. He is also currently
president and sole shareholder of ST Advisory Corporation, an investment
company, and vice-president of Star-Tex Trading Company, also an investment
company. He was formerly president of Star-Tex Asset Management, a
commodity-trading advisor, and a position he held from 1988 until 1992 when he
sold his ownership interest. Mr. Loehr is a CPA and is a member of the American
Institute of Certified Public Accountants and Texas Society of Certified Public
Accountants.
Anthony P. Towell has served as a director of GulfWest since November
13, 1997. From July 1998 to March 2001 he served as chairman of the board. Mr.
Towell is a director of a number of public companies, both in the United Kingdom
and the United States, in the safety, environmental and computer network
industries. Mr. Towell has been in the petroleum business since 1957 and has
held executive positions with various public oil and gas companies including the
Royal Dutch Shell group companies and Pacific Resources, Inc.
J. Virgil Waggoner has served as a director of GulfWest since December
1, 1997. Mr. Waggoner's career in the petrochemical industry began in 1950 and
included senior management positions with Monsanto Company and El Paso Products
Company, the petrochemical and plastics unit of El Paso Company. He served as
president and chief executive officer of Sterling Chemicals, Inc. from the
firm's inception in 1986 until its sale and his retirement in 1996. He is
currently president and chief executive officer of JVW Investments, Ltd., a
private company. He continues to serve as non-executive vice chairman of the
Board of Directors of Sterling Chemicals, Inc. He is also on the Board of
Directors of Kirby Corporation and an advisory board director of First
Commercial Bank of Little Rock, Arkansas.
Steven M. Morris was appointed a director of GulfWest on January 6, 2000.
He was the president of Pozo Resources, Inc., an oil and gas production company,
until its asset were sold to GulfWest on December 31, 1999. Mr. Morris is a
certified public accountant and president of Pentad Enterprises, Inc., a private
investment firm in Houston, Texas. He is currently a director of the Bank of
Tanglewood, Houston, Texas, and Quicksilver Resources, Inc., a publicly traded
oil and gas exploration and production company with offices in Ft. Worth, Texas.
Our directors are elected annually and hold office until the next annual
meeting of shareholders and until their successors are duly elected and
qualified. The board of directors met five times during the calendar year ended
December 31, 2000.
25
Committees of the Board of Directors
Our board of directors has established an audit committee, a compensation
committee and an executive committee. The functions of these committees, their
current members, and the number of meetings held during 2000 are described
below.
The audit committee was established to review and appraise the audit
efforts of our independent auditors, and monitor the company's accounts,
procedures and internal controls. The committee is comprised of Mr. John E.
Loehr (Chairman), Mr. Anthony P. Towell, Mr. J. Virgil Waggoner and Mr. Steven
M. Morris. The committee met twice in 2000.
The function of the compensation committee is to fix the annual salaries
and other compensation for the officers and key employees of the Company. The
committee is comprised of Mr. J. Virgil Waggoner (Chairman), Mr. Anthony P.
Towell, and Mr. John E. Loehr. The committee met twice in 2000.
The executive committee was established to make recommendations to the
board of directors in the areas of financial planning, strategies and business
alternatives. The committee is comprised of Mr. Anthony P. Towell (Chairman),
Mr. J. Virgil Waggoner, Mr. Marshall A. Smith III, Mr. John E. Loehr and Mr.
Thomas R. Kaetzer. The committee met twice in 2000.
Compensation of Directors
The shareholders approved an amended and restated Employee Stock Option
Plan on May 28, 1998, which included a provision for the payment of reasonable
fees in cash or stock to directors. No fees were paid to directors in 2000.
ITEM 11. Executive Compensation
Information regarding executive compensation is incorporated herein by
reference to our Proxy Statement.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management
Information regarding security ownership of certain beneficial owners and
management is incorporated herein by reference to our Proxy Statement.
ITEM 13. Certain Relationships and Related Transactions
Information regarding certain relationships and related transactions is
incorporated herein by reference to our Proxy Statement.
26
GLOSSARY OF INDUSTRY TERMS AND ABBREVIATIONS
The following are definitions of certain industry terms and abbreviations used
in this report:
Bbl. Barrel.
BOE. Barrel of oil equivalent, based on a ratio of 6,000 cubic feet of
natural gas for each barrel of oil.
Gross Acres or Gross Wells. The total acres or wells, as the case may be,
in which a working interests is owned.
Horizontal Drilling. High angle directional drilling with lateral
penetration of one or more productive reservoirs.
Mcf. One thousand cubic feet.
Net Acres or Net Wells. The sum of the fractional working interests owned
in gross acres or gross wells.
Overriding Royalty Interest. The right to receive a share of the proceeds
of production from a well, free of all costs and expenses, except
transportation.
Present Value. The pre-tax present value, discounted at 10%, of future net cash
flows from estimated proved reserves, calculated holding prices and costs
constant at amounts in effect on the date of the report (unless such prices or
costs are subject to change pursuant to contractual provisions) and otherwise in
accordance with the Commission's rules for inclusion of oil and gas reserve
information in financial statements filed with the Commission.
Proceeds of Production. Money received (usually monthly) from the sale of
oil and gas produced from producing properties.
Producing Properties. Properties that contain one or more wells that
produce oil and/or gas in paying quantities (i.e., a well for which proceeds
from production exceed operating expenses).
Productive Well. A well that is producing oil or gas or that is capable of
production.
Prospect. A lease or group of leases containing possible reserves, capable
of producing crude oil, natural gas, or natural gas liquids in commercial
quantities, either at the time of acquisition, or after vertical or horizontal
drilling, completion of workovers, recompletions, or operational modifications.
Proved Reserves. Estimated quantities of crude oil, natural gas, and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic conditions; i.e., prices and costs as of the date the
estimate is made. Reservoirs are considered proved if either actual production
or a conclusive formation test supports economic production.
The area of a reservoir considered proved includes:
a. That portion delineated by drilling and defining by gas-oil or oil-water
contacts, if any; and
b. The immediately adjoining portions not yet drilled but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls the
lower proved limit of the reservoir.
27
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Proved Reserves do not include:
a. Oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves";
b. Crude oil, natural gas, and natural gas liquids, the recovery of which
is subject to reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors;
c. Crude oil, natural gas, and natural gas liquids that may occur in
undrilled prospects; and
d. Crude oil, natural gas, and natural gas liquids that may be recovered
from oil shales and other sources.
Proved Developed Reserves. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods. Additional oil and
gas expected to be obtained through the application of fluid injection or other
improved recovery techniques for supplementing the natural forces and mechanisms
of primary recovery should be included as proved developed only after testing by
a pilot project or after operation of an installed program has confirmed through
production response that increased recovery will be achieved.
Proved Undeveloped Reserves. Reserves that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion. Reserves on undrilled acreage shall be
limited to those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other units that have
not been drilled can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
Under no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proven effective by actual tests in the area and in the same reservoir.
Recompletion. The completion for production of an existing wellbore in
another formation from that in which the well has previously been completed.
Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible oil or gas that is confined by impermeable rock or
water barriers and is individual and separate from other reservoirs.
Royalty. The right to a share of production from a well, free of all costs
and expenses, except transportation.
Royalty Interest. An interest in an oil and gas property entitling the
owner to a share of oil and natural gas production free of costs of production.
Standardized Measure. The present value, discounted at 10%, of future net cash
flows from estimated proved reserves, after income taxes, calculated holding
prices and costs constant at amounts in effect on the date of the report (unless
such prices or costs are subject to change pursuant to contractual provisions)
and otherwise in accordance with the Commission's rules for inclusion of oil and
gas reserve information in financial statements filed with the Commission.
28
Waterflood. An engineered, planned effort to inject water into an existing
oil reservoir with the intent of increasing oil reserve recovery and production
rates.
Working Interest. The operating interest under a lease, the owner of which has
the right to explore for and produce oil and gas covered by such lease. The full
working interest bears 100 percent of the costs of exploration, development,
production, and operation, and is entitled to the portion of gross revenue from
the proceeds of production which remains after proceeds allocable to royalty and
overriding royalty interests or other lease burdens have been deducted.
Workover. Rig work performed to restore an existing well to production or
improve its production from the current existing reservoir.
29
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:
Consolidated Balance Sheets at December 31, 2000 and 1999.
Consolidated Statements of Operations for the years
ended December 31, 2000, 1999 and 1998.
Consolidated Statements of Stockholders' Equity for
the years ended December 31, 2000, 1999 and 1998.
Consolidated Statements of Cash Flows for the years
ended December 31, 2000, 1999 and 1998.
Notes to Consolidated Financial Statements, December 31,
2000, 1999 and 1998.
(2) Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts
(3) Exhibits:
Number Description
#2.8 Purchase and Sale Agreement between Pozo
Resources, Inc. and GulfWest Oil Company,
effective December 31, 1999.
*3.1 Articles of Incorporation of the Registrant and
Amendments thereto.
*3.2 Bylaws of the Registrant.
%10.1 GulfWest Oil Company 1994 Stock Option and
Compensation Plan, amended and restated as of
April 15, 1998 and approved by the
shareholders on May 28, 1998.
22.1 Subsidiaries of the Registrant filed herewith.
25 Power of Attorney (included on signature page of
this Annual Report).
# Previously filed with the Company's Form 8-K, Current Report dated
December 31, 1999, filed with the Commission on January 10,2000.
* Previously filed with the Company's Registration Statement (on Form
S-1, Reg. No. 33-53526), filed with the Commission on October 21, 1992.
% Previously filed with the Company's Annual Report on Form 10-K for the
year ended December 31, 1994, filed with the Commission on April 14,1995.
30
S I G N A T U R E S
Pursuant to the requirements of Section 13 or 15(d) 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.
GULFWEST OIL COMPANY
Date: March 20, 2001 By:\s\ Thomas R. Kaetzer
------------------------
Thomas R. Kaetzer, President
31
POWER OF ATTORNEY
Know all men by these presents, that each person whose signature
appears below constitutes and appoints Thomas R. Kaetzer as his true and lawful
attorney-in-fact and agent, with full power of substitution, for him and in his
name, place, and stead, in any and all capacities to sign any and all amendments
or supplements to this Annual Report on Form 10-K, and to file the same, and
with all exhibits thereto and other documents in connection therewith, with the
Securities and Exchange Commission, granting unto said attorney-in-fact and
agent full power and authority to do and perform each and every act and thing
requisite and necessary to be done as fully to all intents and purposes as he
might or could do in person, hereby ratifying and confirming all that said
attorney-in-fact and agent or his substitute or substitutes, may lawfully do or
cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons, on behalf of the
registrant, and in the capacities and on the dates indicated.
Signature Title Date
- --------- ----- ----
\s\ Marshall A. Smith III Chairman of the Board March 20, 2001
- --------------------------
Marshall A. Smith III
\s\ Thomas R. Kaetzer President, Chief Executive Officer March 20, 2001
- --------------------------
Thomas R. Kaetzer and Director
\s\ Jim C. Bigham Executive Vice President, Secretary March 20, 2001
- --------------------------
Jim C. Bigham and Director
\s\ Richard L. Creel Vice President of Finance, Controller March 20, 2001
- --------------------------
Richard L. Creel
\s\ William T. Winston Vice President March 20, 2001
- --------------------------
William T. Winston
\s\ Anthony P. Towell Director March 20, 2001
- --------------------------
Anthony P. Towell
\s\ J. Virgil Waggoner Director March 20, 2001
- --------------------------
J. Virgil Waggoner
\s\ John E. Loehr Director March 20, 2001
- --------------------------
John E. Loehr
\s\ Steven M.Morris Director March 20, 2001
- --------------------------
Steven M. Morris
32
GULFWEST OIL COMPANY
FINANCIAL REPORT
DECEMBER 31, 2000
C O N T E N T S
Page
INDEPENDENT AUDITOR'S REPORT
ON THE FINANCIAL STATEMENTS F-1
FINANCIAL STATEMENTS
Consolidated balance sheets F-2
Consolidated statements of operations F-4
Consolidated statements of stockholders' equity F-5
Consolidated statements of cash flows F-9
Notes to consolidated financial statements F-10
INDEPENDENT AUDITOR'S REPORT ON
THE FINANCIAL STATEMENT SCHEDULE F-31
FINANCIAL STATEMENT SCHEDULE
Schedule II - Valuation and Qualifying Accounts F-32
All other Financial Statement Schedules have been omitted because they are
either inapplicable or the information required is included in the
financial statements or the notes thereto.
INDEPENDENT AUDITOR'S REPORT
To the Stockholders and
Board of Directors
GULFWEST OIL COMPANY
We have audited the accompanying consolidated balance sheets of GulfWest Oil
Company (a Texas Corporation) and Subsidiaries as of December 31, 2000 and 1999,
and the related consolidated statements of operations, stockholders' equity and
cash flows for each of the three years in the period ended December 31, 2000.
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 auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the consolidated
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the consolidated 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
GulfWest Oil Company and Subsidiaries as of December 31, 2000 and 1999 and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States of America.
\s\WEAVER AND TIDWELL, L.L.P
- ----------------------------
WEAVER AND TIDWELL, L.L.P.
Dallas, Texas
March 9, 2001
F-1
GULFWEST OIL COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2000 AND 1999
ASSETS
2000 1999
----------- -------------
CURRENT ASSETS
Cash and cash equivalents $ 663,032 $ 287,300
Accounts receivable - trade, net of allowance
for doubtful accounts of $ -0-
in 2000 and 1999 2,188,421 990,402
Prepaid expenses 83,351 79,763
---------- ---------
Total current assets 2,934,804 1,357,465
---------- ---------
OIL AND GAS PROPERTIES,
using the successful efforts
method of accounting 30,895,049 20,083,696
OTHER PROPERTY AND EQUIPMENT 1,961,203 1,358,400
Less accumulated depreciation,
depletion, and amortization (4,049,510) (2,940,191)
---------- ----------
Net oil and gas properties and
other property and equipment 28,806,742 18,501,905
---------- ----------
OTHER ASSETS
Deposits 27,638 27,638
Investments 122,785 122,785
Debt issue cost 482,159
---------- -------------
Total other assets 632,582 150,423
---------- -------------
TOTAL ASSETS $32,374,128 $ 20,009,793
=========== =============
The Notes to Consolidated Financial Statements are an integral part of these
statements.
F-2
LIABILITIES AND STOCKHOLDERS' EQUITY
2000 1999
---------------- ----------------
CURRENT LIABILITIES
Notes payable $ 935,000 $ 250,000
Notes payable - related parties 700,000 750,000
Current portion of long-term debt 3,111,120 2,114,251
Current portion of long-term debt - related parties 303,296 234,355
Accounts payable - trade 2,189,656 839,129
Accrued expenses 355,614 462,956
---------- ----------
Total current liabilities 7,594,986 4,650,691
---------- ---------
LONG-TERM DEBT, net of current portion 17,960,455 11,040,744
---------- ----------
LONG-TERM DEBT - RELATED PARTIES 116,916 263,574
----------- ----------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock 80 88
Common stock 18,445 15,697
Additional paid-in capital 23,537,900 21,321,909
Retained deficit (16,854,654) (17,130,436)
Long-term accounts and notes receivable -
related parties, net of allowance for doubtful
accounts of $740,478 in 2000 and $700,230 in 1999 (152,474)
----------- -----------
Total stockholders' equity 6,701,771 4,054,784
---------- ----------
TOTAL LIABILITIES AND
STOCKHOLDERS' EQUITY $ 32,374,128 $ 20,009,793
========== ==========
F-3
GULFWEST OIL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
2000 1999 1998
------------------ ---------------- -------------------
OPERATING REVENUES
Oil and gas sales $ 8,445,932 $ 2,533,304 $ 1,804,147
Well servicing revenues 188,052 116,791 432,352
Operating overhead and other income 350,191 162,544 167,054
--------- --------- ---------
8,984,175 2,812,639 2,403,553
--------- --------- ---------
OPERATING EXPENSES
Lease operating expenses 3,377,583 1,399,710 1,647,329
Cost of well servicing operations 212,286 190,399 420,527
Impairment of assets 2,279,449
Depreciation, depletion, and amortization 1,341,890 703,533 2,322,423
General and administrative 1,588,399 1,983,091 2,063,709
--------- --------- ---------
6,520,158 4,276,733 8,733,437
--------- --------- ---------
INCOME (LOSS) FROM OPERATIONS 2,464,017 (1,464,094) (6,329,884)
OTHER INCOME AND EXPENSE
Interest income 16,082 5,162 11,602
Interest expense (2,134,718) (889,796) (1,302,885)
Gain (loss) on sale of assets 7,393 79,222 (765,893)
---------- ---------- ----------
INCOME (LOSS) BEFORE INCOME TAXES 352,774 (2,269,506) (8,387,060)
INCOME TAXES ---------- ----------- -----------
NET INCOME (LOSS) $ 352,774 $ (2,269,506) $ (8,387,060)
DIVIDENDS ON PREFERRED STOCK (PAID 2000
$76,992; 1999- $344,288;
1998 - $101,254) (450,684) (427,173)
--------- ----------- -----------
NET INCOME (LOSS) AVAILABLE TO
COMMON SHAREHOLDERS $ 352,774 $ (2,720,190) $ (8,814,233)
============== ================ ===================
INCOME (LOSS) PER COMMON SHARE
BASIC $ .02 $ (.34) $ (3.68)
============== ================ ===================
DILUTED $ .02 $ (.34) $ (3.68)
============== ================ ===================
F-4
GULFWEST OIL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
Number of Shares
----------------
Preferred Common
Stock Stock
----- -----
BALANCE, December 31, 1997 5,390 1,759,185
Conversion of 200 shares of AAA preferred stock and unpaid
dividends to 77,988 shares of common stock (200) 77,988
Conversion of related party debt to 3,830 shares of BB preferred stock 3,830
Issuance of 4,000 shares of C preferred stock for acquisition of assets 4,000
Issuance of 1,276,344 common shares, net of offering costs (116,920
through private placement, 53,587 through exercise of warrants,
955,837 in exchange for debt, accrued interest, deferred compen-
sation and accounts payable, 150,000 for acquisition of assets) 1,276,344
Issuance of options/warrants for services and additional financing costs
Increase in accounts and notes receivable - related parties
Provision for bad debts - receivables from related parties
Net loss
Dividends paid on preferred stock
----------- ----------
BALANCE, December 31, 1998 13,020 3,113,517
Conversion of 2,425 shares of Class AAA preferred stock and unpaid
dividends to 1,661,604 shares of common stock (2,425) 1,661,604
Conversion of 1,950 shares of Class AA preferred stock and unpaid
dividends to 1,550,000 shares of common stock (1,950) 1,550,000
Conversion of 5,100 shares of Series BB preferred stock to 4,250,000
shares of common stock (5,100) 4,250,000
Conversion of 4,000 shares of Series C preferred stock to 200,000
shares of common stock (4,000) 200,000
Issuance of 1,270 shares of Series BB preferred stock for the
conversion of debt 1,270
Issuance of 8,000 shares of Series D preferred stock for the acquisition
of assets 8,000
Issuance of 4,921,761 shares of common stock, net of offering costs
(4,000,000 through private placement, 104,139 through exercise
of warrants, 300,000 for acquisition of assets, 273,000 for services,
244,622 in exchange for debt) 4,921,761
Issuance of warrants and options for services and additional financing
Net loss
Dividends paid on preferred stock
---------- ----------
BALANCE, December 31, 1999 8,815 15,696,882
The Notes to Consolidated Financials are an integral part of these statements
F-5
Common Preferred Additional Retained Receivables from
Stock Stock Paid-In Capital Deficit Related Parties
------ --------- --------------- ------------ ----------------
$1,759 $ 54 $ 8,204,533 $ (6,028,328) $ (152,474)
78 (2) 6,876
38 1,914,962
40 630,094
1,276 1,845,439
162,032
(152,000)
152,000
(8,387,060)
(101,254)
------ -------- -------------- ------------- --------------
3,113 130 12,763,936 (14,516,642) (152,474)
1,662 (24) 232,803
1,550 (19) 108,257
4,250 (51) (4,199)
200 (40) (160)
12 634,987
80 3,999,920
4,922 3,541,715
44,650
(2,269,506)
(344,288)
------- ------- ------------ ------------- ------------
$15,697 $88 $21,321,909 $(17,130,436) $ (152,474)
F-6
GULFWEST OIL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
Number of Shares
----------------
Preferred Common
Stock Stock
----- -----
BALANCE, December 31, 1999 8,815 15,696,882
Conversion of 815 shares of AAA preferred stock and unpaid
dividends to 538,222 shares of common stock (815) 538,322
Issuance of 2,209,837 shares of common stock, net of offering costs
(1,143,837 through private placement, 200,000 for acquisition of
assets, 866,000 in exchange for debt) 2,209,837
Issuance of warrants and options for services and additional financing
Netting of related party receivables and payables
Provision for bad debts - receivables from related parties
Net income --------- ----------
BALANCE, December 31, 2000 8,000 18,445,041
========== ==========
The Notes to Consolidated Financials are an integral part of these statements.
F-7
Common Preferred Additional Retained Receivables from
Stock Stock Paid-In Capital Deficit Related Parties
----- ----- --------------- ------- ---------------
$ 15,697 $ 88 $ 21,321,909 $(17,130,436) $ (152,474)
538 (8) 76,463 (76,992)
2,210 2,123,868
15,660
112,226
40,248
352,774
-------- ------- ------------- ------------- --------------
$ 18,445 $ 80 $ 23,537,900 $(16,854,654) $
======== ======= ============= ============= ==============
F-8
GULFWEST OIL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
2000 1999 1998
-------------- -------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss $ 352,774 $ (2,269,506) $ (8,387,060)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization 1,341,890 703,533 2,322,423
Partnership loss 68,693 8,522
Common stock and warrants issued and charged to operations 15,660 234,250 162,032
(Gain) Loss on sale of assets (7,393) (79,222) 765,893
Other non-operating income (5,780)
Impairment of assets 2,279,449
Provision for bad debts 40,248 252,000
(Increase) decrease in accounts receivable - trade, net (1,344,767) (447,855) 329,439
(Increase) decrease in inventory 13,925 (13,925)
(Increase) decrease in prepaid expenses (3,588) (4,802) (20,467)
Increase (decrease)in accounts payable and accrued expenses 1,710,769 (359,290) 1,587,723
--------- -------- ---------
Net cash provided by (used in) operating activities 2,099,813 (2,140,274) (713,971)
--------- ---------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Deposits (10,338)
Proceeds from sale of property and equipment 14,915 155,844 148,351
Purchase of property and equipment (6,126,817) (1,482,548) (6,407,296)
(Increase)decrease in accounts and notes receivable - related party (102,000)
---------- ----------- -----------
Net cash used in investing activities (6,111,902) (1,337,042) (6,360,945)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock, net 795,378 3,000,000 155,827
Payments on debt (1,733,513) (1,300,891) (247,702)
Proceeds from debt issuance 5,694,510 1,861,200 6,845,833
Debt issue cost (368,554)
Dividends paid (101,254)
---------- ---------- ----------
Net cash provided by financing activities 4,387,821 3,560,309 6,652,704
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 375,732 82,993 (422,212)
CASH AND CASH EQUIVALENTS,
beginning of year 287,300 204,307 626,519
------- ------- -------
CASH AND CASH EQUIVALENTS,
end of year $ 663,032 $ 287,300 $ 204,307
============ ============ ===========
CASH PAID FOR INTEREST $ 2,041,630 $ 758,226 $ 407,054
============ ============ ===========
The Notes to Consolidated Financial Statements are an integral part of these
statements.
F-9
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
The following is a summary of the significant accounting policies
consistently applied by management in the preparation of the accompanying
financial statements.
Organization/Concentration of Credit Risk
GulfWest Oil Company and subsidiaries (the "Company") intends to
pursue the acquisition of quality oil and gas prospects which have
proved developed and undeveloped reserves and the development of
prospects with third party industry partners.
The accompanying financial statements include the Company and its
wholly-owned subsidiaries: RigWest Well Service, Inc. ("RigWest"),
GulfWest Texas Company ("GWT"), both formed in 1996; DutchWest Oil
Company formed in 1997; SETEX Oil and Gas Company ("SETEX") formed
August 11, 1998; Southeast Texas Oil and Gas Company, L.L.C. ("Setex
LLC") acquired September 1, 1998; GulfWest Oil & Gas Company formed
February 18, 1999; LTW Pipeline Co. formed April 19, 1999; and
GulfWest Development Company ("GWD") formed November 9, 2000. All
material intercompany transactions and balances are eliminated upon
consolidation. The financial statements also include the results of
operations for the first nine months of 1998 for the Company's former
wholly-owned subsidiaries: WestCo Oil Company (WestCo), formed in 1995
and sold October 1, 1998; and GulfWest Permian Company ("GWP") formed
in 1996 and sold October 1, 1998.
The Company grants credit to independent and major oil and gas
companies for the sale of crude oil and natural gas. In addition, the
Company grants credit to joint owners of oil and gas properties, which
the Company, through SETEX, operates. Such amounts are secured by the
underlying ownership interests in the properties. The Company also
grants credit to various third parties through RigWest for well
servicing operations.
The Company maintains cash on deposit in interest and
non-interest bearing accounts which, at times, exceed federally
insured limits. The Company has not experienced any losses on such
accounts and believes it is not exposed to any significant credit risk
on cash and equivalents.
Statement of Cash Flows
The Company considers all highly liquid investment instruments
purchased with remaining maturities of three months or less to be cash
equivalents for purposes of the consolidated statements of cash flows.
Non-Cash Investing and Financing Activities:
During the twelve month period ended December 31, 2000, the
Company acquired $5,434,161 in property and equipment through notes
payable to financial institutions and related parties of $4,958,163, in
exchange of accounts receivable of $169,798 and by issuing 200,000
shares of common stock valued at $306,200. In addition, accounts
payable and accrued expenses decreased $312,791, debt issue costs
increased $206,875 through notes payable to financial institutions.
During the period, 815 shares of preferred stock, along with unpaid
dividends of $76,992, were converted to 538,322 shares of common stock,
notes payable of $975,000 (including $750,000 to a director) were
converted to 800,000 shares of common stock and accounts payable of
$49,352 were converted to 66,000 shares of common stock. Also, related
party receivables of $112,226 and accounts receivable of $26,950 were
exchanged for related party notes payable of $75,000 and for accounts
payable of $64,176.
In 1999, the Company converted deferred compensation of $47,883,
debt of $700,000, accounts payable of $10,000 and $108,465 of accrued
interest to common stock. In addition, the Company issued notes
payable for $6,679,700, along with 300,000 shares of common stock,
valued at $150,000, and 8,000 shares of preferred stock, valued at
$4,000,000, for the acquisition of properties and equipment. Common
stock was also issued for the exercise of warrants by converting
$21,025 in deferred compensation and the conversion of 13,475 shares
F-10
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Non-Cash Investing and Financing Activities - continued:
of preferred stock, plus $344,288 in unpaid dividends, to 7,661,604
shares of common stock. Equipment was exchanged for the assumption
of $7,975 of debt. As a result of the sale of assets, accounts
receivable were reduced by $14,756 and notes payable were reduced
by $39,009.
In 1998, $1,965,000 of notes payable, $311,500 of accounts
payable, $100,090 of accrued expenses and $1,105,000 of long-term debt
were converted to common or preferred stock. All of the outstanding
membership interest of Setex LLC was acquired in exchange for $630,134
of preferred stock. In addition, $131,250 in common stock was issued
in exchange for property and equipment costs. Long-term debt totaling
$1,299,200 was re-financed during 1998.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results
could differ from those estimates.
Oil and Gas Properties
The Company uses the successful efforts method of accounting for
oil and gas producing activities. Costs to acquire mineral interests
in oil and gas properties, to drill and equip exploratory wells that
find proved reserves, and to drill and equip development wells are
capitalized. Costs to drill exploratory wells that do not find proved
reserves, and geological and geophysical costs are expensed.
As the Company acquires significant oil and gas properties, any
unproved property that is considered individually significant is
periodically assessed for impairment of value, and a loss is
recognized at the time of impairment by providing an impairment
allowance. Capitalized costs of producing oil and gas properties and
support equipment, after considering estimated dismantlement and
abandonment costs and estimated salvage values, are depreciated and
depleted by the unit-of-production method.
On the sale of an entire interest in an unproved property, gain
or loss on the sale is recognized, taking into consideration the
amount of any recorded impairment if the property has been assessed
individually. If a partial interest in an unproved property is sold,
the amount received is treated as a reduction of the cost of the
interest retained. On the sale of an entire or partial interest in a
proved property, gain or loss is recognized, based upon the fair
values of the interests sold and retained.
Other Property and Equipment
The following tables set forth certain information with respect
to the Company's other property and equipment.
The Company provides for depreciation and amortization using the
straight-line method over the following estimated useful lives of the
respective assets:
Automobiles 3 - 5 years
Office equipment 7 years
Gathering system 10 years
Well servicing equipment 10 years
F11
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Capitalized costs relating to other properties and equipment:
2000 1999
------------- ------------
Automobiles $ 448,598 $ 376,443
Office equipment 111,477 39,820
Gathering system 481,311 291,796
Well servicing equipment 919,817 650,341
------- -------
1,961,203 1,358,400
Less accumulated depreciation (684,327) (585,595)
-------- --------
Net capitalized cost $ 1,276,876 $ 772,805
============= ============
Revenue Recognition
The Company recognizes oil and gas revenues on the sales method as oil and
gas production is sold. Differences between sales and production volumes during
the years ended December 31, 2000, 1999, and 1998 were not significant. Well
servicing revenues are recognized as the related services are performed.
Operating overhead income is recognized based upon monthly contractual amounts
for lease operations and other income is recognized as received.
Fair Value of Financial Instruments
At December 31, 2000 and 1999, the Company's financial instruments consist
of notes receivable from related parties, notes payable and long-term debt.
Interest rates currently available to the Company for notes receivable, notes
payable and long-term debt with similar terms and remaining maturities are used
to estimate fair value of such financial instruments. Accordingly, the carrying
amounts are a reasonable estimate of fair value.
Investments
Investments consist of an interest in a partnership acquired in the Setex
LLC acquisition, accounted for under the equity method of accounting.
Earnings (Loss) Per Share
Earnings (loss) per share are calculated based upon the weighted-average
number of outstanding common shares. Diluted earnings (loss) per share are
calculated based upon the weighted-average number of outstanding common shares,
plus the effect of dilutive stock options, warrants, convertible preferred stock
and convertible debentures.
The Company has adopted Statement of Financial Accounting Standards (SFAS)
No. 128 "Earnings Per Share", which requires that both basic earnings (loss) per
share and diluted earnings (loss) per share be presented on the face of the
statement of operations. All per-share amounts are presented on a diluted basis,
that is, based upon the weighted-average number of outstanding common shares and
the effect of all potentially diluted common shares. Implementation of SFAS No.
128 had no effect on previously reported loss per share amounts.
F12
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Impairments
Impairments, measured using fair market value, are recognized whenever
events or changes in circumstances indicate that the carrying amount of
long-lived assets (other than unproved oil and gas properties discussed above)
may not be recoverable and the future undiscounted cash flows attributable to
the asset are less than its carrying value. Because of declining sales prices
for oil and gas in 1998, certain producing oil and gas properties were impaired
at December 31, 1998. The Company charged $2,279,449 to operations in 1998 as an
impairment loss, based upon the discounted net present value of future cash
flows of related oil and gas properties.
Stock Based Compensation
In October 1995, SFAS No. 123, "Stock Based Compensation," (SFAS 123) was
issued. This statement requires the Company to choose between two different
methods of accounting for stock options and warrants. The statement defines a
fair-value-based method of accounting for stock options and warrants but allows
an entity to continue to measure compensation cost for stock options and
warrants using the accounting prescribed by APB Opinion No. 25 (APB 25),
"Accounting for Stock Issued to Employees." Use of the APB 25 accounting method
results in no compensation cost being recognized if options are granted at an
exercise price at the current market value of the stock or higher. The Company
will continue to use the intrinsic value method under APB 25 but is required by
SFAS 123 to make pro forma disclosures of net income (loss) and earnings (loss)
per share as if the fair value method had been applied in its 2000, 1999 and
1998 financial statements. See Note 6 to the consolidated financial statements
for further information.
Implementation of New Financial Accounting Standards
The Company will adopt SFAS No. 137 "Accounting for Derivative Instruments
and Hedging Activities" in 2001. The Company does not know the effects, if any,
this statement will have on the Company's financial position, results of
operations or cash flows. The Company adopted SFAS No. 130 "Reporting
Comprehensive Income", No. 131 "Disclosures About Segments of an Enterprise and
Related Information" and No. 132 "Employers Disclosures About Pensions and Other
Post Retirement Benefits" in 1998. Adoption of these statements had no material
effects on the Company's financial position, results of operations or cash
flows.
Note 2. Operations and Management Plans
At December 31, 2000, the Company's current liabilities exceeded its
current assets by $4,660,182. The Company had a profit of $352,774 compared to a
loss of $2,269,506 at December 31, 1999. The profit in the year 2000 can be
attributed to increased production from development projects and additional
acquisitions, and more favorable crude oil and natural gas prices.
On April 5, 2000, the Company entered into an agreement with Aquila
Energy Capital, an energy lender, to provide $19,302,000 in financing, of which
$13,302,000, less closing costs of $402,000, was funded at closing and
$6,000,000 was future development capital. The proceeds were used to (i) retire
existing debt, including accrued interest of $10,234,977; (ii) acquire crude oil
and natural gas properties in Zavala County, Texas for $2,300,000, including
$3,266 in cash and 200,000 shares of the Company's common stock; and, (iii)
acquire additional interests in the Madisonville Field, Texas. The loan is
secured by substantially all of the Company's interests in oil and gas
properties, bears interest at prime plus 3.5% and matures May 29, 2004. Monthly
payments as to principal and interest are from an 85% net revenue interest in
the secured properties. The lender retains a 7% overriding royalty interest with
payments commencing after the loan is paid in full.
F-13
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 2. Operations and Management Plans - continued
The development capital included in the Aquila financing was designated
for projects to increase production on the Company's existing properties, as
identified by the Company and approved by the lender. The Company used
approximately $3,400,000 for such projects in the year 2000 and will continue
development activities in 2001 with the remaining $2,600,000. The Company will
also continue to identify and evaluate opportunities for growth through
acquisitions. Management believes profits will increase in the future; however
adverse changes in the prices of crude oil and natural gas would have a severe
impact on the Company's plans.
Note 3. Cost of Oil and Gas Properties
The following tables set forth certain information with respect to the
Company's oil and gas producing activities for the periods presented:
Capitalized Costs Relating to Oil and Gas Producing Activities:
2000 1999
---- ----
Unproved oil and gas properties $ 384,240 $ 6,171
Proved oil and gas properties 28,540,631 19,096,565
Support equipment and facilities 1,970,178 980,960
-------------- -----------
30,895,049 20,083,696
Less accumulated depreciation,
depletion and amortization (3,365,182) (2,354,596)
-------------- -----------
Net capitalized costs $ 27,529,867 $17,729,100
============== ============
F-14
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Cost of Oil and Gas Properties - continued
Results of Operations for Oil and Gas Producing Activities:
2000 1999 1998
---- ---- ----
Oil and gas sales $ 8,445,932 $ 2,533,304 $ 1,804,147
Production costs (3,377,583) (1,399,710) (1,647,329)
Depreciation, depletion and amortization (1,030,635) (524,295) (2,100,332)
Income tax expense _ _ _
------------ ------------ -------------
Results of operations for oil and gas
producing activities - income (loss) $ 4,037,714 $ 609,299 $ (1,943,514)
=========== =========== ============
Costs Incurred in Oil and Gas Producing Activities:
2000 1999 1998
---- ---- ----
Property Acquisitions
Proved $ 5,874,199 $11,006,257 $ 4,704,408
Unproved 122,837 1,568 -
Development Costs 4,814,317 1,041,858 1,786,900
--------- --------- ---------
$ 10,811,353 $12,049,683 $ 6,491,308
============ =========== ============
On July 3, 1994, the Company exercised its option under the Investment
Letter and Subscription Agreement with Madisonville Project, Ltd. (the
"Partnership"), an unrelated party, to convert $500,000 of the note receivable
from the Partnership into 100 Partnership units. At December 31, 1994, the
Company's 100 units represent an interest of 32.46% of the Partnership. Per the
agreement with the Partnership, income and expenses are to be distributed
between partners based on the weighted average interest in the partnership
during the year. As a result of the investment in the Partnership, the balance
sheet of the Partnership as of December 31, 2000 and 1999, and its results of
operations for the years ended December 31, 2000, 1999 and 1998 have been
proportionately consolidated with the accompanying balance sheets, statements of
operations and cash flows of the Company. All material intercompany transactions
and balances have been eliminated in consolidation.
Effective April 1, 1998, the Company acquired oil and gas reserves from an
unrelated party. The acquisition cost was $3,072,000, including $2,575,000 in
long-term debt, $100,000 cash paid in 1998, $200,000cash paid in 1997 and other
fees and expenses totaling $197,000. Effective October 1, 1998, the Company sold
its interest in these properties as part of the sale of its wholly owned
subsidiary, GulfWest Permian.
Effective September 1, 1998, the Company acquired all the membership
interests of Setex LLC, pursuant to an Interest Purchase Agreement
("Agreement"). The aggregate purchase consideration for all the membership
interests consisted of 4,000 shares of the Series C Preferred Stock of GulfWest
and warrants to purchase 100,000 shares of GulfWest common stock. In this
transaction, the Company acquired working interests in proved undeveloped oil
and gas properties located in six (6) counties in South and East Texas with
estimated proved reserves of approximately 3 billion cubic feet of natural gas
equivalent net to the Company's interest. The net consideration received
($630,134) was determined through negotiations based upon third party
engineering reports.
F-15
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Cost of Oil and Gas Properties - continued
Costs Incurred in Oil and Gas Producing Activities: - continued
Supplemental unaudited pro forma information (under the purchase
method of accounting) presenting the results of operations for the year
ended December 31, 1998, as if the Setex LLC transaction had occurred
as of January 1, 1998:
Year Ended
December 31,
1998
------------
Operating revenues $ 2,485,510
Operating expenses 8,988,287
------------
Income (loss) from operations (6,502,777)
Other income and expense (2,058,063)
Income taxes ------------
Net income (loss) $(8,560,840)
============
Earnings (loss) per share - basic and diluted $ (3.75)
============
F-16
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Cost of Oil and Gas Properties - continued
Costs Incurred in Oil and Gas Producing Activities: - continued
Effective July 1, 1999, the Company acquired interests in oil and
gas properties in Zavala County, Texas from an unrelated party. The
acquisition cost was $438,759, consisting of $150,000 cash, $138,757
in debt and 300,000 shares of common stock.
Effective December 31, 1999, the Company acquired interests in
oil and gas properties in Colorado and Texas from an unrelated party,
Pozo Resources, Inc. The acquisition cost was $10,500,000, consisting
of 8,000 shares of Series D preferred stock and $6,500,000 in debt. In
addition, the Company paid a $65,000 commission to an unrelated party.
On the same date, the Company transferred its ownership interest in
these properties to its wholly owned subsidiary, GulfWest Oil & Gas
Company.
Effective April 1, 2000, the Company acquired interests in oil
and gas properties in Texas from an unrelated party. The acquisition
cost was $2,624,455, consisting of $21,522 cash, $2,296,734 in debt and
200,000 shares of common stock. On the same date, the Company acquired
additional interest in its Madisonville Field from three working
interest owners. The acquisition cost was $294,648, consisting of
$155,343 in debt, $167,798 in accounts receivable due to the Company
and $30,493 in accounts payable due a working interest owner.
Effective October 1, 2000, the Company acquired interests in oil
and gas properties located in Texas, Oklahoma and Mississippi from an
unrelated party. The acquisition cost was $2,955,096, consisting of
$855,096 cash and $2,100,000 in debt.
Supplemental unaudited pro forma information (under the purchase method of
accounting) presenting the results of operations for the years ended
December 31, 1999 and 1998, as if the Pozo Resources transaction had
occurred as of January 1, 1999 and 1998:
Year Ended Year Ended
December 31, December 31,
1999 1998
------------- ------------
Operating Revenues $ 3,885,644 $ 3,812,107
Operating Expenses 5,169,105 9,750,701
------------- -------------
Income (loss) from operations (1,283,461) (5,938,594)
Other income and expense (2,091,662) (3,343,426)
Income taxes _ -
-------------- -------------
Net income (loss) $ (3,375,123) $ (9,282,020)
============== =============
Earnings (loss) per share - basic and diluted $ (.48) $ (4.05)
============== =============
Note 4. Accrued Expenses
Accrued expenses consisted of the following:
December 31, December 31,
2000 1999
------------ ------------
Payroll and payroll taxes $ 15,569 $ 28,841
Interest 296,989 388,063
Professional fees 42,000 36,000
Sales taxes 1,056 10,052
------------ ------------
$ 355,614 $ 462,956
============ ============
F-17
Note 5. Notes Payable and Long-Term Debt
Notes payable is as follows:
2000 1999
--------------- --------------
$500,000 notes payable (including $100,000 to related parties in 1999)
due October through November, 1998. 12% interest payable quarterly;
secured by 20% interest in the Madisonville Project, Ltd. (Note 3);
$50,000 converted to common stock June, 1998; $50,000 converted to
common stock September, 1999; retired
April, 2000. $ $ 400,000
$175,000 notes payable due May, 1998. Interest at
prime rate, plus 2% (prime rate at 9.5% at December 31,
2000); 18% past due rate, payable monthly. Secured by
oil and gas properties; past due. 45,000 175,000
Promissory notes payable to director of the Company at 8.5% interest;
various due dates from January, 2000 through
June, 2000; unsecured; converted to common stock March, 2000. 750,000
Promissory note payable to unrelated party at 10% interest;
due April, 2000; unsecured; converted to common stock May, 2000. 75,000
Note payable to unrelated entity to finance oil and gas properties;
due August, 2000; secured by related oil and gas properties and
guaranty of director; interest at prime rate plus 1/2 % (8.5% at
December 31, 1999); retired April, 2000. 6,257,403
Promissory note payable to related party at 10% interest; due on demand;
unsecured; retired June, 2000. 242,597
Promissory note payable to a director of a subsidiary of the Company
at 8.5%; due May, 2000; unsecured; retired April, 2000. 200,000
Promissory note payable to a director of the Company at 10%; payable on
demand; unsecured. 500,000
Promissory note payable to a director of a subsidiary of the Company at 8.5%;
due April, 2001; unsecured 200,000
F-18
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Notes Payable and Long-Term Debt
Notes payable is as follows - continued:
2000 1999
--------------- ----------------
Promissory note payable to an unrelated party at 10%; payable on demand;
unsecured. 100,000
Promissory note payable to an unrelated party at 10%; due January, 2001;
Unsecured. 250,000
Non-interest bearing note payable to an unrelated party; payable out of 50%
of the net transportation revenues from a certain natural gas pipeline; no
due date. 40,300
Note payable to a bank at 11%; due March, 2001; secured by the
guaranty of three directors of the Company. 500,000
------------ ------------
$ 1,635,300 $ 8,100,000
============
Notes reclassified as a result of the Aquila financing (Note 2) (7,100,000)
------------
$ 1,000,000
=============
Long-term debt is as follows:
2000 1999
------------- -------------
Line of credit (up to $3,000,000) to bank; due March, 2002;
secured by guaranty of a director. Interest at prime rate
(prime rate 9.5% at December 31, 2000). $ 2,989,515 $ 2,709,515
Nonrecourse debt to the Partnership to acquire
oil and gas properties, at 8% interest per annum; retired April, 2000. 865,210
Subordinated promissory notes to various individuals at 9.5% interest
per annum; $25,000 retired April, 1997; $105,000 converted to
common stock June, 1998; $50,000 converted to common stock
September, 1999;$75,000 retired July, 2000; amounts include
$120,000 ($195,000 - 1999) due to
related parties; past due. 245,000 320,000
Notes payable to finance vehicles, payable in aggregate monthly
installments of approximately $6,000, including interest of 8.5% to
13% per annum; secured by the related
equipment, due various dates through 2005. 141,990 102,632
Notes payable to unrelated entity to retire other debt at an
interest rate of prime plus 1%, changed to prime in April, 1999
(prime rate 8.5% at December 31, 1999); due February 1, 2001. Secured
by oil and gas properties, and guaranty of a director; retired April, 2000 1,150,000
F-19
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Notes Payable and Long-Term Debt - continued
Long-term debt is as follows - continued:
2000 1999
--------------- ----------------
Line of credit up to $500,000 to bank; due April, 2000; secured by
guaranties of a director and officer.
interest at prime rate (8.5% at December 31, 1999); retired April, 2000. 490,000
Note payable to related party to finance equipment with monthly
installments of $5,200, including interest at 13.76% per annum;
final payment due October, 2003; secured by related equipment. 145,716 185,071
Note payable to unrelated party with monthly installments of $12,500;
interest at 11%; due March, 2004; secured by oil and gas
properties;
retired April, 2000. 480,360
Promissory note to a director of the Company; interest at 8.5%;
due December 31, 2001. 100,980 117,858
Non-interest bearing note payable to unrelated party (interest imputed
at 10%); payable out of 25% net profits from certain oil and gas
properties; due January, 2001; secured by related oil and gas
properties. 132,278 132,278
Note payable to a related party to finance equipment with monthly
installments of $2,300, including interest at 11% per annum; final
payment due March, 2002; secured by related equipment. 32,553
Note payable to a related party to finance equipment with monthly
installments of $1,100, including interest at 11% per annum; final
payment due September, 2002; secured by related equipment. 20,963
Note payable to a bank with monthly principal payments of $2,300;
interest at 9.5%; due May, 2003; secured by related equipment. 67,456
Note payable to an energy lender; interest at prime plus 3.5% (prime
rate 9.5% at December 31, 2000) payable monthly out of 85% net
profits from certain oil and gas properties;
final payment due May, 2004; secured by related oil and gas properties. 15,530,336
Note payable to a bank with monthly principal payments of $15,000;
interest at prime plus 1% (prime rate 9.5% at December 31, 2000);
final payment due November, 2003; secured by related oil and gas
properties. 2,085,000
--------- ------------
6,552,924
Notes reclassified as a result of the Aquila financing (Note 2) 7,100,000
--------- -----------
21,491,787 13,652,924
Less current portion (3,414,416) (2,348,606)
----------- -----------
Total long-term debt $18,077,371 $11,304,318
============ ============
F-20
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Notes Payable and Long-Term Debt - continued
Long-term debt is as follows - continued
On April 5, 2000, the Company entered into a financing agreement
with Aquila Energy Capital Corporation. Terms of the financing require
payment of the principal and interest from 85% of the net profits from
the properties securing the loan. For purposes of the following table,
maturities have been estimated based on principal payments actually
made as calculated from 85% of the net profits from the most recent
6-month trailing average. Because the maturities are based upon
estimates of future net profits, it is reasonably possible that the
amount the Company will actually pay could differ materially in the
near term from the estimated amount.
Estimated annual maturities for long-term debt, including the
refinancing, are as follows:
2001 $ 3,414,415
2002 5,902,352
2003 4,407,188
2004 7,762,926
2005 4,906
------------
$21,491,787
===========
F-21
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity
Common Stock 2000 1999
------------ ------------- ------------
Par value $.001; 40,000,000 shares authorized;
18,445,041 and 15,696,882 shares issued and
outstanding as of December 31, 2000 and
1999, respectively. $ 18,445 $ 15,697
=========== ==========
Preferred Stock
---------------
Class AAA, par value $.01; 4,000 shares authorized;
0 and 815 shares issued and outstanding as
of December 31, 2000 and 1999, respectively.
Dividends are cumulative and payable quarterly at
the rate of $45 per share per annum. The shares
are convertible into common stock based upon a
purchase value of $500 per share of Class AAA stock
divided by the lesser of (i) $3.50 per share or (i) 70%
of the average closing NASDAQ bid price of the common
stock for the 15 trading days that end on the 3rd business
day preceding conversion. In addition, the Company is
obligated to pay $2.10 per week (from August 15, 1997;
$2.00 from May 15 to August 15, 1997) per $1,000
purchase amount to Class AAA stock as additional
dividends until sufficient securities are registered
to cover public resales of common stock issuance
upon conversion of Class AAA shares. Under special
agreement, a majority of the Class AAA preferred
shareholders (2,425 shares)converted their shares and
approximately $235,000 in unpaid dividends into
1,661,064 common shares in 1999. The remaining Class
AAA preferred shareholders (815 shares) converted their
shares and approximately $77,000 in unpaid dividends
into 538,322 shares of common stock in 2000. 8
Series D, par value $.01; 12,000 shares authorized;
8,000 issued and outstanding at December 31, 2000 and 1999.
The Series D preferred stock does not pay dividends
and is not redeemable. The liquidation value is
$500 per share. After three years from the date of
issuance, and thereafter, the shares are convertible into
common stock based upon a value of $500 per Series D
share divided by $8 per share of common stock. 80 80
---------- ---------
$ 80 $ 88
========== ==========
F-22
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity - continued
Preferred Stock - continued
All classes of preferred shareholders have liquidation
preference over common shareholders of $500 per preferred share,
plus accrued dividends. Dividends in arrears at December 31, 2000
were $159,409 (Series BB). Dividends in arrears at December 31,
1999 were $379,602 ($220,192 -Class AAA; $159,409 - Series BB).
Stock Options
The Company maintains a Non-Qualified Stock Option Plan (as
amended and restated, the "Plan") which authorizes the grant of
options of up to 1,000,000 shares of common stock. Under the Plan,
options may be granted to any of the Company's key employees
(including officers), employee and nonemployee directors, and
advisors. A committee appointed by the Board administers the Plan.
Prior to 1999, options granted under the Plan had been granted at an
option price of $3.13 and $1.81 per share. In July 1999, the Board
authorized that all then current employee and director options under
the plan be reduced to a price of $.75 per share. Following is a
schedule by year of the activity related to stock options, including
weighted-average ("WTD AVG") exercise prices of options in each
category.
2000 1999 1998
------------------ ------------------- ------------------
WTD AVG WTD AVG WTD AVG
Prices Number Prices Number Prices Number
--------- ------- ---------- ------- ------- ---------
Balance, January 1 $ 1.07 717,000 $ 2.52 490,000 $ 2.85 800,000
Options issued $ 1.17 206,000 $ .75 582,000 $ 1.81 210,000
Options expired - - $ 2.53 (355,000) $ 3.12 (520,000)
------- -------- ----------
Balance, December 31 $ 1.09 923,000 $ 1.07 717,000 $ 2.52 490,000
======= ======= =======
All options were exercisable at December 31, 2000. Following is a
schedule by year and by exercise price of the expiration of the
Company's stock options issued as of December 31, 2000:
2001 2002 2003 2004 2005 Thereafter Total
-------- ---------- ---------- --------- -------- ---------- --------
$ .75 432,000 150,000 582,000
$1.13 100,000 100,000
$1.20 106,000 106,000
$1.81 60,000 60,000
$3.00 10,000 65,000 75,000
--------- ---------- ---------- --------- -------- --------- --------
10,000 65,000 432,000 206,000 210,000 923,000
======== ========== ========== ========== ======== ========= ========
F-23
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity - continued
Stock Options - continued
Stock Warrants
The Company has issued a significant number of stock warrants for
a variety of reasons, including compensation to employees, additional
inducements to purchase the Company's common or preferred stock,
inducements related to the issuance of debt and for payment of goods
and services. Following is a schedule by year of the activity related
to stock warrants, including weighted-average exercise prices of
warrants in each category:
2000 1999 1998
-------------------- ------------------ ----------------
WTD AVG WTD AVG WTD AVG
Prices Number Prices Number Prices Number
-------- --------- -------- ------- ------- ------
Balance, January 1 $ 2.53 1,369,754 $ 3.16 2,888,343 $ 3.23 2,654,555
Warrants issued $ 1.86 170,000 $ 1.09 694,254 $ 3.49 1,008,500
Warrants exercised/expired $ 2.65 (147,500) $ 2.90 (2,212,843) $ 1.92 (774,712)
--------- ---------- ----------
Balance, December 31 $ 2.31 1,392,254 $ 2.53 1,369,754 $ 3.16 2,888,343
========= ========== =========
Included in the "warrants exercised/expired" column in 1999 were
43,589 with a weighted average of $.49 exercised by related parties.
Included in the "warrants issued" and "warrants exercised/expired"
columns in 1999 were 536,754 warrants whose price was reduced in 1999 to
$.75. The remaining 1,632,500 warrants expired. Included in the
"warrants exercised/expired" column in 1998 were 53,587 warrants with a
weighted average price of $.48 exercised by related parties. Included in
the "warrants issued" and "warrants exercised/expired" column in 1998
were 644,250 warrants issued in previous years whose expiration dates
were extended. The remaining 76,875 warrants expired.
Following is a schedule by year and by exercise price of the
expiration of the Company's stock warrants issued as of December 31,
2000:
2001 2002 2003 2004 2005 Thereafter Total
------ ------ ------ ------ ------ ---------- ----------
$ .75 20,000 166,754 370,000 556,754
.875 150,000 150,000
1.625 19,000 19,000
2.00 56,500 56,500
2.25 40,000 40,000
2.50 50,000 50,000
3.00 50,000 200,000 250,000
5.00 50,000 50,000
5.75 20,000 20,000
6.00 200,000 200,000
------- ------ ------- ------ ------- ------- ---------
235,500 366,754 150,000 640,000 1,392,254
======= ======= ======= ======= ======= ======= =========
F-24
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity - continued
Stock Warrants - continued
Warrants outstanding to officers, directors and employees of the
Company at December 31, 2000 and 1999 were approximately 957,000 and
807,000, respectively. The exercise prices on these warrants range
from $.75 to $5.75 and expire various dates through 2006.
Other Stock Based Compensation Disclosures
During 2000, 1999 and 1998, the Company issued options and
warrants totaling 2000 - 354,000 (all exercisable); 1999 - 963,754
(all exercisable); and 1998 - 90,000 (all exercisable), respectively,
to employees as compensation. As disclosed in Note 1, the Company
continues to use the intrinsic value based method of APB 25 to measure
stock based compensation. If the Company had used the fair value
method required by SFAS 123, the Company's net income (loss) and per
share information would approximate the following amounts:
2000 1999 1998
------------------------- ------------------------- ------------------------
As Reported Pro Forma As Reported Pro Forma As Reported Pro Forma
---------- --------- ----------- --------- ----------- ---------
SFAS 123 compensation cost $ $ 265,620 $ $ 312,749 $ $ 128,210
APB 25 compensation cost $ $ $ $ $ $
Net income (loss) $ 352,774 $ 87,154 $(2,269,506) $(2,582,255) $(8,387,060) $(8,515,270)
Income (loss) per common
share - basic
and diluted $ .02 $ .00 $ (.34) $ (.38) $ (3.68) $ (3.73)
Other Stock Based Compensation Disclosures - continued
The effects of applying SFAS 123 as disclosed above are not
indicative of future amounts. The Company anticipates making
additional stock based employee compensation awards in the
future.
The Company utilized the Black-Sholes option pricing model to
estimate the fair value of the options and warrants (to employee
and non-employees) on the grant date. Significant assumptions
include (1) 5.75% risk free interest rate; (2) weighted average
expected life of 2000 - 4.8; 1999 - 4 years; 1998 - 4.4 years;
(3) expected volatility of 2000 - 99.82%; 1999 - 95.68%; 1998 -
70.48%; and (4) no expected dividends.
F-25
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 7. Income (Loss) Per Common Share
The following is a reconciliation of the numerators and denominators
used in computing income (loss) per share:
2000 1999 1998
---- ---- ----
Net income (loss) $ 352,774 $ (2,269,506) $ (8,387,060)
Preferred stock dividends - (450,684) (427,173)
-------- -------- --------
Income (loss) available to common
shareholders (numerator) $ 352,774 $ (2,720,190) $ (8,814,233)
Weighted-average number of shares
of common stock - basic and
diluted (denominator) 17,293,848 7,953,147 2,394,866
========== ========= =========
Income (loss) per share - basic $ .02 $ (.34) $ (3.68)
============ ============ ============
Potential dilutive securities (stock options, stock warrants and
convertible preferred stock) totaling 1,102,960 weighted average shares
in 2000 have not been considered because there is no effect on income
per common share. Potential dilutive securities (stock options, stock
warrants and convertible preferred stock) in 1999 and 1998 have not
been considered since the Company reported a net loss and, accordingly,
their effects would be antidilutive.
Note 8. Related Party Transactions
On December 1, 1992, Ray Holifield and Associates, Inc. executed an
unsecured promissory note to the Company for $118,645 with interest at 10% per
annum, due on October 1, 1993. At December 31, 1993, the note was still
outstanding. During 1994, the Company entered into an agreement with the
Holifield Trust in which Holifield will make payments on the past due note from
future oil and gas revenue. During 1995, $10,995 of interest payments were
received. At December 31, 2000 and 1999 the unsecured promissory note has been
fully reserved.
On December 1, 1992, Parkway Petroleum Company, a Ray Holifield related
company, executed an unsecured promissory note to the Company for $54,616 with
interest at 10% per annum, due on October 1, 1993. The note was issued for
amounts due from contract drilling services provided by the Company. At December
31, 1993, the note was still outstanding. During 1994, the Company entered into
an agreement with the Holifield Trust in which Holifield will make payments on
the past due note from future oil and gas revenue. During 1995, $6,250 of
interest payments were received. At December 31, 2000 and 1999, the unsecured
promissory note has been fully reserved.
On January 10, 1994, the Company entered into a consulting agreement
with Williams whereby the Company would provide management and accounting
services for $25,000 per month for a period of one year. The Company accrued the
consulting fees with an offset to deferred income until payment of the fees are
actually received. During 1994, $172,140 was recorded as consulting fee income.
Beginning in the second quarter 1994, the Company began recognizing consulting
income only as cash payments were received. Prior to the second quarter, $75,000
in consulting fee revenue was accrued. The Company has received $97,140 in
consulting fee payments. As of December 31, 1994, the receivable from Williams
of $202,860 for consulting fees has been offset by deferred income of $127,860
and a provision for doubtful accounts of $75,000. Effective January 1, 1995, the
Company received a promissory note from Williams in the amount of $202,860,
bearing interest at the rate of 10% per annum, and payable in quarterly
installments of principal and interest of $15,538.87. At December 31, 2000 and
1999, the unsecured promissory note has been fully reserved.
F-26
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 8. Related Party Transactions - continued
As of December 31, 1995, the Company had accrued compensation for two
officers of the Company totaling $54,123. On March 27, 1996, notes due April 1,
1997 were issued to these two officers for this amount. Additionally, the
Company has accrued consulting fees to ST Advisory Corp., a related party owned
by a director of the Company, totaling $12,500 for services performed in
connection with economic evaluations and non-recourse financing arrangements for
future acquisitions of oil and gas properties and other corporate development
opportunities. As of December 31, 1996, accrued compensation to one officer
totaled $10,500. At December 31, 1997, accrued compensation to three officers
totaled approximately $75,000. At December 31, 1998, accrued compensation to one
current and two former officers totaled $89,917. At December 31, 1999, accrued
compensation to one director totaled $14,392. At December 31, 2000, there was no
accrued compensation.
From July 22 to August 13, 1998, the Company advanced sums totaling
$102,000 to Gulf Coast Exploration, Inc. At December 31, 1998, the debt had been
fully reserved.
On October 1, 1998, Toro Oil Company executed an unsecured promissory
note to the Company for the purchase of 100% of WestCo for $150,000, with
interest at the prime rate per annum and due September 30, 1999. To date, no
principal payments have been received. At December 31, 1998, the promissory note
had been fully reserved.
Interest expensed on related party notes totaled approximately
$186,000, $165,400 and $154,000 for the years December 31, 2000, 1999 and 1998,
respectively.
Note 9. Income Taxes
The components of the net deferred federal income tax assets
(liabilities) recognized in the Company's balance sheet were as follows:
December 31, December 31,
2000 1999
---- ----
Deferred tax assets
Provision for bad debts $ 251,763 $ 238,078
Net operating loss carryforwards 4,056,444 4,000,998
Oil and gas properties 603,900 720,800
Capital Loss carryforwards 103,344 114,997
------- -------
Net deferred tax assets before
valuation allowance 5,014,451 5,074,873
Valuation allowance (5,014,451) (5,074,873)
---------- -----------
Net deferred tax assets (liabilities) $ - $ -
As of December 31, 2000 and 1999, the Company did not believe it
was more likely than not that the net operating loss carryforwards
would be realizable through generation of future taxable income;
therefore, they were fully reserved.
F-27
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 9. Income Taxes - continued
The following table summarizes the difference between the actual
tax provision and the amounts obtained by applying the statutory tax
rate of 34% to the loss before income taxes for the years ended
December 31, 2000, 1999 and 1998.
2000 1999 1998
---- ---- ----
Tax benefit calculated at statutory rate $ 119,943 $ (771,632) $ (2,851,601)
Increase (reductions) in taxes due to:
Effect of net operating loss carryforwards (45,176)
Effect on non-deductible expenses 43,133 50,479 66,724
Change in valuation allowance (60,422) 621,076 2,810,241
Other (57,478) 100,077 (25,364)
-------- ------- ----------
Current federal income tax provision $ - - -
============ ======= ==========
As of December 31, 2000 the Company had net operating loss
carryforwards of approximately$11,900,000 and capital loss carryforwards of
approximately $304,000, which are available to reduce future taxable income and
capital gains, respectively, and the related income tax liability. The capital
loss carryforward expires in 2003. The net operating loss carryforward expires
at various dates through 2019.
Note 10. Commitments and Contingencies
Oil and Gas Hedging Activities
As a result of the April 2000 financing (See Note 2), the Company
entered into an agreement with an energy lender, commencing in May
2000, to hedge a portion of its oil and gas sales for the period of May
2000 through April 2004. The agreement calls for the initial volumes of
7,900 barrels of oil and 62,200 Mcf of gas per month, decling monthly
thereafter. Volumes at December 31, 2000 had declined to 6,200 barrels
of oil and 49,800 Mcg of gas. As a result of this agreement, the
Company realized a reduction in revenues of $1,200,794 for the
twelve-month period ended December 31, 2000, which is included in oil
and gas sales.
Lease Obligations
The Company leases office space at one location under a three (3)
year lease which commenced January 1, 1999. Annual commitments under
the lease are: 1999 - $38,353, 2000 - $51,829 and 2001 - $54,055.
Litigation
The Company is involved in other litigation and disputes.
Management believes such claims are without merit with respect to the
Company or are adequately covered by insurance and has concluded the
ultimate resolution of such disputes will not have a material effect on
the Company's consolidated financial statements.
F-28
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 11. Oil and Gas Reserves Information (Unaudited)
The estimates of proved oil and gas reserves utilized in the
preparation of the financial statements are estimated in accordance
with guidelines established by the Securities and Exchange Commission
and the Financial Accounting Standards Board, which require that
reserve estimates be prepared under existing economic and operating
conditions with no provision for price and cost escalations over
prices and costs existing at year end except by contractual
arrangements.
The Company emphasizes that reserve estimates are inherently
imprecise. Accordingly, the estimates are expected to change as more
current information becomes available. The Company's policy is to
amortize capitalized oil and gas costs on the unit of production
method, based upon these reserve estimates. It is reasonably possible
that, because of changes in market conditions or the inherent
imprecision of these reserve estimates, that the estimates of future
cash inflows, future gross revenues, the amount of oil and gas
reserves, the remaining estimated lives of the oil and gas properties,
or any combination of the above may be increased or reduced in the
near term. If reduced, the carrying amount of capitalized oil and gas
properties may be reduced materially in the near term.
The following unaudited table sets forth proved oil and gas
reserves, all within the United States, at December 31, 2000, 1999,
and 1998, together with the changes therein.
Crude Oil Natural Gas
(Bbls) (Mcf)
------------- ------------
QUANTITIES OF PROVED RESERVES:
Balance December 31, 1997 4,676,427 6,195,358
Revisions (2,317,025) (845,166)
Extensions, discoveries, and additions 21,306 65,751
Purchases 177,416 2,958,550
Sales (1,375,820) (1,518,913)
Production (98,157) (200,225)
----------- -----------
Balance December 31, 1998 1,084,147 6,655,355
Revisions 1,184,623 (754,478)
Extensions, discoveries, and additions 343,857 2,917,613
Purchase 781,942 10,835,725
Sales - -
Production (79,661) (467,350)
----------- -----------
Balance December 31, 1999 3,314,908 19,186,865
Revisions 433,409 1,478,834
Extensions, discoveries, and additions 501,293 1,509,014
Purchases 490,600 3,748,845
Sales - -
Production (165,031) (1,111,639)
---------- -----------
Balance December 31, 2000 4,575,179 24,811,919
========= ===========
PROVED DEVELOPED RESERVES:
December 31, 1998 769,862 3,866,308
========= =========
December 31, 1999 1,569,750 9,316,529
========= =========
December 31, 2000 2,883,641 15,141,979
========= ==========
F-29
GULFWEST OIL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 11. Oil and Gas Reserves Information (Unaudited) - continued
STANDARDIZED MEASURE:
Standardized measure of discounted future net cash flows relating to
proved reserves:
2000 1999 1998
---- ---- ----
- ---
Future cash inflows $ 318,504,931 $ 119,006,567 $ 22,260,688
Future production and development costs
Production 97,465,972 42,544,454 10,379,070
Development 13,400,359 9,903,729 2,935,160
---------- --------- ---------
Future cash flows before income taxes 207,638,600 66,558,384 8,946,458
Future income taxes (56,466,527) (11,847,076) (0)
----------- ---------- ---------
Future net cash flows after income taxes 151,172,073 54,711,308 8,946,458
10% annual discount for estimated
timing of cash flows (60,790,946) (23,755,909) (3,756,850)
Standardized measure of discounted
future net cash flows $ 90,381,127 $ 30,955,399 $ 5,189,608
============= ============= =============
The following reconciles the change in the standardized measure of
discounted future net cash flows:
Beginning of year $ 30,955,399 $ 5,189,608 $ 20,763,261
Changes from:
Purchases 18,483,582 14,211,998 1,619,804
Sales (7,563,199)
Extensions, discoveries and improved
recovery, less related costs 10,727,329 4,798,128 258,112
Sales of oil and gas produced net of
production costs (5,068,349) (1,133,594) (156,818)
Revision of quantity estimates 7,365,348 7,363,300 (7,584,033)
Accretion of discount 3,765,842 518,961 2,553,324
Change in income taxes (27,056,577) (6,703,020) 4,769,976
Changes in estimated future
development costs (504,445) (1,434,291) (677,160)
Development costs incurred that
reduced future development costs 4,359,405 1,012,141 1,786,900
Change in sales and transfer prices,
net of production costs 38,543,222 6,348,062 (11,523,635)
Changes in production rates (timing)
and other 8,810,371 784,106 943,076
--------- ------- -------
End of year $ 90,381,127 $ 30,955,399 $ 5,189,608
============= ============ ===========
F-30
INDEPENDENT AUDITOR'S REPORT
Stockholders and Board of Directors
GULFWEST OIL COMPANY
Our report on the consolidated financial statements of
GulfWest Oil Company and Subsidiaries as of December 31,
2000 and 1999 and for each of the three years in the
period ended December 31, 2000, is included on page F-1.
In connection with our audit of such financial statements,
we have also audited the related financial statement
schedule for the years ended December 31, 2000, 1999 and
1998 on page F-32.
In our opinion, the financial statement schedule referred
to above, when considered in relation to the basic
consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information
required to be included therein.
\s\ WEAVER AND TIDWELL, L.L.P.
- ------------------------------
WEAVER AND TIDWELL, L.L.P.
Dallas, Texas
March 9, 2001
F-31
GULFWEST OIL COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
BALANCE BALANCE
AT BEGINNING AT END
OF PROVISIONS/ RECOVERIES/ OF
DESCRIPTION PERIOD ADDITIONS DEDUCTIONS PERIOD
- ----------- ------ --------- ---------- ------
>
For the year ended
December 31, 1998:
Accounts and notes receivable
- related parties $ 448,230 $ 252,000 $ $ 700,230
=========== =========== ========= ============
Valuation allowance for
deferred tax assets $ 1,643,556 $ 2,810,241 $ $ 4,453,797
=========== =========== ========== ============
For the year ended
December 31, 1999:
Accounts and notes receivable -
related parties $ 700,230 $ $ $ 700,230
=========== =========== ========== ============
Valuation allowance for
deferred tax assets $ 4,453,797 $ 621,076 $ $ 5,074,873
=========== =========== ========== ============
For the year ended
December 31, 2000:
Accounts and notes receivable -
related parties $ 700,230 $ 40,248 $ $ 740,478
=========== =========== ========== ============
Valuation allowance for
deferred tax assets $ 5,074,873 $ 50,678 $ $ 5,125,551
=========== =========== ========== ============
F-32
Exhibit 22.1
Subsidiaries of the Registrant
GulfWest Oil Company has eight wholly owned subsidiaries, all Texas corporations
or companies:
1. GulfWest Oil & Gas Company was organized February 18, 1999 and
is the owner of record of interests in certain crude oil and
natural gas properties located in Colorado and Texas.
2. SETEX Oil and Gas Company was organized August 11, 1998 and is
the operator of crude oil and natural gas properties in which
we own the majority working interest.
3. LTW Pipeline Co. was organized April 19, 1999, is the owner
and operator of certain natural gas gathering systems
and pipelines that we own, and markets the natural gas
produced from our properties.
4. RigWest Well Service, Inc. was organized September 5, 1996
and operates well servicing equipment for us and under
contract for other operators.
5. Southeast Texas Oil and Gas Company, L.L.C. was acquired
by us on September 1, 1998 and is the owner of record of
interests in certain crude oil and natural gas properties
located in three Texas counties.
6. DutchWest Oil Company was organized July 28, 1997 and is the
owner of record of interests in certain crude oil and natural
gas properties located in Hardin and Polk Counties, Texas.
7. GulfWest Development Company was organized November 9, 2000
and is the owner of record of interests in certain crude oil
and natural gas properties located in Texas, Oklahoma and
Mississippi.
8. GulfWest Texas Company was organized September 23, 1996 and was
the owner of interests in certain crude oil and natural gas
properties located in the Vaughn Field, Crockett County, Texas.
Effective April 1, 2000, these properties were assigned to
GulfWest Oil & Gas Company to facilitate financing.