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, 2001
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 Energy Inc.
(Exact name of registrant as specified in its charter)
Texas 87-0444770
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
480 N. Sam Houston Parkway East, Suite 300
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
$3,968,219 on April 4, 2002.
Indicate the number of shares outstanding of each of the Registrant's
classes of common stock: Class A Common Stock $.001 par value: 18,492,451 shares
on April 4, 2002.
DOCUMENTS INCORPORATED BY REFERENCE:
The registrant's definitive Proxy Statement pertaining to the 2002 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.
<PAGE>
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,
2001, our part of the estimated proved reserves these properties contain was
approximately 5.9 million barrels (MBbl) of oil and 39.3 billion cubic feet
(Bcf) of natural gas with a Present Value discounted 10% (PV-10) of $56.5
million. At present, all of our properties are located on land in Texas,
Colorado, Louisiana and Oklahoma, except for the property on Grand Lake,
Louisiana. 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
28.
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. On May 21, 2001, we changed our name to
GulfWest Energy Inc.
Our principal office is located at 480 North Sam Houston Parkway East,
Suite 300, Houston, Texas 77060 and our telephone number is (281) 820-1919.
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GulfWest Energy Inc. has nine wholly owned subsidiaries:
1. GulfWest Oil & Gas Company, a Texas corporation, 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, a Texas corporation, 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., a Texas corporation, 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., a Texas corporation, 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., a Texas company,
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, a Texas corporation, was organized July 28,
1997 and is the owner of record of interests in certain crude oil
and natural gas properties located along the Gulf Coast of Texas.
7. GulfWest Development Company, a Texas corporation, 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, a Texas corporation, was organized Septem-
ber 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.
9. GulfWest Oil & Gas Company (Louisiana) LLC, a Louisiana
company, was formed July 31, 2001 and is the owner of record of
interests in certain crude oil and natural gas properties in
Louisiana.
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 properties in four crude oil and
natural gas fields in Texas and Louisiana in the year 2001. 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.
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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.
Significant Operating Control. Currently, we are the operator of all the
wells, except one, 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, 2001, our reserves were
comprised of 47% crude oil and 53% 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 included significant acreage for prospective oil
and gas exploration. These include producing wells and acreage in Crockett,
Grimes, Hardin, Jim Wells, Kimble, Madison, Palo Pinto, Refugio, Sutton, Wharton
and Zavala, Counties, Texas; Adams, Arapaho, Elbert and Weld Counties, Colorado;
Creek County, Oklahoma; and, Cameron Parish, Louisiana. 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 April 4, 2002, we had 64 full time salaried and contract employees, of
whom 49 were field personnel.
Our Executive Officers.
See Item 10 of this report, which information is incorporated herein by
reference.
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<PAGE>
ITEM 2. Our Properties.
At December 31, 2001, we owned an average 92% working interest in 290 gross
wells (268 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 5.9 million barrels (MBbl) of oil and 39.3 billion cubic feet
(Bcf) of natural gas. Substantially all of our properties are located in Texas,
Colorado, Louisiana and Oklahoma.
Proved Reserves.
The following table reflects our estimated proved reserves at December 31
for each of the preceding three years.
2001 2000 1999
---- ---- ----
Crude Oil (MBbl)
Developed 3,940 2,884 1,570
Undeveloped 1,932 1,692 1,745
----- ----- -----
Total 5,872 4,576 3,315
===== ===== =====
Natural Gas (MMcf)
Developed 21,204 15,142 9,317
Undeveloped 18,054 9,670 9,870
------ ----- -----
Total 39,258 24,812 19,187
====== ====== ======
Total (MBOE) 12,415 8,711 6,513
====== ====== ======
(a) Approximately 60% of our total proved reserves were classified as
proved developed at December 31, 2001.
(b) Barrel of Oil Equivalent (BOE) is based on a ratio of 6,000 cubic feet
of natural gas for each barrel of oil.
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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.
2001 2000 1999
-------------------- -------------------- --------------------
Future cash inflows $ 199,162,921 $ 318,504,931 $ 119,006,567
Future production and development costs-
Production 77,526,278 97,465,972 42,544,454
Development 23,610,596 13,400,359 9,903,729
-------------------- -------------------- --------------------
Future net cash flows before income taxes 98,026,047 207,638,600 66,558,384
Future income taxes (13,281,358) (56,466,527) (11,847,076)
-------------------- -------------------- --------------------
Future net cash flows after income taxes 84,744,689 151,172,073 54,711,308
10% annual discount for estimated timing
of cash flows (35,895,306) (60,790,946) (23,755,909)
-------------------- -------------------- -------------------
Standardized measure of discounted
Future net cash flows(1) $ 48,849,383 $ 90,381,127 $ 30,955,399
================== ================= ===================
(1) The average prices of our proved reserves were $17.67 per Bbl and $2.43
per Mcf, $23.81 per Bbl and $8.45 per Mcf, and $22.80 per Bbl and $2.19 per Mcf
at December 31, 2001, 2000 and 1999, respectively.
Significant Properties.
Summary information on our properties with proved reserves is set forth
below as of December 31, 2001.
Productive Wells Proved Reserves (1) Present
------------------------------- ------------------------------------------ --------
Gross Net Value (1)
---------
Productive Productive Crude Natural
Wells Wells Oil Gas Total Amount
--------- ----------- --- --- ----- ------
(MBbl) (MMcf) (MBOE) ($M)
Texas 207 199.26 3,468 19,183 6,665 $ 29,132
Colorado 39 26.57 480 9,185 2,011 5,949
Oklahoma 27 27.00 68 251 110 487
Louisiana 16 15.08 1,839 10,639 3,612 20,819
Mississippi 1 .38 17 - 17 112
--------- --------- ----- ------ ------ ---------
Total 290 268.29 5,872 39,258 12,415 $ 56,499
========= ========= ===== ====== ====== =========
(1) The average prices of our proved reserves were $17.67 per Bbl and $2.43
per Mcf at December 31, 2001.
6
<PAGE>
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, 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
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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, 2001 2000
and 1999.
2001 2000 1999
---------------- ---------------- ----------------
Production
Oil (Bbl) 294,276 165,031 79,661
Natural gas (Mcf) 1,594,899 1,111,639 467,350
Total (BOE) 560,092 350,304 157,553
Revenue
Oil production $ 6,690,338 $ 4,320,943 $ 1,565,200
Natural gas production 5,735,765 4,124,989 968,104
---------------- ---------------- ----------------
---------------- ---------------- ----------------
Total $ 12,426,103 $ 8,445,932 $ 2,533,304
Operating Expenses $ 5,155,500 $ 3,377,583 $ 1,399,710
Production Data
Average sales price
Per barrel of oil $ 22.73 $ 26.18 $ 19.65
Per Mcf of natural gas 3.60 3.71 2.07
Per BOE 22.19 24.11 16.08
Average expenses per BOE
Lease operating 9.20 9.64 8.88
Depreciation, depletion and
amortization 4.45 3.83 4.47
General and administrative $ 3.05 $ 4.53 $ 12.59
Productive Wells at December 31, 2001:
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 118 120.11 89 79.15
Colorado 18 11.42 21 15.15
Oklahoma 27 27.00 - -
Louisiana 14 13.08 2 2.00
Mississippi 1 .38 - -
------------ ------------ ------------- ------------
Total 178 171.99 112 96.30
============ ============ ============= ============
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Developed Acreage at December 31, 2001.
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 19,440 14,936
Colorado 5,000 2,700
Louisiana 1,560 1,560
Oklahoma 1,200 912
------- -------
Total 27,200 20,108
======= =======
Undeveloped Acreage at December 31, 2001.
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 23,900 18,479
Louisiana 630 630
Colorado 20,000 14,175
------ ------
Total 44,530 33,284
====== ======
Drilling Results.
We have not drilled any exploratory wells in the past three years. We
drilled three wells in 2001 and six in 2000, all of which were development wells
and are currently productive. These development wells included six 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.
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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.
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.
10
<PAGE>
We were profitable for the year 2001, 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.
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 40% of our total estimated proved reserves at December 31,
2001 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, 2001. The average prices of all properties were $17.67 per barrel
of oil and $2.43 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
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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.
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.
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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.
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
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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.
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 April 4, 2002, we had a total of 8,000 shares of our Series D
Preferred Stock and 9,000 shares of our Series E Preferred Stock issued and
outstanding, both par value $.01 and liquidation value $500 per share. The
Series D and E Preferred Stock are senior to our common stock regarding
liquidation. The holders of the preferred stock do not have voting rights or
preemptive rights nor are they subject to the benefits of any retirement or
sinking fund.
The Series D Preferred Stock is not entitled to dividends, nor is it
redeemable, however it is convertible to common stock at anytime following
December 31, 2002, the third anniversary of the issue date. 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.
The Series E Preferred Stock is entitled to receive dividends at the rate
of $12.50 per share per annum, payable quarterly. The Series E Preferred Stock
is redeemable in whole or in part at any time, at our option, at a price of $500
per share, plus all accrued and undeclared or unpaid dividends; except that,
after two years from the date of the original issuance and prior to redemption
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<PAGE>
of remaining shares by the Company, the holders of record shall be given a
60-day written notice of our intent to redeem and the opportunity to convert the
Series E Preferred Stock to common stock. The conversion price for the Series E
Preferred Stock shall be $2.00 per share of common stock. At April 4, 2002, none
of the 9,000 outstanding shares of Series E Preferred Stock had been redeemed or
converted. On a fully converted basis, the 9,000 shares of Series E Preferred
Stock would convert to 2,250,000 shares of common stock.
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 April 4, 2002, there were 18,492,451 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 April 4, 2002, we had outstanding warrants and options for the purchase of
2,338,754 shares of common stock at prices ranging from $.75 to $6.00 per share,
including employee stock options to purchase 1,032,000 shares at prices ranging
from $.75 to $1.81 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.
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 April 4, 2001, 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, 2001.
15
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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 2001, 2000
and 1999 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
---- ---
2001
----
First Quarter $1.46 $.39
Second Quarter 1.01 .53
Third Quarter .96 .48
Fourth Quarter .72 .58
2000
----
First Quarter 1.81 .75
Second Quarter 2.00 1.25
Third Quarter 1.63 1.13
Fourth Quarter 1.69 .88
1999
----
First Quarter 2.63 1.88
Second Quarter 1.00 .38
Third Quarter .75 .38
Fourth Quarter .94 .63
We are authorized to issue 40,000,000 shares of Class A common stock, par
value $.001 per share (the "common stock"). As of April 4, 2002, there were
18,492,451 shares of 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 dividend
rate, voting rights and other rights, preferences and restrictions of each such
series. As of April 4, 2002, we had a total of 17,000 shares of preferred stock
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issued and outstanding, including 8,000 of our Series D and 9,000 of our Series
E Preferred Stock. The Series D and E Preferred Stock are senior to our common
stock regarding liquidation. The holders of the preferred stock do not have
voting rights or preemptive rights nor are they subject to the benefits of any
retirement or sinking fund.
The Series D Preferred Stock is not entitled to dividends, nor is it
redeemable, however it is convertible to Common Stock at anytime following
December 31, 2002, the third anniversary of the date of issue. 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.
The Series E Preferred Stock is entitled to receive dividends at the rate
of $12.50 per share per annum, payable quarterly. The Series E Preferred Stock
is redeemable in whole or in part at any time, at our option, at a price of $500
per share, plus all accrued and undeclared or unpaid dividends; except that,
after two years from the date of the original issuance and prior to redemption
of remaining shares by the Company, the holders of record shall be given a
60-day written notice of our intent to redeem and the opportunity to convert the
Series E Preferred Stock to common stock. The conversion price for the Series E
Preferred Stock shall be $2.00 per share of common stock. At April 4, 2002, none
of the 9,000 outstanding shares of Series E Preferred Stock had been redeemed or
converted. On a fully converted basis, the 9,000 shares of Series E Preferred
Stock would convert to 2,225,000 shares of common stock.
Outstanding Options and Warrants.
At April 4, 2002, we had outstanding warrants and options for the purchase
of 2,338,754 shares of common stock at prices ranging from $.75 to $6.00 per
share, including employee stock options to purchase 1,032,000 shares at prices
ranging from $.75 to $1.81 per share.
Recent Sales of Unregistered Securities.
During 2001, we sold and issued the following shares of common or preferred
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
accredited investors not affiliated with the company or consultants. No
underwriters were used and no underwriting discounts or commissions were paid in
any of the sales.
Number of
Date Security Purchaser Shares Consideration
---- -------- --------- ------ -------------
04/30/01 Common Property Seller 17,500 Exchange for oil and gas
properties
08/07/01 Preferred Property Seller 9,000 Exchange for oil and gas
properties
08/16/01 Common Consultants 10,000 Consulting fees
10/25/01 Common Property Seller 20,000 Exchange for oil and gas
properties
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, consultants 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 Derivative Grantee(s) Shares Price Consideration
---- ---------- ---------- ------ ----- -------------
05/18/01 Option Employees 184,000 $.83 Compensation
08/16/01 Warrant Consultants 156,000 $.75 Fees
17
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ITEM 6. Selected Financial Data.
The following table sets forth selected historical financial data of our
company as of December 31, 2001, 2000, 1999, 1998 and 1997, 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, 2001, 2000 and 1999 and the
balance sheet data at December 31, 2001 and 2000 are derived from our audited
financial statements contained elsewhere herein. The income statement data for
the years ended December 31, 1998 and 1997 and the balance sheet data at
December 31, 1999, 1998 and 1997 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,
--------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
----------------- ----------------- ----------------- ----------------- -----------------
Income Statement Data
---------------------
Operating Revenues $ 12,990,581 $ 8,984,175 $ 2,812,639 $ 2,403,553 $ 4,960,966
Net income (loss) from
operations 3,451,875 2,464,017 (1,464,094) (6,329,884) (598,320)
Net income (loss) 576,709 352,774 (2,269,506) (8,387,060) (1,676,681)
Dividends on preferred stock (56,250) - (450,684) (427,173) (380,928)
Net income (loss) available to
Common Shareholders 520,459 352,774 (2,720,190) (8,814,233) (2,057,609)
Net income (loss), per share
of common stock $ .03 $ .02 $ (.34) (3.68) $ (1.19)
Weighted average number of
shares of common stock
outstanding 18,464,343 17,293,848 7,953,147 2,394,866 1,725,926
Balance Sheet Data
------------------
Current assets $ 2,205,862 $ 2,934,804 $ 1,357,465 $ 820,984 $ 1,536,396
Total assets 50,911,627 32,374,128 20,009,793 8,058,827 17,089,855
Current liabilities 12,492,365 7,594,986 4,650,691 6,559,393 2,879,256
Long-term obligations 26,541,957 18,077,371 11,304,318 3,401,371 12,185,055
Stockholders' Equity
(Deficit) $ 11,877,305 $ 6,701,771 $ 4,054,784 $ (1,901,937) $ 2,025,544
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<PAGE>
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, 2001 Compared to Year Ended December 31, 2000
Revenues
Oil and Gas Sales. Our operating revenues from the sale of crude oil and
natural gas increased by 47% from $8,446,000 in 2000 to $12,426,000 in 2001, due
to increased oil and gas production from development projects and acquisitions
of additional properties.
Well Servicing Revenues. Revenues from our well servicing operations
decreased by 10% from $188,000 in 2000 to $169,000 in 2001. This decrease was
due to higher rig utilization on operated properties where the Company has
working interest partners and less work for third parties.
Operating Overhead and Other Income. Revenues from these activities
increased 13% from $350,000 in 2000 to $395,000 in 2000. Major components of the
increase included operating overhead $81,800, gathering and marketing $210,900,
sale of exploratory leases $96,300 and miscellaneous income $6,000.
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<PAGE>
Costs and Expenses
Lease Operating Expenses. Lease operating expenses increased 53% from
$3,378,000 in 2000 to $5,155,000 in 2001. This increase in operating expenses
was due to the acquisitions of additional properties, expanded oil and gas
production, and increased vendor prices.
Cost of Well Servicing Operations. Well servicing expenses decreased 14%
from $212,000 in 2000 to $182,000 in 2001. This decrease in expenses was due to
less utilization of our equipment under contract to third parties.
Depreciation, Depletion and Amortization (DD&A). DD&A increased 86%
from $1,342,000 in 2000 to $2,491,000 in 2001, due to significantly higher
production resulting from successful field development activities and
acquisitions.
General and Administrative (G&A) Expenses. G&A expenses increased
8% from $1,588,000 in 2000 to $1,710,000 in 2001 due to the increased number of
properties being managed.
Interest Expense and Dividends on Preferred Stock. Interest expense
increased 29% from $2,135,000 in 2000 to $2,757,000 in 2001 due to increased
debt associated with the funding of our additional acquisitions and capital
development program.
Dividends on preferred stock due was $56,250 and paid was $28,125 in 2001.
No dividends were due or paid in 2000.
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.
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
less work under contract to third parties.
20
<PAGE>
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.
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.
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<PAGE>
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.
Financial Condition and Capital Resources.
At December 31, 2001, our current liabilities exceeded our current assets
by $10,286,503. We had a profit of $576,709 compared to a profit of $352,774 at
December 31, 2000. The profit in the year 2001was attributed to increased
production from development projects and additional acquisitions.
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. On August 16, 2001, the total amount of financing
increased by $16,800,000 to $36,102,000. The proceeds are to be used as follows:
$10,000,000 for the Goldking Acquisition (see below), $6,630,000 for development
of the properties securing the loan and $170,000 for a structuring fee paid to
the lender. As a result of the amendment, the net revenue increased from 85% to
90%. In addition, the amendment requires payments on principal of $1,000,000 in
February, 2002, August 2000 and February, 2003
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 $4,230,000 in the year 2001. We will continue our
development plans in 2002 with the remaining $5,000,000. 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.
On August 17, 2001, we purchased several oil and natural gas properties
located in four fields in Texas and Louisiana (the "Goldking Acquisition"). The
effective date of the acquisition was July 1, 2001. The acquired properties are
currently producing an aggregate 600 barrels of oil and 1,200 Mcf of natural gas
per day, with total proved reserves (net to the acquired interests) estimated at
1.2 million barrels of oil and 9.5 billion cubic feet of natural gas. There are
additional possible reserves estimated at 10 billion cubic feet of natural gas.
The purchase price of the acquisition was $15 million in a combination of notes
payable, preferred stock, cash, warrants and common stock. Financing was
arranged through an existing credit facility and included expanding the
company's credit line to continue the development of its properties through the
year 2002.
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<PAGE>
Effective December 1, 200l, we entered into an Oil and Gas Property
Acquisition, Exploration and Development Agreement (the "Summit Agreement") with
Summit Investment Group-Texas, L.L.C., an unrelated party, ("Summit"). Under the
agreement, Summit will provide or makes available to us payments in the
aggregate of $1,200,000 in advanced funds (the Advanced Funds") for our use in
the acquisition of oil and gas leases and other mineral and royalty interests in
order that we may conduct specified oil and gas exploration and production
activities. We will pay Summit a sourcing fee of $100,000 and expenses of
$100,000 from the Advanced Funds. We agree to drill four (4) wells located on
oil and gas properties acquired under the Summit Agreement (the "Obligation
Wells") and to commence such drilling prior to the expiration of two (2) years
from the effective date of the Summit Agreement. We will pay Summit $175,000 on
or before the date of commencement of drilling of each Obligation Well and
Summit shall assign us its interest in the applicable oil and gas leases
attributable to the production unit for such well. We further agree to conduct
well workover operations on certain existing wells acquired by us, which are
located on lands described in the Summit Agreement, all such well workover
operations to be completed within nine (9) months of the Effective Date. Summit
will reserve a 2.5% overriding royalty interest in the drilling prospect leases
and a 25% net profits interest in the workover leases.
The Advanced Funds shall be recouped by Summit in the following manner:
(a) A total of $500,000.00 shall be repaid out of an undivided 40% of the
"Summit Net Profits Interest", defined as twenty five percent (25%) of
the monthly net sale proceeds of all oil and gas production allocable
to our interest in the pertinent oil and gas properties, as more fully
defined in the Summit Agreement. Summit will retain an 8.5% working
interest in the workover leases after payment of the $500,000.
(b) We shall pay $175,000 in cash to Summit on the date we commence
drilling each Obligation Well; or
(c) By virtue of a lump sum production payment by us.
If, at the expiration of two (2) years from the Effective Date, Summit has
not completely recouped the Advanced Funds from the payments referred to in (a),
(b) and (c) above, then Summit, at its sole election, may require that we issue
to it a quantity of our Common Stock equivalent to the quotient of the
outstanding Advanced Funds (numerator) and $2.00 per share (denominator). Upon
issuance of such stock to Summit, Summit shall assign to us all its interest in
the remaining oil and gas properties within the subject area, reserving its
overriding royalty interest in the properties.
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.
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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)
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
2001
----
First $ 24.15 $ 5.27 $ 27.87
Second 24.14 3.88 23.71
Third 23.25 3.08 21.08
Fourth 19.94 2.62 17.96
ITEM 7a. Qualitative and Quantitative Disclosures About Market Risk.
Information with respect to this Item 7a is contained in Item 1 "Risk
Factors".
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
24
<PAGE>
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) 54 Chairman of the Board 1989
Thomas R. Kaetzer(3) 43 Chief Executive Officer 1998
President and Director
Jim C. Bigham 66 Executive Vice President 1991
and Secretary
Richard L. Creel 53 Vice President of Finance 1998
and Controller
William T. Winston 35 Director 2000
John E. Loehr(1)(2)(3) 56 Director 1992
J. Virgil Waggoner(1)(2)(3) 74 Director 1997
Steven M. Morris(1)(2) 50 Director 2000
John P. Boylan(1) 35 Director 2001
(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.
25
<PAGE>
Jim C. Bigham has served as secretary since 1991 and as executive vice
president of GulfWest since 1996. 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 served as vice
president from May 2000 until March 29, 2002. He became a director in August
2001. While vice president, he was 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, was chairman
of the board from September 1, 1993 to July 8, 1998 and was 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.
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 chief executive officer of JVW Investments, Ltd., a private company.
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.
John P. Boylan was appointed a director of GulfWest on August 7, 2001. Mr.
Boylan has served as Managing Partner and Chief Executive Officer of Birdwell
Partners, L.P., the parent company and General Partner of Five Star
Transportation, Superior Trucking Company and American Pipe Inspection Company
since 1999. He began his career in the oil and gas industry in 1993 providing
venture funding for lease acquisition and drilling projects, and from 1996 to
present has been actively involved in the management of an independent
exploration and production company. His experience covers most of the
management, finance and non-technical aspects of the oilfield services, as well
as the upstream oil and gas exploration and production industry. He has had
experience in all of the major producing trends covering the Texas Gulf Coast
and South Texas. In 1995, he received the degree of Master of Business
26
<PAGE>
Administration, with majors in Finance, Economics and International Business
from the Leonard N. Stern Graduate School of Business of New York University. He
received the degree of Bachelor of Business Administration, with a major in
Accounting, from the University of Texas in 1988. Mr. Boylan has been a
Certified Public Accountant in the State of Texas since 1991.
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 seven times during the calendar year ended
December 31, 2001.
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 2001 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. J. Virgil Waggoner, Mr. John P. Boylan and Mr. Steven M.
Morris. The committee met twice in 2001.
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. John E. Loehr
and Mr. Steven M. Morris. The committee met twice in 2001.
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. Marshall A. Smith III
(Chairman), Mr. J. Virgil Waggoner, Mr. John E. Loehr and Mr. Thomas R. Kaetzer.
The committee met twice in 2001.
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 2001.
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.
27
<PAGE>
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
28
<PAGE>
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.
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.
29
<PAGE>
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.
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.
30
<PAGE>
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, 2001 and 2000.
Consolidated Statements of Operations for the years ended
December 31, 2001, 2000 and 1999.
Consolidated Statements of Stockholders' Equity for the years
ended December 31, 2001, 2000 and 1999.
Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999.
Notes to Consolidated Financial Statements, December 31, 2001,
2000 and 1999.
(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 1, 2001 and
approved by the shareholders on May 18, 2001.
22.1 Subsidiaries of the Registrant filed herewith.
25 Power of Attorney (included on signature page of this
Annual Report).
# Previously filed with our Form 8-K, Current Report dated
December 31, 1999, filed with the Commission on January
10,2000.
* Previously filed with our Registration Statement (on Form
S-1, Reg. No. 33-53526), filed with the Commission on
October 21, 1992.
% Previously filed with our Proxy Statement on Form DEF 14A,
filed with the Commission on April 16, 2001. 31
<PAGE>
(b) Reports on Form 8-K.
None.
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 ENERGY INC.
Date: April 4, 2002 By:/s/Thomas R. Kaetzer
-------------------------------
Thomas R. Kaetzer, President
32
<PAGE>
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 Chairman of the Board April 4, 2002
----------------------
Marshall A. Smith III
\s\ Thomas R. Kaetzer President, Chief Executive Officer April 4, 2002
----------------------
Thomas R. Kaetzer and Director
\s\ Jim C. Bigham Executive Vice President and Secretary April 4, 2002
----------------------
Jim C. Bigham
\s\ Richard L. Creel Vice President of Finance, Controller April 4, 2002
----------------------
Richard L. Creel
\s\ William T. Winston Director April 4, 2002
----------------------
William T. Winston
\s\ J. Virgil Waggoner Director April 4, 2002
----------------------
J. Virgil Waggoner
\s\ John E. Loehr Director April 4, 2002
----------------------
John E. Loehr
\s\ John P. Boylan Director April 4, 2002
----------------------
John P. Boylan
\s\ Steven M.Morris Director April 4, 2002
----------------------
Steven M. Morris
33
<PAGE>
GULFWEST ENERGY INC.
FINANCIAL REPORT
DECEMBER 31, 2001
<PAGE>
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.
<PAGE>
INDEPENDENT AUDITOR'S REPORT
To the Stockholders and
Board of Directors
GULFWEST ENERGY INC.
We have audited the accompanying consolidated balance sheets of GulfWest Energy
Inc. (a Texas Corporation) and Subsidiaries as of December 31, 2001 and 2000,
the related consolidated statements of operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 2001. 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 Energy Inc. and Subsidiaries as of December 31, 2001 and 2000, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 2001, 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
April 4, 2002
F-1
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2001 AND 2000
ASSETS
2001 2000
---- ----
CURRENT ASSETS
Cash and cash equivalents $ 689,030 $ 663,032
Accounts receivable - trade, net of allowance
for doubtful accounts of $ -0-
in 2001 and 2000 1,392,751 2,188,421
Prepaid expenses 124,081 83,351
--------- ---------
Total current assets 2,205,862 2,934,804
--------- ---------
OIL AND GAS PROPERTIES,
using the successful efforts
method of accounting 52,045,178 30,895,049
OTHER PROPERTY AND EQUIPMENT 2,352,166 1,961,203
Less accumulated depreciation,
depletion, and amortization (6,235,251) (4,049,510)
---------- ----------
Net oil and gas properties and
other property and equipment 48,162,093 28,806,742
---------- ----------
OTHER ASSETS
Deposits 37,442 27,638
Investments 122,785
Debt issue cost, net 506,230 482,159
---------- ----------
Total other assets 543,672 632,582
----------- ------------
TOTAL ASSETS $50,911,627 $32,374,128
=========== ===========
The Notes to Consolidated Financial Statements are an integral part of these
statements.
F-2
<PAGE>
LIABILITIES AND STOCKHOLDERS' EQUITY
2001 2000
---- ----
CURRENT LIABILITIES
Notes payable $ 2,821,020 $ 935,300
Notes payable - related parties 40,000 700,000
Current portion of long-term debt 6,065,588 3,111,120
Current portion of long-term debt - related parties 222,687 303,296
Accounts payable - trade 3,099,399 2,189,656
Accrued expenses 243,671 355,614
------- -------
Total current liabilities 12,492,365 7,594,986
---------- ---------
LONG-TERM DEBT, net of current portion 26,330,589 17,960,455
---------- ----------
LONG-TERM DEBT - RELATED PARTIES 211,368 116,916
------- -------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock 170 80
Common stock 18,493 18,445
Additional paid-in capital 28,164,712 23,537,900
Retained deficit (16,306,070) (16,854,654)
Long-term accounts and notes receivable -
related parties, net of allowance for doubtful
accounts of $740,478 in 2001 and 2000 - -
------------ -----------
Total stockholders' equity 11,877,305 6,701,771
------------ -----------
TOTAL LIABILITIES AND
STOCKHOLDERS' EQUITY $ 50,911,627 $32,374,128
============ ===========
The Notes to Consolidated Financial Statements are an integral part of these statements.
F-3
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
2001 2000 1999
---- ---- ----
OPERATING REVENUES
Oil and gas sales $ 12,426,103 $ 8,445,932 $ 2,533,304
Well servicing revenues 169,167 188,052 116,791
Operating overhead and other income 395,311 350,191 162,544
------- ------- -------
Total Operating Revenues 12,990,581 8,984,175 2,812,639
---------- --------- ---------
OPERATING EXPENSES
Lease operating expenses 5,155,500 3,377,583 1,399,710
Cost of well servicing operations 182,180 212,286 190,399
Depreciation, depletion, and amortization 2,491,385 1,341,890 703,533
General and administrative 1,709,641 1,588,399 1,983,091
--------- --------- ---------
Total Operating Expenses 9,538,706 6,520,158 4,276,733
--------- --------- ---------
INCOME (LOSS) FROM OPERATIONS 3,451,875 2,464,017 (1,464,094)
--------- --------- ----------
OTHER INCOME AND EXPENSE
Interest income 16,082 5,162
Interest expense (2,756,912) (2,134,718) (889,796)
Gain (loss) on sale of assets (118,254) 7,393 79,222
-------- ----- ------
Total Other Income (Expense) (2,875,166) (2,111,243) (805,412)
---------- ---------- --------
INCOME (LOSS) BEFORE INCOME TAXES 576,709 352,774 (2,269,506)
INCOME TAXES
---------- ---------- --------
NET INCOME (LOSS) $ 576,709 $ 352,774 $(2,269,506)
DIVIDENDS ON PREFERRED STOCK
(PAID 2001 - $28,125; 2000 - $76,992;
1999 - $344,288) (56,250) (450,684)
NET INCOME (LOSS) AVAILABLE TO
COMMON SHAREHOLDERS $ 520,459 352,774 $ (2,720,190)
============= ============= =============
INCOME (LOSS) PER COMMON SHARE
BASIC
$ .03 $ .02 $ (.34)
============= ============= =============
DILUTED $ .03 $ .02 $ (.34)
============= ============= ==============
F-4
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
-------------------------------
Number of Shares
-------------- -- -------------
Preferred Common
Stock 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
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-5
<PAGE>
Common Preferred Additional Retained Receivables from
Stock Stock Paid-In Capital Deficit Related Parties
---------------------- -------------------- ------------------- --------------- ------------------
$ 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)
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) $ -
====================== ==================== ====================== ============= ==================
The Notes to Consolidated Financials are an integral part of these statements.
F-6
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
---------------------------------
Number of Shares
-------------- -- ---------------
Preferred Common
Stock Stock
-------------- ---------------
BALANCE, December 31, 2000 8,000 18,445,041
Issuance of 9,000 shares of Series E preferred stock for the acquisition of 9,000
assets
Issuance of 47,500 shares of common stock for the acquisition of assets 47,500
Issuance of warrants for the acquisition of assets
Net income
Dividends paid on preferred stock
-------------- ---------------
BALANCE, December 31, 2001 17,000 18,492,541
============== ===============
The Notes to Consolidated Financials are an integral part of these statements.
F-7
<PAGE>
Common Preferred Additional Retained Receivables from
Stock Stock Paid-In Capital Deficit Related Parties
---------------------- -------------------- --------------------- ---------------------- ------------------
$ 18,445 $ 80 $ 23,537,900 $ (16,854,654) $ -
90 4,499,910
48 35,402
91,500
576,709
(28,125)
---------------------- -------------------- --------------------- ---------------------- ------------------
$ 18,493 $ 170 $ 28,164,712 $ (16,306,070) $ -
====================== ==================== ===================== ====================== ==================
The Notes to Consolidated Financials are an integral part of these statements.
F-8
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
2001 2000 1999
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 576,709 $ 352,774 $ (2,269,506)
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization 2,491,385 1,341,890 703,533
Partnership loss 68,693
Common stock and warrants issued and charged to operations 15,660 234,250
(Gain) loss on sale of assets 118,254 (7,393) (79,222)
Other non-operating income (5,780)
Provision for bad debts 40,248
(Increase) decrease in accounts receivable - trade, net 765,939 (1,344,767) (447,855)
(Increase) decrease in inventory 13,925
(Increase) decrease in prepaid expenses (40,730) (3,588) (4,802)
Increase (decrease) in accounts payable and accrued expenses 797,800 1,710,769 (359,290)
------- --------- --------
Net cash provided by (used in) operating activities 4,709,357 2,099,813 (2,140,274)
--------- --------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Deposits (9,804) (10,338)
Proceeds from sale of property and equipment 394,423 14,915 155,844
Purchase of property and equipment (6,962,650) (6,126,817) (1,482,548)
---------- ---------- ----------
Net cash used in investing activities (6,578,031) (6,111,902) (1,337,042)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock, net 795,378 3,000,000
Payments on debt (6,577,928) (1,733,513) (1,300,891)
Proceeds from debt issuance 8,530,269 5,694,510 1,861,200
Debt issue cost (29,544) (368,554)
Dividends paid (28,125)
---------- ---------- ----------
Net cash provided by financing activities 1,894,672 4,387,821 3,560,309
--------- --------- ---------
INCREASE IN CASH AND CASH EQUIVALENTS 25,998 375,732 82,993
CASH AND CASH EQUIVALENTS,
beginning of year 663,032 287,300 204,307
------------- ---------- ----------
CASH AND CASH EQUIVALENTS,
end of year $ 689,030 $ 663,032 $ 287,300
=========== =========== ==========
CASH PAID FOR INTEREST $ 2,811,677 $ 2,041,630 $ 758,226
=========== =========== ==========
The Notes to Consolidated Financial Statements are an integral part of these statements.
F-9
<PAGE>
GULFWEST ENERGY INC. 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
consolidated financial statements.
Organization/Concentration of Credit Risk
GulfWest Energy Inc. 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 consolidated 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; GulfWest Development Company ("GWD") formed November 9, 2000
and GulfWest Oil & Gas Company (Louisiana) LLC, formed July 31,
2001. All material intercompany transactions and balances are
eliminated upon consolidation.
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, 2001, we
acquired $15,068,774 in property and equipment through $10,441,824 in
notes payable to financial institutions and related parties, by
issuing 9,000 shares of preferred stock valued at $4,500,000, by
issuing 47,500 shares of common stock valued at $35,450 and by issuing
150,000 warrants valued at $91,500. Also, debt issue costs increased
$170,000 in notes payable.
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.
F-10
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Statement of Cash Flows - Non-Cash Investing and Financing Activities -
continued
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
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.
Use of Estimates in the Preparation of Financial Statements
The preparation of consolidated 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 consolidated 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
F-11
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Other Property and Equipment - continued
Capitalized costs relating to other properties and equipment:
2001 2000
--------------- ----------------
--------------- ----------------
Automobiles $ 446,055 $ 448,598
Office equipment 126,690 111,477
Gathering system 529,486 481,311
Well servicing equipment 1,249,935 919,817
------------------ -------------
2,352,166 1,961,203
Less accumulated depreciation (937,488) (684,327)
------------------ -------------
Net capitalized cost $ 1,414,678 $ 1,276,876
================== =============
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, 2001, 2000, and
1999 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 earned.
Fair Value of Financial Instruments
At December 31, 2001 and 2000, 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. The partnership was dissolved during 2001 and the assets
were distributed.
Debt Issue Costs
Debt issue costs incurred are capitalized and subsequently
amortized over the term of the related debt on a straight-line basis.
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.
F-12
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Earnings (Loss) Per Share - continued
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.
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.
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 2001, 2000 and 1999 financial
statements. See Note 6 to the consolidated financial statements for
further information.
Implementation of New Financial Accounting Standards
Effective January 1, 2001, the Company adopted SFAS No. 133
"Accounting for Derivative Instruments and other Hedging Activities",
as amended by SFAS No. 137 and No. 138. Adoption of this statement had
no material effects on the Company's financial position, results of
operations or cash flows.
In June, 2001, SFAS No. 141 "Business Combinations" and SFAS No.
142 "Goodwill and Other Intangible Assets were issued. The Company
presently has no goodwill or intangible assets and is thus not
affected by SFAS No. 142.
Note 2. Operations and Management Plans
At December 31, 2001, the Company's current liabilities exceeded
its current assets by $10,286,503. The Company had a profit of
$576,709 compared to a profit of $352,774 at December 31, 2000. The
profit in the year 2001 can be attributed to increased production from
development projects and additional acquisitions.
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
F-13
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
Note 2. Operations and Management Plans - continued
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. On August 16, 2001, the total amount of financing
increased by $16,800,000 to $36,102,000. The proceeds are to be used
as follows: $10,000,000 for the Goldking Acquisition (see Note 3),
$6,630,000 for development of the properties securing the loan and
$170,000 for a structuring fee paid to the lender. As a result of the
amendment, the net revenue interest increased from 85% to 90%. In
addition, the amendment required payments on principal of $1,000,000
in February 2002, August 2002 and February 2003.
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 $4,230,000 for such projects in
the year 2001 and will continue development activities in 2002 with
the remaining $5,000,000. 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 or the inability to make
the required payments under the amended Aquila financing would have a
severe impact on the Company's plans.
F-14
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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:
2001 2000
---- ----
Unproved oil and gas properties $ 440,033 $ 384,240
Proved oil and gas properties 48,702,656 28,540,631
Support equipment and facilities 2,902,489 1,970,178
52,045,178 30,895,049
Less accumulated depreciation,
depletion and amortization (5,297,763) (3,365,182)
-------------- --------------
Net capitalized costs $46,747,415 $ 27,529,867
=========== ==============
Results of Operations for Oil and Gas Producing Activities:
2001 2000 1999
---- ---- ----
Oil and gas sales $ 12,426,103 $ 8,445,932 $ 2,533,304
Production costs (5,155,500) (3,377,583) (1,399,710)
Depreciation, depletion and amortization (2,018,890) (1,030,635) (524,295)
Income tax expense _ _ _
---------------- ---------------- ---------------
Results of operations for oil and gas
producing activities - income $ 5,251,713 $ 4,037,714 $ 609,299
================ ================ ===============
Costs Incurred in Oil and Gas Producing Activities:
2001 2000 1999
---- ---- ----
Property Acquisitions
Proved $ 15,236,808 $ 5,874,199 $ 11,006,257
Unproved 154,076 122,837 1,568
Development Costs 6,317,527 4,814,317 1,041,858
---------------- ---------------- ----------------
$ 21,708,411 $ 10,811,353 $ 12,049,683
================ ================ ================
F-15
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Cost of Oil and Gas Properties - continued
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,
2001 and 2000, and its results of operations for the years ended
December 31, 2001, 2000 and 1999 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 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.
Supplemental unaudited pro forma information (under the purchase
method of accounting) presenting the results of operations for the
years ended December 31, 1999, as if the Pozo Resources transaction
had occurred as of January 1, 1999:
Year Ended
December 31,
1999
---------------
Operating Revenues $ 3,885,644
Operating Expenses 5,169,105
---------------
Income (loss) from operations (1,283,461)
Other income and expense (2,091,662)
Income taxes -
---------------
Net income (loss) $ (3,375,123)
===============
Earnings (loss) per share - basic and diluted $ (.48)
===============
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.
F-16
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Cost of Oil and Gas Properties - continued
Effective July 1, 2001, the Company acquired interests in oil and
gas properties located in Texas and Louisiana from an unrelated party,
Grand Goldking L.L.C. The acquisition cost was $15,077,358, consisting
of 9,000 shares of Series E preferred stock valued at $4,500,000 and
$10,000,000 in debt. In addition, the Company paid $545,300 in
commissions to unrelated parties. The commissions were paid by issuing
10,000 shares of common stock valued at $8,800, 150,000 warrants
valued at $91,500 and $445,000 in cash. The Company incurred
additional cash costs of $33,058 related to the acquisition. On the
same date, the Company transferred its ownership interest in these
properties to its wholly owned subsidiary, GulfWest Oil & Gas Company.
Supplemental unaudited pro forma information (under the purchase
method of accounting) presenting the results of operations for the
years ended December 31, 2001 and 2000, as if the Grand Goldking
acquisition had occurred as of January 1, 2001 and 2000:
Year Ended Year Ended
December 31, December 31,
2001 2000
-------------- ----------------
Operating revenues $ 15,649,329 $ 16, 343,559
Operating expenses 10,652,222 9,027,278
-------------- ----------------
Income from operations 4,997,107 7,316,281
Other income and expense (3,325,166) (3,011,243)
Income taxes - -
-------------- ----------------
Net income 1,671,941 4,305,038
Preferred dividends (112,500) (112,500)
-------------- ----------------
Net income to common
shareholders $ 1,559,441 $ 4,192,538
============== =============
Earnings per share
Basic $ 0.08 $ 0.24
============== =============
============== =============
Diluted $ 0.07 $ 0.21
============== =============
Note 4. Accrued Expenses
Accrued expenses consisted of the following:
December 31, December 31,
2001 2000
-------------- ------------
Payroll and payroll taxes $ 3,910 $ 15,569
Interest 194,761 296,989
Professional fees 45,000 42,000
Sales taxes - 1,056
-------------- --------------
$ 243,671 $ 355,614
=============== ============
F-17
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Notes Payable and Long-Term Debt
Notes payable is as follows:
2001 2000
--------------- ----------------
$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; retired February, 2001. 45,000
Promissory note payable to a director of the Company at 10%; payable on
demand; unsecured; retired May, 2001. 500,000
Promissory note payable to a director of the Company at 8.5%;
due April, 2001; unsecured; retired May, 2001. 200,000
Promissory note payable to an unrelated party at 10%; payable on demand;
unsecured; retired May, 2001. 100,000
Promissory note payable to an unrelated party at 10%; due January, 2001;
unsecured; retired May, 2001. 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 40,300
Note payable to a bank at 11%; due March, 2001; secured by the
guaranty of three directors of the Company; retired March, 2001. 500,000
Note payable to a bank with monthly principal payments of $13,889; interest
at prime plus 1%; due March, 2002; secured by the guaranty of three
directors of the Company. 374,999
Promissory note payable to a director of the Company at 8%; due May, 2001;
unsecured. 40,000
Promissory note payable to an unrelated party at 10%; payable on demand;
unsecured. 115,000
Line of credit (up to $2,500,000) to a bank; due October, 2002; secured by
guaranty of a director; interest at prime rate, less .25% (prime rate
4.75% at December 31, 2001). 2,251,192
Promissory note to an unrelated party at 10%; due and retired in
January, 2002. 39,529
------------ -------------
$2,861,020 $ 1,635,300
========== =============
The weighted average interest rate for notes payable at December 31, 2001 and 2000 was 5.0% and 10.1%, respectively.
F-18
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Notes Payable and Long-Term Debt
Long-term debt is as follows:
2001 2000
--------------- ----------------
Line of credit (up to $3,000,000) to bank; due July, 2003;
secured by guaranty of a director. Interest at prime rate
(prime rate 4.75% at December 31, 2001). $2,939,515 $2,989,515
Subordinated promissory notes to various individuals at 9.5% interest
per annum; amounts include $100,000 ($120,000 - 2000) due to related
parties; past due. 200,000 245,000
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. 96,024 141,990
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. 100,591 145,716
Promissory note to a director of the Company; interest at 8.5%;
due December 31, 2003. 88,814 100,980
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; retired May, 2001. 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. 6,871 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. 9,453 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. 39,543 67,456
Note payable to an energy lender; interest at prime plus 3.5% (prime
rate 4.75% at December 31, 2001) payable monthly out of 85%
(90% beginning July, 2001) net profits from certain oil and gas properties;
final payment due May, 2004; secured by related oil and gas properties. 26,679,770 15,530,336
F-19
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Notes Payable and Long-Term Debt
Long-term debt is as follows - continued:
2001 2000
---- ----
Note payable to a bank with monthly principal payments of $15,000;
interest at prime plus 1% (prime rate 4.75% at December 31, 2001);
in October, 2001 monthly principal payments became $36,000 and
interest prime plus 1% with a minimum prime rate of 5.50%; final
payment due November, 2003; secured by related oil and gas
properties. 2,392,000 2,085,000
Note payable to unrelated party to finance salt-water disposal well with
monthly installments of $4,540, including interest at 10% per annum;
final payment due January, 2005; secured by related well. 149,325
Note payable to a related party to finance equipment with monthly
installments of $5,109, including interest at 13.75% per annum;
final payment due February, 2004; secured by related equipment. 114,324
Note payable to a related party to finance equipment with monthly
installments of $608, including interest at 11% per annum; final
payment due February, 2004; secured by related equipment. 14,002
--------------- --------------
32,830,232 21,491,787
Less current portion (6,288,275) (3,414,416)
---------------- --------------
Total long-term debt $ 26,541,957 $ 18,077,371
=============== ==============
On April 5, 2000 and August 16, 2001, 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%
(90% beginning July, 2001) 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% (90% beginning July, 2001) 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. The 2001 agreement also
requires additional payments of $1,000,000 each in February, 2002,
August, 2002 and February, 2003, which have also been incorporated
into the following table:
Estimated annual maturities for long-term debt are as follows:
2002 $ 6,288,275
2003 9,605,190
2004 16,926,077
2005 10,690
------------
$ 32,830,232
============
The February, 2002 payment was made by selling producing
properties with a carrying value at December 31, 2001 of $446,419 for
$550,000 on March 18, 2002 and by paying $450,000 in cash on April 4,
2002.
F-20
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity
Common Stock 2001 2000
------------ ------------- -------------
Par value $.001; 40,000,000 shares authorized;
18,492,541 and 18,445,041 shares issued and
outstanding as of December 31, 2001 and
2000, respectively. $ 18,493 $ 18,445
============= =============
Preferred Stock
---------------
Series D, par value $.01; 12,000 shares authorized;
8,000 issued and outstanding at December 31, 2001
and 2000. 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
Series E, par value $.01; 9,000 shares authorized; 9,000
issued and outstanding at December 31, 2001 and -0- at
December 31, 2000. The Series D preferred stock pays
dividends, as declared, at a rate of 2.5% per annum, has
a liquidation value of $500 per share, may be redeemed
at the option of the Company and, if not redeemed after
two years, is convertible to common stock at a price of
$2.00 per share of common stock. 90
--------------- ------------
$ 170 $ 80
=============== =============
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).
F-21
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity - continued
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
2,000,000 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.
2001 2000 1999
------------------------------ -------------------------- ---------------------------
Wtd Avg Wtd Avg Wtd Avg
Prices Number Prices Number Prices Number
------------ ------------- ---------- ----------- ----------- -----------
Balance, January 1 $ 1.09 923,000 $ 1.07 717,000 $ 2.52 490,000
Options issued $ .83 184,000 $ 1.17 206,000 $ .75 582,000
Options expired $ 3.00 (10,000) - - $ 2.53 (355,000)
------------- ----------- -----------
Balance, December 31 $ 1.03 1,097,000 $ 1.09 923,000 $ 1.07 717,000
============= =========== ===========
All options were exercisable at December 31, 2001. Following is a
schedule by year and by exercise price of the expiration of the Company's
stock options issued as of December 31, 2001:
2002 2003 2004 2005 2006 Thereafter Total
-------- -------- -------- -------- -------- -------- --------
$ .75 432,000 150,000 582,000
$ .83 184,000 184,000
$ 1.13 100,000 100,000
$ 1.20 106,000 106,000
$ 1.81 60,000 60,000
$ 3.00 65,000 65,000
-------- -------- -------- -------- -------- -------- --------
65,000 432,000 206,000 184,000 210,000 1,097,000
======== ======== ======== ======== ======== ========= =========
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:
2001 2000 1999
------------------------------ --------------------------- --------------------------------
Wtd Avg Wtd Avg Wtd Avg
Prices Number Prices Number Prices Number
------------ -------------- ----------- ------------ ------------ ----------------
Balance, January 1 $ 2.31 1,392,254 $ 2.53 1,369,754 $ 3.16 2,888,343
Warrants issued $ .75 150,000 $ 1.86 170,000 $ 1.09 694,254
Warrants exercised
or expired $ 2.22 (235,500) $ 2.65 (147,500) $ 2.90 (2,212,843)
-------------- ------------ ----------------
Balance, December 31 $ 2.15 1,306,754 $ 2.31 1,392,254 $ 2.53 1,369,754
============== ============ ================
F-22
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity - continued
Stock Warrants - continued
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.
Following is a schedule by year and by exercise price of the
expiration of the Company's stock warrants issued as of December 31, 2001:
2002 2003 2004 2005 2006 Total
---- ---- ---- ---- ---- -----
$ .75 166,754 520,000 686,754
.875 150,000 150,000
3.00 200,000 200,000
5.00 50,000 50,000
5.75 20,000 20,000
6.00 200,000 200,000
--------- ---------- ---------- ------------ ------------ -----------
366,754 150,000 790,000 1,306,754
========= ========== ========== ============ ============ ===========
Warrants outstanding to officers, directors and employees of the
Company at December 31, 2001 and 2000 were approximately 957,000. The
exercise prices on these warrants range from $.75 to $.88 and expire
various dates through 2006.
Other Stock Based Compensation Disclosures
------------------------------------------
During 2001, 2000 and 1999, the Company issued options and warrants
totaling 2001 - 184,000 (all exercisable); 2000 - 354,000 (all
exercisable); and 1999 - 963,754 (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:
2001 2000 1999
---- ---- ----
As Reported Pro Forma As Reported Pro Forma As Reported Pro Forma
----------- --------- ----------- --------- ----------- ---------
SFAS 123 compensation
cost $ $ 99,360 $ $ 265,620 $ $ 312,749
APB 25 compensation
cost $ $ $ $ $ $
Net income (loss) $ 576,709 $ 477,349 $ 352,774 $ 87,154 $(2,269,506) $(2,582,255)
Income (loss) per
common share - basic
and diluted $ .03 $ .02 $ (.02) $ .00 $ (.34) $ (.38)
F-23
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity - continued
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
2001 - 5.0; 2000 - 4.8; 1999 - 4 years; (3) expected volatility of
2001 - 103.27%; 2000 - 99.82%; 1999 - 95.68%, and (4) no expected
dividends.
Note 7. Income (Loss) Per Common Share
The following is a reconciliation of the numerators and
denominators used in computing income (loss) per share:
2001 2000 1999
---- ---- ----
Net income (loss) $ 576,709 $ 352,774 $ (2,269,506)
Preferred stock dividends (56,250) - (450,684)
------------ ------------ ------------
Income (loss) available to common
shareholders (numerator) $ 520,459 $ 352,774 $ (2,720,190)
============ ============ =============
Weighted-average number of shares
of common stock - basic
(denominator) 18,464,343 17,293,848 7,953,147
------------ ------------ ------------
Income (loss) per share - basic $ 0.03 $ .02 $ (0.34)
============ ============ ============
Potential dilutive securities (stock options, stock warrants and
convertible preferred stock) totaling 2,780,520 weighted average
shares in 2001 and 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 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, 2001
and 2000 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, 2001 and 2000, the
unsecured promissory note has been fully reserved.
F-24
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 8. Related Party Transactions - continued
On January 10, 1994, the Company entered into a consulting
agreement with Williams Southwest Drilling Company, Inc. ("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, 2001 and 2000, the unsecured promissory
note has been fully reserved.
As of December 31, 1995, the Company had accrued compensation for
two officers of the Company totaling $54,123. On April 4, 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, 2001 and 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, 2001
and 2000, 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, 2001 and 2000, the promissory note had been fully
reserved.
Interest expensed on related party notes totaled approximately
$128,000, $186,000 and $165,400 for the years December 31, 2001, 2000
and 1999, respectively.
F-25
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 9. Income Taxes
The components of the net deferred federal income tax assets
(liabilities) recognized in the Company's consolidated balance sheets
were as follows:
December 31, December 31,
2001 2000
---- ----
Deferred tax assets
Provision for bad debts $ 251,763 $ 251,763
Net operating loss carryforwards 3,843,135 4,056,444
Oil and gas properties 617,780 602,900
Capital loss carryforwards 114,997 103,344
---------------- ----------------
Net deferred tax assets before
valuation allowance 4,827,675 5,014,451
Valuation allowance (4,827,675) (5,014,451)
---------------- ----------------
Net deferred tax assets (liabilities) $ - $ -
================ ================
As of December 31, 2001 and 2000, 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.
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, 2001, 2000 and 1999.
2001 2000 1999
---- ---- ----
Tax benefit calculated at statutory rate $ 196,081 $ 119,943 $ (771,632)
Increase (reductions) in taxes due to:
Effect of net operating loss carryforwards (45,176)
Effect on non-deductible expenses 18,157 43,133 50,479
Change in valuation allowance (186,776) (60,422) 621,076
Other (27,462) (57,478) 100,077
------------- ------------ -------------
Current federal income tax provision $ - - -
============= ============ =============
As of December 31, 2001 the Company had net operating loss
carryforwards of approximately $11,300,000 and capital loss
carryforwards of approximately $338,000, 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.
F-26
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 10. Commitments and Contingencies
Oil and Gas Hedging Activities
We entered into an agreement with an energy lender commencing in
May, 2000, to hedge a portion of our oil and gas sales for the period
of May, 2000 through April, 2004. The agreement calls for initial
volumes of 7,900 barrels of oil and 52,400 Mmbtu of gas per month,
declining monthly thereafter. We entered into a second agreement with
the energy lender, commencing September, 2001, to hedge an additional
portion of our oil and gas sales for the periods of September, 2001
through July, 2004 and September, 2001 through December 2002,
respectively. The agreement calls for initial volumes of 15,000
barrels of oil and 50,000 Mmbtu of gas per month, declining monthly
thereafter. Volumes at December 31, 2001 had declined to 16,700
barrels of oil and 71,600 Mmbtu of gas. As a result of these
agreements, we realized a reduction in revenues of $762,480 for the
twelve-month period ended December 31, 2001, which is included in oil
and gas sales.
Lease Obligations
The Company leases office space at one location under a
sixty-four (64) month lease, which commenced December 1, 2001. Annual
commitments under the lease are: 2002 - $82,154, 2003 - $109,539, 2004
- $112,582, 2005 - $115,118, 2006 - $117,146 and 2007 - $29,413. Total
rent expense for the years ended December 31, 2001, 2000 and 1999 were
approximately $60,000, $54,000 and $41,000, respectively.
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.
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.
F-27
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 11. Oil and Gas Reserves Information (Unaudited) - continued
The following unaudited table sets forth proved oil and gas
reserves, all within the United States, at December 31, 2001, 2000,
and 1999, together with the changes therein.
Crude Oil Natural Gas
(Bbls) (Mcf)
------------- ---------
QUANTITIES OF PROVED RESERVES:
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
Revisions (386,078) 238,595
Extensions, discoveries, and additions 5,676 895,333
Purchases 2,078,561 14,905,837
Sales (107,225) 1,122
Production (294,276) (1,594,899)
----------- -------------
Balance December 31, 2001 5,871,837 39,257,907
============ ===========
PROVED DEVELOPED RESERVES:
December 31, 1999 1,569,750 9,316,529
========== ===========
December 31, 2000 2,883,641 15,141,979
========== ===========
December 31, 2001 3,939,593 21,203,989
=========== ===========
F-28
<PAGE>
GULFWEST ENERGY INC. 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:
2001 2000 1999
---- ---- ----
Future cash inflows $ 199,162,921 $ 318,504,931 $ 119,006,567
Future production and development costs
Production 77,526,278 97,465,972 42,544,454
Development 23,610,596 13,400,359 9,903,729
------------------ ------------------ ----------------
Future cash flows before income taxes 98,026,047 207,638,600 66,558,384
Future income taxes (13,281,358) (56,466,527) (11,847,076)
------------------- ------------------- -----------------
Future net cash flows after income taxes 84,744,689 151,172,073 54,711,308
10% annual discount for estimated
timing of cash flows (35,895,306) (60,790,946) (23,755,909)
------------------- ------------------- -----------------
Standardized measure of discounted
future net cash flows $ 48,849,383 $ 90,381,127 $ 30,955,399
=================== =================== =================
The following reconciles the change in the standardized measure
of discounted future net cash flows:
Beginning of year $ 90,381,127 $ 30,955,399 $ 5,189,608
Changes from:
Purchases 27,032,359 18,483,582 14,211,998
Sales (443,324)
Extensions, discoveries and improved
recovery, less related costs 427,192 10,727,329 4,798,128
Sales of oil and gas produced net of
production costs (7,270,603) (5,068,349) (1,133,594)
Revision of quantity estimates (1,783,276) 7,365,348 7,363,300
Accretion of discount 12,414,073 3,765,842 518,961
Change in income taxes 26,109,535 (27,056,577) (6,703,020)
Changes in estimated future
development costs (6,360,990) (504,445) (1,434,291)
Development costs incurred that
reduced future development costs 5,945,369 4,359,405 1,012,141
Change in sales and transfer prices,
net of production costs (89,573,528) 38,543,222 6,348,062
Changes in production rates (timing)
and other (8,028,551) 8,810,371 784,106
-------------------- ------------------- ------------------
End of year $ 48,849,383 $ 90,381,127 $ 30,955,399
==================== =================== ==================
F-29
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 12. Quarterly Results (Unaudited)
Summary data relating to the results of operations for each
quarter for the years ended December 31, 2001and 2000 follows:
Three Months Ended
----------------------------------------------------------------------------
March 31 June 30 September 30 December 31
---------------- ---------------- ---------------- ----------------
2001
Operating revenues $ 3,057,739 $ 3,455,882 $ 3,669,203 $ 2,807,757
Income from operations 930,784 1,218,002 1,083,789 219,300
Net income (loss) 247,013 507,937 366,919 (545,160)
Income (loss) per common
share - basic and diluted $ 0.01 $ 0.03 $ 0.02 $ (0.03)
2000
Operating revenues $ 1,618,456 $ 2,124,077 $ 2,291,848 $ 2,949,794
Income from operations 308,225 604,294 747,797 803,701
Net income (loss) (70,328) 82,186 140,363 200,553
Income (loss) per common
share - basic and diluted $ (0.00) $ 0.00 $ 0.01 $ 0.01
F-30
<PAGE>
INDEPENDENT AUDITOR'S REPORT
Stockholders and Board of Directors
GULFWEST ENERGY INC.
Our report on the consolidated financial statements of GulfWest Energy Inc.
and Subsidiaries as of December 31, 2001 and 2000 and for each of the three
years in the period ended December 31, 2001, is included on page F-1. In
connection with our audit of such consolidated financial statements, we
have also audited the related financial statement schedule for the years
ended December 31, 2001, 2000 and 1999 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
April 4, 2002
F-31
<PAGE>
GULFWEST ENERGY INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
BALANCE BALANCE
AT BEGINNING AT END
OF PROVISIONS/ RECOVERIES/ OF
DESCRIPTION PERIOD ADDITIONS DEDUCTIONS PERIOD
----------- ------ --------- ---------- ------
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 $ (60,422) $ $ 5,014,451
============ ========== ============= ============
For the year ended
December 31, 2001:
Accounts and notes receivable
- related parties $ 740,478 $ $ $ 740,478
============ ========== ============= =============
Valuation allowance for
deferred tax assets $ 5,014,451 $ (186,776) $ $ 4,827,675
============ ========== ============= =============
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