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[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2002
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/A or any amendment to
this Form 10-K/A. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12-b2 of the Act).
Yes _ No X
The aggregate market value of voting stock of the Registrant held by
non-affiliates, computed by reference to the closing price of such stock on June
28, 2002, was approximately $3,543,451. For purposes of this computation, all
executive officers, directors and ten percent (10%) beneficial owners of the
Registrant are deemed to be affiliates. Such determination should not be deemed
an admission that such executive officers, directors and ten percent (10%)
beneficial owners are affiliates.
Indicate the number of shares outstanding of each of the Registrant's
classes of common stock: Class A Common Stock $.001 par value: 18,492,541 shares
on April 9, 2003.
DOCUMENTS INCORPORATED BY REFERENCE:
The registrant's definitive Proxy Statement pertaining to the 2003 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.
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,
2002, our part of the estimated proved reserves these properties contain was
approximately 5.5 million barrels (MBbl) of oil and 34.1 billion cubic feet
(Bcf) of natural gas with a Present Value discounted 10% (PV-10) of $98.9
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.
2
GulfWest Energy Inc. has nine wholly owned subsidiaries:
1. GulfWest Oil and 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
September 23, 1996 and was the owner of interests in certain
crude oil and natural gas properties located in the Vaughn Field,
Crockett County, Texas. Effective April 1, 2000, these properties
were assigned to GulfWest Oil and Gas Company to facilitate
financing.
9. GulfWest Oil and 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.
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 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.
3
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 two, 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 three 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, 2002, our reserves were
comprised of 49% crude oil and 51% 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 December 31, 2002, we had 44 full time salaried and contract employees,
of whom 32 were field personnel.
Our Executive Officers.
See Item 10 of this report, which information is incorporated herein by
reference.
4
ITEM 2. Our Properties.
At December 31, 2002, we owned an average 92% working interest in 291 gross
wells (269 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 5.5 million barrels (MBbl) of oil and 34.1 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.
2002 2001 2000
---- ---- ----
Crude Oil (MBbl)
Developed 4,026 3,940 2,884
Undeveloped 1,496 1,932 1,692
--------- -------- --------
Total 5,522 5,872 4,576
========= ======== ========
Natural Gas (MMcf)
Developed 25,374 21,204 15,142
Undeveloped 8,785 18,054 9,670
--------- -------- --------
Total 34,159 39,258 24,812
========= ======== ========
Total (MBOE) 11,215 12,415 8,711
========= ======== ========
(a) Approximately 74% of our total proved reserves were classified as
proved developed at December 31, 2002.
(b) Barrel of Oil Equivalent (BOE) is based on a ratio of 6,000 cubic
feet of natural gas for each barrel of oil.
5
Standardized Measure of Discounted Future Net Cash Flows.
The following table sets forth as of December 31 for each of the preceding
three years, the estimated future net cash flow from and standardized measure of
discounted future net cash flows of our proved reserves, which were prepared in
accordance with the rules and regulations of the SEC. Future net cash flow
represents future gross cash flow from the production and sale of proved
reserves, net of crude oil and natural gas production costs (including
production taxes, ad valorem taxes and operating expenses) and future
development costs. The calculations used to produce the figures in this table
are based on current cost and price factors at December 31 for each year. We
cannot assure you that the proved reserves will all be developed within the
periods used in the calculations or that prices and costs will remain constant.
2002 2001 2000
-------------------- -------------------- -------------------
Future cash inflows $ 308,381,837 $ 199,162,921 $ 318,504,931
Future production and development costs-
Production 105,629,872 77,526,278 97,465,972
Development 23,350,811 23,610,596 13,400,359
-------------------- -------------------- -------------------
Future net cash flows before income taxes 179,401,154 98,026,047 207,638,600
Future income taxes (38,611,577) (13,281,358) (56,466,527)
-------------------- -------------------- -------------------
Future net cash flows after income taxes 140,789,577 84,744,689 151,172,073
10% annual discount for estimated timing
of cash flows (63,165,742) (35,895,306) (60,790,946)
-------------------- -------------------- -------------------
Standardized measure of discounted
Future net cash flows(1) $ 77,623,835 $ 48,849,383 $ 90,381,127
==================== ==================== ===================
(1) The average prices of our proved reserves were $28.72 per Bbl and $4.43 per
Mcf, $17.67 per Bbl and $2.43 per Mcf, and $23.81 per Bbl and $8.45 per Mcf
at December 31, 2002, 2001 and 2000, respectively.
Significant Properties.
Summary information on our properties with proved reserves is set forth
below as of December 31, 2002.
Productive Wells Proved Reserves Present
------------------------------ ------------------------------------------------------ ----------------
Gross Net Value (1)
Productive Productive Crude Natural
Wells Wells Oil Gas Total Amount
-------------- -------------- ---------------- -------------- ---------------- ---------------
(MBbl) (MMcf) (MBOE) ($M)
Texas 206 199.76 3,401 19,356 6,627 $ 56,425
Colorado 39 26.57 355 6,180 1,385 9,101
Oklahoma 27 27.00 146 - 146 1,159
Louisiana 17 16.88 1,614 8,623 3,051 32,152
Mississippi 1 .38 6 - 6 62
-------------- -------------- ---------------- --------------- ---------------- --------------
Total 290 270.59 5,522 34,159 11,215 $ 98,899
============== ============== ================ =============== ================ ==============
(1) The average prices of our proved reserves were $28.72 per Bbl and $4.43 per
Mcf at December 31, 2002.
6
All information set forth herein relating to our proved reserves, estimated
future net cash flows and present values is taken from reports prepared by
Pressler Petroleum Consultants, independent petroleum engineers. The estimates
of these engineers were based upon their review of production histories and
other geological, economic, ownership and engineering data provided by and
relating to us. No reports on our reserves have been filed with any federal
agency. In accordance with the SEC's guidelines, our estimates of proved
reserves and the future net revenues from which present values are derived are
made using year end crude oil and natural gas sales prices held constant
throughout the life of the properties (except to the extent a contract
specifically provides otherwise). Operating costs, development costs and certain
production-related taxes were deducted in arriving at estimated future net
revenues, but such costs do not include debt service, general and administrative
expenses and income taxes.
There are numerous uncertainties inherent in estimating crude oil and
natural gas reserves and their values, including many factors beyond our
control. The reserve data set forth in this report are based upon estimates.
Reservoir engineering is a subjective process, which involves estimating the
sizes of underground accumulations of crude oil and natural gas that cannot be
measured in an exact manner. The accuracy of any reserve estimate is a function
of the quality of available data, engineering and geological interpretation of
that data, and judgment. As a result, estimates of different engineers,
including those used by us, may vary. In addition, estimates of reserves are
subject to revision based upon actual production, results of future development,
exploitation and exploration activities, prevailing crude oil and natural gas
prices, operating costs and other factors. Such revisions may be material.
Accordingly, reserve estimates are often different from the quantities of crude
oil and natural gas that are ultimately recovered and are highly dependent upon
the accuracy of the assumptions upon which they are based. We cannot assure you
that the estimates contained in this report are accurate predictions of our
crude oil and natural gas reserves or their values. Estimates with respect to
proved reserves that may be developed and produced in the future are often based
upon volumetric calculations and upon analogy to similar types of reserves
rather than upon actual production history. Estimates based on these methods are
generally less reliable than those based on actual production history.
Subsequent evaluation of the same reserves based upon production history will
result in potentially substantial variations in the estimated reserves.
7
Production, Revenue and Price History.
The following table sets forth information (associated with our proved
reserves) regarding production volumes of crude oil and natural gas, revenues
and expenses attributable to such production (all net to our interests) and
certain price and cost information for the years ended December 31, 2002, 2001
and 2000.
2002 2001 2000
---------------- ---------------- ----------------
Production
Oil (Bbl) 278,374 294,276 165,031
Natural gas (Mcf) 1,487,048 1,594,899 1,111,639
Total (BOE) 526,215 560,092 350,304
---------------- ---------------- ----------------
Revenue
Oil production $ 5,859,568 $ 6,690,338 $ 4,320,943
Natural gas production 4,587,601 5,735,765 4,124,989
---------------- ---------------- ----------------
Total $ 10,447,169 $ 12,426,103 $ 8,445,932
Operating Expenses $ 5,430,205 $ 5,155,500 $ 3,377,583
Production Data
Average sales price
Per barrel of oil $ 21.05 $ 22.73 $ 26.18
Per Mcf of natural gas 3.09 3.60 3.71
Per BOE 19.85 22.19 24.11
Average expenses per BOE
Lease operating 10.32 9.20 9.64
Depreciation, depletion and
amortization 5.13 4.45 3.83
General and administrative $ 3.28 $ 3.05 $ 4.53
Productive Wells at December 31, 2002:
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 118 116.11 88 85.65
Colorado 18 11.42 21 15.15
Oklahoma 27 27.00 - -
Louisiana 14 13.88 3 3.00
Mississippi 1 .38 - -
------------ ------------ ------------- -----------
Total 178 168.79 112 103.80
============ ============ ============= ===========
8
Developed Acreage at December 31, 2002.
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 19,260 14,826
Colorado 5,000 2,700
---------- ----------
Louisiana 1,695 1,256
Oklahoma 900 684
---------- ----------
Total 26,855 19,466
========== ==========
Undeveloped Acreage at December 31, 2002.
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 22,910 17,800
Colorado 10,000 6,000
Louisiana 440 314
Oklahoma 900 684
----------- -----------
Total 34,250 24,798
=========== ===========
Drilling Results.
In 2002, we drilled one exploratory well, in which we own 18% working
interest, that resulted in a dry hole and one development well, in which we own
100% working interest, that is productive. 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.
9
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
We have incurred net losses in the past and there can be no assurance that
we will 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 26% of our total estimated proved reserves at December 31,
2002 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, 2002. The average prices of all properties were $28.72 per barrel
of oil and $4.43 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
11
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.
12
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.
13
The crude oil and natural gas industry is highly competitive in all of its
phases.
Competition is particularly intense with respect to the acquisition of
desirable producing properties, the acquisition of crude oil and natural gas
prospects suitable for enhanced production efforts, and the hiring of
experienced personnel. Our competitors in crude oil and natural gas acquisition,
development, and production include the major oil companies, in addition to
numerous independent crude oil and natural gas companies, individual proprietors
and drilling programs.
Many of these competitors possess and employ financial and personnel
resources substantially in excess of those which are available to us and may,
therefore, be able to pay more for desirable producing properties and prospects
and to define, evaluate, bid for, and purchase a greater number of producing
properties and prospects than our financial or personnel resources will permit.
Our ability to generate reserves in the future will be dependent on our ability
to select and acquire suitable producing properties and prospects while
competing with these companies.
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 9, 2003, 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 8,000
shares of Series D Preferred Stock are held by Steven M. Morris, a director, and
the 9,000 shares of Series E Preferred Stock are held by J. Virgil Waggoner, a
director. 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.
14
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 9, 2003, 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 9, 2003, there were 18,492,541 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 December 31, 2002, we had outstanding warrants and options for the purchase
of 3,248,754 shares of common stock at prices ranging from $.75 to $6.00 per
share, including employee stock options to purchase 1,067,000 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 9, 2003, 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, 2002.
15
PART II
ITEM 5. Market for Our Common Stock and Related Stockholder Matters.
Our common stock is traded over-the-counter under the symbol "GULF". The
high and low trading prices for the common stock for each quarter in 2002, 2001
and 2000 are set forth below. The trading prices represent prices between
dealers, without retail mark-ups, mark-downs, or commissions, and may not
necessarily represent actual transactions.
High Low
---- ---
2002
----
First Quarter $.66 $.55
Second Quarter .60 .46
Third Quarter .51 .20
Fourth Quarter .44 .32
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
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 9, 2003, there were
18,492,541 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 9, 2003, we had a total of 17,000 shares of preferred stock
issued and outstanding, including 8,000 of our Series D and 9,000 of our Series
16
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 9, 2003, 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 9, 2003, we had outstanding warrants and options for the purchase
3,398,754 shares of common stock at prices ranging from $.75 to $6.00 per share,
including employee stock options to purchase 1,067,000 shares at prices ranging
from $.75 to $1.81 per share.
Recent Sales of Unregistered Securities.
During 2002 and to April 9, 2003, we 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
- ---- ---------- ---------- ------ ----- -------------
02/25/02 Warrant Director(1) 270,000 $ .75 Compensation
04/30/02 Warrant Employee 100,000 $ .75 Compensation
07/15/02 Warrant Accredited Investor 75,000 $ .75 Loan transaction
10/31/02 Option Employee 35,000 $ .75 Compensation
11/06/02 Warrant Director 625,000 $ .75 Loan transaction
12/02/02 Warrant Accredited Investor 75,000 $ .75 Loan transaction
01/24/03 Warrant Accredited Investor 100,000 $ .75 Loan transaction
02/12/03 Warrant Accredited Investor 50,000 $ .75 Loan transaction
(1) 200,000, 50,000 and 20,000 warrants originally issued to an
officer/director (currently a director) in 1996 at exercise prices of
$3.00, $5.00 and $5.75, respectively, were re-priced to $.75 per
share.
17
ITEM 6. Selected Financial Data.
The following table sets forth selected historical financial data of our
company as of December 31, 2002, 2001, 2000, 1999 and 1998, 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, 2002, 2001 and 2000 and the
balance sheet data at December 31, 2002 and 2001 are derived from our audited
financial statements contained elsewhere herein. The income statement data for
the years ended December 31, 1999 and 1998 and the balance sheet data at
December 31, 2000, 1999 and 1998 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,
--------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
----------------- ----------------- ----------------- ----------------- -----------------
Income Statement Data
- ---------------------
Operating Revenues $ 10,839,797 $ 12,990,581 $ 8,984,175 $ 2,812,639 $ 2,403,553
Net income (loss) from
operations 927,655 3,451,875 2,464,017 (1,464,094) (6,329,884)
Net income (loss) (4,502,313) 1,044,291 352,774 (2,269,506) (8,387,060)
Dividends on preferred stock (112,500) (56,250) - (450,684)
Net income (loss) available to
Common Shareholders (4,614,813) 988,401 352,774 (2,720,190) (8,814,233)
Net income (loss), per share
of common stock $ (.25) $ .05 $ .02 $ (.34) (3.68)
Weighted average number of
shares of common stock
outstanding 18,492,541 18,464,343 17,293,848 7,953,147 2,394,866
Balance Sheet Data
- ------------------
Current assets $ 2,353,046 $ 2,205,862 $ 2,934,804 $ 1,357,465 $ 820,984
Total assets 53,088,941 51,379,209 32,374,128 20,009,793 8,058,827
Current liabilities 43,998,566 12,492,365 7,594,986 4,650,691 6,559,393
Long-term obligations 1,266,801 26,541,957 18,077,371 11,304,318 3,401,371
Stockholders' Equity
(Deficit) $ 7,823,574 $ 12,344,887 $ 6,701,771 $ 4,054,784 $ (1,901,937)
18
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
Overview.
We are engaged primarily in the acquisition, development, exploitation,
exploration and production of crude oil and natural gas. Our focus is on
increasing production from our existing crude oil and natural gas properties
through the further exploitation, development and exploration of those
properties, and on acquiring additional interests in crude oil and natural gas
properties. Our gross revenues are derived from the following sources:
1. Oil and gas sales that are proceeds from the sale of crude oil and
natural gas production to midstream purchasers;
2. Operating overhead and other income that consists of earnings from
operating crude oil and natural gas properties for other working
interest owners, and marketing and transporting natural gas. This also
includes earnings from other miscellaneous activities.
3. Well servicing revenues that are earnings from the operation of well
servicing equipment under contract to other operators.
The following is a discussion of our consolidated financial condition,
results of operations, liquidity and capital resources. You should read this
discussion in conjunction with the Consolidated Financial Statements of the
Company and the Notes thereto contained elsewhere herein. See "Financial
Statements."
Results of Operations.
The factors which most significantly affect our results of operations are
(1) the sales price of crude oil and natural gas, (2) the level of total sales
volumes of crude oil and natural gas, (3) depletion and depreciation of oil and
gas property costs and related equipment (4) the level of and interest rates on
borrowings and, (5) the level and success of new acquisitions and development of
existing properties.
We consider depletion and depreciation of oil and gas properties and
related support equipment to be critical accounting estimates, based upon
estimates of oil and gas reserves.
The estimates of oil and gas reserves utilized in the calculation of
depletion and depreciation 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.
We emphasize that reserve estimates are inherently imprecise. Accordingly,
the estimates are expected to change as more current information becomes
available. Our policy is to amortize capitalized oil and gas costs on the unit
of production method, based upon these reserve estimates. It is reasonably
possible 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.
19
Comparative results of operations for the periods indicated are discussed
below.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Revenues
Oil and Gas Sales. Our operating revenues from the sale of crude oil and
natural gas decreased by 16% from $12,426,000 in 2001 to $10,447,000 in 2002.
This decrease resulted from normal oil and gas production declines and the
inability to offset those declines through development efforts because of
limited development capital.
Well Servicing Revenues. Revenues from our well servicing operations
decreased by 77% from $169,000 in 2001 to $39,000 in 2002. This decrease was due
to performing less work for third parties and the sale of one of our workover
rigs.
Operating Overhead and Other Income. Revenues from these activities
decreased 10% from $395,000 in 2001 to $354,000 in 2002, primarily as a result
of the termination of a gas transportation sales contract with a local utility.
Costs and Expenses
Lease Operating Expenses. Lease operating expenses increased 5% from
$5,155,000 in 2001 to $5,430,000 in 2002 due to increased vendor prices.
Cost of Well Servicing Operations. Well servicing expenses decreased 69%
from $182,000 in 2001 to $56,000 in 2002 due to less work under contract to
third parties and the sale of one workover rig.
Depreciation, Depletion and Amortization (DD and A). DD and A increased 8%
from $2,491,000 in 2001 to $2,698,000 in 2002, due to our proved reserves being
calculated slightly lower at the end of 2001.
General and Administrative (G and A) Expenses. G and A expenses increased
only slightly from $1,710,000 in 2001 to $1,728,000 in 2002.
Interest Income and Expense. Interest expense increased 15% from $2,757,000
in 2001 to $3,159,000 in 2002 due to increased debt associated with the funding
of acquisitions in August, 2001, capital used in our development program and
issuance of warrants associated with working capital loans.
Unrealized Gain (Loss) on Derivative Instruments. The estimated future fair
value of derivative instruments at December 31, 2002 resulted in an unrealized
loss of $1,596,000 in 2002 compared to an unrealized gain of $4,215,000 in 2001.
Also in 2001, an unrealized loss of $3,747,000, resulting from the cumulative
effect of adopting SFAS No. 133 "Accounting for Derivative Instruments and Other
Hedging Activities," was recorded.
Dry Holes, Abandoned Property, Impaired Assets. The costs of a dry hole in
Louisiana of $339,000, abandoned property in Oklahoma of $223,500 and impaired
assets in Mississippi of $54,900 totaled $617,400 in 2002 compared to none in
2001.
Dividends on preferred stock due was $112,500 and paid was $112,500 in
2002. Dividends on preferred stock due was $56,250 and paid was $28,125 in 2001.
20
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.
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 and A). DD and 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 and A) Expenses. G and 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.
Unrealized Gain (Loss) on Derivative Instruments. The estimated future fair
value of derivative instruments at December 31, 2001 resulted in an unrealized
gain of $4,215,000 in 2001. Also in 2001, an unrealized loss of $3,747,000,
resulting from the cumulative effect of adopting SFAS No. 133 "Accounting for
Derivative Instruments and Other Hedging Activities," was recorded. There was no
unrealized gain or loss in 2000.
Dividends on preferred stock due was $56,250 and paid was $28,125 in 2001.
No dividends were due or paid in 2000.
21
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.
Depreciation, Depletion and Amortization (DD and A). DD and 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 and A) Expenses. G and 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.
Financial Condition and Capital Resources.
At December 31, 2002, our current liabilities exceeded our current assets
by $41,645,520. We had a loss available to common shareholders of $4,614,813
compared to income available to common shareholders of $988,041 at December 31,
2001. This loss included non-cash items of $1,596,600 for unrealized loss on
derivative instruments and $617,400 for dry holes, abandoned property and
impaired assets.
22
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 were 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 interest
payment increased from 85% to 90%. In addition, the amendment requires payments
on principal of $1,000,000 in February, 2002, August 2002 and February, 2003
In December, 2002, Aquila sold its loan portfolio, including our loan, to
another energy lender. In a subsequent event on February 28, 2003, we entered
into an agreement with that lender to buy-out the loan, which has a current
balance of $27.9 million for a cash payment of $20 million, under the following
terms and conditions:
1. A cash payment of Twenty Million Dollars ($20,000,000), funded at
Closing.
2. Cancellation of the Note and Credit Agreement and termination of all
debt instruments securing this obligation.
3. Re-assignment to GulfWest O and G of the Overriding Royalty Interest
previously conveyed to Aquila and now held by the lender.
4. Cancellation and termination of all fixed price hedges and swap
agreements entered into between GulfWest O and G and Aquila. Such
cancellation to be effective the first day of the month following the
Closing Date.
5. The current reporting and cashflow sweep will remain in effect through
the Closing Date. Commencing January 1, 2003, GulfWest O and G will
pay interest only due under the Note and no part of the funds retained
by lender in the "sweep" shall include any amounts for principal
repayment. Therefore, as respects oil and gas sales revenues due
GulfWest O and G under the "sweep" for January 2003 production, which
is to be paid in March 2003, no funds will be retained by the lender
for principal repayment under the Note.
6. Within forty-five (45) days of the date of the lender's written
acceptance of this offer, GulfWest will furnish the lender acceptable
financial assurance that GulfWest will close the anticipated
refinancing within ninety (90) days of the written acceptance of the
offer. If within such forty-five (45) day period, GulfWest does not
furnish the lender the required financial assurance, then the lender
may, at its option, notify GulfWest that it is no longer obligated to
the terms of this Agreement, and at the lender's option, re-instate
the combined principal and interest payments under the "sweep"
arrangement.
7. Should GulfWest not close this transaction within ninety (90) days of
the lender's written acceptance of this offer, then GulfWest will,
within thirty (30) days, issue to the lender one $1 million of
preferred stock convertible at $1.00 per share of common stock. The
stock will be in the form of 2,000 shares of a new GulfWest Series F
23
Preferred Stock, par value $.01 and liquidation value $500 per share,
with the same terms as the existing GulfWest Preferred E stock (except
there will be no net profits interest redemption rights and the
conversion price of the GulfWest Preferred Series F stock shall be
$1.00 per common share instead of the $2.00 conversion price
established for GulfWest's Preferred Series E stock). Provisions will
be included in the Preferred Series F Stock Agreement to protect the
Preferred Series F stockholder(s) and keep them on par with the
Preferred Series E stockholders and other past and future preferred
stockholders.
We are currently negotiating with various financial institutions to
refinance the loan under the above terms and conditions, as well as providing
funds for our $6.4 million capital development plan for 2003.
In a subsequent event on March 3, 2003, the lender notified us we were in
default and agreed to forbear from exercising its rights and remedies regarding
Events of Default resulting from (1) our most recent Reserve Reporting, as
adjusted by the lender, being insufficient to fully amortize the loans by their
stated maturity; and, (2 our failure to make the $1,000,000 repayment originally
scheduled for August 31, 2002 and deferred to November 30, 2002 and the
$1,000,000 repayment scheduled for February 28, 2003. The lender agreed to
forebear until the earlier of: (1) May 31, 2003, (2) the occurrence of another
Event of Default or Unmatured Event of Default, or (3) the lender learning of
another Event of Default or Unmatured Event of Default that has occurred and is
continuing, which is not listed above.
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.
Effective December 1, 200l and amended August 16, 2002, 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 $150,000 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 $600,000 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
24
defined in the Summit Agreement. Summit will retain an 8.5% working
interest in the workover leases after payment of the $600,000.
(b) We shall pay $150,000 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.
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)
2002
----
First $ 19.40 $ 2.81 $ 18.31
Second 20.75 3.16 19.83
Third 22.04 2.87 19.67
Fourth 22.38 3.56 22.11
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
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
25
ITEM 7a. Qualitative and Quantitative Disclosures About Market Risk.
Information with respect to qualitative disclosures about material risk is
contained in Item 1 "Risk Factors".
Information with respect to quantitative disclosures about material risk
follow:
All of the Company's financial instruments are for purposes other than
trading. The Company only enters derivative financial instruments in conjunction
with its oil and gas hedging activities.
Hypothetical changes in interest rates and prices chosen for the following
stimulated sensitivity effects are considered to be reasonably possible
near-term changes generally based on consideration of past fluctuations for each
risk category. It is not possible to accurately predict future changes in
interest rates and product prices. Accordingly, these hypothetical changes may
not be an indicator of probable future fluctuations.
Interest Rate Risk
The Company is exposed to interest rate risk on debt with variable interest
rates. At December 31, 2002, the Company carried variable rate debt of
$38,598,511. Assuming a one percentage point change at December 31, 2002 on the
Company's variable rate debt, the annual pretax income (loss) would change by
$385,985.
Commodity Price Risk
The Company hedges a portion of its price risks associated with its oil and
natural gas sales which are classified as derivative instruments. As of December
31, 2002, these derivative instruments' assets had a fair value of $(1,128,993).
Fair value was estimated based upon the net present value of expected future
cash flows, comparing prices for oil and gas in the hedge contract with quoted
oil and gas futures prices. A hypothetical change in oil and gas prices could
have an effect on oil and gas futures prices, which are used to estimate the
fair value of our derivative instrument. However, it is not practicable to
estimate the resultant change, in any, in the fair value of our derivative
instrument.
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
26
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
- ---- --- -------- -------------------
J. Virgil Waggoner(1)(2)(3) 75 Chairman of the Board 1997
Thomas R. Kaetzer(3) 44 Chief Executive Officer 1998
President and Director
Jim C. Bigham 67 Executive Vice President 1991
and Secretary
Richard L. Creel 54 Vice President of Finance 1998
and Controller
Marshall A. Smith III(3) 55 Director 1989
John E. Loehr(1)(2)(3) 57 Director 1992
William T. Winston 36 Director 2000
Steven M. Morris(1)(2) 51 Director 2000
John P. Boylan(1) 36 Director 2001
(1) Member of the Audit Committee.
(2) Member of the Compensation Committee.
(3) Member of the Executive Committee.
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.
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.
27
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.
Marshall A. Smith III founded GulfWest and served as an officer in various
capacities, including president, chief executive officer and chairman of the
board, from July 1989 until his resignation in May 2002. He is currently a paid
consultant and remains a director.
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 a member of the American Institute of Certified Public
Accountants.
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.
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.
In a subsequent event, Mr. Morris resigned as a director for personal reasons
effective January 7, 2003.
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. He has had experience in all of the major
producing trends covering the Texas Gulf Coast and South Texas. He received the
degree of Bachelor of Business Administration, with a major in Accounting, from
the University of Texas in 1988 and the degree of Master of Business
Administration, with majors in Finance, Economics and International Business
from the Leonard N. Stern Graduate School of Business of New York University in
1995. Mr. Boylan has been a Certified Public Accountant in the State of Texas
since 1991.
28
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 six times during the calendar year ended
December 31, 2002.
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 2002 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 2002.
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 2002.
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 2002 or
2001.
29
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.
ITEM 14. Controls and Procedures
Within ninety days of the date of this Report, we carried out an
evaluation, under the supervision and with the participation of management,
including the Chief Executive Officer and Chief Financial Officer, of our
disclosure controls and procedures (as defined in Rules 13a-14 and 15d-14 under
the Securities Exchange Act of 1934). Based upon that evaluation, the Chief
Executive Officer and Chief Financial Officer concluded that our disclosure
controls and procedures are effective in timely alerting them to material
information required to be included in periodic filings with the Securities and
Exchange Commission. There were no significant changes in our internal controls
or in other factors that could significantly affect these internal controls
subsequent to the date of our most recent evaluation.
30
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
31
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.
32
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.
33
PART III
ITEM 15. 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,
2002 and 2001. Consolidated Statements of Operations for the
years ended December 31, 2002, 2001 and 2000. Consolidated
Statements of Stockholders' Equity for the years ended December
31, 2002, 2001 and 2000. Consolidated Statements of Cash Flows
for the years ended December 31, 2002, 2001 and 2000. Notes to
Consolidated Financial Statements, December 31, 2002, 2001 and
2000.
(2) Financial Statement Schedule: Schedule II - Valuation and
Qualifying Accounts
(3) Exhibits:
Number Description
------ -----------
*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 (included on page 3 of this
Annual Report).
25 Power of Attorney (included on signature page of this Annual
Report).
- -----------------
* Previously filed with the Company's Registration Statement
(on Form S-1, Reg. No. 33-53526), filed with the Commission
on October 21, 1992.
% Previously filed with the Company's Proxy Statement on Form
DEF 14A, filed with the Commission on April 16, 2001.
(b) Reports on Form 8-K.
None.
34
S I G N A T U R E S
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
GULFWEST ENERGY INC.
Date: April 9, 2003 By \s\ Thomas R. Kaetzer
----------------------------
Thomas R. Kaetzer, President
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\ J. Virgil Waggoner Chairman of the Board April 9, 2003
- ----------------------
J. Virgil Waggoner
\s\ Thomas R. Kaetzer President, Chief Executive Officer April 9, 2003
- ----------------------
Thomas R. Kaetzer and Director
\s\ Jim C. Bigham Executive Vice President and Secretary April 9, 2003
- ----------------------
Jim C. Bigham
\s\ Richard L. Creel Vice President of Finance, Controller April 9, 2003
- ----------------------
Richard L. Creel
\s\ William T. Winston Director April 9, 2003
- ----------------------
William T. Winston
\s\ Marshall A. Smith III Director April 9, 2003
- -------------------------
Marshall A. Smith III
\s\ John E. Loehr Director April 9, 2003
- -----------------
John E. Loehr
\s\ John P. Boylan Director April 9, 2003
- ------------------
John P. Boylan
\s\ Steven M.Morris Director April 9, 2003
- -------------------
Steven M. Morris
35
GULFWEST ENERGY INC.
FINANCIAL REPORT
DECEMBER 31, 2002
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-7
Notes to consolidated financial statements F-8
INDEPENDENT AUDITOR'S REPORT ON
THE FINANCIAL STATEMENT SCHEDULE F-30
FINANCIAL STATEMENT SCHEDULE
Schedule II - Valuation and Qualifying Accounts F-31
All other Financial Statement Schedules have
been omitted because they are either
inapplicable or the information required is
included in the financial statements or
the notes thereto.
INDEPENDENT AUDITOR'S REPORT
To the Stockholders and
Board of Directors
GULFWEST ENERGY INC.
We have audited the accompanying consolidated balance sheets of GulfWest Energy
Inc. (a Texas Corporation) and Subsidiaries as of December 31, 2002 and 2001,
and the related consolidated statements of operations, stockholders' equity and
cash flows for each of the three years in the period ended December 31, 2002.
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, 2002 and 2001, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 2002, in conformity with accounting
principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As shown in the consolidated
financial statements, the Company incurred a net loss of $4,502,313 during the
year ended December 31, 2002, and, as of that date, had a working capital
deficiency of $41,645,520. Those conditions raise substantial doubt about the
Company's ability to continue as a going concern. Management's plans regarding
those matters described in Note 2, "Operations and Management Plans". The
consolidated financial statements do not include any adjustments that might
result from the outcome of this uncertainty.
\s\WEAVER AND TIDWELL, L.L.P
- ------------------------------
WEAVER AND TIDWELL, L.L.P.
Dallas, Texas
March 24, 2003
F-1
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2002 AND 2001
ASSETS
---------------- -----------------
2002 2001
---------------- -----------------
CURRENT ASSETS
Cash and cash equivalents $ 687,694 $ 689,030
Accounts receivable - trade, net of allowance
for doubtful accounts of $-0- in 2002 and 2001 1,361,446 1,392,751
Prepaid expenses 303,906 124,081
---------------- -----------------
Total current assets 2,353,046 2,205,862
---------------- -----------------
OIL AND GAS PROPERTIES,
using the successful efforts method of accounting 56,786,043 52,045,178
OTHER PROPERTY AND EQUIPMENT 2,121,410 2,352,166
Less accumulated depreciation, depletion and amortization (8,498,497) (6,235,251)
---------------- -----------------
Net oil and gas properties and other property and equipment 50,408,956 48,162,093
---------------- -----------------
OTHER ASSETS
Deposits 37,442 37,442
Debt issue cost, net 289,497 506,230
Derivative instruments 467,582
---------------- -----------------
Total other assets 326,939 1,011,254
---------------- -----------------
TOTAL ASSETS $ 53,088,941 $51,379,209
================ =================
The Notes to Consolidated Financial Statements are an integral part of these statements.
F-2
LIABILITIES AND STOCKHOLDERS' EQUITY
---------------- -----------------
2002 2001
---------------- -----------------
CURRENT LIABILITES
Notes payable $ 4,936,088 $ 2,821,020
Notes payable - related parties 1,290,000 40,000
Current portion of long-term debt 33,128,447 6,065,588
Current portion of long-term debt - related parties 256,967 222,687
Accounts payable - trade 3,928,477 3,099,399
Accrued expenses 458,587 243,671
---------------- -----------------
Total current liabilities 43,998,566 12,492,365
---------------- -----------------
NONCURRENT LIABILITIES
Long-term debt, net of current portion 126,552 26,330,589
Long-term debt - related parties 11,256 211,368
---------------- -----------------
Total noncurrent liabilities 137,808 26,541,957
---------------- -----------------
OTHER LIABILITES
Derivative instruments 1,128,993
---------------- -----------------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock 170 170
Common stock 18,493 18,493
Additional paid-in capital 28,258,212 28,164,712
Retained deficit (20,453,301) (15,838,488)
---------------- -----------------
Total stockholders' equity 7,823,574 12,344,887
---------------- -----------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 53,088,941 $ 51,379,209
================ =================
The Notes to Consolidated Financial Statements are an integral part of these statements.
F-3
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
2002 2001 2000
---------------- ----------------- -----------------
---------------- ----------------- -----------------
OPERATING REVENUES
Oil and gas sales $ 10,447,169 $ 12,426,103 $ 8,445,932
Well servicing revenues 39,116 169,167 188,052
Operating overhead and other income 353,512 395,311 350,191
---------------- ----------------- -----------------
Total Operating Revenues 10,839,797 12,990,581 8,984,175
---------------- ----------------- -----------------
OPERATING EXPENSES
Lease operating expenses 5,430,205 5,155,500 3,377,583
Cost of well servicing operations 56,295 182,180 212,286
Depreciation, depletion and amortization 2,697,784 2,491,385 1,341,890
General administrative 1,727,858 1,709,641 1,588,399
---------------- ----------------- -----------------
Total Operating Expenses 9,912,142 9,538,706 6,520,158
---------------- ----------------- -----------------
INCOME FROM OPERATIONS 927,655 3,451,875 2,464,017
---------------- ----------------- -----------------
OTHER INCOME AND EXPENSE
Interest income 16,082
Interest expense (3,159,381) (2,756,912) (2,134,718)
Gain (loss) on sale of assets (56,647) (118,254) 7,393
Unrealized gain (loss) on derivative instruments (1,596,575) 4,215,017
Dry holes, abandoned property and impaired assets (617,365)
---------------- ----------------- -----------------
Total Other Income and (Expense) 5,429,968 1,339,851 (2,111,243)
---------------- ----------------- -----------------
INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES (4,502,313) 4,791,726 352,774
INCOME TAXES
---------------- ----------------- -----------------
INCOME (LOSS) BEFORE CUMULATIVE FFECT OF CHANGE
IN ACCOUNTING PRINCIPLES (4,502,313) 4,791,726 352,774
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES, NET OF INCOME TAXES
(3,747,435)
---------------- ----------------- -----------------
NET INCOME (LOSS) $ (4,502,313) $ 1,044,291 $ 352,774
DIVIDENDS ON PREFERRED STOCK
(PAID 2002-$112,500; 2001-$28,125; 2000-$76,992) (112,500) (56,250)
---------------- ----------------- -----------------
NET INCOME (LOSS) AVAILABLE TO COMMON
SHAREHOLDERS $ (4,614,813) $ 988,041 $ 352,774
================ ================= =================
NET INCOME (LOSS) PER SHARE, BASIC
BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLES $ (.25) $ .25 $ .02
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES (.20)
---------------- ----------------- -----------------
NET INCOME (LOSS) PER SHARE BASIC $ (.25) $ .05 $ .02
================ ================= =================
NET INCOME (LOSS) PER SHARE, DILUTED BEFORE CUMULATIVE
EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES $ (.25) $ .23 $ .02
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES (.18)
---------------- ----------------- -----------------
NET INCOME (LOSS) PER SHARE, DILUTED $ (.25) $ .05 $ .02
================ ================= =================
F-4
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
-------------------------------
Number of Shares
-------------------------------
-------------- -- -------------
Preferred Common
Stock Stock
-------------- -------------
-------------- -------------
BALANCE, December 31, 1999 8,815 15,696,882
Conversion of 815 shares of AAA preferred stock and unpaid
dividends to 538,222 shares of common stock (815) 538,322
Issuance of 2,209,837 shares of common stock, net of offering costs
(1,143,837 through private placement, 200,000 for acquisition of
assets, 866,000 in exchange for debt) 2,209,837
Issuance of warrants and options for services and additional financing
Netting of related party receivables and payables
Provision for bad debts - receivables from related parties
Net income
-------------- -------------
BALANCE, December 31, 2000 8,000 18,445,041
Issuance of 9,000 shares of Series E preferred stock for the
acquisition of assets 9,000
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
Issuance of warrants for additional financing
Net loss
Dividends paid on preferred stock
-------------- -------------
BALANCE, December 31, 2002 17,000 18,492,541
============== =============
The Notes to Consolidated Financials are an integral part of these statements.
F-5
Common Preferred Additional Retained Receivables from
Stock Stock Paid-In Capital Deficit Related Parties
- ---------------------- -------------------- ---------------------- ---------------------- ---------------------
$ 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) $ -
90 4,499,910
48 35,402
91,500
1,044,291
(28,125)
- ---------------------- -------------------- ---------------------- ---------------------- ---------------------
$ 18,493 $ 170 $ 28,164,712 $ (15,838,488) $ -
93,500
(4,502,313)
(112,500)
- ---------------------- -------------------- ---------------------- ---------------------- ---------------------
$ 18,493 $ 170 $ 28,258,212 $ (20,453,301) $ -
====================== ==================== ====================== ====================== =====================
The Notes to Consolidated Financials are an integral part of these statements.
F-6
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
2002 2001 2000
--------------- ---------------- ---------------
--------------- ---------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (4,502,313) $ 1,044,291 $ 352,774
Adjustments to reconcile net income (loss) to net cash
Provide by (used in) operating activities:
Depreciation, depletion and amortization 2,697,784 2,491,385 1,341,890
Common stock and warrants issued and charged to
operations 93,500 15,660
(Gain) loss on sale of assets 56,647 118,254 (7,393)
Dry holes, abandoned property, impaired assets 617,365
Unrealized (gain) loss on derivative instruments 1,596,575 (4,215,017)
Cumulative effect of accounting change 3,747,435
Other non-operating income (5,780)
Provision for bad debts 40,248
(Increase)decrease in accounts receivable - trade, net (109,437) 765,939 (1,344,767)
(Increase) decrease in prepaid expenses (179,825) (40,730) (3,588)
Increase (decrease)in accounts payable and accrued expenses 1,043,994 797,800 1,710,769
--------------- ---------------- ---------------
Net cash provided by operating activities 1,314,290 4,709,357 2,099,813
--------------- ---------------- ---------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Deposits (9,804)
Proceeds from sale of property and equipment 675,440 394,423 14,915
Purchase of property and equipment (5,861,969) (6,962,650) (6,126,817)
--------------- ---------------- ---------------
Net cash used in investing activities (5,186,529) (6,578,031) (6,111,902)
--------------- ---------------- ---------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock, net 795,378
Payments on debt (3,410,778) (6,577,928) (1,733,513)
Proceeds from debt issuance 7,394,181 8,530,269 5,694,510
Debt issue cost (29,544) (368,554)
Dividends paid (112,500) (28,125)
--------------- ---------------- ---------------
Net cash provided by financing activities 3,870,903 1,894,672 4,387,821 --------------- ---------------- ---------------
--------------- ---------------- ---------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (1,336) 25,998 375,732
CASH AND CASH EQUIVALENTS,
Beginning of year 689,030 663,032 287,300
--------------- ---------------- ---------------
CASH AND CASH EQUIVALENTS,
End of year $ 687,694 $ 689,030 $ 663,032
=============== ================ ===============
CASH PAID FOR INTEREST $ 3,004,015 $ 2,811,677 $ 2,041,630
=============== ================ ================
The Notes to Consolidated Financial Statements are an integral part of these statements.
F-7
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 our subsidiaries intend 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 our
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 and Gas
Company formed February 18, 1999; LTW Pipeline Co. formed April 19,
1999; GulfWest Development Company ("GWD") formed November 9, 2000 and
GulfWest Oil and Gas Company (Louisiana) LLC, formed July 31, 2001.
All material intercompany transactions and balances are eliminated
upon consolidation.
We grant credit to independent and major oil and gas companies
for the sale of crude oil and natural gas. In addition, we grant
credit to joint owners of oil and gas properties, which we, through
our subsidiary, SETEX, operate. Such amounts are secured by the
underlying ownership interests in the properties. We also grant credit
to various third parties through RigWest for well servicing
operations.
We maintain cash on deposit in interest and non-interest bearing
accounts, which, at times, exceed federally insured limits. We have
not experienced any losses on such accounts and believe we are not
exposed to any significant credit risk on cash and equivalents.
Statement of Cash Flows
We consider 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, 2002, we
acquired $74,653 in property and equipment through notes payable to
financial institutions. We also acquired $182,742 of oil producing
properties in exchange of accounts receivable from a related party. In
addition, we sold property and equipment, which included an account
receivable of $42,000. This receivable was collected in January 2003.
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.
F-8
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
During the twelve month period ended December 31, 2000, we
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 66,000shares 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.
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
We use 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 we acquire 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 our other property and equipment. We provide for depreciation and
amortization using the straight-line method over the following
estimated useful lives of the respective assets:
Assets Years
--------------------------------- -------------
Automobiles 3-5
Office equipment 7
Gathering system 10
Well servicing equipment 10
F-9
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:
2002 2001
--------------------- ------------------
--------------------- ------------------
Automobiles $ 420,776 $ 446,055
Office equipment 137,362 126,690
Gathering system 529,486 529,486
Well servicing equipment 1,033,786 1,249,935
--------------------- ------------------
2,121,410 2,352,166
Less accumulated depreciation (1,037,076) (937,488)
--------------------- ------------------
Net capitalized cost $ 1,084,334 $ 1,414,678
===================== ==================
Revenue Recognition
We recognize 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, 2002,
2001, and 2000 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, 2002 and 2001, our financial instruments
consist of notes payable and long-term debt. Interest rates
currently available to us for 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.
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.
Trade Accounts Receivable
Trade accounts receivable are reported in the consolidated
balance sheet at the outstanding principal adjusted for any
chargeoffs. An allocation for doubtful accounts is recognized by
management based upon a review of specific customer balances,
historical losses and general economic conditions.
F-10
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Earnings (Loss) Per Share - continued
We have 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.
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 that we 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. We will continue to
use the intrinsic value method under APB 25 but are 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 2002, 2001 and 2000 financial statements.
During 2002, 2001 and 2000, we issued options and warrants
totaling: 2002 - 405,000 (all exercisable); 2001 - 184,000 (all
exercisable); and 2000 - 354,000 (all exercisable), respectively,
to employees and directors as compensation. If we had used the
fair value method required by SFAS 123, our net income (loss) and
per share information would approximate the following amounts:
2002 2001 2000
--------------------------- --------------------------- --------------------------
As Reported ProForma As Reported ProForma As Reported ProForma
------------ ----------- ------------ ----------- ------------ ----------
SFAS 123
compensation cost $ $ 38,300 $ 99,360 $ 265,620
APB 25
compensation cost $ $ $ $
Net income (loss) $(4,614,813) $(4,653,113) $ 988,041 $ 888,681 $ 352,774 $ 87,154
Income (loss) per
common share-basic $ (.25) $ (.25) $ .05 $ .05 $ .02 $ .00
Income (loss) per
common share-diluted $ (.25) $ (.25) $ .05 $ .04 $ .02 $ .00
F-11
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Stock Based Compensation - continued
The effects of applying SFAS 123 as disclosed above are not
indicative of future amounts. We anticipate making additional stock
based employee compensation awards in the future.
We use 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 2002 - 3.6; 2001
- 5.0; 2000 - 4.8; (3) expected volatility of 2002 - 101.73%; 2001 -
103.27%; 2000 - 99.82%; and (4) no expected dividends.
Implementation of New Financial Accounting Standards
Effective January 1, 2001, we adopted SFAS No. 133 "Accounting
for Derivative Instruments and Other Hedging Activities", as amended
by SFAS No. 137 and No. 138. As a result of a financing agreement with
an energy lender, we were required to enter into an oil and gas
hedging agreement with the lender. It has been determined this
agreement meets the definition of SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" and is accounted for as a
derivative instrument.
The estimated change in fair value of the derivatives is reported
in Other Income and Expense as unrealized (gain) loss on derivative
instruments. The estimated fair value of the derivatives is reported
in Other Assets (or Other Liabilities) as derivative instruments.
The estimated fair value of the derivative instruments at January
1, 2001, the date of initial application of SFAS 133, of $3,747,435 is
reported in the Statement of Operations as the cumulative effect of a
change in accounting principle.
In June, 2001, SFAS No. 141 "Business Combinations" and SFAS No.
142 "Goodwill and Other Intangible Assets were issued. We presently
have no goodwill or intangible assets and are thus not affected by
SFAS No. 142.
Effective January 1, 2002, we adopted SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets." This statement
requires the following three-step approach for assessing and
recognizing the impairment of long-lived assets: (1) consider whether
indicators of impairment of long-lived assets are present; (2) if
indicators of impairment are present, determine whether the sum of the
estimated undiscounted future cash flows attributable to the assets in
question is less than their carrying amount; and (3) if less,
recognize an impairment loss based on the excess of the carrying
amount of the assets over their respective fair values. In addition,
SFAS No. 144 provides more guidance on estimating cash flows when
performing a recoverability test, requires that a long-lived asset to
be disposed of other than by sale (such as abandoned) be classified as
"held and used" until it is disposed of, and establishes more
restrictive criteria to classify an asset as "held for sale". The
adoption of SFAS No. 144 did not have a material impact on our
financial statements since it retained the fundamental provisions of
SFAS No. 121, "Accounting for the Impairment or Disposal of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of," related to the
recognition and measurement of the impairment of long-lived assets to
be "held and used".
F-12
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Implementation of New Financial Accounting Standards - continued
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 addresses
financial accounting and reporting for costs associated with exit or
disposal activities and nullifies EITF Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." SFAS No. 146 requires that a liability for a cost
associated with an exit or disposal activity be recognized when the
liability is incurred. Under EITF Issue No. 94-3, a liability for an
exit cost as defined was recognized at the date of an entity's
commitment to an exit plan. SFAS No. 146 also establishes that the
fair value is the objective for the initial measurement of the
liability. SFAS No. 146 is effective for exit and disposal activities
that are initiated after December 31, 2002. This statement will impact
the timing of our recognition of liabilities for costs associated with
exit or disposal activities.
Note 2. Operations and Management Plans
At December 31, 2002, our current liabilities exceeded our current
assets by $41,645,520. We had a net loss available to common shareholders
of $4,614,813 compared to a net income available to common shareholders of
$988,041 at December 31, 2001. This loss included non-cash items of
$1,596,600 for unrealized loss on derivative instruments and $617,400 for
dry holes, abandoned property and impaired assets.
On April 5, 2000, we entered into an agreement with Aquila Energy
Capital ("Aquila"), 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 were 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 interest payment increased from 85% to 90%. In addition, the
amendment requires payments on principal of $1,000,000 in February, 2002,
August 2002 and February, 2003.
In December, 2002, Aquila sold its loan portfolio, including our loan,
to another energy lender. In a subsequent event on February 28, 2003, we
entered into an agreement with that lender to buy-out the loan, which has a
current balance of $27.9 million for a cash payment of $20 million, under
the following terms and conditions:
1. A cash payment of Twenty Million Dollars ($20,000,000), funded at
Closing.
2. Cancellation of the Note and Credit Agreement and termination of
all debt instruments securing this obligation.
3. Re-assignment to us of the Overriding Royalty Interest previously
conveyed to Aquila and now held by the lender.
F-13
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 2. Operations and Management Plans - continued
4. Cancellation and termination of all fixed price hedges and swap
agreements entered into between Aquila and us. Such cancellation
to be effective the first day of the month following the Closing
Date.
5. We will pay interest only due under the Note.
6. By April 14, 2003, we furnish the lender acceptable financial
assurance that we will close the anticipated refinancing by May
29, 2003. If by April 14, 2003 we do not furnish the lender the
required financial assurance, then the lender may, at its option,
notify us that it is no longer obligated to the terms of this
Agreement, and at the lender's option, re-instate the combined
principal and interest payments.
7. Should we not close this transaction within ninety (90) days of
the lender's written acceptance of this offer, then we will,
within thirty (30) days, issue to the lender one $1 million of
preferred stock convertible at $1.00 per share of common stock.
The stock will be in the form of 2,000 shares of a new GulfWest
Series F Preferred Stock, par value $.01 and liquidation value
$500 per share, with the same terms as the existing GulfWest
Preferred E stock (except there will be no net profits interest
redemption rights and the conversion price of the GulfWest
Preferred Series F stock shall be $1.00 per common share instead
of the $2.00 conversion price established for GulfWest's
Preferred Series E stock). Provisions will be included in the
Preferred Series F Stock Agreement to protect the Preferred
Series F stockholder(s) and keep them on par with the Preferred
Series E stockholders and other past and future preferred
stockholders.
We are currently negotiating with various financial institutions to
refinance the loan under the above terms and conditions, as well as
providing funds for our $6.4 million capital development plan for 2003.
In a subsequent event on March 3, 2003, the lender notified us we were
in default and agreed to forbear from exercising its rights and remedies
regarding Events of Default resulting from (1) our most recent Reserve
Reporting, as adjusted by the lender, being insufficient to fully amortize
the loans by their stated maturity; and, (2 our failure to make the
$1,000,000 repayment originally scheduled for August 31, 2002 and deferred
to November 30, 2002 and the $1,000,000 repayment scheduled for February
28, 2003. The lender agreed to forebear until the earlier of: (1) May 31,
2003, (2) the occurrence of another Event of Default or Unmatured Event of
Default, or (3) the lender learning of another Event of Default or
Unmatured Event of Default that has occurred and is continuing, which is
not listed above. Because of the defaults, the long term portion of this
debt was reclassified to current.
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.
Effective December 1, 200l and amended August 16, 2002, 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
F-14
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 2. Operations and Management Plans - continued
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 $150,000 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 $600,000 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 $600,000.
(b) We shall pay $150,000 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.
F-15
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 our
oil and gas producing activities for the periods presented:
Capitalized Costs Relating to Oil and Gas Producing Activities:
2002 2001
---------------- ----------------
Unproved oil and gas properties $ 439,926 $ 440,033
Proved oil and gas properties 52,847,625 48,702,656
Support equipment and facilities 3,498,492 2,902,489
---------------- ----------------
56,786,043 52,045,178
Less accumulated depreciation, depletion and
Amortization (7,461,421) (5,297,763)
---------------- ----------------
Net capitalized costs $ 49,324,622 $ 46,747,415
================ ================
Results of Operations for Oil and Gas Producing Activities:
2002 2001 2000
---------------- ---------------- ---------------
Oil and gas sales $ 10,447,169 $ 12,426,103 $ 8,445,932
Production costs (5,430,205) (5,155,500) (3,377,583)
Depreciation, depletion and amortization (2,187,036) (2,018,890) (1,030,635)
Income tax expense - - -
---------------- ---------------- ---------------
Results of operations for oil and gas
producing activities - income $ 2,829,928 $ 5,251,713 $ 4,037,714
================ ================ ===============
Costs Incurred in Oil and Gas Producing Activities:
2002 2001 2000
---------------- ---------------- ---------------
Property Acquisitions
Proved $ 562,760 $ 15,236,808 $ 5,874,199
Unproved 14,401 154,076 122,837
Development Costs 5,141,075 6,317,527 4,814,317
---------------- ---------------- ---------------
$ 5,718,236 $ 21,708,411 $ 10,811,353
================ ================ ===============
F-16
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Cost of Oil and Gas Properties - continued
Effective July 1, 2001, we 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, we 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. We
incurred additional cash costs of $33,058 related to the acquisition. On
the same date, we transferred its ownership interest in these properties to
our wholly owned subsidiary, GulfWest Oil and 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
================ =================
Effective January 1, 2002, we acquired oil and gas properties located
in Louisiana from a related party for $182,742. The acquisition price was
the amount of accounts receivable due us.
Note 4. Accrued Expenses
Accrued expenses consisted of the following:
December 31, December 31,
2002 2001
---------------- -----------------
Payroll and payroll taxes $ 1,863 $ 3,910
Interest 414,724 194,761
Professional fees 42,000 45,000
---------------- -----------------
$ 458,587 $ 243,671
================ =================
F-17
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Notes Payable and Long-Term Debt
Notes payable is as follows:
2002 2001
------------- ------------------
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 with monthly principal payments of $13,889;
interest at prime plus 1%; due March 2002; secured by the guaranty
of three of our directors; retired September, 2002. 374,999
Promissory note payable to one of our directors at 8%; due May,
2001; unsecured. 40,000 40,000
Promissory note payable to an unrelated party at 10%; payable on
demand; unsecured. 45,000 115,000
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 4.25% at December 31, 2001). Line of credit increased to
$3,000,000 and due date extended to April, 2003 2,995,488 2,251,192
Promissory note to an unrelated party at 10%; due and retired in
January, 2002. 39,529
Note payable to a bank; due March, 2003; interest at prime rate plus 1%
(prime rate 4.25% at December 31, 2002); secured by guaranty of
three of our directors 500,000
Promissory note payable to an unrelated party; payable on demand;
interest at 8%; secured by certain oil and gas properties. 300,000
Line of credit payable to a bank; due April, 2003; secured by guaranty
of a director; interest at prime rate (prime rate 4.25% at December
31, 2002 with a floor of 5.5% and a ceiling of 8.5%. 1,000,000
Promissory note payable to unrelated party; interest at 6%; due June,
2003. 55,300
Promissory note payable to one of our directors; interest at 8%;
due on demand; unsecured. 50,000
Promissory note payable to one of our directors; interest at
prime rate (prime rate 4.25% at December 31, 2002); due May, 2003;
secured by common stock of DutchWest Oil Company, our wholly
owned subsidiary. 1,200,000
------------- ------------------
$ 6,226,088 $ 2,861,020
============= ==================
The weighted average interest rate for notes payable at December 31, 2002 and 2001 was 4.7% and 5.0%, respectively.
F-18
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Notes Payable and Long-Term Debt
Long-term debt is as follows:
2002 2001
-------------- ------------------
Line of credit (up to $3,000,000) to a bank; due July, 2003; secured
by the guaranty of a director; interest at prime rate (prime rate
4.25% at December 31, 2002). $ 2,999,515 $ 2,939,515
Subordinated promissory notes to various individuals at 9.5% interest
per annum; amounts include $50,000 ($100,000 - 2001) due to
related parties; past due. 150,000 200,000
Notes payable to finance vehicles, payable in aggregate monthly
installments of approximately $6,000, including interest of.9% to
13% per annum; secured by the related equipment; due various
dates through 2007. 116,721 96,024
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. 48,850 100,591
Promissory note to a director; interest at 8.5%; due
December 31, 2003. 95,670 88,814
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
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
Note payable to a bank with monthly principal payments of $2,300;
interest at 9.5%; due May, 2003; secured by related equipment. 11,630 39,543
Note payable to an energy lender; interest at prime plus 3.5% (prime
rate 4.25% at December 31, 2002) 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. 27,907,509 26,679,770
F-19
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:
2002 2001
------------------ -----------------
Note payable to a bank with monthly principal payments of $15,000;
interest at prime plus 1% (prime rate 4.75% at December 31,
2002); in October, 2001 monthly principal payments became
$36,000 and interest prime plus 1% with a minimum prime rate
of 5.5%; final payment due November, 2003; secured by related
oil and gas properties. $ 1,996,000 $ 2,392,000
Note payable to unrelated party to finance saltwater disposal well
with monthly installments of $4,540, including interest at 10%
per annum; final payment due January, 2005; secured by related well. 123,624 149,325
Note payable to 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.
65,743 114,324
Note payable to 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. 7,960 14,002
------------------ -----------------
33,523,222 32,830,232
Less current portion (33,385,414) (6,288,275)
------------------ -----------------
Total long-term debt $ 137,808 $ 26,541,957
================== =================
Estimated annual maturities for long-term debt are as follows:
2003 $ 33,385,414
2004 102,008
2005 27,291
2006 7,150
2007 1,359
------------------
$ 33,523,222
==================
F-20
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity
Common Stock
------------
2002 2001
----------------- --------------
Par value $.001; 40,000,000 shares authorized; 18,492,541
shares issued and outstanding as of December 31, 2002 and
2001, respectively $ 18,493 $ 18,493
================= ==============
Preferred Stock
---------------
Series D, par value $.01; 12,000 shares authorized; 8,000 shares
issued and outstanding at December 31, 2002 and 2001. 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 issue, and thereafter, the shares
are convertible to 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 shares
issued and outstanding at December 31, 2002 and 2001. The
Series E preferred stock pays dividends, as declared, at a
rate of 2.5% per anum, has a liquidation value of $500 per share,
may be redeemed at our and, if not redeemed after two years,
is convertible to common stock based upon a value of $500 per
Series E share divided by $2 per share of common stock. 90 90
----------------- --------------
$ 170 170
================= ==============
All classes of preferred shareholders have liquidation preference
over common shareholders of $500 per preferred share, plus accrued
dividends. There were no dividends in arrears at December 31, 2002.
Stock Options
-------------
We maintain 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 our 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.
2002 2001 2000
--------------------------- ----------------------------- ------------------------
Wtd Avg Wtd Avg Wtd Avg
Prices Number Prices Number Prices Number
-------- -------------- ---------- --------------- --------- -----------
Balance, January 1 $ 1.03 1,097,000 $ 1.09 923,000 $ 1.07 717,000
Options issued $ .75 35,000 $ .83 184,000 $ 1.17 206,000
Options expired $ 3.00 (65,000) $ 3.00 (10,000) - -
-------------- --------------- -----------
Balance, December 31 $ .90 1,067,000 $ 1.03 1,097,000 $ 1.09 923,000
============== =============== ===========
F-21
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity - continued
All options were exercisable at December 31, 2002. Following is a
schedule by year and by exercise price of the expiration of our stock
options issued as of December 31, 2002:
2003 2004 2005 2006 2007 Thereafter Total
--------- ---------- ----------- ---------- ---------- ------------ -----------
$ .75 432,000 35,000 150,000 617,000
$ .83 184,000 184,000
$1.13 100,000 100,000
$1.20 106,000 106,000
$1.81 60,000 60,000
--------- ---------- ----------- ---------- ---------- ------------ -----------
- 432,000 206,000 184,000 35,000 210,000 1,067,000
========= ========== =========== ========== ========== ============ ===========
Stock Warrants
--------------
We have issued a significant number of stock warrants for a
variety of reasons, including compensation to employees, additional
inducements to purchase our 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:
2002 2001 2000
-------------------------- -------------------------- ---------------------------
Wtd Avg Wtd Avg Wtd Avg
Prices Number Prices Number Prices Number
--------- ------------- --------- ------------- --------- --------------
Balance, January 1 $ 2.15 1,306,754 $ 2.31 1,392,254 $ 2.53 1,369,754
Warrants issued $ .75 1,145,000 $ .75 150,000 $ 1.86 170,000
Warrants exercised
or expired $ 3.57 (270,000) $ 2.22 (235,500) $ 2.65 (147,500)
------------- ------------- --------------
Balance, December 31 $ 1.24 2,181,754 $ 2.15 1,306,754 $ 2.31 1,392,254
============= ============= ==============
Included in the "warrants issued" and "warrants
exercised/expired" columns in 2002 were 270,000 warrants whose price
was reduced in 2002 to $.75.
Following is a schedule by year and by exercise price of the
expiration of our stock warrants issued as of December 31, 2002:
2003 2004 2005 2006 2007 Total
---- ---- ---- ---- ---- -----
$ .75 166,754 75,000 1,590,000 1,831,754
.875 150,000 150,000
6.00 200,000 200,000
---------- ---------- ------------- ------------ ----------- ------------
366,754 - 225,000 1,590,000 - 2,181,754
========== ========== ============= ============ =========== ============
Warrants outstanding to our officers, directors and employees at
December 31, 2002 and 2001 were approximately 1,682,000 and 957,000,
respectively. The exercise prices on these warrants range from $.75 to
$.88 and expire various dates through 2006.
F-22
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 7. Income (Loss) Per Common Share
The following is a reconciliation of the numerators and denominators
used in computing income (loss) per share:
2002 2001 2000
------------------ ----------------- ------------------
Net income (loss) $ (4,502,313) $ 1,044,291 $ 352,774
Preferred stock dividends (112,500) (56,250) -
------------------ ----------------- ------------------
Income (loss) available to common
shareholders (numerator) $ (4,614,813) $ 988,041 $ 352,774
================== ================= ==================
Weighted-average number of shares
of common stock - basi
(denominator) 18,492,541 18,464,343 17,293,848
------------------ ----------------- ------------------
Income (loss) per share - basic $ (.25) $ .05 $ .02
================== ================= ==================
Potential dilutive securities (stock options, stock warrants and
convertible preferred stock) in 2002 have not been considered since we
reported a net loss and, accordingly, their effects would be
antidilutive. 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 been considered but there is no effect on income per common
share.
Note 8. Related Party Transactions
On December 1, 1992, Ray Holifield and Associates, Inc. executed
an unsecured promissory note to us 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, we 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 the unsecured promissory
note had been fully reserved. At December 31, 2002, the unsecured
promissory note had been fully written off.
On December 1, 1992, Parkway Petroleum Company, a Ray Holifield
related company, executed an unsecured promissory note to us 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 we
provided Parkway Petroleum Company. At December 31, 1993, the note was
still outstanding. During 1994, we 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, the unsecured promissory
note had been fully reserved. At December 31, 2002, the unsecured
promissory note had been fully written off.
On January 10, 1994, we entered into a consulting agreement with
Williams Southwest Drilling Company, Inc. ("Williams") whereby we
would provide management and accounting services for $25,000 per month
for a period of one year. We accrued the consulting fees with an
offset to deferred income until payment of the fees is actually
received. During 1994, $172,140 was recorded as consulting fee income.
Beginning in the second quarter 1994, we began recognizing consulting
income only as cash payments were received. Prior to the second
quarter, $75,000 in consulting fee revenue was accrued. We 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, we 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, the unsecured promissory note had been fully reserved. At
December 31, 2002, the unsecured promissory note had been fully
written off.
F-23
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 8. Related Party Transactions (continued)
From July 22 to August 13, 1998, we advanced sums totaling
$102,000 to Gulf Coast Exploration, Inc. At December 31, 2001, the
debt had been fully reserved. At December 31, 2002, the debt had been
fully written off.
On October 1, 1998, Toro Oil Company executed an unsecured
promissory note to us 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, the promissory note had been fully reserved. At December 31,
2002, the debt had been fully written off.
Interest expensed on related party notes totaled approximately
$53,000, $128,000 and $186,000 for the years ended December 31, 2002,
2001 and 2000, respectively.
Note 9. Income Taxes
The components of the net deferred federal income tax assets
(liabilities) recognized in our consolidated balance sheets were as
follows:
December 31, December 31,
2002 2001
---- ----
Deferred tax assets
Provision for bad debts $ $ 251,763
Net operating loss carryforwards 5,236,485 3,843,135
Oil and gas properties 542,131 617,780
Capital loss carryforwards 93,211 114,997
Derivative instruments 383,858
Deferred tax liability
Derivative instruments (158,978)
----------------- -------------------
Net deferred tax assets before
valuation allowance 6,255,685 4,668,697
Valuation allowance (6,255,685) (4,668,697)
----------------- -------------------
Net deferred tax assets (liabilities) $ - $ -
================= ===================
As of December 31, 2002 and 2001, we did not believe it was more
likely than not that the net operating loss carryforwards would be
realizable through generation of future taxable income; therefore,
they were fully reserved.
F-24
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 9. Income Taxes - continued
The following table summarizes the difference between the actual
tax provision and the amounts obtained by applying the statutory tax
rate of 34% to the income (loss) before income taxes for the years
ended December 31, 2002, 2001 and 2000.
2002 2001 2000
----------------- ----------------- ----------------
Tax (benefit) calculated at statutory rate $ (1,530,786) $ 355,059 $ 119,943
Increase (reductions) in taxes due to:
Effect of net operating loss carryforwards (45,176)
Effect on non-deductible expenses 65,174 18,157 43,133
Change in valuation allowance 1,586,988 (345,754) (60,422)
Other (121,376) (27,462) (57,478)
----------------- ----------------- ----------------
Current federal income tax provision $ - $ - $ -
================= ================= ================
As of December 31, 2002 we had net operating loss carryforwards
of approximately $15,400,000 and capital loss carryforwards of
approximately $274,000, 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 2022.
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 called 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 called for initial volumes of 15,000
barrels of oil and 50,000 Mmbtu of gas per month, declining monthly
thereafter. Volumes at December 31, 2002 had declined to 9,800 barrels
of oil and 26,500 Mmbtu of gas. As a result of these agreements, we
realized a reduction in revenues of $368,776, $762,480 and $1,200,794
for the twelve-month periods ended December 31, 2002, 2001 and 2000,
respectively, which is included in oil and gas sales.
Lease Obligations
We lease office space at one location under a sixty-four (64)
month lease, which commenced December 1, 2001 and was amended May 30,
2002 after expansion. Annual commitments under the lease are: 2003 -
$126,536, 2004 - $130,051, 2005 - $132,980, 2006 - $135,241 and 2007 -
$33,977. Total rent expense for the years ended December 31, 2002,
2001 and 2000 were approximately $91,000, $60,000 and $54,000,
respectively.
Litigation
From time to time, we are involved in litigation arising out of
our operations or from disputes with vendors in the normal course of
business. As of April 9, 2003, we were not engaged in any legal
proceedings that are expected, individually or in the aggregate, to
have a material effect on our consolidated financial statements.
F-25
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 11. Oil and Gas Reserves Information (Unaudited)
The estimates of proved oil and gas reserves utilized in the
preparation of the financial statements are estimated in accordance
with guidelines established by the Securities and Exchange Commission
and the Financial Accounting Standards Board, which require that
reserve estimates be prepared under existing economic and operating
conditions with no provision for price and cost escalations over
prices and costs existing at year end except by contractual
arrangements.
We emphasize that reserve estimates are inherently imprecise.
Accordingly, the estimates are expected to change as more current
information becomes available. Our 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-26
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, 2002, 2001,
and 2000, together with the changes therein.
Crude Oil Natural Gas
(BBls) (Mcf)
---------------- ----------------
QUANTITIES OF PROVED RESERVES:
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
Purchase 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
Purchase 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
Revisions (125,468) (4,959,229)
Extensions, discoveries and additions 22,129 1,090,024
Purchase 52,480 1,090,025
Sales (20,698) (837,856)
Production (278,374) (1,487,048)
---------------- ----------------
Balance December 31, 2002 5,521,906 34,158,823
================ ================
PROVED DEVELOPED RESERVES:
December 31, 2000 2,883,641 15,141,979
================ ================
December 31, 2001 3,939,593 21,203,989
================ ================
December 31, 2002 4,025,552 25,374,113
================ ================
F-27
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:
2002 2001 2000
---- ---- ----
Future cash inflows $ 308,381,837 $ 199,162,921 $ 318,504,931
Future production and development costs
Production 105,629,872 77,526,278 97,465,972
Development 23,350,811 23,610,596 13,400,359
------------------- ----------------- -----------------
Future cash flows before income taxes 179,401,154 98,026,047 207,638,600
Future income taxes (38,611,577) (13,281,358) (56,466,527)
------------------- ----------------- -----------------
Future net cash flows after income taxes 140,789,577 84,744,689 151,172,073
10% annual discount for estimated
timing of cash flows (63,165,742) (35,895,306) (60,790,946)
------------------- ----------------- -----------------
Standardized measure of discounted
future net cash flows $ 77,623,835 $ 48,849,383 $ 90,381,127
=================== ================= =================
The following reconciles the change in the standardized measure of discounted future net cash flows:
Beginning of year $ 48,849,383 $ 90,381,127 $ 30,955,399
Changes from:
Purchases 3,054,793 27,032,359 18,483,582
Sales (953,159) (443,324)
Extensions, discoveries and improved
recovery, less related costs 2,002,176 427,192 10,727,329
Sales of oil and gas produced net of
production costs (5,016,964) (7,270,603) (5,068,349)
Revision of quantity estimates (9,974,557) (1,783,276) 7,365,348
Accretion of discount 5,649,945 12,414,073 3,765,842
Change in income taxes (13,624,917) 26,109,535 (27,056,577)
Changes in estimated future
development costs (5,254,561) (6,360,990) (504,445)
Development costs incurred that
reduced future development costs 5,569,881 5,945,369 4,359,405
Change in sales and transfer prices,
net of production costs 46,903,282 (89,573,528) 38,543,222
Changes in production rates (timing)
and other 418,533 (8,028,551) 8,810,371
------------------- ----------------- -----------------
End of year $ 77,623,835 $ 48,849,383 $ 90,381,127
=================== ================= =================
F-28
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, 2002 and 2001 follows:
Three Months Ended
----------------------------------------------------------------------------
March 31 June 30 September 30 December 31
---------------- ---------------- ---------------- ----------------
2002
Net sales $ 2,648,873 $ 2,951,798 $ 2,641,626 $ 2,597,500
Gross profit 239,912 450,255 100,527 136,961
Net income (loss) (1,964,010) (305,060) (924,750) (1,420,993)
Income (loss) per common
share - basic and diluted $ (0.11) $ (0.02) $ (0.05) $ (0.07)
2001
Net sales $ 3,057,739 $ 3,455,882 $ 3,669,203 $ 2,807,757
Gross profit 930,784 1,219,002 1,083,789 218,300
Net income (loss) (2,409,567) 1,919,735 1,671,994 (194,121)
Income (loss) per common
share - basic $ (0.13) $ 0.10 $ 0.09 $ (0.01)
- diluted $ (0.13) $ 0.10 $ 0.08 $ (0.01)
F-29
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, 2002 and 2001 and for each of the three
years in the period ended December 31, 2002, 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, 2002, 2001 and 2000 on page F-31.
In our opinion, the financial statement schedule referred to above, when
considered in relation to the basic consolidated financial statements taken
as a whole, presents fairly, in all material respects, the information
required to be included therein.
\s\ WEAVER AND TIDWELL, L.L.P.
---------------------------------
WEAVER AND TIDWELL, L.L.P.
Dallas, Texas
March 24, 2003
F-30
GULFWEST ENERGY INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
BALANCE BALANCE
AT AT
BEGINNING PROVISIONS/ RECOVERIES/ END
DECRIPTION OF PERIOD ADDITIONS DEDUCTIONS OF PERIOD
- ---------------------------------------- ---------------- ----------------- ------------------ ---------------
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 $ (345,754) $ $ 4,668,697
================ ================= ================== ===============
For the year ended
December 31, 2002
Accounts and notes receivable
related parties $ 740,478 $ $ (740,478) $
================ ================= ================== ===============
Valuation allowance for
Deferred tax assets $ 4,668,697 $ 1,586,988 $ $ 6,255,685
================ ================= ================== ===============
F-31
CERTIFICATIONS
I, Thomas R. Kaetzer, certify that:
1. I have reviewed this amended annual report on Form 10-K of GulfWest
Energy Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date.
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
i
6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: April 9, 2003
/s/ Thomas R. Kaetzer
-------------------------------
Thomas R. Kaetzer
President and Chief Executive Officer
ii
CERTIFICATIONS
I, Richard L. Creel, certify that:
1. I have reviewed this amended annual report on Form 10-K of GulfWest
Energy Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date.
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
i
6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: April 9, 2003
/s/ Richard L. Creel
-----------------------------------
Richard L. Creel
Vice President of Finance
ii
April 9, 2003
Securities and Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549
Re: Certification Required Under Section 906 of Sarbanes-Oxley Act of 2002
In connection with the accompanying amended report on Form 10-K for the period
ended December 31, 2002, and filed with the Securities and Exchange Commission
on the date hereof (the "Report"), We, Thomas R. Kaetzer, President and CEO of
GulfWest Energy Inc. (the "Company"), and Richard L. Creel, Vice President of
Finance of the Company hereby certify that:
1. The report fully complies with the requirements of Section 13(a) or
15(d) of the Securities Exchange Act of 1934; and
2. The information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations
of the Company.
GulfWest Energy Inc.
/s/ Thomas R. Kaetzer
- ------------------------------------
By: Thomas R. Kaetzer
President and Chief Executive Officer
/s/ Richard L. Creel
- ------------------------------------
By: Richard L. Creel
Vice President of Finance