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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, 2003
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. [ ]
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
30, 2003, was approximately $3,507,271. 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 March 29, 2004.
DOCUMENTS INCORPORATED BY REFERENCE:
The registrant's definitive Proxy Statement pertaining to the 2004 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,
2003, our part of the estimated proved reserves these properties contain was
approximately 5.0 million barrels (MBbl) of oil and 32.7 billion cubic feet
(Bcf) of natural gas with a Present Value discounted 10% (PV-10) of $114.4
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. During 2003, we
worked only for our own account.
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 our own
account.
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.
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 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. By owning and
operating this equipment, we are better able to control costs, quality of
operations and availability of equipment and services.
Greater Natural Gas Ownership. At December 31, 2003, our reserves were
comprised of 48% crude oil and 52% 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, 2003, we had 34 full time employees, of whom 22 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, 2003, we owned a total of 684 gross wells, of which 266
were producing, 351 were shut-in or temporarily abandoned and 67 were injection
or saltwater wells. We owned an average 94% working interest in the 266 gross
(249.90 net) producing 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 5.0 million barrels (MBbl) of oil and 32.7 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.
2003 2002 2001
---- ---- ----
Crude Oil (MBbl)
Developed 3,773 4,026 3,940
Undeveloped 1,265 1,496 1,932
-------- --------- ---------
Total 5,038 5,522 5,872
======== ========= =========
Natural Gas (MMcf)
Developed 24,642 25,374 21,204
Undeveloped 8,018 8,785 18,054
-------- --------- ---------
Total 32,660 34,159 39,258
======== ========= =========
Total (MBOE) 10,481 11,215 12,415
======== ========= =========
(a) Approximately 75% of our total proved reserves were classified as
proved developed at December 31, 2003.
(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.
2003 2002 2001
-------------------- -------------------- -------------------
-------------------- -------------------- -------------------
Future cash inflows $ 336,795,385 $ 308,381,837 $ 199,162,921
Future production and development costs-
Production 109,468,727 105,629,872 77,526,278
Development 21,460,459 23,350,811 23,610,596
-------------------- -------------------- -------------------
Future net cash flows before income taxes 205,866,199 179,401,154 98,026,047
Future income taxes (46,885,360) (38,611,577) (13,281,358)
-------------------- -------------------- -------------------
Future net cash flows after income taxes 158,980,839 140,789,577 84,744,689
10% annual discount for estimated timing
of cash flows (70,653,419) (63,165,742) (35,895,306)
-------------------- -------------------- -------------------
Standardized measure of discounted
Future net cash flows(1) $ 88,327,420 $ 77,623,835 $ 48,849,383
==================== ==================== ===================
(1) The average prices of our proved reserves were $29.51 per Bbl and $5.82 per
Mcf, $28.72 per Bbl and $4.43 per Mcf, and $17.67 and $2.43 per Mcf at December
31, 2003, 2002 and 2001 respectively.
Significant Properties.
Summary information on our properties with proved reserves is set forth
below as of December 31, 2003.
Productive Wells Proved Reserves Present
--------------------------------------------------------------------------------------- ----------------
Value (1)
---------
Gross Net
Productive Productive Crude Natural
Wells Wells Oil Gas Total Amount
-------------- --------------------------------- -------------- ---------------- ---------------
(MBbl) (MMcf) (MBOE) ($M)
Texas 185 181.03 2,969 18,717 6,088 $ 67,235
Colorado 35 23.62 355 6,090 1,370 11,303
Oklahoma 28 28.00 150 - 150 1,301
Louisiana 17 16.88 1,558 7,853 2,867 34,484
Mississippi 1 .37 6 - 6 73
------------------------------------------------- ------------------------------------ --------------
Total 266 249.90 5,038 32,660 10,481 $ 114,396
================================================= ==================================== ==============
(1) The average prices of our proved reserves were $29.51 per Bbl and $5.82 per
Mcf at December 31, 2003.
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, 2003, 2002
and 2001.
2003 2002 2001
------------- ---------------- ----------------
Production
Oil (Bbl) 221,433 278,374 294,276
Natural gas (Mcf) 1,191,350 1,487,048 1,594,899
------------- ---------------- ----------------
Total (BOE) 419,991 526,215 560,092
Revenue
Oil production $ 5,362,657 $ 5,859,568 $ 6,690,338
Natural gas production 5,481,803 4,587,601 5,735,765
------------- ---------------- ----------------
Total $10,844,460 $10,447,169 $12,426,103
Operating Expenses $ 5,527,841 $ 5,430,205 $ 5,155,500
Production Data
Average sales price
Per barrel of oil $ 24.22 $ 21.05 $ 22.73
Per Mcf of
natural gas 4.60 3.09 3.60
Per BOE 25.82 19.85 22.19
Average expenses per BOE
Lease operating 13.16 10.32 9.20
Depreciation, depletion
and amortization 5.30 5.13 4.45
General and
administrative $ 5.39 3.28 3.05
Productive Wells at December 31, 2003:
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 109 108.81 76 72.22
Colorado 22 14.37 13 9.25
Oklahoma 28 28.00 - -
Louisiana 13 12.88 4 4.00
Mississippi 1 .37 - -
------------ ------------ ------------- ------------
Total 173 164.43 93 85.47
============ ============ ============= ============
8
Developed Acreage at December 31, 2003.
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 18,380 14,255
Colorado 5,000 2,700
Louisiana 1,695 1,256
Oklahoma 900 684
------------------ --------------------
Total 25,975 18,895
================== ====================
Undeveloped Acreage at December 31, 2003.
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 18,070 14,749
Colorado 10,000 6,000
Louisiana 80 55
Oklahoma 900 684
------------------ --------------------
Total 29,050 21,488
================== ====================
Drilling Results.
We did not drill any wells in 2003. 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, all of which were development wells and are
currently productive. These development wells included two horizontal wells, in
which we own 96% and 89% working interest, drilled by sidetracking from existing
wellbores in the Madisonville Field, Texas, and one well, in which we own 100%
working interest, 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 25% of our total estimated proved reserves at December 31,
2003 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, 2003. The average prices of all properties were $29.51 per barrel
of oil and $5.82 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
11
from proved reserves. In addition, the 10% discount factor, which is required by
the SEC to be used in calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor. The effective
interest rate at various times and the risks associated with our business or the
oil and gas industry in general will affect the accuracy of the 10% discount
factor.
Except to the extent that we acquire properties containing proved reserves
or conduct successful development or exploitation activities, our proved
reserves will decline as they are produced.
In general, the volume of production from crude oil and natural gas
properties declines as reserves are depleted. Our future crude oil and natural
gas production is highly dependent upon our success in finding or acquiring
additional reserves.
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, as was the case in 2003.
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 March 29, 2004, there was a total of 19,000 shares of preferred stock
issued and outstanding in three series, including 8,000 shares of Series D,
9,000 shares of Series E and 2,000 shares of Series F. The 8,000 shares of
Series D Preferred Stock are held by a former director, the 9,000 shares of
Series E Preferred Stock are held by a current director and the 2,000 shares of
Series F are held by our largest lender. Our preferred stock is senior to our
common stock regarding liquidation. The holders of the preferred stock do not
have voting rights or preemptive rights nor are they 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. None of the
8,000 outstanding shares of Series D preferred stock has been converted. On a
fully converted basis, the 8,000 shares of Series D preferred stock would
convert to 500,000 shares of common stock.
14
The Series E preferred stock is entitled to receive dividends at the rate
of $12.50 per share per annum, payable quarterly, as declared by the board of
directors, until June 30, 2004 when the dividend rate shall be increased to
$30.00 per share per annum. The board of directors did not declare payment of
dividends during 2003. The Series E preferred stock is redeemable in whole or in
part at any time, at the option of the issuer, at a price of $500 per share,
plus all accrued and undeclared or unpaid dividends; except that, prior to our
redemption of the remaining, the holders of record shall be given a 60-day
written notice of the issuer's 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 is based on $2.00 per share of common stock. None of
the 9,000 outstanding shares of Series E preferred stock has 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.
The Series F preferred stock is entitled to receive dividends at the rate
of $12.50 per share per annum, payable quarterly, as declared by the board of
directors, until May 30, 2006 when the dividend rate shall be increased to
$30.00 per share per annum. The Series F preferred stock is redeemable in whole
or in part at any time, at the option of the issuer, 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, June 1, 2003, and prior to our
redemption of the remaining shares, the holders of record shall be given a
60-day written notice of the issuer's intent to redeem and the opportunity to
convert the Series F preferred stock to common stock. The conversion price for
the Series F preferred stock is based on $1.00 per share of common stock. None
of the 2,000 outstanding shares of Series F preferred stock has been redeemed or
converted. On a fully converted basis, the 2,000 shares of Series F preferred
stock would convert to 1,000,000 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 March 29, 2004, 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, 2003, we had outstanding warrants and options for the purchase
of 3,067,000 shares of common stock at prices ranging from $.75 to $1.81 per
share, including employee stock options to purchase 1,102,000 shares at prices
ranging from $.75 to $1.81 per share. If we issue additional shares, the
existing shareholders' percentage ownership of our 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."
15
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 March 29, 2004, 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, 2003.
16
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 2003, 2002
and 2001 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
---- ---
2003
----
First Quarter $ .45 $.42
Second Quarter .47 .35
Third Quarter .47 .43
Fourth Quarter .47 .32
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
We are authorized to issue 40,000,000 shares of Class A common stock, par
value $.001 per share (the "common stock"). As of March 29, 2004, 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.
17
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 March 29, 2004, there was a total of 19,000 shares of preferred
stock issued and outstanding in three series, including 8,000 shares of Series
D, 9,000 shares of Series E and 2,000 shares of Series F. The 8,000 shares of
Series D Preferred Stock are held by a former director, the 9,000 shares of
Series E Preferred Stock are held by a current director and the 2,000 shares of
Series F are held by our largest lender. Our preferred stock is senior to our
common stock regarding liquidation. The holders of the preferred stock do not
have voting rights or preemptive rights nor are they 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. None of the
8,000 outstanding shares of Series D preferred stock has been converted. On a
fully converted basis, the 8,000 shares of Series D preferred stock would
convert to 500,000 shares of common stock.
The Series E preferred stock is entitled to receive dividends at the rate
of $12.50 per share per annum, payable quarterly, as declared by the board of
directors, until June 30, 2004 when the dividend rate shall be increased to
$30.00 per share per annum. The board of directors did not declare payment of
dividends during 2003. The Series E preferred stock is redeemable in whole or in
part at any time, at the option of the issuer, at a price of $500 per share,
plus all accrued and undeclared or unpaid dividends; except that, prior to our
redemption of the remaining shares, the holders of record shall be given a
60-day written notice of the issuer's 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 is based on $2.00 per share of common stock. None
of the 9,000 outstanding shares of Series E preferred stock has 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.
The Series F preferred stock is entitled to receive dividends at the rate
of $12.50 per share per annum, payable quarterly, as declared by the board of
directors, until May 30, 2006 when the dividend rate shall be increased to
$30.00 per share per annum. The Series F preferred stock is redeemable in whole
or in part at any time, at the option of the issuer, 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, June 1, 2003, and prior to our
redemption of the remaining shares, the holders of record shall be given a
60-day written notice of the issuer's intent to redeem and the opportunity to
convert the Series F preferred stock to common stock. The conversion price for
the Series F preferred stock is based on $1.00 per share of common stock. None
of the 2,000 outstanding shares of Series F preferred stock has been redeemed or
converted. On a fully converted basis, the 2,000 shares of Series F preferred
stock would convert to 1,000,000 shares of common stock.
Outstanding Options and Warrants.
At March 29, 2004, we had outstanding warrants and options for the purchase
3,067,000 shares of common stock at prices ranging from $.75 to $1.81 per share,
including employee stock options to purchase 1,102,000 shares at prices ranging
from $.75 to $1.81 per share.
18
Recent Sales of Unregistered Securities.
During 2002 and 2003, and to March 29, 2004, 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
----------- --------
Derivative Grantee(s) Shares Price Consider-
ation
---------- ---------- ------ ----- -------------
Date
----
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
04/01/03 Option Employee 35,000 $ .75 Compensation
(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.
19
ITEM 6. Selected Financial Data.
The following table sets forth selected historical financial data of our
company as of December 31, 2003, 2002, 2001, 2000 and 1999, 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, 2003, 2002 and 2001 and the
balance sheet data at December 31, 2003 and 2002 are derived from our audited
financial statements contained elsewhere herein. The income statement data for
the years ended December 31, 2000 and 1999 and the balance sheet data at
December 31, 2001, 2000 and 1999 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,
2003 2002 2001 2000 1999
----------------- ----------------- ----------------- ----------------- -----------------
Income Statement Data
- ---------------------
Operating Revenues $ 11,010,723 $ 10,839,797 $ 12,990,581 $ 8,984,175 $ 2,812,639
Net income (loss) from
operations 917,571 927,655 3,451,875 2,464,017 (1,464,094)
Net income (loss) (3,024,426) (4,502,313) 1,044,291 352,774 (2,269,506)
Dividends on preferred stock (127,083) (112,500) (56,250) - (450,684)
Net income (loss) available to
common shareholders (3,151,509) (4,614,813) 988,401 352,774 (2,720,190)
Net income (loss), per share
of common stock $ (.17) $ (.25) $ .05 $ .02 $ (.34)
Weighted average number
of shares of common
stock outstanding 18,492,541 18,492,541 18,464,343 17,293,848 7,953,147
Balance Sheet Data
- ------------------
Current assets $ 1,742,689 $ 2,353,046 $ 2,205,862 $ 2,934,804 $ 1,357,465
Total assets 52,428,774 53,088,941 51,379,209 32,374,128 20,009,793
Current liabilities 44,619,652 43,998,566 12,492,365 7,594,986 4,650,691
Long-term obligations 1,393,607 137,808 26,541,957 18,077,371 11,304,318
Other liabilities 591,467 1,128,993 - - -
Stockholders' Equity $ 5,824,648 $ 7,823,574 $ 12,344,887 $ 6,701,771 $ 4,054,784
20
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. During 2003, we
worked only for our own account.
The following is a discussion of our consolidated financial condition,
results of operations, financial condition and capital resources. You should
read this discussion in conjunction with our Consolidated Financial Statements
and the Notes thereto contained elsewhere herein. See "Financial Statements."
Results of Operations.
The factors which most significantly affect our results of operations are
(1) the sales price of crude oil and natural gas, (2) the level of total sales
volumes of crude oil and natural gas, (3) the cost and efficiency of operating
our own properties, (4) depletion and depreciation of oil and gas property costs
and related equipment (5) the level of and interest rates on borrowings, (6) the
level and success of new acquisitions and development of existing properties,
and (7) the adoption of changes in accounting rules.
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.
21
Comparative results of operations for the periods indicated are discussed
below.
Year Ended December 31, 2003 Compared to Year Ended December 31, 2002
Revenues
Oil and Gas Sales. Our operating revenues from the sale of crude oil and
natural gas increased by 4% from $10,447,000 in 2002 to $10,844,000 in 2003.
This increase was due to higher sales prices but offset by normal oil and gas
production declines and lower production volumes. We were unable to offset those
declines and maintain or increase production through development efforts because
of limited development capital.
Well Servicing Revenues. There were no revenues from our well servicing
operations in 2003 compared to $39,000 in 2002 since we ceased performing work
for other operators and concentrated on our own properties.
Operating Overhead and Other Income. Revenues from these activities
decreased 53% from $354,000 in 2002 to $166,000 in 2003, primarily due to (1)
the loss of an oil and gas marketing contract and (2) lower pipeline volumes
resulting in less transportation revenue.
Costs and Expenses
Lease Operating Expenses. Lease operating expenses increased 2% from
$5,430,000 in 2002 to $5,528,000 in 2003 due to increased vendor prices.
Cost of Well Servicing Operations. There were no well servicing expenses in
2003 compared to $56,000 in 2002 since we did not work for other operators.
Depreciation, Depletion and Amortization (DD and A). DD and A decreased 17%
from $2,698,000 in 2002 to $2,226,000 in 2003, due to lower production volumes.
We also recorded income of $262,000 related to the cumulative effect of adopting
SFAS 143.
Accretion Expense. We recorded accretion expense of $77,000 as a result of
adopting SFAS 143 "Asset Retirement Obligation", effective January 1, 2003.
General and Administrative (G and A) Expenses. G and A expenses increased
31% from $1,728,000 in 2002 to $2,262,000 in 2003 due to expenses associated
with financing efforts that were not culminated.
Interest Income and Expense. Interest expense increased 6% from $3,159,000
in 2002 to $3,363,000 in 2003 due to penalty interest paid to our largest lender
under a provision in the loan agreement.
Other Financing Costs. In 2003, we recorded an expense of $1,000,000 to
account for the issuance of 2,000 shares of our preferred stock to our largest
lender under a financial agreement.
Unrealized Gain (Loss) on Derivative Instruments. The estimated future fair
value of derivative instruments at December 31, 2003 resulted in an unrealized
gain of $537,000 in 2003 compared to an unrealized loss of $1,597,000 in 2002.
Dry Holes, Abandoned Property and Impaired Assets. The cost of abandoned
property in 2003 was $538,000 because the lack of capital to complete projects
resulted in the loss of leases. This compared to combined costs of dry holes,
abandoned property and impaired assets of $617,000 in 2002.
22
Dividends on Preferred Stock. In 2003, dividends on preferred stock due was
$127,000, however the board of directors did not declare any dividends be paid.
In 2002, dividends on preferred stock due was $112,000 and paid was $112,000.
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 $1,597,000 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 $222,000 and impaired
assets in Mississippi of $55,000 totaled $617,000 in 2002 compared to none in
2001.
Dividends on preferred stock due was $112,000 and paid was $112,000 in
2002. Dividends on preferred stock due was $56,000 and paid was $28,000 in 2001.
23
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 we have 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 2001. Major components of the
increase included operating overhead $82,000, gathering and marketing $211,000,
sale of exploratory leases $96,000 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 $56,000 and paid was $28,000 in 2001.
No dividends were due or paid in 2000.
24
Financial Condition and Capital Resources.
At December 31, 2003, our current liabilities exceeded our current assets
by $42,876,963. We had a loss available to common shareholders of $3,151,509
compared to a loss available to common shareholders of $4,614,813 at December
31, 2002. This loss included non-cash items of $537,526 for unrealized gain on
derivative instruments, a loss of $358,737 for abandonment of properties and a
$262,452 gain from the recording of Asset Retirement Obligations ("ARO's"), as
required by SFAS 143, at January 1, 2003.
In 2004, we will continue the recapitalization of debt and funding of our
capital development program that we began in 2003. Following are the steps we
are taking and plan to take to achieve that purpose:
(a) The first step is to close the refinancing of our largest debt of $27.8
million held by Concert Capital Resources LP ("CCR") and loaned to our
wholly-owned subsidiary, GulfWest Oil and Gas Company. We have entered into an
agreement with a new lending source that, subject to due diligence, will fund
approximately $14 million to purchase the $27.8 million note. The new debt
financing will also provide for the payment of closing costs. CCR has agreed to
sell the note to our new financier for a $14 million cash payment and a $4
million subordinated note from us.
(b) Secondly, we are continuing to work with our financial advisor to raise
an additional $4 to $5 million through the sale of our preferred stock. Proceeds
from this equity sale will be used for working capital and fund our new
development projects. The refinancing of the CCR debt and sale of new equity are
both currently scheduled to close in April, 2004.
(c) 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 provided payments in the
aggregate of $1,200,000 in advanced funds for our use in the acquisition of oil
and gas leases and other mineral and royalty interests, and production
activities, and was to recoup and recover those advanced funds.
In a subsequent event on March 5, 2004, we entered into an Option Agreement
for the Purchase of Oil and Gas Leases (the "Addison Agreement") with W. L.
Addison Investments L.L.C., a private company owned by Mr. J. Virgil Waggoner
and Mr. John E. Loehr, two of our directors, (`Addison"). Under the Addison
Agreement, Addison agreed to pay Summit, on our behalf, the non-recouped and
outstanding advanced funds amounting to $1,200,000, thereby retiring the Summit
Agreement. For consideration of such payment, Addison acquired certain oil and
gas leases and wellbores from Summit but agreed to grant us a 180-day redemption
option (which may be extended by mutual consent) to purchase the same for
$1,200,000, plus interest at the prime rate plus 2%. We tendered Addison a
promissory note in the amount of $600,000, with interest at the prime rate plus
2%, to substitute for an account payable to Summit, pursuant to the Summit
Agreement, in the same amount. The note will be considered paid in full if we
exercise the redemption option and pay the $1,200,000, plus interest. Summit
retained the right to participate up to a 25% working interest in the drilling
of any wells on the leases acquired by Addison. In the event we exercise the
redemption option, Addison may, at its sole option, retain up to a 25% working
interest in the leases.
(d) Finally, after completing the above, we will pursue the consolidation
of all of our debt, including other asset and bridge loans. Our goal is to
simplify our financial structure and provide adequate capitalization for the
development of our oil and gas assets.
25
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)
2003
- ----
First $ 24.53 $ 5.36 $ 28.08
Second 23.53 4.47 25.04
Third 23.85 4.32 24.86
Fourth 24.99 4.56 25.02
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
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 our financial instruments are for purposes other than trading. We
only enter derivative financial instruments in conjunction with our 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.
26
Interest Rate Risk
We are exposed to interest rate risk on debt with variable interest rates.
At December 31, 2003, we carried variable rate debt of $37,955,334. Assuming a
one percentage point change at December 31, 2003 on our variable rate debt, the
annual pretax income (loss) would change by $379,553.
Commodity Price Risk
We hedge a portion of its price risks associated with its oil and natural
gas sales which are classified as derivative instruments. As of December 31,
2003, these derivative instruments' liabilities had a fair value of $591,467.
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
ITEM 9A. 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.
27
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) 76 Chairman of the Board 1997
Thomas R. Kaetzer 45 Chief Executive Officer 1998
President and Director
Jim C. Bigham 68 Executive Vice President 1991
and Secretary
Richard L. Creel 55 Vice President of Finance 1998
and Controller
Marshall A. Smith III 56 Director 1989
John E. Loehr(1)(2) 58 Director 1992
M. Scott Manolis(1)(2) 50 Director 2003
(1) Member of the Audit Committee.
(2) Member of the Compensation Committee.
J. Virgil Waggoner has served as a director of GulfWest since December 1,
1997 and was elected Chairman of the Board in May, 2002. 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.
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.
28
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.
M. Scott Manolis is newly nominated to the board. He is the chairman and
chief executive officer of Intermarket Management, LLC and Intermarket
Brokerage, LLC. He has over twenty years experience in commodity risk
management, commodity finance and commodity-based investments. Prior to founding
Intermarket, Mr. Manolis concurrently served as managing director of Commodity
Strategies for Refco Group, LTD. and Managing Director of Global Derivatives
Strategies for Forstmann-Leff International (an asset management firm wholly
owned by Refco Group, LTD), where he directed commodity-based investments. Prior
to that, he served as a vice president and director of the Commodity Portfolio
Management Group at Jefferies and Company. He received a B. S. in Economics from
the University of South Dakota in 1979.
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 4 times during the calendar year ended
December 31, 2003.
Committees of the Board of Directors.
Our board of directors has established an audit committee and a
compensation committee. The functions of these committees, their current
members, and the number of meetings held during 2003 are described below.
The audit committee was established to review and appraise the audit
efforts of our independent auditors, and monitor our accounts, procedures and
internal controls. The committee is comprised of Mr. John E. Loehr (Chairman),
Mr. J. Virgil Waggoner and Mr. M. Scott Manolis. The committee met twice in
2003.
The function of the compensation committee is to fix the annual salaries
and other compensation for our officers and key employees. The committee is
comprised of Mr. J. Virgil Waggoner (Chairman), Mr. John E. Loehr and Mr. M.
Scott Manolis. The committee met twice in 2003.
29
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 2003 or
2002.
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. Principal Accounting Fees and Services.
Information regarding principal accounting fees and services is
incorporated herein by reference to our Proxy Statement.
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.
32
Royalty Interest. An interest in an oil and gas property entitling the owner to
a share of oil and natural gas production free of costs of production.
Standardized Measure. The present value, discounted at 10%, of future net cash
flows from estimated proved reserves, after income taxes, calculated holding
prices and costs constant at amounts in effect on the date of the report (unless
such prices or costs are subject to change pursuant to contractual provisions)
and otherwise in accordance with the Commission's rules for inclusion of oil and
gas reserve information in financial statements filed with the Commission.
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,
2003 and 2002. Consolidated Statements of Operations for the
years ended December 31, 2003, 2002 and 2001. Consolidated
Statements of Stockholders' Equity for the years ended December
31, 2003, 2002 and 2001. Consolidated Statements of Cash Flows
for the years ended December 31, 2003, 2002 and 2001. Notes to
Consolidated Financial Statements, December 31, 2003, 2002 and
2001.
(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.
----------
* Previously filed with our Registration Statement
(on Form S-1, Reg. No. 33-53526), filed with the
Commission on October 21, 1992.
% Previously filed with our Proxy Statement on Form DEF
14A, filed with the Commission on April 16, 2001.
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).
31.1 Certification of Chief Executive Officer pursuant to
Exchange Rule 13a-14(a) as adopted pursuant to Section
302 of the Sarbanes-Oxley Act of 2002; filed herewith.
31.2 Certification of Chief Financial Officer pursuant to
Exchange Rule 13a-14(a) as adopted pursuant to Section
302 of the Sarbanes-Oxley Act of 2002; filed herewith.
32 Certification pursuant to 18.U.S.C Section 1350 pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002;
filed herewith.
(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: March 29, 2004 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 March 29, 2004
- ----------------------
J. Virgil Waggoner
\s\ Thomas R. Kaetzer President, Chief Executive March 29, 2004
- ------------------------- Officer and Director
Thomas R. Kaetzer
\s\ Jim C. Bigham Executive Vice President March 29, 2004
- --------------------------- and Secretary
Jim C. Bigham
\s\ Richard L. Creel Vice President of Finance, March 29, 2004
- ---------------------------- Controller
Richard L. Creel
\s\ Marshall A. Smith III Director March 29, 2004
- -------------------------
Marshall A. Smith III
\s\ John E. Loehr Director March 29, 2004
- -----------------
John E. Loehr
\s\ M. Scott Manolis Director March 29, 2004
- --------------------
M. Scott Manolis
35
GULFWEST ENERGY INC.
FINANCIAL REPORT
DECEMBER 31, 2003
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, 2003 and 2002,
and the related consolidated statements of operations, stockholders' equity and
cash flows for each of the three years in the period ended December 31, 2003.
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, 2003 and 2002, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 2003, 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 $3,151,509 during the
year ended December 31, 2003, and, as of that date, had a working capital
deficiency of $42,876,963. 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.
As explained in Note 1 to the Financial Statements, effective January 1, 2003,
the Company changed its accounting method for Asset Retirement Obligations.
\s\WEAVER AND TIDWELL, L.L.P
- ------------------------------
WEAVER AND TIDWELL, L.L.P.
Dallas, Texas
March 19, 2004
F-1
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2003 AND 2002
ASSETS
---------------- -----------------
2003 2002
---------------- -----------------
CURRENT ASSETS
Cash and cash equivalents $ 483,618 $ 687,694
Accounts receivable - trade, net of allowance
for doubtful accounts of $-0- in 2003 and 2002 1,099,802 1,361,446
Prepaid expenses 159,269 303,906
---------------- -----------------
Total current assets 1,742,689 2,353,046
---------------- -----------------
OIL AND GAS PROPERTIES,
using the successful efforts method of accounting 58,472,886 56,786,043
OTHER PROPERTY AND EQUIPMENT 2,132,220 2,121,410
Less accumulated depreciation, depletion and amortization (10,017,931) (8,498,497)
---------------- -----------------
Net oil and gas properties and other property and equipment 50,587,175 50,408,956
---------------- -----------------
OTHER ASSETS
Deposits 20,142 37,442
Debt issue cost, net 78,768 289,497
---------------- -----------------
Total other assets 98,910 326,939
---------------- -----------------
TOTAL ASSETS $ 52,428,774 $ 53,088,941
================ =================
The Notes to Consolidated Financial Statements are an integral part of these statements.
F-2
LIABILITIES AND STOCKHOLDERS' EQUITY
---------------- -----------------
2003 2002
---------------- -----------------
CURRENT LIABILITES
Notes payable $ 8,182,165 $ 4,936,088
Notes payable - related parties 1,465,000 1,290,000
Current portion of long-term debt 29,396,092 33,128,447
Current portion of long-term debt - related parties 130,152 256,967
Accounts payable - trade 5,002,675 3,928,477
Accrued expenses 443,568 458,587
---------------- -----------------
Total current liabilities 44,619,652 43,998,566
---------------- -----------------
NONCURRENT LIABILITIES
Long-term debt, net of current portion 35,801 126,552
Long-term debt - related parties - 11,256
Asset retirement obligations 1,357,206 -
---------------- -----------------
Total noncurrent liabilities 1,393,007 137,808
---------------- -----------------
OTHER LIABILITES
Derivative instruments 591,467 1,128,993
---------------- -----------------
Total Liabilities 46,604,126 45,265,367
---------------- -----------------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock 190 170
Common stock 18,493 18,493
Additional paid-in capital 29,283,692 28,258,212
Retained deficit (23,477,727) (20,453,301)
---------------- -----------------
Total stockholders' equity 5,824,648 7,823,574
---------------- -----------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 52,428,774 $ 53,088,941
================ =================
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, 2003, 2002 AND 2001
2003 2002 2001
---------------- ----------------- -----------------
---------------- ----------------- -----------------
OPERATING REVENUES
Oil and gas sales $ 10,844,460 $ 10,447,169 $ 12,426,103
Well servicing revenues 39,116 169,167
Operating overhead and other income 166,263 353,512 395,311
---------------- ----------------- -----------------
Total Operating Revenues 11,010,723 10,839,797 12,990,581
---------------- ----------------- -----------------
OPERATING EXPENSES
Lease operating expenses 5,527,841 5,430,205 5,155,500
Cost of well servicing operations 56,295 182,180
Depreciation, depletion and amortization 2,226,123 2,697,784 2,491,385
Accretion expense 76,823
General administrative 2,262,425 1,727,858 1,709,641
---------------- ----------------- -----------------
Total Operating Expenses 10,093,212 9,912,142 9,538,706
---------------- ----------------- -----------------
INCOME FROM OPERATIONS 917,511 927,655 3,451,875
---------------- ----------------- -----------------
OTHER INCOME AND EXPENSE
Interest expense (3,363,330) (3,159,381) (2,756,912)
Other financing costs (1,000,000)
Gain (loss) on sale of assets (19,848) (56,647) (118,254)
Unrealized gain (loss) on derivative instruments 537,526 (1,596,575) 4,215,017
Dry holes, abandoned property and impaired assets (358,737) (617,365)
---------------- ----------------- -----------------
Total Other Income and (Expense) (4,204,389) 5,429,968 1,339,851
---------------- ----------------- -----------------
INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES (3,286,878) (4,502,313) 4,791,726
INCOME TAXES
---------------- ----------------- -----------------
INCOME (LOSS) BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLES (3,286,878) (4,502,313) 4,791,726
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES, NET OF INCOME TAXES 262,452 (3,747,435)
---------------- ----------------- -----------------
NET INCOME (LOSS) $ (3,024,426) $ (4,502,313) $ 1,044,291
DIVIDENDS ON PREFERRED STOCK
(PAID 2003-$-0-; 2002-$112,500; 2001-
$28,125) (127,083) (112,500) (56,250)
---------------- ----------------- -----------------
NET INCOME (LOSS) AVAILABLE TO COMMON
SHAREHOLDERS $ (3,151,509) $ (4,614,813) $ 988,041
================ ================= =================
NET INCOME (LOSS) PER SHARE, BASIC
BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLES $ (.18) $ (.25) $ .25
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES .01 (.20)
---------------- ----------------- -----------------
NET INCOME (LOSS) PER SHARE BASIC $ (.17) $ (.25) $ .05
================ ================= =================
NET INCOME (LOSS) PER SHARE, DILUTED BEFORE CUMULATIVE
EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES $ (.18) $ (.25) $ .23
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES .01 (.18)
---------------- ----------------- -----------------
NET INCOME (LOSS) PER SHARE, DILUTED $ (.17) $ (.25) $ .05
================ ================= =================
F-4
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
-------------------------------
Number of Shares
-------------------------------
-------------- -- -------------
Preferred Common
Stock Stock
-------------- -------------
BALANCE, December 31, 2000 18,445,041
8,000
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
============== =============
Issuance of warrants for additional financing
Issuance of preferred stock related to current financing 2,000
Net loss
-------------- -------------
BALANCE, December 31, 2003 19,000 18,492,541
============== =============
The Notes to Consolidated Financials are an integral part of these statements.
F-5
Preferred Common Additional Retained
Stock Stock Paid-In Capital Deficit
- -------------------------- ------------------------ ------------------------ ---------------------------
$ 80 $ 18,445 $ 23,537,900 $ (16,854,654)
90 4,499,910
48 35,402
91,500
1,044,291
(28,125)
- -------------------------- ------------------------ ------------------------ ---------------------------
$ 170 $ 18,493 $ 28,164,712 $ (15,838,488)
========================== ======================== ======================== ===========================
93,500
(4,502,313)
(112,500)
- -------------------------- ------------------------ ------------------------ ---------------------------
$ 170 $ 18,493 $ 28,258,212 $ (20,453,301)
========================== ======================== ======================== ===========================
25,500
20 999,980
(3,024,426)
- -------------------------- ------------------------ ------------------------ ---------------------------
$ 190 $ 18,493 $ 29,283,692 $ (23,477,727)
========================== ======================== ======================== ===========================
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, 2003, 2002 AND 2001
2003 2002 2001
--------------- ---------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (3,024,426) $ (4,502,313) $ 1,044,291
Adjustments to reconcile net income (loss) to net cash
Provided by operating activities:
Depreciation, depletion and amortization 2,226,123 2,697,784 2,491,385
Accretion expense 76,823
Common stock and warrants issued and charged to
operations 25,500 93,500
Other financing costs 1,000,000
Loss on sale of assets 19,848 56,647 118,254
Dry holes, abandoned property, impaired assets 358,737 617,365
Unrealized (gain) loss on derivative instruments (537,526) 1,596,575 (4,215,017)
Cumulative effect of accounting change (262,452) 3,747,435
Provision for bad debts 29,201
(Increase) decrease in accounts receivable -
trade, net 232,443 (109,437) 765,939
(Increase) decrease in prepaid expenses 144,637 (179,825) (40,730)
Increase (decrease) in accounts payable and
accrued expenses 1,235,503 1,043,994 797,800
--------------- ---------------- ---------------
Net cash provided by operating activities 1,524,411 1,314,290 4,709,357
--------------- ---------------- ---------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Deposits (9,804)
Proceeds from sale of property and equipment 38,561 675,440 394,423
Purchase of property and equipment (1,067,924) (5,861,969) (6,962,650)
--------------- ---------------- ---------------
Net cash used in investing activities (1,029,363) (5,186,529) (6,578,031)
--------------- ---------------- ---------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on debt (1,672,288) (3,410,778) (6,577,928)
Proceeds from debt issuance 973,164 7,394,181 8,530,269
Debt issue cost (29,544)
Dividends paid (112,500) (28,125)
--------------- ---------------- ---------------
Net cash provided by (used in) financing
activities (699,124) 3,870,903 1,894,672
--------------- ---------------- ---------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (204,076) (1,336) 25,998
CASH AND CASH EQUIVALENTS,
Beginning of year 687,694 689,030 663,032
--------------- ---------------- ---------------
CASH AND CASH EQUIVALENTS,
End of year $ 483,618 $ 687,694 689,030
=============== ================ ===============
CASH PAID FOR INTEREST $ 3,216,034 $ 3,004,015 $ 2,811,677
=============== ================ ===============
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 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, 2003, we
adopted Statement of Financial Accounting Standard No. 143 "Asset
Retirement Obligations" (SFAS 143). As a result of adopting SFAS
143, effective January 1, 2003, we recorded an asset retirement
obligation liability of $1,280,383, an increase in the carrying
value of our oil and gas properties of $1,058,445, a reduction in
accumulated depletion of $484,390 and an adjustment to prior
income of $262,452. This liability was increased during 2003 by
recognizing $76,823 in accretion expense. Also, we decreased the
current portion of long term debt-related parties by applying
$17,300 in deposits and reclassified $176,320 from accrued
expenses to current portion of long term debt.
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.
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, 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.
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:
2003 2002
--------------------- ---------------------
Automobiles $ 420,776 $ 420,776
Office equipment 148,172 137,362
Gathering system 529,486 529,486
Well servicing equipment 1,033,786 1,033,786
--------------------- ---------------------
2,132,220 2,121,410
Less accumulated depreciation (1,268,330) (1,037,076)
--------------------- ---------------------
Net capitalized cost $ 863,890 $ 1,084,334
===================== =====================
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, 2003,
2002, and 2001 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.
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.
Fair Value of Financial Instruments
At December 31, 2003 and 2002, 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.
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.
Basic earnings (loss) per share are based on the weighted-average
number of outstanding common shares. Diluted earnings (loss)
per-share are based on 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 2003, 2002 and 2001 financial statements.
During 2003, 2002 and 2001, we issued options and warrants
totaling: 2003 - 35,000 (all exercisable); 2002 - 405,000 (all
exercisable); and 2001 - 184,000 (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:
2003 2002 2001
--------------------------- ---------------------------- --------------------------
As Reported ProForma As Reported ProForma As Reported ProForma
------------ ----------- ------------ ------------ ----------- -----------
SFAS 123
compensation cost $ $ 7,350 $ $ 38,300 $ $ 99,360
APB 25
compensation cost $ $ $ $ $ $
Net income (loss) $(3,151,509) $(3,158,859) $(4,614,813) $(4,653,113) $ 988,041 $ 888,681
Income (loss) per
common share-basic $ (.17) $ (.17) $ (.25) $ (.25) $ .05 $ .05
Income (loss) per
common share-diluted $ (.17) $ (.17) $ (.25) $ (.25) $ .05 $ .04
F-12
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) risk free interest
rate 2003 - 3.0%; 2002 - 3.0%; 2001 - 4.5%; (2) weighted average
expected life 2003 - 3.4; 2002 - 3.6; 2001 - 5.0; (3) expected
volatility of 2003 - 147.43; 2002 - 101.73%; 2001 - 103.27%; 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.
Beginning in 2003, Statement of Financial Accounting Standards
No. 143, "Asset Retirement Obligations" ("SFAS 143") requires us to
recognize an estimated liability for the plugging and abandonment of
our oil and gas wells and associated pipelines and equipment.
Consistent with industry practice, historically we had assumed the
cost of plugging and abandonment would be offset by salvage value
received. This statement requires us to record a liability in the
period in which our asset retirement obligation ("ARO") is incurred.
After initial recognition of the liability, we must capitalize an
additional asset cost equal to the amount of the liability. In
addition to any obligation that arises after the effective date of
SFAS 143, upon initial adoption we must recognize (1) a liability for
any existing ARO's, (2) capitalized cost related to the liability, and
(3) accumulated depreciation, depletion and amortization on that
capitalized cost adjusting for the salvage value of related equipment.
The estimated liability is based on historical experience in
plugging and abandoning wells, estimated remaining lives of those
wells based on reserves estimates and federal and state regulatory
requirements. The liability is discounted using an assumed
credit-adjusted risk-free rate of 7.5%. Revisions to the liability
could occur due to changes in estimates of plugging and abandonment
costs, changes in the risk-free rate or remaining lives of the wells,
or if federal or state regulators enact new plugging and abandonment
requirements. At the time of abandonment, we will be required to
recognize a gain or loss on abandonment if the actual costs do not
equal the estimated costs.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative
effect adjustment to record (i) a $1,058,445 increase in the carrying
value of proved properties, (ii) a $484,390 decrease in accumulated
depreciation, depletion and amortization, (iii) a $1,280,383 increase
in noncurrent liabilities, and (iv) a $262,452 gain, net of tax.
Note 2. Operations and Management Plans
At December 31, 2003, our current liabilities exceeded our
current assets by $42,876,963. We had a loss available to common
shareholders of $3,151,509 compared to a loss available to common
shareholders of $4,614,813 at December 31, 2002. This loss included
non-cash items of $537,526 for unrealized gain on derivative
instruments, a loss of $358,737 for abandonment of properties and a
$262,452 gain from the recording of Asset Retirement Obligations
("ARO's"), as required by SFAS 143, at January 1, 2003.
In 2004, we will continue the recapitalization of debt and
funding of our capital development program that we began in 2003.
Following are the steps we are taking and plan to take to achieve that
purpose:
F-13
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 2. Operations and Management Plans - continued
(a) The first step is to close the refinancing of our largest debt of $27.8
million held by Concert Capital Resources LP ("CCR") and loaned to our
wholly-owned subsidiary, GulfWest Oil and Gas Company. We have entered into an
agreement with a new lending source that, subject to due diligence, will fund
approximately $14 million to purchase the $27.8 million note. The new debt
financing will also provide for the payment of closing costs. CCR has agreed to
sell the note to our new financier for a $14 million cash payment and a $4
million subordinated note from us.
(b) Secondly, we are continuing to work with our financial advisor to raise
an additional $4 to $5 million through the sale of our preferred stock. Proceeds
from this equity sale will be used for working capital and fund our new
development projects. The refinancing of the CCR debt and sale of new equity are
both currently scheduled to close in April, 2004.
(c) 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 provided payments in the
aggregate of $1,200,000 in advanced funds for our use in the acquisition of oil
and gas leases and other mineral and royalty interests, and production
activities, and was to recoup and recover those advanced funds.
In a subsequent event on March 5, 2004, we entered into an Option Agreement
for the Purchase of Oil and Gas Leases (the "Addison Agreement") with W. L.
Addison Investments L.L.C., a private company owned by Mr. J. Virgil Waggoner
and Mr. John E. Loehr, two of our directors, (`Addison"). Under the Addison
Agreement, Addison agreed to pay Summit, on our behalf, the non-recouped and
outstanding advanced funds amounting to $1,200,000, thereby retiring the Summit
Agreement. For consideration of such payment, Addison acquired certain oil and
gas leases and wellbores from Summit but agreed to grant us a 180-day redemption
option (which may be extended by mutual consent) to purchase the same for
$1,200,000, plus interest at the prime rate plus 2%. We tendered Addison a
promissory note in the amount of $600,000, with interest at the prime rate plus
2%, to substitute for an account payable to Summit, pursuant to the Summit
Agreement, in the same amount. The note will be considered paid in full if we
exercise the redemption option and pay the $1,200,000, plus interest. Summit
retained the right to participate up to a 25% working interest in the drilling
of any wells on the leases acquired by Addison. In the event we exercise the
redemption option, Addison may, at its sole option, retain up to a 25% working
interest in the leases.
(d) Finally, after completing the above, we will pursue the consolidation
of all of our debt, including other asset and bridge loans. Our goal is to
simplify our financial structure and provide adequate capitalization for the
development of our oil and gas assets.
F-14
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:
2003 2002
---------------- ----------------
Unproved oil and gas properties $ 261,650 $ 439,926
Proved oil and gas properties 54,669,482 52,847,625
Support equipment and facilities 3,541,754 3,498,492
---------------- ----------------
58,472,886 56,786,043
Less accumulated depreciation, depletion and
Amortization (8,749,601) (7,461,421)
---------------- ----------------
Net capitalized costs $ 49,723,285 $ 49,324,622
================ ================
Results of Operations for Oil and Gas Producing Activities:
2003 2002 2001
--------------- ---------------- ---------------
Oil and gas sales $ 10,844,466 $ 10,447,169 $ 12,426,103
Production costs (5,527,841) (5,430,205) (5,155,500)
Depreciation, depletion and amortization (1,527,727) (2,187,036) (2,018,890)
Accretion expense (76,823)
--------------- ---------------- ---------------
Income tax expense - - _
--------------- ---------------- ---------------
Results of operations for oil and gas
producing activities - income $ 3,712,075 $ 2,829,928 $ 5,251,713
=============== ================ ===============
Costs Incurred in Oil and Gas Producing Activities:
2003 2002 2001
--------------- ---------------- ---------------
Property Acquisitions
Proved $ - $ 562,760 $ 15,236,808
Unproved 110,119 14,401 154,076
Development Costs 2,024,663 5,141,075 6,317,527
--------------- ---------------- ---------------
$ 2,134,782 $ 5,718,236 $ 21,708,411
=============== ================ ===============
F-15
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 year
ended December 31, 2001, as if the Grand Goldking acquisition had occurred
as of January 1, 2001:
Year Ended
December 31,
2001
----------------
Operating revenues $ 15,649,329
Operating expenses 10,652,222
----------------
Income from operations 4,997,107
Other income and expense (3,325,166)
Income taxes -
----------------
Net income 1,671,941
Preferred dividends (112,500)
----------------
Net income to common shareholders $ 1,559,441
================
Earnings per share
Basic $ 0.08
================
Diluted $ 0.07
================
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,
2003 2002
---------------- -----------------
Payroll and payroll taxes $ 5,833 $ 1,863
Interest 395,735 414,724
Professional fees 42,000 42,000
---------------- -----------------
$ 443,568 $ 458,587
================ =================
f-16
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: 2003 2002
------------------ ------------------
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
Promissory note payable to a former director 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 45,000
Line of credit (up to $2,500,000) to a bank; due October, 2002; secured
by guaranty of a director; interest greater of prime rate less
.25% or 5.25%, (prime rate 4.0% at December 31, 2003). Line of
credit increased to $3,000,000 and due date extended to April, 2004. 2,995,488 2,995,488
Note payable to a bank; due March, 2003; interest at prime rate plus 1%
(prime rate 4.0% at December 31, 2003); secured by guaranty of
three of our directors; retired September 2003. 500,000
Promissory note payable to an unrelated party; payable on demand;
interest at 8%; interest increased to 12% on January 1, 2003;
secured by certain oil and gas properties. 300,000 300,000
Note payable to a bank; due July, 2004; secured by guaranty
of a director; interest at prime rate (prime rate 4.0% at December
31, 2003 with a floor of 4.75% and a ceiling of 8.0%. 948,400 1,000,000
Promissory note payable to unrelated party; interest at 6%; due June,
2003. 55,300 55,300
Promissory note payable to one of our directors; interest at 8%;
due on demand; unsecured. 50,000 50,000
Promissory note payable to one of our directors; interest at
prime rate (prime rate 4.0% at December 31, 2003); due May, 2003;
secured by common stock of DutchWest Oil Company, our wholly
owned subsidiary. 1,375,000 1,200,000
Promissory note payable to an unrelated party at 8%; due June 2003;
secured by 4% of the common stock of DutchWest Oil Company, our
wholly owned subsidiary 100,000
Promissory note payable to an unrelated party at 8%; due May 2003;
secured by 8% of the common stock of DutchWest Oil Company, our
wholly owned subsidiary 200,000
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 - continued:
2003 2002
-------------- -------------------
Line of credit (up to $3,500,000) to a bank; due June 2004; secured by
the guaranty of a director; interest at prime rate (prime rate
4.0% at December 31, 2003) with a floor of 4.75% and a ceiling of
8.0% 3,497,677
-------------- -------------------
$ 9,647,165 $ 6,226,088
============== ===================
The weighted average interest rate for notes payable at December
31, 2003 and 2002 was 5.0% and 4.7%, respectively.
Long-term debt is as follows:
2003 2002
-------------- ------------------
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
4.0% at December 31, 2003); replaced by a short-term line of
credit (up to $3,500,000) from the same bank. $ $ 2,999,515
Subordinated promissory notes to various individuals at 9.5% interest
per annum; amounts include $50,000 due to related parties; past
due. 150,000 150,000
Notes payable to finance vehicles, payable in aggregate monthly
installments of approximately $4,000, including interest of.9% to
13% per annum; secured by the related equipment; due various
dates through 2007. 69,500 116,721
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;
retired June, 2003. 48,850
Promissory note to a director; interest at 8.5%; due
December 31, 2003. 78,941 95,670
Note payable to a bank with monthly principal payments of $2,300;
interest at 9.5%; due May, 2003; secured by related equipment;
retired May, 2003. 11,630
Note payable to an energy lender; interest at prime plus 3.5% (prime
rate 4.0% at December 31, 2003) payable monthly out of 90%
net profits from certain oil and gas properties; final payment due
May, 2004; secured by related oil and gas properties. 27,574,769 27,907,509
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 - continued:
2003 2002
----------------- -----------------
Note payable to a bank with monthly principal payments of $36,000;
interest at prime plus 1% (prime rate 4.0% at December 31,
2003) with a minimum prime rate of 5.5%; final payment due
November, 2003; secured by related oil and gas properties;
extended to March, 2004. 1,564,000 1,996,000
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. 123,624 123,624
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;
retired June, 2003. 65,743
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. 1,211 7,960
----------------- -----------------
29,562,045 33,523,222
Less current portion (29,526,244) (33,385,414)
----------------- -----------------
Total long-term debt $ 35,801 137,808
================= =================
Estimated annual maturities for long-term debt are as follows:
2004 $ 29,526,244
2005 27,292
2006 7,150
2007 1,359
2008 -
------------------
$ 29,562,045
==================
F-19
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity
Common Stock
------------
2003 2002
----------------- --------------
Par value $.001; 40,000,000 shares authorized; 18,492,541
shares issued and outstanding as of December 31, 2003 and
2002, 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, 2003 and 2002. 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, 2003 and 2002. The
Series E preferred stock pays dividends, as declared, at a
rate
of 2.5% per annum, has a liquidation value of $500 per share,
may be redeemed at our option 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
Series F, par value $.01; 2,000 shares authorized; 2,000 shares
issued and outstanding at December 31, 2003. The Series F
preferred stock pays dividends, as declared, at a rate of
2.5% per
annum, has a liquidation value of $500 per share, may be
redeemed at our option and, if not redeemed after two years,
is convertible to common stock based upon a value of $500 per
Series E share divided by $1 per share of common stock. 20
----------------- --------------
$ 190 170
================= ==============
All classes of preferred shareholders have liquidation
preference over common shareholders of $500 per preferred share,
plus accrued dividends. Dividends in arrears at December 31, 2003
we $127,083 (Series E $112,500; Series F $14,583).
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.
F-20
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity - continued
2003 2002 2001
--------------------------- ----------------------------- ------------------------
Wtd Avg Wtd Avg Wtd Avg
Prices Number Prices Number Prices Number
-------- --------------- ---------- --------------- --------- -----------
Balance, January 1 $ .90 1,067,000 $ 1.03 1,097,000 $ .09 923,000
Options issued $ .75 35,000 $ .75 35,000 $ .83 184,000
Options expired $ - - $ 3.00 (65,000) $ 3.00 (10,000)
--------------- --------------- -----------
Balance, December 31 $ .90 1,102,000 $ .90 1,067,000 $ 1.03 1,097,000
=============== =============== ===========
All options were exercisable at December 31, 2003. Following
is a schedule by year and by exercise price of the expiration of
our stock options issued as of December 31, 2003:
2004 2005 2006 2007 Thereafter Total
---------- ----------- ---------- ---------- ------------ -----------
$ .75 432,000 35,000 185,000 652,000
$ .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 1,102,000
========== =========== ========== ========== ============ ===========
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:
2003 2002 2001
-------------------------- -------------------------- ---------------------------
Wtd Avg Wtd Avg Wtd Avg
Prices Number Prices Number Prices Number
--------- ------------- --------- ------------- --------- --------------
Balance, January 1 $ 1.24 2,181,754 $ 2.15 1,306,754 $ 2.31 1,392,254
Warrants issued $ .75 150,000 $ .75 1,145,000 $ .75 150,000
Warrants exercised
or expired $(3.61) (366,754) $ 3.57 (270,000) $ 2.22 (235,500)
------------- ------------- --------------
Balance, December 31 $ .76 1,965,000 $ 1.24 2,181,754 $ 2.15 1,306,754
============= ============= ==============
Included in the "warrants issued" and "warrants
exercised/expired" columns in 2002 were 270,000 warrants whose
price was reduced in 2002 to $.75.
F-21
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity - continued
Following is a schedule by year and by exercise price of the
expiration of our stock warrants issued as of December 31, 2003:
2004 2005 2006 2007 2008 Total
---- ---- ---- ---- ---- -----
$ .75 225,000 1,590,000 1,815,000
.875 150,000 150,000
---------- ---------- ------------- ------------ ----------- ------------
- 375,000 1,590,000 - - 1,965,000
========== ========== ============= ============ =========== ============
Warrants outstanding to our officers, directors and employees at
December 31, 2003 and 2002 were approximately 1,515,000 and 1,682,000,
respectively. The exercise prices on these warrants range from $.75 to
$.88 and expire various dates through 2006.
Note 7. Income (Loss) Per Common Share
The following is a reconciliation of the numerators and denominators
used in computing income (loss) per share:
2003 2002 2001
------------------ ----------------- ------------------
Net income (loss) $ (3,024,426) (4,502,313) $ 1,044,291
Preferred stock dividends (127,083) (112,500) (56,250)
------------------ ----------------- ------------------
Income (loss) available to common
shareholders (numerator) $ (3,151,509) $ (4,614,813) $ 988,041
================== ================= ==================
Weighted-average number of shares
of common stock - basic (denominator) 18,492,541 18,492,541 18,464,343
------------------ ----------------- ------------------
Income (loss) per share - basic $ (.17) $ (.25) $ .05
================== ================= ==================
Potential dilutive securities (stock options, stock warrants and
convertible preferred stock) in 2003 and 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 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,
F-22
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 8. Related Party Transactions - continued
$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.
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.
In a subsequent event on March 5, 2004, we entered into an Option
Agreement for the Purchase of Oil and Gas Leases (the "Addison
Agreement") with W. L. Addison Investments L.L.C., a private company
owned by Mr. J. Virgil Waggoner and Mr. John E. Loehr, two of our
directors, (`Addison"). Effective December 1, 200l and amended August
16, 2002, we had 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 provided payments in the aggregate of
$1,200,000 in advanced funds for our use in the acquisition of oil and
gas leases and other mineral and royalty interests, and production
activities, and was to recoup and recover those advanced funds. Under
the Addison Agreement, Addison agreed to pay Summit, on our behalf,
the non-recouped and outstanding advanced funds amounting to
$1,200,000, thereby retiring the Summit Agreement. For consideration
of such payment, Addison acquired certain oil and gas leases and
wellbores from Summit but agreed to grant us a 180-day redemption
option (which may be extended by mutual consent) to purchase the same
for $1,200,000, plus interest at the prime rate plus 2%. We tendered
Addison a promissory note in the amount of $600,000, with interest at
the prime rate plus 2%, to substitute for an account payable due to
Summit, pursuant to the Summit Agreement, in the same amount. The note
will be considered paid in full if we exercise the redemption option
and pay the $1,200,000, plus interest. Summit retained the right to
participate up to a 25% working interest in the drilling of any wells
on the leases acquired by Addison. In the event we exercise the
redemption option, Addison may, at its sole option, retain up to a 25%
working interest in the leases.
Interest expensed on related party notes totaled approximately
$76,000, $53,000 and $128,000 for the years ended December 31, 2003,
2002 and 2001 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::
F-23
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 9. Income Taxes - continued
December 31, December 31,
2003 2002
---- ----
Deferred tax assets
Net operating loss carryforwards $ 6,352,507 5,236,485
Oil and gas properties 610,381 542,131
Capital loss carryforwards - 93,211
Derivative instruments 201,099 383,858
Accretion 26,120
----------------- -------------------
Net deferred tax assets before
valuation allowance 7,190,107 6,255,685
Valuation allowance (7,190,107) (6,255,685)
----------------- -------------------
Net deferred tax assets (liabilities) $ - $ -
================= ===================
As of December 31, 2003 and 2002, 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.
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, 2003, 2002 and 2001.
2003 2002 2001
----------------- ----------------- ----------------
Tax (benefit) calculated at statutory rate $ (1,028,305) $ (1,530,786) $ 355,059
Increase (reductions) in taxes due to:
Effect on non-deductible expenses 362,910 65,174 18,157
Change in valuation allowance 934,422 1,586,988 (345,754)
Other (269,027) (121,376) (27,462)
----------------- ----------------- ----------------
Current federal income tax provision $ - $ - $ -
================= ================= ================
As of December 31, 2003 we had net operating loss carryforwards
of approximately $18,700,000, which are available to reduce future
taxable income and capital gains, respectively, and the related income
tax liability. The net operating loss carryforward expires at various
dates through 2023.
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, 2003 had declined to 6,400 barrels
of oil and 21,200 Mmbtu of gas. As a result of these agreements,
F-24
GULFWEST ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 10. Commitments and Contingencies - continued
we realized a reduction in revenues of $1,496,303, $368,776 and
$762,480 for the twelve-month periods ended December 31, 2003, 2002
and 2001, 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: 2004 -
$130,050, 2005 - $132,979, 2006 - $135,323 and 2007 - $33,977. Total
rent expense for the years ended December 31, 2003, 2002 and 2001 were
approximately $134,500, $91,000 and $60,000, 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 March 29, 2004, 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, 2003, 2002,
and 2001, together with the changes therein.
Crude Oil Natural Gas
(BBls) (Mcf)
---------------- ----------------
QUANTITIES OF PROVED RESERVES:
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
Revisions (262,608) (308,080)
Extensions, discoveries and additions - -
Purchase - -
Sales - -
Production (221,335) (1,190,624
---------------- ----------------
Balance December 31, 2003 5,037,963 32,660,119
================ ================
PROVED DEVELOPED RESERVES:
December 31, 2001 3,939,593 21,203,989
================ ================
December 31, 2002 4,025,552 25,374,113
================ ================
December 31, 2003 3,772,926 24,642,407
================ ================
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:
2003 2002 2001
------------------- ----------------- -----------------
Future cash inflows $ 336,795,385 $ 308,381,837 $ 199,162,921
Future production and development costs
Production 109,468,727 105,629,872 77,526,278
Development 21,460,459 23,350,811 23,610,596
------------------- ----------------- -----------------
Future cash flows before income taxes 205,866,199 179,401,154 98,026,047
Future income taxes (46,885,360) (38,611,577) (13,281,358)
------------------- ----------------- -----------------
Future net cash flows after income taxes 158,980,839 140,789,577 84,744,689
10% annual discount for estimated
timing of cash flows (70,653,419) (63,165,742) (35,895,306)
------------------- ----------------- -----------------
Standardized measure of discounted
future net cash flows $ 88,327,420 $ 77,623,835 $ 48,849,383
=================== ================= =================
The following reconciles the change in the standardized measure
of discounted future net cash flows:
Beginning of year $ 77,623,835 $ 48,849,383 $ 90,381,127
Changes from:
Purchases - 3,054,793 27,032,359
Sales - (953,159) (443,324)
Extensions, discoveries and improved
recovery, less related costs - 2,002,176 427,192
Sales of oil and gas produced net of
production costs (5,316,619) (5,016,964) (7,270,603)
Revision of quantity estimates (3,751,921) (9,974,557) (1,783,276)
Accretion of discount 9,889,881 5,649,945 12,414,073
Change in income taxes (4,793,281) (13,624,917) 26,109,535
Changes in estimated future
development costs 2,003,801 (5,254,561) (6,360,990)
Development costs incurred that
reduced future development costs 2,024,663 5,569,881 5,945,369
Change in sales and transfer prices,
net of production costs 16,470,113 46,903,282 (89,573,528)
Changes in production rates (timing)
and other (5,823,052) 418,533 (8,028,551)
------------------- ----------------- -----------------
End of year $ 88,327,420 $ 77,623,835 $ 48,849,383
=================== ================= =================
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, 2003 and 2002 follows:
Three Months Ended
----------------------------------------------------------------------------
March 31 June 30 September 30 December 31
---------------- ---------------- ---------------- ----------------
2003
Net sales $ 3,250,603 $ 2,790,124 $ 2,436,063 $ 2,533,933
Gross profit 862,683 406,576 81,573 (433,321)
Net income (loss) 120,659 (1,231,883) (399,457) (1,640,828)
Income (loss) per common
share - basic and diluted $ .01 $ (.07) $ (.02) $ (.09)
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)
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, 2003 and 2002 and for each of the three
years in the period ended December 31, 2003, 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, 2003, 2002 and 2001 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 19, 2004
F-30
GULFWEST ENERGY INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
BALANCE BALANCE
AT AT
BEGINNING PROVISIONS/ RECOVERIES/ END
DECRIPTION OF PERIOD ADDITIONS DEDUCTIONS OF PERIOD
- ------------------------------------- ---------------- ----------------- ----------------- --------------
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
================ ================= ================= ==============
For the year ended
December 31, 2003
Valuation allowance for
deferred tax assets $ 6,255,685 $ 934,422 $ $ 7,190,107
================ ================= ================= ==============
F-31