Back to GetFilings.com
As filed with the Securities and Exchange Commission on __________, 2005
Registration No. 333 _______
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------------
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2004
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 (I.R.S. Employer Identification No.)
Incorporation or Organization)
480 N. SAM HOUSTON PARKWAY EAST, SUITE 300
HOUSTON, TEXAS 77060
(Address of Principal Executive Offices) (Name, Address, Including Zip Code,
and Telephone Number, Including
Area Code, of Agent for Service)
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
March 29, 2005, was approximately $16,267,423. 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: 24,897,893 shares
on March 29, 2005.
DOCUMENTS INCORPORATED BY REFERENCE:
The registrant's definitive Proxy Statement pertaining to the 2005 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
This summary highlights selected information contained elsewhere in this
Annual Report. The following summary does not contain all of the information
that may be important. You should read the detailed information appearing
elsewhere in this Annual Report before making an investment decision. Certain
terms that we use in our industry are italicized and defined in the "Glossary of
Industry Terms and Abbreviations". Unless otherwise indicated, all references to
"GulfWest", the "Company", "we", "us" and "our" refer to GulfWest Energy Inc.
and our subsidiaries.
We make forward-looking statements throughout this Annual 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. We do not guarantee that
the transactions and events described in this Annual Report will happen as
described (or that they will happen at all). The forward-looking information
contained in this Annual Report is generally located in the material set forth
under the headings "Summary," "Risk Factors," "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and "Business" but
may be found in other locations as well. 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.
ITEM 1. Business.
Our Business.
We are primarily engaged in the acquisition, development, exploitation and
production of crude oil and natural gas, primarily in the onshore producing
regions of the United States. Our focus is on increasing production from our
existing properties through further exploitation, development and exploration,
and on acquiring additional interests in undeveloped and underdeveloped 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 our crude oil
and natural gas reserves through a combination of acquisitions and the further
exploitation and development of our properties. At December 31, 2004, our part
of the estimated proved reserves these properties contained was approximately
3.0 million barrels (MBbl) of oil and 29.1 billion cubic feet (Bcf) of natural
gas with an estimated Net Present Value discounted at 10% (PV-10) of $114.1
million. At present, all of our properties are located on land in Texas,
Colorado, Louisiana and Mississippi, except for the property in the shallow
inland boundaries of Grand Lake, Louisiana. In the future, we plan to expand by
acquiring additional properties in those areas, and in similar properties
located in other producing regions of the United States, including the shallow
waters of the Gulf of Mexico.
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 administrative
fees received for operating crude oil and natural gas properties for
other working interest owners, and for marketing and transporting
natural gas for those owners. 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 2004,
our well servicing equipment was used 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."
1
Our Common Stock, designated Class A Common Stock ("Common Stock") is
traded over-the-counter (OTC) under the symbol "GULF.OB".
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 in 1992. We became a Texas corporation by a merger effected
in July 1992, through 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.
GulfWest Energy Inc. has six active and three inactive, direct or indirect,
wholly owned subsidiaries. The active subsidiaries are:
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. It
has one wholly owned subsidiary, GulfWest Oil and Gas Company
(Louisiana) LLC.
2. 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.
3. 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 a majority working interest.
4. RigWest Well Service, Inc., a Texas corporation, was organized
September 5, 1996 and operates well servicing equipment for our own
account and for others when not being utilized for our own account..
5. 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.
6. 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 and Mississippi.
Balance. At December 31, 2004, our proved reserves were comprised of 38%
crude oil and 62% natural gas. We will continue to expand our role in the
domestic natural energy industry by (i) acquiring additional interests in crude
oil and natural gas properties, (ii) increasing the production and reserve base
of our existing producing properties, and (iii) acquiring ownership of more
natural gas gathering systems and pipelines. 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. 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.
Financial Recapitalization
On April 27, 2004, we completed an $18,000,000 financing package with new
energy lenders. We used $15,700,000 in net proceeds from the financing to retire
existing debt of $27,584,145, resulting in forgiveness of debt of $12,475,612,
the elimination of a hedging liability and the return to the Company of Series F
Preferred Stock, par value $.01 per share and liquidation value $500 per share
(the "Series F Preferred Stock"), with an aggregate liquidation preference of
$1,000,000 (this preferred stock, at our request was transferred by the previous
lender to a financial advisor of ours and to two companies affiliated with two
of our directors in satisfaction of our obligation to them. (See "Certain
Relationships and Related Transactions.") The taxable gain resulting from these
transactions will be completely offset by available net operating loss
carryforwards. The term of the note was eighteen months and it bore interest at
the prime rate plus 11%. This rate increased by .75% per month beginning in
month ten. We paid the new lenders $1,180,000 in cash fees and also issued them
warrants to purchase 2,035,621 shares of our Common Stock at an exercise price
of $.01 per share, expiring in five years. The warrants are subject to
anti-dilution provisions. In connection with the February 2005 transactions
described below, the anti-dilution provisions were amended such that additional
issuances of stock (other than issuances to all holders) would not trigger an
adjustment to the number of shares issuable upon exercise of the warrants.
2
Simultaneously, our wholly-owned subsidiary, GulfWest Oil & Gas Company
("GOGC"), completed the initial phase of a private offering of its Series A
Preferred Stock, par value $.01 and liquidation value $500 per share (the
"Series A Preferred Stock") for $4,000,000. The Series A Preferred Stock is
exchangeable into our Common Stock based on a liquidation value of $500 per
share of Series A Preferred Stock divided by $.35 per share of our Common Stock,
or 11,428,571 shares. As part of an advisory fee, we issued $500,000 of the
Series A Preferred Stock to a financial advisor. One of our directors acquired
$1,500,000 of the Series A Preferred Stock.
On January 7, 2005, we amended our April 2004 credit agreement to extend
the target date for repayment to February 28, 2005. We exercised this option on
January 26, 2005. We issued 29,100 shares of our common stock in connection with
this amendment.
In a subsequent event, on February 28, 2005, we sold in a private
placement, 81,000 shares of our Series G Preferred Stock, par value $0.01 per
share and liquidation value $500 per share, (the "Series G Preferred Stock") to
OCM GW Holdings, LLC ("OCMGW" or "Holdings"), an affiliate of Oaktree Capital
Management, LLC for an aggregate offering price of $40.5 million. In addition,
GOGC issued, in a private placement, 2,000 shares of its Series A Preferred
Stock, having an aggregate liquidation preference of $1.0 million, to OCMGW for
$1.5 million. Net proceeds of the offerings of approximately $38 million after
expenses are being used for the repayment of substantially all of our debt,
other past due liabilities and for general corporate purposes.
The Series G Preferred Stock bears a coupon of 8% per year, has an
aggregate liquidation preference of $40.5 million, is convertible to the Common
Stock at $0.90 per share of Common Stock and is senior to all of our outstanding
capital stock. For the first four years after issuance, we may defer the payment
of dividends on the Series G Preferred Stock and these deferred dividends will
also be convertible into our Common Stock at $0.90 per share. In addition, the
Series G Preferred Stock is entitled to nominate and elect a majority of the
members of our Board of Directors.
In connection with these transactions, the terms of the Series A Preferred
Stock have been amended such that by March 15, 2005, all such stock would either
convert into a newly created Series H Preferred Stock, par value $.01 and
liquidation value $500 per share (the "Series H Preferred Stock") on a one for
one basis or into Common Stock at a conversion price of $0.35 per share of
Common Stock. The Series H Preferred Stock is required to be paid a dividend of
40 shares of Common Stock per share of Series H Preferred Stock per year. In
addition, the Series H Preferred Stock is convertible into Common Stock at a
conversion price of $0.35 per share. At March 15, 2005, holders of 6,700 shares
of Series A Preferred Stock converted to Series H Preferred Stock and holders of
3,250 shares of Series A Preferred Stock converted to an aggregate 4,642,859
shares of Common Stock. One holder of the Series H Preferred Stock also
converted its shares to 285,715 shares of Common Stock. The outstanding Series H
Preferred Stock has an aggregate liquidation preference of $3.25 million. The
Series H Preferred Stock is senior to all of our outstanding capital stock
except Series G Preferred Stock.
In addition, we amended the terms of our 9,000 shares of Series E Preferred
Stock, par value $.01 and liquidation value $500 per share (the "Series E
Preferred Stock"), such that the coupon of 6% per year they bear may be deferred
for the next four years and these deferred dividends will be convertible into
Common Stock at conversion price of $0.90 per share. The initial liquidation
preference of the Series E Preferred Stock of $500 per share remains convertible
into Common Stock at $2.00 per share. The Series E Preferred Stock has an
aggregate liquidation preference of $4.5 million, is senior to our Common Stock,
of equal preference with respect to liquidation with our Series D Preferred
Stock, par value $.01 and liquidation value $500 per share (the "Series D
Preferred Stock") and junior to our Series G Preferred Stock and Series H
Preferred Stock.
3
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 exploitation activities. Such activities include workovers, development
drilling, recompletions, replacement or addition of equipment and waterflood or
other secondary recovery techniques. Key elements of our business strategy
include:
Development and Exploitation of Existing Properties. Our strategy is to
increase crude oil and natural gas production and reserves of our existing
assets through relatively low-risk development activities, such as performing
workovers, recompletions and horizontal drilling from existing wellbores,
infield drilling and more efficiently using production facilities.
Continued Acquisition Program. We acquired properties in four crude oil and
natural gas fields in Texas and Louisiana in the year 2001. Though capital
constrained since 2001, to the extent financial resources are available, we
intend to continue to pursue the acquisition of 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.
Significant Operating Control. Currently, we are the operator of all but
two of the wells in which we own working interests. This operating control
enables us to better manage the nature, timing and costs of developing and
servicing such wells, and the timing and marketing of the resulting production.
Ownership of Workover Rigs. We currently own two 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.
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 Grimes,
Hardin, Jim Wells, Madison, Palo Pinto, Refugio, Wharton and Zavala, Counties,
Texas; Adams, Arapaho, Elbert and Weld Counties, Colorado; Cameron Parish,
Louisiana; and Jones County, Mississippi. 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 development drilling
opportunities as well as the potential for generating exploratory opportunities
on the acquired acreage. We have expanded our evaluation efforts in these fields
and intend to increase our development of reserves through workovers of existing
wells and by drilling additional wells. As we develop exploration opportunities
on these properties or see high-quality prospects generated by others, as
capital resources are available, we will complement our development activities
with capital for exploratory or exploitation projects.
Our Employees.
At December 31, 2004, we had 26 full time employees, of whom 13 were field
personnel. None of our employees are covered by collective bargaining
agreements.
Our Executive Officers.
See Item 10 of this report, which information is incorporated herein by
reference.
ITEM 2. Our Properties.
At December 31, 2004, we owned a total of 250 gross wells, of which 137
were producing, 95 were shut-in or temporarily abandoned and 18 were injection
or saltwater wells. We owned an average 89% working interest in the 137 gross
(120 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 3 million barrels (MMBL) of oil and 29.1 billion cubic
feet (Bcf) of natural gas at December 31, 2004. Substantially all of our
properties are located onshore or shallow inland waters in Texas, Colorado and
Louisiana.
4
Proved Reserves.
The following table reflects our estimated proved reserves at December 31
for each of the preceding three years.
2004 2003 2002
-------- -------- --------
Crude Oil (MBBL)
Developed 2,575 3,773 4,026
Undeveloped 388 1,265 1,496
-------- -------- --------
Total 2,963 5,038 5,552
======== ======== ========
Natural Gas (MMCF)
Developed 20,966 24,642 25,374
Undeveloped 8,125 8,018 8,785
-------- -------- --------
Total 29,091 32,660 34,159
======== ======== ========
Total (MBOE) 7,812 10,481 11,215
======== ======== ========
(a) Approximately 78% of our total PROVED RESERVES were classified as
proved developed at December 31, 2004.
(b) Barrel of Oil Equivalent (BOE) is based on a ratio of 6,000 cubic feet
of natural gas for each barrel of oil.
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 and the Financial
Accounting Standard Board. 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.
2004 2003 2002
-------------- -------------- --------------
Future cash inflows $ 290,998,312 $ 336,795,385 $ 308,381,837
Future production and development costs-
Production 80,880,330 109,468,727 105,629,872
Development 24,141,982 21,460,459 23,350,811
-------------- -------------- --------------
Future net cash flows before income taxes 185,976,000 205,866,199 179,401,154
Future income taxes (49,871,272) (46,885,360) (38,611,577)
-------------- -------------- --------------
Future net cash flows after income taxes 136,104,728 158,980,839 140,789,577
10% annual discount for estimated timing
of cash flows (52,602,351) (70,653,419) (63,165,742)
-------------- -------------- --------------
Standardized measure of discounted
future net cash flows(1) $ 83,502,377 $ 88,327,420 $ 77,623,835
============== ============== ==============
- ------------------
(1) The average sales prices utilized in the estimation of our proved reserves
were $40.41 per Bbl and $5.89 per MCF, $29.51 per Bbl and $5.82 per MCF,
and $28.72 per Bbl and $4.43 per MCF at December 31, 2004, 2003 and 2002,
respectively.
5
Significant Properties.
Summary information on our properties with proved reserves is set forth
below as of December 31, 2004.
Present
Productive Wells Proved Reserves Value(1)
------------------------- ---------------------------- ----------
Gross Net
Productive Productive Crude Natural
Wells Wells Oil Gas Total Amount
------------ ---------- ------- -------- ------- ----------
(MBbl) (MMcf) (MBOE) ($M)
Texas 80 75.91 1,295 15,663 3,906 $ 57,706
Colorado 37 24.81 278 5,550 1,203 13,676
Louisiana 19 18.88 1,383 7,878 2,696 42,549
Mississippi 1 0.37 7 - 7 126
------------ ---------- ------- ---- ---------- ----------
Total 137 119.97 2,963 29,091 7,812 $ 114,057
============ ========== ======= ==== ========== ==========
- ------------------
(1) The average sales prices used in the estimation of our proved reserves were
$40.41 per Bbl and $5.89 per Mcf at December 31, 2004.
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.
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, 2004, 2003
and 2002.
6
2004 2003 2002
------------- ------------- -------------
Production
Oil (Bbl) 173,865 221,433 278,374
Natural gas (Mcf) 1,033,433 1,191,350 1,487,048
------------- ------------- -------------
Total (BOE) 346,104 419,991 526,215
Revenue
Oil production $5,498,598 $ 5,362,657 $ 5,859,568
Natural gas production 5,602,516 5,481,803 4,587,601
------------- ------------- -------------
Total $ 11,101,114 $ 10,844,460 $ 10,447,169
Operating Expenses $ 4,879,754 $ 5,527,841 $ 5,430,205
Production Data
Average sales price (1)
Per barrel of oil $ 31.63 $ 24.22 $ 21.05
Per Mcf of natural gas $ 5.42 $ 4.60 3.09
Per BOE $ 32.07 $ 25.82 19.85
Average expenses per BOE
Lease operating $ 14.10 $ 13.16 $ 10.32
Depreciation, depletion and
Amortization $ 6.31 $ 5.30 $ 5.13
General and administrative $ 5.83 $ 5.39 $ 3.28
- -------------------------
(1) Average sales prices are shown net of the settled amounts of our oil and
gas hedge contracts. Average sales prices per BOE, before adjustments for
the hedge contracts, were $37.39, $29.38 and $20.55 in 2004, 2003 and 2002,
respectively.
Productive Wells at December 31, 2004:
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 31 29.99 49 45.92
Colorado 21 13.45 16 11.36
Louisiana 14 13.88 5 5.00
Mississippi 1 0.37 - -
--------- --------- --------- ---------
Total 67 57.69 70 62.28
========= ========= ========= =========
Developed Acreage at December 31, 2004.
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 9,055 8,439
Colorado 6,000 4,020
Louisiana 1,320 1,315
------------- -----------
Total 16,375 13,774
============= ===========
7
Undeveloped Acreage at December 31, 2004.
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 form the basis to determine whether the property is
capable of production of commercial quantities of crude oil and natural gas.
Gross Acres Net Acres
------------- -----------
Texas 20,420 17,920
Colorado 11,000 8,250
Louisiana 375 375
------------- -----------
Total 31,795 26,545
============= ===========
Drilling Results.
In 2004, we drilled one well that was completed as a successful gas well.
The well was located in Grimes County, Texas and was drilled during the fourth
quarter of 2004. The well was completed, brought on-line in mid-January 2005 and
has produced at any average rate of 600 Mcf per day (net to our interest) for
the first 60 days. We did not drill any wells in 2003. In 2002, we drilled one
exploratory well, in which we own an 18% working interest, that resulted in a
dry hole and one development well, in which we own 100% working interest, that
is currently productive.
Costs Incurred
The following table shows the costs incurred in our oil and gas producing
activities for the past three years:
2004 2003 2002
------------ ------------ ------------
Property Acquisitions
Proved $ 6,742 - $ 562,760
Unproved 17,347 110,119 14,401
Development Costs 6,117,899 2,024,663 5,141,075
------------ ------------ ------------
$ 6,141,988 $ 2,134,782 $ 5,718,236
============ ============ ============
Property Dispositions
The following table shows oil and gas property dispositions:
2004 2003 2002
------------ ------------ ------------
Oil and gas properties $ 5,425,040 $ 31,979 $ 464,806
Accumulated DD&A (1,659,001) (11,569) (21,375)
------------ ------------ ------------
Net oil and gas properties $ 3,766,039 20,410 $ 443,431
============ ============ ============
As a result of these sales we recorded a loss of $2,029,932 in 2004 and
$20,409 in 2003 and a gain of $21,569 in 2002.
Marketing
We sell substantially all of our crude oil and natural gas production to
purchasers pursuant to sales contracts that typically have a thirty-day primary
term, although occasionally we enter into longer term contracts when it is
advantageous to do so. The sales prices for crude oil and condensate are tied to
industry standard posted prices plus negotiated premiums. The sales prices for
natural gas are based upon published index prices, subject to negotiated price
deductions.
8
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.
We may borrow funds to finance capital expenditures and for other purposes
which 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 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 could have
floating rates of interest, which would cause us to be vulnerable to
increases in interest rates; and
(vii) Our degree of leverage could make us more vulnerable to a downturn in
general economic conditions.
We have incurred net losses in the past and there can be no assurance that
we will be profitable in the future.
We have incurred net losses in three of the last five fiscal years. We
cannot assure you that our current level of operating results will continue or
improve. Our activities could require additional debt or equity financing on our
part. Since the terms and availability of this financing depend to a large
degree upon general economic conditions and third parties over which we have no
control, we can give no assurance that we will obtain the needed financing or
that we will obtain such financing on attractive terms. In addition, our ability
to obtain financing depends on a number of other factors, many of which are also
beyond our control, such as interest rates and national and local business
conditions. If the cost of obtaining needed financing is too high or the terms
of such financing are otherwise unacceptable in relation to the opportunity we
are presented with, we may decide to forego that opportunity. Additional
indebtedness could increase our leverage and make us more vulnerable to economic
downturns and may limit our ability to withstand competitive pressures.
Additional equity financing could result in dilution to our shareholders. 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 out to be inaccurate.
9
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 22% of our total estimated proved reserves at December 31,
2004 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 annual
report as the current market value of our estimated crude oil and natural gas
reserves.
In accordance with Securities and Exchange Commission 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, 2004. The average sales prices of all properties were $40.41 per
barrel of oil and $5.89 per thousand cubic feet (Mcf) of natural gas at that
date.
Actual future net cash flows will also be affected by increases or
decreases in consumption by crude oil and natural gas purchasers and changes in
governmental regulations or taxation. The timing of both the production and the
incurring of expenses in connection with the development and production of crude
oil and natural gas properties affect the timing of actual future net cash flows
from proved reserves. In addition, the 10% discount factor, which is required by
the Securities and Exchange Commission 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.
10
Drilling for crude oil and natural gas may not be profitable.
Any wells that we drill may be dry wells or wells that are not sufficiently
productive to be profitable after drilling. Such wells will have a negative
impact on our profitability. In addition, our properties may be susceptible to
drainage from production by other operators on adjacent properties.
Our industry experiences numerous operating risks that could cause us to
suffer substantial losses.
Such risks include fire, explosions, blowouts, pipe failure and
environmental hazards, such as oil spills, natural gas leaks, ruptures or
discharges of toxic gases. We could also suffer losses due to personnel injury
or loss of life; severe damage to or destruction of property; or environmental
damage that could result in clean-up responsibilities, regulatory investigation,
penalties or suspension of our operations. In accordance with customary industry
practice, we maintain insurance policies against some, but not all, of the risks
described above. Our insurance policies may not adequately protect us against
loss or liability. There is no guarantee that insurance policies that protect us
against the many risks we face will continue to be available at justifiable
premium levels.
As owners and operators of crude oil and natural gas properties, we may be
liable under federal, state and local environmental regulations for activities
involving water pollution, hazardous waste transport, storage, disposal or other
activities.
Our past growth has been attributable to acquisitions of producing crude
oil and natural gas properties with proved reserves. There are risks involved
with such acquisitions.
The successful acquisition of properties requires an assessment of
recoverable reserves, future crude oil and natural gas prices, operating costs,
potential environmental and other liabilities, and other factors beyond our
control. Such assessments are necessarily inexact and their accuracy uncertain.
In connection with such an assessment, we perform a review of the subject
properties that we believe to be generally consistent with industry practices.
Such a review, however, will not reveal all existing or potential problems, nor
will it permit us, as the buyer, to become sufficiently familiar with the
properties to fully assess their capabilities or deficiencies. We may not
inspect every well and, even when an inspection is undertaken, structural and
environmental problems may not necessarily be observable.
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, and in these
situations we cannot assure you that we will identify all areas of existing or
potential exposure. 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.
11
We will need additional financing in the future to continue to fund our
development 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 2004 and 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.
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, the obtaining of goods and
services from industry providers, 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.
We have "blank check" preferred stock.
Our Articles of Incorporation authorize the Board of Directors to issue
preferred stock without further shareholder action in one or more series and to
designate the dividend rate, voting rights and other rights preferences and
restrictions. The issuance of preferred stock could have an adverse impact on
holders of Common Stock. Preferred stock is senior to Common Stock.
Additionally, preferred stock could be issued with dividend rights senior to the
rights of holders of Common Stock. Finally, preferred stock could be issued as
part of a "poison pill", which could have the effect of deterring offers to
acquire the Company. See "Description of Securities"
12
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.
One investor controls us.
As a result of the February 2005 preferred stock offerings, OCMGW Holdings
("OCMGW") acquired a controlling interest in us. OCMGW has the right to acquire
45,468,253 shares of our Common Stock pursuant to conversion of Series G
Preferred Stock and Series H Preferred Stock owned by it which represents
approximately 65% of the currently outstanding Common Stock, assuming the
conversion of preferred stock held by it. Pursuant to the terms of Series G
Preferred Stock, the holders of the Series G Preferred Stock, voting as a class,
have the right to elect a majority of our board of directors. OCMGW currently
owns approximately 95% of the Series G Preferred Stock.
Mr. J. Virgil Waggoner, Chairman of the Board, owns 9,545,229 shares of our
Common Stock, which represents approximately 38% of the currently outstanding
Common Stock. Additionally, Mr. Waggoner has the right to acquire an additional
7,180,715 shares pursuant to conversion of preferred stock and exercise of
currently exercisable warrants and options. Mr. Waggoner has entered into a
Share Transfer Restriction Agreement, dated February 28, 2005, with OCMGW,
restricting his transfer of shares of capital stock, and an Irrevocable Proxy
with respect to his stock thereby allowing OCMGW to vote such shares at any time
in favor of our Delaware reincorporation or, if the reincorporation is not
consummated by December 31, 2005, in favor of the conversion of certain of the
Series G into new preferred stock. The Irrevocable Proxy also grants OCM GW
Holdings a proxy with additional rights with respect to his Series H until such
time as all the Series H has converted into Common Stock.
Additionally, OCMGW and all current directors and officers as a group
represent approximately 67% of the outstanding voting power (assuming they
convert all preferred stock other than the Series G Preferred Stock and Series H
Preferred Stock, which vote on an as converted basis, and exercise all currently
exercisable warrants and options held by them). For as long as OCMGW, Mr.
Waggoner and the other directors and officers continue to own over a majority of
the outstanding voting power, they will be able to control elections to the
board of directors that common shareholders are entitled to vote on and other
matters submitted to shareholders. The percentage ownership of OCMGW, directors
and officers could be reduced by the issuance of Common Stock on conversion of
preferred stock and the exercise of warrants, although it is impossible to say
how many shares will be actually issued.
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 80,000,000 shares of Common Stock, $.001 par
value per share. As of March 29, 2005 there were 24,897,893 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, and Series G Preferred Stock and Series H Preferred Stock (on an as
converted basis) present, in person or by proxy, will be able to elect all of
the remaining members of our board of directors that the holders of the Series G
Preferred Stock are not entitled to elect as a class. The holders of shares of
our Common Stock do not have preemptive rights or rights to convert their Common
Stock into other securities.
The number of shares of outstanding Common Stock could increase
significantly as a result of the recent sale of Series G Preferred Stock sold to
OCMGW and Affiliates.
If all of the Common Stock underlying our various convertible and
derivative securities, including warrants and granted employee stock options, is
issued by us, the number of our outstanding shares of Common Stock would
increase to approximately 103.8 million shares. Currently, we are only
authorized to issue 80,000,000 shares of our Common Stock, 24,897,893 shares of
which are outstanding as of March 29, 2005. It is impossible to say how many
shares, if any, we will issue and how many shares, in turn, will be resold.
However, it is possible that our stock price could decline significantly as a
result of an increased number of shares being offered into the market.
13
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, 2005, we were not engaged in any legal proceedings
that are expected, individually or in the aggregate, to have a material adverse
effect on the Company.
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, 2004.
PART II
ITEM 5. Market for Our Common Stock and Related Stockholder Matters.
The high and low trading prices for the Common Stock for each quarter in
2004, 2003 and 2002 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
------ ------
2004
----
First Quarter $ .45 $ .32
Second Quarter .56 .33
Third Quarter .85 .45
Fourth Quarter .94 .66
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
Common Stock.
We are authorized to issue up to 80,000,000 shares of Common Stock, par
value $.001 per share. As of March 29, 2005, there were 24,897,893 shares of
Common Stock issued and outstanding and held by approximately 620 beneficial
owners. Our Common Stock is traded over-the-counter (OTC) under the symbol
"GULF.OB". 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. The holders of a majority of the outstanding shares of the Common Stock
and Series G and H (on an as converted basis) have the ability to elect all of
the directors that the Series G does not elect. As of February 28, 2005, the
holders of the Series G Preferred Stock were granted the right to elect a
majority of our Board of Directors.
14
Holders of Common Stock have no preemptive or other rights to subscribe for
shares. Holders of Common Stock are entitled to such dividends as may be
declared by the Board out of funds legally available therefore. We have never
paid cash dividends on the Common Stock and do not anticipate paying any cash
dividends in the foreseeable future.
Preferred Stock.
Our board of directors is authorized, without further shareholder action,
to issue preferred stock in one or more series and to designate the dividend
rate, voting rights and other rights, preferences and restrictions of each such
series. Our preferred stock is senior to our Common Stock regarding liquidation.
The holders of the preferred stock do not have voting rights (except for the
Series G and Series H Preferred Stock holders as discussed below) or preemptive
rights, nor are they subject to the benefits of any retirement or sinking fund.
As of December 31, 2004, there was a total of 25,290 shares of preferred
stock issued and outstanding in four series: Series A, D, E and F Preferred
Stock.
In a subsequent event, the holders of 340 shares our Series F Preferred
Stock converted to an aggregate 170,000 shares of Common Stock.
The Series D Preferred Stock is not entitled to dividends, nor is it
redeemable, however it is convertible to Common Stock at anytime based on $8.00
per share of Common Stock. The 8,000 outstanding shares of Series D Preferred
Stock are held by a former director and none 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 6% per share per annum, which may be deferred for the next four years and
those deferred dividends will be convertible into Common Stock at the conversion
price of $.90 per share of Common Stock. The conversion price for the Series E
Preferred Stock is based on $2.00 per share of Common Stock. The Series E
Preferred Stock is held by a director and none of the 9,000 outstanding shares
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 E Preferred Stock has an aggregate liquidation preference of $4.5
million, and is senior to all of our Common Stock and of equal preference with
our Series D Preferred Stock and junior to our Series G Preferred Stock and
Series H Preferred Stock.
In a subsequent event, on February 28, 2005, we sold 81,000 shares of our
Series G Preferred Stock to OCMGW for an aggregate offering price of $40.5
million in a private placement. In addition, our subsidiary, GOGC sold 2,000
shares of its Series A Preferred Stock, having a liquidation preference of $1.0
million, to OCMGW for $1.5 million in a private placement.
The Series G Preferred Stock bears a coupon of 8% per year and has an
aggregate liquidation preference of $40.5 million. For the first four years
after issuance, we may defer the payment of dividends on the Series G Preferred
Stock and these deferred dividends will also be convertible into our Common
Stock at $0.90 per share. In addition, the Series G Preferred Stock is entitled
to vote on an as-converted basis with the holders of our Common Stock and, as a
class, is entitled to nominate and elect a majority of the members of the Board
of Directors of GulfWest. The Series G Preferred Stock is senior to all of
GulfWest's outstanding capital stock in liquidation preference.
In connection with the above transactions, the terms of our Series A
Preferred Stock have been amended such that by March 15, 2005, all such stock
would either convert into a newly created Series H Preferred Stock on a one for
one basis or into Common Stock at a conversion price of $0.35 per share. The
Series H Preferred Stock is required to be paid a dividend of 40 shares of
Common Stock per Series H Preferred Stock share per year. In addition, the
Series H Preferred Stock is convertible into Common Stock at a conversion price
of $0.35 per share. At March 15, 2005, holders of 6,700 shares of Series A
Preferred Stock converted to Series H Preferred Stock, one of which subsequently
converted his 200 shares to 285,715 shares of Common Stock, and holders of 3,250
shares of Series A Preferred Stock converted to an aggregate 4,642,859 shares of
Common Stock. The Series H Preferred Stock has an aggregate liquidation value of
$3.35 million and is senior to all of GulfWest's outstanding capital stock in
liquidation preference other than its Series G Preferred Stock. (See discussion
in Note 2 "Operations and Management Plans" on page F-16 of the Financial
Statements).
15
Outstanding Options and Warrants.
At December 31, 2004, we had outstanding employee stock options, fully
vested under our 1994 and 2004 Stock Option and Compensation Plans, to purchase
1,949,000 shares of Common Stock at prices ranging from $.45 to $1.81 per share
and warrants to purchase 4,000,621 shares of Common Stock at prices ranging from
$.01 to $.75 per share. In conjunction with the subsequent financing event on
February 28, 2005, we established our 2005 Stock Incentive Plan and authorized
the issuance of 27 million shares of Common Stock pursuant to awards under the
plan, 16,200,000 shares of which were granted on that date.
Recent Sales of Unregistered Securities.
As shown in the table that follows, during 2004 and to March 29, 2005, we
sold preferred stock convertible to Common Stock not registered under the
Securities Act of 1933, as amended, and exempt under Section 4(2) of the Act. No
underwriters were used, and no underwriting discounts or commissions were paid
in connection with the sales.
Exercise/
---------
Underlying Conversion
---------- ----------
Date Derivative Holder(s) Shares Price Consideration
- -------- ---------- ---------- ------ ----- -------------
04/27/04 Preferred Accredited
Stock Investors 11,428,571 $ .35 $ 4,000,000
1/10/05 Warrants Accredited
Investors 50,000 $ .01 $ 200,000 Loan
1/21/05 Common Accredited
Stock Investors 29,100 N/A Loan Extension
02/28/05 Preferred Accredited
Stock Investors 47,857,143 $ .90 $ 42,000,000
Please see item 1. Business- Financial Recapitalization for additional
information.
16
ITEM 6. Selected Financial Data.
The following table sets forth selected historical financial data of our
company as of December 31, 2004, 2003, 2002, 2001 and 2000, 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, 2004, 2003 and 2002 and the
balance sheet data at December 31, 2004 and 2003 are derived from our audited
financial statements contained elsewhere herein. The income statement data for
the years ended December 31, 2001 and 2000 and the balance sheet data at
December 31, 2002, 2001 and 2000 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,
2004 2003 2002 2001 2000
------------- ------------- ------------- ------------- ------------
Income Statement Data
- ---------------------
Operating Revenues $ 11,207,673 $ 11,010,723 $ 10,839,797 $ 12,990,581 $ 8,984,175
Net income (loss) from
operations 1,557,815 558,774 310,290 3,451,875 2,464,017
Net income (loss) 8,072,221 (3,024,426) (4,502,313) 1,044,291 352,774
Dividends on preferred stock (455,612) (127,083) (112,500) (56,250) -
Net income (loss) available to
common shareholders 7,761,863 (3,151,509) (4,614,813) 988,401 352,774
Net income (loss), per share
of Common Stock $ .41 $ (.17) $ (.25) $ .05 $ .02
Weighted average number
of shares of common
stock outstanding 18,535,022 18,492,541 18,492,541 18,464,343 17,293,848
Balance Sheet Data
- ------------------
Current assets $ 2,214,542 $ 1,742,689 $ 2,353,046 $ 2,205,862 $ 2,934,804
Total assets 57,700,891 52,428,774 53,088,941 51,379,209 32,374,128
Current liabilities 35,568,417 44,619,652 43,998,566 12,492,365 7,594,986
Long-term obligations 1,950,300 1,393,607 137,808 26,541,957 18,077,371
Other liabilities 1,505,527 591,467 1,128,993 - -
Stockholders' Equity $ 18,676,643 $ 5,824,648 $ 7,823,574 $ 12,344,887 $ 6,701,771
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
Overview.
We are primarily engaged in the acquisition, development, exploitation and
production of crude oil and natural gas, primarily in the onshore producing
regions of the United States. Our focus is on increasing production from our
existing properties through further exploitation, development and exploration,
and on acquiring additional interests in undeveloped 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 administrative
fees received for operating crude oil and natural gas properties for
other working interest owners, and for marketing and transporting
natural gas for those owners. This also includes earnings from other
miscellaneous activities.
17
3. Well servicing revenues that are earnings from the operation of well
servicing equipment under contract to other operators. During 2004,
our well servicing equipment was used only for our own account.
The following is a discussion of our consolidated 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.
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 acquiring or finding new reserves, and the acquisition,
finding and development costs incurred in adding these reserves, 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 total recoverable 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 (engineering standards reference), 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 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.
Comparative results of operations for the periods indicated are discussed
below.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Revenues
Oil and Gas Sales. Our operating revenues from the sale of crude oil and
natural gas increased by 2% from $10,844,000 in 2003 to $11,101,000 in 2004.
Revenue increases due to higher oil and natural gas sales prices were
substantially offset by a 17% decrease in sales volumes, 12% of which was due to
normal oil and gas production declines and 5% due to property sales.
Operating Overhead and Other Income. Revenues from these activities
decreased 36% from $166,000 in 2003 to $107,000 in 2004, primarily due to (1) a
one time $58,000 contract settlement received in 2003, and (2) lower pipeline
volumes resulting in less transportation revenue.
Costs and Expenses
Lease Operating Expenses. Lease operating expenses decreased 12% from
$5,528,000 in 2003 to $4,880,000 in 2004, 5% was due to lower variable costs on
lower production volumes and 7% due to property sales. On a per BOE basis, costs
increased from $13.16 in 2003 to $14.10 per BOE in 2004 because of lower volume
and higher vendor prices.
Depreciation, Depletion and Amortization (DD & A). DD & A decreased 2% from
$2,226,000 in 2003 to $2,185,000 in 2004, due to lower production volumes. On a
per BOE basis, the DD & A rate increased from $5.30 in 2003 to $6.31 per BOE in
2004 due to higher than anticipated development costs.
18
The cost of Dry Holes, Abandoned Property and Impaired Assets expense in
2004 was $453,000 (abandoned- $391,000; impaired- $62,000), compared to $359,000
(dry holes- $70,000; abandoned $289,000) in 2003. The abandoned property was due
to a lack of capital to complete projects resulting in the loss of leases.
General and Administrative (G & A) Expenses. G & A expenses decreased 11%
from $2,262,000 in 2003 to $2,019,000 in 2004 due to expenses incurred in 2003
associated with financing efforts that were not culminated.
Interest Income and Expense. Interest expense increased 24% from $3,363,000
in 2003 to $4,154,000 in 2004. In April 2004 we retired debt of approximately
$27.6 million carrying an interest rate of prime plus 3.5% and replaced it with
debt of approximately $18.0 million that carries an interest rate of prime plus
11.0%. Also, included in 2004 is non cash interest expense of approximately $.4
million resulting from the discounting on a note payable issued in 2004.
Other Financing Costs. Other financing costs increased 47% from $1,000,000
in 2003 to $1,472,000 in 2004. In 2003, we recorded an expense of $1,000,000 to
account for the issuance of 2,000 shares of our preferred stock in conjunction
with the financial agreement on the retired debt referred to above. The expense
in 2004 represents the amortized portion of loan fees associated with the
refinancing of debt referred to above.
Unrealized Gain (Loss) on Derivative Instruments. The estimated future fair
value of derivative instruments at December 31, 2004 resulted in an estimated
unrealized loss of $1,506,000 in 2004 compared to an unrealized gain of $537,000
in 2003. Estimated unrealized gain/ loss on oil and gas price hedges in place on
a particular balance sheet date is based on a "mark to market" calculation based
on a market price forecast on the balance sheet date compared to the prices
provided for in the derivative instruments.
Loss on Sale of Property and Equipment. We recorded a loss on sale of
property and equipment of $2,034,000 in 2004 as compared to $20,000 in 2003. See
Note 3 to the Financial Statements.
Accretion Expense. Accretion expense decreased 6% from $77,000 in 2003 to
$72,000 in 2004 due to sales of oil and gas properties.
Forgiveness of Debt. In 2004 we had $12,476,000 in debt forgiven as the
result of debt refinancing in April, 2004.
Dividends on Preferred Stock. In 2004, a dividend on preferred stock due
was $456,000. In 2003 dividends on preferred stock due was $127,000. The board
of directors did not declare any dividends be paid.
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, offset by normal oil and gas
production declines and resulting in 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.
19
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 & A). DD & A decreased 17%
from $2,698,000 in 2002 to $2,226,000 in 2003, due to lower production volumes.
We also recorded in other income $262,000 related to the cumulative effect of
adopting SFAS 143 "Asset Retirement Obligations".
Dry Holes, Abandoned Property and Impaired Assets. The cost of abandoned
property in 2003 was $359,000 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.
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 failed 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.
Loss on Sale of Property and Equipment. We recorded a loss on sale of
property and equipment of $20,000 in 2003 as compared to $57,000 in 2002. See
Note 3 to the Financial Statements.
Accretion Expense. We recorded accretion expenses of $77,000 as a result of
adapting SPAS 143 "Asset Retirement Obligations", effective January 1, 2003.
Dividends on Preferred Stock. In 2003, dividends due on preferred stock due
was $127,000, however the board of directors did not declare any dividends to 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.
20
Depreciation, Depletion and Amortization (DD & A). DD & 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.
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.
General and Administrative (G & A) Expenses. G & 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.
Loss on Sale of Property and Equipment. We recorded a loss on sale of
property and equipment of $57,000 in 2002 as compared to $118,000 in 2001. See
Note 3 to the Financial Statements.
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.
Contractual Obligations
Our obligations as of December 31, 2004, under contractual obligations with
maturities exceeding one year, were as follows:
More than 5
Total 2005 2006 2007 2008 2009 years
------------- ------------- ---------- ---------- --------- ----- ------------
Long-term debt
obligations $ 23,603,897 $ 22,798,447 $ 506,565 $ 286,673 $ 12,212 $ - $ -
Operating lease
obligations 302,279 132,979 135,323 33,977 - - -
Asset retirement
obligations 1,144,854 - - 49,034 20,989 - 1,074,831
------------- ------------- ---------- ---------- --------- ----- ------------
$ 25,051,030 $ 22,931,426 $ 641,888 $ 369,684 $ 33,201 $ - $ 1,074,831
============= ============= ========== ========== ========= ===== ============
Financial Condition and Capital Resources.
At December 31, 2004, our current liabilities exceeded our current assets
by $33,353,875, primarily because of the classification of approximately $29.6
million of Company debt as current. Substantially all of that debt was paid off
in conjunction with the February 28, 2005 investment by Oaktree Capital
Management (see below). We had income available to common shareholders of
$7,616,609 compared to a loss available to common shareholders of $3,151,509 at
December 31, 2003.
On April 27, 2004, we completed an $18,000,000 financing package with new
energy lenders. We used $15,700,000 in net proceeds from the financing to retire
existing debt of $27,584,145, resulting in forgiveness of debt of $12,475,612,
the elimination of a hedging liability and the return to the Company of Series F
Preferred Stock with an aggregate liquidation preference of $1,000,000 (this
preferred stock, at the request of the Company, was transferred by the previous
lender to a financial advisor to the Company and to two companies affiliated
with two directors of the Company in satisfaction of Company obligations to
them. (See "Certain Relationships and Related Transactions.") This taxable gain
resulting from these transactions will be completely offset by available net
operating loss carryforwards. The term of the note is eighteen months and it
bears interest at the prime rate plus 11%. This rate increases by .75% per month
beginning in month ten. We paid the new lenders $1,180,000 in cash fees and also
issued them warrants to purchase 2,035,621 shares of our Common Stock at an
exercise price of $.01 per share, expiring in five years. The warrants are
subject to anti-dilution provisions. In connection with the February 2005
transactions described below, the anti-dilution provisions were amended such
that additional issuances of stock (other than issuances to all holders) would
not trigger an adjustment to the number of shares issuable upon exercise of the
warrants.
21
On January 7, 2005, we amended our April 2004 credit agreement to extend
the target date for repayment to February 28, 2005. We exercised this option on
January 26, 2005. We issued 29,100 shares of our common stock in connection with
this amendment.
In a subsequent event, on February 28, 2005, we sold in a private
placement, 81,000 shares of our Series G Preferred Stock to OCMGW for an
aggregate offering price of $40.5 million. GOGC issued, in a private placement,
2,000 shares of our Series A Preferred Stock, having a liquidation preference of
$1.0 million, to OCMGW for $1.5 million. Net proceeds of the offerings of
approximately $38 million after expenses are being used for the repayment of
substantially all of our outstanding debt and other past due liabilities and for
general corporate purposes.
The Series G Preferred Stock bears a coupon of 8% per year, has an
aggregate liquidation preference of $40.5 million, is convertible in the Common
Stock at $0.90 per share and is senior to all of our capital stock. For the
first four years after issuance, we may defer the payment of dividends on the
Series G Preferred Stock and these deferred dividends will also be convertible
into our Common Stock at $0.90 per share. In addition, the Series G Preferred
Stock is entitled to nominate and elect a majority of the members of the Board
of Directors of GulfWest.
In connection with these transactions, the terms of the Series A Preferred
Stock have been amended such that by March 15, 2005, all such stock would either
convert into a newly created Series H Preferred Stock on a one for one basis or
into Common Stock at a conversion price of $0.35 per share. The Series H
Preferred Stock is required to be paid a dividend of 40 shares of Common Stock
per share of Series H Preferred Stock per year. In addition, the Series H
Preferred Stock is convertible into Common Stock at a conversion price of $0.35
per share. At March 15, 2005, holders of 6,700 shares of Series A Preferred
Stock converted to Series H Preferred Stock and holders of 3,250 shares of
Series A Preferred Stock converted to an aggregate 4,642,859 shares of Common
Stock. One Series H Preferred Stock holder converted its shares of Series H
Preferred Stock to 285,715 shares of Common Stock. The outstanding Series H
Preferred Stock has an aggregate liquidation preference of $3.250 million. The
Series H Preferred Stock is senior to all of our capital stock other than Series
G Preferred Stock.
In addition, we amended the terms of our 9,000 shares of Series E Preferred
Stock such that the coupon of 6% per year they bear may be deferred for the next
four years and these deferred dividends will be convertible into Common Stock at
conversion price of $0.90 per share. The initial liquidation preference of the
Series E Preferred Stock of $500 per share remains convertible into Common Stock
at $2.00 per share. The Series E Preferred Stock has an aggregate liquidation
preference of $4.5 million, and is senior to all of our Common Stock, of equal
preference with our Series D Preferred Stock as to liquidation and junior to our
Series G Preferred Stock and H.
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(1)
------------------------------------
Crude Oil Per
And Natural Equivalent
Liquids Gas Barrel
--------- --------- ----------
(per Bbl) (per Mcf)
2004
- ----
First $ 27.97 $ 4.87 $ 28.59
Second 30.41 5.34 31.18
Third 32.72 5.44 33.36
Fourth 35.32 5.97 35.58
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
- ------------------
(1) Average sales price are shown net of the settled amounts of our oil and gas
hedge contracts.
22
ITEM 7a. Qualitative and Quantitative Disclosures About Market Risk.
The following market rate disclosures should be read in conjunction with
our financial statements and notes thereto beginning on Page F-1 of this Annual
Report. All of our financial instruments are for purposes other than trading. We
only enter into derivative financial instruments in conjunction with our oil and
gas sales price hedging activities. Hypothetical changes in interest rates and
prices chosen for the following stimulated sensitivity effects are considered to
be reasonably possible near-term changes generally based on consideration of
past fluctuations for each risk category. It is not possible to accurately
predict future changes in interest rates and product prices. Accordingly, these
hypothetical changes may not be an indicator of probable future fluctuations.
Interest Rate Risk
We are exposed to interest rate risk on debt with variable interest rates.
At December 31, 2004, we carried variable rate debt of $30,189,455. Assuming a
one percentage point change at December 31, 2004 on our variable rate debt, the
annual pretax net income or loss would change by $301,895.
Commodity Price Risk
In the past we have entered into, and may in the future enter into, certain
derivative arrangements with respect to portions of our oil and natural gas
production to reduce our sensitivity to volatile commodity prices. During 2004,
2003, and 2002, we entered into price swaps and put agreements with financial
institutions. We believe that these derivative arrangements, although not free
of risk, allow us to achieve a more predictable cash flow and to reduce exposure
to price fluctuations. However, derivative arrangements limit the benefit to us
of increases in the prices of crude oil and natural gas sales. Moreover, our
derivative arrangements apply only to a portion of our production and provide
only partial price protection against declines in price. Such arrangements may
expose us to risk of financial loss in certain circumstances. We expect that the
monthly volume of derivative arrangements will vary from time to time. We
continuously reevaluate our price hedging program in light of market conditions,
commodity price forecasts, capital spending and debt service requirements. The
following hedges were in place at December 31, 2004 or were added subsequent to
that date and are effective for the periods shown.
Crude Oil Volume/ Month Average Price/ Unit
--------- ------------- -------------------
January 2005 thru October 2005 Swap 10,000 Bbls $32.00
April 2005 thru June 2005 Swap 2,000 Bbls $56.50
July 2005 thru October 2005 Swap 1,000 Bbls $56.50
November & December 2005 Swap 11,000 Bbls $56.50
January 2006 thru March 2006 Collar 10,000 Bbls Floor $50.00-$59.00 Ceiling
April 2006 thru December 2006 Collar 9,000 Bbls Floor $50.00-$59.00 Ceiling
January 2007 thru December 2007 Collar 3,000 Bbls Floor $45.00-$59.45 Ceiling
Natural Gas Volume/ Month Average Price/ Unit
----------- ------------- -------------------
January 2005 thru October 2005 Swap 60,000 MMBTU $5.15
April 2005 thru June 2005 Swap 20,000 MMBTU $7.45
July 2005 thru October 2005 Swap 10,000 MMBTU $7.45
November & December 2005 Swap 70,000 MMBTU $7.45
January 2006 thru December 2006 Collar 70,000 MMBTU Floor $6.00-$8.25 Ceiling
January 2007 thru December 2007 Collar 20,000 MMBTU Floor $6.00-$6.95 Ceiling
23
These volumes represent approximately 75% of the estimated production (for
both oil and natural gas) on currently producing properties for the remainder of
2005 and for 2006 and approximately 30% of estimated production for 2007.
We also had, at December 31, 2004, the following puts options in place for
the months reflected. These contracts were terminated in conjunction with the
new swap and cost-less collars added in March 2005.
Crude Oil Monthly Volume Price per Bbl
--------- -------------- -------------
November 1, 2005 to April 30, 2006 7,000 Bbls $25.75 put
May 1, 2006 to October 31, 2006 6,000 Bbls $25.75 put
November 1, 2006 to April 30, 2007 5,000 Bbls $25.75 put
Natural Gas Monthly Volume Price per MMBTU
----------- -------------- ---------------
November 1, 2005 to April 30, 2006 50,000 MMBTU $4.50 put
May 1, 2006 to October 31, 2006 40,000 MMBTU $4.50 put
November 1, 2006 to April 30, 2007 30,000 MMBTU $4.50 put
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 as of the balance sheet dates is
reported in Other Assets (or Other Liabilities) as derivative instruments.
Oil and gas sales are adjusted for gains or losses related to the effective
portion of hedging transactions as the underlying hedged production is sold.
Changes in fair value of the ineffective portion of designated hedges or for
derivative arrangements that do not qualify as hedges are recognized in the
consolidated statement of income as derivative gain or loss. Adjustments to oil
and gas sales realized from our hedging activities resulted in a reduction in
revenues of $1,841,209, $1,496,303 and $368,776 in 2004, 2003 and 2002,
respectively. In addition, we accrued an unrealized gain/(loss) on derivatives
of ($1,505,527), $537,526 and ($1,596,575) in 2004, 2003 and 2002, respectively,
for the fair value of the hedges at each balance sheet date. See Note 1 to our
Consolidated Financial Statements included in this Annual Report for additional
discussion on derivative instruments.
All hedges which were in existence at March 31, 2004 were canceled as part
of our debt restructuring on April 27, 2004. As of December 31, 2004, new
derivative instruments in place had an estimated liability fair value of
$1,505,527. 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 instruments. However, it is not practicable to estimate the resultant
change, if any, in the future fair value of our derivative instruments.
More generally, dramatic price volatility in the natural gas and oil
markets has existed the past several years. In fact, the average quoted prices
for natural gas hovered around the low levels of $2.10 per MCf in January 2002,
with the expectation of further decreases. However, the market prices
dramatically reversed in the summer months of 2002 and have continued to
increase
24
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
At the end of 2004, our President, Chief Executive Officer and Chief
Financial Officer evaluated the effectiveness of the design and operation of our
disclosure controls and procedures pursuant to Rule 13a-15 (b) under the
Securities Exchange Act of 1934, as amended ("the Exchange Act"). Based upon
this evaluation, they concluded that, subject to the limitations described
below, the Company's disclosure controls and procedures offer reasonable
assurance that the information required to be disclosed by the Company in the
reports it files under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the rules and forms adopted by the
Securities and Exchange Commission.
During the period covered by this report, there has been no change in the
Company's internal controls over financial reporting that materially affected,
or is reasonably likely to materially affect, these controls.
Limitations on the Effectiveness of Controls. Our management, including the
President, Chief Executive Officer and Chief Financial Officer, does not expect
that the Company's disclosure controls and procedures will prevent all error and
all fraud. A well conceived and operated control system is based in part upon
certain assumptions about the likelihood of future events and can provide only
reasonable, not absolute, assurance that the objectives of the control systems
are met. Further, the design of a control system must reflect the fact that
there are resource constraints, and the benefits of controls must be considered
relative to their costs.
PART III
ITEM 10. Directors and Executive Officers of the Registrant.
Information regarding directors and executive officers of the registrant is
incorporated herein by reference to our Proxy Statement that is expected to be
filed prior to April 30, 2005.
ITEM 11. Executive Compensation.
Information regarding executive compensation is incorporated herein by
reference to our Proxy Statement that is expected to be filed prior to April 30,
2005
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
Information regarding security ownership of certain beneficial owners and
management and related stockholder matters is incorporated herein by reference
to our Proxy Statement that is expected to be filed prior to April 30, 2005
ITEM 13. Certain Relationships and Related Transactions.
Information regarding certain relationships and related transactions is
incorporated herein by reference to our Proxy Statement that is expected to be
filed prior to April 30, 2005.
25
ITEM 14. Principal Accountant Fees and Services.
Information regarding principal accountant fees and services is
incorporated herein by reference to our Proxy Statement that is expected to be
filed prior to April 30, 2005.
26
GLOSSARY OF INDUSTRY TERMS AND ABBREVIATIONS
The following are definitions of certain industry terms and abbreviations used
in this report:
Bbl. Barrel.
BOE. Barrel of oil equivalent, based on a ratio of 6,000 cubic feet of natural
gas for each barrel of oil.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in
which a working interests is owned.
Horizontal Drilling. High angle directional drilling with lateral penetration of
one or more productive reservoirs.
Mcf. One thousand cubic feet.
Net Acres or Net Wells. The sum of the fractional working interests owned in
gross acres or gross wells.
Overriding Royalty Interest. The right to receive a share of the proceeds of
production from a well, free of all costs and expenses, except transportation.
Present Value. The pre-tax present value, discounted at 10%, of future net cash
flows from estimated proved reserves, calculated holding prices and costs
constant at amounts in effect on the date of the report (unless such prices or
costs are subject to change pursuant to contractual provisions) and otherwise in
accordance with the Commission's rules for inclusion of oil and gas reserve
information in financial statements filed with the Commission.
Proceeds of Production. Money received (usually monthly) from the sale of oil
and gas produced from producing properties.
Producing Properties. Properties that contain one or more wells that produce oil
and/or gas in paying quantities (i.e., a well for which proceeds from production
exceed operating expenses).
Productive Well. A well that is producing oil or gas or that is capable of
production.
Prospect. A lease or group of leases containing possible reserves, capable of
producing crude oil, natural gas, or natural gas liquids in commercial
quantities, either at the time of acquisition, or after vertical or horizontal
drilling, completion of workovers, recompletions, or operational modifications.
Proved Reserves. Estimated quantities of crude oil, natural gas, and natural gas
liquids that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic conditions; i.e., prices and costs as of the date the estimate is made.
Reservoirs are considered proved if either actual production or a conclusive
formation test supports economic production.
The area of a reservoir considered proved includes:
a. That portion delineated by drilling and defining by gas-oil or
oil-water contacts, if any; and
b. The immediately adjoining portions not yet drilled but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on
fluid contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.
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:
27
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 sales and other sources.
Proved Developed Reserves. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods. Additional oil and
gas expected to be obtained through the application of fluid injection or other
improved recovery techniques for supplementing the natural forces and mechanisms
of primary recovery should be included as proved developed only after testing by
a pilot project or after operation of an installed program has confirmed through
production response that increased recovery will be achieved.
Proved Undeveloped Reserves. Reserves that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion. Reserves on undrilled acreage shall be
limited to those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other units that have
not been drilled can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
Under no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proven effective by actual tests in the area and in the same reservoir.
Recompletion. The completion for production of an existing wellbore in another
formation from that in which the well has previously been completed.
Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible oil or gas that is confined by impermeable rock or
water barriers and is individual and separate from other reservoirs.
Royalty. The right to a share of production from a well, free of all costs and
expenses, except transportation.
Royalty Interest. An interest in an oil and gas property entitling the owner to
a share of oil and natural gas production free of costs of production.
Standardized Measure. The present value, discounted at 10%, of future net cash
flows from estimated proved reserves, after income taxes, calculated holding
prices and costs constant at amounts in effect on the date of the report (unless
such prices or costs are subject to change pursuant to contractual provisions)
and otherwise in accordance with the Commission's rules for inclusion of oil and
gas reserve information in financial statements filed with the Commission.
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.
28
PART IV
ITEM 15. Exhibits and Financial Statement Schedules.
(a) The following documents are filed as part of this Report: (1)
Financial Statements:
Consolidated Balance Sheets at December 31, 2004 and 2003.
Consolidated Statements of Operations for the years ended
December 31, 2004, 2003 and 2002.
Consolidated Statements of Stockholders' Equity for the years
ended December 31, 2004, 2003 and 2002.
Consolidated Statements of Cash Flows for the years ended
December 31, 2004, 2003 and 2002.
Notes to Consolidated Financial Statements, December 31, 2004,
2003 and 2002.
(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. (Previously filed with our Registration Statement
on Form S-1, Reg. No. 33-53526, filed with the Commission on
October 21, 1992.)
3.2 Amendment to the Company's Articles of Incorporation to
increase the number of shares of Class A Common Stock that
the Company will have authority to issue from 20,000,000 to
40,000,000 shares, approved by the Shareholders on November
19, 1999 and filed with the Secretary of State of Texas on
December 3, 1999. (Previously filed with our Definitive
Proxy Statement, filed with the Commission on October 20,
1999.)
3.3 Amendment to the Articles of Incorporation of the Registrant
changing the name of the Registrant to "GulfWest Energy
Inc.", approved by the Shareholders on May 18, 2001 and
filed with the Secretary of Texas on May 21, 2001.
(Previously filed with our Definitive Proxy Statement, filed
with the Commission on April 16, 2001.)
3.4 Bylaws of the Registrant.