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."
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.
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.
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.
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.
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.
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.
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 ============= ===========
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.
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.
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.
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.
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"
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.
ITEM 3.
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.
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.
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 ------ ------ ---- First Quarter $ .45 $ .32 Second Quarter .56 .33 Third Quarter .85 .45 Fourth Quarter .94 .66
---- First Quarter $ .45 $ .42 Second Quarter .47 .35 Third Quarter .47 .43 Fourth Quarter .47 .32
---- 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.
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 of the Financial Statements).
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.
ITEM 6.
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.
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.
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.
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.
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.
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:
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.
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) - ---- 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
- ---- 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
- ---- 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.
ITEM 7a.
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 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.
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.
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
ITEM 8.
ITEM 8. Financial Statements and Supplementary Data.
Information with respect to this Item 8 is contained in our financial statements beginning on Page of this Annual Report.
ITEM 9.
ITEM 9. Changes In and Disagreements With Accountants and Accounting and Financial Disclosure.
None
ITEM 9A.
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.
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.
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,
ITEM 12.
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.
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.
ITEM 14.
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.
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:
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.
PART IV
ITEM 15.
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. (Previously filed with our Registration Statement on Form S-1, Reg. No. 33-53526, filed with the Commission on October 21, 1992.)
3.5 Statement of Resolution Establishing Series H Convertible Preferred Stock, dated February 28, 2005. (Previously filed with our Form 8-K, Reg. No. 001-12108, filed with the Commission on March 4, 2005.)
3.6 Statement of Resolution Establishing Series G Convertible Preferred Stock, dated February 28, 2005. (Previously filed with our Form 8-K, Reg. No. 001-12108, filed with the Commission on March 4, 2005.)
*3.7 Certificate of Correction to the Statement of Resolution Establishing Series G Convertible Preferred Stock, dated March 16, 2005.
3.8 Articles of Amendment amending Statement of Resolution Establishing Series E Preferred Stock, dated February 28, 2005. (Previously filed with our Form 8-K, Reg. No. 001-12108, filed with the Commission on March 4, 2005.)
3.9 Articles of Amendment amending Statement of Resolution Establishing Series A Preferred Stock, dated February 28, 2005. (Previously filed with our Form 8-K, Reg. No. 001-12108, filed with the Commission on March 4, 2005.)
3.10 Statement of Resolution Establishing and Designating a Series of Shares of GulfWest Oil & Gas Company Series A Preferred Stock, as filed with the Secretary of State of Texas on April 26, 2004. (Previously filed with our Current Report on Form 8-K dated April 29, 2004 and filed with the Commission on May 10, 2004.)
3.11 Statement of Resolution Establishing and Designating a Series of Shares of GulfWest Energy Inc. Series D Preferred Stock, as filed with the Secretary of State of Texas on June 11, 2000. (Previously filed with our Registration Statement on Form S-1, Reg. No. 333-116048, filed with the Commission on June 1, 2004.)
3.12 Statement of Resolution Establishing and Designating a Series of Shares of GulfWest Energy Inc. Series E Preferred Stock, as filed with the Secretary of State of Texas on August 14, 2001. (Previously filed with our Current Report on Form 8-K dated August 16, 2001 and filed Commission on August 31, 2001.)
3.13 Statement of Resolution Establishing and Designating a Series of Shares of GulfWest Energy Inc. Series F Preferred Stock, as filed with the Secretary of State of Texas on June 18, 2003. (Previously filed with our Registration Statement on Form S-1, Reg. No. 333-116048, filed with the Commission on June 1, 2004.)
4.1 Letter Agreement by and among GulfWest Energy Inc., a Texas corporation, GulfWest Oil & Gas Company and the investors listed on the signature page thereof, dated April 22, 2004. (Previously filed with our Current Report on Form 8-K, dated April 29, 2004 and filed with the Commission on May 10, 2004.)
4.2 Warrant Agreement made by and between GulfWest Energy Inc., and Highbridge/Zwirn Special Opportunities FUND, L.P., and Drawbridge Special Opportunities Fund LP, Grantees, dated and effective April 29, 2004. (Previously filed with our Current Report on Form 8-K dated April 29, 2004 and filed with the Commission on May 10, 2004.)
4.3 Shareholders Rights Agreement between GulfWest Energy Inc. and OCM GW Holdings, LLC dated February 28, 2005. (Previously filed with our Form 13D, Reg. No. 005-54301, filed with the Commission on March 10, 2005.)
*4.4 Omnibus and Release Agreement among GulfWest Energy Inc., OCM GW Holdings, LLC and those signatories set forth on the signature page thereto, dated as of February 28, 2004. (Previously filed with our Form 13D, Reg. No. 005-54301, filed with the Commission on March 10, 2005.)
4.5 Share Transfer Restriction Agreement between J. Virgil Waggoner and OCM GW Holdings, LLC, dated February 28, 2005.
*4.6 Irrevocable Proxy executed by J. Virgil Waggoner dated February 28, 2005.
*4.7 Exchange Agreement between GulfWest Energy Inc. and GulfWest Oil & Gas Company, dated February 28, 2005.
*4.8 Letter Agreement among OCM GW Holdings, LLC, OCM Principal Opportunities Fund III, L.P., OCM Principal Opportunities Fund III GP, LLC, Oaktree Capital Management, LLC, GulfWest Energy Inc., GuflWest Oil & Gas Company and J. Virgil Waggoner dated February 28, 2005
4.9 Subscription Agreement among OCM GW Holdings, LLC, Allan D. Keel and those individuals listed on the signature page thereto, dated February 28, 2005. (Previously filed with our Form 13D, Reg. No. 005-54301, filed with the Commission on March 10, 2005.)
*4.10 First Amendment to Warrant Agreement among GulfWest Energy Inc., D.B. Zwirn Special Opportunities Fund, L.P. and Drawbridge Special Opportunities Fund, dated February 28, 2005.
*10.1 Employment Agreement between Allan D. Keel and GulfWest Energy, Inc., dated February 28, 2005.
*10.2 Employment Agreement between E. Joseph Grady and GulfWest Energy, Inc., dated February 28, 2005.
10.3 GulfWest Oil Company 1994 Stock Option and Compensation Plan,amended and restated as of April 1, 2001 and approved by the shareholders on May 18, 2001. (Previously filed with our Proxy Statement on Form DEF 14A, filed with the Commission on April 16, 2001.)
*10.4 GulfWest Energy Inc. 2004 Stock Option Incentive Plan
*10.5 GulfWest Energy Inc. 2005 Stock Option Incentive Plan.
*10.6 Form of GulfWest Energy Inc. 2005 Stock Incentive Plan Stock Option Agreement.
*10.7 Form of Warrant Agreement.
*10.8 Indemnification Agreement between GulfWest Energy Inc. and J. Virgil Waggoner, dated February 28, 2005.
*10.9 Indemnification Agreement between GulfWest Energy Inc. and B. James Ford, dated February 28, 2005.
*10.10 Indemnification Agreement between GulfWest Energy Inc. and Skardon F. Baker, dated February 28, 2005.
*10.11 Indemnification Agreement between GulfWest Energy Inc. and John Loehr, dated February 28, 2005.
*10.12 Indemnification Agreement between GulfWest Energy Inc. and Allan Keel, dated February 28, 2005.
*10.13 Letter Agreement among D.B. Zwirn Special Opportunities Fund, LP, GulfWest Oil & Gas, and Drawbridge Special Opportunities Fund, LP, dated January 7, 2005.
10.14 Series G Subscription Agreement between GulfWest Energy Inc. and OCM GW Holdings, LLC dated February 28, 2005. (Previously filed with our Form 13D, Reg. No. 005-54301, filed with the Commission on March 10, 2005.)
10.15 Series A Subscription Agreement between GulfWest Oil & Gas Company and OCW GW Holdings, LLC dated February 28, 2005. (Previously filed with our Form 13D, Reg. No. 005-54301, filed with the Commission on March 10, 2005.)
*10.16 Letter Agreement between W.L. Addison Investment, L.L.C., GulfWest Energy Inc., and Setex Oil and Gas Company dated February 24, 2005 extending Option Agreement for the Purchase of Oil and Gas Leases dated March 5, 2004.
*10.17 Letter Agreement between W.L. Addison Investment, L.L.C., GulfWest Energy Inc., and Setex Oil and Gas Company dated July 15, 2004 extending Option Agreement for the Purchase of Oil and Gas Leases dated March 5, 2004.
10.18 Option Agreement for the Purchase of Oil and Gas Leases with W.L. Addison Investments L.L.C. dated March 5, 2004 (Previously filed with our Registration Statement on Form S-1, Reg. No. 333-116048, filed with the Commission on June 1, 2004.)
10.19 Employment Agreement with Thomas R. Kaetzer. (Previously filed with our Registration Statement on Form S-1, Reg. No. 333-116048, filed with the Commission on June 1, 2004.)
10.20 Consulting Agreement with Marshall A. Smith. (Previously filed with our Registration Statement on Form S-1, Reg. No. 333-116048, filed with the Commission on June 1, 2004.)
10.21 Oil and Gas Property Acquisition, Exploration and Development Agreement with Summit Investment Group-Texas, L.L.C. effective December 1, 2001. (Previously filed with our Registration Statement on Form S-1, Reg. No. 333-116048, filed with the Commission on June 1, 2004.)
10.22 Credit Facility between GulfWest Energy Inc. and Highbridge/Zwirn Special Opportunities FUND, L.P., and Drawbridge Special Opportunities Fund LP, Grantees, dated and effective April 29, 2004. (Previously filed with our Registration Statement on Form S-1, Reg. No. 333-116048, filed with the Commission on June 1, 2004.)
10.23 Credit Agreement between GulfWest Development Company and Texas Capital Bank, dated November 30, 2000. (Previously filed with our Registration Statement on Form S-1, Reg. No. 333-116048, filed with the Commission on June 1, 2004.)
10.24 First Amendment to Credit Agreement between GulfWest Development Company and Texas Capital Bank, dated October 24, 2001. (Previously filed with our Registration Statement on Form S-1, Reg. No. 333-116048, filed with the Commission on June 1, 2004.)
10.25 Revolving Letter Loan Agreement between GulfWest Energy Inc. and Texas Capital Bank, N.A. dated April 3, 2002. (Previously filed with our Registration Statement on Form S-1, Reg. No. 333-116048, filed with the Commission on June 1, 2004.)
10.26 Change in Terms Agreement between GulfWest Energy Inc. and Southwest Bank of Texas N.A. dated April 29, 2003. (Previously filed with our Registration Statement on Form S-1, Reg. No. 333-116048, filed with the Commission on June 1, 2004.) *22.1 Subsidiaries of the Registrant (included on page 3 of this Annual Report.
*23.1 Consent of Weaver and Tidwell, L.L.P.
*23.2 Consent of Independent Petroleum Engineers.
*25 Power of Attorney (included on signature page of this Annual Report).
*31.1 Certification of Chief Executive Officer pursuant to Exchange Rule 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002; filed herewith.
*31.2 Certification of Chief Financial Officer pursuant to Exchange Rule 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002; filed herewith.
*32 Certification pursuant to 18.U.S.C Section 1350 pursuant to Section 906 of the Sarbanes-Oxley Act of 2002; filed herewith.
*Filed Herewith
S I G N A T U R E S
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
GULFWEST ENERGY INC.
Date: March 31,2005 By /s/ Allan D. Keel ------------------------ Allan D. Keel, President
POWER OF ATTORNEY
Know all men by these presents, that each person whose signature appears below constitutes and appoints Allan D. Keel as his true and lawful attorney-in-fact and agent, with full power of substitution, for him and in his name, place, and stead, in any and all capacities to sign any and all amendments or supplements to this Annual Report on Form 10-K, and to file the same, and with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons, on behalf of the registrant, and in the capacities and on the dates indicated.
Signature Title Date - ---------------------- ---------------------------------- -------------- /s/ J. Virgil Waggoner Chairman of the Board March 29, 2005 - ---------------------- J. Virgil Waggoner
/s/ Allan D. Keel President, Chief Executive Officer March 29, 2005 - ----------------- and Director Allan D. Keel
/s/ E. Joseph Grady Senior Vice President and March 29, 2005 - -------------------- Chief Financial Officer E. Joseph Grady
/s/ Richard L. Creel Vice President Finance and March 29, 2005 - -------------------- Chief Accounting Officer Richard L. Creel
/s/ Skardon F. Baker Director March 29, 2005 - -------------------- Skardon F. Baker
/s/ John E. Loehr Director March 29, 2005 - ----------------- John E. Loehr
/s/ B. James Ford Director March 29, 2005 - ----------------- B. James Ford
GULFWEST ENERGY INC.
FINANCIAL REPORT
DECEMBER 31, 2004
C O N T E N T S
Page ---- REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
FINANCIAL STATEMENTS
Consolidated Balance Sheets............................................F-2
Consolidated Statement of Operations...................................F-4
Consolidated Statements of Stockholders Equity.........................F-5
Consolidated Statements of Cashflows...................................F-7
Notes to Consolidated Financial Statements.............................F-8
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM.....................F-33
FINANCIAL STATEMENT SCHEDULE
SCHEDULE II- VALUATION AND QUALIFYING ACCOUNTS........................F-34
All other Financial Statement Schedules have been omitted because they are either inapplicable or the information required is included in the financial statements or the notes thereto.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors GULFWEST ENERGY INC.
We have audited the accompanying consolidated balance sheets of GulfWest Energy Inc. (a Texas Corporation) and Subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2004. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of The Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of GulfWest Energy Inc. and Subsidiaries as of December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.
/s/WEAVER AND TIDWELL, L.L.P WEAVER AND TIDWELL, L.L.P.
Dallas, Texas March 29, 2005
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2004 AND 2003
ASSETS
GULFWEST ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2004 AND 2003
LIABILITIES AND STOCKHOLDERS' EQUITY
The Notes to Consolidated Financial Statements are an integral part of these statements.
GULFWEST ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
GULFWEST ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
The Notes to Consolidated Financials are an integral part of these statements.
GULFWEST ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
The Notes to Consolidated Financials are an integral part of these statements.
GULFWEST ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
The Notes to Consolidated Financial Statements are an integral part of these statements.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
The following is a summary of the significant accounting policies consistently applied by management in the preparation of the accompanying consolidated financial statements.
Organization
GulfWest Energy Inc. and our subsidiaries intend to pursue the acquisition of quality oil and gas prospects, which have proved developed and undeveloped reserves, and the development of prospects with third party industry partners.
The accompanying consolidated financial statements include our company and its wholly-owned subsidiaries: RigWest Well Service, Inc. ("RigWest"), GulfWest Texas Company ("GWT"), both formed in 1996; DutchWest Oil Company formed in 1997; SETEX Oil and Gas Company ("SETEX") formed August 11, 1998; Southeast Texas Oil and Gas Company, L.L.C. ("Setex LLC") acquired September 1, 1998; GulfWest Oil and Gas Company formed February 18, 1999; LTW Pipeline Co. formed April 19, 1999; GulfWest Development Company ("GWD") formed November 9, 2000 and GulfWest Oil and Gas Company (Louisiana) LLC, formed July 31, 2001. All material intercompany transactions and balances have been eliminated in consolidation.
Statement of Cash Flows
We consider all highly liquid investment instruments purchased with remaining maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows.
Non-Cash Investing and Financing Activities:
During the twelve month period ended December 31, 2004, in settlement of a contract we issued a note payable for $600,000 in replacement of an account payable for $538,954 and the recognition of an additional $61,046 of interest expense. Also, as a result of refinancing debt in which we recorded a $12,475,612 forgiveness of debt, we issued Common Stock warrants valued at $916,029 which were recorded as a discount to the face value of the new note issued, we issued $500,000 of preferred stock of a wholly owned subsidiary as a commission to our financial advisor, and recorded a $360,000 payable for a loan termination fee. The termination fee was subsequently increased by $48,000 as a result of increasing the principal amount of the new note. We also financed field trucks for $78,036. In addition, we invested $274,362 in a partnership by contributing our cost basis of $76,732 in a natural gas pipeline and $197,630 in undeveloped oil and gas leases to the partnership.
During the twelve month period ended December 31, 2003, we adopted Statement of Financial Accounting Standard No. 143 "Asset Retirement Obligations" (SFAS 143). As a result of adopting SFAS 143, effective January 1, 2003, we recorded an asset retirement obligation liability of $1,280,383, an increase in the carrying value of our oil and gas properties of $1,058,445, a reduction in accumulated depletion of $484,390 a change of $262,452 to income as a cumulative effect of a change in accounting principal. This retirement liability was increased during 2004 and 2003 by recognizing$72,247 and $76,823 respectfully, in accretion expense. Also, we decreased the current portion of long term debt-related parties by applying $17,300 in deposits and reclassified $176,320 from accrued expenses to current portion of long term debt.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. in Summary of Significant Accounting Policies (continued)
Use of Estimates in the Preparation of Financial Statements
The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Oil and Gas Properties
We use the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, and geological and geophysical costs are expensed.
As we acquire significant oil and gas properties, any unproved property that is considered individually significant is periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Capitalized costs of producing oil and gas properties and support equipment, after considering estimated dismantlement and abandonment costs and estimated salvage values, are depreciated and depleted by the unit-of-production method.
On the sale of an entire interest in an unproved property, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property has been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. On the sale of an entire or partial interest in a proved property, gain or loss is recognized, based upon the fair values of the interests sold and retained.
Other Property and Equipment
The following tables set forth certain information with respect to our other property and equipment. We provide for depreciation and amortization using the straight-line method over the following estimated useful lives of the respective assets:
Assets Years --------------------------------- ------------- Automobiles 3-5 Office equipment 7 Gathering system 10 Well servicing equipment 10
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Other Property and Equipment - continued
Capitalized costs relating to other properties and equipment:
Impairments
We have adopted SFAS 144 "Accounting for the Impairment or Disposal of Long- Lived Assets". Accordingly, impairments, measured using fair market value, are recognized whenever events or changes in circumstances indicate that the carrying amount of long-lived assets (other than unproved oil and gas properties discussed above) may not be recoverable and the future undiscounted cash flows attributable to the asset are less than its carrying value.
Revenue Recognition
We recognize oil and gas revenues on the sales method as oil and gas production is sold. Differences between sales and production volumes during the years ended December 31, 2004, 2003, and 2002 were not significant. Well servicing revenues are recognized as the related services are performed. Operating overhead income is recognized based upon monthly contractual amounts for lease operations and other income is recognized as earned.
Trade Accounts Receivable
We grant credit to creditworthy independent and major oil and gas companies for the sale of crude oil and natural gas. In addition, we grant credit to joint owners of oil and gas properties, which we, through our subsidiary, SETEX, operate. Such amounts are secured by the underlying ownership interests in the properties. We also grant credit to various third parties through RigWest for well servicing operations.
Trade accounts receivable are reported in the consolidated balance sheet at the outstanding principal adjusted for any chargeoffs. An allocation for doubtful accounts is recognized by management based upon a review of specific customer balances, historical losses and general economic conditions.
We maintain cash on deposit in non-interest bearing accounts, which, at times, exceed federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents.
Fair Value of Financial Instruments
At December 31, 2004 and 2003, our financial instruments consist of notes payable and long-term debt. Interest rates currently available to us for notes payable and long-term debt with similar terms and remaining maturities are used to estimate fair value of such financial instruments. Accordingly, since interest rates on substantially all of our debt are variable, market based rates, the carrying amounts are a reasonable estimate of fair value.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Debt Issuance Costs
Debt issue costs incurred are capitalized and subsequently amortized over the term of the related debt on a straight-line basis.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Earnings (Loss) Per Share
We have adopted Statement of Financial Accounting Standards (SFAS) No. 128 "Earnings Per Share", which requires that both basic earnings (loss) per share and diluted earnings (loss) per share be presented on the face of the statement of operations. Basic earnings (loss) per share are based on the weighted-average number of outstanding common shares. Diluted earnings (loss) per-share are based on the weighted-average number of outstanding common shares and the effect of all potentially diluted common shares.
Stock Based Compensation
In October 1995, SFAS No. 123, "Stock Based Compensation," (SFAS 123) was issued. This statement requires that we choose between two different methods of accounting for stock options and warrants. The statement defines a fair-value-based method of accounting for stock options and warrants but allows an entity to continue to measure compensation cost for stock options and warrants using the accounting prescribed by APB Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees." Use of the APB 25 accounting method results in no compensation cost being recognized if options are granted at an exercise price at the current market value of the stock or higher. We are required by SFAS 123 to make pro forma disclosures of net income (loss) and earnings (loss) per share as if the fair value method had been applied in its 2004, 2003 and 2002 financial statements. All options were issued with an exercise price at or above fair market value on the date of grant with the exception of one grant of 281,000 options, for which we have accrued $129,260 in compensation expense in 2004. Also see Recent Accounting Pronouncements.
During 2004, 2003 and 2002, we issued options and warrants totaling: 1,610,000 shares in 2004 (exercisable 1,085,000); 35,000 in 2003 (all exercisable); 405,000 shares in 2002 (all exercisable), respectively, to employees and directors as compensation. If we had used the fair value method required by SFAS 123, our net income (loss) and per share information would approximate the following amounts:
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Stock Based Compensation - continued
The effects of applying SFAS 123 as disclosed above are not indicative of future amounts. We anticipate making additional stock based employee compensation awards in the future.
We use the Black-Sholes option-pricing model to estimate the fair value of the options and warrants (to employee and non-employees) on the grant date. Significant assumptions include (1) risk free interest rate 2004- 3.0%, 2003 - 3.0%; 2002 - 3.0%; (2) weighted average expected life 2004- 3.0, 2003 - 3.4; 2002 - 3.6; (3) expected volatility of 2004- 94.32%, 2003 - 147.43%; 2002 - 101.73%; and (4) no expected dividends.
Implementation of New Financial Accounting Standards
Effective January 1, 2001, we adopted SFAS No. 133 "Accounting for Derivative Instruments and other Hedging Activities", as amended by SFAS No. 137 and No. 138. It has been determined that our oil and gas hedging agreements meet the definition of SFAS 133 "Accounting for Derivative Instruments and other Hedging Activities" and are accounted for as a derivative instruments.
Effective January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This statement requires the following three-step approach for assessing and recognizing the impairment of long-lived assets: (1) consider whether indicators of impairment of long-lived assets are present; (2) if indicators of impairment are present, determine whether the sum of the estimated undiscounted future cash flows attributable to the assets in question is less than their carrying amount; and (3) if less, recognize an impairment loss based on the excess of the carrying amount of the assets over their respective fair values. In addition, SFAS No. 144 provides more guidance on estimating cash flows when performing a recoverability test, requires that a long-lived asset to be disposed of other than by sale (such as abandoned) be classified as "held and used" until it is disposed of, and establishes more restrictive criteria to classify an asset as "held for sale". The adoption of SFAS No. 144 did not have a material impact on our financial statements since it retained the fundamental provisions of SFAS No. 121, "Accounting for the Impairment or Disposal of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," related to the recognition and measurement of the impairment of long-lived assets to be "held and used".
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies - continued
Implementation of New Financial Accounting Standards - continued
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF Issue No. 94-3, a liability for an exit cost as defined was recognized at the date of an entity's commitment to an exit plan. SFAS No. 146 also establishes that the fair value is the objective for the initial measurement of the liability. SFAS No. 146 is effective for exit and disposal activities that are initiated after December 31, 2002. This statement will impact the timing of our recognition of liabilities for costs associated with future exit or disposal activities.
Beginning in 2003, Statement of Financial Accounting Standards No. 143, "Asset Retirement Obligations" ("SFAS 143") requires us to recognize an estimated liability for the plugging and abandonment of our oil and gas wells and associated pipelines and equipment. Consistent with industry practice, historically we had assumed the cost of plugging and abandonment would be offset by salvage value received. This statement requires us to record a liability in the period in which our asset retirement obligation ("ARO") is incurred. After initial recognition of the liability, we must capitalize an additional asset cost equal to the amount of the liability. In addition to any obligation that arises after the effective date of SFAS 143, upon initial adoption we must recognize (1) a liability for any existing ARO's, (2) capitalized cost related to the liability, and (3) accumulated depreciation, depletion and amortization on that capitalized cost adjusting for the salvage value of related equipment.
The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate of 7.5%. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free rate or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, we will be required to recognize a gain or loss on abandonment if the actual costs do not equal the estimated costs.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record (i) a $1,058,445 increase in the carrying value of proved properties, (ii) a $484,390 decrease in accumulated depreciation, depletion and amortization, (iii) a $1,280,383 increase in noncurrent liabilities, and (iv) a $262,452 gain, net of tax.
Recent Accounting Pronouncements
On December 16, 2004, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 123 (revised 2004), Share-Based Payments which is a revision of FASB No. 123, Accounting for Stock-Based Compensation. Statement 123 (R) supercedes APB opinion No. 25, Accounting for Stock Issued to Employees, and amends FASB Statement No. 95, Statement of Cash Flows. Generally, the approach in Statement 123 (R) is similar to the approach described in Statement 123. However, Statement 123 (R) requires all share- based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative. The provisions of this statement become effective for our third quarter of 2005. Management has not yet determined the impact that this statement will have on our consolidated financial statements.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 2. Recapitalization
At December 31, 2004, despite certain refinancing during 2004 our current liabilities exceeded our current assets by $33,353,875, which without additional capital left doubt about our ability to survive; however this doubt was eliminated pursuant to the 2005 recapitalization described below.
On April 27, 2004, we completed an $18,000,000 financing package with new energy lenders. We used $15,700,000 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 us our Series F Convertible Preferred Stock with an aggregate liquidation preference of $1,000,000. This preferred stock, at our request, was transferred to our financial advisor and to two companies affiliated with two of our directors. 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.
We continued to pursue new equity capital during 2005, culminating in the sale of $42,000,000 in newly issued preferred stock. 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. In addition, our subsidiary, GulfWest Oil & Gas Company (GOGC) issued, in a private placement, 2,000 shares of its 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 debt and other liabilities and for general corporate purposes. See note 5.
The Series G Preferred Stock bears a coupon of 8% per year. The Series G Preferred Stock has an aggregate liquidation preference of $40.5 million, 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 vote on an as-converted basis with the Common Stockholders and, as a class, to nominate and elect a majority of the members of the Board of Directors of GulfWest. The Series G Preferred Stock is senior in liquidation preference to all of our capital stock.
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 will 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 Convertible Preferred Stock has a liquidation preference of $500 per share and is required to be paid a dividend of 40 shares of Common Stock per share per year. In addition, the Series H Convertible 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. The outstanding Series H Preferred Stock has an aggregate liquidation preference of $3.350 million and is senior to all of our capital stock other than Series G Preferred Stock.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 and junior to our Series G Preferred Stock and Series H Preferred Stock.
Note 3. Cost of Oil and Gas Properties
The following tables set forth certain information with respect to our oil and gas producing activities for the periods presented:
Capitalized Costs Relating to Oil and Gas Producing Activities:
Results of Operations for Oil and Gas Producing Activities:
The following table shows oil and gas property dispositions:
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.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Cost of Oil and Gas Properties - continued
A reconciliation of our asset retirement obligation liability is as follows:
Note 4. Accrued Expenses
Accrued expenses consisted of the following:
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Notes Payable and Long-Term Debt
Notes payable is as follows:
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Notes Payable and Long-Term Debt
Notes payable is as follows - continued:
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Notes Payable and Long-Term Debt
Long-term debt is as follows - continued:
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity
All classes of preferred shareholders have liquidation preference over common shareholders of $500 per preferred share, plus accrued dividends. Dividends in arrears at December 31, 2004 were $608,087 (Series A $244,147; Series E $347,409; Series F $16,531).
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock Options - -------------
We maintain a 1994 Stock Option and Compensation Plan (the "1994 Plan"), which terminated on February 11, 2004. There are options to purchase 424,000 shares of Common Stock still outstanding and exercisable under the 1994 Plan. Effective July 15, 2004, we implemented our 2004 Stock Option and Compensation Plan (the "2004 Plan"). There are options to purchase 1,525,000 shares of Common Stock outstanding under the 2004 Plan. Following is a schedule by year of the activity related to stock options, including weighted-average ("WTD AVG") exercise prices of options in each category.
Note 6. Stockholders' Equity - continued
Options to purchase 1,474,000 shares of Common Stock were exercisable at December 31, 2004. Following is a schedule by year and by exercise price of the expiration of our stock options issued as of December 31, 2004:
281,000 of the options issued are subject to variable award accounting treatment. As a result, we accrued $129,260 as compensation expense in 2004.
Stock Warrants
We have issued a significant number of stock warrants for a variety of reasons, including compensation to employees, additional inducements to purchase our common or preferred stock, inducements related to the issuance of debt and for payment of goods and services. Following is a schedule by year of the activity related to stock warrants, including weighted-average exercise prices of warrants in each category:
Included in the "warrants issued" and "warrants exercised/expired" columns in 2002 were 270,000 warrants whose price was reduced in 2002 to $.75.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Stockholders' Equity - continued
Following is a schedule by year and by exercise price of the expiration of our stock warrants issued as of December 31, 2004:
Warrants outstanding to our officers, directors and employees at December 31, 2004 and 2003 were approximately 1,515,000 and 1,515,000, respectively. The exercise prices on these warrants range from $.75 to $.875 and expire on various dates through 2006.
Note 7. Income (Loss) Per Common Share
The following is a reconciliation of the numerators and denominators used in computing income (loss) per share:
Potential dilutive securities (stock options, stock warrants and convertible preferred stock) in 2003 and 2002 have not been considered since we reported a net loss and, accordingly, their effects would be antidilutive.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 8. Related Party Transactions
As described in "Our Company - Financial Recapitalization" OCM GW Holdings purchased 81,000 shares of Series G Preferred Stock and 2,000 shares of Series A Preferred Stock for $42 million. Skardon F. Baker, a director, is an employee of and B. James Ford, also a director is a managing director of Oaktree Capital Management, LLC, the ultimate parent of OCM GW Holdings.
In connection with our April 2004 financing, J. Virgil Waggoner, a director, and Star-Tex Trading Co., an entity managed by John Loehr, an officer at the time and currently a director, purchased 3,000 shares and 200 shares, respectively, of Series A Preferred Stock at a price of $500 per share. Both Mr. Waggoner and Star-Tex, in connection with the February 2005 offering, elected to exchange those shares for an equal number of shares of Series H Preferred Stock.
On October 23, 1995, we sold $25,000 each of 9% promissory notes in a private offering to two trusts, the trustee of whom is John E. Loehr, an officer at the time of the transaction and currently a director. The balance of the notes plus accrued interest thereon at February 28, 2005 was $87,855. The note was paid off in connection with the February 2005 offering.
In June, 1999, we issued a promissory note with interest at 8.5% to Mr. Marshall A. Smith III, an officer and director at the time, in the amount of $124,083 for accrued compensation. At February 28, 2005, the note had a balance and accrued and unpaid interest of $99,360 and was being paid in monthly installments of approximately $1,500 per month. The note was paid off in connection with the February 2005 offering.
On November 6, 2002, Mr. J. Virgil Waggoner, a director, provided us a loan in the initial amount of $1,200,000, which was subsequently increased to a total of $1,500,000, which was outstanding at February 28, 2005. We issued Mr. Waggoner a promissory note with interest at the prime rate (prime rate 4.0% at May 26, 2004), secured by common stock of our wholly-owned subsidiary, DutchWest Oil Company. Mr. Waggoner also received warrants to purchase 625,000 shares of our common stock at an exercise price of $.75 per share. The note with accrued interest was paid off in connection with the February 2005 offering, for a total payment amount of $1,727,655.
On April 26, 2001, we obtained a line of credit of up to $2,500,000 from a bank for which two directors, Mr. J. Virgil Waggoner and Mr. Marshall A. Smith, were guarantors. On April 3, 2002, the balance of the line of credit was retired and a new line of credit of up to $3,000,000 was obtained from the bank for which Mr. Waggoner and Mr. Smith were guarantors. The line of credit was paid off in connection with the February 2005 offering.
On March 5, 2004, we entered into an Option Agreement for the Purchase of Oil and Gas Leases (the "Addison Agreement") with W. L. Addison Investments L.L.C., a private company owned by Mr. J. Virgil Waggoner and Mr. John E. Loehr, two of our directors ("Addison"). Under the Addison Agreement, Addison agreed to pay Summit, on our behalf, the non-recouped and outstanding advanced funds amounting to $1,200,000, thereby retiring the Summit Agreement except for certain surviving obligations with respect to areas of mutual interest and lease bank agreements. For consideration of such payment, Addison acquired certain oil and gas leases and wellbores from Summit but agreed to grant us a 180-day redemption option (which was extended by mutual consent) to purchase the same for $1,200,000, plus interest at the prime rate plus 2%. We tendered Addison a promissory note in the amount of $600,000, with interest at the prime rate plus 2%, to substitute for an account payable to Summit, pursuant to the Summit Agreement, in the same amount. The note would be considered paid in full if we exercised the redemption option and paid the $1,200,000, plus interest. Summit retained the right to participate up to a 25% working interest in the drilling of any wells on the leases acquired by Addison. In the event we exercised the redemption option, Addison could have, at its sole option, retained up to a 25% working interest in the leases. The Addison Agreement was extended on July 15, 2004. We exercised the redemption option and Addison received $1,275,353 at the closing of the February 2005 offering and waived its rights under the agreement to a working interest under the leases.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As part of the April 2004 refinancing, the former lender agreed to return all 2,000 shares of our Series F Preferred Stock held by it. Rather than receive the shares as treasury shares (which would have meant cancellation of the series) at our request the former lender transferred 400 of the shares to ST Advisory Corp., an entity owned by John Loehr, our former CEO and a current director, 400 of the shares to a financial advisor to the Company, and 200 of the shares to Thomas R. Kaetzer, our President and Director at that time and 1,000 shares to Intermarket Management LLC, an entity partially owned by M. Scott Manolis, one of our directors at that time. These transfers were to compensate the financial advisor and Mr. Loehr, Kaetzer and Manolis for service to the Company. On September 29, 2004, the financial advisor with 400 shares transferred 140 shares to three non-management transferees.
$675,203 of the proceeds from the February 2005 offering went towards the payment of accrued and unpaid dividends of the preferred stock. J. Virgil Waggoner received $469,603 as a result. On December 22, 2004, ST Advisory Corp, Intermarket Management LLC and Mr. Kaetzer converted their Series F preferred shares into common stock. At the closing of the February 2005 offering they were paid their proportionate share of accrued dividends due on the 2000 shares, which totaled $17,167.
As part of the closing of the February 2005 offering, the investor and the Company agreed to pay certain legal, accounting and other due diligence costs and, also certain closing fees which totaled approximately $3.75 million. Of this certain related parties received the following fees: OCWGW $1,000,000; Intermarket Management LLC $500,000; Mr. Allan D. Keel $300,000 (which was used to invest in the subject offering).
In January 2005, Allan D. Keel, our current president and chief executive officer, and another individual lent an aggregate of $200,000 to the Company, which was repaid in full out of the proceeds of the February 2005 offering. $120,000 of that loan was attributable to Mr. Keel. In addition, Mr. Keel received warrants to purchase 30,000 shares of Common Stock at $0.01 share in connection with this transaction.
Note 9. Income Taxes
The components of the net deferred federal income tax assets (liabilities) recognized in our consolidated balance sheets were as follows:
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 9. Income Taxes - continued
At December 31, 2003 we had recorded a valuation allowance for the entire balance of our deferred tax asset, due the uncertainty of our ability to ever realize that benefit. Due to a change in circumstances described below, we made an adjustment to the valuation allowance in 2004 resulting from a change in judgment about the realizability of the net operating loss carryforwards in future years. On February 28, 2005 we sold $ 42,000,000 in newly issued preferred stock. We realized approximately $38,000,000, net of offering expenses (See Note 2). We used the proceeds to retire substantially all of our notes payable, paid substantial amounts of accounts payable and accrued expenses and retained approximately $2,000,000 for working capital. After these transactions we had approximately $190,000 in notes payable remaining. Of the retired notes $20,094,000 bore interest at the prime rate plus 11%. As a result of these transactions we believe we will generate enough future taxable income to fully realize all of our available net operating loss carryforwards other than those limited by Internal Revenue Code Section 382.
We had no income tax provision in 2003 and 2002. The provision for 2004 consists of the following:
----------------- Current tax $ 118,255 Deferred tax 1,252,395 Re-evaluation of beginning valuation allowance (4,693,201) ----------------- Current income tax provision $ (3,322,551) =================
The following table summarizes the difference between the actual tax provision and the amounts obtained by applying the statutory tax rate of 38% to the income (loss) before income taxes for the year ended December 31, 2004 and 34% for the years ended December 31, 2003 and 2002.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2004 we had net operating loss carryforwards of approximately $12,800,000, which are available to reduce future taxable income and the related income tax liability. We expect we will not be able to utilize carryforwards of approximately $6,600,000 due to the limitations of Internal Revenue Code Section 382. The net operating loss carryforward expires at various dates through 2023.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 10. Commitments and Contingencies
Oil and Gas Hedging Activities
We entered into an agreement with an energy lender commencing in May, 2000, to hedge a portion of our oil and gas sales for the period of May, 2000 through April, 2004. The agreement called for initial volumes of 7,900 barrels of oil and 52,400 Mmbtu of gas per month, declining monthly thereafter. We entered into an additional agreement with the energy lender, commencing September, 2001, to hedge an additional portion of our oil and gas sales for the periods of September, 2001 through July, 2004 and September, 2001 through December 2003, respectively. The agreement called for initial volumes of 15,000 barrels of oil and 50,000 Mmbtu of gas per month, declining monthly thereafter. These agreements were terminated in April 2004 with the refinancing of the related debt. We entered into a second agreement, as a result of refinancing the debt, commencing May 2004, to hedge a portion of our oil and gas sales for the period of May 2004 through October 2005. The agreement calls for 10,000 barrels of oil and 60,000 Mmbtu of gas per month. As a result of these agreements, we realized a reduction in revenues of $1,841,209 , $1,496,303 and $368,776 for the twelve - month periods ended December 31, 2004, 2003 and 2002, respectively, which is included in oil and gas sales.
Lease Obligations
We lease office space at one location under a sixty-four (64) month lease, which commenced December 1, 2001 and was amended May 30, 2002 after expansion. Annual commitments under the lease are: 2005 - $132,979, 2006 - $135,323 and 2007 - $33,977. Total rent expense for the years ended December 31, 2004, 2003 and 2002 were approximately $142,500, $134,500 and $91,000, respectively.
Litigation
From time to time, we are involved in litigation arising out of our operations or from disputes with vendors in the normal course of business. As of March 29, 2005, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material effect on our consolidated financial statements.
Note 11. Oil and Gas Reserves Information (Unaudited)
The estimates of proved oil and gas reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations over prices and costs existing at year end except by contractual arrangements.
We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Our policy is to amortize capitalized oil and gas costs on the unit of production method, based upon these reserve estimates. It is reasonably possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, that the estimates of future cash inflows, future gross revenues, the amount of oil and gas reserves, the remaining estimated lives of the oil and gas properties, or any combination of the above may be increased or reduced in the near term. If reduced, the carrying amount of capitalized oil and gas properties may be reduced materially in the near term.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 11. Oil and Gas Reserves Information (Unaudited) - continued
The following unaudited table sets forth proved oil and gas reserves, all within the United States, at December 31, 2004, 2003, and 2002, together with the changes therein.
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 11. Oil and Gas Reserves Information (Unaudited) - continued
STANDARDIZED MEASURE:
Standardized measure of discounted future net cash flows relating to proved reserves:
The following reconciles the change in the standardized measure of discounted future net cash flows:
GULFWEST ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 12. Quarterly Results (Unaudited)
Summary data relating to the results of operations for each quarter for the years ended December 31, 2004 and 2003 follows:
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON THE FINANCIAL STATEMENT SCHEDULE
To the Stockholders and Board of Directors GULFWEST ENERGY INC.
Our report on the consolidated financial statements of GulfWest Energy Inc. and Subsidiaries as of December 31, 2004 and 2003 and for each of the three years in the period ended December 31, 2004, is included on page. In connection with our audit of such consolidated financial statements, we have also audited the related financial statement schedule for the years ended December 31, 2004, 2003 and 2002 on page.
In our opinion, the financial statement schedule referred to above, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein.
/s/ WEAVER AND TIDWELL, L.L.P. - -------------------------------- WEAVER AND TIDWELL, L.L.P.
Dallas, Texas March 29, 2005