UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 or [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ____ to ____. Commission file number 1-12108. GulfWest Energy Inc. (Exact name of registrant as specified in its charter) Texas 87-0444770 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.) 480 N. Sam Houston Parkway East, Suite 300 Houston, Texas 77060 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (281) 820-1919. Securities registered pursuant to Section 12(b) of the Act: Title of Each Class ------------------- Class A Common Stock, par value of $.001 per share Securities registered pursuant to Section 12(g) of the Act: Title of Each Class ------------------- Class A Common Stock, par value of $.001 per share Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or informational statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of voting stock of the Registrant held by non-affiliates (excluding voting shares held by officers and directors) was $3,968,219 on April 4, 2002. Indicate the number of shares outstanding of each of the Registrant's classes of common stock: Class A Common Stock $.001 par value: 18,492,451 shares on April 4, 2002. DOCUMENTS INCORPORATED BY REFERENCE: The registrant's definitive Proxy Statement pertaining to the 2002 Annual Meeting of Shareholders (the "Proxy Statement") and filed or to be filed not later than 120 days after the end of the fiscal year pursuant to Regulation 14A is incorporated herein by reference into Part III. <PAGE> PART I ITEM 1. Business. Our Business. We are primarily engaged in the acquisition, development, exploitation and production of crude oil and natural gas. Our focus is on increasing production from our existing properties through further exploitation, development and exploration, and on acquiring additional interests in crude oil and natural gas properties. Since we made our first significant acquisition in 1993, we have substantially increased our ownership in producing properties and the value of our crude oil and natural gas reserves through a combination of acquisitions and the further exploitation and development of our properties. At December 31, 2001, our part of the estimated proved reserves these properties contain was approximately 5.9 million barrels (MBbl) of oil and 39.3 billion cubic feet (Bcf) of natural gas with a Present Value discounted 10% (PV-10) of $56.5 million. At present, all of our properties are located on land in Texas, Colorado, Louisiana and Oklahoma, except for the property on Grand Lake, Louisiana. In the future, we plan to expand by acquiring additional properties in those areas, and in similar properties located in other areas of the United States. Our gross revenues are derived from the following sources: 1. Oil and gas sales that are proceeds from the sale of crude oil and natural gas production to midstream purchasers; 2. Operating overhead and other income that consists of earnings from operating crude oil and natural gas properties for other working interest owners, and marketing and transporting natural gas. This also includes earnings from other miscellaneous activities. 3. Well servicing revenues that are earnings from the operation of well servicing equipment under contract to other operators. Our operations are considered to fall within a single industry segment, which is the acquisition, development, production and servicing of crude oil and natural gas properties. See Item 7. " Management's Discussion and Analysis of Financial Condition and Results of Operations." Certain industry terms are italicized and defined in the Glossary beginning on page 28. Our common stock is traded over-the-counter (OTC) under the symbol "GULF". Our Company. We were formed as a corporation under the laws of the State of Utah in 1987 as Gallup Acquisitions, Inc., and subsequently changed our name to First Preference Fund, Inc. and then to GulfWest Energy, Inc. We became a Texas corporation by a merger effected in July 1992, in which our name became GulfWest Oil Company. On May 21, 2001, we changed our name to GulfWest Energy Inc. Our principal office is located at 480 North Sam Houston Parkway East, Suite 300, Houston, Texas 77060 and our telephone number is (281) 820-1919. 1 <PAGE> GulfWest Energy Inc. has nine wholly owned subsidiaries: 1. GulfWest Oil & Gas Company, a Texas corporation, was organized February 18, 1999 and is the owner of record of interests in certain crude oil and natural gas properties located in Colorado and Texas. 2. SETEX Oil and Gas Company, a Texas corporation, was organized August 11, 1998 and is the operator of crude oil and natural gas properties in which we own the majority working interest. 3. LTW Pipeline Co., a Texas corporation, was organized April 19, 1999, is the owner and operator of certain natural gas gathering systems and pipelines that we own, and markets the natural gas produced from our properties. 4. RigWest Well Service, Inc., a Texas corporation, was organized September 5, 1996 and operates well servicing equipment for us and under contract for other operators. 5. Southeast Texas Oil and Gas Company, L.L.C., a Texas company, was acquired by us on September 1, 1998 and is the owner of record of interests in certain crude oil and natural gas properties located in three Texas counties. 6. DutchWest Oil Company, a Texas corporation, was organized July 28, 1997 and is the owner of record of interests in certain crude oil and natural gas properties located along the Gulf Coast of Texas. 7. GulfWest Development Company, a Texas corporation, was organized November 9, 2000 and is the owner of record of interests in certain crude oil and natural gas properties located in Texas, Oklahoma and Mississippi. 8. GulfWest Texas Company, a Texas corporation, was organized Septem- ber 23, 1996 and was the owner of interests in certain crude oil and natural gas properties located in the Vaughn Field, Crockett County, Texas. Effective April 1, 2000, these properties were assigned to GulfWest Oil & Gas Company to facilitate financing. 9. GulfWest Oil & Gas Company (Louisiana) LLC, a Louisiana company, was formed July 31, 2001 and is the owner of record of interests in certain crude oil and natural gas properties in Louisiana. Our Business Strategy. We have pursued a business strategy of acquiring interests in crude oil and natural gas producing properties where production and reserves can be increased through engineering and development activities. Such activities include workovers, development drilling, recompletions, replacement or addition of equipment and waterflood or other secondary recovery techniques. We have expanded our business plan to include an increased but controlled emphasis on development drilling for additional crude oil and natural gas reserves. Key elements of our business strategy include: Continued Acquisition Program. We acquired properties in four crude oil and natural gas fields in Texas and Louisiana in the year 2001. We intend to continue to aggressively pursue interests in crude oil and natural gas properties (i) held by small, under-capitalized operators and (ii) being divested by larger independent and major oil and gas companies. 3 <PAGE> Development and Exploitation of Existing Properties. We intend to increase the development of properties in which we currently own interest by expanding our engineering and geological field studies. Our intent is to increase crude oil and natural gas production and reserves of our existing assets through relatively low-risk development activities, such as workovers, recompletions, horizontal drilling from existing wellbores and infield drilling, as well as the more efficient use of production facilities and the expansion of existing waterflood operations. Significant Operating Control. Currently, we are the operator of all the wells, except one, in which we own working interests. This operating control enables us to better manage the nature, timing and costs of development of such wells, and the marketing of the resulting production. Ownership of Workover Rigs. We currently own four workover service rigs and one swabbing unit that we operate for our own account and under contract for other parties. By owning and operating this equipment, we are better able to control costs, quality of operations and availability of equipment and services. We intend to purchase additional service rigs as needed to accommodate our acquisition and development programs. Greater Natural Gas Ownership. At December 31, 2001, our reserves were comprised of 47% crude oil and 53% natural gas. We will continue to expand our role in the domestic natural gas industry by (i) acquiring additional interests in natural gas properties, (ii) increasing the production and reserve base of our existing natural gas properties, and (iii) acquiring ownership of more natural gas gathering systems and pipelines. We are presently focusing our workover and development efforts on both crude oil and natural gas reserves to take advantage of the higher prices of both commodities. We are also seeking to expand our ownership of gas gathering systems and pipelines located in our main field areas. Our goal is to have greater control of our natural gas transportation and marketing, and an expanded role in the transportation of natural gas produced by other parties in our area of operations. Expanded Exploration and Exploitation Role. Historically, we have not drilled exploratory wells due to the cost and risk associated with drilling prospective locations. However, since the end of 1998, we have acquired producing properties that have included significant acreage for prospective oil and gas exploration. These include producing wells and acreage in Crockett, Grimes, Hardin, Jim Wells, Kimble, Madison, Palo Pinto, Refugio, Sutton, Wharton and Zavala, Counties, Texas; Adams, Arapaho, Elbert and Weld Counties, Colorado; Creek County, Oklahoma; and, Cameron Parish, Louisiana. These acquisitions have added existing natural gas and crude oil production to our asset base and, as importantly, have provided us with immediate geological databases for drilling opportunities. We have expanded our evaluation efforts in these fields and intend to increase our development of reserves, not only through workovers of existing wells, but by drilling additional wells. Our Employees. At April 4, 2002, we had 64 full time salaried and contract employees, of whom 49 were field personnel. Our Executive Officers. See Item 10 of this report, which information is incorporated herein by reference. 4 <PAGE> ITEM 2. Our Properties. At December 31, 2001, we owned an average 92% working interest in 290 gross wells (268 net wells). Gross wells are the total wells in which we own a working interest. Net wells are the sum of the fractional working interests we own in gross wells. Our part of the estimated proved reserves these properties contain was approximately 5.9 million barrels (MBbl) of oil and 39.3 billion cubic feet (Bcf) of natural gas. Substantially all of our properties are located in Texas, Colorado, Louisiana and Oklahoma. Proved Reserves. The following table reflects our estimated proved reserves at December 31 for each of the preceding three years. 2001 2000 1999 ---- ---- ---- Crude Oil (MBbl) Developed 3,940 2,884 1,570 Undeveloped 1,932 1,692 1,745 ----- ----- ----- Total 5,872 4,576 3,315 ===== ===== ===== Natural Gas (MMcf) Developed 21,204 15,142 9,317 Undeveloped 18,054 9,670 9,870 ------ ----- ----- Total 39,258 24,812 19,187 ====== ====== ====== Total (MBOE) 12,415 8,711 6,513 ====== ====== ====== (a) Approximately 60% of our total proved reserves were classified as proved developed at December 31, 2001. (b) Barrel of Oil Equivalent (BOE) is based on a ratio of 6,000 cubic feet of natural gas for each barrel of oil. 5 <PAGE> Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth as of December 31 for each of the preceding three years, the estimated future net cash flow from and standardized measure of discounted future net cash flows of our proved reserves, which were prepared in accordance with the rules and regulations of the SEC. Future net cash flow represents future gross cash flow from the production and sale of proved reserves, net of crude oil and natural gas production costs (including production taxes, ad valorem taxes and operating expenses) and future development costs. The calculations used to produce the figures in this table are based on current cost and price factors at December 31 for each year. We cannot assure you that the proved reserves will all be developed within the periods used in the calculations or that prices and costs will remain constant. 2001 2000 1999 -------------------- -------------------- -------------------- Future cash inflows $ 199,162,921 $ 318,504,931 $ 119,006,567 Future production and development costs- Production 77,526,278 97,465,972 42,544,454 Development 23,610,596 13,400,359 9,903,729 -------------------- -------------------- -------------------- Future net cash flows before income taxes 98,026,047 207,638,600 66,558,384 Future income taxes (13,281,358) (56,466,527) (11,847,076) -------------------- -------------------- -------------------- Future net cash flows after income taxes 84,744,689 151,172,073 54,711,308 10% annual discount for estimated timing of cash flows (35,895,306) (60,790,946) (23,755,909) -------------------- -------------------- ------------------- Standardized measure of discounted Future net cash flows(1) $ 48,849,383 $ 90,381,127 $ 30,955,399 ================== ================= =================== (1) The average prices of our proved reserves were $17.67 per Bbl and $2.43 per Mcf, $23.81 per Bbl and $8.45 per Mcf, and $22.80 per Bbl and $2.19 per Mcf at December 31, 2001, 2000 and 1999, respectively. Significant Properties. Summary information on our properties with proved reserves is set forth below as of December 31, 2001. Productive Wells Proved Reserves (1) Present ------------------------------- ------------------------------------------ -------- Gross Net Value (1) --------- Productive Productive Crude Natural Wells Wells Oil Gas Total Amount --------- ----------- --- --- ----- ------ (MBbl) (MMcf) (MBOE) ($M) Texas 207 199.26 3,468 19,183 6,665 $ 29,132 Colorado 39 26.57 480 9,185 2,011 5,949 Oklahoma 27 27.00 68 251 110 487 Louisiana 16 15.08 1,839 10,639 3,612 20,819 Mississippi 1 .38 17 - 17 112 --------- --------- ----- ------ ------ --------- Total 290 268.29 5,872 39,258 12,415 $ 56,499 ========= ========= ===== ====== ====== ========= (1) The average prices of our proved reserves were $17.67 per Bbl and $2.43 per Mcf at December 31, 2001. 6 <PAGE> All information set forth herein relating to our proved reserves, estimated future net cash flows and present values is taken from reports prepared by Pressler Petroleum Consultants, independent petroleum engineers. The estimates of these engineers were based upon their review of production histories and other geological, economic, ownership and engineering data provided by and relating to us. No reports on our reserves have been filed with any federal agency. In accordance with the SEC's guidelines, our estimates of proved reserves and the future net revenues from which present values are derived are made using year end crude oil and natural gas sales prices held constant throughout the life of the properties (except to the extent a contract specifically provides otherwise). Operating costs, development costs and certain production-related taxes were deducted in arriving at estimated future net revenues, but such costs do not include debt service, general and administrative expenses and income taxes. There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their values, including many factors beyond our control. The reserve data set forth in this report are based upon estimates. Reservoir engineering is a subjective process, which involves estimating the sizes of underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation of that data, and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development, exploitation and exploration activities, prevailing crude oil and natural gas prices, operating costs and other factors. Such revisions may be material. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. We cannot assure you that the estimates contained in this report are accurate predictions of our crude oil and natural gas reserves or their values. Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than upon actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in potentially substantial variations in the estimated reserves. 7 <PAGE> Production, Revenue and Price History. The following table sets forth information (associated with our proved reserves) regarding production volumes of crude oil and natural gas, revenues and expenses attributable to such production (all net to our interests) and certain price and cost information for the years ended December 31, 2001 2000 and 1999. 2001 2000 1999 ---------------- ---------------- ---------------- Production Oil (Bbl) 294,276 165,031 79,661 Natural gas (Mcf) 1,594,899 1,111,639 467,350 Total (BOE) 560,092 350,304 157,553 Revenue Oil production $ 6,690,338 $ 4,320,943 $ 1,565,200 Natural gas production 5,735,765 4,124,989 968,104 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- Total $ 12,426,103 $ 8,445,932 $ 2,533,304 Operating Expenses $ 5,155,500 $ 3,377,583 $ 1,399,710 Production Data Average sales price Per barrel of oil $ 22.73 $ 26.18 $ 19.65 Per Mcf of natural gas 3.60 3.71 2.07 Per BOE 22.19 24.11 16.08 Average expenses per BOE Lease operating 9.20 9.64 8.88 Depreciation, depletion and amortization 4.45 3.83 4.47 General and administrative $ 3.05 $ 4.53 $ 12.59 Productive Wells at December 31, 2001: The following table shows the number of productive wells we own by location: Gross Net Gross Net Oil Wells Oil Wells Gas Wells Gas Wells ------------ ------------ ------------- ------------ Texas 118 120.11 89 79.15 Colorado 18 11.42 21 15.15 Oklahoma 27 27.00 - - Louisiana 14 13.08 2 2.00 Mississippi 1 .38 - - ------------ ------------ ------------- ------------ Total 178 171.99 112 96.30 ============ ============ ============= ============ 8 <PAGE> Developed Acreage at December 31, 2001. The following table shows the developed acreage that we own, by location, which is acreage spaced or assigned to productive wells. Gross acres are the total acres in which we own a working interest. Net acres are the sum of the fractional working interests we own in gross acres. Gross Acres Net Acres ----------- ---------- Texas 19,440 14,936 Colorado 5,000 2,700 Louisiana 1,560 1,560 Oklahoma 1,200 912 ------- ------- Total 27,200 20,108 ======= ======= Undeveloped Acreage at December 31, 2001. The following table shows the undeveloped acreage that we own, by location. Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas. Gross Acres Net Acres ----------- ---------- Texas 23,900 18,479 Louisiana 630 630 Colorado 20,000 14,175 ------ ------ Total 44,530 33,284 ====== ====== Drilling Results. We have not drilled any exploratory wells in the past three years. We drilled three wells in 2001 and six in 2000, all of which were development wells and are currently productive. These development wells included six horizontal wells drilled by sidetracking from existing wellbores in the Madisonville Field, Texas, two new wells drilled on our Colorado acreage; and one well that was deepened in our Leona River Field, Texas. We did not drill any wells in 1999. 9 <PAGE> Risk Factors. Our success depends heavily upon our ability to market our crude oil and natural gas production at favorable prices. In recent decades, there have been both periods of worldwide overproduction and underproduction of crude oil and natural gas, and periods of increased and relaxed energy conservation efforts. Such conditions have resulted in excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. At other times, there has been short supply of, and increased demand for, crude oil and, to a lesser extent, natural gas. These changes have resulted in dramatic price fluctuations. The degree to which we are leveraged could possibly have important consequences to our shareholders, including the following: (i) Our indebtedness, acquisitions, working capital, capital expenditures or other purposes may be impaired; (ii) Funds available for our operations and general corporate purposes or for capital expenditures will be reduced as a result of the dedication of a substantial portion of our consolidated cash flow from operations to the payment of the principal and interest on our indebtedness; (iii)We may be more highly leveraged than certain of our competitors, which may place us at a competitive disadvantage; (iv) The agreements governing our long-term indebtedness and bank loans may contain restrictive financial and operating covenants; (v) An event of default (not cured or waived) under financial and operating covenants contained in our debt instruments could occur and have a material adverse effect; (vi) Certain of the borrowings under our debt agreements have floating rates of interest, which causes us to be vulnerable to increases in interest rates; and, (vii)Our substantial degree of leverage could make us more vulnerable to a downturn in general economic conditions. Our ability to make principal and interest payments under long-term indebtedness and bank loans will be dependent upon our future performance, which is subject to financial, economic and other factors, some of which are beyond our control. We cannot assure you that our current level of operating results will continue or improve. We believe that we will need to access capital markets in the future in order to provide the funds necessary to repay a significant portion of our indebtedness. We cannot assure you that any such refinancing will be possible or that we can obtain any additional financing, particularly in view of our anticipated high levels of debt. If no such refinancing or additional financing were available, we could default on our debt obligations. 10 <PAGE> We were profitable for the year 2001, however we have incurred net losses in the past and there can be no assurance that we will continue to be profitable in the future. Our future operating results may fluctuate significantly depending upon a number of factors, including industry conditions, prices of crude oil and natural gas, rates of production, timing of capital expenditures and drilling success. These variables could have a material adverse effect on our business, financial condition, results of operations and the market price of our common stock. Estimates of crude oil and natural gas reserves depend on many assumptions that may turn our to be inaccurate. Estimates of our proved reserves for crude oil and natural gas and the estimated future net revenues from the production of such reserves rely upon various assumptions, including assumptions as to crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating crude oil and natural gas reserves is complex and imprecise. Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves may vary substantially from the estimates we obtain from reserve engineers. Any significant variance in these assumptions could materially affect the estimated quantities and present value of reserves we have set forth. In addition, our proved reserves may be subject to downward or upward revision due to factors that are beyond our control, such as production history, results of future exploration and development, prevailing crude oil and natural gas prices and other factors. Approximately 40% of our total estimated proved reserves at December 31, 2001 were proved undeveloped reserves, which are by their nature less certain. Recovery of such reserves requires significant capital expenditures and successful drilling operations. The reserve data set forth in the reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves. Although cost and reserve estimates attributable to our crude oil and natural gas reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate, that development will occur as scheduled or that the results of such development will be as estimated. You should not interpret the present value referred to in this report or documents incorporated herein by reference as the current market value of our estimated crude oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. The estimates of our proved reserves and the future net revenues from which the present value of our properties is derived were calculated based on the actual prices of our various properties on a property-by-property basis at December 31, 2001. The average prices of all properties were $17.67 per barrel of oil and $2.43 per thousand cubic feet (Mcf) of natural gas at that date. Actual future net cash flows will also be affected by increases or decreases in consumption by crude oil and natural gas purchasers and changes in governmental regulations or taxation. The timing of both the production and the incurring of expenses in connection with the development and production of crude oil and natural gas properties affect the timing of actual future net cash flows from proved reserves. In addition, the 10% discount factor, which is required by 11 <PAGE> the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the accuracy of the 10% discount factor. Except to the extent that we acquire properties containing proved reserves or conduct successful development or exploitation activities, our proved reserves will decline as they are produced. In general, the volume of production from crude oil and natural gas properties declines as reserves are depleted. Our future crude oil and natural gas production is highly dependent upon our success in finding or acquiring additional reserves. The business of acquiring, enhancing or developing reserves requires considerable capital. Our ability to make the necessary capital investment to maintain or expand our asset base of crude oil and natural gas reserves could be impaired to the extent that cash flow from operations is reduced and external sources of capital become limited or unavailable. In addition, we cannot be sure that our future acquisition and development activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Crude oil and natural gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include (i) the possibility that no commercially productive oil or gas reservoirs will be encountered; and, (ii) that operations may be curtailed, delayed or canceled due to title problems, weather conditions, governmental requirements, mechanical difficulties, or delays in the delivery of drilling rigs and other equipment that may limit our ability to develop, produce and market our reserves. We cannot assure you that new wells we drill will be productive or that we will recover all or any portion of our investment in such new wells. Drilling for crude oil and natural gas may not be profitable. Any wells that we drill may be dry wells or wells that are not sufficiently productive to be profitable after drilling. Such wells will have a negative impact on our profitability. In addition, our properties may be susceptible to drainage from production by other operators on adjacent properties. Our industry experiences numerous operating risks that could cause us to suffer substantial losses. Such risks include fire, explosions, blowouts, pipe failure and environmental hazards, such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. We could also suffer losses due to personnel injury or loss of life; severe damage to or destruction of property; or environmental damage that could result in clean-up responsibilities, regulatory investigation, penalties or suspension of our operations. In accordance with customary industry practice, we maintain insurance policies against some, but not all, of the risks described above. Our insurance policies may not adequately protect us against loss or liability. There is no guarantee that insurance policies that protect us against the many risks we face will continue to be available at justifiable premium levels. As owners and operators of crude oil and natural gas properties, we may be liable under federal, state and local environmental regulations for activities involving water pollution, hazardous waste transport, storage, disposal or other activities. 12 <PAGE> Our past growth has been attributable to acquisitions of producing crude oil and natural gas properties with proved reserves. There are risks involved with such acquisitions. The successful acquisition of properties requires an assessment of recoverable reserves, future crude oil and natural gas prices, operating costs, potential environmental and other liabilities, and other factors beyond our control. Such assessments are necessarily inexact and their accuracy uncertain. In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Such a review, however, will not reveal all existing or potential problems, nor will it permit us, as the buyer, to become sufficiently familiar with the properties to fully assess their capabilities or deficiencies. We may not inspect every well and, even when an inspection is undertaken, structural and environmental problems may not necessarily be observable. When we acquire properties, in most cases, we are not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. We generally acquire interests in properties on an "as is" basis with limited remedies for breaches of representations and warranties. In those circumstances in which we have contractual indemnification rights for pre-closing liabilities, we cannot assure you that the seller will be able to fulfill its contractual obligations. In addition, the competition to acquire producing crude oil and natural gas properties is intense and many of our larger competitors have financial and other resources substantially greater than ours. We cannot assure you that we will be able to acquire producing crude oil and natural gas properties that have economically recoverable reserves for acceptable prices. We may acquire royalty, overriding royalty or working interests in properties that are less than the controlling interest. In such cases, it is likely that we will not operate, nor control the decisions affecting the operations, of such properties. We intend to limit such acquisitions to properties operated by competent parties with whom we have discussed their plans for operation of the properties. We will need additional financing in the future to continue to fund our developmental and exploitation activities. We have made and will continue to make substantial capital expenditures in our exploitation and development projects. We intend to finance these capital expenditures with cash flow from operations, existing financing arrangements or new financing. We cannot assure you that such additional financing will be available. If it is not available, our development and exploitation activities may have to be curtailed, which could adversely affect our business, financial condition and results of operations. The marketing of our natural gas production depends, in part, upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We could be adversely affected by changes in existing arrangements with transporters of our natural gas since we do not own most of the gathering systems and pipelines through which our natural gas is delivered to purchasers. Our ability to produce and market our natural gas could also be adversely affected by federal, state and local regulation of production and transportation. The crude oil and natural gas industry is highly competitive in all of its phases. Competition is particularly intense with respect to the acquisition of desirable producing properties, the acquisition of crude oil and natural gas prospects suitable for enhanced production efforts, and the hiring of 13 <PAGE> experienced personnel. Our competitors in crude oil and natural gas acquisition, development, and production include the major oil companies, in addition to numerous independent crude oil and natural gas companies, individual proprietors and drilling programs. Many of these competitors possess and employ financial and personnel resources substantially in excess of those which are available to us and may, therefore, be able to pay more for desirable producing properties and prospects and to define, evaluate, bid for, and purchase a greater number of producing properties and prospects than our financial or personnel resources will permit. Our ability to generate reserves in the future will be dependent on our ability to select and acquire suitable producing properties and prospects while competing with these companies. The domestic oil industry is extensively regulated at both the federal and state levels. Although we believe we are presently in compliance with all laws, rules and regulations, we cannot assure you that changes in such laws, rules or regulations, or the interpretation thereof, will not have a material adverse effect on our financial condition or the results of our operations. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on the industry. There are numerous federal and state agencies authorized to issue rules and regulations affecting the oil and gas industry. These rules and regulations are often difficult and costly to comply with and carry substantial penalties for noncompliance. State statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Most states also have statutes and regulations governing conservation matters, including the unitization or pooling of properties, and the establishment of maximum rates of production from wells. Some states have also enacted statutes prescribing price ceilings for natural gas sold within their states. Our industry is also subject to numerous laws and regulations governing plugging and abandonment of wells, discharge of materials into the environment and other matters relating to environmental protection. The heavy regulatory burden on the oil and gas industry increases the costs of our doing business as an oil and gas company, consequently affecting our profitability. Our board of directors is authorized, without further shareholder action, to issue preferred stock in one or more series and to designate the dividend rate, voting rights and other rights, preferences and restrictions of each such series. As of April 4, 2002, we had a total of 8,000 shares of our Series D Preferred Stock and 9,000 shares of our Series E Preferred Stock issued and outstanding, both par value $.01 and liquidation value $500 per share. The Series D and E Preferred Stock are senior to our common stock regarding liquidation. The holders of the preferred stock do not have voting rights or preemptive rights nor are they subject to the benefits of any retirement or sinking fund. The Series D Preferred Stock is not entitled to dividends, nor is it redeemable, however it is convertible to common stock at anytime following December 31, 2002, the third anniversary of the issue date. Thereafter, the holder may convert any or all of the shares of the Series D Preferred Stock to common stock. The total number of shares of common stock to be issued upon such conversion shall be 500,000. The Series E Preferred Stock is entitled to receive dividends at the rate of $12.50 per share per annum, payable quarterly. The Series E Preferred Stock is redeemable in whole or in part at any time, at our option, at a price of $500 per share, plus all accrued and undeclared or unpaid dividends; except that, after two years from the date of the original issuance and prior to redemption 14 <PAGE> of remaining shares by the Company, the holders of record shall be given a 60-day written notice of our intent to redeem and the opportunity to convert the Series E Preferred Stock to common stock. The conversion price for the Series E Preferred Stock shall be $2.00 per share of common stock. At April 4, 2002, none of the 9,000 outstanding shares of Series E Preferred Stock had been redeemed or converted. On a fully converted basis, the 9,000 shares of Series E Preferred Stock would convert to 2,250,000 shares of common stock. We do not pay dividends on our common stock. Our board of directors presently intends to retain all of our earnings for the expansion of our business, therefore we do not anticipate distributing cash dividends on our common stock in the foreseeable future. Any decision of our board of directors to pay cash dividends will depend upon our earnings, financial position, cash requirements and other factors. The holders of our common stock do not have cumulative voting rights, preemptive rights or rights to convert their common stock to other securities. We are authorized to issue 40,000,000 shares of common stock, $.001 par value per share. As of April 4, 2002, there were 18,492,451 shares of common stock issued and outstanding. Since the holders of our common stock do not have cumulative voting rights, the holder(s) of a majority of the shares of common stock present, in person or by proxy, will be able to elect all of the members of our board of directors. The holders of shares of our common stock do not have preemptive rights or rights to convert their common stock into other securities. At April 4, 2002, we had outstanding warrants and options for the purchase of 2,338,754 shares of common stock at prices ranging from $.75 to $6.00 per share, including employee stock options to purchase 1,032,000 shares at prices ranging from $.75 to $1.81 per share. If we issue additional shares, the existing shareholders' percentage ownership of the Company may be further diluted. Actual results may differ from forward-looking statements. We make forward-looking statements throughout this report. Whenever you read a statement that is not simply a statement of historical fact, such as when we describe what we "believe," "expect" or "anticipate" will occur, and other similar statements, you must remember that our expectations may not be correct, even though we believe they are reasonable. These forward-looking statements generally relate to our plans and objectives for future operations and are based upon our management's reasonable estimates of future results and trends. We do not guarantee that the transactions and events described will happen as described (or that they will happen at all). In connection with forward-looking statements, you should carefully review the factors set forth in this report under "Risk Factors." ITEM 3. Legal Proceedings. From time to time, we are involved in litigation relating to claims arising out of our operations or from disputes with vendors in the normal course of business. As of April 4, 2001, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us. ITEM 4. Submission of Matters to a Vote of Security Holders. We did not submit any matters to a vote of our security holders during the fourth quarter of the fiscal year ended December 31, 2001. 15 <PAGE> PART II ITEM 5. Market for Our Common Stock and Related Stockholder Matters. Our common stock is traded over-the-counter under the symbol "GULF". The high and low trading prices for the common stock for each quarter in 2001, 2000 and 1999 are set forth below. The trading prices represent prices between dealers, without retail mark-ups, mark-downs, or commissions, and may not necessarily represent actual transactions. High Low ---- --- 2001 ---- First Quarter $1.46 $.39 Second Quarter 1.01 .53 Third Quarter .96 .48 Fourth Quarter .72 .58 2000 ---- First Quarter 1.81 .75 Second Quarter 2.00 1.25 Third Quarter 1.63 1.13 Fourth Quarter 1.69 .88 1999 ---- First Quarter 2.63 1.88 Second Quarter 1.00 .38 Third Quarter .75 .38 Fourth Quarter .94 .63 We are authorized to issue 40,000,000 shares of Class A common stock, par value $.001 per share (the "common stock"). As of April 4, 2002, there were 18,492,451 shares of common stock issued and outstanding and held by approximately 580 beneficial owners. Our common stock is traded over-the-counter (OTC) under the symbol "GULF". Fidelity Transfer Company, 1800 South West Temple, Suite 301, Box 53, Salt Lake City, Utah 84115, (801) 484-7222 is the transfer agent for the common stock. Holders of common stock are entitled, among other things, to one vote per share on each matter submitted to a vote of shareholders and, in the event of liquidation, to share ratably in the distribution of assets remaining after payment of liabilities (including preferential distribution and dividend rights of holders of preferred stock). Holders of common stock have no cumulative rights, and, accordingly, the holders of a majority of the outstanding shares of the common stock have the ability to elect all of the directors. Holders of common stock have no preemptive or other rights to subscribe for shares. Holders of common stock are entitled to such dividends as may be declared by the Board out of funds legally available therefore. We have never paid cash dividends on the common stock and do not anticipate paying any cash dividends in the foreseeable future. Preferred Stock. Our board of directors is authorized, without further shareholder action, to issue preferred stock in one or more series and to designate the dividend rate, voting rights and other rights, preferences and restrictions of each such series. As of April 4, 2002, we had a total of 17,000 shares of preferred stock 16 <PAGE> issued and outstanding, including 8,000 of our Series D and 9,000 of our Series E Preferred Stock. The Series D and E Preferred Stock are senior to our common stock regarding liquidation. The holders of the preferred stock do not have voting rights or preemptive rights nor are they subject to the benefits of any retirement or sinking fund. The Series D Preferred Stock is not entitled to dividends, nor is it redeemable, however it is convertible to Common Stock at anytime following December 31, 2002, the third anniversary of the date of issue. Thereafter, the holder may convert any or all of the shares of the Series D Preferred Stock to Common Stock. The total number of shares of Common Stock to be issued upon such conversion shall be 500,000. The Series E Preferred Stock is entitled to receive dividends at the rate of $12.50 per share per annum, payable quarterly. The Series E Preferred Stock is redeemable in whole or in part at any time, at our option, at a price of $500 per share, plus all accrued and undeclared or unpaid dividends; except that, after two years from the date of the original issuance and prior to redemption of remaining shares by the Company, the holders of record shall be given a 60-day written notice of our intent to redeem and the opportunity to convert the Series E Preferred Stock to common stock. The conversion price for the Series E Preferred Stock shall be $2.00 per share of common stock. At April 4, 2002, none of the 9,000 outstanding shares of Series E Preferred Stock had been redeemed or converted. On a fully converted basis, the 9,000 shares of Series E Preferred Stock would convert to 2,225,000 shares of common stock. Outstanding Options and Warrants. At April 4, 2002, we had outstanding warrants and options for the purchase of 2,338,754 shares of common stock at prices ranging from $.75 to $6.00 per share, including employee stock options to purchase 1,032,000 shares at prices ranging from $.75 to $1.81 per share. Recent Sales of Unregistered Securities. During 2001, we sold and issued the following shares of common or preferred stock in private offerings not registered under the Securities Act of 1933, as amended, and exempt under Section 4(2) of the Act. All the purchasers were accredited investors not affiliated with the company or consultants. No underwriters were used and no underwriting discounts or commissions were paid in any of the sales. Number of Date Security Purchaser Shares Consideration - ---- -------- --------- ------ ------------- 04/30/01 Common Property Seller 17,500 Exchange for oil and gas properties 08/07/01 Preferred Property Seller 9,000 Exchange for oil and gas properties 08/16/01 Common Consultants 10,000 Consulting fees 10/25/01 Common Property Seller 20,000 Exchange for oil and gas properties We also granted warrants or options exercisable for shares of common stock not registered under the Securities Act of 1933, as amended, and exempt under Section 4(2) of the Act. All the grantees were current employees, consultants or accredited investors not affiliated with the company. No underwriters were used, and no underwriting discounts or commissions were paid in connection with the grants. Exercisable Exercise Date Derivative Grantee(s) Shares Price Consideration ---- ---------- ---------- ------ ----- ------------- 05/18/01 Option Employees 184,000 $.83 Compensation 08/16/01 Warrant Consultants 156,000 $.75 Fees 17 <PAGE> ITEM 6. Selected Financial Data. The following table sets forth selected historical financial data of our company as of December 31, 2001, 2000, 1999, 1998 and 1997, and for each of the periods then ended. See "Item 1. Business" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." The income statement data for the years ended December 31, 2001, 2000 and 1999 and the balance sheet data at December 31, 2001 and 2000 are derived from our audited financial statements contained elsewhere herein. The income statement data for the years ended December 31, 1998 and 1997 and the balance sheet data at December 31, 1999, 1998 and 1997 are derived from our Annual Report on Form 10-K for those periods. You should read this data in conjunction with our consolidated financial statements and the notes thereto included elsewhere herein. Year Ended December 31, -------------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 ----------------- ----------------- ----------------- ----------------- ----------------- Income Statement Data - --------------------- Operating Revenues $ 12,990,581 $ 8,984,175 $ 2,812,639 $ 2,403,553 $ 4,960,966 Net income (loss) from operations 3,451,875 2,464,017 (1,464,094) (6,329,884) (598,320) Net income (loss) 576,709 352,774 (2,269,506) (8,387,060) (1,676,681) Dividends on preferred stock (56,250) - (450,684) (427,173) (380,928) Net income (loss) available to Common Shareholders 520,459 352,774 (2,720,190) (8,814,233) (2,057,609) Net income (loss), per share of common stock $ .03 $ .02 $ (.34) (3.68) $ (1.19) Weighted average number of shares of common stock outstanding 18,464,343 17,293,848 7,953,147 2,394,866 1,725,926 Balance Sheet Data - ------------------ Current assets $ 2,205,862 $ 2,934,804 $ 1,357,465 $ 820,984 $ 1,536,396 Total assets 50,911,627 32,374,128 20,009,793 8,058,827 17,089,855 Current liabilities 12,492,365 7,594,986 4,650,691 6,559,393 2,879,256 Long-term obligations 26,541,957 18,077,371 11,304,318 3,401,371 12,185,055 Stockholders' Equity (Deficit) $ 11,877,305 $ 6,701,771 $ 4,054,784 $ (1,901,937) $ 2,025,544 18 <PAGE> ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Overview. We are engaged primarily in the acquisition, development, exploitation, exploration and production of crude oil and natural gas. Our focus is on increasing production from our existing crude oil and natural gas properties through the further exploitation, development and exploration of those properties, and on acquiring additional interests in crude oil and natural gas properties. Our gross revenues are derived from the following sources: 1. Oil and gas sales that are proceeds from the sale of crude oil and natural gas production to midstream purchasers; 2. Operating overhead and other income that consists of earnings from operating crude oil and natural gas properties for other working interest owners, and marketing and transporting natural gas. This also includes earnings from other miscellaneous activities. 3. Well servicing revenues that are earnings from the operation of well servicing equipment under contract to other operators. The following is a discussion of our consolidated financial condition, results of operations, liquidity and capital resources. You should read this discussion in conjunction with the Consolidated Financial Statements of the Company and the Notes thereto contained elsewhere herein. See "Financial Statements." Results of Operations. The factors which most significantly affect our results of operations are (1) the sales price of crude oil and natural gas, (2) the level of total sales volumes of crude oil and natural gas, (3) the level of and interest rates on borrowings and, (4) the level and success of new acquisitions and development of existing properties. Comparative results of operations for the periods indicated are discussed below. Year Ended December 31, 2001 Compared to Year Ended December 31, 2000 Revenues Oil and Gas Sales. Our operating revenues from the sale of crude oil and natural gas increased by 47% from $8,446,000 in 2000 to $12,426,000 in 2001, due to increased oil and gas production from development projects and acquisitions of additional properties. Well Servicing Revenues. Revenues from our well servicing operations decreased by 10% from $188,000 in 2000 to $169,000 in 2001. This decrease was due to higher rig utilization on operated properties where the Company has working interest partners and less work for third parties. Operating Overhead and Other Income. Revenues from these activities increased 13% from $350,000 in 2000 to $395,000 in 2000. Major components of the increase included operating overhead $81,800, gathering and marketing $210,900, sale of exploratory leases $96,300 and miscellaneous income $6,000. 19 <PAGE> Costs and Expenses Lease Operating Expenses. Lease operating expenses increased 53% from $3,378,000 in 2000 to $5,155,000 in 2001. This increase in operating expenses was due to the acquisitions of additional properties, expanded oil and gas production, and increased vendor prices. Cost of Well Servicing Operations. Well servicing expenses decreased 14% from $212,000 in 2000 to $182,000 in 2001. This decrease in expenses was due to less utilization of our equipment under contract to third parties. Depreciation, Depletion and Amortization (DD&A). DD&A increased 86% from $1,342,000 in 2000 to $2,491,000 in 2001, due to significantly higher production resulting from successful field development activities and acquisitions. General and Administrative (G&A) Expenses. G&A expenses increased 8% from $1,588,000 in 2000 to $1,710,000 in 2001 due to the increased number of properties being managed. Interest Expense and Dividends on Preferred Stock. Interest expense increased 29% from $2,135,000 in 2000 to $2,757,000 in 2001 due to increased debt associated with the funding of our additional acquisitions and capital development program. Dividends on preferred stock due was $56,250 and paid was $28,125 in 2001. No dividends were due or paid in 2000. Year Ended December 31, 2000 Compared to Year Ended December 31, 1999 Revenues Oil and Gas Sales. Our operating revenues from the sale of crude oil and natural gas increased by 233% from $2,533,000 in 1999 to $8,446,000 in 2000, due to increased oil and gas production from development projects, higher oil and gas prices, and acquisitions of additional properties. Well Servicing Revenues. Revenues from our well servicing operations increased by 61% from $117,000 in 1999 to $188,000 in 2000. This increase was due to higher rig utilization on operated properties where the Company has working interest partners and increased work for third parties. Operating Overhead and Other Income. Revenues from these activities increased 115% from $163,000 in 1999 to $350,000 in 2000. Major components of the change included a decrease of $38,000 in revenues we received for operating properties for other parties (due to our acquiring additional working interests in the operated properties); an increase of $117,000 in natural gas marketing and transportation; $52,000 received in damages from a drilling contractor; and, $20,000 received for the assignment of certain deep drilling rights on one of our leases. Costs and Expenses Lease Operating Expenses. Lease operating expenses increased 141% from $1,400,000 in 1999 to $3,378,000 in 2000. This increase in operating expenses was due to the acquisitions of additional properties, expanded oil and gas production, and the costs related to such production. Cost of Well Servicing Operations. Well servicing expenses increased 12% from $190,000 in 1999 to $212,000 in 2000. This increase in expenses was due to less work under contract to third parties. 20 <PAGE> Depreciation, Depletion and Amortization (DD&A). DD&A increased 91% from $704,000 in 1999 to $1,342,000 in 2000, due to significantly higher production resulting from successful field development activities and acquisitions. General and Administrative (G&A) Expenses. G&A expenses decreased 20% from $1,983,000 for 1999 to $1,588,000 in 2000. The Company had non-recurring expenses consisting of costs associated with the consolidation of its offices to Houston and non-cash charges of $232,000 related to the issuance of stocks and warrants in 1999 compared to $2,000 in 2000. Interest Expense and Dividends on Preferred Stock. Interest expense increased 140% from $890,000 in 1999 to $2,135,000 in 2000 due to increased debt associated with additional acquisitions and our capital development program, and higher borrowing rates. Preferred dividends decreased $451,000 from year-end 1999, since all of the preferred stock entitled to receive dividends had been converted to common stock. Year Ended December 31, 1999 Compared to Year Ended December 31, 1998 Revenues Oil and Gas Sales. Operating revenues from the sale of crude oil and natural gas increased by 40% from $1,804,000 in 1998 to $2,533,000 in 1999. This was due to increased crude oil and natural gas production, and higher crude oil and natural gas prices. Well Servicing Revenues. Revenues from well servicing operations decreased by 73% from $432,000 in 1998 to $117,000 in 1999. This decrease was due to fewer rig utilization contracts with third parties as a result of significantly lower industry activity. Operating Overhead Revenues. Revenues from the operating of properties decreased 2% from $167,000 in 1998 to $163,000 in 1999. This decrease was due to the fact that we operated fewer wells for other working interest owners. Costs and Expenses Lease Operating Expenses. Lease operating expenses decreased 15% from $1,647,000 in 1998 to $1,400,000 in 1999. This decrease in operating expenses was due to the sale of GulfWest Permian assets, effective October 1, 1998, and the overall reduction in operating expenses. Cost of Well Servicing Operations. Well servicing expenses decreased 55% from $421,000 in 1998 to $190,000 in 1999. This decrease in expenses was due to the reduced utilization of our equipment under contract to third parties. Impairment of Assets. Impairment of assets decreased to $0 in 1999 from $2,279,000 in 1998. The decrease was due to our not being required to write down the carrying values of crude oil and natural gas properties (whose future estimated undiscounted net cash inflows are less than such carrying value) to fair value. An impairment of assets write-down is a charge to earnings, which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity. The risk that we will be required to write down the carrying value of our crude oil and natural gas reserves increases when crude oil and natural gas prices are depressed or volatile as they were at December 31, 1998. No assurance can be given that we will not experience additional write-downs in the future if commodity prices decline. 21 <PAGE> General and Administrative (G&A) Expenses. G&A expenses decreased 4% from $2,064,000 for the year ended December 31, 1998 to $1,983,000 for the year ended December 31, 1999, as a result of a consolidation of offices to Houston, Texas. This reduction was achieved despite the cost of relocating the office and our staff from Dallas, Texas and Baton Rouge, Louisiana to Houston, Texas. Depreciation, Depletion and Amortization (DD&A). DD&A decreased 70% from $2,322,000 in 1998 to $704,000 in 1999. The decrease was due to the significant write-down of the crude oil and natural gas property book values in 1998 and the increased reserves booked in 1999. Interest Expense and Dividends on Preferred Stock. Interest expense decreased 32% from $1,303,000 in 1998 to $890,000 in 1999. This decrease was due to the sale of our subsidiary, GulfWest Permian Company, in 1998 and the resulting significant debt reduction. Preferred dividends increased $19,000 due to the increase in the amount of preferred stock issued; however, by year-end 1999, the majority of the preferred stock had been converted to common stock. Financial Condition and Capital Resources. At December 31, 2001, our current liabilities exceeded our current assets by $10,286,503. We had a profit of $576,709 compared to a profit of $352,774 at December 31, 2000. The profit in the year 2001was attributed to increased production from development projects and additional acquisitions. On April 5, 2000, we entered into an agreement with Aquila Energy Capital, an energy lender, to provide $19,302,000 in financing, of which $13,302,000, less closing costs of $402,000, was funded at closing and $6,000,000 was for future development capital. We used the net proceeds to (i) retire existing debt, including accrued interest of $10,234,977; (ii) acquire crude oil and natural gas properties in Zavala County, Texas for $2,300,000, including $3,266 in cash and 200,000 shares of common stock; and, (iii) acquire additional interests in the Madisonville Field, Texas. The loan is secured by substantially all of the Company's interests in oil and gas properties, bears interest at prime plus 3.5% and matures May 29, 2004. Monthly payments as to principal and interest are from an 85% net revenue interest in the secured properties. The lender retains a 7% overriding royalty interest with payments commencing after the loan is paid in full. On August 16, 2001, the total amount of financing increased by $16,800,000 to $36,102,000. The proceeds are to be used as follows: $10,000,000 for the Goldking Acquisition (see below), $6,630,000 for development of the properties securing the loan and $170,000 for a structuring fee paid to the lender. As a result of the amendment, the net revenue increased from 85% to 90%. In addition, the amendment requires payments on principal of $1,000,000 in February, 2002, August 2000 and February, 2003 The development capital included in the Aquila financing was designated for projects to increase production on our existing properties, as identified by us and approved by the lender. We used approximately $3,400,000 for such projects in the year 2000 and $4,230,000 in the year 2001. We will continue our development plans in 2002 with the remaining $5,000,000. We will also continue to identify and evaluate opportunities for growth through acquisitions. We believe our profits will increase in the future; however adverse changes in the prices of crude oil and natural gas would have a severe impact on our plans. On August 17, 2001, we purchased several oil and natural gas properties located in four fields in Texas and Louisiana (the "Goldking Acquisition"). The effective date of the acquisition was July 1, 2001. The acquired properties are currently producing an aggregate 600 barrels of oil and 1,200 Mcf of natural gas per day, with total proved reserves (net to the acquired interests) estimated at 1.2 million barrels of oil and 9.5 billion cubic feet of natural gas. There are additional possible reserves estimated at 10 billion cubic feet of natural gas. The purchase price of the acquisition was $15 million in a combination of notes payable, preferred stock, cash, warrants and common stock. Financing was arranged through an existing credit facility and included expanding the company's credit line to continue the development of its properties through the year 2002. 22 <PAGE> Effective December 1, 200l, we entered into an Oil and Gas Property Acquisition, Exploration and Development Agreement (the "Summit Agreement") with Summit Investment Group-Texas, L.L.C., an unrelated party, ("Summit"). Under the agreement, Summit will provide or makes available to us payments in the aggregate of $1,200,000 in advanced funds (the Advanced Funds") for our use in the acquisition of oil and gas leases and other mineral and royalty interests in order that we may conduct specified oil and gas exploration and production activities. We will pay Summit a sourcing fee of $100,000 and expenses of $100,000 from the Advanced Funds. We agree to drill four (4) wells located on oil and gas properties acquired under the Summit Agreement (the "Obligation Wells") and to commence such drilling prior to the expiration of two (2) years from the effective date of the Summit Agreement. We will pay Summit $175,000 on or before the date of commencement of drilling of each Obligation Well and Summit shall assign us its interest in the applicable oil and gas leases attributable to the production unit for such well. We further agree to conduct well workover operations on certain existing wells acquired by us, which are located on lands described in the Summit Agreement, all such well workover operations to be completed within nine (9) months of the Effective Date. Summit will reserve a 2.5% overriding royalty interest in the drilling prospect leases and a 25% net profits interest in the workover leases. The Advanced Funds shall be recouped by Summit in the following manner: (a) A total of $500,000.00 shall be repaid out of an undivided 40% of the "Summit Net Profits Interest", defined as twenty five percent (25%) of the monthly net sale proceeds of all oil and gas production allocable to our interest in the pertinent oil and gas properties, as more fully defined in the Summit Agreement. Summit will retain an 8.5% working interest in the workover leases after payment of the $500,000. (b) We shall pay $175,000 in cash to Summit on the date we commence drilling each Obligation Well; or (c) By virtue of a lump sum production payment by us. If, at the expiration of two (2) years from the Effective Date, Summit has not completely recouped the Advanced Funds from the payments referred to in (a), (b) and (c) above, then Summit, at its sole election, may require that we issue to it a quantity of our Common Stock equivalent to the quotient of the outstanding Advanced Funds (numerator) and $2.00 per share (denominator). Upon issuance of such stock to Summit, Summit shall assign to us all its interest in the remaining oil and gas properties within the subject area, reserving its overriding royalty interest in the properties. Inflation and Changes in Prices. While the general level of inflation affects certain costs associated with the petroleum industry, factors unique to the industry result in independent price fluctuations. Such price changes have had, and will continue to have a material effect on our operations; however, we cannot predict these fluctuations. 23 <PAGE> The following table indicates the average crude oil and natural gas prices received over the last three years by quarter. Average prices per barrel of oil equivalent, computed by converting natural gas production to crude oil equivalents at the rate of 6 Mcf per barrel, indicate the composite impact of changes in crude oil and natural gas prices. Average Prices ---------------------------------------------- Crude Oil Per and Natural Equivalent Liquids Gas Barrel --------- -------- ----------- (per Bbl) (Per Mcf) 1999 ---- First $ 9.72 $ 1.63 $ 9.84 Second 14.28 2.17 13.71 Third 19.77 2.77 18.52 Fourth 20.27 2.71 18.64 2000 ---- First $ 26.06 $ 2.73 $ 21.23 Second 25.14 3.19 21.89 Third 25.79 3.90 24.42 Fourth 27.38 4.68 27.74 2001 ---- First $ 24.15 $ 5.27 $ 27.87 Second 24.14 3.88 23.71 Third 23.25 3.08 21.08 Fourth 19.94 2.62 17.96 ITEM 7a. Qualitative and Quantitative Disclosures About Market Risk. Information with respect to this Item 7a is contained in Item 1 "Risk Factors". ITEM 8. Financial Statements and Supplementary Data. Information with respect to this Item 8 is contained in our financial statements beginning on Page F-1 of this Annual Report. ITEM 9. Changes In and Disagreements With Accountants and Accounting and Financial Disclosure. None 24 <PAGE> PART III ITEM 10. Directors and Executive Officers of the Registrant. The following table sets forth information on our directors and executive officers: Year First Elected Name Age Position Director or Officer - ---- --- -------- ------------------- Marshall A. Smith III(3) 54 Chairman of the Board 1989 Thomas R. Kaetzer(3) 43 Chief Executive Officer 1998 President and Director Jim C. Bigham 66 Executive Vice President 1991 and Secretary Richard L. Creel 53 Vice President of Finance 1998 and Controller William T. Winston 35 Director 2000 John E. Loehr(1)(2)(3) 56 Director 1992 J. Virgil Waggoner(1)(2)(3) 74 Director 1997 Steven M. Morris(1)(2) 50 Director 2000 John P. Boylan(1) 35 Director 2001 (1) Member of the Audit Committee. (2) Member of the Compensation Committee. (3) Member of the Executive Committee. Marshall A. Smith III has served as an officer and a director of GulfWest since July 1989. From July 1989 to November 20, 1992, he served as president and chairman of the Board. On November 20, 1992, he resigned as president but continued as chief executive officer and chairman of the board. On September 1, 1993, Mr. Smith reassumed the duties of president and resigned as chairman of the board. On December 21, 1998, he resigned as president but remained chief executive officer. On March 20, 2001, he resigned as chief executive officer and was elected chairman of the board. Thomas R. Kaetzer was appointed senior vice president and chief operating officer of GulfWest on September 15, 1998 and on December 21, 1998 became president and a director. On March 20, 2001, he was appointed chief executive officer. Mr. Kaetzer has 17 years experience in the oil and gas industry, including 14 years with Texaco Inc., which involved the evaluation, exploitation and management of oil and gas assets. He has both onshore and offshore experience in operations and production management, asset acquisition, development, drilling and workovers in the continental U.S., Gulf of Mexico, North Sea, Colombia, Saudi Arabia, China and West Africa. Mr. Kaetzer has a Masters Degree in Petroleum Engineering from Tulane University and a Bachelor of Science Degree in Civil Engineering from the University of Illinois. 25 <PAGE> Jim C. Bigham has served as secretary since 1991 and as executive vice president of GulfWest since 1996. Prior to joining GulfWest, he held management and sales positions in the real estate and printing industries. Mr. Bigham is also a retired United States Air Force Major. During his military career, he served in both command and staff officer positions in the operational, intelligence and planning areas. Richard L. Creel has served as controller of GulfWest since May 1, 1997 and was elected vice president of finance on May 28, 1998. Prior to joining GulfWest, Mr. Creel served as Branch Manager of the Nashville, Tennessee office of Management Reports and Services, Inc. He has also served as controller of TLO Energy Corp. He has extensive experience in general accounting, petroleum accounting, and financial consulting and income tax preparation. William T. Winston joined GulfWest in April 1999 and served as vice president from May 2000 until March 29, 2002. He became a director in August 2001. While vice president, he was responsible for business development, including identifying and evaluating pipeline and gathering system acquisitions, and assisting in the evaluation for production acquisitions. Before joining GulfWest, Mr. Winston was in charge of field operations and project planning for Eagle Natural Gas Co., a privately held natural gas gathering company based in Houston. He served six years in the United States Army and Texas National Guard and holds a Bachelor of Arts Degree in Government from the University of Texas at Austin. John E. Loehr has served as a director of GulfWest since 1992, was chairman of the board from September 1, 1993 to July 8, 1998 and was chief financial officer from November 22, 1996 to May 28, 1998. He is also currently president and sole shareholder of ST Advisory Corporation, an investment company, and vice-president of Star-Tex Trading Company, also an investment company. He was formerly president of Star-Tex Asset Management, a commodity-trading advisor, and a position he held from 1988 until 1992 when he sold his ownership interest. Mr. Loehr is a CPA and is a member of the American Institute of Certified Public Accountants. J. Virgil Waggoner has served as a director of GulfWest since December 1, 1997. Mr. Waggoner's career in the petrochemical industry began in 1950 and included senior management positions with Monsanto Company and El Paso Products Company, the petrochemical and plastics unit of El Paso Company. He served as president and chief executive officer of Sterling Chemicals, Inc. from the firm's inception in 1986 until its sale and his retirement in 1996. He is currently chief executive officer of JVW Investments, Ltd., a private company. Steven M. Morris was appointed a director of GulfWest on January 6, 2000. He was the president of Pozo Resources, Inc., an oil and gas production company, until its asset were sold to GulfWest on December 31, 1999. Mr. Morris is a certified public accountant and president of Pentad Enterprises, Inc., a private investment firm in Houston, Texas. He is currently a director of the Bank of Tanglewood, Houston, Texas, and Quicksilver Resources, Inc., a publicly traded oil and gas exploration and production company with offices in Ft. Worth, Texas. John P. Boylan was appointed a director of GulfWest on August 7, 2001. Mr. Boylan has served as Managing Partner and Chief Executive Officer of Birdwell Partners, L.P., the parent company and General Partner of Five Star Transportation, Superior Trucking Company and American Pipe Inspection Company since 1999. He began his career in the oil and gas industry in 1993 providing venture funding for lease acquisition and drilling projects, and from 1996 to present has been actively involved in the management of an independent exploration and production company. His experience covers most of the management, finance and non-technical aspects of the oilfield services, as well as the upstream oil and gas exploration and production industry. He has had experience in all of the major producing trends covering the Texas Gulf Coast and South Texas. In 1995, he received the degree of Master of Business 26 <PAGE> Administration, with majors in Finance, Economics and International Business from the Leonard N. Stern Graduate School of Business of New York University. He received the degree of Bachelor of Business Administration, with a major in Accounting, from the University of Texas in 1988. Mr. Boylan has been a Certified Public Accountant in the State of Texas since 1991. Our directors are elected annually and hold office until the next annual meeting of shareholders and until their successors are duly elected and qualified. The board of directors met seven times during the calendar year ended December 31, 2001. Committees of the Board of Directors. Our board of directors has established an audit committee, a compensation committee and an executive committee. The functions of these committees, their current members, and the number of meetings held during 2001 are described below. The audit committee was established to review and appraise the audit efforts of our independent auditors, and monitor the company's accounts, procedures and internal controls. The committee is comprised of Mr. John E. Loehr (Chairman), Mr. J. Virgil Waggoner, Mr. John P. Boylan and Mr. Steven M. Morris. The committee met twice in 2001. The function of the compensation committee is to fix the annual salaries and other compensation for the officers and key employees of the Company. The committee is comprised of Mr. J. Virgil Waggoner (Chairman), Mr. John E. Loehr and Mr. Steven M. Morris. The committee met twice in 2001. The executive committee was established to make recommendations to the board of directors in the areas of financial planning, strategies and business alternatives. The committee is comprised of Mr. Marshall A. Smith III (Chairman), Mr. J. Virgil Waggoner, Mr. John E. Loehr and Mr. Thomas R. Kaetzer. The committee met twice in 2001. Compensation of Directors. The shareholders approved an amended and restated Employee Stock Option Plan on May 28, 1998, which included a provision for the payment of reasonable fees in cash or stock to directors. No fees were paid to directors in 2001. ITEM 11. Executive Compensation. Information regarding executive compensation is incorporated herein by reference to our Proxy Statement. ITEM 12. Security Ownership of Certain Beneficial Owners and Management. Information regarding security ownership of certain beneficial owners and management is incorporated herein by reference to our Proxy Statement. ITEM 13. Certain Relationships and Related Transactions. Information regarding certain relationships and related transactions is incorporated herein by reference to our Proxy Statement. 27 <PAGE> GLOSSARY OF INDUSTRY TERMS AND ABBREVIATIONS The following are definitions of certain industry terms and abbreviations used in this report: Bbl. Barrel. BOE. Barrel of oil equivalent, based on a ratio of 6,000 cubic feet of natural gas for each barrel of oil. Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interests is owned. Horizontal Drilling. High angle directional drilling with lateral penetration of one or more productive reservoirs. Mcf. One thousand cubic feet. Net Acres or Net Wells. The sum of the fractional working interests owned in gross acres or gross wells. Overriding Royalty Interest. The right to receive a share of the proceeds of production from a well, free of all costs and expenses, except transportation. Present Value. The pre-tax present value, discounted at 10%, of future net cash flows from estimated proved reserves, calculated holding prices and costs constant at amounts in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions) and otherwise in accordance with the Commission's rules for inclusion of oil and gas reserve information in financial statements filed with the Commission. Proceeds of Production. Money received (usually monthly) from the sale of oil and gas produced from producing properties. Producing Properties. Properties that contain one or more wells that produce oil and/or gas in paying quantities (i.e., a well for which proceeds from production exceed operating expenses). Productive Well. A well that is producing oil or gas or that is capable of production. Prospect. A lease or group of leases containing possible reserves, capable of producing crude oil, natural gas, or natural gas liquids in commercial quantities, either at the time of acquisition, or after vertical or horizontal drilling, completion of workovers, recompletions, or operational modifications. Proved Reserves. Estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions; i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if either actual production or a conclusive formation test supports economic production. The area of a reservoir considered proved includes: a. That portion delineated by drilling and defining by gas-oil or oil-water contacts, if any; and 28 <PAGE> b. The immediately adjoining portions not yet drilled but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. Proved Reserves do not include: a. Oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; b. Crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; c. Crude oil, natural gas, and natural gas liquids that may occur in undrilled prospects; and d. Crude oil, natural gas, and natural gas liquids that may be recovered from oil shales and other sources. Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed only after testing by a pilot project or after operation of an installed program has confirmed through production response that increased recovery will be achieved. Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other units that have not been drilled can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proven effective by actual tests in the area and in the same reservoir. Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has previously been completed. Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. Royalty. The right to a share of production from a well, free of all costs and expenses, except transportation. Royalty Interest. An interest in an oil and gas property entitling the owner to a share of oil and natural gas production free of costs of production. 29 <PAGE> Standardized Measure. The present value, discounted at 10%, of future net cash flows from estimated proved reserves, after income taxes, calculated holding prices and costs constant at amounts in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions) and otherwise in accordance with the Commission's rules for inclusion of oil and gas reserve information in financial statements filed with the Commission. Waterflood. An engineered, planned effort to inject water into an existing oil reservoir with the intent of increasing oil reserve recovery and production rates. Working Interest. The operating interest under a lease, the owner of which has the right to explore for and produce oil and gas covered by such lease. The full working interest bears 100 percent of the costs of exploration, development, production, and operation, and is entitled to the portion of gross revenue from the proceeds of production which remains after proceeds allocable to royalty and overriding royalty interests or other lease burdens have been deducted. Workover. Rig work performed to restore an existing well to production or improve its production from the current existing reservoir. 30 <PAGE> PART IV ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. (a) The following documents are filed as part of this Report: (1) Financial Statements: Consolidated Balance Sheets at December 31, 2001 and 2000. Consolidated Statements of Operations for the years ended December 31, 2001, 2000 and 1999. Consolidated Statements of Stockholders' Equity for the years ended December 31, 2001, 2000 and 1999. Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999. Notes to Consolidated Financial Statements, December 31, 2001, 2000 and 1999. (2) Financial Statement Schedule: Schedule II - Valuation and Qualifying Accounts (3) Exhibits: Number Description ------ ----------- #2.8 Purchase and Sale Agreement between Pozo Resources, Inc. and GulfWest Oil Company, effective December 31, 1999. *3.1 Articles of Incorporation of the Registrant and Amendments thereto. *3.2 Bylaws of the Registrant. %10.1 GulfWest Oil Company 1994 Stock Option and Compensation Plan, amended and restated as of April 1, 2001 and approved by the shareholders on May 18, 2001. 22.1 Subsidiaries of the Registrant filed herewith. 25 Power of Attorney (included on signature page of this Annual Report). # Previously filed with our Form 8-K, Current Report dated December 31, 1999, filed with the Commission on January 10,2000. * Previously filed with our Registration Statement (on Form S-1, Reg. No. 33-53526), filed with the Commission on October 21, 1992. % Previously filed with our Proxy Statement on Form DEF 14A, filed with the Commission on April 16, 2001. 31 <PAGE> (b) Reports on Form 8-K. None. Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. GULFWEST ENERGY INC. Date: April 4, 2002 By:/s/Thomas R. Kaetzer ------------------------------- Thomas R. Kaetzer, President 32 <PAGE> POWER OF ATTORNEY Know all men by these presents, that each person whose signature appears below constitutes and appoints Thomas R. Kaetzer as his true and lawful attorney-in-fact and agent, with full power of substitution, for him and in his name, place, and stead, in any and all capacities to sign any and all amendments or supplements to this Annual Report on Form 10-K, and to file the same, and with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons, on behalf of the registrant, and in the capacities and on the dates indicated. Signature Title Date - ------------------------ -------------------------------------- --------------- \s\ Marshall A. Smith Chairman of the Board April 4, 2002 - ---------------------- Marshall A. Smith III \s\ Thomas R. Kaetzer President, Chief Executive Officer April 4, 2002 - ---------------------- Thomas R. Kaetzer and Director \s\ Jim C. Bigham Executive Vice President and Secretary April 4, 2002 - ---------------------- Jim C. Bigham \s\ Richard L. Creel Vice President of Finance, Controller April 4, 2002 - ---------------------- Richard L. Creel \s\ William T. Winston Director April 4, 2002 - ---------------------- William T. Winston \s\ J. Virgil Waggoner Director April 4, 2002 - ---------------------- J. Virgil Waggoner \s\ John E. Loehr Director April 4, 2002 - ---------------------- John E. Loehr \s\ John P. Boylan Director April 4, 2002 - ---------------------- John P. Boylan \s\ Steven M.Morris Director April 4, 2002 - ---------------------- Steven M. Morris 33 <PAGE> GULFWEST ENERGY INC. FINANCIAL REPORT DECEMBER 31, 2001 <PAGE> C O N T E N T S Page INDEPENDENT AUDITOR'S REPORT ON THE FINANCIAL STATEMENTS F-1 FINANCIAL STATEMENTS Consolidated balance sheets F-2 Consolidated statements of operations F-4 Consolidated statements of stockholders' equity F-5 Consolidated statements of cash flows F-9 Notes to consolidated financial statements F-10 INDEPENDENT AUDITOR'S REPORT ON THE FINANCIAL STATEMENT SCHEDULE F-31 FINANCIAL STATEMENT SCHEDULE Schedule II - Valuation and Qualifying Accounts F-32 All other Financial Statement Schedules have been omitted because they are either inapplicable or the information required is included in the financial statements or the notes thereto. <PAGE> INDEPENDENT AUDITOR'S REPORT To the Stockholders and Board of Directors GULFWEST ENERGY INC. We have audited the accompanying consolidated balance sheets of GulfWest Energy Inc. (a Texas Corporation) and Subsidiaries as of December 31, 2001 and 2000, the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2001. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of GulfWest Energy Inc. and Subsidiaries as of December 31, 2001 and 2000, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. \s\WEAVER AND TIDWELL, L.L.P - ------------------------------ WEAVER AND TIDWELL, L.L.P. Dallas, Texas April 4, 2002 F-1 <PAGE> GULFWEST ENERGY INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 2001 AND 2000 ASSETS 2001 2000 ---- ---- CURRENT ASSETS Cash and cash equivalents $ 689,030 $ 663,032 Accounts receivable - trade, net of allowance for doubtful accounts of $ -0- in 2001 and 2000 1,392,751 2,188,421 Prepaid expenses 124,081 83,351 --------- --------- Total current assets 2,205,862 2,934,804 --------- --------- OIL AND GAS PROPERTIES, using the successful efforts method of accounting 52,045,178 30,895,049 OTHER PROPERTY AND EQUIPMENT 2,352,166 1,961,203 Less accumulated depreciation, depletion, and amortization (6,235,251) (4,049,510) ---------- ---------- Net oil and gas properties and other property and equipment 48,162,093 28,806,742 ---------- ---------- OTHER ASSETS Deposits 37,442 27,638 Investments 122,785 Debt issue cost, net 506,230 482,159 ---------- ---------- Total other assets 543,672 632,582 ----------- ------------ TOTAL ASSETS $50,911,627 $32,374,128 =========== =========== The Notes to Consolidated Financial Statements are an integral part of these statements. F-2 <PAGE> LIABILITIES AND STOCKHOLDERS' EQUITY 2001 2000 ---- ---- CURRENT LIABILITIES Notes payable $ 2,821,020 $ 935,300 Notes payable - related parties 40,000 700,000 Current portion of long-term debt 6,065,588 3,111,120 Current portion of long-term debt - related parties 222,687 303,296 Accounts payable - trade 3,099,399 2,189,656 Accrued expenses 243,671 355,614 ------- ------- Total current liabilities 12,492,365 7,594,986 ---------- --------- LONG-TERM DEBT, net of current portion 26,330,589 17,960,455 ---------- ---------- LONG-TERM DEBT - RELATED PARTIES 211,368 116,916 ------- ------- COMMITMENTS AND CONTINGENCIES STOCKHOLDERS' EQUITY Preferred stock 170 80 Common stock 18,493 18,445 Additional paid-in capital 28,164,712 23,537,900 Retained deficit (16,306,070) (16,854,654) Long-term accounts and notes receivable - related parties, net of allowance for doubtful accounts of $740,478 in 2001 and 2000 - - ------------ ----------- Total stockholders' equity 11,877,305 6,701,771 ------------ ----------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 50,911,627 $32,374,128 ============ =========== The Notes to Consolidated Financial Statements are an integral part of these statements. F-3 <PAGE> GULFWEST ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 2001 2000 1999 ---- ---- ---- OPERATING REVENUES Oil and gas sales $ 12,426,103 $ 8,445,932 $ 2,533,304 Well servicing revenues 169,167 188,052 116,791 Operating overhead and other income 395,311 350,191 162,544 ------- ------- ------- Total Operating Revenues 12,990,581 8,984,175 2,812,639 ---------- --------- --------- OPERATING EXPENSES Lease operating expenses 5,155,500 3,377,583 1,399,710 Cost of well servicing operations 182,180 212,286 190,399 Depreciation, depletion, and amortization 2,491,385 1,341,890 703,533 General and administrative 1,709,641 1,588,399 1,983,091 --------- --------- --------- Total Operating Expenses 9,538,706 6,520,158 4,276,733 --------- --------- --------- INCOME (LOSS) FROM OPERATIONS 3,451,875 2,464,017 (1,464,094) --------- --------- ---------- OTHER INCOME AND EXPENSE Interest income 16,082 5,162 Interest expense (2,756,912) (2,134,718) (889,796) Gain (loss) on sale of assets (118,254) 7,393 79,222 -------- ----- ------ Total Other Income (Expense) (2,875,166) (2,111,243) (805,412) ---------- ---------- -------- INCOME (LOSS) BEFORE INCOME TAXES 576,709 352,774 (2,269,506) INCOME TAXES ---------- ---------- -------- NET INCOME (LOSS) $ 576,709 $ 352,774 $(2,269,506) DIVIDENDS ON PREFERRED STOCK (PAID 2001 - $28,125; 2000 - $76,992; 1999 - $344,288) (56,250) (450,684) NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS $ 520,459 352,774 $ (2,720,190) ============= ============= ============= INCOME (LOSS) PER COMMON SHARE BASIC $ .03 $ .02 $ (.34) ============= ============= ============= DILUTED $ .03 $ .02 $ (.34) ============= ============= ============== F-4 <PAGE> GULFWEST ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 ------------------------------- Number of Shares -------------- -- ------------- Preferred Common Stock Stock -------------- ------------- BALANCE, December 31, 1998 13,020 3,113,517 Conversion of 2,425 shares of Class AAA preferred stock and unpaid dividends to 1,661,604 shares of common stock (2,425) 1,661,604 Conversion of 1,950 shares of Class AA preferred stock and unpaid dividends to 1,550,000 shares of common stock (1,950) 1,550,000 Conversion of 5,100 shares of Series BB preferred stock to 4,250,000 shares of common stock (5,100) 4,250,000 Conversion of 4,000 shares of Series C preferred stock to 200,000 shares of common stock (4,000) 200,000 Issuance of 1,270 shares of Series BB preferred stock for the conversion of debt 1,270 Issuance of 8,000 shares of Series D preferred stock for the acquisition of assets 8,000 Issuance of 4,921,761 shares of common stock, net of offering costs (4,000,000 through private placement, 104,139 through exercise of warrants, 300,000 for acquisition of assets, 273,000 for services, 244,622 in exchange for debt) 4,921,761 Issuance of warrants and options for services and additional financing Net loss Dividends paid on preferred stock -------------- ------------- BALANCE, December 31, 1999 8,815 15,696,882 Conversion of 815 shares of AAA preferred stock and unpaid dividends to 538,222 shares of common stock (815) 538,322 Issuance of 2,209,837 shares of common stock, net of offering costs (1,143,837 through private placement, 200,000 for acquisition of assets, 866,000 in exchange for debt) 2,209,837 Issuance of warrants and options for services and additional financing Netting of related party receivables and payables Provision for bad debts - receivables from related parties Net income -------------- ------------- BALANCE, December 31, 2000 8,000 18,445,041 ============== ============= The Notes to Consolidated Financials are an integral part of these statements. F-5 <PAGE> Common Preferred Additional Retained Receivables from Stock Stock Paid-In Capital Deficit Related Parties - ---------------------- -------------------- ------------------- --------------- ------------------ $ 3,113 $ 130 $ 12,763,936 $ (14,516,642) $ (152,474) 1,662 (24) 232,803 1,550 (19) 108,257 4,250 (51) (4,199) 200 (40) (160) 12 634,987 80 3,999,920 4,922 3,541,715 44,650 (2,269,506) (344,288) - ---------------------- -------------------- ---------------------- ------------- ------------------ 15,697 88 21,321,909 (17,130,436) (152,474) 538 (8) 76,463 (76,992) 2,210 2,123,868 15,660 112,226 40,248 352,774 - ---------------------- -------------------- ---------------------- ------------- ------------------ $ 18,445 $ 80 $ 23,537,900 $(16,854,654) $ - ====================== ==================== ====================== ============= ================== The Notes to Consolidated Financials are an integral part of these statements. F-6 <PAGE> GULFWEST ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 --------------------------------- Number of Shares -------------- -- --------------- Preferred Common Stock Stock -------------- --------------- BALANCE, December 31, 2000 8,000 18,445,041 Issuance of 9,000 shares of Series E preferred stock for the acquisition of 9,000 assets Issuance of 47,500 shares of common stock for the acquisition of assets 47,500 Issuance of warrants for the acquisition of assets Net income Dividends paid on preferred stock -------------- --------------- BALANCE, December 31, 2001 17,000 18,492,541 ============== =============== The Notes to Consolidated Financials are an integral part of these statements. F-7 <PAGE> Common Preferred Additional Retained Receivables from Stock Stock Paid-In Capital Deficit Related Parties - ---------------------- -------------------- --------------------- ---------------------- ------------------ $ 18,445 $ 80 $ 23,537,900 $ (16,854,654) $ - 90 4,499,910 48 35,402 91,500 576,709 (28,125) - ---------------------- -------------------- --------------------- ---------------------- ------------------ $ 18,493 $ 170 $ 28,164,712 $ (16,306,070) $ - ====================== ==================== ===================== ====================== ================== The Notes to Consolidated Financials are an integral part of these statements. F-8 <PAGE> GULFWEST ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 2001 2000 1999 ---- ---- ---- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)