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disruption of sales, a prolonged loss of sales or a failure or delay by PDVSA to pay our invoices could have a material adverse effect on our financial condition.

          We have been required to curtail sales to PDVSA in April and December 2002 due to insufficient crude oil storage capacity. While these appear to be isolated incidents, we cannot be assured that our sales to PDVSA will not be curtailed in the future in the same manner.

          Our strategy to focus on Russia carries operating, financial, legal and political risk. While we believe our established presence in Russia and our experience and skills from prior operations positions us well for future projects, doing business in Russia also carries unique risks. The operating environment is often difficult, and the ability to operate successfully will depend on a number of factors, including our ability to control the pace of development, apply “best practices” in drilling and development, and the fostering of relationships with Russian partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for Russian projects, while remaining within our existing debt covenants. In addition, the Russian legal system is not mature and its reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and gas projects, as well as our ability to obtain adequate compensation for any resulting losses.

          Acquiring new projects in Venezuela depends upon our ability to meet the requirements of the Organic Hydrocarbon Law. New oil projects in Venezuela are governed by the Organic Hydrocarbon Law which requires that such projects be carried out through incorporated joint ventures with majority ownership by governmental entities. While we believe it is possible to comply with the Organic Hydrocarbons Law and at the same time meet our criteria for new projects, no precedents exist and there is a risk we will be unable to achieve the desired result.

          Operations in areas outside the U.S. are subject to various risks inherent in foreign operations, and our strategy to focus on Venezuela and Russia limits our country risk diversification. Our operations in areas outside the U.S. are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and governmental royalties, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign trade, taxation and the possibility of having to be subject to exclusive jurisdiction of courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States. Our strategy to focus on Venezuela and Russia concentrates our foreign operations risk and increases the potential impact to us of the operating, financial and political risks in those countries.

          Our foreign operations expose us to foreign currency risk. Presently, our only operations are located in Venezuela. Venezuela has historically been considered a highly inflationary economy. Results of operations in that country are measured in U.S. dollars, and all currency gains or losses recorded in the consolidated statement of operations. There are many factors which affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan currency to the U.S. dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates. Our Venezuelan receipts are denominated in U.S. dollars, and most expenditures are in U.S. dollars as well. For a discussion of currency controls in Venezuela, see Capital Resources and Liquidity below. Successful acquisition of projects in Russia may also expose us to foreign currency risk in that country.

          The loss of key personnel could adversely affect our ability to successfully execute our strategy. We are a small organization and depend on the skills and experience of a few individuals in key management and operating positions to execute our business strategy. Loss of one or more key individuals in the organization could hamper or delay achieving our strategy.

          Leverage materially affects our operations. As of December 31, 2003, our long-term debt was $96.8 million. Our long-term debt represented 33 percent of our total capitalization at December 31, 2003. Our current

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cash balances are in excess of these obligations and lessen the impact of our debt but our long-term debt can effect our operations in several important ways, including the following:

	•		a significant portion of our cash flow from operations is used to pay interest on borrowings;
	•		our single largest indebtedness of $85 million is due in November 2007;
	•		the covenants contained in the indentures governing such debt limits our ability to borrow additional funds or to dispose of assets;
	•		the covenants contained in the indentures governing our debt affect our flexibility in planning for, and reacting to, changes in business conditions;
	•		the level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and
	•		the terms of the indentures governing our debt permit our creditors to accelerate payments upon an event of default or a change of control.

          The total capital required for development of new fields may exceed our ability to finance. Our future capital requirements for new projects may exceed the cash available from existing free cash flow and cash on hand. Our ability to acquire financing is uncertain and may be affected by numerous factors beyond our control. Because of the financial risk factors in the countries in which we operate, we may not be able to secure either the equity or debt financing necessary to meet any future cash needs for investment, which may limit our ability to fully develop new projects, cause delays with their development or require early divestment of all or a portion of those projects.

          Our current and future revenue is subject to concentrated counter-party risk. Our current operations in Venezuela rely on production fee payments from PDVSA for all revenue receipts. We do not own the hydrocarbons and do not sell oil and gas in open markets. Future projects in Venezuela, Russia and other countries may involve similar production fee payments from a limited number of companies or governments.

          We may not be able to invest the net cash proceeds from the sale of Geoilbent in new oil and gas projects. The terms of the 2007 Notes require that net cash proceeds in excess of $25 million from the sale of Geoilbent must be invested in the oil and gas business within one year of the sale, or any amount not so invested must be used to repay or prepay the 2007 Notes or certain debts of subsidiaries.

          Oil price declines and volatility could adversely affect our revenue, cash flows and profitability. Prices for oil fluctuate widely. The average price we received for oil in Venezuela increased to $14.07 per Bbl for the year ended December 31, 2003, compared to $13.08 per Bbl for the year ended December 31, 2002. In November 2003, we began selling natural gas in Venezuela under an addendum to our operating service contract at $1.03 per Mcf and Incremental Crude Oil at $7.00 per Bbl. While this diversifies our revenue stream, revenues, profitability and future rate of growth depend substantially upon the prevailing prices of oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to service our debt. In addition, we may have ceiling test write-downs when prices decline. Lower prices may also reduce the amount of oil that we can produce economically and lower oil production could affect the amount of natural gas we can produce. We cannot predict future oil prices. Factors that can cause this fluctuation include:

	•		relatively minor changes in the supply of and demand for oil;
	•		market uncertainty;
	•		the level of consumer product demand;
	•		weather conditions;
	•		domestic and foreign governmental regulations;
	•		the price and availability of alternative fuels;
	•		political and economic conditions in oil-producing countries; and
	•		overall economic conditions.

          Lower oil and natural gas prices or downward adjustments to our reserves may cause us to record ceiling limitation write-downs. We use the full cost method of accounting to report our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10 percent,

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plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down”. This charge does not impact cash flow from operating activities, but does reduce stockholders’ equity. The risk that we will be required to write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. The consolidated financial statements of the wholly-owned and majority owned subsidiaries do not include ceiling test write-downs in 2003. Equity in Net Losses of Affiliated Companies includes a $32.3 million (our share) ceiling test write-down recorded by Geoilbent during their fiscal year ending September 30, 2003.

          Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

          The process of estimating oil and natural gas reserves is complex. Such process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Actual production, revenue, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used. Such variances may be material.

          At December 31, 2003, approximately 47 percent of our estimated Proved Reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The estimates of our future reserves include the assumption that we will make significant capital expenditures to develop these reserves. Although we have prepared estimates of our oil and natural gas reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the results will be as estimated. See Supplemental Information on Oil and Natural Gas Producing Activities.

          You should not assume that the present value of future net revenues referred to is the current market value of our estimated 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 than the prices and costs as of the date of the estimate. Any changes in demand, our ability to produce or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and gas properties will affect the timing of actual future net cash flows from estimated proved reserves and their present value. In addition, the 10 percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and our risks or the risks associated with the oil and natural gas industry in general will affect the accuracy of the 10 percent discount factor.

          We may not be able to replace production with new reserves. In general, production rates and remaining reserves from oil and gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. Our reserves in the South Monagas Unit in Venezuela will decline as they are produced unless we acquire additional properties in Venezuela, Russia or elsewhere with proved reserves or conduct successful exploration and development activities. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive and uncertain. We may be unable to make the necessary capital investment to maintain or expand our oil and natural gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot assure you that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.

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          Our operations are subject to numerous risks of oil and natural gas drilling and production activities. Oil and natural gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is often uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

	•		unexpected drilling conditions;
	•		pressure or irregularities in formations;
	•		equipment failures or accidents;
	•		weather conditions;
	•		shortages in experienced labor;
	•		shortages or delays in the delivery of equipment; and
	•		delays in receipt of permits or access to lands.

          The prevailing price of oil also affects the cost of and the demand for drilling rigs, production equipment and related services. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs.

          The oil and natural gas industry experiences numerous operating risks. These operating risks include the risk of fire, explosions, blow-outs, pump and pipe failures, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, natural gas leaks, pipeline ruptures and discharges of toxic gases. If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. We cannot predict the continued availability of insurance at premium levels that justify its purchase.

          Competition within the industry may adversely affect our operations. We operate in a highly competitive environment. We compete with major and independent oil and natural gas companies for the acquisition of desirable oil and gas properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours.

          Our oil and natural gas operations are subject to various governmental regulations that materially affect our operations. Our oil and natural gas operations are subject to various foreign governmental regulations. These regulations may be changed in response to economic or political conditions. Matters regulated may include permits for discharges of wastewaters and other substances generated in connection with drilling operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve or limit supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

2003 Financial and Operational Performance

          In 2003, we strengthened our management team and board of directors, added to our financial flexibility by completing the sale of Geoilbent for $69.5 million in cash plus $5.5 million for repayment of our intercompany debt and accounts receivable, added a gas revenue stream and advanced our growth plan by announcing an agreement with PDVSA to study two oil and gas fields close to our facilities in Venezuela.

          At December 31, 2003, we had $138.7 million of cash and a debt to total capitalization ratio of 33 percent compared with 38 percent at the end of 2002.

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          Our board of directors has authorized the repurchase of up to one million shares of our common stock. In March 2003 we repurchased approximately 80,000 shares for an aggregate price of $0.4 million.

2004 Capital Program

          Benton-Vinccler’s capital expenditures for 2004 are projected to be $30-35 million, compared with 2003 capital expenditures of $58.1 million. The 2004 capital program includes plans for ten wells in Proved Undeveloped Reserves and related facilities at Uracoa for approximately $18 million as well as the start of the engineering and design studies at East Bombal in anticipation of gas sales in 2005.

          In 2003, we completed our three well Bombal Field development program in Venezuela and constructed a pipeline from Bombal to the Tucupita delivery line. The Bombal drilling program delivered disappointing results. Instead of initial flush production with little or no water, the wells experienced early water breakthrough and consequently lower oil production. Benton-Vinccler converted two gas injection wells in Uracoa to gas production and completed the gas project and facilities improvements on time at a cost of $27 million.

Results of Operations

          We include the results of operations of Benton-Vinccler in our consolidated financial statements and reflect the 20 percent ownership interest of Vinccler as a minority interest. We accounted for our investments in Geoilbent and Arctic Gas using the equity method. We include Geoilbent and Arctic Gas in our consolidated financial statements based on a fiscal year ending September 30. Our results of operations for the years ended December 31, 2003, 2002 and 2001 reflect the results of Geoilbent (until sold on September 25, 2003) and Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2003, 2002 and 2001.

          You should read the following discussion of the results of operations for each of the years in the three-year period ended December 31, 2003 and the financial condition as of December 31, 2003 and 2002 in conjunction with our Consolidated Financial Statements and related Notes thereto.

          We have presented selected expense items from our consolidated income statement as a percentage of revenue in the following table:

Years ended December 31, 2003 and 2002

          Net income for the year ended 2003 was $27.3 million, or $0.74 per diluted share, compared with $100.4 million for the year ended 2002. The $27.3 million net income included the gain from the sale of our minority equity investment in Geoilbent of $46.6 million, $0.4 million partial recovery of a bad debt and $1.5 million arbitration settlement related to A. E. Benton (See Note 13 – Related Party Transactions). Operating and general and administrative expenses were reduced by $3.8 million, or almost 8 percent, compared with 2002.

          Our results of operations for the year 2003 primarily reflected the results for Benton-Vinccler in Venezuela, which accounted for all of our production and oil and gas sales revenue. Oil revenue per barrel increased 8 percent (from $13.05 in 2002 to $14.07 in 2003) and oil sales quantities decreased 24 percent (from 9.7 MBbl of oil in 2002 to 7.3 MBbl of oil in 2003) during the year ended 2003 compared with 2002. Gas sales began on November 25, 2003, at the contract rate of $1.03 per Mcf. Incremental Crude Oil sales began on the same date at a fixed price of $7.00 per barrel. Total gas sales were 2.7 Bcf for the period.

          Our revenues decreased $20.6 million, or 16 percent, during the year ended 2003 compared with 2002. This was primarily due to lower production offset by higher world crude oil prices. Our sales quantities for the year ended

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2003 from Venezuela were 7.8 MBoe compared with 9.7 MBoe in 2002. The decrease in sales quantities of 1.9 MBoe, or 20 percent, was due to the Venezuelan national civil work stoppage which led to the shut-in of our production from December 2002 to February 2003, natural reservoir decline rates and the fact that some wells did not immediately return to previous production levels following the national work stoppage.

          Our operating expenses decreased $3.1 million, or 9 percent, for the year ended 2003 compared with 2002. This was primarily due to lower production volumes partially offset by higher workover and maintenance programs that continued during the Venezuelan national civil work stoppage. Depletion, depreciation and amortization decreased $5.2 million, or 20 percent, during the year 2003 compared with 2002 primarily due to decreased production from Venezuela and the addition of natural gas reserves in 2002. Depletion expense per barrel of oil produced from Venezuela during 2003 was $2.52 compared with $2.56 during 2002 primarily due to reduced future development costs. We recognized write-downs of $0.2 million for additional capitalized costs associated with former exploration projects during the year ended 2003 compared with $13.4 million for the impairment of the China WAB-21 block and $1.1 million for the Lakeside Prospect exploration activities during the year ended 2002. General and administrative expenses decreased $0.8 million from 2002 to 2003. An arbitration settlement of $1.5 million and a bad debt recovery of $0.4 million were recorded in the third quarter of 2003, and a bad debt recovery of $3.3 million was recorded in the third quarter of 2002 related to A. E. Benton.

          Taxes other than on income decreased $0.7 million, or 17 percent, during the year ended 2003 compared with 2002. This was primarily due to decreased Venezuelan municipal taxes which are a function of oil revenues partially offset by a one-time adjustment of U.S. employment taxes of $0.7 million in 2002.

          Investment income and other decreased $0.7 million, or 32 percent, during the year ended 2003 compared with 2002. This was due to lower interest rates earned on average cash and marketable securities balances. Interest expense decreased $5.9 million, or 36 percent, during the year ended 2003 compared with 2002 due to lower average outstanding debt balances for the year ended 2003 compared to 2002. In 2002, we redeemed all $108 million of our 11.625 percent Senior Notes due in May 2003 and purchased $20 million face of the 9.375 percent Senior Notes due in November 2007. In October 2002, we borrowed $15.5 million to finance the construction of the gas pipeline in Venezuela from the Uracoa field to the PDVSA sales line, and we repaid all Bolivar denominated debt in March 2003.

          Net gain on exchange rates decreased $4.0 million, or 88 percent, for the year ended 2003 compared with 2002. This was due to the significant devaluation of the Bolivar and Bolivar currency controls imposed in February 2003 which fixed the exchange rate between the Bolivar and the U.S. dollar and restricts the ability to exchange Venezuelan Bolivars for dollars and vice versa. We realized income before income taxes and minority interest of $71.8 million during the year 2003 compared with income of $169.8 million in the year ended 2002. The decrease was primarily attributable to the Arctic Gas Sale in 2002 offset by the sale of our minority equity investment in Geoilbent in 2003. Income tax expense decreased $50.6 million due to lower pre-tax income. The effective tax rate decreased from 36 to 13 percent for the year ended 2003 compared with 2002. The rate decrease was due to an increase in U.S. income with no corresponding U.S. taxes because they were offset by U.S. operating loss carryforwards for which the benefit was fully reserved in historical periods. The income before minority interests decreased $47.4 million for the year ended 2003 compared with 2002. This decrease was due to the sale of our minority equity investment in Geoilbent partially offset by decreased production of Benton-Vinccler.

          Equity in net losses of affiliated companies decreased $29.0 million during the year 2003 from $0.2 million in 2002 to a loss of $28.9 million in 2003. This was primarily due to full cost ceiling test writedowns of $32.3 million (our share) and decreased income from Geoilbent. See Note 9 – Russian Operations. The year ended 2002 included a loss of $1.5 million on Arctic Gas.

Years ended December 31, 2002 and 2001

          Net income for the year ended 2002 was $100.4 million, or $2.78 per diluted share, compared with $43.2 million for 2001. The $100.4 million net income included the after-tax gain from the Arctic Gas Sale of $93.6 million, and the pre-tax $3.3 million, partial recovery of a bad debt related to A. E. Benton (See Note 13 – Related Party Transactions); offset, in part, by a pre-tax $13.4 million impairment of the WAB-21 petroleum property located in the South China Sea. Operating and general and administrative expenses were reduced by $12 million, or almost 20 percent, compared with 2001.

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          Our results of operations for the year ended 2002 primarily reflected the results for Benton-Vinccler in Venezuela, which accounted for all of our production and oil sales revenue. As a result of increases in world crude oil prices, partially offset by lower production from the South Monagas Unit, oil sales in Venezuela were 3.8 percent higher in 2002 compared with 2001. Realized fees per barrel increased 4.5 percent (from $12.52 in 2001 to $13.08 in 2002).

          Our revenues increased $4.6 million, or 3.6 percent, during the year ended 2002 compared with 2001. This was due to increased oil sales revenue in Venezuela as a result of increases in world crude oil prices, partially offset by lower sales quantities. Our sales quantities for the year ended 2002 from Venezuela were 9.7 MMBbls compared to 9.8 MMBbls for the year ended 2001. The decrease in sales quantities of 100,000 Bbls, or less than 1 percent, was due primarily to logistics and equipment delays in early 2002 at the Tucupita field and the Venezuelan national civil work stoppage which led to the shut-in of our production in late December 2002 for nine days. Average production for the year decreased by less than 775 Bbls per day for the aforementioned reasons.

          Our operating expenses decreased $8.8 million, or 21 percent, for the year ended 2002 compared with the year ended 2001. Lower fuel gas, water and oil treatments accounted for $3.4 million of the reduction. Reduced workover expense ($2.6 million) and lower expenses associated with the transportation of Tucupita oil ($5.0 million) with the completion of the Tucupita oil pipeline in late 2001 were offset by $1.1 million of increases in various other categories. Depletion, depreciation and amortization increased $0.8 million, or 4 percent, during the year ended 2002 compared with 2001 primarily due to the first three quarters of 2002 having been calculated on the lower beginning of the year reserves. Depletion expense per barrel of oil produced from Venezuela during 2002 was $2.56 compared with $2.26 during 2001 primarily due to future development costs. We recognized write-downs of capitalized costs of $13.4 million associated with WAB-21 offshore China and $1.1 million for the Lakeside Prospect exploration activities during the year ended 2002 compared with $0.5 million associated with final costs associated with prior exploration activities. General and administrative expenses decreased $3.6 million from 2001 to 2002. The move to Houston was completed in 2001 and overall staff levels were reduced to the current level of ten in Houston. We recognized $3.3 million of income for the partial recovery of prior year bad debt allowance for the funds received from the A.E. Benton bankruptcy. The consideration includes 600,000 shares of stock taken into treasury at a price of $3.56 per share and approximately $1.1 million in cash.

          Taxes other than on income decreased $1.3 million, or 24 percent, during the year ended 2002 compared with 2001. This was primarily due to decreased Venezuelan municipal taxes and a one-time adjustment of U.S. employment taxes of $0.7 million.

          Investment income and other decreased $1.0 million, or 33 percent, during the year ended 2002 compared with 2001. This was due to lower interest rates earned on average cash and marketable securities balances. Interest expense decreased $8.6 million, or 34 percent, during the year ended 2002 compared with 2001. We redeemed all $108 million of our 11.625 percent Senior Notes due in May 2003 and purchased $20 million face of the 9.375 percent Senior Notes due in November 2007. In October 2002, we borrowed $15.5 million to finance the construction of the gas pipeline in Venezuela from the Uracoa field to the PDVSA sales line.

          Net gain on exchange rates increased $3.8 million, or 493 percent for the year ended 2002 compared with 2001. This was due to the significant devaluation of the Bolivar. We realized income before income taxes and minority interest of $169.8 million during the year ended 2002 compared with $7.2 million in 2001. The increase was dominated by the Arctic Gas Sale. The 2001 income tax benefit related to the potential utilization by the Arctic Gas Sale of net operating loss carry forwards in 2002. Income tax expense decreased $105.0 million due to the reversal of a substantial portion of the valuation allowance on U.S. net operation loss carryforwards in 2001. The effective tax rate in 2002 of 36 percent reflects foreign income taxes incurred on profitable foreign operations and an increase in U.S. income with no corresponding U.S. taxes because they were offset by U.S. operating loss carryforwards for which the benefit was fully reserved in historical periods. The income before minority interests increased $3.8 million for the year ended 2002 compared with 2001. This was primarily due to the increased profitability (oil prices) and reduced expenses of Benton-Vinccler.

          Equity in net earnings of affiliated companies decreased $5.7 million, during the year ended 2002 compared with 2001. This was primarily due to the decreased income from Geoilbent and the elimination of Arctic Gas equity income on April 12, 2002, the date of its sale.

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Capital Resources and Liquidity

          The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks (see Risk Factors). We require capital principally to service our debt and to fund the following costs:

	•		drilling and completion costs of wells and the cost of production, treating and transportation facilities;
	•		geological, geophysical and seismic costs; and
	•		acquisition of interests in oil and gas properties.

          The amount of available capital will affect the scope of our operations and the rate of our growth. We began selling Venezuelan natural gas in November 2003, but our future rate of growth also depends substantially upon the prevailing prices of oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to service our debt.

          On February 5, 2003, the Government of Venezuela fixed the exchange rate between the Bolivar and the U.S. dollar, and restricted the ability to exchange Venezuelan Bolivars for U.S. dollars and vice versa. Initially the exchange rate was fixed at 1,600 Venezuelan Bolivars for each U.S. dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. dollar. Oil companies, such as Benton-Vinccler are allowed to receive payments for oil sales in U.S. dollars and pay U.S. dollar-denominated expenses from those payments. The full amount of the Bolivar denominated debt was repaid as of March 31, 2003. As of March 1, 2004, we have cash reserves of approximately $156.0 million and do not expect the currency conversion restriction to adversely affect our ability to meet our short-term loan obligations.

          Our ability to pay interest on our debt and general corporate overhead is dependent upon the ability of Benton-Vinccler to make loan repayments, dividends and other cash payments to us. However, there have been, and may again be, unforeseeable interruptions in oil and gas sales or there may be contractual obligations or legal impediments such as the recently instituted currency controls to receiving dividends or distributions from Benton-Vinccler, which could prohibit Benton-Vinccler from remitting funds to us. Management does not believe that the currency controls will prohibit our ability to receive funds from Benton-Vinccler, although were it to do so, our ability to meet our cash requirements would be adversely affected.

          Debt Reduction. We currently have a significant debt principal obligation payable in 2007 ($85 million). By September 24, 2004, we may be obligated to repay or prepay some portion of this debt with some of the net cash proceeds from the sale of Geoilbent (see Risk Factors). In 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan commercial bank for the construction of an oil pipeline. A portion of the loan was denominated in Bolivars and was repaid as of March 31, 2003.

          Working Capital. Our capital resources and liquidity are affected by the timing of our semiannual interest payments of approximately $4.0 million each May 1 and November 1 on the 9.375 percent Senior Notes due in November 2007 and by receipt of the quarterly payments from PDVSA at the end of the months of February, May, August and November pursuant to the terms of the operating service agreement for the South Monagas Unit. As a consequence of the timing of these interest payment outflows and the PDVSA payment inflows, our cash balances can increase and decrease dramatically on a few dates during the year. In each May and November in particular, interest payments at the beginning of the month and PDVSA payments at the end of the month create large swings in our cash balances.

          Benton-Vinccler’s oil and gas pipeline project loans allow the lender to accelerate repayment if production ceases for a period greater than thirty days. During the production shut-in which started in December 2002, Benton-Vinccler was granted a waiver of this provision until February 18, 2003 in exchange for a prepayment of the next two principal obligations aggregating $0.9 million. This prepayment, while using cash reserves, reduced our net interest expense as the current interest expense was more than the current interest income earned on the invested funds. On February 8, 2003, Benton-Vinccler commenced production, thereby eliminating the need for an additional waiver. A future disruption of production could trigger the debt acceleration provision again. While no assurances can be given, we believe Benton-Vinccler would be able to obtain another waiver under acceptable terms and conditions.

          The net funds raised and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:

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          At December 31, 2003, we had current assets of $183.4 million and current liabilities of $46.2 million, resulting in working capital of $137.2 million and a current ratio of 4.0:1. This compares with a working capital of $97.0 million and a current ration of 3.8:1 at December 31, 2002. The increase in working capital of $40.2 million was primarily due to the sale of our minority equity investment in Geoilbent.

          Cash Flow from Operating Activities. During the years ended December 31, 2003 and 2002, net cash provided by operating activities was approximately $38.5 million and $42.6 million, respectively. The $4.1 million decrease was primarily due to lower oil revenues offset by the commencement of gas sales in the fourth quarter of 2003.

          Cash Flow from Investing Activities. During the years ended December 31, 2003 and 2002, we had drilling and production-related capital expenditures of approximately $60.9 million and $43.3 million, respectively. Of the 2003 expenditures, $33.6 million was attributable to the development of the South Monagas Unit, $27.0 million to the construction of the gas pipeline and the balance for other administrative property.

          The timing and size of capital expenditures for the South Monagas Unit are entirely at our discretion. Our remaining capital commitments worldwide support our search for new acquisitions, and are relatively minimal and substantially at our discretion. We will also be required to make annual interest payments of approximately $8.0 million on the 2007 Notes.

          We continue to assess production levels and commodity prices in conjunction with our capital resources and liquidity requirements.

          Cash Flow from Financing Activities. During 2003, Benton-Vinccler repaid the balance of their Bolivar denominated debt of $2.2 million and other debt of $1.2 million. During 2002, we paid $108 million in 11.625 percent senior unsecured notes due May 1, 2003, $20 million in 9.375 percent senior unsecured notes due November 1, 2007 and Benton-Vinccler repaid other debt of $4.3 million. In November 1997, we issued $115 million in 9.375 percent senior unsecured notes due November 1, 2007, of which we repurchased $30 million. Interest on these notes is due May 1 and November 1 of each year. The indenture agreements provide for certain limitations on liens, additional indebtedness, certain investment and capital expenditures, dividends, mergers and sales of assets. At December 31, 2003, we were in compliance with all covenants of the indenture.

          Contractual Obligations. We have a lease obligation of approximately $11,000 per month for our Houston office space. This lease is valid through August 2004. The following table summarizes our contractual obligations at December 31, 2003.

          While we can give no assurance, we currently believe that our cash flow from operations coupled with our cash and marketable securities on hand will provide sufficient capital resources and liquidity to fund our planned capital expenditures, investments in and advances to affiliates, and semiannual interest payment obligations for the next 12 months. Our expectation is based upon our current estimate of projected prices, production levels, and our assumptions that there will be no further disruptions to our production and that PDVSA will timely pay our invoices. Actual results could be materially affected if there is a significant change in our expectations or assumptions. Future cash flows are subject to a number of variables including, but not limited to, the level of production and prices, as well

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as various economic and political conditions that have historically affected the oil and natural gas business. Additionally, prices for oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond our control.

          We currently have a significant debt obligation of $85 million payable in November 2007. Our ability to meet our debt obligation and to reduce our level of debt depends on the successful implementation of our business strategy.

Effects of Changing Prices, Foreign Exchange Rates and Inflation

          Our results of operations and cash flow are affected by changing oil prices. Fluctuations in oil and natural gas prices may affect our total planned development activities and capital expenditure program.

          As noted above under Capital Resources and Liquidity, Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004. We do not expect the currency conversion restrictions or the adjustment in the exchange rate to have a material impact on us at this time.

          Within the United States, inflation has had a minimal effect on us, but it is potentially an important factor in results of operations in Venezuela. With respect to Benton-Vinccler, a significant majority of the sources of funds, including the proceeds from oil sales, our contributions and credit financings, are denominated in U.S. dollars, while a minor amount of local transactions in Venezuela are conducted in local currency. If the rate of increase in the value of the U.S. dollar compared with the Bolivar continues to be less than the rate of inflation in Venezuela, then inflation could be expected to have an adverse effect on Benton-Vinccler.

          During the year ended December 31, 2002, our net foreign exchange gain attributable to our international operations was $4.6 million. The U.S. dollar and Bolivar exchange rates were fixed in February 2003 and no gains or losses were recognized after February 2003. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, many of which are beyond our control. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan currency to the U.S. dollar. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.

Critical Accounting Policies

Principles of Consolidation

          The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. The equity method of accounting is used for companies and other investments in which we have significant influence. All intercompany profits, transactions and balances have been eliminated. We account for our investment in Geoilbent and Arctic Gas based on a fiscal year ending September 30 prior to their respective sales.

          Oil and natural gas revenue is accrued monthly based on sales. Each quarter, Benton-Vinccler invoices PDVSA based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. dollar contract service fees per barrel.

Property and Equipment

          We follow the full cost method of accounting for oil and gas properties with costs accumulated in cost centers on a country-by-country basis. All costs associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized as incurred, including exploration overhead. Only overhead that is directly identified with acquisition, exploration or development activities is capitalized. All costs related to production, general corporate overhead and similar activities are expensed as incurred. The costs for China unproved properties are excluded from amortization until the properties are evaluated. At least annually, we evaluate our unproved property for possible impairment. If we abandon all exploration efforts in China where no proved reserves are assigned, all exploration and acquisition costs associated with the country will be expensed. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty.

          The full cost method of accounting uses proved reserves in the calculation of depletion, depreciation and amortization. Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids which geological

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and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place. Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors. A large portion of our proved reserves base from consolidated operations is comprised of oil and gas properties that are sensitive to oil price volatility. We are susceptible to significant upward and downward revisions to our Proved Reserve volumes and values as a result of changes in year end oil and gas prices and the corresponding adjustment to the projected economic life of such properties. Prices for oil and gas are likely to continue to be volatile, resulting in future revision to our Proved Reserve base. We perform a quarterly cost center ceiling test of our oil and gas properties under the full cost accounting rules of the SEC. These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter and require a write–down if our capitalized costs exceed this “ceiling,” even if prices declined for only a short period of time. We have had no write-downs due to these ceiling test limitations since 1998 other than the write-downs recorded by our equity affiliates. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved reserves will change in the near term. If oil and gas prices decline significantly in the future, even if only for a short period of time, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities.

Income Taxes

          Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

Foreign Currency

          Our current operations are in Venezuela. The U.S. dollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in U.S dollars, and all currency gains or losses are recorded in the statement of operations. We attempt to manage our operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan Bolivar to the U.S. dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates.

New Accounting Pronouncements

          In May 2003, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (the “Statement”). The Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The Statement is generally effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this Statement had no effect on our consolidated financial statements.

          In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”) Consolidation of Variable Interest Entities, which addresses the consolidation of variable interest entities (“VIEs”) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the

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majority of the risks or rewards associated with the VIE. In December 2003, the FASB issued a revision to FIN 46, Interpretation No. 46R (“FIN 46R”), to clarify some of the provisions of FIN 46, and to defer certain entities from adopting until the end of the first interim or annual reporting period ending after March 15, 2004. Application of FIN 46R is required in financial statements of public entities that have interests in structures that are commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application for all other types of VIEs is required in financial statements for periods ending after March 15, 2004. We believe we have no arrangements that would require the application of FIN 46R. We have no material off-balance sheet arrangements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

          We are exposed to market risk from adverse changes in oil and natural gas prices, interest rates, foreign exchange and political risk, as discussed below.

Oil Prices

          As an independent oil producer, our revenue, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control. Historically, prices received for oil production have been volatile and unpredictable, and such volatility is expected to continue. Through February 14, 2003, we utilized a costless collar hedge transaction with respect to a portion of our oil production to achieve a more predictable cash flow, and establish an acceptable rate of return on our Tucupita drilling program, as well as to reduce our exposure to price fluctuations. Benton-Vinccler hedged a portion of its 2003 oil production by purchasing a WTI crude oil “put” to protect its 2003 cash flow. Because gains or losses associated with hedging transactions are included in oil sales when the hedged production is delivered, such gains and losses are generally offset by similar changes in the realized prices of the commodities. See Note 1 – Derivatives and Hedging for a complete discussion of our derivative activity. Currently, we have no hedging transactions in place for our 2004 production.

Interest Rates

          Total long-term debt at December 31, 2003 of $96.8 million consisted of fixed-rate senior unsecured notes maturing in 2007 ($85.0 million). Benton-Vinccler has $11.8 million of U.S. dollar denominated variable rate loans. A hypothetical 10 percent adverse change in the interest rate would not have a material affect on our results of operations.

Foreign Exchange

          For the Venezuelan operations, oil and gas sales are received under a contract in effect through 2012 in U.S. dollars; expenditures are both in U.S. dollars and local currency. We have utilized no currency hedging programs to mitigate any risks associated with operations in these countries, and therefore our financial results are subject to favorable or unfavorable fluctuations in exchange rates and inflation in these countries. Venezuela has recently imposed currency exchange controls (see Capital Resources and Liquidity above).

Political Risk

          Political and economic uncertainty remains very high in Venezuela. During 2003, the production from the South Monagas Unit in Venezuela represented all of our total production from consolidated companies. Our production, revenue and cash flow will be adversely affected if production from the South Monagas Unit decreases significantly for any reason. From December 14, 2002 through February 6, 2003, no sales were made because of PDVSA’s inability to accept our oil due to the national civil work stoppage in Venezuela. As a result, 2002 sales were reduced by approximately 0.6 million barrels and 2003 sales were reduced by an estimated 1.2 million barrels. As a result of the Venezuelan national civil work stoppage, the Venezuelan government terminated several thousand PDVSA employees and announced a restructuring of PDVSA’s operations. Throughout 2003, there have been numerous organizational changes in PDVSA. As a result of the situation in PDVSA, its payment to Benton-Vinccler for crude delivered in the fourth quarter of 2002 was late by seven days. However, all other payments have been on time, and we believe PDVSA is committed to building its production levels and returning to more normalized business relations with its customers and suppliers.

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          There are ongoing efforts by opponents of President Chavez for a constitutional recall referendum. A successful recall referendum could lead to new presidential elections. These events create civil unrest and the possibility of work stoppages or disruptions. The political uncertainty and economic instability in Venezuela could adversely affect our operations and business prospects in that country. In addition, while the effect of the changes and the possible politicalization of PDVSA cannot be predicted, it could adversely affect PDVSA’s ability to manage its contracts and meet its obligations with its suppliers and vendors, such as Benton-Vinccler. Organizational instability and uncertainty at PDVSA could also adversely affect our ability to acquire new projects in Venezuela and the timing of those acquisitions. While we have substantial cash reserves to withstand a future disruption of sales, a prolonged loss of sales or a failure or delay by PDVSA to pay our invoices could have a material adverse effect on our financial condition.

Item 8. Financial Statements and Supplementary Data

          The information required by this item is included herein on pages S-1 through S-36.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

          None.

Item 9A. Controls and Procedures

          The SEC, among other things, adopted rules requiring reporting companies to maintain disclosure controls and procedures to provide reasonable assurance that a registrant is able to record, process, summarize and report the information required in the registrant’s quarterly and annual reports under the Securities Exchange Act of 1934 (the “Exchange Act”). While we believe that our existing disclosure controls and procedures have been effective to accomplish these objectives, we intend to continue to examine, refine and formalize our disclosure controls and procedures and to monitor ongoing developments in this area.

          Our principal executive officer and our principal financial officer have informed us that, based upon their evaluation, as of December 31, 2003, of our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Exchange Act), they have concluded that those disclosure controls and procedures are effective.

          There have been no changes in our internal controls or in other factors known to us that could significantly affect these controls subsequent to their evaluation, nor have we been required to take any corrective actions with regard to any significant deficiencies and material weaknesses.

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PART III

Item 10. Directors and Executive Officers of the Registrant

          Please refer to the information under the captions “Election of Directors” and “Executive Officers” in our Proxy Statement for the 2004 Annual Meeting of Shareholders.

Item 11. Executive Compensation

          Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the 2004 Annual Meeting of Shareholders.

Item 12. Security Ownership of Certain Beneficial Owners and Management

          Please refer to the information under the caption “Stock Ownership” in our Proxy Statement for the 2004 Annual Meeting of Shareholders.

Item 13. Certain Relationships and Related Transactions

          Please refer to the information under the caption “Certain Relationships and Related Transactions” in our Proxy Statement for the 2004 Annual Meeting of Shareholders.

Item 14. Principal Accounting Fees and Services

          Please refer to the “Independent Accountants” in our Proxy Statement for the 2004 Annual Meeting of Shareholders.

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PART IV

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

2.     Consolidated Financial Statement Schedules:

Schedule II       - - Valuation and Qualifying Accounts

Schedule III       - - Financial Statements and Notes for LLC Geoilbent

	All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto.

3.     Exhibits:

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(b) Reports on Form 8-K

     On October 10, 2003, we filed a Current Report on Form 8-K disclosing the Unaudited Pro Forma results from the sale of our minority equity investment in Geoilbent.

     On November 6, 2003, we filed a Current Report on Form 8-K announcing our third quarter and nine months net income and earnings.

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REPORT OF INDEPENDENT AUDITORS

To the Board of Directors
and Stockholders of Harvest Natural Resources, Inc.

     In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Harvest Natural Resources, Inc. and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement Schedule II – Valuation and Qualifying Accounts listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     As discussed in Note 1, the Company changed its method of accounting for employee stock-based compensation to the fair value based method effective January 1, 2003.

PricewaterhouseCoopers LLP

Houston, Texas
March 4, 2004

S-1

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

See accompanying notes to consolidated financial statements.

S-2

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS