(1)

No cash dividends were declared or paid during the periods presented.

Item 7.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Business Strategy      We intend to continue to identify, acquire and exploit known oil and natural gas fields in our current areas of interest and possibly other areas while maintaining our financial strength and flexibility. To accomplish this, we intend to: •   Seek to Deliver More Operating Cash Flow:In Venezuela, we seek to deliver more operating cash flow through the efficient management of our capital expenditure programs and cost structure. •   Focus Our Efforts in Areas of Low Geologic Risk:We intend to focus our activities principally in areas of large known but undeveloped or under-developed oil and gas resources. •   Seek Operational And Financial Control: We desire control of major decisions for development, production, staffing and financing for each project for a period of time sufficient for us to ensure maximum returns on investments. •   Establish a Local Presence Through Joint Venture Partners and the Use of Local Personnel:We seek to establish a local presence in our areas of operation to facilitate stronger relationships with local government and labor. In addition, using local personnel helps us to take advantage of local knowledge and experience and to minimize costs. In pursuing new opportunities, we will seek to enter at an early stage and find local partners in an effort to reduce our risk in any one venture. •   Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time:We are willing to agree to minimum capital expenditure or development commitments at the outset of new projects, but we endeavor to structure such commitments so that we can fulfill them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our 16 maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure. •   Limit Exploration Activities:We do not engage in exploration except in connection with the expansion of an existing reservoir and in that case only where the risks are deemed to be manageable in the context of total cash exposure and probability of success. •   Maintain A Prudent Financial Plan: We intend to maintain our financial flexibility by closely monitoring spending, holding significant cash reserves, actively seeking opportunities to reduce our weighted average cost of capital and increasing our liquidity. Risk Factors           In addition to the other information set forth elsewhere in thisForm 10-K, the following factors should be carefully considered when evaluating us.           Our concentrationonly source of assetsproduction may be reduced by actions of the Venezuelan Government. Currently, the production from the South Monagas Unit in Venezuela represents all of our production. Our revenue and cash flow will be adversely affected if we are not allowed to produce under our contract crude oil and natural gas at our projected levels. Recent events have increased the likelihood of this event occurring.           Under the operating service agreement Harvest Vinccler submits an annual budget to PDVSA for review and comment. Harvest Vinccler submitted to PDVSA its 2005 budget which provided for a $68 million drilling and facilities program. Under the terms of the operating service agreement this budget was deemed approved by PDVSA in November 2004. However, on December 17, 2004, Harvest Vinccler received letters from PDVSA seeking to reduce the 2005 drilling and facilities budget by over 60 percent and appearing to restrict average crude oil production for 2005 to about 20,400 barrels a day. At about the same time, Harvest Vinccler began to experience delays in the receipt of permits to drill new wells pursuant to its budget. In accordance with established procedures, Harvest Vinccler submitted requests to PDVSA to obtain permits from MEP for the drilling of eight wells. Only one of those requests was forwarded to the MEP. As a consequence of these delayed drilling permits, Harvest Vinccler began to run out of approved locations to continue its two-rig drilling program. On January 11, 2005, Harvest Vinccler formally notified one of its rig contractors that it would not be renewing its drilling contract and placed the rig on standby until January 29, 2005. Also, on January 11, 2005, Harvest Vinccler gave a thirty-day termination notice to the other rig company. On January 18, 2005, we announced that Harvest Vinccler was suspending its drilling program. In recent months, Harvest Vinccler has also experienced some operational interruptions in deliveries to PDVSA, although not of such a magnitude or duration as to affect production.           It has been reported that PDVSA has also sought to cut the budgets between 30 percent and 90 percent of the other 31 active operating service agreements in Venezuela. In addition, Rafael Ramirez, the President of PDVSA and Minister of MEP, has stated that PDVSA wants to renegotiate the terms of the operating service agreements as they are too costly, and that five or six of the operating service agreements have serious problems. It has been reported that one of these agreements is the South Monagas Unit operating service agreement held by Harvest Vinccler. Mr. Ramirez has also said that PDVSA will honor its contracts.           Collectively, these actions by the Venezuelan Government and PDVSA create a risk that our production will be reduced. Currently, Harvest Vinccler’s production has not been reduced, but if it is not allowed to conduct its drilling and facilities program, or if that program is restricted, then we will not meet our production forecasts and, over time, existing levels of production and available reserves will decline. While we believe such actions are not in accord with the operating service agreement, we and Harvest Vinccler are in discussions with Venezuelan officials and PDVSA to determine if these issues can be resolved through a mutually acceptable agreement. While we are hopeful of achieving a business solution, no assurance can be given that we will succeed or that the situation will not continue for an extended period of time. While we have substantial cash reserves, a prolonged curtailment of production or a failure or delay by PDVSA to pay our invoices could have a material adverse effect on our financial condition, results of operations and cash flows. 17 Political uncertainty in Venezuela increases our exposure to production disruptions and project execution risk.Political and economic uncertainty is very high in Venezuela. Currently, the production from the South Monagas Unit in Venezuela represents all of our production, and 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 inabilityPDVSA was unable to accept our oil due to the national civil work stoppage in Venezuela.Venezuela protesting the government of President Chavez. As a result, Harvest Vinccler’s 2002 salesoil deliveries were reduced by approximatelyan estimated 0.6 million barrels and 2003 salesdeliveries were reduced by an estimated 1.2 million barrels. As a result ofIn response to 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.employees. As a result of the situation in PDVSA, its payment to Benton-VincclerHarvest Vinccler for crude oil delivered in the fourth quarter of 2002 was late by seven days. However, since then all other payments have been on time, and we believetime.           Following the national work stoppage, President Chavez prevailed in a recall referendum. In addition, PDVSA has been reorganized a number of times, most recently in January 2005. The current President of PDVSA is committedalso the Minister of MEP. The political situation in Venezuela adds to building its production levelsthe risk that we will be able to enforce the operating service agreement in Venezuela and returning to more normalized business relations with its customers and suppliers.           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 createfurther civil unrest and the possibility of work stoppages or disruptions. The political uncertaintythat could affect our ability to produce crude oil and natural gas. In addition, the increasing integration of PDVSA into the governmental structure adds legal and economic instability in Venezuelauncertainty to our continued operations. These same risk factors 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. Acquiring new oil 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. It is our understanding that the MEP is still defining the methodology for the application of this law. While we have substantial cash reservesbelieve it is possible to withstand a future 16 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 Aprilcomply with this law 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 inat the same manner.time meet our criteria for new projects, no precedents exist and there is a risk we will be unable to achieve the desired result.           Our strategy to focus on Russia carries deal execution, operating, financial, legal and political risk.risks.While we believe our established presence in Russia and our experience and skills from prior operations positionsposition 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, our ability to 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.projects. 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 Our strategy in VenezuelaRussia depends uponon our ability to meethave operational and financial control. Recently, the requirements of the Organic Hydrocarbon Law.New oilRussian government has restricted certain “strategic” projects in Venezuela are governed by the Organic Hydrocarbon Law which requires that suchRussia to majority-owned Russia companies. Such a policy, if widely applied, could adversely affect our ability to acquire projects be carried out through incorporated joint venturesin Russia consistent 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.strategy.           Operations in areas outside the U.S. are subject to various risks inherent in foreign operations, and our strategy to primarily 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, nationalization, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and governmental royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts or tribunals, 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 policy, 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, seeCapital Resources and Liquiditybelow. 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 current18 17 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.control, including the risks associated with our sole operations in Venezuela. 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.           Our foreign operations expose us to foreign currency risk.Presently, our only operations are located in Venezuela. Venezuela continues to be considered a highly inflationary economy. Results of operations in that country are measured in U.S. Dollars with 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 may not be able to investhave recognized significant exchange gains and losses in the net cash proceedspast, resulting from fluctuations in the sale of Geoilbent in new oil and gas projects. The termsrelationship of the 2007 Notes requireVenezuelan 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. 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, seeCapital Resources and Liquiditybelow. Successful acquisition of projects in Russia may also expose us to foreign currency risk in 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.country.           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 $18.90 per Bbl for the year ended December 31, 2004, compared with $14.07 per Bbl for the year ended December 31, 2003, compared to $13.08 per Bbl for the year ended December 31, 2002.2003. 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 global supply of and demand for oil;     •    market uncertainty;     •    the level of consumer product demand;     •    weather conditions;     •    domestic and foreign governmental regulations;regulations and policies;     •    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, 18 plus the lower of cost or fair market value of unproved properties. The estimated future net cash flows include the impact of effective hedging activity as applicable. 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. TheWe did not incur ceiling test write-downs in 2004 in the consolidated financial statements of the wholly-owned and majority owned subsidiaries do not include ceiling test write-downs in 2003.subsidiaries. Equity in Net Losses of Affiliated Companies 19 includes a $32.3 million (our share) ceiling test write-down recorded by Geoilbent during their fiscal year endingended 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. SeeOur only source of production may be reduced by actions of the Venezuelan Government.           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, ability to deliver under the terms of our operating service agreement, approval of capital budgets and permits from PDVSA 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, 2003,2004, approximately 4744 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.certain than developed reserves. The estimated future development cost increased by over $39 million to develop the Undeveloped Reserves. 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. SeeSupplemental 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, policies 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. 19           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 20 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;     • delays in receiving necessary governmental permits; •   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. 20           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-VincclerHarvest 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 includeincluded 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 20012002 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 2001.2002.           You should read the following discussion of the results of operations for each of the years in the three-year period ended December 31, 20032004 and the financial condition as of December 31, 20032004 and 20022003 in conjunction with our Consolidated Financial Statements and related Notes thereto. 21           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   2002   2001         Operating Expenses     29 %     27 %     35 % Depletion, Depreciation and Amortization     20       21       21   General and Administrative     15       13       16   Taxes Other Than on Income     3       3       4   Interest     10       13       20                                 Years Ended December 31,       2004     2003     2002   Operating Expenses     18 %     29 %     27 % Depletion, Depreciation and Amortization     19       20       21   General and Administrative     12       15       13   Taxes Other Than on Income     3       3       3   Interest     4       10       13   Years ended December 31, 2004 and 2003           Net income for 2004 was $34.4 million, or $0.90 per diluted share, compared with $27.3 million, or $0.74 per diluted share for 2003.           Our results of operations for 2004 primarily reflected the results for Harvest-Vinccler in Venezuela, which accounted for all of our production and oil and gas sales revenue. Oil revenue per barrel increased 34 percent (from $14.07 in 2003 to $18.90 in 2004) and oil sales quantities increased 11 percent (from 7.3 MBbls of oil in 2003 to 8.2 MBbls of oil in 2004) during 2004 compared with 2003. Natural gas sales quantities for 2004 from Venezuela were 31.1 Bcf. Revenue for 2004 includes 0.7 MBbls of oil at a $7.00 fixed price associated with the gas sales contract.           Our revenues increased $80.0 million, or 75 percent, during 2004 compared with 2003. This was due to the addition of a full year of natural gas sales ($29.3 million), higher oil volumes ($7.7 million) and higher crude oil prices ($43.0 million). Our sales quantities for 2004 from Venezuela were 13.3 MBoe compared with 7.8 MBoe in 2003. The increase in sales quantities of 5.5 MBoe, or 71 percent, was due to a full year of natural gas production. Crude oil volumes for 2004 were also higher as 2003 was affected by the shut-in of the production in Venezuela from December 2002 to February 2003 due to the national work stoppage.           Our operating expenses increased $2.4 million, or 8 percent, for 2004 compared with 2003. This was primarily due to higher production volumes, higher workover and maintenance programs and increased insurance costs. Depletion, depreciation and amortization increased $14.8 million, or 70 percent, during 2004 compared with 2003 due to increased oil and gas production from Venezuela. Depletion expense per barrel of oil produced from Venezuela during 2004 was $2.56 compared with $2.52 during 2003. The increase was primarily due to increased future development costs. We recognized write-downs of $0.2 million for additional capitalized costs associated with former exploration projects during 2003. General and administrative expenses increased $6.1 million, or 39 percent, for 2004 compared with 2003. This was, in part, due to severance payments for a number of employees paid in the second quarter of 2004, the write-off of project evaluation costs associated with projects in Russia, restricted stock bonuses recorded in the third quarter 2004, additional costs associated with Sarbanes-Oxley compliance and an increase in liability under our deferred compensation plan for directors. An arbitration settlement of $1.5 million was recorded in 2003, and bad debt recoveries of $0.6 million and $0.4 million were recorded in 2004 and 2003, respectively, related to an allowance for uncollectible accounts in prior years.           Taxes other than on income increased $2.2 million, or 65 percent, during 2004 compared with 2003. This was primarily due to increased Venezuelan municipal taxes which result from higher oil and gas revenues.           Investment income and other increased $0.7 million, or 47 percent, during 2004 compared with 2003. This was due to higher interest rates earned on average cash balances. Interest expense decreased $2.7 million, or 26 percent, during 2004 compared with 2003 due to lower average outstanding debt balances for 2004 compared to 2003. In 2004, we redeemed all $85 million of our 2007 Notes, and we repaid all Bolivar denominated debt in March 2003.           Net gain (loss) on exchange rates decreased $1.2 million, or 218 percent, for 2004 compared with 2003. 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. 22           We realized income before income taxes and minority interest of $81.3 million during 2004 compared with income of $71.8 million in 2003. The increase was primarily attributable to higher crude oil and natural gas volumes and an increase in crude oil price in 2004 offset by the sale of our minority equity investment in Geoilbent in 2003. Income tax expense increased $23.6 million due to higher Venezuela pre-tax income. The effective tax rate increased from 13 to 41 percent for 2004 compared with 2003. The rate increase was due to foreign income taxes incurred on profitable foreign operations in 2004. The sale of our minority equity investment in Geoilbent in 2003 was offset by U.S. loss carryforwards. The income before minority interest decreased $14.2 million for 2004 compared with 2003. This decrease was due to the sale of our minority equity investment in Geoilbent partially offset by increased production of Harvest Vinccler.           Equity in net losses of affiliated companies decreased $28.9 million during 2004 compared to 2003. This was due to the elimination of Geoilbent equity losses on September 25, 2003, the date of its sale. 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, or $2.78 per diluted share, 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 (SeeNote 13 – Related Party Transactions).an allowance for uncollectible accounts in prior years. 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-VincclerHarvest 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. Revenue for 2003 includes 0.1 MMBbls of oil at the $7.00 fixed price associated with the gas sales contract.           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 21 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 20022002. The decrease was 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.an allowance for uncollectible accounts in prior years.           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 ofresult from lower 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 23 balances for the year ended 2003 compared towith 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. dollarDollar 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 interestsinterest 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.Harvest Vinccler.           Equity in net losses of affiliated companies decreased $29.0 million during the year 2003 from income of $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. SeeNote 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 (SeeNote 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. 22           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. 23 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 ourOur future rate of capital resource and liquidity 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,Dollar, and restricted the ability to exchange Venezuelan Bolivars for U.S. dollarsDollars and vice versa. Initially the exchange rate was fixed at 1,600 Venezuelan Bolivars for each U.S. dollar.Dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. dollar.Dollar. Oil companies, such as Benton-VincclerHarvest Vinccler are allowed to receive payments for oil sales in U.S. dollarsDollars and pay U.S. dollar-denominatedDollar-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, weWe have substantial cash reserves of approximately $156.0 million and do not expect the Venezuelan currency conversion restriction to adversely affect our ability to meet our short-term loan obligations.obligations and operating requirements for the next twelve months.           Our ability to pay interest on our debt and general corporate overheadreplace production with new reserves is dependent upon the ability of Benton-VincclerHarvest 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,Harvest Vinccler, which could prohibit Benton-Vinccler from remittingaffect the ability of Harvest Vinccler to remit funds to us. Management does not believe Debt Reduction.In September 2004, we announced 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 requirementsremaining 2007 Notes would be adversely affected. Debt Reduction.redeemed on November 1, 2004, and we irrevocably deposited with the Trustee for the 2007 Notes as trust funds $85.0 million plus accrued interest through November 1, 2004 and a prepayment call premium of $1.3 million to redeem the 2007 Notes on the redemption date. We currently have a significant debt principal obligation payable inwere released from all obligations related to the 2007 ($85 million). By September 24, 2004, we may be obligated to repay or prepay some portion of this debt with someNotes upon deposit of the net cash proceeds fromtrust funds with the saleTrustee. We recorded a loss on early extinguishment of Geoilbent (seeRisk Factors). In 2001, Benton-Vinccler borrowed $12.3debt of $2.9 million which includes the $1.3 million prepayment call premium, $0.7 million for interest related to the period October 1, 2004 to 24 November 1, 2004 and $0.9 million write-off of unamortized debt financing costs. Our repayment of the 2007 Notes triggered an obligation under the terms of Harvest Vinccler’s loans from a Venezuelan commercial bank forto renegotiate the constructionterms of an oil pipeline. A portionthose loans or, if agreement on renegotiated terms cannot be reached within 30 days after November 1, 2004, the loans can be declared due and payable. Harvest Vinccler is in discussions with the Venezuelan bank on possible renegotiated terms. While we believe the loans will be renegotiated, it is possible that agreement will not be reached and Harvest Vinccler will be required to repay the remaining balance of the loan was denominated in Bolivars and was repaid as$11.8 million. As of March 31, 2003.February 11, 2005, no agreement had been reached.           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’sHarvest Vinccler’s oil and gas pipeline project loans of $11.8 million 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.provision.           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: 24                               Year Ended December 31,         (in thousands)     2003   2002   2001         Net cash provided by operating activities   $ 38,538     $ 42,627     $ 36,608   Net cash provided by (used in) investing activities     38,191       126,143       (48,082 ) Net cash provided by (used in) financing activities     (2,570 )     (113,293 )     5,366                       Net increase (decrease) in cash   $ 74,159     $ 55,477     $ (6,108 )                                                   Year Ended December 31,               (in thousands)             2004     2003     2002   Net cash provided by operating activities   $ 74,140     $ 38,538     $ 42,627   Net cash provided by (used in) investing activities     (39,684 )     38,191       126,143   Net cash used in financing activities     (88,516 )     (2,570 )     (113,293 )                     Net increase (decrease) in cash   $ (54,060 )   $ 74,159     $ 55,477                                 At December 31, 2003,2004, we had current assets of $183.4$172.2 million and current liabilities of $46.2$83.2 million, resulting in working capital of $89.0 million and a current ratio of 2:1. This compares with a 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 3.8:4:1 at December 31, 2002.2003. The increasedecrease in working capital of $40.2$48.2 million was primarily due to the saleprepayment of our minority equity investmentthe 2007 Notes offset by higher crude oil prices and an increase in Geoilbent.crude oil and natural gas sales in Venezuela.           Cash Flow from Operating Activities.Activities. During the years ended December 31, 20032004 and 2002,2003, net cash provided by operating activities was approximately $38.5$74.1 million and $42.6$38.5 million, respectively. The $4.1$35.6 million decreaseincrease was primarily due to lowernatural gas sales, higher crude oil revenuesprices and the sale of our California onshore property, offset by Harvest Vinccler’s purchase of two WTI crude oil puts and the commencementloss of gas sales in$2.9 million on the fourth quarterearly repayment of 2003.the 2007 Notes. As of September 30, 2004, we no longer have an obligation to make annual interest payments of approximately $8.0 million on the 2007 Notes.           Cash Flow from Investing Activities.During the years ended December 31, 20032004 and 2002,2003, we had drilling and production-related capital expenditures of approximately $39.1 million and $60.9 million, and $43.3 million, respectively. Of the 2003The decrease in capital expenditures $33.6 million was attributableis due to the developmentcompletion of the South Monagas Unit, $27.0 million to the construction of theour gas pipelineproject in 2003 and the balance for other administrative property.timing of our 2004 Uracoa drilling program. The year ended 2003 included the receipt of $69.5 million from the sale of our minority equity investment in Geoilbent.           The timing and size of capital expenditures for the South Monagas Unit are entirelylargely at our discretion.discretion, although PDVSA has recently attempted to limit Harvest Vinccler’s capital spending (seeRisk Factors). Our remaining capital commitments worldwide support our search for new acquisitions, and are relatively minimal and are 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 the year ended 2004, we irrevocably deposited with the Trustee for our 2007 Notes as trust funds $85.0 million plus accrued interest through November 1, 2004 and a prepayment call premium of $1.3 million to redeem the 2007 Notes on the redemption date. During the same period, Harvest Vinccler repaid $6.4 million of its U.S. Dollar denominated debt. During the year ended 2003, Benton-Vinccler Harvest Vinccler 25 repaid the balanceall of theirits Bolivar denominated debt ($2.2 million) and $1.2 million of $2.2 million and otherits U.S. Dollar 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 covenantswas an acceleration of the indenture.next two principal payments.           Contractual Obligations.We have a lease obligation of approximately $11,000$17,000 per month for our Houston office space. This lease is validruns through August 2004.April 2014. In addition, Harvest Vinccler leased new office space in Maturin and Caracas, Venezuela for $13,200 and $4,000 per month, respectively. The following table summarizes our contractual obligationsBoard of Directors Deferred Compensation Plan at December 31, 2003.                                       Payments (in thousands) Due by Period                 Less than                 Contractual Obligation   Total   1 Year   1-3 Years   3-5 Years         Long Term Debt   $ 103,200     $ 6,367     $ 6,367     $ 90,466   Office Lease     88       88       —       —                             Total   $ 103,288     $ 6,455     $ 6,367     $ 90,466                             2004 represents 106,000 phantom stock shares with an aggregate liability of $1.8 million, or $17.27 per share, based on the December 31, 2004 stock price.                                               Payments (in thousands) Due by Period               Less than                     After 4   Contractual Obligation   Total     1 Year     1-2 Years     3-4Years     Years   Long-Term Debt   $ 11,833     $ 11,833     $ —     $ —     $ —   Building Lease     3,117       415       421       388       1,893                                   Total   $ 14,950     $ 12,248     $ 421     $ 388     $ 1,893                                             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 semiannualquarterly 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 we will be allowed to carry out our capital program on acceptable terms, that there will be no further disruptions toor limitations on our production and that PDVSA will timely pay our invoices.invoices timely. Actual results could be materially affected if there is a significant change in our expectations or assumptions.assumptions (seeRisk Factors). Future cash flows are subject to a number of variables including, but not limited to, the level of production and prices, as well 25 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. In August and September 2004, Harvest Vinccler hedged a portion of its oil sales for calendar year 2005 by purchasing two WTI crude oil puts. SeeNote 1 – Derivatives and Hedging.           As noted above underCapital 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,Harvest 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,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. dollarDollar 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.Harvest Vinccler.           During the year ended December 31, 2002,2004, our net foreign exchange gainloss attributable to our international operations was $4.6$0.6 million. The U.S. dollarDollar and Bolivar exchange rates were fixed in February 2003 and noadjusted in February 2004. No gains or losses were recognized afterfrom February 2003.2003 to February 2004. 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.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. 26 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 accountaccounted 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-VincclerHarvest Vinccler invoices PDVSA based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. dollarDollar 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 26 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, economic changes and economic changes.other relevant developments. 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.factors and other relevant developments. 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. 27 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. dollarDollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in U.S dollars,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.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,December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard No. 150 “Accounting123 (revised 2004) Share-Based Payment (“SFAS 123R”), an amendment to Statement of Accounting Standards 123 and 95. SFAS 123R focuses primarily on accounting for Certain Financial Instrumentstransactions in which an entity obtains employee services in share-based payment transactions. Public companies with Characteristicsa calendar year end will be required to adopt the provisions 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 generallythe standard effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim periodperiods beginning after June 15, 2003. The adoption of this Statement had no2005. We do not expect SFAS 123R to have a material effect on our consolidated financial statements.position, results of operation or cash flows.           In December 2004, the FASB issued Statement of Financial Accounting Standard 153 Exchanges on Nonmonetary Assets (“SFAS 153”), an amendment of Accounting Principles Board (“APB”) Opinion No. 29 (“Opinion 29”). SFAS 153 amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. We do not expect SFAS 153 to have a material effect on our consolidated financial position, results of operation or cash flows.           In September 2004, the SEC issued Staff Accounting Bulletin 106 (“SAB 106”) which provides guidance regarding the interaction of SFAS 143 with the calculation of depletion and the full cost ceiling test of oil and gas properties under the full cost accounting rules of the SEC. The guidance provided in SAB 106 is not expected to have a material effect on our consolidated financial position, results of operation or cash flows.           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 27 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. 28 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 and 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-VincclerHarvest Vinccler hedged a portion of its 2003 oil production by purchasing a WTI crude oil “put” to protect its 2003 cash flow. In August and September 2004, Harvest Vinccler hedged a portion of its oil sales for calendar year 2005 by purchasing two WTI crude oil puts. 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. SeeNote 1 – Derivatives and Hedgingfor a complete discussion of our derivative activity. Currently, we haveWe had no hedging transactions in place for our 2004 production. Interest Rates           Total long-termshort-term debt at December 31, 20032004 of $96.8$11.8 million consisted of fixed-rate senior unsecured notes maturing in 2007 ($85.0 million). Benton-Vinccler has $11.8 million ofHarvest Vinccler U.S. dollarDollar 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;Dollars; expenditures are both in U.S. dollarsDollars 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 (seeCapital Resources and Liquidityabove). 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. 28           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.S-33. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure           None. Item 9A. Controls and Procedures           The SEC,Securities and Exchange Commission, 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 officer29 Evaluation of Disclosure Controls and Procedures.We have established disclosure controls and procedures to ensure that material information relating to us, including our principalconsolidated subsidiaries, is made known to the officers who certify our financial officer have informed us that, based uponreports and to other members of senior management and the Board of Directors.      Based on their evaluation as of December 31, 2003, of2004, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in RuleRules 13a-15(e) and Rule 15d-15(e) under the Exchange Act), they have are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods as specified in the Securities and Exchange Commission rules and forms. Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the Internal Control Integrated Framework, our management 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 deficienciescontrol over financial reporting was effective as of December 31, 2004. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004, and material weaknesses.issued an attestation report which is included herein. 29Item 9B. Other Information      None. 30 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 20042005 Annual Meeting of Shareholders. Item 11. Executive Compensation      Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the 20042005 Annual Meeting of Shareholders. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      Please refer to the information under the caption “Stock Ownership” in our Proxy Statement for the 20042005 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 20042005 Annual Meeting of Shareholders. Item 14. Principal Accounting Fees and Services      Please refer to the information under the caption “Independent Accountants”Registered Public Accounting Firm” in our Proxy Statement for the 20042005 Annual Meeting of Shareholders. 3031 PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) 1. Index to Financial Statements: Page Report of Independent Registered Public Accounting Firm S-1 Consolidated Balance Sheets at December 31, 2004 and 2003 S-2 Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2004, 2003 and 2002 S-3 Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2004, 2003 and 2002 S-4 Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002 S-5 Notes to Consolidated Financial Statements S-7 2. Consolidated Financial Statement Schedules and Other: Schedule II - Valuation and Qualifying Accounts                   Page Financial Statements and Notes for LLC Geoilbent, a significant equity investment         (a) 1.   Index to Financial Statements:         Report of Independent Auditors S-1     Consolidated Balance Sheets at December 31, 2003 and 2002 S-2 Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001 S-3 Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2003, 2002 and 2001 S-4 Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001 S-5 Notes to Consolidated Financial Statements S-7 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: 3.     Exhibits:                   3.1     Amended and Restated Certificate of Incorporation filed September 9, 1988Incorporation. (Incorporated by reference to Exhibit 3.13.1(i) to our Registration Statement (RegistrationForm 10-Q filed on August 13, 2002, File No. 33-26333)1-10762.).                   3.2     AmendmentAmended and Restated Bylaws as of December 11, 2003. (Incorporated by reference to Certificate of Incorporation filed June 7, 1991 (Previously filed as an exhibitExhibit 3.7 to our S-1 Registration Statement (RegistrationForm 10-K filed on March 10, 2004, File No. 33-39214)1-10762.).                   3.34.1     Amended and Restated Bylaws asForm of December 11, 2003.Common Stock Certificate. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-26333).)               4.1 Form of Common Stock Certificate (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-26333)).     4.2     Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.)       4.3 Rights Agreement between Benton Oil and Gas Company and First Interstate Bank, Rights Agent dated April 28, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on August 13, 2002, File No. 1-10762.)             10.14.3     FormAmended and Restated Rights Agreement, dated as of Employment Agreements (Exhibit 10.19)(Previously filed as an exhibitSeptember 16, 2003, between Harvest Natural Resources, Inc. and Wells Fargo Bank Minnesota, N.A. (incorporated by reference to Exhibit 5 to Amendment No. 1 to our S-1 Registration Statement on Form 8-A filed October 29, 2003 (Registration No. 33-26333)000-17534)).                   10.210.1     Operating Service Agreement between Benton Oil and Gas Company and Lagoven, S.A., which has been subsequently combined into PDVSA Petroleo y Gas, S.A., dated July 31, 1992, (portions have been omitted pursuant to Rule 406 promulgated under the Securities Act of 1933 and filed separately with the Securities and Exchange Commission—Exhibit 10.25)(Previously filed as an exhibitCommission. (Incorporated by reference to the exhibits to our S-1 Registration Statement Form S-1 (Registration No. 33-52436).). 3132                   10.3 Indenture dated November 1, 1997 between Benton Oil and Gas Company and First Trust of New York, National Association, Trustee related to an aggregate of $115,000,000 principal amount of 9 3/8 percent Senior Notes due 2007 (Incorporated by reference to Exhibit 10.1 to our Form 10-Q for the quarter ended September 30, 1997, File No. 1-10762). 10.410.2     Note payable agreement dated March 8, 2001 between Benton-Vinccler,Harvest Vinccler, C.A. and Banco Mercantil, C.A. related to a note in the principal amount of $6,000,000 with interest at LIBOR plus five percent, for financing of Tucupita PipelinePipeline. (Incorporated by reference to Exhibit 10.24 to our Form 10-Q, filed on May 15, 2001, File No. 1-10762).1-10762.)                 10.5 10.3†   Change of Control Severance Agreement effective May 4, 20012001. (Incorporated by reference to Exhibit 10.26 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.).                   10.610.4     Alexander E. Benton Settlement and Release Agreement effective May 11, 2001 (Incorporated by reference to Exhibit 10.27 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.).                   10.710.5     First Amendment to Change of Control Severance Plan effective June 5, 20012001. (Incorporated by reference to Exhibit 10.31 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.).                   10.810.6     Sale and Purchase Agreement dated February 27, 2002 between Benton Oil and Gas Company and Sequential Holdings Russian Investors Limited regarding the sale of Benton Oil and Gas Company’s 68 percent interest in Arctic Gas Company. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on March 28, 2002, File No. 1-10762.)                   10.910.7     2001 Long Term Stock Incentive PlanPlan. (Incorporated by reference to Exhibit 4.1 to our S-8 (Registration Statement No. 333-85900).).                   10.1010.8     Addendum No. 2 to Operating Services Agreementservice agreement Monagas SUR dated 19th19th September, 2002. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)                   10.1110.9     Bank Loan Agreement between Banco Mercantil, C.A. and Benton-VincclerHarvest Vinccler C.A. dated October 1, 2002. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)                   10.1210.10     Guaranty issued by Harvest Natural Resources, Inc. dated September 26, 2002. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)                 10.13 10.11†   Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Peter J. Hill. (Incorporated by reference to Exhibit 10.10 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)                 10.14 10.12†   Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.11 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)                 10.15 10.13†   Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.12 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)                 10.16 10.14†   Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.13 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)                   10.1710.15     Sale and Purchase Agreement dated September 26, 2003, between Harvest Natural Resources, Inc. and Yukos Operational Holding Limited regarding the sale of our 34 percent minority equity investment in LLC Geoilbent. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 10, 2003, File No. 1-10762.)                 10.18 10.16†   Employment Agreement dated November 17, 2003 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.18 to our Form 10-Q filed on March 10, 2004, File No. 1-10762.) 33 32                 10.17†   Employment Agreement dated September 1, 2004 between Harvest Natural Resources, Inc. and Karl L. Nesselrode.James A. Edmiston. (Incorporated by reference to Exhibit 10-1 to our Form 10-Q filed on November 5, 2004, File No. 1-10762.)               10.18† Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).) 10.19† Indemnification Agreement between Harvest Natural Resources, Inc. and the Directors and Executive Officers of the Company. 10.20† Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement 10.21† Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement 10.22† Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement     21.1     List of subsidiaries.                   23.1     Consent of PricewaterhouseCoopers LLP -— Houston                   23.2     Consent of ZAO PricewaterhouseCoopers Audit -— Moscow                   23.3     Consent of Ryder Scott Company, LP                   31.1     Certification of the Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                   31.2     Certification of the Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.       32.1     CertificationsCertification of the Chief Executive Officer accompanying the annual report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of the Chief Financial Officer accompanying the annual report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. † Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K. (b) Reports on Form 8-K On October 10, 2003,November 4, 2004, we filed a Current Report on Form 8-K disclosingwith the Unaudited Pro FormaSecurities and Exchange Commission in which we furnished a press release announcing our results fromfor the salethird quarter ended September 30, 2004 and furnishing the following financial statements: (i) Consolidated Balance Sheets for the Period Ended September 30, 2004 and December 31, 2003; (ii) Consolidated Statements of our minority equity investment in Geoilbent.Operations for the Three and Nine Months Ended September 30, 2004 and 2003; and (iii) Consolidated Statement of Cash Flows for the Three and Nine Months Ended September 30, 2004 and 2003. On November 6, 2003,December 14, 2004, we filed a Current Report on Form 8-K announcing our third quarterwith the Securities and nine months net incomeExchange Commission in which we furnished a press release providing financial and earnings.operating guidance assumptions for 2005. 3334 REPORT OF INDEPENDENT AUDITORSREGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Harvest Natural Resources, Inc.:      We have completed an integrated audit of Harvest Natural Resources, Inc.’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004, and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below. Consolidated financial statements and financial statement schedule      In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)15 (a)(1) present fairly, in all material respects, the financial position of Harvest Natural Resources, Inc. and its subsidiaries at December 31, 20032004 and 2002,2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20032004 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 Accountsschedule listed in the indexappearing 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; ourmanagement. 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 auditingthe standards generally accepted inof the United States of America, whichPublic Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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. Internal control over financial reporting      Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.      A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. PricewaterhouseCoopers LLP Houston, Texas March 4, 2004February 22, 2005 S-1 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS                                       December 31,                         2003   2002                           (in thousands, except per             share data)         ASSETS                 Current Assets:                   Cash and cash equivalents   $ 138,660     $ 64,501     Restricted cash     12       1,812     Marketable securities     —       27,388     Accounts and notes receivable:                     Accrued oil sales     32,766       27,359       Joint interest and other, net     11,197       8,002     Prepaid expenses and other     805       2,969                         Total Current Assets     183,440       132,031   Restricted Cash     16       16   Other Assets     2,080       2,520   Deferred Income Taxes     4,749       4,082   Investments In and Advances To Affiliated Companies     —       51,783   Property and Equipment:                   Oil and gas properties (full cost method-costs of $2,900 excluded from amortization in 2003 and 2002, respectively)     593,622       576,601     Other administrative property     8,948       7,503                         602,570       584,104     Accumulated depletion, depreciation, and amortization     (418,507 )     (439,344 )                       Net Property and Equipment     184,063       144,760                       $ 374,348     $ 335,192                           LIABILITIES AND STOCKHOLDERS’ EQUITY                 Current Liabilities:                   Accounts payable, trade and other   $ 4,163     $ 3,804     Accounts payable, related party     10,375       9,779     Accrued expenses     15,251       10,865     Accrued interest payable     1,427       1,405     Income taxes payable     8,647       6,880     Commodity hedging contract     —       430     Current portion of long-term debt     6,367       1,867                         Total Current Liabilities     46,230       35,030   Long-Term Debt     96,833       104,700   Asset Retirement Liability     1,459       —   Commitments and Contingencies     —       —   Minority Interest     30,113       24,145   Stockholders’ Equity:                 Preferred stock, par value $0.01 a share; Authorized 5,000 shares; outstanding, none Common stock, par value $0.01 a share; Authorized 80,000 shares at December 31, 2003 and 2002; issued 36,405 shares and 35,900 shares at December 31, 2003 and 2002, respectively     364       359     Additional paid-in capital     175,051       173,559     Retained earnings     27,537       234     Treasury stock, at cost, 730 shares and 650 shares at December 31, 2003 and 2002, respectively     (3,239 )     (2,835 )                       Total Stockholders’ Equity     199,713       171,317                       $ 374,348     $ 335,192                                         December 31,       2004     2003       (in thousands, except per       share data)   ASSETS                 Current Assets:                 Cash and cash equivalents   $ 84,600     $ 138,660   Restricted cash     12       12   Accounts and notes receivable:                 Accrued oil sales     58,937       32,766   Joint interest and other, net     12,780       11,197   Put options     14,209       —   Deferred income tax     251       —   Prepaid expenses and other     1,426       805                 Total Current Assets     172,215       183,440   Restricted Cash     16       16   Other Assets     2,072       2,080   Deferred Income Taxes     6,034       4,749   Property and Equipment:                 Oil and gas properties (full cost method-costs of $2,900 excluded from amortization in 2004 and 2003, respectively)     631,082       593,622   Other administrative property     10,008       8,948                       641,090       602,570   Accumulated depletion, depreciation, and amortization     (453,941 )     (418,507 )               Net Property and Equipment     187,149       184,063                     $ 367,486     $ 374,348                                   LIABILITIES AND STOCKHOLDERS’ EQUITY                 Current Liabilities:                 Accounts payable, trade and other   $ 8,428     $ 4,163   Accounts payable, related party     11,063       10,557   Accrued expenses     29,355       15,069   Accrued interest payable     71       1,427   Income taxes payable     22,475       8,647   Current portion of long-term debt     11,833       6,367                 Total Current Liabilities     83,225       46,230   Long-Term Debt     —       96,833   Asset Retirement Liability     1,941       1,459   Commitments and Contingencies     —       —   Minority Interest     39,131       30,113   Stockholders’ Equity:                 Preferred stock, par value $0.01 a share; Authorized 5,000 shares; outstanding, none Common stock, par value $0.01 a share; Authorized 80,000 shares at December 31, 2004 and 2003; issued 37,544 shares and 36,405 shares at December 31, 2004 and 2003, respectively     375       364   Additional paid-in capital     185,183       175,051   Retained earnings     61,897       27,537   Accumulated other comprehensive loss     (487 )     —   Treasury stock, at cost, 764 shares and 730 shares at December 31, 2004 and 2003, respectively     (3,779 )     (3,239 )               Total Stockholders’ Equity     243,189       199,713                     $ 367,486     $ 374,348                 See accompanying notes to consolidated financial statements. S-2 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS                                   Years Ended December 31,             2003   2002   2001                 (in thousands, except per share data) Revenues                           Oil sales   $ 103,920     $ 127,015     $ 122,386     Gas sales     2,740       —       —     Ineffective hedge activity     (565 )     (284 )     —                             106,095       126,731       122,386                       Expenses                           Operating expenses     30,893       33,950       42,759     Depletion, depreciation and amortization     21,188       26,363       25,516     Write-downs of oil and gas properties and impairments     165       14,537       468     General and administrative     15,746       16,504       20,072     Arbitration settlement     1,477       —       —     Bad debt recovery     (374 )     (3,276 )     —     Taxes other than on income     3,373       4,068       5,370                             72,468       92,146       94,185                       Income from Operations     33,627       34,585       28,201   Other Non-Operating Income (Expense)                           Gain on disposition of assets     46,619       144,029       —     Gain on early extinguishment of debt     —       874       —     Investment earnings and other     1,418       2,080       3,088     Interest expense     (10,405 )     (16,310 )     (24,875 )   Net gain on exchange rates     529       4,553       768                             38,161       135,226       (21,019 )                     Income from Consolidated Companies Before Income                           Taxes and Minority Interest     71,788       169,811       7,182   Income Tax Expense (Benefit)     9,657       60,295       (35,698 )                     Income Before Minority Interest     62,131       109,516       42,880   Minority Interest in Consolidated Subsidiary Companies     5,968       9,319       5,545                       Income from Consolidated Companies     56,163       100,197       37,335   Equity in Net Income (Losses) of Affiliated Companies     (28,860 )     165       5,902                       Net Income   $ 27,303     $ 100,362     $ 43,237                       Net Income Per Common Share:                           Basic   $ 0.77     $ 2.90     $ 1.27                         Diluted   $ 0.74     $ 2.78     $ 1.27                       AND COMPREHENSIVE INCOME                               Years Ended December 31,       2004     2003     2002       (in thousands, except per share data)   Revenues                         Oil sales   $ 154,075     $ 103,920     $ 127,015   Gas sales     31,991       2,740       —   Ineffective hedge activity     —       (565 )     (284 )                           186,066       106,095       126,731                                                 Expenses                         Operating expenses     33,324       30,893       33,950   Depletion, depreciation and amortization     36,020       21,188       26,363   Write-downs of oil and gas properties and impairments     —       165       14,537   General and administrative     21,857       15,746       16,504   Arbitration settlement     —       1,477       —   Bad debt recovery     (598 )     (374 )     (3,276 ) Gain on sale of long-lived asset     (578 )     —       —   Taxes other than on income     5,561       3,373       4,068                             95,586       72,468       92,146                                                 Income from Operations     90,480       33,627       34,585   Other Non-Operating Income (Expense)                         Gain on disposition of investment     —       46,619       144,029   Gain (loss) on early extinguishment of debt     (2,928 )     —       874   Investment earnings and other     2,085       1,418       2,080   Interest expense     (7,749 )     (10,405 )     (16,310 ) Net gain (loss) on exchange rates     (622 )     529       4,553                             (9,214 )     38,161       135,226                                                 Income from Consolidated Companies Before Income Taxes and Minority Interest     81,266       71,788       169,811   Income Tax Expense     33,288       9,657       60,295                       Income Before Minority Interest     47,978       62,131       109,516   Minority Interest in Consolidated Subsidiary Companies     13,618       5,968       9,319                       Income from Consolidated Companies     34,360       56,163       100,197   Equity in Net Income (Losses) of Affiliated Companies     —       (28,860 )     165                       Net Income   $ 34,360     $ 27,303     $ 100,362                                                 Net Income Per Common Share:                         Basic   $ 0.95     $ 0.77     $ 2.90                       Diluted   $ 0.90     $ 0.74     $ 2.78                                                 Other comprehensive loss:                         Unrealized mark to market loss from cash flow hedging activities, net of tax     (487 )     —       —                       Comprehensive income   $ 33,873     $ 27,303     $ 100,362                       See accompanying notes to consolidated financial statements. S-3 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (in thousands)                                                                                   Retained                       Common           Additional   Earnings                       Shares   Common   Paid-in   (Accumulated   Treasury               Issued   Stock   Capital   Deficit)   Stock   Total                 Balance at January 1, 2001     33,872     $ 339     $ 156,629     $ (143,365 )   $ (699 )   $ 12,904   Issuance of common shares:                                                   Non-employee director compensation     292       3       471       —       —       474   Tax benefits related to stock option compensation     —       —       11,008       —       —       11,008   Net Income     —       —       —       43,237       —       43,237                                         Balance at December 31, 2001     34,164       342       168,108       (100,128 )     (699 )     67,623   Issuance of common shares:                                                   Non-employee director compensation     46       —       543       —       —       543     Employee compensation     175       2       663       —       —       665     Exercise of stock options     1,515       15       4,245       —       —       4,260   Treasury stock (600 shares)     —       —       —       —       (2,136 )     (2,136 ) Net Income     —       —       —       100,362       —       100,362                                         Balance at December 31, 2002     35,900       359       173,559       234       (2,835 )     171,317   Issuance of common shares:                                                   Exercise of stock options     505       5       1,196       —       —       1,201     Employee stock based compensation     —       —       296       —       —       296   Treasury stock (80 shares)     —       —       —       —       (404 )     (404 ) Net Income     —       —       —       27,303       —       27,303                                         Balance at December 31, 2003     36,405     $ 364     $ 175,051     $ 27,537     $ (3,239 )   $ 199,713                                                                                                                               Retained     Accumulated                   Common             Additional     Earnings     Other                   Shares     Common     Paid-in     (Accumulated     Comprehensive     Treasury             Issued     Stock     Capital     Deficit)     Loss     Stock     Total                                                             Balance at January 1, 2002     34,164     $ 342     $ 168,108     $ (100,128 )   $ —     $ (699 )   $ 67,623                                                             Issuance of common shares:                                                         Non-employee director compensation     46       —       543       —       —       —       543   Employee compensation     175       2       663       —       —       —       665   Exercise of stock options     1,515       15       4,245       —       —       —       4,260   Treasury stock (600 shares)     —       —       —       —       —       (2,136 )     (2,136 ) Net Income     —       —       —       100,362       —       —       100,362                                               Balance at December 31, 2002     35,900       359       173,559       234       —       (2,835 )     171,317                                                             Issuance of common shares:                                                         Exercise of stock options     505       5       1,196       —       —       —       1,201   Employee stock based compensation     —       —       296       —       —       —       296   Treasury stock (80 shares)     —       —       —       —       —       (404 )     (404 ) Net Income     —       —       —       27,303       —       —       27,303                                               Balance at December 31, 2003     36,405       364       175,051       27,537       —       (3,239 )     199,713                                                             Issuance of common shares:                                                         Exercise of warrants     53       —       600       —       —       —       600   Exercise of stock options     1,001       10       7,381       —       —       —       7,391   Employee stock-based compensation     85       1       2,151       —       —       —       2,152   Treasury stock (34 shares)     —       —       —       —       —       (540 )     (540 ) Accumulated other comprehensive loss     —       —       —       —       (487 )     —       (487 ) Net Income     —       —       —       34,360       —       —       34,360                                                                                                         Balance at December 31, 2004     37,544     $ 375     $ 185,183     $ 61,897     $ (487 )   $ (3,779 )   $ 243,189                                               See accompanying notes to consolidated financial statements. S-4 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)                                           Years Ended December 31,                     2003   2002   2001                         (in thousands) Cash Flows From Operating Activities:                           Net income   $ 27,303     $ 100,362     $ 43,237     Adjustments to reconcile net income to net cash provided by operating activities:                             Depletion, depreciation and amortization     21,188       26,363       25,516       Write-down and impairment of oil and gas properties     165       14,537       468       Amortization of financing costs     497       1,745       1,179       Gain on disposition of assets     (46,619 )     (144,029 )     (336 )     Equity in net earnings (losses) of affiliated companies     28,860       (165 )     (5,902 )     Allowance for employee notes and accounts receivable     (169 )     (2,987 )     365       Non-cash compensation related charges     296       1,458       474       Minority interest in undistributed earnings of subsidiaries     5,968       9,319       5,545       Gain from early extinguishment of debt     —       (874 )     —       Tax benefits related to stock option compensation     —       —       11,008       Deferred income taxes     (667 )     53,618       (53,407 )   Changes in operating assets and liabilities:                             Accounts and notes receivable     (7,935 )     (1,972 )     11,756       Prepaid expenses and other     2,164       (1,130 )     565       Accounts payable     359       (4,328 )     (4,671 )     Accounts payable, related party     4,386       (604 )     (1,662 )     Accrued interest payable     22       (2,489 )     161       Accrued expenses     (76 )     (9,686 )     1,705       Asset retirement liability     1,459       —       —       Commodity hedging contract     (430 )     430       —       Income taxes payable     1,767       3,059       607                             Net Cash Provided by Operating Activities     38,538       42,627       36,608                       Cash Flows from Investing Activities:                           Proceeds from sale of investment     69,500       189,841       —     Additions of property and equipment     (60,925 )     (43,346 )     (43,364 )   Investment in and advances to affiliated companies     2,328       9,185       (16,855 )   Increase in restricted cash     —       (2,800 )     (57 )   Decrease in restricted cash     1,800       1,000       10,961     Purchases of marketable securities     (256,058 )     (353,478 )     (15,067 )   Maturities of marketable securities     283,446       326,090       16,370     Investment selling costs     (1,900 )     (349 )     (70 )                         Net Cash Provided by (Used In) Investing Activities     38,191       126,143       (48,082 )                     Cash Flows from Financing Activities:                           Net proceeds from exercise of stock options     1,201       3,345       —     Purchase of treasury stock     (404 )     —       —     Proceeds from issuance of notes payable     —       15,500       21,112     Payments on notes payable     (3,367 )     (132,138 )     (15,746 )                         Net Cash Provided by (Used In) Financing Activities     (2,570 )     (113,293 )     5,366                           Net Increase (Decrease) in Cash and Cash Equivalents     74,159       55,477       (6,108 ) Cash and Cash Equivalents at Beginning of Year     64,501       9,024       15,132                       Cash and Cash Equivalents at End of Year   $ 138,660     $ 64,501     $ 9,024                       Supplemental Disclosures of Cash Flow Information:                           Cash paid during the year for interest expense   $ 13,241     $ 19,201     $ 25,721                         Cash paid during the year for income taxes   $ 4,254     $ 3,935     $ 3,057                                                     Years Ended December 31,       2004     2003     2002       (in thousands)   Cash Flows From Operating Activities:                         Net income   $ 34,360     $ 27,303     $ 100,362   Adjustments to reconcile net income to net cash provided by operating activities:                         Depletion, depreciation and amortization     36,020       21,188       26,363   Write-down of oil and gas properties and impairment     —       165       14,537   Amortization of financing costs     228       497       1,745   Gain on disposition of assets and investments     (578 )     (46,619 )     (144,029 ) Write off of unamortized financing costs     936       —       —   Equity in net earnings (losses) of affiliated companies     —       28,860       (165 ) Allowance for employee notes and accounts receivable     (598 )     (169 )     (2,987 ) Deferred compensation expense     1,521       306       —   Non-cash compensation related charges     2,152       296       1,458   Minority interest in consolidated subsidiary companies     13,618       5,968       9,319   Gain from early extinguishment of debt     —       —       (874 ) Deferred income taxes     (1,285 )     (667 )     53,618   Changes in operating assets and liabilities:                         Accounts and notes receivable     (27,156 )     (7,935 )     (1,972 ) Prepaid expenses and other     (621 )     2,164       (1,130 ) Commodity hedging contract     (14,947 )     (430 )     430   Accounts payable     4,265       359       (4,328 ) Accounts payable, related party     506       4,386       (604 ) Accrued interest payable     (1,356 )     22       (2,489 ) Accrued expenses     12,765       (382 )     (9,686 ) Asset retirement liability     482       1,459       —   Income taxes payable     13,828       1,767       3,059                       Net Cash Provided by Operating Activities     74,140       38,538       42,627                       Cash Flows from Investing Activities:                         Proceeds from sale of investment     —       69,500       189,841   Proceeds from sale of long-lived assets     578       —       —   Additions of property and equipment     (39,106 )     (60,925 )     (43,346 ) Investment in and advances to affiliated companies     —       2,328       9,185   Increase in restricted cash     —       —       (2,800 ) Decrease in restricted cash     —       1,800       1,000   Purchases of marketable securities     —       (256,058 )     (353,478 ) Maturities of marketable securities     —       283,446       326,090   Investment costs     (1,156 )     (1,900 )     (349 )                     Net Cash Provided by (Used In) Investing Activities     (39,684 )     38,191       126,143                       Cash Flows from Financing Activities:                         Net proceeds from issuances of common stock     7,451       1,201       3,345   Purchase of treasury stock     —       (404 )     —   Proceeds from issuance of long-term debt     —       —       15,500   Payments on long-term debt     (91,367 )     (3,367 )     (132,138 ) Dividends paid to minority interest     (4,600 )     —       —                       Net Cash Used In Financing Activities     (88,516 )     (2,570 )     (113,293 )                     Net Increase (Decrease) in Cash and Cash Equivalents     (54,060 )     74,159       55,477   Cash and Cash Equivalents at Beginning of Year     138,660       64,501       9,024                       Cash and Cash Equivalents at End of Year   $ 84,600     $ 138,660     $ 64,501                       Supplemental Disclosures of Cash Flow Information:                         Cash paid during the year for interest expense   $ 12,541     $ 13,241     $ 19,201                       Cash paid during the year for income taxes   $ 11,705     $ 4,254     $ 3,935                       See accompanying notes to consolidated financial statements. S-5 Supplemental Schedule of Noncash Investing and Financing Activities:      During the year ended December 31, 2004, we issued 0.1 million shares of restricted stock valued at $1.2 million and we wrote-off $0.9 million of unamortized debt financing costs in connection with the redemption and discharge of the 9.375 percent senior unsecured notes due November 1, 2007. For the three years ended December 31, 2003 and 2002, we recorded an allowance for doubtful accounts related to interest accrued on the remaining amount owed to us by our former chief executive officer, A. E. Benton. During the yearyears ended December 31, 2004, 2003 and 2002, we reversed a portion of such allowance as a result of our collection of certain amounts owed to the Companyus including the portions of the note secured by our stock and other properties (seeNote 1312 – Related Party Transactions).      During the year ended December 2004, the holders of our warrants elected to exercise 45,000 warrants on a cashless basis. This resulted in the issuance of 34,054 shares which are held as treasury stock at cost. See accompanying notes to consolidated financial statements. S-6 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements Note 1 -— Organization and Summary of Significant Accounting Policies Organization      Harvest Natural Resources, Inc. is engaged in the exploration, development, production and management of oil and gas properties. We conduct our business principally in Venezuela (Benton -Vinccler(Harvest Vinccler C.A. or “Benton-Vinccler”“Harvest Vinccler” formerly Benton Vinccler, C.A.) and, until September 25, 2003, through our minority equity investment in LLC Geoilbent, a Russian entity. 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 accounted for our investment in LLC Geoilbent (“Geoilbent”) and Arctic Gas Company (“Arctic Gas”), prior to the sale of our interests, based on a fiscal year ending September 30 (seeNote 2 – Investments In and Advances to Affiliated Companies). Reporting and Functional Currency      The U.S. dollarDollar is our functional and reporting currency. Revenue Recognition      Oil and natural gas revenue is accrued monthly based on production and delivery. Each quarter, Benton-VincclerHarvest Vinccler invoices Petroleos de Venezuela S.A. (“PDVSA”) or affiliates based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. dollarDollar contract service fees per barrel. The operating service agreement provides for Benton-VincclerHarvest Vinccler to receive an operating fee for each barrel of crude oil delivered and the right to receive a capital recovery fee for certain of its capital expenditures, provided that such operating fee and capital recovery fee cannot exceed the maximum total fee per barrel set forth in the agreement. The operating fee is subject to quarterly adjustments to reflect changes in the special energy index of the U.S. Consumer Price Index. The maximum total fee is subject to quarterly adjustments to reflect changes in the average of certain world crude oil prices. Each quarter, Benton-VincclerHarvest Vinccler also invoices PDVSA for natural gas sales based on a fixed price of $1.03 per Mcf. In addition, Benton-VincclerHarvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the gas production (“Incremental Crude Oil”). A portion of the Incremental Crude Oil is invoiced to PDVSA quarterly at a fixed price of $7.00 per Bbl. Cash and Cash Equivalents      Cash equivalents include money market funds and short term certificates of deposit with original maturity dates of less than three months. Restricted Cash      Restricted cash represents cash and cash equivalents used as collateral for financing, letter of credit and loan agreements, and is classified as current or non-current based on the terms of the agreements. Marketable Securities      Marketable securities are carried at cost. The marketable securities we may purchase are limited to those defined as Cash Equivalents in the indentures for our senior unsecured note. Cash Equivalents may be comprised of high-grade debt instruments, demand or time deposits, certificates of deposit and commercial paper of highly rated U.S. corporations, all having maturities of no more than 180 days. Our marketable securities at cost, which approximates fair value, consisted of $27.4 million in commercial paper at December 31, 2002. S-7 Credit Risk and Operations      All of our total consolidated revenues relate to operations in Venezuela. During the year ended December 31, 2003,2004, our Venezuelan crude oil and gas production represented all of our total production from consolidated companies, and our sole source of revenues related to such Venezuelan production is PDVSA, which maintains full ownership of all hydrocarbons in its fields. On December 2, 2002, employers’ and workers’ organizations, together with political and civic organizations began a national civic work stoppage, which has seriously affected many of the country’s economic activities, in particular, the oil industry. As a result of the strike, we were unable to deliver crude oil and hence generate revenues from PDVSA between December 14, 2002 and February 6, 2003. Further, on February 5, 2003, the Venezuelan Government implemented currency exchange controls aimed at restricting the convertibility of the Venezuelan Bolivar and the transfer of funds out of Venezuela. The Venezuelan Government set the exchange rate at 1,600 Bolivars for each U.S. dollarDollar and created a new Currency Exchange Agency which is responsible for the administration of exchange controls. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. dollar.Dollar. Management believes that we have sufficient cash and does not expect the currency conversion restrictions to adversely affect our ability to meet our short-term obligations.obligations and operating requirements for the next twelve months. Derivatives and Hedging      Statement of Financial Accounting Standards No. 133 (“SFAS 133”), as amended, establishes accounting and reporting standards for derivative instruments and hedging activities. In order for a derivative instrument to qualify for hedge accounting, there must be a clear correlation between the derivative instrument and the forecasted transaction. For all derivatives designated as cash flow hedges, we formally document the relationship between the derivative contract and the hedged item, as well as the risk management objective for entering into the contract. To be designated as a cash flow hedge transaction, the relationship between the derivative and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis. All derivatives are recorded on the balance sheet at fair value. To the extent that the hedge is determined to be effective, changes in the fair value of derivatives for qualifying cash flow hedges are recorded each period in other comprehensive income. Our derivatives arehave been designated as cash flow hedge transactions in which we hedge the variability of cash flows related to future oil prices for some or all of our forecasted transactions. These derivative instruments have been designated as a cash flow hedge and theoil production. The changes in the fair value hasof these derivative instruments have been reported in other comprehensive income assumingbecause the highly effective test was met, and have been reclassified to earnings in the period in which earnings arewere impacted by the variability of the cash flows of the hedged item. We measure the hedge effectiveness on a quarterly basis and hedge accounting is discontinued prospectively if it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item.      Benton-VincclerHarvest Vinccler hedged a portion of its 2003 oil sales by purchasing a WTIWest Texas Intermediate (“WTI”) crude oil “put”put option to protect its 2003 cash flow. The put was for 10,000 barrels of oil per day for the period of March 1, 2003 through December 31, 2003. This put qualified under the highly effective test. Due to the pricing structure for our Venezuela oil, the put had the economic effect of hedging approximately 20,800 barrels of oil per day. The put cost iswas $2.50 per barrel, or $7.7 million, and had a strike price of $30.00 per barrel. SettlementsThe notional amount of the financial instrument was based on expected sales of crude oil production from existing and future development wells.      We had no hedging instruments in place for our 2004 production. In August 2004, Harvest Vinccler hedged a portion of its oil sales for calendar year 2005 by purchasing a WTI crude oil put for 5,000 barrels of oil per day. The put cost was $4.24 per barrel, or $7.7 million, and has a strike price of $40.00 per barrel. In September 2004, Harvest Vinccler hedged an additional portion of its calendar year 2005 oil sales by purchasing a second WTI crude oil put for 5,000 barrels of oil per day. The put cost was $3.95 per barrel, or $7.2 million, and has a strike price of $44.40 per barrel. Due to the pricing structure for our Venezuelan oil, these two puts have the economic effect of hedging approximately 20,800 barrels of oil per day for an average of $18.29 per barrel. These puts qualify under the highly effective test and the mark-to-market loss at December 31, 2004 is included in other comprehensive loss.      At December 31, 2004, Accumulated Other Comprehensive Loss consisted of $0.7 million ($0.5 million net of tax) of unrealized losses on our crude oil puts. Oil sales for the year ended 2004 included no losses in settlement of the puts. Oil sales for the year ended 2003 included settlements of $1.7 million as well as the amortization of the put option cost of $7.7 million have been reflected as amillion. Deferred net reduction to oil revenue.      Benton-Vinccler hedged a portion of its 2002 oil sales by purchasing a commodity contract (costless collar), which required payment to (or receipts from) counterparties based on a WTI floor price of $23.00 and a ceiling price of $30.15 for 6,000 barrels of oil per day. The collar qualified under the highly effective test. Atlosses recorded in Accumulated Other Comprehensive Loss at December 31, 2002, we determined that the underlying crude oil would not2004 are expected to be delivered duereclassified to the cessation of production. Accordingly, hedge accounting was discontinuedearnings during 2005.      We continue to assess production levels and the value of the derivative was recorded as an oil revenue reductioncommodity prices in the amount of $0.3 million.      The notional amount of each financial instrument is based on expected sales of crude oil production from existingconjunction with our capital resources and future development wells and the related incremental oil production associated with production from high gas-to-oil ratio wells after the installation of a gas pipeline. These instruments protect our projected investment return and cash flow derived from our production by reducing the impact of a downward crude oil price movement until their expiration.liquidity requirements. S-8 Asset Retirement Liability      Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143)(“SFAS 143”). As a result of adopting this statement, Benton-VincclerIn January 2003, Harvest Vinccler recorded, under the full cost method of accounting for oil and gas properties, an increase in oil and gas properties as well asand a corresponding liability in the amount of $4.3 million. This asset retirement obligation is associated with the plugging and abandonment of S-8 certain wells in Venezuela. SFAS 143 requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. Historically, we determined that there would be noNine wells to plugwere abandoned in the year ended December 31, 2004 and abandon before returning the fields to PDVSA. In January 2003, one of our wells suffered a leak in its casing allowing natural gas to flow to the surface. The well was plugged and abandoned and a comprehensive study of all existing wells was undertaken. This study indicated an increased likelihood that we would have to plug and abandon certain of the wells during the term of the agreement. No prior provision was undertaken and no cumulative adjustment was required. We abandoned 11 wells were abandoned in year ended December 31, 2003. Changes in asset retirement obligations during the yearyears ended December 31, 2004 and 2003 were as follows:           Asset retirement obligations as of January 1, 2003   $ —   Liabilities recorded during the first quarter     4,237   Liabilities settled during the year     (733 ) Revisions in estimated cash flows     (2,125 ) Accretion expense     80             Asset retirement obligations as of December 31, 2003   $ 1,459                                   December 31,     December, 31       2004     2003                     Asset retirement obligations beginning of period   $ 1,459     $ —   Liabilities recorded during the period     1,454       4,237   Liabilities settled during the period     (540 )     (733 ) Revisions in estimated cash flows     (470 )     (2,125 ) Accretion expense     38       80                 Asset retirement obligations end of period   $ 1,941     $ 1,459                 Accounts and Notes Receivable      Allowance for doubtful accounts related to former employee notes at December 31, 2004 and 2003 was $2.8 million and 2002 was $3.4 million, respectively. We received $0.5 million through the exercise of stock options and $3.5$0.1 million respectivelythrough the excess income provision of the settlement and release agreement. (seeNote 1312 – Related Party Transactions). Other Assets      Other assets consist of costs associated with the issuance of long-term debt and investigative costs associated with new projects. Debt issuance costs are amortized on a straight-line basis over the life of the debt, which approximates the effective interest method of amortizing these costs. New project costs are reclassified to oil and gas properties or expensed depending on management’s assessment of the likely outcome of the project. 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, subject to a cost center ceiling (as defined by the Securities and Exchange Commission [“SEC”]). All costs associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized as incurred, including exploration overhead of $0.6 million for the year ended December 31, 2001, and capitalized interest of $0.5 million and $0.9 million for the years ended December 31, 2002 and 2001, respectively. There was no capitalized overhead in 2003 and 2002, and no capitalized interest in 2003.incurred. Only overhead that is directly identified with acquisition, exploration or development activities are capitalized. All costs related to production, general corporate overhead and similar activities are expensed as incurred.      The costs of unproved properties are excluded from amortization until the properties are evaluated. At least annuallyquarterly we evaluate our unproved properties on a country by country basis for possible impairment. If we abandon all exploration efforts in a country where no proved reserves are assigned, all exploration and acquisition costs associated with the country are expensed. During 2003 2002 and 2001,2002, we recognized $0.2 million $14.5 million and $0.5$14.5 million, respectively, in impairments associated with former exploration prospects and the China WAB-21 block. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty.      Excluded costs at December 31, 20032004 consisted of property acquisition costs in the amount of $2.9 million which were all incurred prior to 2001. All of the excluded costs at December 31, 20032004 relate to the acquisition of Benton Offshore China Company and exploration related to its WAB-21 property. The ultimate timing of when the costs related to the acquisition of Benton Offshore China Company will be included in amortizable costs is uncertain. S-9      Statement of Financial Accounting Standards No. 141 – Business Combinations (“FAS 141”) and No. 142 – Goodwill and Other Intangible Assets (“FAS 142”) included new terminology on the disclosure of what constitutes an intangible asset. One interpretation being considered relative to these standards is that a mineral interest associated with proved and undeveloped oil and gas leasehold acquisition costs should be classified separately in Oil and Gas Properties on the Consolidated Balance Sheet as intangible assets, and the disclosures required by FAS 141 and FAS 142 would be included in the Notes to Financial Statements. We believe that the presentation and disclosure of the $2.9 million excluded costs attributed to the China cost center is appropriate pending further guidance on this matter.      All capitalized costs (including oilfield inventory and future abandonment costs under SFAS 143) and estimated future development costs (including estimated dismantlement, restoration and abandonment costs) of proved reserves are depleted using the units of production method based on the total proved reserves of the country cost center. Depletion expense, which was substantially all attributable to the Venezuelan cost center for the years ended December 31, 2004, 2003 and 2002 and 2001 was $34.1 million, $19.6 million and $24.9 million ($2.56, $2.52 and $22.1 million ($2.52, $2.56 and $2.26 per equivalent barrel), respectively.      A gain or loss is recognized on the sale of oil and gas properties only when the sale involves a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved property. S-9      Depreciation of furniture and fixtures is computed using the straight-line method with depreciation rates based upon the estimated useful life of the property, generally 5 years. Leasehold improvements are depreciated over the life of the applicable lease. Depreciation expense was $1.9 million, $1.6 million $1.4 million and $3.4$1.4 million for the years ended December 31, 2004, 2003 2002 and 2001,2002, respectively.      The major components of property and equipment at December 31 are as follows (in thousands):                                 2004   2003     2003   2002   Proved property costs   $ 582,456   $ 566,415     $ 621,679   $ 582,456   Costs excluded from amortization   2,900   2,900     2,900   2,900   Material and supply inventories   8,266   7,286   Oilfield inventories   6,503   8,266   Other administrative property   8,948   7,503     10,008   8,948                         602,570   584,104     641,090   602,570   Accumulated depletion, impairment and depreciation     (418,507 )     (439,344 )     (453,941 )     (418,507 )                       $ 184,063   $ 144,760     $ 187,149   $ 184,063                            We perform a quarterly cost center ceiling test of our oil and gas properties under the full cost accounting rules of the SEC. The consolidated financial statements of the wholly-owned and majority owned subsidiaries do not include ceiling test write-downs in 2004 or 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. Stock-Based Compensation      At December 31, 20032004 and 2002,2003, we had several stock-based employee compensation plans, which are more fully described inNote 65 – Stock Option and Stock Purchase Plans. Prior to 2003, we accounted for those plans under the recognition and measurement provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Effective January 1, 2003, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards Statement No. 123 (“FAS 123”), Accounting for Stock-Based Compensation, prospectively to all employee awards granted, modified, or settled after January 1, 2003. Awards under our plans vest in periodic installments after one year of their grant and expire ten years from grant date. Therefore, the costs related to stock-based employee compensation included in the determination of net income in the years ended December 31, 20032004 and 20022003 are less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of FAS 123. The following table illustrates the effect on net income and earnings per share if the fair value based method had been applied to all outstanding and unvested awards in each period.                               2004     2003     2002                             Net income, as reported   $ 34,360     $ 27,303     $ 100,362                             Add: Stock-based employee compensation cost, net of tax     999       296       915                             Less: Total stock-based employee compensation cost determined under fair value based method, net of tax     (1,382 )     (1,056 )     (2,905 )                                               Net income – proforma   $ 33,977     $ 26,543     $ 98,372                       Net income per common share:                         Basic – as reported   $ 0.95     $ 0.77     $ 2.90                       Basic – proforma   $ 0.94     $ 0.75     $ 2.87                                                 Diluted – as reported   $ 0.90     $ 0.74     $ 2.78                       Diluted – proforma   $ 0.89     $ 0.72     $ 2.75                       S-10                               2003   2002   2001 Net income, as reported   $ 27,303     $ 100,362     $ 43,237   Add: Stock-based employee compensation cost, net of tax     296       915       35   Less: Total stock-based employee compensation cost determined under fair value based method, net of tax     (1,056 )     (2,905 )     (2,459 )                           Net income – proforma   $ 26,543     $ 98,372     $ 40,813                             Net income per common share:                         Basic – as reported   $ 0.77     $ 2.90     $ 1.27                             Basic – proforma   $ 0.75     $ 2.87     $ 1.20                             Diluted – as reported   $ 0.74     $ 2.78     $ 1.27                             Diluted – proforma   $ 0.72     $ 2.75     $ 1.20                             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 carryforwards. 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. In the third quarter of 2003, a portion of the valuation allowance was reversed based on the utilization of net operating losses which offset U.S. taxable income generated by the sale of our minority equity investment in Geoilbent. Foreign Currency      We have significant operations outside of the United States, principally in Venezuela and, until September 25, 2003, a minority equity investment in Russia. The U.S. dollarDollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in U.S. dollars,Dollars, and all currency gains or losses are recorded in the statement of operations. We attempt to manage our operations in a manner 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 currency to the U.S. dollar.Dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates. Financial Instruments      Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents, marketable securities and accounts receivable. Cash and cash equivalents are placed with commercial banks with high credit ratings. This diversified investment policy limits our exposure both to credit risk and to concentrations of credit risk. Accounts receivable result from oil and natural gas exploration and production activities and our customers and partners are engaged in the oil and natural gas business. PDVSA purchases 100 percent of our Venezuelan oil and gas production. Although we do not currently foresee a credit risk associated with these receivables, collection is dependent upon the financial stability of PDVSA. The payment for the fourth quarter 2002 sales, which was due February 28, 2003, was delayed until March 7, 2003, which was approximately seven days late due to the effect of the national civil work stoppage on PDVSA.      The book values of all financial instruments other than long-term debt, are representative of their fair values due to their short-term maturities. The aggregate fair value of our senior unsecured notes, based on the last trading prices at December 31, 2003, and 2002, was approximately $85.0 million and $77.4 million, respectively.million. Our senior unsecured notes were repaid in the quarter ended September 30, 2004. Comprehensive Income      Statement of Financial Accounting Standards No. 130 (“SFAS 130”) requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. We reflected unrealized mark-to- S-11 market gains/(losses)mark-to-market losses from cash flow hedging activities as other comprehensive income/(loss)loss during the yearsyear ended December 31, 20032004 and 2002.in accordance with SFAS 130, have provided a separate line in the audited consolidated statement of operations and comprehensive income. Minority Interests      We record a minority interest attributable to the minority shareholder of our Venezuela and Barbados subsidiaries. The minority interests in net income and losses are generally subtracted from or added to arrive at consolidated net income. New Accounting Pronouncements      In May 2003,December 2004, the Financial Accounting Standards Board (“FASB”FASB’) issued Statement of Financial Accounting Standard No. 150 “Accounting123 (revised 2004) Share-Based Payment (“SFAS 123R”), an amendment to Statement of Accounting Standards 123 and 95. SFAS 123R focuses primarily on accounting for Certain Financial Instrumentstransactions in which an entity obtains employee services in share-based payment transactions. Public companies with Characteristicsa calendar year-end will be required to adopt the provisions 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 generallythe standard effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim periodperiods beginning after June 15, 2003. The adoption of this Statement had no2005. We do not expect SFAS 123R to have a material effect on our consolidated financial statements.position, results of operation or cash flows. S-11      In December 2004, the FASB issued Statement of Financial Accounting Standard 153 Exchanges of Nonmonetary Assets (“SFAS 153”), an amendment of Accounting Principles Board (“APB”) Opinion No. 29 (“Opinion 29”). SFAS 153 amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. We do not expect SFAS 153 to have a material effect on our consolidated financial position, results of operation or cash flows.      In September 2004, the SEC issued Staff Accounting Bulletin 106 (“SAB 106”) which provides guidance regarding the interaction of SFAS 143 with the calculation of depletion and the full cost ceiling test of oil and gas properties under the full cost accounting rules of the SEC. The guidance provided in SAB 106 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.      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 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. Use of Estimates      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, plant products and gas reserve volumes and the future development costs. Actual results could differ from those estimates. Reclassifications      Certain items in 20012002 and 20022003 have been reclassified to conform to the 20032004 financial statement presentation. Note 2 — Investments In and Advances To Affiliated Companies      On September 25, 2003, we sold our minority equity investment in Geoilbent to Yukos Operational Holding Limited and recognized a pre-tax gain on the sale of $46.6 million (seeNote 9 – Russian Operations). Prior to the sale, our 34 percent minority equity investment in Geoilbent was accounted for using the equity method due to the significant influence we exercised over their operations and management. Investments included amounts paid to the investee company for shares of stock and other costs incurred associated with the acquisition and evaluation of technical data for the oil fields operated by the investee company. Equity in earnings of Geoilbent is based on a fiscal year ending September 30. No dividends have been paid to us from Geoilbent.      Equity in earnings and losses and investments in and advances to Geoilbent are as follows (in thousands): S-12                       LLC Geoilbent     2003   2002 Investments:                 In equity in net assets   $ —     $ 28,056   Other costs, net of amortization     —       (263 )                   Total investments     —       28,319   Advances     —       2,527   Equity in earnings     —       20,937                     Total   $ —     $ 51,783                     Note 3 —- Long-Term Debt and Liquidity Long-Term Debt      Long-term debt consists of the following (in thousands):                       December 31,   December 31,     2003   2002 Senior unsecured notes with interest at 9.375%                 See description below   $ 85,000     $ 85,000   Note payable with interest at 6.1%                 See description below     2,700       3,900   Note payable with interest at 39.7%                 See description below     —       2,167   Note payable with interest at 7.1%     15,500       15,500                           103,200       106,567   Less current portion     6,367       1,867                         $ 96,833     $ 104,700                                           December 31,     December 31,       2004     2003   Senior unsecured notes with interest at 9.375% See description below   $ —     $ 85,000   Note payable with interest at 6.1% See description below     1,500       2,700   Note payable with interest at 7.1%     10,333       15,500                       11,833       103,200   Less current portion     11,833       6,367                     $ —     $ 96,833                      In November 1997, we issued $115.0 million in 9.375 percent senior unsecured notes due November 1, 2007 (“2007 Notes”), of which we repurchased $30.0 million. InterestIn September 2004, we announced that the remaining 2007 Notes would be redeemed on November 1, 2004, and we irrevocably deposited with the Trustee for the 2007 Notes is due May 1 andas trust funds $85.0 million plus accrued interest through November 1, 2004 and a prepayment call premium S-12 of each year. At December 31, 2003, we$1.3 million to redeem the 2007 Notes on the redemption date. We were in compliance withreleased from all covenantsobligations related to the 2007 Notes upon deposit of the indenture.trust funds with the Trustee. We recorded a loss on early extinguishment of debt of $2.9 million which includes the $1.3 million prepayment call premium, $0.7 million for interest related to the period October 1, 2004 to November 1, 2004 and $0.9 million write-off of unamortized debt financing costs. Our repayment of the 2007 Notes triggered an obligation under the terms of Harvest Vinccler’s loans from a Venezuelan commercial bank to renegotiate the terms of those loans or, if agreement on renegotiated terms cannot be reached within 30 days after November 1, 2004, the loans can be declared due and payable. Harvest Vinccler is in discussions with the Venezuelan bank on possible renegotiated terms. The entire amount has been reclassified from long term to current in the interim. While we believe the loans will be renegotiated, it is possible that agreement will not be reached and Harvest Vinccler will be required to repay the remaining balance of $11.8 million. As of February 11, 2005, no agreement had been reached.      In March 2001, Benton-VincclerHarvest Vinccler borrowed $12.3 million from a Venezuelan commercial bank, for construction of an oil pipeline. The loan is in two parts, with the first part in an original principal amount of $6.0 million that bears interest payable monthly based on 90-day London Interbank Borrowing Rate (“LIBOR”) plus 5 percent with principal payable quarterly for five years. The second part, in the original principal amount of 4.4 billion Venezuelan Bolivars (“Bolivars”) (approximately $6.3 million). The Bolivar loan was repaid as of March 31, 2003. The loans provide for certain limitations on mergers and sale of assets. We have guaranteed the repayment of thisthe remaining loan.      In October 2002, Benton-Vinccler,Harvest Vinccler, C.A. executed a note and borrowed $15.5 million to fund construction of a gas pipeline and related facilities to deliver natural gas from the Uracoa field to a PDVSA pipeline. The interest rate for this loan is 90-day LIBOR plus 6 percentage points. The term is four years with a quarterly amortization of $1.3 million beginning with the first quarter 2004 to coincide with the first payment from our gas sales.      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 waiverWe have classified all 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 expenseoutstanding debt 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.      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. S-13      The principal payment requirements for our long-term debt outstanding at December 31, 2003 are as follows (in thousands):           2004   $ 6,367   2005     6,367   2006     5,466   2007     85,000                 $ 103,200             Liquidity      We currently have a significant debt obligation payable in November 2007 of $85 million. Our ability to meet our debt obligations and to reduce our level of debt depends on the successful implementation of our strategic objectives. Our cash flow from operations complemented with our cash and cash equivalents of $139 million at December 31, 2003, can be invested in other opportunities used to develop our significant proved undeveloped reserves or used to repurchase our outstanding debt.2004. Note 4 —3 - Commitments and Contingencies      We have employment contracts with fivesix executive officers which provide for annual base salaries, eligibility for bonus compensation and various benefits. The contracts provide for a lump sum payment as a multiple of base salary in the event of termination of employment without cause. In addition, these contracts provide for payments as a multiple of base salary and bonus, tax reimbursement and a continuation of benefits in the event of termination without cause following a change in control. By providing one year notice, these agreements may be terminated by either party on May 31, 2005.2006 for five of the executives and on May 7, 2007 for the sixth executive.      In July 2001,April 2004, we leasedsigned a ten-year lease for three years office space in Houston, Texas, for approximately $11,000$17,000 per month. We leasemoved into the new space in August 2004. In addition, Harvest Vinccler leased new office space in Maturin and Caracas, Venezuela for $13,200 and $4,000 per month, respectively. We leased 17,500 square feet of space in a California building that we no longer occupy under a lease agreement that expiresexpired in December 2004, all of which has beenwas subleased for rents that approximateapproximated our lease costs.      Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-Vinccler,Harvest Vinccler, C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, Texas.Texas. This suit was brought in May, 2003 by Excel alleging, among other things, breach of a consulting agreement between Excel and us, misappropriation of proprietary information and trade secrets, and fraud. Excel seeks actual and exemplary damages, injunctive relief and attorneys’ fees. The Court has abated the suit pending final judgment of a case pending in Louisiana to which we are not a party. We dispute Excel’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.      Uracoa Municipality Tax Assessments. In July 2004, Harvest Vinccler received three tax assessments from a tax inspector for the Uracoa municipality in which part of the South Monagas Unit is located. A protest to the assessments was filed with the municipality, and in September 2004 the tax inspector responded in part by affirming one of the assessments and issuing a payment order. Harvest Vinccler has filed a motion with the tax court in Barcelona, Venezuela, seeking to enjoin the payment order and dismiss the assessment. We dispute all of the tax assessments and believe we have a substantial basis for our positions. We are unable to estimate the amount or range of any possible loss. S-13 We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such litigation which iswill have a material to us.adverse impact on our financial condition, results of operations and cash flows. Note 54 — Taxes Taxes Other Than on Income      Benton-VincclerHarvest Vinccler pays a municipal taxtaxes on operating fee revenues it receives for production from the South Monagas Unit. The year ended December 31, 2002 included a non-recurring foreign payroll tax adjustment of $0.7 million. The components of taxes other than on income were (in thousands):                                                   2003   2002   2001   2004   2003   2002   Venezuelan municipal taxes   $ 2,741   $ 3,805   $ 4,447     $ 4,485   $ 2,741   $ 3,805   Franchise taxes   341   139   121     464   341   139   Payroll and other taxes   291   124   802     612   291   124                                 $ 3,373   $ 4,068   $ 5,370     $ 5,561   $ 3,373   $ 4,068                               S-14 Taxes on Income      The tax effects of significant items comprising our net deferred income taxes as of December 31, 20032004 and 20022003 are as follows (in thousands):                                   2003   2002   2004   2003   Deferred tax assets:   Deferred tax assets – non-current:   Operating loss carryforwards   $ 20,442   $ 19,690     $ 14,748   $ 20,442   Difference in basis of property   29,602   21,495     28,753   29,602   Other   3,070   2,043     3,025   3,070   Valuation allowance     (48,365 )     (39,146 )     (40,492 )     (48,365 )                     Net deferred tax asset   $ 4,749   $ 4,082   Net deferred tax asset – non-current   $ 6,034   $ 4,749                            The valuation allowance increaseddecreased by $9.2$7.9 million as a result of the change in the U.S. deferred tax assets related to the net operating loss carryforward as well as a Venezuelan deferred tax asset impairment. Realization of deferred tax assets associated with net operating loss carryforwards is dependent upon generating sufficient taxable income prior to their expiration. Management believes it is more likely than not that they will not be realized through future taxable income.      The components of income before income taxes and minority interest are as follows (in thousands):                                               2003   2002   2001   2004   2003   2002   Income (loss) before income taxes     United States   $ 21,812   $ 89,455   $ (26,572 )   $ (16,593 )   $ 34,236   $ 92,394   Foreign   49,976   80,356   33,754     97,859   37,552   77,417                               Total   $ 71,788   $ 169,811   $ 7,182     $ 81,266   $ 71,788   $ 169,811                                    The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):                                                   2003   2002   2001   2004   2003   2002   Current:     United States   $ 1,188   $ 353   $ 1     $ (8 )   $ 1,187   $ 351   Foreign   9,136   6,324   6,700     34,581   9,137   6,326                                 $ 34,573   $ 10,324   $ 6,677     $ 10,324   $ 6,677   $ 6,701                                 Deferred:     United States   $ —   $ 53,413     (42,405 )   $ —   $ —   $ 53,413   Foreign     (667 )   205   6       (1,285 )     (667 )   205                                   (667 )   53,618     (42,399 )     (1,285 )     (667 )   53,618                                 $ 9,657   $ 60,295   $ (35,698 )   $ 33,288   $ 9,657   $ 60,295                                    During 2003, we reduced our foreign tax provision approximately $3.9 million related to the resolution of certain prior year foreign income tax matters. Additionally, we recorded a domestic tax provision of approximately $1.1 million related to certain domestic tax matters identified during the year.S-14      A comparison of the income tax expense (benefit) at the federal statutory rate to our provision for income taxes is as follows (in thousands):                                                   2003   2002   2001   2004   2003   2002   Computed tax expense at the statutory rate   $ 15,025   $ 59,348   4,580     $ 28,443   $ 15,025   $ 59,348   State income taxes   1,188   353   —     25   1,188   353   Effect of foreign source income and rate differentials on foreign income     (15,849 )     (19,373 )   1,675       (2,169 )     (15,849 )     (19,373 ) Change in valuation allowance   9,219   19,446     (53,413 )   7,020   9,219   19,446   Prior year adjustments   —   —   2,304   Reclass paid-in capital   —   —   11,007   All other   74   80   215       (31 )   74   80                               Sub-total income tax expense (benefit)   9,657   59,854     (33,632 ) Sub-total income tax expense   33,288   9,657   59,854   Effects of recording equity income of certain affiliated Companies on an after-tax basis   —   441     (2,066 )   —   —   441                               Total income tax expense (benefit)   $ 9,657   $ 60,295   $ (35,698 ) Total income tax expense   $ 33,288   $ 9,657   $ 60,295                                    Rate differentials for foreign income result from tax rates different from the U.S. tax rate being applied in foreign jurisdictions and from the effect of foreign currency devaluation in foreign subsidiaries which use the U.S. dollarDollar as their functional currency. S-15      At December 31, 2003,2004, we had, for federal income tax purposes, operating loss carryforwards of approximately $58.4$42.1 million, expiring in the years 20182014 through 2022.2025.      We do not provide deferred income taxes on undistributed earnings of international consolidated subsidiaries for possible future remittances as all such earnings are reinvested as part of our ongoing business. The amount of deferred taxes on the undistributed earnings cannot be determined at this time. Note 65 — Stock Option and Stock Purchase Plans      In May 2004, our shareholders approved the 2004 Long Term Incentive Plan (the “Plan”). The Plan provides for the issuance of up to 1,750,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to eligible participants including employees, non-employee directors and consultants of our company or subsidiaries. Under the Plan, no more than 438,000 shares may be granted as restricted stock, and no individual may be granted more than 110,000 shares of restricted stock or 438,000 in options over the life of the Plan. The exercise price of stock options granted under the plan must be no less than the fair market value of our common stock on the date of grant. All options granted to date will vest ratably over a three-year period from their dates of grant and expire ten years from grant date. All restricted stock granted to date is subject to a restriction period of 36 months during which the stock will be deposited with the Company and is subject to forfeiture under certain circumstances. The Plan also permits the granting of performance awards to eligible employees and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time of at least one year. Performance awards granted under the Plan may not exceed $5.0 million in a calendar year and may not exceed $2.5 million to any one individual in a calendar year. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become exercisable.      In January 2001, we adopted the Non-Employee Director Stock Purchase Plan (the “Stock Purchase Plan”) to encourage our directors to acquire a greater proprietary interest in us through the ownership of our common stock. Under the Stock Purchase Plan, each non-employee director could elect to receive shares of our common stock for all or a portion of their fee for serving as a director. The number of shares issuable is equal to 1.5 times the amount of cash compensation due the director divided by the fair market value of the common stock on the scheduled date of payment of the applicable director’s fee. The shares have a restriction upon their sale for one year from the date of issuance. As of December 31, 2002, 337,850 shares had been issued from the plan. The Stock Purchase Plan was terminated by the Board of Directors in September 2002.      In July 2001, our shareholders approved the adoption of the 2001 Long Term Stock Incentive Plan. The 2001 Long Term Stock Incentive Plan provides for grants of options to purchase up to 1,697,000 shares of our common stock in the form of Incentive Stock Options and Non-qualifiedNon-Qualified Stock Options to eligible participants including employees of our company or subsidiaries, directors, consultants and other key persons. The exercise price of stock options granted under the plan must be no less than the fair market value of our common stock on the date of grant. No officer may be granted more than 500,000 options during any one fiscal year, as adjusted for any S-15 changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date.      Since 1989 we have adopted several other stock option plans under which options to purchase shares of our common stock have been granted to employees, officers, directors, independent contractors and consultants. Options granted under these plans have been at prices equal to the fair market value of the stock on the grant dates. Options granted under the plans are generally exercisable in varying cumulative periodic installments after one year and cannot be exercised more than ten years after the grant dates. Following the adoption of the 2001 Long Term Stock Incentive Plan, no options may be granted under any of these plans.      A summary of the status of our stock option plans as of December 31, 2004, 2003 2002 and 20012002 and changes during the years ending on those dates is presented below (shares in thousands):                                                                                             2003   2002   2001   2004   2003   2002     Weighted   Weighted   Weighted   Weighted   Weighted   Weighted     Average   Average   Average   Average   Average   Average     Exercise   Exercise   Exercise   Exercise   Exercise   Exercise     Price   Shares   Price   Shares   Price   Shares   Price   Shares   Price   Shares   Price   Shares   Outstanding at beginning of the year:   $ 7.42   5,223   $ 6.36   6,865   7.74   5,660     $ 7.52   4,523   $ 7.42   5,223   $ 6.36   6,865   Options granted   6.26   246   4.84   165   1.65   1,684     13.36   378   6.26   246   4.84   165   Options exercised   2.32     (494 )   2.21     (1,515 )   —   —       (7.41 )     (955 )   2.32     (494 )   2.21     (1,515 ) Options cancelled   11.37     (452 )   8.03     (292 )   6.43     (479 )     (6.31 )     (153 )   11.37     (452 )   8.03     (292 )                             Outstanding at end of the year   7.52   4,523   7.42   5,223   6.36   6,865     8.18   3,793   7.52   4,523   7.42   5,223                               Exercisable at end of the year   8.18   3,857   8.49   4,360   8.32   4,800     7.71   3,236   8.18   3,857   8.49   4,360                                    Significant option groups outstanding at December 31, 20032004 and related weighted average price and life information follow:                                                                               Outstanding   Exercisable Range of   Number   Weighted-Average           Number     Exercise   Outstanding At   Remaining   Weighted-Average   Exercisable at   Weighted-Average Prices   December 31, 2003   Contractual Life   Exercise Price   December 31, 2003   Exercise Price $ 1.55     -   $ 2.75       2,027,150       5.91     $ 1.97       1,679,983     $ 2.03   $ 4.80     -   $ 7.00       621,000       4.69       5.81       337,667       5.87   $ 7.25     -   $ 11.00       488,633       1.69       8.77       452,633       8.90   $ 11.50     -   $ 16.50       946,665       1.42       13.52       946,665       13.52   $ 17.38     -   $ 24.13       439,833       1.78       21.21       439,833       21.21                                                                                   4,523,281                       3,856,781                                                                                                                   Outstanding     Exercisable   Range of   Number     Weighted-Average             Number         Exercise   Outstanding At     Remaining     Weighted-Average     Exercisable at     Weighted-Average   Prices   December 31, 2004     Contractual Life     Exercise Price     December 31, 2004     Exercise Price   $1.55 - $2.75     1,701,149       4.93     $ 1.96       1,701,149     $ 1.96   $4.80 - $7.10     410,834       7.28       5.74       226,832       5.57   $8.72 - $10.88     153,900       0.73       8.86       153,900       8.86   $11.50 - $16.90     1,091,907       3.29       13.48       719,332       13.54   $17.88 - $24.13     434,833       0.33       21.23       434,833       21.23                                               3,792,623                       3,236,046                                                 S-16      Of the number outstanding, 1,108,750858,750 options are controlled bypledged to us through the A. E. Benton settlement.to secure a repayment of debt. SeeNote 1312 – Related Party Transactions.      In connection with our acquisition of Benton Offshore China Company in December 1996, we adopted the Benton Offshore China Company 1996 Stock Option Plan. Under the plan, Benton Offshore China Company is authorized to issue up to 107,571 options to purchase our common stock for $7.00 per share. The plan was adopted in substitution of Benton Offshore China Company’s stock option plan, and all options to purchase shares of Benton Offshore China Company common stock were replaced under the plan by options to purchase shares of our common stock. All options were issued upon the acquisition of Benton Offshore China Company and vested upon issuance. At December 31, 2003,2004, options to purchase 74,427 shares of common stock were both outstanding and exercisable.      In addition to options issued pursuant to the plans, options have been issued to individuals other than our officers, directors or employees at prices ranging from $5.63$10.88 to $11.88 which vest over three to four years. At December 31, 2003,2004, a total of 61,00015,000 options issued outside of the plans were both outstanding and exercisable. Note 76 — Stock Warrants           The datesdate the warrants were issued, the expiration dates,date, the exercise pricesprice and the number of warrants issued and outstanding at December 31, 20032004 were (warrants in thousands):                                         Warrants   Warrants Date Issued   Expiration Date   Exercise Price   Issued   Outstanding   Expiration Date   Exercise Price   Issued   Outstanding July 1994   July 2004   $ 7.50       150       8   December 1994   December 2004     12.00       50       50   June 1995   June 2007     17.09       125       125     June 2007   $ 17.09       125       125                                           325       183                             S-16 Note 87 — Operating Segments      We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Revenue from Venezuela is derived primarily from the production and sale of oil and gas. Other income from USA and Other is derived primarily from interest earnings on various investments and consulting revenues. Operations included under the heading “Russia” include project evaluation costs and other costs to maintain an office in Russia. Operations included under the heading “USA and Other” include corporate management, exploration activities, cash management and financing activities performed in the United States and other countries which do not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the USA and Other segment and are not allocated to other operating segments.                               2004     2003     2002   Segment Revenues                         Oil and gas sales:                         Venezuela   $ 186,066     $ 106,095     $ 126,731                       Total oil and gas sales     186,066       106,095       126,731                                                 Segment Income (Loss)                         Venezuela     54,469       23,874       64,509   Russia     (3,524 )     (29,620 )     (2,777 ) United States and other     (16,585 )     33,049       38,630                       Net income   $ 34,360     $ 27,303     $ 100,362                                             December 31,     December 31,       2004     2003   Operating Segment Assets                 Venezuela   $ 309,794     $ 241,855   Russia     385       237   United States and other     108,408       180,768                       418,587       422,860   Intersegment eliminations     (51,101 )     (48,512 )                   $ 367,486     $ 374,348                 S-17 Year ended December 31, 2003:                                           (in thousands)   Venezuela   USA and Other   Russia   Eliminations   Consolidated Revenues                                         Oil sales   $ 103,920     $ —     $ —     $ —     $ 103,920   Gas sales     2,740       —       —       —       2,740   Ineffective hedge activity     (565 )     —       —       —       (565 )                                                 106,095       —       —       —       106,095                                             Expenses                                         Operating expenses     31,309       76       (492 )     —       30,893   Depletion, depreciation and amortization     21,035       109       44       —       21,188   General and administrative     4,031       10,514       1,201       —       15,746   Arbitration settlement     —       1,477       —       —       1,477   Bad debt recovery     —       (374 )     —       —       (374 ) Taxes other than on income     2,921       447       5       —       3,373                                             Total expenses     59,296       12,249       758       —       72,303                                             Income (loss) from operations     46,799       (12,249 )     (758 )     —       33,792   Other non-operating income (expense)                                         Gain on disposition of assets     —       46,619       —       —       46,619   Investment earnings and other     435       983       —       —       1,418   Interest expense     (1,944 )     (8,470 )     —       9       (10,405 ) Net gain on exchange rates     495       34       —       —       529   Intersegment revenues (expenses)     (7,484 )     7,484       —       —       —   Equity in losses of affiliated companies     —       —       (28,860 )     —       (28,860 )                                                 (8,498 )     46,650       (28,860 )     9       9,301                                             Income (loss) before income taxes     38,301       34,401       (29,618 )     9       43,093   Income tax expense     8,459       1,187       2       9       9,657                                             Operating segment income (loss)     29,842       33,214       (29,620 )     —       33,436   Write-downs of oil and gas properties and impairments     —       (165 )     —       —       (165 ) Minority interest     (5,968 )     —       —       —       (5,968 )                                           Net income (loss)   $ 23,874     $ 33,049     $ (29,620 )   $ —     $ 27,303                                             Total assets   $ 241,855     $ 180,768     $ 237     $ (48,512 )   $ 374,348                                             Additions to properties   $ 60,589     $ 245     $ 91     $ —     $ 60,925                                             Year ended December 31, 2002                                           (in thousands)   Venezuela   USA and Other   Russia   Eliminations   Consolidated Revenues                                         Oil sales   $ 127,015     $ —     $ —     $ —     $ 127,015                                             Ineffective hedge activity     (284 )     —       —       —       (284 )                                                 126,731       —       —       —       126,731                                             Expenses                                         Operating expenses     31,457       360       2,133       —       33,950   Depletion, depreciation and amortization     23,850       2,483       30       —       26,363   General and administrative     4,310       11,420       774       —       16,504   Bad debt recovery     —       (3,276 )     —               (3,276 ) Taxes other than on income     3,997       71       —       —       4,068                                             Total expenses     63,614       11,058       2,937       —       77,609                                             Income (loss) from operations     63,117       (11,058 )     (2,937 )     —       49,122   Other non-operating income (expense):                                         Gain on disposition of assets     —       144,032       (3 )     —       144,029   Gain on early extinguishment of debt     —       874       —       —       874   Investment earnings and other     1,889       1,653       —       (1,462 )     2,080   Interest expense     (4,237 )     (13,611 )     —       1,538       (16,310 ) Net gain on exchange rates     4,356       197       —       —       4,553   Intersegment revenues (expenses)     15,156       (15,156 )     —       —       —   Equity in income of affiliated companies     —       —       165       —       165                                                   17,164       117,989       162       76       135,391                                             Income (loss) before income taxes     80,281       106,931       (2,775 )     76       184,513   Income tax expense     6,453       53,764       2       76       60,295                                             Operating segment income (loss)     73,828       53,167       (2,777 )     —       124,218   Write-downs of oil and gas properties and impairments     —       (14,537 )     —       —       (14,537 ) Minority interest     (9,319 )     —       —       —       (9,319 )                                           Net income (loss)   $ 64,509     $ 38,630     $ (2,777 )   $ —     $ 100,362                                             Total assets   $ 209,733     $ 122,355     $ 52,302     $ (49,198 )   $ 335,192                                             Additions to properties   $ 42,486       738       122       —       43,346                                             S-18 Year ended December 31, 2001:                                           (in thousands)   Venezuela   USA and Other   Russia   Eliminations   Consolidated Revenues                                         Oil sales   $ 122,386     $ —     $ —     $ —     $ 122,386                                             Expenses                                         Operating expenses     42,037       55       667       —       42,759   Depletion, depreciation and amortization     22,096       3,408       12       —       25,516   General and administrative     4,151       14,972       949       —       20,072   Taxes other than on income     4,666       704       —       —       5,370                                             Total expenses     72,950       19,139       1,628       —       93,717                                             Income (loss) from operations     49,436       (19,139 )     (1,628 )     —       28,669   Other non-operating income (expense):                                         Investment earnings and other     5,995       2,053       60       (5,020 )     3,088   Interest expense     (7,403 )     (22,695 )     —       5,223       (24,875 ) Net gain on exchange rates     732       36       —       —       768   Intersegment revenues (expenses)     (14,983 )     14,983       —       —       —   Equity in income of affiliated companies     —       —       5,902       —       5,902                                                   (15,659 )     (5,623 )     5,962       203       (15,117 )                                           Income (loss) before income taxes     33,777       (24,762 )     4,334       203       13,552   Income tax (benefit) expense     6,491       (42,392 )     —       203       (35,698 )                                           Operating segment income     27,286       17,630       4,334       —       49,250   Write-down of oil and gas properties and impairments     —       (468 )     —       —       (468 ) Minority interest     (5,545 )     —       —       —       (5,545 )                                           Net income   $ 21,741     $ 17,162       4,334       —     $ 43,237                                             Total assets   $ 167,671     $ 165,254     $ 100,801     $ (85,575 )   $ 348,151                                             Additions to properties   $ 43,411     $ —     $ 31     $ —     $ 43,442                                             S-19 Note 9 -8 — Russian Operations Geoilbent      On September 25, 2003, we sold our minority equity investment in Geoilbent to Yukos Operational Holding Limited for $69.5 million plus the repayment of the subordinated loan and certain payables owed to us by Geoilbent in the amount of $5.5 million. Prior to the sale, we owned 34 percent of Geoilbent, a Russian limited liability company, formed in 1991 to develop, produce and market crude oil from the North Gubkinskoye and South Tarasovskoye Fields in the Western Siberia region of Russia. Our minority equity investment in Geoilbent was accounted for using the equity method and was based on a fiscal year ending September 30. Sales quantities attributable to Geoilbent for the period until it was sold on September 25, 2003 and for the yearsyear ended September 30, 2002 and 2001 were 5.6 million barrels (3.3 million domestic and 2.3 million export), and 6.9 million barrels (4.6 million domestic and 2.3 million export) and 5.2 million barrels (0.8 million domestic and 4.4 million export), respectively. Prices for crude oil for the period until it was sold on September 25, 2003 and for the yearsyear ended September 30, 2002 and 2001 averaged $14.52 ($8.61 domestic and $23.05 export), and $13.25 ($8.89 domestic and $21.73 export) and $19.51 ($13.69 domestic and $20.48 export) per barrel, respectively. Depletion expense attributable to Geoilbent for the period until it was sold on September 25, 2003 and for the yearsyear ended September 30, 2002 and 2001 was $3.23 $3.93 and $2.88$3.93 per barrel, respectively. All amounts represent 100 percent of Geoilbent. Summarized financial information for Geoilbent follows (in thousands):                         2003   2002   2001                 Year ended September 30:     2003   2002   Revenues     Oil sales   $ 81,724   $ 91,598   $ 101,159     $ 81,724   $ 91,598                             Expenses     Selling and distribution expenses   5,893   6,696   9,876     5,893   6,696   Operating expenses   15,897   15,360   11,415     15,897   15,360   Depletion, depreciation and amortization   18,182   27,168   14,918     18,182   27,168   Write-downs of oil and gas properties   95,000   —   —     95,000   —   General and administrative   9,456   8,335   5,650     9,456   8,335   Taxes other than on income   25,626   27,657   26,011     25,626   27,657                             170,054   85,216   67,870     170,054   85,216                             Income (loss) from operations     (88,330 )   6,382   33,289       (88,330 )   6,382   Other non-operating income (expense)     Investment earnings and other   1,064   381   648     1,064   381   Interest expense     (1,992 )     (4,629 )     (7,547 )     (1,992 )     (4,629 ) Net gain on exchange rates   1,566   2,053   781     1,566   2,053                             638     (2,195 )     (6,118 )   638     (2,195 )                           Income (loss) before income taxes     (87,692 )   4,187   27,171       (87,692 )   4,187   Income tax expense     (3,117 )   302   6,751   Income tax (benefit) expense     (3,117 )   302                               (84,575 )   3,885   20,420       (84,575 )   3,885   Effects of change in accounting policy   310   —   —     310   —                           Net income (loss)   $ (84,885 )   $ 3,885   $ 20,420     $ (84,885 )   $ 3,885                           At September 30:   Current assets   $ 18,785   $ 35,447   Other assets   186,815   187,706   Current liabilities   54,051   60,439   Other liabilities   7,500   22,550   Net equity   144,049   140,164        As of September 30, 2002, the Geoilbent shareholders had provided Geoilbent with subordinate loans totaling $7.5 million ($2.5 million from us). These loans were unsecured, repayable in January 2004 and recorded as a current liability at September 30, 2003. The loan by us was repaid as part of the sale of our minority equity investment in Geoilbent. As of January 1, 2003, the Russian economy was no longer a highly inflationary economy. As a result, the Russian Ruble became the functional currency and not the U.S. dollar. S-20 Arctic Gas Company      On April 12, 2002, we sold our 68 percent equity interest in Arctic Gas. The equity earnings of Arctic Gas have historically been based on a fiscal year ended September 30. The fourth quarter of 2001, the first quarter of 2002 and the first twelve days of April have been included in the results for 2002.      We accounted for our interest in Arctic Gas using the equity method due to the significant influence we exercised over the operating and financial policies of Arctic Gas. Our weighted-average equity interest, for the year ended December 31, 2001 was 39 percent. We recorded as our share in the losses of Arctic Gas $1.5 million and $1.1 million for the period ended April 12, 2002 and September 30, 2001, respectively.2002. Summarized financial information for Arctic Gas follows (in thousands). All amounts represent 100 percent of Arctic Gas.                       2002   2001 Year ended September 30:                 Revenues                 Oil Sales   $ 7,880     $ 13,374                     Expenses                 Selling and distribution expenses     3,170       3,867   Operating expense     2,473       3,483   Depletion, depreciation and amortization     333       1,032   General and administrative     2,112       3,025   Taxes other than on income     1,261       3,881                           9,349       15,288                     Loss from operations     (1,469 )     (1,914 ) Other non-operating income (expense)                 Other income (expense)     (4 )     54   Interest and foreign exchange expense     (1,722 )     (1,848 )                         (1,726 )     (1,794 )                   Loss before income taxes     (3,195 )     (3,708 ) Income tax expense     —       —                     Net loss   $ (3,195 )   $ (3,708 )                   S-18           Year ended September 30:   2002     Revenues         Oil sales   $ 7,880             Expenses         Selling and distribution expenses     3,170   Operating expense     2,473   Depletion, depreciation and amortization     333   General and administrative     2,112   Taxes other than on income     1,261                 9,349                     Loss from operations     (1,469 )           Other non-operating expense         Other expense     (4 ) Interest and foreign exchange expense     (1,722 )               (1,726 )                   Loss before income taxes     (3,195 ) Income tax expense     —           Net loss   $ (3,195 )         Note 10 -9 — Venezuela Operations      On July 31, 1992, we and our partner, Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), signed an operating service agreement to reactivate and further develop three Venezuelan oil fields with Lagoven, S.A., then one of three exploration and production affiliates of the national oil company, PDVSA. The operating service agreement covers the Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit. Under the terms of the operating service agreement, Benton-Vinccler,Harvest Vinccler, a Venezuelan corporation owned 80 percent by us and 20 percent by Vinccler, is a contractor for PDVSA and is responsible for overall operations of the South Monagas Unit, including all necessary investments to reactivate and develop the fields comprising the South Monagas Unit. Benton-VincclerHarvest Vinccler receives an operating fee in U.S. dollarsDollars deposited into a U.S. commercial bank account for each barrel of crude oil produced (subject to periodic adjustments to reflect changes in a special energy index of the U.S. Consumer Price Index) and is reimbursed according to a prescribed formula in U.S. dollarsDollars for its capital costs, provided that such operating fee and cost recovery fee cannot exceed the maximum dollar amount per barrel set forth in the agreement.      In September 2002, Benton-VincclerHarvest Vinccler and PDVSA signed an amendment to the operating service agreement, providing for the delivery of up to 198 Bcf of natural gas through July 2012 at a price of $1.03 per Mcf. Natural gas sales commenced in the fourth quarter of 2003. In addition, Benton-VincclerHarvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the gas production at $7.00 per barrel beginning with our first gas sale. Initial gas production will come from Uracoa, which allows us to more efficiently manage the reservoir and eliminate the restrictions on producing oil wells with high gas to oil ratios. The gas reserves in Bombal will be used to meet the future terms of the gas contract in 2005. S-21      The Venezuelan government maintains full ownership of all hydrocarbons in the fields.      We drilled threeten oil wells and converted two gas injection wells to producingre-entered an additional six wells in 2003.2004. Note 11 -10 — United States Operations      We acquired a 100 percent interest in three California State offshore oil and gas leases (“California Leases”) and a parcel of onshore property from Molino Energy Company, LLC. All capitalizedIn June 2004, we sold our California onshore property, which had a zero carrying value, for net proceeds of $0.6 million. We and other parties may be responsible to the State of California for any remediation costs associated with the California Leases have been fully impaired. The California Leases have expired and we have listed the onshore property for sale.and the related offshore oil and gas leases. S-19 Note 12 -11 — China Operations      In December 1996, we acquired Crestone Energy Corporation, subsequently renamed Benton Offshore China Company. Its principal asset is a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under certain circumstances, and lies within an area which is the subject of a territorial dispute between the People’s Republic of China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The territorial dispute has lasted for many years, and there has been limited exploration and no development activity in the area under dispute. As part of a review of our assets, a third-party conducted an evaluation of the WAB-21 area. Through that evaluation and our own assessment, we recorded a $13.4 million impairment charge in the second quarter of 2002. An evaluation was performed again at December 31, 2003 and such evaluation indicated that noNo further impairment of the property had been incurred in 2003.is currently required. WAB-21 represents the $2.9 million excluded from the full cost pool as reflected on our December 31, 20032004 balance sheet. Note 13 -12 — Related Party Transactions      We haveIn March 2002, we entered into construction service agreements with Venezolana International, S.A. (“Vinsa”). Vinsa is an affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A., which owns 20 percent of Benton-Vinccler.Harvest Vinccler. Vinsa has provided $0.3 million, $1.7 million $0.5 million and $0.6$0.5 million in construction services onfor our Venezuelan gas pipeline and field operations for the years ended December 31, 2004, 2003 and 2002, and 2001, respectively. This agreement was terminated on September 19, 2004.      We haveIn August 1997, we entered into a consulting agreement with Oil & Gas Technology Consultants Inc. (“OGTC”) to provide operational and technical assistance in Venezuela. OGTC is an affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A., which owns 20 percent of Benton-Vinccler.Harvest Vinccler. Payment for services is due when earnings are not reinvested in Benton-VincclerHarvest Vinccler operations. The consulting agreement was cancelled January 1, 2004. Expenses related to this consulting agreement waswere $1.5 million $2.6 million and $2.5$2.6 million at December 31, 2003 2002 and 2001,2002, respectively.      From 1996 through 1998, we made unsecured loans to our then Chief Executive Officer, A. E. Benton, bearing interest at the rate of 6 percent per annum. We subsequently obtained a security interest inAs of December 31, 2004, Mr. Benton’s sharesdebt balance was $2.8 million. This amount is after the payment to us in 2004 of our$0.5 million from the proceeds, net of tax, of the exercise of stock and stock options. In August 1999,options issued to Mr. Benton, filedbut pledged to us to secure repayment of the debt, and a chapter 11 (reorganization) bankruptcy petition in$0.1 million payment under the U.S. Bankruptcy Court for the Central Districtexcess income provision of California, in Santa Barbara, California. In February 2000, we entered into a separationan agreement with Mr. Benton pursuant to which we retained Mr. Benton under a consulting agreement to perform certain services for us. In addition, the consulting agreement provided Mr. Benton with incentive bonuses tied to our net cash receipts from the sale of our interests in Arctic Gas and Geoilbent. In June 2002, we made an incentive bonus payment to Mr. Benton of $1.5 million, subject to future adjustment, in connection with the Arctic Gas sale. We recorded the bonus payment as a reduction of the gain on the Arctic Gas sale. In November 2003, we made a payment to Mr. Benton of $0.5 million for the incentive bonus associated with the sale of our minority equity investment in Geoilbent.      In May 2001, we and Mr. Benton entered into a settlement and release agreement under which the consulting agreement was terminated as to future services and Mr. Benton agreed to propose a plan of reorganization in his bankruptcy case that provided for the repayment of our loans to him. In March 2002, Mr. Benton filed a plan of reorganization, and on July 31, 2002, the bankruptcy court confirmed the plan of reorganization. At the time the plan became final, Mr. Benton’s indebtedness to us was about $6.7 million for which we provided a full allowance for bad debt. On August 14, 2002, we exercised our rights with respect to 600,000 shares of our stock pledged to us as partial repayment of the loan and took the shares into our treasury stock. Based on a $3.56 closing price for the stock on that date, the value of the shares was $2.1 million. Also, in September 2002 and July 2003, we received payments of approximately $1.3 million as distributions from Mr. S-22 Benton’s debtor-in-possession account. Finally, under the terms of the settlement agreement, we have retained about $0.2 million from the Arctic Gas and Geoilbent bonus payments to Mr. Benton, bringing the total recovery on Mr. Benton’s debt to $3.7 million.Benton. We continue to accrue interest and provide a bad debt allowance on the remaining amount due. In addition, we hold the rights to direct the exercise of Mr. Benton’s stock options.      We and Mr. Benton disagreed over Mr. Benton’s remaining obligations to us under the settlement agreement and plan of reorganization. In addition, Mr. Benton claimed that he was due significant additional amounts with respect to the incentive bonus associated with the Arctic Gas sale. We and Mr. Benton submitted our dispute to binding arbitration and in October 2003 the arbitrator found in favor of Mr. Benton in all material respects. As a result, in October 2003, we made a payment to Mr. Benton of $1.9 million for the balance of the incentive bonus associated with the Arctic Gas sale and released certain funds for the payment of Mr. Benton’s taxes and expenses related to the disposition of his 600,000 shares of stock. Note 14 -13 — Earnings Per Share      Basic earnings per common share (“EPS”) are computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. The weighted average number of common shares outstanding for computing basic EPS was 36.1 million, 35.3 million 34.6 million and 33.934.6 million for the years ended December 31, 2004, 2003 2002 and 2001,2002, respectively. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The weighted average number of common shares outstanding for computing diluted EPS, including dilutive stock options, was 38.1 million, 36.8 million, 36.1 million and 34.0 million for the years ended December 31, 2004, 2003 2002 and 2001,2002, respectively.      An aggregate of 2.50.9 million options and warrants were excluded from the earnings per share calculations because they were anti-dilutivetheir exercise price exceeded the average price for the year ended December 31, 2003.2004. For the years ended December 31, 2003 and 2002, and 2001, 3.52.5 million and 6.73.5 million options and warrants, respectively, were excluded from the earnings per share calculations because they were anti-dilutive.their exercise price exceeded the average price. S-23S-20 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES Quarterly Financial Data (unaudited)      Summarized quarterly financial data is as follows:                                                           Quarter Ended   Quarter Ended     March 31   June 30   September 30   December 31   March 31   June 30   September 30   December 31     (amounts in thousands, except per share data)   (amounts in thousands, except per share data)   Year ended December 31, 2003   Year ended December 31, 2004   Revenues   $ 18,825   $ 28,576   $ 27,834   $ 30,860     $ 38,797   $ 41,397   $ 46,053   $ 59,819   Expenses     (13,901 )     (19,911 )     (20,037 )     (18,619 )     (20,329 )     (20,478 )     (24,697 )     (30,082 ) Non-operating income (expense)     (1,864 )     (2,288 )   44,056     (1,743 )     (2,795 )     (2,031 )     (4,779 )   391                                       Income from consolidated companies before income taxes and minority interests   3,060   6,377   51,853   10,498     15,673   18,888   16,577   30,128   Income tax expense   1,056   3,104   3,603   1,894     5,600   9,902   7,617   10,169                                       Income before minority interests   2,004   3,273   48,250   8,604     10,073   8,986   8,960   19,959   Minority interests   887   1,216   1,367   2,498     2,566   2,738   3,654   4,660                                       Income from consolidated companies   1,117   2,057   46,883   6,106   Equity in net income (losses) of affiliated companies     (16,575 )     (13,470 )     (473 )   1,658   Net income   $ 7,507   $ 6,248   $ 5,306   $ 15,299                                       Net income (loss)   $ (15,458 )   $ (11,413 )   $ 46,410   $ 7,764   Other comprehensive income (loss)   2,614     (3,001 )   21   366                       Total comprehensive income (loss)   $ (12,844 )   $ (14,414 )   $ 46,431   $ 8,130                     Net income (loss) per common share:   Net income per common share:   Basic   $ (0.44 )   $ (0.32 )   $ 1.31   $ 0.22     $ 0.21   $ 0.17   $ 0.15   $ 0.42                                       Diluted   $ (0.44 )   $ (0.32 )   $ 1.25   $ 0.21     $ 0.20   $ 0.16   $ 0.14   $ 0.39                                         Other comprehensive income (loss)   —   —     (2,357 )   1,870                     Total comprehensive income   $ 7,507   $ 6,248   $ 2,949   $ 17,169                                                                               Quarter Ended   Quarter Ended     March 31   June 30   September 30   December 31   March 31   June 30   September 30   December 31     (amounts in thousands, except per share data)   (amounts in thousands, except per share data)   Year ended December 31, 2002   Year ended December 31, 2003   Revenues   $ 27,247   $ 33,022   $ 38,841   $ 27,621     $ 18,825   $ 28,576   $ 27,834   $ 30,860   Expenses     (18,720 )     (35,747 )     (17,914 )     (19,765 )     (13,901 )     (19,911 )     (20,037 )     (18,619 ) Non-operating income (expense)     (3,948 )   142,940     (818 )     (2,948 )     (1,864 )     (2,288 )   44,056     (1,743 )                                     Income from consolidated companies before income taxes and minority interests   4,579   140,215   20,109   4,908     3,060   6,377   51,853   10,498   Income tax expense (benefit)   1,801   59,692   6,612     (7,810 ) Income tax expense   1,056   3,104   3,603   1,894                                       Income before minority interests   2,778   80,523   13,497   12,718     2,004   3,273   48,250   8,604   Minority interests   1,380   2,031   2,590   3,318     887   1,216   1,367   2,498                                       Income from consolidated companies   1,398   78,492   10,907   9,400     1,117   2,057   46,883   6,106   Equity in net income (losses) of affiliated companies   87     (2,172 )   1,209   1,041       (16,575 )     (13,470 )     (473 )   1,658                                       Net income   $ 1,485   $ 76,320   $ 12,116   $ 10,441   Net income (loss)   $ (15,458 )   $ (11,413 )   $ 46,410   $ 7,764                                       Other comprehensive loss   —   —     (658 )   658                       Total comprehensive income   1,485   76,320   11,458   11,099                     Net income per common share:   Net income (loss) per common share:   Basic   $ 0.04   $ 2.20   $ 0.35   $ 0.30     $ (0.44 )   $ (0.32 )   $ 1.31   $ 0.22                                       Diluted   $ 0.04   $ 2.10   $ 0.33   $ 0.28     $ (0.44 )   $ (0.32 )   $ 1.25   $ 0.21                                         Other comprehensive income (loss)   2,614     (3,001 )   21   366                     Total comprehensive income (loss)   $ (12,844 )   $ (14,414 )   $ 46,431   $ 8,130                          In the second quarter of 2002, we recognized in non-operating income, the $144.0 million pre-tax gain on the Arctic Gas Sale, and in expense, the write-down of capitalized costs of $13.4 million associated with our WAB-21 offshore China concession. S-24 Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)      In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS 69”), this section provides supplemental information on our oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. S-21 TABLE I -— Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):                                   United States         Venezuela   China   and Other   Total   Year Ended December 31, 2004   Development costs   $ 39,161   $ —   $ —   $ 39,161   Exploration costs   10   53   —   63                                                   $ 39,171   $ 53   $ —   $ 39,224     United States                         Venezuela   China   and Other   Total   Year Ended December 31, 2003     Development costs   $ 58,079   $ —   $ 2   $ 58,081     $ 58,079   $ —   $ 2   $ 58,081   Exploration costs   11   39   133   183     11   39   133   183                                         $ 58,090   $ 39   $ 135   $ 58,264     $ 58,090   $ 39   $ 135   $ 58,264                                         Year Ended December 31, 2002     Development costs   $ 49,163   $ 120   $ 577   $ 49,860   �� $ 49,163   $ 120   $ 577   $ 49,860   Exploration costs   794     (149 )   88   733     794     (149 )   88   733                                         $ 49,957   $ (29 )   $ 665   $ 50,593     $ 49,957   $ (29 )   $ 665   $ 50,593                                       Year Ended December 31, 2001   Acquisition costs   $   $   $   $   Development costs   35,194   77   28   35,299   Exploration costs   7,694   —   909   8,603                       $ 42,888   $ 77   $ 937   $ 43,902                     TABLE II -— Capitalized costs related to oil and natural gas producing activities (in thousands):                                   United States         Venezuela   China   and Other   Total   Year Ended December 31, 2004   Proved property costs   $ 608,225   $ 13,454   $ —   $ 621,679   Costs excluded from amortization   —   2,900   —   2,900   Oilfield inventories   6,503   —   —   6,503   Less accumulated depletion and impairment     (432,302 )     (13,454 )   —     (445,756 )                                                     $ 182,426   $ 2,900   $ —   $ 185,326     United States                         Venezuela   China   and Other   Total   December 31, 2003     Proved property costs   $ 569,055   $ 13,401   $ —   $ 582,456     $ 569,055   $ 13,401   $ —   $ 582,456   Costs excluded from amortization   —   2,900   —   2,900     —   2,900   —   2,900   Oilfield inventories   8,266   —   —   8,266     8,266   —   —   8,266   Less accumulated depletion and impairment     (398,206 )     (13,401 )   —     (411,607 )     (398,206 )     (13,401 )   —     (411,607 )                                       $ 179,115   $ 2,900   $ —   $ 182,015     $ 179,115   $ 2,900   $ —   $ 182,015                                         December 31, 2002     Proved property costs   $ 519,175   $ 26,210   $ 21,030   $ 566,415     $ 519,175   $ 26,210   $ 21,030   $ 566,415   Costs excluded from amortization   —   2,900   —   2,900     —   2,900   —   2,900   Oilfield inventories   7,286   —   —   7,286     7,286   —   —   7,286   Less accumulated depletion and impairment     (386,824 )     (26,210 )     (20,764 )     (433,798 )     (386,824 )     (26,210 )     (20,764 )     (433,798 )                                       $ 139,637   $ 2,900   $ 266   $ 142,803     $ 139,637   $ 2,900   $ 266   $ 142,803                                       December 31, 2001   Proved property costs   $ 469,218   $ 12,892   $ 19,813   $ 501,923   Costs excluded from amortization   —   16,248   560   16,808   Oilfield inventories   15,219   —   —   15,219   Less accumulated depletion and impairment     (361,313 )     (12,892 )     (19,544 )     (393,749 )                     $ 123,124   $ 16,248   $ 829   $ 140,201                     S-25S-22 TABLE III -— Results of operations for oil and natural gas producing activities (in thousands):                                                           United States       United States         Venezuela   China   and Other   Total   Venezuela   China   and Other   Total   Year ended December 31, 2004   Oil and natural gas revenues   $ 186,066   $ —   $ —   $ 186,066   Expenses:   Operating, selling and distribution expenses and taxes other than on income   33,297   —   214   33,511   Depletion   34,108   —   —   34,108   Income tax expense   38,968   —   —   38,968                     Total expenses   106,373   —   214   106,587                     Results of operations from oil and natural gas producing activities   $ 79,693   $ —   $ (214 )   $ 79,479                       Year ended December 31, 2003     Oil sales   $ 106,095   $ —   $ —   $ 106,095   Oil and natural gas revenues   $ 106,095   $ —   $ —   $ 106,095   Expenses:     Operating, selling and distribution expenses and taxes other than on income   31,445   —   76   31,521     31,445   —   76   31,521   Write-down of oil and gas properties and impairments   —   23   142   165     —   23   142   165   Depletion   19,599   —   —   19,599     19,599   —   —   19,599   Income tax expense   12,158   —   1,187   13,345     12,158   —   1,187   13,345                                       Total expenses   63,202   23   1,405   64,630     63,202   23   1,405   64,630                                       Results of operations from oil and natural gas producing activities   $ 42,893   $ (23 )   $ (1,405 )   $ 41,465     $ 42,893   $ (23 )   $ (1,405 )   $ 41,465                                         Year ended December 31, 2002     Oil sales   $ 126,731   $ —   $ —   $ 126,731   Oil revenue   $ 126,731   $ —   $ —   $ 126,731   Expenses:     Operating, selling and distribution expenses and taxes other than on income   31,608   2,493   —   34,101     31,608   2,493   —   34,101   Write-down of oil and gas properties and impairments   —   13,371   1,166   14,537     —   13,371   1,166   14,537   Depletion   24,941   —   —   24,941     24,941   —   —   24,941   Income tax expense   4,715   3   —   4,718     4,715   3   —   4,718                                       Total expenses   61,264   15,867   1,166   78,297     61,264   15,867   1,166   78,297                                       Results of operations from oil and natural gas producing activities   $ 65,467   $ (15,867 )     (1,166 )   48,434     $ 65,467   $ (15,867 )     (1,166 )   48,434                                       Year ended December 31, 2001   Oil and natural gas sales   $ 122,386   $ —   $ —   $ 122,386   Expenses:   Operating, selling and distribution expenses and taxes other than on income   42,212   —   722   42,934   Write-down of oil and gas properties and impairments   —   13   455   468   Depletion   22,119   —   —   22,119   Income tax expense   11,156   —   13   11,169                     Total expenses   75,487   13   1,190   76,690                     Results of operations from oil and natural gas producing activities   $ 46,899   $ (13 )   $ (1,190 )   $ 45,696                     TABLE IV -— Quantities of Oil and Natural Gas Reserves      Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological 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. All Venezuelan reserves are attributable to an operating service agreement between Benton-VincclerHarvest Vinccler and PDVSA, under which all mineral rights are owned by the government of Venezuela. Venezuelan reserves include production projected through the end of the operating service agreement in July 2012. Benton-Vinccler has requested thatWe believe the operating service agreement period be extended fortwo months representing the delay due to the time sales were halted by the national civil work stoppage underwill be added to the original term of the operating service agreement pursuant to the force majeure clause.provisions of the agreement.      The SEC requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. 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, economic changes and economic changes.other relevant developments. 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.      Proved Developed Reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well. S-26S-23      Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.      Proved Undeveloped Reserves are Proved Reserves which 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 are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates.      Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir.      Changes in previous estimates of Proved Reserves result from new information obtained from production history and changes in economic factors.      The evaluations of the oil and natural gas reserves as of December 31, 2004, 2003 2002 and 20012002 were prepared by Ryder Scott Company L.P., independent petroleum engineers.      The tables shown below represent our interests in the United SatesVenezuela and VenezuelaRussia in each of the years.                                               Minority       Minority         Interest in       Interest in         Venezuela   Venezuela   Net Total   Venezuela   Venezuela   Net Total   Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls)     Year ended December 31, 2004   Proved Reserves at beginning of the year   87,872     (17,574 )   70,298   Revisions of previous estimates     (1,578 )   316     (1,262 ) Purchases of reserves in place   —   —   —   Extensions, discoveries and improved recovery   —   —   —   Production     (8,152 )   1,630     (6,522 ) Sales of reserves in place   —   —   —                 Proved Reserves at end of the year   78,142     (15,628 )   62,514                   Year ended December 31, 2003     Proved Reserves beginning of the year   95,168     (19,033 )   76,135     95,168     (19,033 )   76,135   Revisions of previous estimates     (521 )   104     (417 )     (521 )   104     (417 ) Extensions, discoveries and improved recovery   572     (114 )   458     572     (114 )   458   Production     (7,347 )   1,469     (5,878 )     (7,347 )   1,469     (5,878 ) Sales of reserves in place   —   —   —     —   —   —                               Proved Reserves at end of the year   87,872     (17,574 )   70,298     87,872     (17,574 )   70,298                                 Year ended December 31, 2002     Proved Reserves beginning of the year   104,514     (20,903 )   83,611     104,514     (20,903 )   83,611   Revisions of previous estimates   362     (72 )   290     362     (72 )   290   Extensions, discoveries and improved recovery   —   —   —     —   —   —   Production     (9,708 )   1,942     (7,766 )     (9,708 )   1,942     (7,766 ) Sales of reserves in place   —   —   —     —   —   —                               Proved Reserves at end of the year   95,168     (19,033 )   76,135     95,168     (19,033 )   76,135                               Russia – Geoilbent (34%) Proved Reserves at end of the year   24,781     24,781               Year ended December 31, 2001   Proved Reserves at beginning of the year   123,039     (24,608 )   98,431   Revisions of previous estimates     (8,747 )   1,749     (6,998 ) Purchases of reserves in place   —   —   —   Extensions, discoveries and improved recovery   —   —   —   Production     (9,778 )   1,956     (7,822 ) Sales of reserves in place   —   —   —                 Proved Reserves at end of the year   104,514     (20,903 )   83,611                 Russia – Arctic Gas (39%) Proved Reserves at end of the year   20,964         Russia – Geoilbent (34%) Proved Reserves at end of the year   29,668         S-27S-24                                               Minority       Minority         Interest in       Interest in         Venezuela   Venezuela   Net Total   Venezuela   Venezuela   Net Total   Proved Developed Reserves at:   Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at:   December 31, 2004   45,488     (9,098 )   36,390   December 31, 2003   45,860     (9,172 )   36,688     45,860     (9,172 )   36,688   December 31, 2002   53,833     (10,767 )   43,066     53,833     (10,767 )   43,066   December 31, 2001   51,465     (10,293 )   41,172   January 1, 2001   67,217     (13,443 )   53,774   Russia – Arctic Gas Proved Reserves at end of the year   2001 (39%)   2,483   2000 (29%)   2,325   Russia – Geoilbent (34%) Proved Reserves at end of the year   2002   11,840   2001   15,658   2000   14,913   Proved Reserves-natural gas (MMcf)   January 1, 2002   51,465     (10,293 )   41,172     Russia – Geoilbent (34%) Proved Reserves at end of the year 2002   11,840     Proved Reserves-Natural gas (MMcf)     Year ended December 31, 2004   Proved Reserves beginning of the year   195,500     (39,100 )   156,400   Revisions of previous estimates     (159 )   32     (127 ) Extensions, discoveries and improved recovery   —   —   —   Production     (31,059 )   6,212     (24,847 )               Proved Reserves end of the year   164,282     (32,856 )   131,426                   Year ended December 31, 2003     Proved Reserves beginning of the year   198,000     (39,600 )   158,400     198,000     (39,600 )   158,400   Revisions of previous estimates   160     (32 )   128     160     (32 )   128   Extensions, discoveries and improved recovery   —   —   —     —   —   —   Production     (2,660 )   532     (2,128 )     (2,660 )   532     (2,128 )                             Proved Reserves end of the year   195,500     (39,100 )   156,400     195,500     (39,100 )   156,400                                 Year ended December 31, 2002     Proved Reserves beginning of the year   —   —   —     —   —   —   Revisions of previous estimates   —   —   —     —   —   —   Extensions, discoveries and improved recovery   198,000     (39,600 )   158,400     198,000     (39,600 )   158,400   Sales of reserves in place   —   —   —     —   —   —                               Proved Reserves end of the year   198,000     (39,600 )   158,400     198,000     (39,600 )   158,400                               Russia – Arctic Gas (39%) Proved Reserves – December 31, 2001   ��   208,010           Russia – Arctic Gas (39%) Proved Reserves – December 31, 2000   152,496         Proved Developed Reserves at:   Proved Developed Reserves-Natural gas (MMcf) at:   December 31, 2004   80,897     (16,179 )   64,718   December 31, 2003   106,147     (21,229 )   84,918     106,147     (21,229 )   84,918   December 31, 2002   105,000     (21,000 )   84,000     105,000     (21,000 )   84,000   Russia – Arctic Gas 2001 (39%)   21,292   Russia – Arctic Gas 2000 (29%)   17,801   TABLE V - TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities      The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.      Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.      The tables shown below represent our interest in Venezuela in each of the years. In addition to these reserves is our 34 percent interest in Geoilbent at December 31, 2002 and our Arctic Gas interest of 39% at December 31, 2001. This combined with our Venezuela crude oil and natural gas reserves represent our net interest in all reserves as of December 31, 2003.2002. We report the results of Ryder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan reserves. S-28S-25                                                   Minority       Minority         Interest in       Interest in         Venezuela   Venezuela   Net Total     (amounts in thousands)   December 31, 2004   Future cash inflow   $ 1,852,045   $ (370,409 )   $ 1,481,636   Future production costs     (342,373 )   68,475     (273,898 ) Future development costs     (141,565 )   28,313     (113,252 )               Future net revenue before income taxes   1,368,107     (273,621 )   1,094,486   10% annual discount for estimated timing of cash flows     (365,580 )   73,116     (292,464 )               Discounted future net cash flows before income taxes   1,002,527     (200,505 )   802,022   Future income taxes, discounted at 10% per annum     (321,302 )   64,260     (257,042 )               Standardized measure of discounted future net cash flows   $ 681,225   $ (136,245 )   $ 544,980     Venezuela   Venezuela   Net Total                 (amounts in thousands)   December 31, 2003     Future cash inflow   $ 1,513,525   $ (302,705 )   $ 1,210,820     $ 1,513,525   $ (302,705 )   $ 1,210,820   Future production costs     (382,577 )   76,515     (306,062 )     (382,577 )   76,515     (306,062 ) Future development costs     (130,160 )   26,032     (104,128 )     (130,160 )   26,032     (104,128 )                             Future net revenue before income taxes   1,000,788     (200,158 )   800,630     1,000,788     (200,158 )   800,630   10% annual discount for estimated timing of cash flows     (319,152 )   63,830     (255,322 )     (319,152 )   63,830     (255,322 )                             Discounted future net cash flows before income taxes   681,636     (136,328 )   545,308     681,636     (136,328 )   545,308   Future income taxes, discounted at 10% per annum     (223,172 )   44,634     (178,538 )     (223,172 )   44,634     (178,538 )                             Standardized measure of discounted future net cash flows   $ 458,464   $ (91,694 )   $ 366,770     $ 458,464   $ (91,694 )   $ 366,770                                 December 31, 2002     Future cash flows   $ 1,510,346   $ (302,069 )   $ 1,208,277     $ 1,510,346   $ (302,069 )   $ 1,208,277   Future production costs     (400,694 )   80,139     (320,555 )     (400,694 )   80,139     (320,555 ) Future development costs     (192,671 )   38,534     (154,137 )     (192,671 )   38,534     (154,137 )                             Future net revenue before income taxes   916,981     (183,396 )   733,585     916,981     (183,396 )   733,585   10% annual discount for estimated timing of cash flows     (315,376 )   63,075     (252,301 )     (315,376 )   63,075     (252,301 )                             Discounted future net cash flows before income taxes   601,605     (120,321 )   481,284     601,605     (120,321 )   481,284   Future income taxes, discounted at 10% per annum     (204,356 )   40,871     (163,485 )     (204,356 )   40,871     (163,485 )                             Standardized measure of discounted future net cash flows   $ 397,249   $ (79,450 )   $ 317,799     $ 397,249   $ (79,450 )   $ 317,799                               Russia – Geoilbent (34%)   $ 45,395   Russia — Geoilbent (34%)   $ 45,395               December 31, 2001   Future cash inflow   $ 1,030,404   $ (206,081 )   $ 824,323   Future production costs     (558,431 )   111,686     (446,745 ) Future development costs     (142,006 )   28,401     (113,605 )               Future net revenue before income taxes   329,967     (65,994 )   263,973   10% annual discount for estimated timing of cash flows     (109,704 )   21,941     (87,763 )               Discounted future net cash flows before income taxes   220,263     (44,053 )   176,210   Future income taxes, discounted at 10% per annum     (16,103 )   3,221     (12,882 )               Standardized measure of discounted future net cash flows   $ 204,160   $ (40,832 )   $ 163,328                 Russia – Arctic Gas (29%)   $ 82,205         Russia – Geoilbent (34%)   $ 70,648         TABLE VI — Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves                                                 Net Venezuela       Net Venezuela     2003   2002   2001   2004   2003   2002     (amounts in thousands)   (amounts in thousands)   Present Value at January 1   $ 317,799   $ 163,328   $ 284,549     $ 366,770   $ 317,799   $ 163,328   Sales of oil and natural gas, net of related costs     (59,720 )     (76,098 )     (64,139 )     (122,215 )     (59,720 )     (76,098 ) Revisions to estimates of Proved Reserves     Net changes in prices, development and production costs   76,037   310,043     (141,429 )   333,237   76,037   310,043   Quantities     (1,584 )   611     (26,198 )     (7,597 )     (1,584 )   611   Extensions, discoveries and improved recovery, net of future costs   4,971   89,670   —     —   4,971   89,670   Accretion of discount   48,128   17,621   36,846     54,531   48,128   17,621   Net change in income taxes     (15,053 )     (150,603 )   71,033       (78,504 )     (15,053 )     (150,603 ) Development costs incurred   46,463   40,532   23,768     31,329   46,463   40,532   Changes in timing and other     (50,271 )     (77,305 )     (21,102 )     (32,571 )     (50,271 )     (77,305 )                             Present Value at December 31   $ 366,770   $ 317,799   $ 163,328     $ 544,980   $ 366,770   $ 317,799                               S-29S-26 Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Russia Equity Affiliates as of September 30, their fiscal year end.      In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS 69”), this section provides supplemental information on our oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.      Geoilbent (34 percent ownership until sold September 25, 2003) and Arctic Gas (39 percent ownership not subject to certain sale and transfer restrictions at December 31, 2001, until Arctic Gas was sold on April 12, 2002, respectively), which are accounted for under the equity method, have been included at their respective ownership interests in the consolidated financial statements and the following Tables based on a fiscal period ending September 30 and, accordingly, results of operations for oil and natural gas producing activities in Russia reflect the yearsyear ended September 30, 2002 and 2001.2002. TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):                                               Total Equity   Total Equity     Arctic Gas   Geoilbent   Affiliates   Arctic Gas   Geoilbent   Affiliates   Year Ended September 25, 2003     Development costs   $ —   $ 3,474   $ 3,474     $ —   $ 3,474   $ 3,474   Exploration costs   —   1,034   1,034     —   1,034   1,034                                 $ —   $ 4,508   $ 4,508     $ —   $ 4,508   $ 4,508                                 Year Ended September 30, 2002     Development costs   $ —   $ 8,599   $ 8,599     $ —   $ 8,599   $ 8,599   Exploration costs   16,156   498   16,654     16,156   498   16,654                                 $ 16,156   $ 9,097   $ 25,253     $ 16,156   $ 9,097   $ 25,253                               Year Ended September 30, 2001   Development costs   $ —   $ 11,483   $ 11,483   Exploration costs   8,136   2,074   10,210                   $ 8,136   $ 13,557   $ 21,693                 TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):                                                   Total Equity   Total Equity     Arctic Gas   Geoilbent   Affiliates   Arctic Gas   Geoilbent   Affiliates   September 25, 2003     Proved property costs   $ —   $ 102,753   $ 102,753     $ —   $ 102,753   $ 102,753   Oilfield inventories   —   2,530   2,530     —   2,530   2,530   Less accumulated depletion and impairment   —     (72,333 )     (72,333 )   —     (72,333 )     (72,333 )                               $ —   $ 32,950   $ 32,950     $ —   $ 32,950   $ 32,950                                 September 30, 2002     Proved property costs   $ —   $ 94,404   $ 94,404     $ —   $ 94,404   $ 94,404   Costs excluded from amortization   —   272   272     —   272   272   Oilfield inventories   —   2,348   2,348     —   2,348   2,348   Less accumulated depletion and impairment   —     (31,440 )     (31,440 )   —     (31,440 )     (31,440 )                               $ —   $ 65,584   $ 65,584     $ —   $ 65,584   $ 65,584                               September 30, 2001   Proved property costs   $ 5,786   $ 85,677   $ 91,463   Costs excluded from amortization   11,549   —   11,549   Oilfield inventories   175   4,357   4,532   Less accumulated depletion and impairment     (389 )     (22,203 )     (22,592 )                 $ 17,121   $ 67,831   $ 84,952                 S-30 TABLE III — Results of operations for oil and natural gas producing activities (in thousands):                                               Total Equity   Total Equity     Arctic Gas   Geoilbent   Affiliates   Arctic Gas   Geoilbent   Affiliates   Year ended September 25, 2003     Oil sales   $ —   $ 27,876   $ 27,876     $ —   $ 27,876   $ 27,876   Expenses:     Operating, selling and distribution expenses and taxes other than on income   —   16,088   16,088     —   16,088   16,088   Depletion   —   6,215   6,215     —   6,215   6,215   Write-down of oil and gas properties   —   32,300   32,300     —   32,300   32,300   Income tax expense   —   2,073   2,073     —   2,073   2,073                               Total expenses   —   56,676   56,676     —   56,676   56,676                               Results of operations from oil and natural gas producing activities   $ —   $ (28,800 )   $ (28,800 )   $ —   $ (28,800 )   $ (28,800 )                             Year ended September 30, 2002   Oil sales   $ 3,554   $ 31,039   $ 34,593   Expenses:   Operating, selling and distribution expenses and taxes other than on income   3,102   16,902   20,004   Depletion   139   9,237   9,376   Income tax expense   19   1,955   1,974                 Total expenses   3,260   28,094   31,354                 Results of operations from oil and natural gas producing activities   $ 294   $ 2,945   $ 3,239                 Year ended September 30, 2001   Oil sales   $ 4,016   $ 34,261   $ 38,277   Expenses:   Operating, selling and distribution expenses and taxes other than on income   3,381   16,083   19,464   Depletion   311   5,072   5,383   Income tax expense   80   3,742   3,822                 Total expenses   3,772   24,897   28,669                 Results of operations from oil and natural gas producing activities   $ 244   $ 9,364   $ 9,608                 S-27                                               Total Equity       Arctic Gas     Geoilbent     Affiliates   Year ended September 30, 2002                         Oil sales   $ 3,554     $ 31,039     $ 34,593   Expenses:                         Operating, selling and distribution expenses and taxes other than on income     3,102       16,902       20,004   Depletion     139       9,237       9,376   Income tax expense     19       1,955       1,974                       Total expenses     3,260       28,094       31,354                       Results of operations from oil and natural gas producing activities   $ 294     $ 2,945     $ 3,239                       TABLE IV — Quantities of Oil and Natural Gas Reserves      Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological 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. Geoilbent and Arctic Gas oil and gas fields are situated on land belonging to the Government of the Russian Federation. Each obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Geoilbent had licenses to develop the North Gubkinskoye and South Tarasovskoye fields in western Siberia. Our 34 percent equity investment in Geoilbent was sold September 25, 2003. Arctic Gas had licenses to develop the Samburg and Yevo-Yakhinskiy fields in western Siberia. Arctic Gas was sold on April 12, 2002.      The SEC requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. 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.      Proved Developed Reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well. S-31      Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.      Proved Undeveloped Reserves are Proved Reserves which 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 are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates.      Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir.      Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.                                               Total Equity     Arctic Gas   Geoilbent   Affiliates Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls)                         Year ended September 30, 2003                         Proved reserves beginning of the year     —       25,356       25,356   Revisions of previous estimates     —       537       537   Extensions, discoveries and improved recovery     —       962       962   Production     —       (1,942 )     (1,942 ) Sales of reserves in place     —       (24,913 )     (24,913 )                           Proved reserves at end of the year     —       —       —                             Year ended September 30, 2002                         Proved Reserves beginning of the year     20,965       29,668       50,633   Revisions of previous estimates     —       (3,455 )     (3,455 ) Extensions, discoveries and improved recovery     —       1,493       1,493   Production     (89 )     (2,350 )     (2,439 ) Sales of reserves in place     (20,876 )     —       (20,876 )                           Proved Reserves at end of the year     —       25,356       25,356                             Year ended September 30, 2001                         Proved Reserves beginning of the year     15,821       32,614       48,435   Revisions of previous estimates     5,327       (5,594 )     (267 ) Extensions, discoveries and improved recovery     —       4,411       4,411   Production     (183 )     (1,763 )     (1,946 ) Sales of reserves in place     —       —       —                             Proved Reserves at end of the year     20,965       29,668       50,633                             Proved Developed Reserves at:                         September 30, 2003     —       —       —   September 30, 2002     —       13,200       13,200   September 30, 2001     2,483       15,658       18,141   October 1, 2000     2,325       14,913       17,238   Proved Reserves-natural gas (MMcf)                         Year ended September 30, 2002                         Proved Reserves beginning of the year     208,010       —       208,010   Revisions of previous estimates     —       —       —   Extensions, discoveries and improved recovery     —       —       —   Production     —       —       —   Sales of reserves in place     (208,010 )     —       (208,010 )                           Proved Reserves end of the year     —       —       —                             S-32S-28                                                   Total Equity   Total Equity     Arctic Gas   Geoilbent   Affiliates   Arctic Gas   Geoilbent   Affiliates   Year ended September 30, 2001   Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls)     Year ended September 30, 2003   Proved reserves beginning of the year   —   25,356   25,356   Revisions of previous estimates   —   537   537   Extensions, discoveries and improved recovery   —   962   962   Production   —     (1,942 )     (1,942 ) Sales of reserves in place   —     (24,913 )     (24,913 )               Proved reserves at end of the year   —   —   —                   Year ended September 30, 2002   Proved Reserves beginning of the year   20,965   29,668   50,633   Revisions of previous estimates   —     (3,455 )     (3,455 ) Extensions, discoveries and improved recovery   —   1,493   1,493   Production     (89 )     (2,350 )     (2,439 ) Sales of reserves in place     (20,876 )   —     (20,876 )               Proved Reserves at end of the year   —   25,356   25,356                   Proved Developed Reserves at:   September 30, 2003   —   —   —   September 30, 2002   —   13,200   13,200   October 1, 2001   2,483   15,658   18,141     Proved Reserves-natural gas (MMcf)   Year ended September 30, 2002   Proved Reserves beginning of the year   152,496   —   152,496     208,010   —   208,010   Revisions of previous estimates   55,514   —   55,514     —   —   —   Extensions, discoveries and improved recovery   —   —   —     —   —   —   Production   —   —   —     —   —   —   Sales of reserves in place   —   —   —       (208,010 )   —     (208,010 )                             Proved Reserves end of the year   208,010   —   208,010     —   —   —                                 Proved Developed Reserves at:     September 30, 2002   —   —   —     —   —   —   September 30, 2001   21,292   —   21,292   October 1, 2000   17,801   —   17,801   October 1, 2001   21,292   —   21,292   S-29 TABLE V - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities      The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.      Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.                                           Total Equity   Total Equity     Arctic Gas   Geoilbent   Affiliates   Geoilbent   Affiliates     (amounts in thousands)     (amounts in thousands)   September 30, 2003     Future cash inflow   $ —   $ 481,557   $ 481,557     $ 481,557   $ 481,557   Future production costs   —     (229,982 )     (229,982 )     (229,982 )     (229,982 ) Future development costs   —     (36,666 )     (36,666 )     (36,666 )     (36,666 )                         Future net revenue before income taxes   —   214,909   214,909     214,909   214,909   10% annual discount for estimated timing of cash flows   —     (99,948 )     (99,948 )     (99,948 )     (99,948 )                         Discounted future net cash flows before income taxes   —   114,961   114,961     114,961   114,961   Future income taxes, discounted at 10% per annum   —     (23,163 )     (23,163 )     (23,163 )     (23,163 )                         Standardized measure of discounted future net cash flows   $ —   $ 91,798   $ 91,798     $ 91,798   $ 91,798                             September 30, 2002     Future cash inflow   $ —   $ 469,837   $ 469,837     $ 469,837   $ 469,837   Future production costs   —     (203,754 )     (203,754 )     (203,754 )     (203,754 ) Future development costs   —     (40,707 )     (40,707 )     (40,707 )     (40,707 )                         Future net revenue before income taxes   —   225,376   225,376     225,376   225,376   10% annual discount for estimated timing of cash flows   —     (108,147 )     (108,147 )     (108,147 )     (108,147 )                         Discounted future net cash flows before income taxes   —   117,229   117,229     117,229   117,229   Future income taxes, discounted at 10% per annum   —     (24,290 )     (24,290 )     (24,290 )     (24,290 )                         Standardized measure of discounted future net cash flows   $ —   $ 92,939   $ 92,939     $ 92,939   $ 92,939                           September 30, 2001   Future cash inflow   $ 630,340   $ 434,348   $ 1,064,688   Future production costs     (373,458 )     (251,335 )     (624,793 ) Future development costs     (49,139 )     (37,020 )     (86,159 )               Future net revenue before income taxes   207,743   145,993   353,736   10% annual discount for estimated timing of cash flows     (99,343 )     (64,868 )     (164,211 )               Discounted future net cash flows before income taxes   108,400   81,125   189,525   Future income taxes, discounted at 10% per annum     (26,195 )     (10,477 )     (36,672 )               Standardized measure of discounted future net cash flows   $ 82,205   $ 70,648   $ 152,853                 S-33 TABLE VI — Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves                       Equity Affiliates       2003     2002       (amounts in thousands)   Present Value at October 1   $ 92,939     $ 152,853   Sales of oil and natural gas, net of related costs     (20,410 )     (23,644 ) Revisions to estimates of Proved Reserves                 Net changes in prices, development and production costs     (5,522 )     76,545   Quantities     3,178       (10,007 ) Sales of reserves in place     (91,798 )     (82,205 ) Extensions, discoveries and improved recovery, net of future costs     1,246       2,031   Accretion of discount     11,723       7,065   Net change in income taxes     1,127       1,145   Development costs incurred     4,507       8,999   Changes in timing and other     3,010       (39,843 )               Present Value at September 30   $ —     $ 92,939                 TABLE VI - Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves                                       Equity Affiliates             2003   2002   2001     (amounts in thousands) Present Value at October 1   $ 92,939     $ 152,853     $ 171,605   Sales of oil and natural gas, net of related costs     (20,410 )     (23,644 )     (19,001 ) Revisions to estimates of Proved Reserves                         Net changes in prices, development and production costs     (5,522 )     76,545       (39,880 ) Quantities     3,178       (10,007 )     8,881   Sales of reserves in place     (91,797 )     (82,205 )     —   Extensions, discoveries and improved recovery, net of future costs     1,245       2,031       18,767   Accretion of discount     11,723       7,065       21,468   Net change in income taxes     1,127       1,145       6,400   Development costs incurred     4,507       8,999       17,110   Changes in timing and other     3,010       (39,843 )     (32,497 )                           Present Value at September 30   $ —     $ 92,939     $ 152,853                             S-34S-30 SIGNATURES      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.             HARVEST NATURAL RESOURCES, INC. (Registrant)     Date: March 9, 2004 February 22, 2005  By:    /s/ Peter J. Hill       Peter J. Hill       Chief Executive Officer      Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the 9th22nd day of March, 2004,February, 2005, on behalf of the registrant and in the capacities indicated:       Signature   Title /s/Peter J. Hill   Director, President and Chief Executive Officer   Officer Peter J. Hill           /s/ Steven W. Tholen   Senior Vice President — Finance, Chief Financial Steven W. Tholen   Officer and Treasurer Steven W. Tholen (Principal Financial Officer)           /s/ Kurt A. Nelson   Vice President-Controller, Chief Accounting Officer     Kurt A. Nelson     (Principal Accounting Officer)           /s/ Stephen D. Chesebro’   Chairman of the Board and Director     Stephen D. Chesebro’           /s/ John U. Clarke   Director     John U. Clarke           /s/ Byron A. Dunn   Director     Byron A. Dunn           /s/ H. H. Hardee   Director     H.H. Hardee           /s/ Patrick M. Murray   Director     Patrick M. Murray     S-35S-31 SCHEDULE II HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES Valuation and Qualifying Accounts (in thousands)                                                                           Additions           Additions             Balance at   Charged to   Deductions   Balance at   Balance at   Charged to   Deductions   Balance at     Beginning   Charged to   Other   From   End of   Beginning   Charged to   Other   From   End of     of Year   Income   Accounts   Reserves   Year   of Year   Income   Accounts   Reserves   Year   At December 31, 2004   Amounts deducted from applicable assets   Accounts receivable   $ 3,355   $ —   $ —   $ 598   $ 2,757   Deferred tax valuation allowance   48,365     (3,284 )   —   —   45,081   Investment at cost   1,350   —   —   —   1,350   At December 31, 2003     Amounts deducted from applicable assets Amounts deducted from applicable assets   Accounts receivable   $ 3,525   $ 205   $ —   $ 375   $ 3,355     $ 3,525   $ 205   $ —   $ 375   $ 3,355   Deferred tax valuation allowance   39,146   9,219   —   —   48,365     39,146   9,219   —   —   48,365   Investment at cost   1,350   —   —   —   1,350     1,350   —   —   —   1,350   At December 31, 2002     Amounts deducted from applicable assets Amounts deducted from applicable assets   Accounts receivable   $ 6,512   $ 289   $ —   $ 3,276   $ 3,525     $ 6,512   $ 289   $ —   $ 3,276   $ 3,525   Deferred tax valuation allowance   19,700   20,577   —   1,131   39,146     19,700   20,577   —   1,131   39,146   Investment at cost   1,350   —   —   —   1,350     1,350   —   —   —   1,350   At December 31, 2001   Amounts deducted from applicable assets Accounts receivable   $ 6,518   $ 330   $ —   $ 336   $ 6,512   Deferred tax valuation allowance   54,207   14,352     (11,008 )   37,851   19,700   Investment at cost   1,350   —   —   —   1,350   S-36S-32 SCHEDULE III Financial Statements and Notes for LLC Geoilbent LLC Geoilbent Financial Statements 30 September 2003   REPORT OF INDEPENDENT AUDITORS To the Board of Directors and Owners of Limited Liability Company Geoilbent In our opinion, the accompanying balance sheets and the related statements of income, cash flows and changes in stockholders’ equity, present fairly, in all material respects, the financial position of LLC Geoilbent (the “Company”) at 30 September 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended 30 September 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements 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. The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Notes 4 and 10 to the financial statements, the Company has a long-term debt facility for which it is in violation of certain loan covenants and therefore the lender may declare the loan to be in default and can accelerate the maturity. Accordingly, this long-term debt has been classified in the accompanying financial statements as a current liability resulting in a working capital deficit of approximately US$35,772,000 as at 30 September 2003 which raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regards to this matter are also described in Note 4. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. ZAO PricewaterhouseCoopers Audit Moscow, Russian Federation 2 March 20032004 LLC GEOILBENT BALANCE SHEETS (expressed in thousand of US Dollars)                                       As at   As at     Notes   30 September 2003   30 September 2002 Assets                         Cash and cash equivalents             680       2,001   Restricted cash     10       1,217       1,469   Accounts receivable and advances to suppliers     7       7,161       6,308   Inventories     8       8,018       7,201   Deferred income tax, current     14       966       1,806                             Total current assets             18,042       18,785   Oil and gas producing properties, full cost method     9       89,469       185,989   Deferred income tax, non-current     14       —       696   Other long term assets             —       130                             Total assets             107,511       205,600                             Liabilities and Stockholders’ Equity                         Current portion of long-term debt     10       37,500       22,550   Accounts payable             6,559       15,244   Trade advances             993       3,000   Taxes payable     11       7,858       12,354   Other payables and accrued liabilities             904       903                             Total current liabilities             53,814       54,051                             Long-term debt     10       —       7,500   Asset retirement obligation     3       734       —                             Total liabilities             54,548       61,551                             Commitments and contingent liabilities     16       —       —   Contributed capital     12       82,518       82,518   Retained earnings (accumulated deficit)             (23,353 )     61,531   Accumulated other comprehensive loss             (6,202 )     —                             Total stockholders’ equity             52,963       144,049                             Total liabilities and stockholders’ equity             107,511       205,600                             The accompanying notes are an integral part of these financial statements.   LLC GEOILBENT STATEMENTS OF INCOME (expressed in thousand of US Dollars)                                               Year ended   Year ended   Year ended     Notes   30 September 2003   30 September 2002   30 September 2001 Total sales and other operating revenues     13       82,307       91,598       101,159                                     Costs and other deductions                                 Operating expenses             15,801       15,360       11,415   Selling and distribution expenses             5,893       6,696       9,876   General and administrative expenses             9,456       8,335       5,650   Depletion and amortization expense             18,278       27,168       14,918   Impairment of property, plant and equipment     9       95,000       —       —   Taxes other than income tax     14       25,625       27,657       26,011                                     Total costs and other deductions             170,053       85,216       67,870                                     Other income and expense                                 Exchange gain, net             (1,566 )     (2,053 )     (781 ) Interest expense, net             1,992       4,629       7,547   Other non-operating income, net             (481 )     (381 )     (648 )                                   Total other expense (income)             (55 )     2,195       6,118                                     Income (loss) before income tax             (87,691 )     4,187       27,171                                     Income tax expense     14                           Current income tax expense             3,542       2,804       6,751   Deferred income tax benefit             (6,659 )     (2,502 )     —                                     Total income tax expense (benefit)             (3,117 )     302       6,751                                     Income (loss) before cumulative effect of change in accounting principle, net of tax             (84,574 )     3,885       20,420   Cumulative effect of change in accounting principle, net of tax     3       (310 )     —       —                                     Net income (loss)             (84,884 )     3,885       20,420                                     The accompanying notes are an integral part of these financial statements.   LLC GEOILBENT STATEMENTS OF CASHFLOWS (expressed in thousand of US Dollars)                               Year ended   Year ended   Year ended     30 September 2003   30 September 2002   30 September 2001 Cash flows from operating activities                         Net income (loss)     (84,884 )     3,885       20,420   Adjustments to reconcile net income to net cash provided by operating activities:                         Depletion and amortization expense     18,278       27,168       14,918   Impairment of oil and gas properties     95,000       —       —   Amortization of financing costs     130       520       520   Exchange gain     (1,566 )     (2,053 )     (781 ) Deferred tax benefit     (6,659 )     (2,502 )     —   Decrease/(increase) in accounts receivable and advances to suppliers     (631 )     403       85   Decrease/(increase) in inventories     (544 )     6,362       (4,700 ) Increase/(decrease) in accounts payable     (9,030 )     (3,407 )     11,902   Increase/(decrease) in trade advances     (2,070 )     (5,747 )     3,785   Increase/(decrease) in taxes payable     (4,822 )     5,436       4,780   Decrease in other payables and accrued liabilities     (28 )     (1,378 )     (2,386 )                           Cash provided by operating activities     3,174       28,687       48,543                             Cash flow from investing activities                         Capital expenditures     (13,257 )     (26,755 )     (39,874 ) Proceeds on disposal of oil and gas producing properties     1,023       286       191   Disposal/(purchase) of investments     —       367       (129 )                           Net cash used in investing activities     (12,234 )     (26,102 )     (39,812 )                           Cash flows from financing activities                         Payment of short-term borrowings from founders     —       —       (717 ) Payment of short-terms borrowings     —       (3,000 )     (3,845 ) Proceeds from short-term borrowings     —       —       6,446   Proceeds from long-term borrowings from founders     —       7,500       —   Payments of long-term borrowings     (550 )     (18,200 )     (10,455 ) Proceeds from long-term borrowings     8,000       —       —   Decrease in restricted cash     252       8,738       2,153                             Net cash provided by (used in) financing activities     7,702       (4,962 )     (6,418 )                           Effect of foreign exchange on cash balances     37       (31 )     (37 )                           Net decrease in cash and cash equivalents     (1,321 )     (2,408 )     2,276   Cash and cash equivalents, beginning of year     2,001       4,409       2,133                             Cash and cash equivalents, end of year     680       2,001       4,409                             Supplemental cash flow information                         Interest paid     1,977       4,862       7,609   Income taxes paid     2,388       2,747       6,906   The accompanying notes are an integral part of these financial statements.   LLC GEOILBENT STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (expressed in thousands of US Dollars except as indicated)                                                               Total     Contributed   Retained earnings   Accumulated other   stockholders'     Capital   (accumulated deficit)   comprehensive loss   equity Balance at 30 September 2000     82,518       37,226       —       119,744                                     Net income and total comprehensive income     —       20,420       —       20,420                                     Balance at 30 September 2001     82,518       57,646       —       140,164                                     Net income and total comprehensive income     —       3,885       —       3,885                                     Balance at 30 September 2002     82,518       61,531       —       144,049                                     Net loss     —       (84,884 )     —       (84,884 ) Cumulative translation adjustment     —       —       (6,202 )     (6,202 )                                   Total comprehensive loss                             (91,086 )                                   Balance at 30 September 2003     82,518       (23,353 )     (6,202 )     52,963                                     The accompanying notes are an integral part of these financial statements.   LLC GEOILBENT NOTES TO THE FINANCIAL STATEMENTS (expressed in US Dollars except as indicated) Note 1: Organization LLC Geoilbent (the “Company”) is engaged in the development and production of oil and gas in the North Gubkinskoye and South Tarasovskoye fields. These fields are located in the West Siberian region of the Russian Federation, approximately 2,000 miles northeast of Moscow. The Company was established in December 1991 by two Russian oil companies, OAO Purneftegas (“PNG”) and OAO Purneftegasgeologia (“PNGG”), and by Harvest Natural Resources, Inc. (“Harvest”, formerly, Benton Oil and Gas Company) of the United States, which contributed 33%, 33% and 34%, respectively, of the Company’s charter capital, in accordance with the Company’s Foundation Document. In January 2002, PNG and PNGG transferred their stakes in the Company to OAO Minley. In September 2003, Harvest sold its interests in the Company to a company affiliated with OAO YUKOS (“YUKOS”). Note 2: Basis of Presentation The Company maintains its accounting records and prepares its statutory financial statements in accordance with the Regulations on Accounting and Reporting of the Russian Federation (“RAR”). The accompanying financial statements have been prepared from these accounting records and adjusted as necessary to comply with accounting principles generally accepted in the United States of America (“US GAAP”). The Company has a year ending 30 September for US GAAP reporting purposes. In preparing the financial statements in conformity with US GAAP, management makes estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from such estimates. Certain previously presented amounts have been reclassified to conform to the presentation adopted during the current period. These reclassifications had no impact on previously reported net income or stockholders’ equity. Reporting and functional currency.The Russian Rouble is the functional currency (primary currency in which business is conducted) for the Company’s operations in the Russian Federation. The Company considers the US dollar as its reporting currency. In November 2002, the International Practices Task Force concluded that Russia ceased being a highly inflationary economy as of 1 January 2003. As a result of the Task Force conclusion, the Company applied the guidance contained in Emerging Issues Task Force (“EITF”) No. 92-4 and EITF No. 92-8 as of 1 January 2003, which address changes in accounting when an economy ceases to be considered highly inflationary. As a result of the application of the guidance in EITF No. 92-4 and No. 92-8, as of 1 January 2003, the Company recognised a deferred tax liability of USD 8.1 million for temporary differences related to its property, plant and equipment and a corresponding amount as a cumulative translation adjustment as a separate component in stockholders’ equity. Effective 1 January 2003, the measurement currency of the Company is the Russian Rouble. The transactions and balances in the accompanying financial statements have been translated into US dollars in accordance with the relevant provisions of Statement of Financial Accounting Standards (“SFAS”) No. 52,Foreign Currency Translation(“SFAS No. 52”). Consequently, assets and liabilities are translated at closing exchange rates. The statements of income and cash flows have been translated using monthly average exchange rates. Translation differences resulting from the use of these exchange rates have been included as a component of stockholders equity. The amount of such differences for the period beginning 1 January 2003 through 30 September 2003 was approximately USD 1.9 million. The exchange rates at 30 September 2003, and 30 September 2002, were 30.61 and 31.64, respectively, Russian Roubles to the US dollar. Prior to 1 January 2003, transactions not already measured in US dollars were remeasured into US dollars in accordance with the relevant provisions of SFAS No. 52 as applied to hyperinflationary economies. Consequently, monetary assets and liabilities were translated at closing exchange rates and non-monetary items were translated at historic exchange rates and adjusted for any impairments. The statements of income and cash flows were translated using monthly average exchange rates. Translation differences resulting from the use of these exchange rates were included in the determination of net income and were included in exchange gains/losses in the accompanying statements of income through 31 December 2002. 1 LLC GEOILBENT NOTES TO THE FINANCIAL STATEMENTS (expressed in US Dollars except as indicated) Note 2: Basis of Presentation (continued) Inflation, exchange restriction and controls.Exchange restrictions and controls exist relating to converting Russian Roubles to other currencies. At present, the Russian Rouble is not a convertible currency outside the Russian Federation. Future movements in the exchange rates between the Russian Rouble and the US dollar will affect the carrying value of the Company’s Russian Rouble denominated assets and liabilities. Such movements may also affect the Company’s ability to realise non-monetary assets represented in US dollars in the accompanying financial statements. Accordingly, any translation of Russian Rouble amounts to US dollars should not be construed as a representation that such Russian Rouble amounts have been, could be, or will in the future be converted into US dollars at the exchange rate shown or at any other exchange rate. At 30 September 2003, the Company was required to sell 25% of its foreign currency receipts within the Russian Federation to the Central Bank for Russian Roubles. Such amounts are subject to certain deductions depending on debt payments on certain hard currency denominated borrowing agreements. Note 3: Summary of Significant Accounting Policies Cash and cash equivalents.Cash and cash equivalents include all highly liquid securities with original maturities of three months or less when acquired. Accounts receivable.Accounts receivable are presented at net realisable value and include value-added and excise taxes which are payable to tax authorities upon collection of such receivables. Inventories.Crude oil and petroleum products inventories are valued at the lower of cost, using the first-in-first out method, or net realisable value. Materials and supplies inventories are recorded at the lower of average cost or net realisable value. Property, plant and equipment.The Company follows the full cost method of accounting for oil and gas properties. Under this method, all oil and gas property acquisition, exploration, and development costs including internal costs directly attributable to such activities are capitalized as incurred in the Company’s cost center (full cost pool), which is the Russian Federation. Payroll and other internal costs capitalized include salaries and related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties as well as all other directly identifiable internal costs associated with these activities. Payroll and other internal costs associated with production operations and general corporate activities are expensed in the period incurred. The full cost pool, including future development costs, estimated asset retirement obligations, net of prior accumulated depletion, is depleted using the unit-of-production method based upon actual production and estimates of proved reserve quantities. Proceeds from sales of oil and gas properties are credited to the full cost pool with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas. Pursuant to full cost accounting rules, capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves discounted at 10 percent; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. During 2003, the Company’s capitalized costs exceeded the ceiling limit resulting in an impairment of oil and gas properties. See Note 9 for additional information. Pension and post-employment benefits.The Company’s mandatory contributions to the governmental pension scheme are expensed when incurred. Revenue recognition.Revenue from the sale of crude oil and gas condensate are recognized when dispatched to customers and title has transferred. 2 LLC GEOILBENT NOTES TO THE FINANCIAL STATEMENTS (expressed in US Dollars except as indicated) Note 3: Summary of Significant Accounting Policies (continued) Income taxes.Deferred income tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, in accordance with SFAS No. 109,Accounting for Income Taxes. Deferred income tax assets and liabilities are measured using enacted tax rates in the years in which these temporary differences are expected to reverse. Valuation allowances are provided for deferred income tax assets when management believes it is more likely than not that the assets will not be realized. Change in accounting principle. Effective 1 October 2002, the Company adopted Statement of Financial Accounting Standards No. 143,Accounting for Assets Retirement Obligations(“SFAS No. 143”). SFAS No. 143 requires entities to record the fair value of its asset retirement obligation as a liability in the period in which they are incurred and a corresponding increase in the carrying amount of the related long-lived asset. SFAS No. 143 differs in several respects from the previous accounting method employed by the Company. Prior to the adoption of SFAS No. 143, the Company included estimated undiscounted asset retirement costs in its calculation for determining depletion expense. Under SFAS 143, the Company recognizes a liability for the fair value of an asset retirement obligation (“ARO”) in the period in which it is incurred, and capitalizes the associated asset retirement cost. In periods subsequent to initial measurement, the Company recognizes period-to-period changes in the liability for an ARO resulting from a) the passage of time and b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows. The Company’s asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities. The cumulative effect of this change in accounting principle was a reduction in net income of USD 310 thousand, net of tax, which was recorded in the statement of income for the year ended 30 September 2003. The effect of adoption resulted in increases in property, plant and equipment and long-temlong-term liabilities of USD 303 thousand and USD 613 thousand as of 1 October 2002, respectively. The following table provides pro forma information as if SFAS No. 143 has been applied in previous periods:                               Year ended   Year ended   Year ended Thousands of US dollars   30 September 2003   30 September 2002   30 September 2001 Asset retirement obligations as of the beginning of the period     613       483       358   Liabilities incurred for the period     25       56       79   Accretion expense     96       75       45   Asset retirement obligations as of the end of the period     734       613       483   Net income for the period as reported             3,885       20,420   Pro-forma net income             3,777       20,358                             Recent accounting standards.FASB Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities(“FIN 46R”), identifies certain off-balance sheet arrangements that meet the definition of a variable interest entity (“VIE”). FIN 46R requires consolidation of VIEs by primary beneficiaries and requires more extensive disclosures. FIN 46R is applicable to any VIE created after 1 February 2003. The Company does not expect the adoption of this interpretation will have any material effect on its financial position or results of operations. 3 LLC GEOILBENT NOTES TO THE FINANCIAL STATEMENTS (expressed in US Dollars except as indicated) Note 4: Going Concern During the years ended 30 September 2003 and 2002 the Company took steps to reduce its working capital deficit. These included the repayment of debt, the receipt of subordinated long-term loans from the Company’s stockholders and the repayment of accounts payable, primarily from additional borrowings from the European Bank for Reconstruction and Development (“EBRD”). However, as at 30 September 2003, and 30 September 2002, the current liabilities of the Company exceeded its current assets by USD 35,772 thousand and USD 35,266 thousand, respectively. Included in current liabilities, as at 30 September 2003 and 30 September 2002, are loans repayable to the EBRD of USD 30,000 thousand and USD 22,000 thousand, respectively. This debt has been reclassified as current because the Company is not in compliance with a loan facility covenant related to the required implementation of a new management information system, required by 1 May 2003. The loan facility also requires the Company to maintain a minimum working capital ratio. The Company was not in compliance with the required working capital ratio as of the interim reporting dates during the year ended 30 September 2003, however, it met the minimum required working capital ratio as of 30 September 2003 (see also Note 10). Under the terms of the loan facility the EBRD may declare the loan to be in default and can accelerate the maturity. There can be no assurance that the EBRD will not demand repayment of the loan. During the year ended 30 September 2003, a substantial portion of the Company’s cash flow was utilised to pay accounts and taxes payable resulting in a reduction in capital expenditures for the year. In order to maintain or increase proved oil and gas reserves, the Company must make substantial capital expenditures in 2004 and subsequently. The Company’s cash flow from operations is dependent on the level of oil prices, which are historically volatile and are significantly impacted by the proportion of production that the Company can sell on the export market. Historically, the Company has supplemented its cash flow from operations with additional borrowings or equity capital and may continue to do so. Should oil prices decline for a prolonged period and should the Company not have access to additional capital, the Company would need to reduce its capital expenditures, which could limit its ability to maintain or increase production and, in turn, meet its debt service requirements. Asset sales and financing are restricted under the terms of debt agreements. Management plans to further address the Company’s working capital deficit by resolving issues with the EBRD relating to its non compliance with the loan covenants and by reducing certain capital expenditures and funding its 2004 cash requirements with cash flows from existing producing properties and its development drilling program. Management is in the process of implementing the required management information system and expects to have implemented this system during the 2004 reporting year. The accompanying financial statements do not include any adjustments that might result if the Company were unable to continue as a going concern. Note 5: Cash and Cash Equivalents Included in cash and cash equivalents as at 30 September 2003, and 2002, respectively, are Russian Rouble denominated amounts totaling RR 19.7 million (USD 643 thousand) and RR 18.3 million (USD 578 thousand). Restricted cash consists of deposits with lending institutions to pay interest and principal as discussed in Note 10. As at 30 September 2003, the amount of restricted cash was USD 1,217 thousand (2002: USD 1,469 thousand). These accounts are maintained in US Dollar denominated accounts located outside Russia. Note 6: Financial Instruments Fair values.The estimated fair values of financial instruments are determined with reference to various market information and other valuation methodologies as considered appropriate, however considerable judgment is required in interpreting market data to develop these estimates. Accordingly, the estimates are not necessarily indicative of the amounts that the Company could realize in a current market transaction. The methods and assumptions used to estimate fair value of each class of financial instrument are presented below. Cash and cash equivalents, accounts receivable and accounts payable.The carrying amount of these items are a reasonable approximation of their fair value. Short-term and long-term debt. Loan arrangements have both fixed and variable interest rates that reflect the currently available terms and conditions for similar debt. The carrying value of this debt is a reasonable approximation of its fair value. 4 LLC GEOILBENT NOTES TO THE FINANCIAL STATEMENTS (expressed in US Dollars except as indicated) Note 6: Financial Instruments (continued) Credit risk. A significant portion of the Company’s accounts receivable are from domestic and foreign customers, and advances are made to domestic suppliers. Although collection of these amounts could be influenced by economic factors affecting these entities, management believes there is no significant risk of loss to the Company beyond the provisions already recorded, provided that the economic situation in the Russian Federation does not deteriorate (Note 16). Note 7: Accounts Receivable and Advances to Suppliers                   Thousands of US dollars   30 September 2003   30 September 2002 Trade accounts receivable     1,531       1,387   Recoverable value-added tax     4,227       3,515   Advances to suppliers     1,286       1,193   Advances to customs     117       137   Other receivables     —       76                     Total accounts receivable and advances to suppliers     7,161       6,308                     Accounts receivables are presented net of an allowance for doubtful accounts of USD 147 thousand and USD 70 thousand at 30 September 2003 and 2002, respectively. Note 8: Inventories                   Thousands of US Dollars   30 September 2003   30 September 2002 Materials and supplies     7,442       6,905   Crude oil     576       296                     Total inventories     8,018       7,201                     Note 9: Oil and Gas Producing Properties                   Thousands of US dollars   30 September 2003   30 September 2002 Oil and gas producing properties, cost     302,214       278,459   Accumulated depletion and impairment     (212,745 )     (92,470 )                   Oil and gas producing properties, net book value     89,469       185,989                     The Company’s oil and gas fields are situated on land belonging to the Government of the Russian Federation. The Company obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Licenses will expire in September 2018 for the North Gubkinskoye field, and in March 2023 for the South Tarasovskoye field. However, under Paragraph 4 of the Russian Federal Law 20-FZ, dated 2 January 2000, the licenses may be extended over the economic life of the lease at the Company’s option. Management intends to extend such licenses for properties that are expected to produce subsequent to their expiry dates. Estimates of proved reserves extending past 2018 represent approximately 9 percent of total proved reserves. At 31 December 2002 and at 31 March 2003, the Company’s capitalized costs for oil and gas producing properties exceeded its full cost accounting ceiling limitation. The Company’s ceiling limitation decreased primarily because of a decline in the Company’s average realized price it received for its oil at those dates. As a result the Company recorded impairments of its oil and gas producing properties in the aggregate amount of USD 95 million (excluding a deferred income tax benefit of USD 7.6 million); this impairment was recorded as an impairment expense in the statement of income for the year ended 30 September 2003. 5 LLC GEOILBENT NOTES TO THE FINANCIAL STATEMENTS (expressed in US Dollars except as indicated) Note 10: Long-term Debt                   Thousands of US dollars   30 September 2003   30 September 2002 EBRD     30,000       22,000   IMB     —       550   OAO Minley     5,000       5,000   YUKOS     2,500       —   Harvest Natural Resources     —       2,500   Less: current portion     (37,500 )     (22,550 )                   Total long-term debt     —       7,500                     EBRD loan.At 30 September 2003, the outstanding balance of loans with the EBRD totaled USD 30 million. On 23 September 2002, the Company signed an amended loan agreement with the EBRD that increased the maximum amount that could be drawn down under the facility with the EBRD to USD 50 million. Under the loan agreement, the use of loan proceeds is restricted to the repayment of accounts payable and development of oil and gas reserves. This loan facility is to be repaid such that the loan balance may not exceed set amounts at certain dates in the future. The interest rate under the loan agreement is linked to the London interbank offer rate (“LIBOR”) and an agreed upon margin. The Company must hold as restricted cash a) principal and interest to be paid at the next repayment date and b) 30 percent of the total of principal and interest to be paid at the following repayment date. LIBOR interest rates ranged from 1.12 percent to 1.84 percent in 2003 (2002: 1.84 percent to 3.5 percent, 2001: 3.5 percent to 6.94 percent). The annual weighted average interest rates on these loans varied between 5.09 percent and 5.43 percent for the year ended 30 September 2003 (2002: 8.59 percent and 11.71 percent, 2001: 14.93 percent to 15.17 percent). The loan is collaterized by the Company’s immovable assets and crude oil export contracts. The EBRD loan agreement includes certain covenants which include, among other things, the maintenance of financial ratios. If the Company fails to meet these requirements for two concecutiveconsecutive quarters it will result in an event of default whereby the EBRD may, at its option, demand payment of the outstanding principal and interest. As dicusseddiscussed in Note 4, as of 31 December 2002, 31 March 2003 and 30 June 2003 the Company was in violation of the minimum working capital ratio covenant. As of 30 September 2003, the minimum working capital ratio as defined in the loan facility exceeds the covenant requirements. Additionally, the Company has not completed its implementation of a management information system as required under the terms of the loan. Due to these loan convenant violations, the Company has classified the EBRD debt as a current liability. In addition, while in default of EBRD covenants, the Company may not declare or pay any dividend, make any distribution on its charter capital, purchase, or redeem any shares of the charter capital of the Company, nor make any payment of principal or interest on subordinated shareholder loans or make any other payment or distribution to any stockholder or any affiliate of any stockholder. As part of the sale of Harvest’s interest in the Company to YUKOS, as described in Note 1, YUKOS assumed Harvest’s stockholder loan. Loans from OAO Minley and YUKOS are subordinated, unsecured and repayable commencing from January 2004. Interest rates are 2 percent for the Minley loan, and LIBOR for the YUKOS loan, to January 2004. Repayment of the subordinated loans are subject to approval from the EBRD. If approval is not received, the terms of the loan agreements are not considered to be violated. After January 2004, the interest rates on the YUKOS loan increases to 8 percent for the remainder of 2004, and 12 percent from 2005 onwards. 6 LLC GEOILBENT NOTES TO THE FINANCIAL STATEMENTS (expressed in US Dollars except as indicated) Note 10: Long-term Debt (continued) While the Company remains in violation of its EBRD loan convenants, further borrowings under the facility are at the sole discretion of the EBRD. The maximum loan facility available under the terms of the EBRD loan and the related aggregate maturities are as follows:               Maximum loan facility Thousands of US dollars   outstanding 30 September 2003 to 27 January 2004     50,000   27 January 2004 to 27 July 2004     41,667   27 July 2004 to 27 January 2005     33,333   27 January 2005 to 27 July 2005     25,000   27 July 2005 to 27 January 2006     16,667   27 January 2006 to 27 January 2007     8,333   Thereafter     —             The aggregate maturities of long-term debt outstanding at 30 September 2003 are as follows:           Thousands of US dollars         Year ended 30 September 2004     7,500   Year ended 30 September 2005     5,000   Year ended 30 September 2006     8,333   Year ended 30 September 2007     8,333   Year ended 30 September 2008     8,333             Note 11: Taxes Payable                   Thousands of US dollars   30 September 2003   30 September 2002 Value added tax     —       1,445   Income tax     3,777       1,176   Royalty     —       896   Mineral restoration tax     —       152   Road users tax     —       642   Unified production tax     1,552       6,703   Property taxes     586       1,121   Penalties and interest     1,784       219   Other taxes     159       —                     Total taxes payable     7,858       12,354                     7 LLC GEOILBENT NOTES TO THE FINANCIAL STATEMENTS (expressed in US Dollars except as indicated) Note 12: Contributed Capital Capital contributions are as follows:                   Thousands of US dollars   30 September 2003   30 September 2002 OAO Minley     54,733       54,733   YUKOS     27,785       —   Harvest Natural Resources     —       27,785                     Total contributed capital     82,518       82,518                     All capital contributions have been made since inception in accordance with the Company’s Foundation Document. Reserves available for distribution to shareholders are based on the statutory accounting reports of the Company, which are prepared in accordance with Regulations on Accounting and Reporting of the Russian Federation and differ from US GAAP. Russian legislation identifies the basis of distribution as net income. For 2002, the current year statutory net income for the Company as reported in the annual statutory accounting reports was RR 772 million (2001: RR 551 million). However, current legislation and other statutory laws and regulations dealing with distribution rights are open to legal interpretation and, consequently, actual distributable reserves may differ from the amount disclosed. The Company cannot distribute capital while in default of its EBRD loan facility obligations (Note 10). Note 13: Revenues Revenues for the years ended 30 September 2003, 2002 and 2001, consisted of the following:                           Thousand of US dollars   30 September 2003   30 September 2002   30 September 2001 Crude oil — export (Europe and CIS)     51,949       47,751       83,889   Crude oil — domestic     28,599       40,778       10,900   Gas condensate — domestic     1,176       —       —   Refined products — domestic     —       2,764       6,231   Other operating revenues     583       305       139                             Total sales and other operating revenues     82,307       91,598       101,159                             Note 14: Taxes Presented below is a reconciliation between the provision for income taxes and taxes determined by applying the statutory tax rate as applied in the Russian Federation to income before income taxes.                           Thousand of US dollars   30 September 2003   30 September 2002   30 September 2001 Income (loss) before income taxes     (87,691 )     4,187       27,171                             Theoretical income tax expense (benefit) at statutory rate (24% in 2002 and 2003; 35% in 2001)     (21,046 )     1,005       9,509   Increase (reduction) due to:                         Change in valuation allowance     17,192       80       1,810   Non-deductible expenses     1,860       2,894       2,693   Investment tax credits     (593 )     (5,348 )     (6,821 ) Change in statutory tax rate     —       595       (750 ) Tax penalties and interest     442       1,135       517   Other     (972 )     (59 )     (207 )                           Total income tax expense (benefit)     (3,117 )     302       6,751                             8 LLC GEOILBENT NOTES TO THE FINANCIAL STATEMENTS (expressed in US Dollars except as indicated) Note 14: Taxes (continued) Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for statutory tax purposes. Net deferred tax assets are comprised of the following, at 30 September 2003 and 2002:                   Thousand of US dollars   30 September 2003   30 September 2002 Inventories     (313 )     93   Accounts receivable     121       258   Accounts payable and accrued liabilities     1,205       430   Losses carried forward     966       2,502   Property, plant and equipment     4,989       4,810                     Total deferred tax assets     6,968       8,093   Less: Valuation allowance     (6,002 )     (5,591 )                   Net deferred tax asset     966       2,502                     Losses carried forward represent those losses for tax purposes which, according to legislation, the Company is permitted to offset against future taxable earnings in the periods up to 2008, and is subject to limitations of no more than 30% of the Company’s tax liabilities for the tax reporting period. As at 30 September 2003, management of the Company have assessed the recoverability of the Company’s deferred tax assets and believe that it will be able to realise the tax losses carried forward. Accordingly, the Company has provided a valuation allowance as at 30 September 2003 and 2002, of USD 6,002 thousand and USD 5,591 thousand, respectively, against the remaining deferred tax assets. Principal movements in the valuation allowance for deferred income tax assets (“DTA”) during the year ended 30 September 2003 are as follows:           Millions of US dollars         Valuation allowance, beginning of period     5.6   Increase related to DTA resulting from the December ceiling test writedown     12.0   Net other increase in DTA movements during the December quarter     1.0   Decrease due to application of EITF No. 92-4 and No. 92-8 effective 1 January 2003     (16.8 ) Increase relating to DTA resulting from the March ceiling test writedown     3.2   Net other increase in DTA movements     1.0             Valuation allowance, end of period     6.0             As a result of the application of EITF No. 92-4 and No. 92-8, the valuation allowance related to property, plant and equipment was reduced to zero and a deferred tax liability of USD 8.1 million recorded on 1 January 2003 (Note 2), with no effect on income as the adjustment was recorded as part of the currency translation adjustment as of 1 January 2003. A subsequent ceiling test writedown in March resulted in the recognition of an additional deferred tax asset of USD 10.8 million of which USD 7.6 million and USD 3.2 million were credited as a deferred tax benefit and an increase to the DTA valuation allowance, respectively. Deferred income tax assets are classified as follows:                   Thousands of US dollars   30 September 2003   30 September 2002 Deferred income tax, current     966       1,806   Deferred income tax, non-current     —       696                     Total net deferred tax asset     966       2,502                     9 LLC GEOILBENT NOTES TO THE FINANCIAL STATEMENTS (expressed in US Dollars except as indicated) Note 14: Taxes (continued) Taxes other than income tax.The Company is subject to a number of taxes other than on income which are detailed below.                           Thousands of US dollars   30 September 2003   30 September 2002   30 September 2001 Export duties     8,464       5,376       10,922   Excise tax     —       535       1,548   Royalty     —       2,254       4,867   Mineral restoration tax     377       885       4,596   Road users tax     203       860       1,427   Unified production tax     19,056       14,221       —   Property taxes     2,263       1,994       1,424   Taxes recovery     (7,017 )     —       —   Other taxes     2,279       1,532       1,227                             Total taxes other than income tax     25,625       27,657       26,011                             Beginning 1 January 2002, mineral restoration tax, royalty tax and excise tax on crude oil production were abolished and replaced by the unified natural resources production tax. From 1 January 2004 through 31 December 2006, the base rate for the unified natural resources production tax is set at RR 347 per metric ton of crude oil produced, and is to be adjusted depending on the market price of Urals blend and the RR/USD exchange rate. The tax becomes nil if the Urals blend price falls to or below USD 8.00 per barrel. From 1 January 2007, the unified natural resources production tax rate is set by law at 16.5 percent of crude oil revenues recognized by the Company based on Tax Regulations of the Russian Federation. During the year ended 30 September 2003, the Company pursued its claim of overpayment of mineral restoration taxes (MRT) paid during the period from 1999 to 2001 of approximately RR 211 million (USD 7.0 million), plus approximately RR 4 million (USD 0.1 million) in related penalties paid. During the year, the regional courts ruled in favour of the Company and, accordingly, the Company and the tax authorities agreed to offset the amounts awarded against the Company’s unified production taxes payable. Note 15: Related Party Transactions As of 30 September 2003 and 2002, the Company had the following balances with its stockholders. These balances are included in the balance sheet within accounts receivable, accounts payable and long-term debt as appropriate.                   Thousand of US Dollars   30 September 2003   30 September 2002 Accounts receivable                 Purneftegasgeologia and affiliated entities     19       63   Accounts payable                 Purneftegasgeologia and affiliated entities     183       574   YUKOS     2,111       —   Harvest Natural Resources     —       3,354   Purneftegas and affiliated entities     —       22   Long-term debt                 Harvest Natural Resources     —       2,500   YUKOS     2,500       —   Minley     5,000       5,000   10 LLC GEOILBENT NOTES TO THE FINANCIAL STATEMENTS (expressed in US Dollars except as indicated) Note 15: Related Party Transactions (continued) Harvest Natural Resources/YUKOS.During 2003 and 2002, Harvest provided insurance on behalf of the Company and personnel services to the Company for a total value of approximately USD 1,087 thousand (2002: USD 1,752 thousand). The remaining portion of the accounts payable balance outstanding relates to services provided in prior reporting periods. As part of the sale of Harvest’s interest in the Company to YUKOS, all balances owing by the Company to Harvest were transferred to YUKOS. Purneftegasgeologia.During 2003, 2002 and 2001, Purneftegasgeologia and affiliated entities provided services to the Company for a total value of approximately nil, USD 2,414 thousand and USD 4,193 thousand, respectively. Services consisted of drilling, well maintenance and other related work. The Company sold crude oil for a total value of USD 19 thousand and USD 24 thousand during 2003 and 2002, respectively, and materials during 2003 and 2002 for a total value of approximately USD 726 thousand and USD 613 thousand, respectively. Purneftegas.During 2002 and 2001, Purneftegas and affiliated companies provided well maintenance services and supplies to the Company for a total of approximately USD 312 thousand and USD 248 thousand, respectively. The Company sold materials to Purneftegas and affiliated entities during 2002 for a total value of approximately USD 260 thousand. Minley.During 2002, the Company paid USD 4.9 million to Minley in settlement at face value of promissory notes originally issued to the Company’s suppliers and contractors. During 2003, interest expense on shareholder loans of USD 99 thousand was incurred with respect to Minley and USD 49 thousand was incurred with respect to Harvest. At 30 September 2003 interest payable to Minley totalled USD 21 thousand (2002: USD 21 thousand) and interest payable to Harvest was USD 65 thousand (2002: USD 14 thousand). Note 16: Commitments and Contingent Liabilities Economic and operating environment in the Russian Federation.Whilst there have been improvements in the economic situation in the Russian Federation in recent years, the country continues to display some characteristics of an emerging market. These characteristics include, but are not limited to, the existence of a currency that is not freely convertible in most countries outside of the Russian Federation, restrictive currency controls, and relatively high inflation. The prospects for future economic stability in the Russian Federation are largely dependent upon the effectiveness of economic measures undertaken by the government, together with legal, regulatory, and political developments. Taxation.Russian tax legislation is subject to varying interpretations and changes occurring frequently, which may be retroactive. Further, the interpretation of tax legislation by tax authorities as applied to the transactions and activity of the Company may not coincide with that of management. As a result, the tax authorities may challenge transactions and the Company may be assessed additional taxes, penalties and interest, which may be significant. The tax periods remain open to review by the tax and customs authorities for three years. The Company cannot predict the ultimate amount of additional assessments, if any, and the timing of their related settlements with certainty, but expects that additional liabilities, if any, arising will not have a significant effect on the accompanying financial statements. Environmental matters.Environmental regulations and their enforcement are continually being considered by government authorities and the Company periodically evaluates its obligations related thereto. As obligations are determined, they are provided for over the estimated remaining lives of the related oil and gas reserves, or recognized immediately, depending on their nature. The existence of environmental liabilities under proposed or any future legislation, or as a result of stricter enforcement of existing legislation, cannot reasonably be estimated. Under existing legislation, management believes, there are no liabilities that would have a material adverse effect on the financial position, operating results or liquidity of the Company, and that have not been accrued in the financial statements. 11 LLC GEOILBENT NOTES TO THE FINANCIAL STATEMENTS (expressed in US Dollars except as indicated) Note 16: Commitments and Contingent Liabilities (continued) Oilfield licenses.The Company is subject to periodic reviews of its activities by governmental authorities with respect to the requirements of its oilfield licenses. Management of the Company correspond with governmental authorities to agree on remedial actions necessary to resolve any findings resulting from these reviews. Failure to comply with the terms of a license could result in fines, penalties or license limitation, suspension or revocation. The Company’s management believes any issues of non-compliance will be resolved through negotiations or corrective actions without any materially adverse effect on the Company’s financial position or results of operations. Legal contingencies.The Company is claiming additional deductions relating to the fiscal periods from 1999 to 2001 amounting to approximately RR 330 million (USD 10.8 million). Management believe these deductions are permitted for companies operating in the northern regions of the Russian Federation and also deductions for certain interest paid during that period. Although the Company was successful in the initial hearing before the courts, the tax authorities have continued to challenge the Company’s position. As at 30 September 2003, the Company has not recorded any benefit relating to the above claims. The Company is the named defendant in a number of lawsuits as well as the named party in numerous other proceedings arising in the ordinary course of business. While the outcomes of such contingencies, lawsuits or other proceedings cannot be determined at present, management believes that any resulting liabilities will not have a materially adverse effect on the operating results or the financial position of the Company. Insurance.At 30 September 2003 and 2002, the Company held limited insurance policies in relation to its assets and operations, or in respect of public liability or other insurable risks. Since the absence of insurance alone does not indicate that an asset has been impaired or a liability incurred, no provision has been made in the financial statements for unspecified losses. 12 LLC GEOILBENT Supplemental Information on Oil and Natural Gas Producing Activities(unaudited) (expressed in thousands US Dollars except as indicated) Supplemental Information on Oil and Natural Gas Producing Activities(unaudited) In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS No. 69”), this section provides supplemental information on the Company’s oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities:                               Year ended   Year ended   Year ended Thousand of US Dollars   30 September 2003   30 September 2002   30 September 2001 Development costs     10,217       25,290       33,774   Exploration costs     3,040       1,465       6,100                             Total costs incurred in oil and natural gas acquisition, exploration, and development activities     13,257       26,755       39,874                             TABLE II — Capitalized costs related to oil and natural gas producing activities:                       As at   As at Thousand of US Dollars   30 September 2003   30 September 2002 Proved property costs     302,214       277,659   Costs excluded from amortisation     —       800   Oilfield inventories     7,442       6,905   Less accumulated depletion and impairment     (212,745 )     (92,470 )                   Total capitalised costs related to oil and natural gas producing activities     96,911       192,894                     TABLE III — Results of operations for oil and natural gas producing activities: In accordance with SFAS 69, results of operations for oil and natural gas producing activities do not include general corporate overhead and monetary effects, nor their associated tax effects. Income tax is based on statutory rates for the year, adjusted for tax deductions, tax credits and allowances.                               Year ended   Year ended   Year ended Thousand of US Dollars   30 September 2003   30 September 2002   30 September 2001 Oil and natural gas sales     81,987       91,291       100,768   Expenses:                         Operating, selling and distribution expenses and taxes other than on income     47,319       49,713       47,302   Depletion and amortization     18,278       27,168       14,918   Impairment of oil and gas properties     95,000       —       —   Income tax expense     6,098       5,750       11,006   Total expenses     166,695       82,631       73,226                             Results of operations from oil and natural gas producing activities     (84,708 )     8,660       27,542                             13 LLC GEOILBENT SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) (expressed in thousands US Dollars except as indicated) TABLE IV — Quantities of oil and natural gas reserves Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. The Company’s oil and gas fields are situated on land belonging to the Government of the Russian Federation. The Company obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Licenses will expire in September 2018 for the North Gubkinskoye field, and in March 2023 for the South Tarasovskoye field. However, under Paragraph 4 of the Russian Federal Law 20-FZ, dated 2 January 2000, the licenses may be extended over the economic life of the lease at the Company’s option. Management intends to extend such licenses for properties that are expected to produce subsequent to their expiry dates. Estimates of proved reserves extending past 2018 represent approximately 9 percent of total proved reserves. The Securities and Exchange Commission requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. 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 the Company considers 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. Proved developed reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed non producing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well. Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. Proved undeveloped reserves are proved reserves which 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 are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for proved undeveloped reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir. Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors. The evaluations of the oil and natural gas reserves were prepared by Ryder-Scott Company, independent petroleum engineers. 14 LLC GEOILBENT SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) (expressed in thousands US Dollars except as indicated)                           Proved reserves-crude oil,             condensate and natural gas   Year ended   Year ended   Year ended liquids (MBbls)   30 September 2003   30 September 2002   30 September 2001 Proved reserves beginning of year     74,575       87,259       95,924   Revisions of previous estimates     1,580       (10,163 )     (16,454 ) Extensions, discoveries and improved recovery     2,829       4,391       12,974   Production     (5,712 )     (6,912 )     (5,185 )                           Proved reserves, end of year     73,272       74,575       87,259                             Proved developed reserves     35,344       38,824       46,052                             TABLE V — Standardized measure of discounted future net cash flows related to proved oil and natural gas reserve quantities The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions. Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.                               Year ended   Year ended   Year ended Thousand of US Dollars   30 September 2003   30 September 2002   30 September 20 Future cash inflow     1,416,343       1,381,874       1,277,494   Future production costs     (676,419 )     (599,277 )     (739,221 ) Future development costs     (107,841 )     (119,725 )     (108,882 )                           Future net revenue before income taxes     632,083       662,872       429,391   10% annual discount for estimated timing of cash flows     (293,965 )     (318,079 )     (190,788 )                           Discounted future net cash flows before income taxes     338,118       344,793       238,603   Future income taxes, discounted at 10% per annum     (68,126 )     (71,442 )     (30,815 )                           Standardized measure of discounted future net cash flows     269,992       273,351       207,788                             15 LLC GEOILBENT SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) (expressed in thousands US Dollars except as indicated) TABLE VI — Changes in the standardized measure of discounted future net cash flows from proved reserves                               Year ended   Year ended   Year ended Thousand of US Dollars   30 September 2003   30 September 2002   30 September 2001 Present value at beginning of period     273,351       207,788       337,426   Sales of oil and natural gas, net of related costs     (60,030 )     (69,541 )     (54,015 ) Revisions to estimates of proved reserves:                         Net changes in prices, development and production costs     (16,242 )     225,132       (107,356 ) Quantities     9,346       (29,432 )     (71,709 ) Extensions, discoveries and improved recovery, net of future costs     3,663       5,974       55,197   Accretion of discount     34,479       23,862       41,224   Net change of income taxes     3,316       3,367       43,994   Development costs incurred     13,257       26,468       37,953   Changes in timing and other     8,852       (120,267 )     (74,926 )                           Present value at end of period     269,992       273,351       207,788                             16 EXHIBIT INDEX Index to Exhibits       Exhibits Description of Exhibit 3.1   Amended and Restated Certificate of Incorporation filed September 9, 1988Incorporation. (Incorporated by reference to Exhibit 3.13.1(i) to our Registration Statement (RegistrationForm 10-Q filed on August 13, 2002, File No. 33-26333)1-10762.).       3.2 Amendment to Certificate of Incorporation filed June 7, 1991 (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-39214)). 3.3   Amended and Restated Bylaws as of December 11, 2003. (Incorporated by reference to Exhibit 3.7 to our Form 10-K filed on March 10, 2004, File No. 1-10762.)       4.1   Form of Common Stock Certificate (Previously filed as an exhibitCertificate. (Incorporated by reference to the exhibits to our S-1 Registration Statement Form S-1 (Registration No. 33-26333).).       4.2   Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.)       4.3   Amended and Restated Rights Agreement, dated as of September 16, 2003, between Benton OilHarvest Natural Resources, Inc. and Gas Company and First InterstateWells Fargo Bank Rights Agent dated April 28, 1995. (IncorporatedMinnesota, N.A. (incorporated by reference to Exhibit 4.15 to Amendment No. 1 to our Form 10-Q filed on August 13, 2002, File No. 1-10762.) 10.1 Form of Employment Agreements (Exhibit 10.19)(Previously filed as an exhibit to our S-1 Registration Statement on Form 8-A filed October 29, 2003 (Registration No. 33-26333)000-17534)).       10.210.1   Operating Service Agreement between Benton Oil and Gas Company and Lagoven, S.A., which has been subsequently combined into PDVSA Petroleo y Gas, S.A., dated July 31, 1992, (portions have been omitted pursuant to Rule 406 promulgated under the Securities Act of 1933 and filed separately with the Securities and Exchange Commission—Exhibit 10.25)(Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-52436)). Exhibits Description of Exhibit 10.3 Indenture dated November 1, 1997 between Benton Oil and Gas Company and First Trust of New York, National Association, Trustee related to an aggregate of $115,000,000 principal amount of 9 3/8 percent Senior Notes due 2007Commission. (Incorporated by reference to Exhibit 10.1the exhibits to our Registration Statement Form 10-Q for the quarter ended September 30, 1997, FileS-1 (Registration No. 1-10762)33-52436).)       10.410.2   Note payable agreement dated March 8, 2001 between Benton-Vinccler,Harvest Vinccler, C.A. and Banco Mercantil, C.A. related to a note in the principal amount of $6,000,000 with interest at LIBOR plus five percent, for financing of Tucupita PipelinePipeline. (Incorporated by reference to Exhibit 10.24 to our Form 10-Q, filed on May 15, 2001, File No. 1-10762).1-10762.)       10.5 10.3†   Change of Control Severance Agreement effective May 4, 20012001. (Incorporated by reference to Exhibit 10.26 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.).       10.610.4   Alexander E. Benton Settlement and Release Agreement effective May 11, 2001 (Incorporated by reference to Exhibit 10.27 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.).       10.710.5   First Amendment to Change of Control Severance Plan effective June 5, 20012001. (Incorporated by reference to Exhibit 10.31 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.).       10.810.6   Sale and Purchase Agreement dated February 27, 2002 between Benton Oil and Gas Company and Sequential Holdings Russian Investors Limited regarding the sale of Benton Oil and Gas Company’s 68 percent interest in Arctic Gas Company. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on March 28, 2002, File No. 1-10762.)       10.910.7   2001 Long Term Stock Incentive PlanPlan. (Incorporated by reference to Exhibit 4.1 to our S-8 (Registration Statement No. 333-85900).).       10.1010.8   Addendum No. 2 to Operating Services Agreementservice agreement Monagas SUR dated 19th September, 2002. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)       10.1110.9   Bank Loan Agreement between Banco Mercantil, C.A. and Benton-VincclerHarvest Vinccler C.A. dated October 1, 2002. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)       10.1210.10   Guaranty issued by Harvest Natural Resources, Inc. dated September 26, 2002. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)       10.13 10.11†   Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Peter J. Hill. (Incorporated by reference to Exhibit 10.10 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)       10.14 10.12†   Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.11 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)       10.15 10.13†   Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.12 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)       10.16 10.14†   Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.13 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)       10.1710.15   Sale and Purchase Agreement dated September 26, 2003, between Harvest Natural Resources, Inc. and Yukos Operational Holding Limited regarding the sale of our 34 percent minority equity investment in LLC Geoilbent. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 10, 2003, File No. 1-10762.)       10.18 10.16†   Employment Agreement dated November 17, 2003 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.18 to our Form 10-Q filed on March 10, 2004, File No. 1-10762.)         Exhibits 10.17†   Description ofEmployment Agreement dated September 1, 2004 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit  10-1 to our Form 10-Q filed on November 5, 2004, File No. 1-10762.)     10.18† Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).) 10.19† Indemnification Agreement between Harvest Natural Resources, Inc. and Karl L. Nesselrode.the Directors and Executive Officers of the Company. 10.20† Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement 10.21† Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement 10.22† Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement       21.1   List of subsidiaries.       23.1   Consent of PricewaterhouseCoopers LLP -— Houston       23.2   Consent of ZAO PricewaterhouseCoopers Audit -— Moscow       23.3   Consent of Ryder Scott Company, LP       31.1   Certification of the Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.       31.2   Certification of the Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.       32.1   CertificationsCertification of the Chief Executive Officer accompanying the annual report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of the Chief Financial Officer accompanying the annual report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. † Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K.