UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

(Mark One)

Commission File No.: 1-10762

HARVEST NATURAL RESOURCES, INC.

Registrant’s telephone number, including area code: (281) 899-5700

15835 Park Ten Place Drive, Suite 115
Houston, Texas 77084
(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes þ No o

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity as of the last business day of the registrant’s most recently completed second fiscal quarter, June 30, 2004: $535,652,892.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practical date. Class: Common Stock, par value $0.01 per share, on February 11, 2005, shares outstanding: 37,596,464.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for the 2005 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission, not later than 120 days after the close of the registrant’s fiscal year, pursuant to Regulation 14A, are incorporated by reference into Items 10, 11, 12, 13 and 14 of Part III of this annual report.

HARVEST NATURAL RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS

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PART I

Harvest Natural Resources, Inc. (“Harvest” or the “Company”) cautions that any forward-looking statements (as such term is defined in the Private Securities Litigation Reform Act of 1995) contained in this report or made by management of the Company involve risks and uncertainties and are subject to change based on various important factors. When used in this report, the words “budget”, “guidance”, forecast”, “anticipate”, “expect”, “believes”, “goals”, “projects”, “plans”, “anticipates”, “estimates”, “should”, “could”, “assume” and similar expressions are intended to identify forward-looking statements. In accordance with the provisions of the Private Securities Litigation Reform Act of 1995, we caution you that important factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include our concentration of operations in Venezuela, the political and economic risks associated with international operations (particularly those in Venezuela), the anticipated future development costs for our undeveloped proved reserves, the risk that actual results may vary considerably from reserve estimates, the dependence upon the abilities and continued participation of certain of our key employees, the risks normally incident to the operation and development of oil and gas properties, the permitting and drilling of oil and natural gas wells, the availability of materials and supplies necessary to projects and operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, basis risk and counterparty credit risk in executing commodity price risk management activities, the Company’s ability to acquire oil and gas properties that meet its objectives, changes in operating costs, overall economic conditions, political instability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in governmental policy, availability of sufficient financing, changes in weather conditions, and ability to hire, retain and train management and personnel. See Risk Factors included in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 1. Business

Executive Summary

     Harvest Natural Resources, Inc. is an independent energy company engaged in the acquisition, development, production and disposition of oil and gas properties since 1989, when it was incorporated under Delaware law. Over our history, we have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”) and the Russian Federation (“Russia”) and have undeveloped acreage offshore China. Currently, our producing operations are conducted through our 80 percent-owned Venezuelan subsidiary, Harvest Vinccler, C.A. (“Harvest Vinccler”, formerly Benton Vinccler, C.A.), which operates the South Monagas Unit in Venezuela.

     In September 2004, we announced the redemption on November 1, 2004 of all $85 million of our 9.375 percent senior unsecured notes due November 1, 2007 (the “2007 Notes”). In August and September 2004, we purchased West Texas Intermediate (“WTI”) crude oil puts covering 10,000 barrels of oil per day for calendar year 2005 to protect our 2005 cash flow. These puts cost a total of $14.9 million, have an average strike price of $42.20 per barrel and, due to our pricing structure for our Venezuelan oil, have the economic effect of hedging approximately 20,800 barrels of oil per day. During 2004, we drilled ten new wells and re-entered and completed an additional six wells in the South Monagas Unit. Our daily crude oil and natural gas sales on December 31, 2004, were 29,000 barrels of oil and 77 million cubic feet of gas. See Item 7 – Management’s Discussion and Analysis of Financial Conditions and Results of Operations for a complete description of these and other events during 2004.

     As of December 31, 2004, we had total estimated Proved Reserves in the South Monagas Unit, net of minority interest, of 84.4 million barrels of oil equivalent (“MMBoe”), and a standardized measure of discounted future net cash flow, before income taxes, for total Proved Reserves of $802 million.

     As of December 31, 2004, we had total assets of $367.5 million. We had cash in the amount of $84.6 million and no long-term debt. We had total revenues of $186.1 million and net cash provided by operating activities of $74.1 million. For the year ended December 31, 2003, we had cash in the amount of $138.7 million and $96.8 million in long-term debt. We had total revenues of $106.1 million and net cash provided by operating activities of $38.5 million.

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Our business strategy is to identify, acquire, develop and produce large discovered oil and gas fields in Venezuela and Russia. We have more than twelve years of experience in Venezuela and Russia, and have established organizations in both countries. We seek additional opportunities in these two countries and would consider investments in other countries that meet our criteria. In executing our business strategy, we will strive to sustain the current balance sheet strength through:

	•	maintaining financial prudence and rigorous investment criteria;
	•	maximizing cash flows from existing operations in order to invest in new opportunities;
	•	using our experience, skills and cash on hand to acquire new projects; and
	•	keeping our organizational capabilities in line with our rate of growth.

     In Venezuela, we seek to deliver maximum operating cash flow through the efficient management of our capital expenditure programs and cost structure. The year 2004 represented our first full year of natural gas production, which allowed us to diversify our revenues and cash flow. Our Venezuelan producing properties generate net cash from operating activities in excess of projected capital expenditures.

     We have significant financial flexibility and substantial cash flow supported by current oil prices and current production levels for both oil and gas. We believe this provides us with the ability to pursue growth opportunities while at the same time maintaining a strong balance sheet. However, we have recently experienced difficulties in Venezuela with getting our budgets approved and obtaining permits from the Ministry of Energy and Petroleum (“MEP”, formerly Ministry of Energy and Mines) and Ministry of Environment, as required, which are critical to our ability to fully execute our drilling program. A continuation of these difficulties or a curtailment of production in Venezuela could adversely affect our production and our ability to pursue growth opportunities.

     While we cannot predict the degree to which we will be successful, we continue to evaluate properties in both Venezuela and Russia to find opportunities which meet our focused acquisition criteria. We expect our cash generating capacity to be supported by our new gas production, lower operating expenses and our expected future Uracoa and Bombal drilling programs.

     Our ability to successfully execute our strategy is subject to significant risks including, among other things, operating risks, political risks, legal risks and financial risks. See Item 7 – Management’s Discussion and Analysis of Financial Conditions and Results of Operations and other information set forth elsewhere in this Form 10-K for a description of these and other risk factors.

Available Information

     We file annual, quarterly and current reports, proxy statements and other documents with the Securities and Exchange Commission (“SEC”) under the Securities Act of 1934. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.

     We also make available, free of charge on or through our Internet website (http://www.harvestnr.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Securities Act of 1934 are also available on the website. In addition, we have adopted a Code of Business Conduct and Ethics that applies to all of our employees, including our chief executive officer, principal financial officer and principal accounting officer. The text of the Code of Business Conduct and Ethics has been posted on the Governance section of our website. We intend to post on our website any amendments to, or waivers from, our Code of Business Conduct and Ethics applicable to our senior officers. Additionally, the Code of Business Conduct and Ethics is available in print to any person who requests the information. Individuals wishing to obtain this printed material should submit a request to Harvest Natural Resources, Inc., attention Investor Relations.

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Operations

     The following table summarizes our Proved Reserves, drilling and production activity, and financial operating data by principal geographic area at the end of each of the years ending December 31, 2004, 2003 and 2002. All Venezuelan reserves are attributable to an operating service agreement between Harvest Vinccler and Petroleos de Venezuela S.A. (“PDVSA”) under which all mineral rights are owned by the Government of Venezuela. We own 80 percent of Harvest Vinccler. The reserve information presented below is net of a 20 percent deduction for the minority interest in Harvest Vinccler. Drilling and production activity and financial data are reflected without deduction for minority interest. Reserves include production projected through the end of the operating service agreement in 2012. The Venezuelan national civil work stoppage required Harvest Vinccler to shut-in production for approximately two months. We believe the two months representing this delay will be added to the original term of the operating service agreement pursuant to the force majeure provisions of the agreement.

     We disposed of our Russian investments partly in 2002 and partly in 2003. LLC Geoilbent (“Geoilbent”) and Arctic Gas Company (“Arctic Gas”) were accounted for under the equity method and were included at their respective ownership interests in our consolidated financial statements for the periods in which we owned such investments. Our year-end financial information contains results from our Russian operations based on a twelve-month period ending September 30. Accordingly, our results of operations for the years ended December 31, 2003 and 2002 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002, and from Arctic Gas, until it was sold on April 12, 2002.

     We owned 34 percent of Geoilbent, which we accounted for under the equity method. The following table presents our proportionate share of Geoilbent’s Proved Reserves (at September 30 for each respective year), drilling and production activity, and financial operating data for the period until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002.

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     We owned, free of any sale and transfer restrictions, until it was sold on April 12, 2002, 39 percent of the equity interests in Arctic Gas, which we accounted for under the equity method. The following table presents our proportionate share, free of sale and transfer restrictions, of Arctic Gas’s financial operating data for the period.

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South Monagas Unit, Venezuela (Harvest Vinccler)

General

     In July 1992, we and Venezolana de Inversiones y Construcciones Clerico, C.A., a Venezuelan construction and engineering company (“Vinccler”), signed a 20-year operating service agreement with Lagoven, S.A., an affiliate of PDVSA, to reactivate and further develop the Uracoa, Tucupita and Bombal fields. These fields comprise the South Monagas Unit. We were the first U.S. company since 1976 to be granted such an oil field development contract in Venezuela.

     The oil and natural gas operations in the South Monagas Unit are conducted by Harvest Vinccler, our 80 percent-owned subsidiary. The remaining 20 percent of the outstanding capital stock of Harvest Vinccler is owned by Vinccler. Through our majority ownership of stock in Harvest Vinccler, we make all operational and corporate decisions related to Harvest Vinccler, subject to certain super-majority provisions of Harvest Vinccler’s charter documents related to:

		Ÿ mergers;
		Ÿ consolidations;
		Ÿ sales of substantially all of its corporate assets;
		Ÿ change of business; and
		Ÿ similar major corporate events.

     Vinccler has an extensive operating history in Venezuela. It provided Harvest Vinccler with initial financial assistance and significant construction services. Vinccler provided assistance with construction projects, governmental relations and labor relations during 2004 and 2003.

     Under the terms of the operating service agreement, Harvest Vinccler is a contractor for PDVSA. Harvest Vinccler 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. The Venezuelan government maintains full ownership of all hydrocarbons in the fields. In addition, PDVSA maintains full ownership of equipment and capital infrastructure following its installation.

     The operating service agreement provides for Harvest Vinccler to receive an operating fee for each barrel of crude oil delivered. It also provides Harvest Vinccler with 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. Since 1992, the maximum total fee received by Harvest Vinccler has approximated 48 percent of West Texas Intermediate crude oil (“WTI”) price.

     In September 2002, Harvest 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. For 2004, natural gas sales averaged 85 million cubic feet (“MMcf”) per day. In addition, Harvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the gas production (“Incremental Crude Oil”). Incremental Crude Oil is sold at a price of $7.00 per barrel with the quarterly volume of such sales based on quarterly natural gas sales multiplied by the ratio of 4.5 MMBbls to 198 Bcf.

     At the end of each quarter, Harvest Vinccler prepares an invoice to PDVSA based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted contract service fees per barrel. At the end of each quarter, Harvest Vinccler also prepares invoices for natural gas sales and Incremental Crude Oil. Payment is due under the invoices by the end of the second month after the end of the quarter. Invoice amounts and payments are denominated in U.S. Dollars. Payments are wire transferred into Harvest Vinccler’s account in a commercial bank in the United States.

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     Harvest Vinccler has constructed a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA’s storage facility, the custody transfer point. The operating service agreement specifies that the oil stream may contain no more than one percent base sediment and one percent water. Quality measurements are conducted both at Harvest Vinccler’s facilities and at PDVSA’s storage facility.

     In 2003, we built and completed a 64-mile pipeline with a normal capacity of 70 MMcf of natural gas per day and a design capacity of 90 MMcf of natural gas per day, a gas gathering system, upgrades to the UM-2 plant facilities and new gas treatment and compression facilities. Harvest Vinccler borrowed $15.5 million under a project loan for the gas pipeline and related facilities and the remainder of the project costs were funded from existing cash balances and internally generated cash flow. The operating service agreement contains requirements for the measurement and quality of the natural gas delivered to PDVSA.

     In August 1999, Harvest Vinccler sold its power generation facility located in the Uracoa and Tucupita Fields. Concurrently with the sale, Harvest Vinccler entered into a long-term power purchase agreement with the purchaser of the facility to provide for the electrical needs of the field throughout the remaining term of the operating service agreement. Harvest Vinccler has entered into long-term agreements for the leasing of compression and the operation and maintenance of the gas treatment and compression facilities.

Risk Factors

     Currently, the production from the South Monagas Unit represents all of our production. This production may be reduced by actions of the Venezuelan government. In addition, political uncertainty in Venezuela increases our exposure to production disruptions and project execution risk. These risk factors and other risk factors are discussed in Item 7, Risk Factors.

Location and Geology

     The South Monagas Unit extends across the southeastern part of the state of Monagas and the southwestern part of the state of Delta Amacuro in eastern Venezuela. The South Monagas Unit is approximately 51 miles long and eight miles wide and consists of 157,843 acres, of which the fields comprise approximately one-half of the acreage. At December 31, 2004, Proved Reserves attributable to our Venezuelan operations were 105.5 MBoe (84.4 MBoe net to Harvest). This represented 100 percent of our Proved Reserves at year end. Harvest Vinccler has been primarily developing the Oficina sands in the Uracoa Field. The Uracoa Field contains 66 percent of the South Monagas Unit’s Proved Reserves.

Drilling and Development Activity

     Harvest Vinccler drilled ten oil wells and re-entered an additional six wells in 2004 and had 124 wells on production in all fields at year end 2004 in the Uracoa Field.

Uracoa Field

     Harvest Vinccler has been developing the South Monagas Unit since 1992, beginning with the Uracoa Field. There are currently 90 oil and gas producing wells in the field.

     Harvest Vinccler processes the oil, water and natural gas in the Uracoa central processing unit and ships the processed oil via pipeline to the PDVSA custody transfer point. Harvest Vinccler treats and filters produced water, then reinjects it into the aquifer to assist the natural water drive. Harvest Vinccler had reinjected produced natural gas into the natural gas cap primarily for storage conservation until November 2003, at which time it began selling the natural gas. The major components of the state-of-the-art process facility were designed in the United States and installed by Harvest Vinccler. This process design is commonly used in heavy oil production in the United States, but was not previously used extensively in Venezuela to process crude oil of similar gravity or quality. The current production facility has capacity to handle 60 thousand barrels (“MBbls”) of oil per day, 130 MBbls of water per day and injection capacity of 46 MMcf of natural gas per day and storage of up to 75 MBbls of crude oil. All gas presently being sold by Harvest Vinccler is produced from the Uracoa Field.

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Tucupita Field

     There are currently 30 oil producing wells and five water injection wells at Tucupita. The current production facility has capacity to handle 30 MBbls of oil per day, 125 MBbls of water per day and storage for up to 60 MBbls of crude oil. The oil is transported through a 31-mile, 20 MBbl per day capacity oil pipeline constructed in 2001 from Tucupita to the Uracoa plant facilities.

     Harvest Vinccler reinjects produced water from Tucupita into the aquifer to aid the natural water drive, and we utilize a portion of the associated natural gas to operate a power generation facility to supply our power needs.

Bombal Field

     The East Bombal Field was drilled in 1992, and the wells were suspended until gas sales could take place. There are currently four oil producing wells in the West Bombal Field. Portable separation, pumping and storage for 7.5 MBbl of crude oil are maintained at the field. The crude oil is pumped via a pipeline and tied into the 31-mile Tucupita oil pipeline to the Uracoa plant facilities. Harvest Vinccler began engineering and design studies in late 2004 with first gas sales expected in 2005. Gas from this field will be used to supplement gas production from Uracoa as production there declines.

Customers and Market Information

     Under the operating service agreement, all oil and natural gas produced is delivered to PDVSA for a fee. While we have substantial cash reserves, a prolonged loss of sales could have a material adverse effect on our financial condition.

Employees and Community Relations

     Harvest Vinccler has a highly skilled staff of 219 local employees and two expatriates. Harvest Vinccler has invested in a Social Community Program that includes medical programs in ophthalmologic and dental care, as well as additional social investments including the purchase of medicines and medical equipment for local communities within the South Monagas Unit.

Health, Safety and Environment

     Harvest Vinccler’s health, safety and environmental policy is an integral part of its business. Harvest Vinccler continually improves its policy and practices related to personnel safety, property protection and environmental management. These improvements can be directly attributed to its efforts in accident prevention programs and the training and implementation of a comprehensive Process Safety Management System.

North Gubkinskoye and South Tarasovskoye, Russia (Geoilbent)

     In September 2003, we sold our 34 percent minority equity investment in Geoilbent to Yukos Operational Holding Limited for $69.5 million plus $5.5 million for the repayment of intercompany loans and accounts receivable. See Note 8 – Russian Operations.

East Urengoy, Russia (Arctic Gas Company)

     Arctic Gas Company was sold in April 2002. See Note 8 – Russian Operations.

WAB-21, South China Sea (Benton Offshore China Company)

General

     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

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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. No further impairment of the property is currently required.

Location and Geology

     The WAB-21 contract area is located approximately 50 miles southeast of the Dai Hung (Big Bear) Oil Field. The block is adjacent to British Petroleum’s giant natural gas discovery at Lan Tay (Red Orchid) and 100 miles north of Exxon’s Natuna Discovery. The contract area covers several similar structural trends, each with potential for hydrocarbon reserves in possible multiple pay zones.

Drilling and Development Activity

     Due to the sovereignty issues between China and Vietnam, we have been unable to pursue an exploration program during phase one of the contract. As a result, we have obtained license extensions, with the current extension in effect until May 31, 2005. While no assurance can be given, we believe we will continue to receive license extensions so long as the sovereignty issues persist.

Domestic Operations

     We acquired a 100 percent interest in three California State offshore oil and gas leases (“the California Leases”) and a parcel of onshore property from Molino Energy Company, LLC. In 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 onshore property and the related offshore oil and gas leases.

Activities by Area

     The following table summarizes our consolidated activities by area. Total Assets represents all assets, including long-lived assets accounted for under the equity method:

Reserves

     Estimates of our Proved Reserves as of December 31, 2004 and 2003 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. The following table sets forth information regarding estimates of Proved Reserves at December 31, 2004, which are all Venezuelan. The information includes reserve information net of a 20 percent deduction for the minority interest in Harvest Vinccler. All reserves are attributable to an operating service

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agreement between Harvest Vinccler and PDVSA under which all mineral rights are owned by the Government of Venezuela.

          Estimates of commercially recoverable oil and natural gas reserves and of the future net cash flows derived therefrom are based upon a number of variable factors and assumptions, such as:

	•	historical production from the subject properties;
	•	comparison with other producing properties;
	•	the assumed effects of regulation by governmental agencies; and
	•	assumptions concerning future operating costs, municipal taxes, abandonment costs, development costs, and workover and remedial costs, all of which may vary considerably from actual results.

          All such estimates are to some degree speculative and various classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of the commercially recoverable reserves of oil and natural gas attributable to any particular property or group of properties, the classification, cost and risk of recovering such reserves and estimates of the future net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times may vary substantially. The difficulty of making precise estimates is accentuated by the fact that 44 percent of our total Proved Reserves were undeveloped as of December 31, 2004. The cost to develop the Proved Undeveloped Reserves is expected to be $102.8 million over the next three years.

          Reserve estimates are not constrained by the availability of the capital resources required to finance the estimated development and operating expenditures. In addition, actual future net cash flows will be affected by factors such as:

	•	actual production;
	•	oil and natural gas sales;
	•	supply and demand for oil and natural gas;
	•	availability and capacity of gathering systems and pipelines;
	•	changes in governmental regulations, policies or taxation; and
	•	the impact of inflation on costs.

          The timing of actual future net oil and natural gas sales from Proved Reserves as well as the year-end price, and thus their actual present value, can be affected by the timing of the incurrence of expenditures in connection with development of oil and gas properties. The 10 percent discount factor required by the SEC to be used to calculate present value for reporting purposes is not necessarily the most appropriate discount factor based on interest rates in effect from time to time, risks associated with the oil and natural gas industry and the political risks associated with operations in Venezuela. Discounted present value, regardless of what discount rate is used, is materially affected by assumptions as to the amount and timing of future production, which assumptions may, and often do, prove to be inaccurate. For the period ending December 31, 2004, we reported $1,003 million ($802 million net to us) of discounted future net cash flows before income taxes from Proved Reserves based on the SEC’s required calculations.

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Production, Prices and Lifting Cost Summary

          In the following table we have set forth by country our net production, average sales prices and average operating expenses for the years ended December 31, 2004, 2003 and 2002. The presentation for Venezuela includes 100 percent of the production, without deduction for minority interest. Geoilbent (34 percent ownership) and Arctic Gas (39 percent ownership not subject to any sale or transfer restrictions at December 2001), which are accounted for under the equity method, have been included at their respective ownership interest in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, our results of operations for the years ended December 31, 2004, 2003 and 2002 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002 and from Arctic Gas until it was sold on April 12, 2002.

Regulation

General

          Our operations are affected by political developments and laws and regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are affected by:

	•	change in governments;
	•	civil unrest;
	•	price and currency controls;
	•	limitations on oil and natural gas production;
	•	world demand for crude oil;
	•	tax, environmental, safety and other laws relating to the petroleum industry;
	•	changes in such laws;
	•	changes in administrative regulations and the interpretation and application of such rules and regulations; and
	•	changes in contract interpretation and policies of contract adherence.

          In any country in which we may do business, the oil and natural gas industry legislation and agency regulation are periodically changed for a variety of political, economic, environmental and other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some

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of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business.

Venezuela

          On February 5, 2003, Venezuela imposed currency controls and created the Commission for Administration of Foreign Currency with the task of establishing the detailed rules and regulations and generally administering the exchange control regime. These controls fix the exchange rate between the Venezuelan Bolivar and the U.S. Dollar and restrict the ability to exchange Venezuelan Bolivars for U.S. Dollars and vice versa. Initially the exchange rate was set at 1,600 Venezuelan Bolivars for each U.S. Dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. Dollar. Oil companies such as Harvest Vinccler are allowed to receive payments for oil sales in U.S. Dollars and pay U.S. Dollar-denominated expenses from those payments. We have substantial cash reserves and do not expect the Venezuelan currency conversion restriction to adversely affect our ability to meet short-term loan obligations and operating requirements for the next twelve months.

          Venezuela requires environmental and other permits for certain operations conducted in oil field development, such as site construction, drilling and seismic activities. As a contractor to PDVSA, Harvest Vinccler submits capital budgets to PDVSA for review, including capital expenditures to comply with Venezuelan environmental regulations. No capital expenditures to comply with environmental regulations were required in 2003 or 2004. Harvest Vinccler also submits requests for permits for drilling, seismic and operating activities to PDVSA, which then obtains such permits from the MEP and Ministry of Environment, as required. Harvest Vinccler is also subject to income, municipal and value-added taxes, and must file certain monthly and annual compliance reports with the national tax administration and with various municipalities.

Drilling and Undeveloped Acreage

          For acquisitions of leases and producing properties, development and exploratory drilling, production facilities and additional development activities such as workovers and recompletions, we spent approximately (excluding our share of capital expenditures incurred by equity affiliates) $39.2 million, $58.3 million and $50.6 million in 2004, 2003 and 2002, respectively. Included in these numbers is $33.5 million, $43.6 million and $44.3 million for the development of Proved Undeveloped Reserves in 2004, 2003 and 2002, respectively.

          We have drilled or participated through our equity affiliate in the drilling of wells as follows:

          All of our drilling activities are conducted on a contract basis with independent drilling contractors. We do not directly operate any drilling equipment.

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Acreage

          The following table summarizes the developed and undeveloped acreage that we owned, leased or held under operating service agreement or concession as of December 31, 2004:

Competition

          We encounter substantial competition from major oil and gas companies and independent operators in acquiring properties and leases for the exploration and development of crude oil and natural gas. The principal competitive factors in the acquisition of such oil and gas properties include staff and data necessary to identify, investigate and purchase such properties, the financial resources necessary to acquire and develop such properties, and access to local partners and governmental entities. Many of our competitors have influence, financial resources, staffs, data resources and facilities substantially greater than ours.

Environmental Regulation

          Various federal, state, local and international laws and regulations relating to the discharge of materials into the environment, the disposal of oil and natural gas wastes, or otherwise relating to the protection of the environment, may affect our operations and costs. We are committed to the protection of the environment and believe we are in substantial compliance with the applicable laws and regulations. However, regulatory requirements may, and often do, change and become more stringent, and there can be no assurance that future regulations will not have a material adverse effect on our financial position, results of operations and cash flows.

Employees

          At December 31, 2004, we had 19 full-time employees. Harvest Vinccler had 219 employees and our Moscow office had 16 employees. We augment our staffs from time to time with independent consultants, as required.

Title to Developed and Undeveloped Acreage

          All Venezuelan reserves are attributable to an operating service agreement between Harvest Vinccler and PDVSA, under which all mineral rights are owned by the Government of Venezuela.

          The WAB-21 petroleum contract 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 a third party. The territorial dispute has existed for many years, and there has been limited exploration and no development activity in the area under dispute. It is uncertain when or how this dispute will be resolved, and under what terms the various countries and parties to the agreements may participate in the resolution.

Item 2. Properties

          In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month. We moved 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 expired in December 2004. We subleased all of the office space in California for rents that approximated our lease costs. See also “Item 1 – Business” for a description of our oil and gas properties and reserves.

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Item 3. Legal Proceedings

          Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Harvest Vinccler, C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, 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.

          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.

Item 4. Submission of Matters to a Vote of Security Holders

     None.

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PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

          Our Common Stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HNR”. As of December 31, 2004, there were 36,779,409 shares of common stock outstanding, with approximately 698 stockholders of record. The following table sets forth the high and low sales prices for our Common Stock reported by the NYSE.

          On February 11, 2005, the last sales price for the common stock as reported by the NYSE was $12.26 per share.

          Our policy is to retain earnings to support the growth of our business. Accordingly, our board of directors has never declared a cash dividend on our common stock.

Item 6. Selected Financial Data

SELECTED CONSOLIDATED FINANCIAL DATA

          The following table sets forth our selected consolidated financial data for each of the years in the five-year period ended December 31, 2004. The selected consolidated financial data have been derived from and should be read in conjunction with our annual audited consolidated financial statements, including the notes thereto. Our year-end financial information contains results from our Russian operations through our equity affiliates based on a twelve-month period ending September 30. Accordingly, our results of operations for the years ended December 31, 2003, 2002, 2001 and 2000 reflect results from Geoilbent (until sold on September 25, 2003) for the twelve months ended September 30, 2002, 2001 and 2000, and from Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2001 and 2000.

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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

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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 this Form 10-K, the following factors should be carefully considered when evaluating us.

          Our only source of production 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.

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          Political uncertainty in Venezuela increases our exposure to production disruptions and project execution risk. Political and economic uncertainty is very high in Venezuela. From December 14, 2002 through February 6, 2003, PDVSA was unable to accept our oil due to the national civil work stoppage in Venezuela protesting the government of President Chavez. As a result, Harvest Vinccler’s 2002 oil deliveries were reduced by an estimated 0.6 million barrels and 2003 deliveries were reduced by an estimated 1.2 million barrels. In response to the national civil work stoppage, the Venezuelan government terminated several thousand PDVSA employees. As a result of the situation in PDVSA, its payment to Harvest 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.

          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 also the Minister of MEP. The political situation in Venezuela adds to the risk that we will be able to enforce the operating service agreement in Venezuela and could lead to further civil unrest and work stoppages that 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 uncertainty to our continued operations. These same risk factors could also 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 believe it is possible to comply with this 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.

          Our strategy to focus on Russia carries deal execution, operating, financial, legal and political risks. While we believe our established presence in Russia and our experience and skills from prior operations position 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. 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. Our strategy in Russia depends on our ability to have operational and financial control. Recently, the Russian government has restricted certain “strategic” projects in Russia to majority-owned Russia companies. Such a policy, if widely applied, could adversely affect our ability to acquire projects in Russia consistent with our 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 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.

          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.

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          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, 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 have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan Bolivar to the U.S. Dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates. Our Venezuelan receipts are denominated in U.S. Dollars, and most expenditures are in U.S. Dollars as well. For a discussion of currency controls in Venezuela, see Capital Resources and Liquidity below. Successful acquisition of projects in Russia may also expose us to foreign currency risk in that country.

          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. 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 and demand for oil;
	•	market uncertainty;
	•	the level of consumer product demand;
	•	weather conditions;
	•	domestic and foreign governmental 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, 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. We did not incur ceiling test write-downs in 2004 in the consolidated financial statements of the wholly-owned and majority owned subsidiaries. Equity in Net Losses of Affiliated Companies

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includes a $32.3 million (our share) ceiling test write-down recorded by Geoilbent during their fiscal year ended 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. See Our 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 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, 2004, approximately 44 percent of our estimated Proved Reserves were undeveloped. Undeveloped reserves, by their nature, are less 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. See Supplemental Information on Oil and Natural Gas Producing Activities.

          You should not assume that the present value of future net revenues referred to is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in demand, our ability to produce or in governmental regulations, 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.

          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

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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.

Results of Operations

          We include the results of operations of Harvest 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 included 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 and 2002 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, 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, 2004 and the financial condition as of December 31, 2004 and 2003 in conjunction with our Consolidated Financial Statements and related Notes thereto.

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

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.

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          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 2003 was $27.3 million, or $0.74 per diluted share, compared with $100.4 million, or $2.78 per diluted share, for 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 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 2003 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 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 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 2003 compared with 2002. This was primarily due to lower production offset by higher world crude oil prices. Our sales quantities for 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 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 2003 compared with 2002 primarily due to decreased production from Venezuela and the addition of natural gas reserves in 2002. Depletion expense per barrel of oil produced from Venezuela during 2003 was $2.52 compared with $2.56 during 2002. 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 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 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 an allowance for uncollectible accounts in prior years.

          Taxes other than on income decreased $0.7 million, or 17 percent, during 2003 compared with 2002. This was primarily due to decreased Venezuelan municipal taxes which result 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 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 2003 compared with 2002 due to lower average outstanding debt

23

balances for 2003 compared with 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 2003 compared with 2002. This was due to the significant devaluation of the Bolivar and Bolivar currency controls imposed in February 2003 which fixed the exchange rate between the Bolivar and the U.S. Dollar and restricts the ability to exchange Venezuelan Bolivars for dollars and vice versa.

          We realized income before income taxes and minority interest of $71.8 million during 2003 compared with income of $169.8 million in 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 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 interest decreased $47.4 million for 2003 compared with 2002. This decrease was due to the sale of our minority equity investment in Geoilbent partially offset by decreased production of Harvest Vinccler.

          Equity in net losses of affiliated companies decreased $29.0 million during 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. See Note 9 – Russian Operations. The year ended 2002 included a loss of $1.5 million on Arctic Gas.

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 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. Our 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, and restricted the ability to exchange Venezuelan Bolivars for U.S. Dollars and vice versa. Initially the exchange rate was fixed at 1,600 Venezuelan Bolivars for each U.S. Dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. Dollar. Oil companies, such as Harvest Vinccler are allowed to receive payments for oil sales in U.S. Dollars and pay U.S. Dollar-denominated expenses from those payments. We have substantial cash reserves and do not expect the Venezuelan currency conversion restriction to adversely affect our ability to meet our short-term loan obligations and operating requirements for the next twelve months.

          Our ability to replace production with new reserves is dependent upon the ability of Harvest Vinccler to make loan repayments, dividends and other cash payments to us. However, there have been, and may again be, interruptions in oil and gas sales or there may be contractual obligations or legal impediments to receiving dividends or distributions from Harvest Vinccler, which could affect the ability of Harvest Vinccler to remit funds to us.

          Debt Reduction. In 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 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 were released from all obligations related to the 2007 Notes upon deposit of the 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

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 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. 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.

          Working Capital. Our capital resources and liquidity are affected by the 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 the PDVSA payment inflows, our cash balances can increase and decrease dramatically on a few dates during the year.

          Harvest 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. A future disruption of production could trigger the debt acceleration 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:

          At December 31, 2004, we had current assets of $172.2 million and current liabilities of $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 ration of 4:1 at December 31, 2003. The decrease in working capital of $48.2 million was primarily due to the prepayment of the 2007 Notes offset by higher crude oil prices and an increase in crude oil and natural gas sales in Venezuela.

          Cash Flow from Operating Activities. During the years ended December 31, 2004 and 2003, net cash provided by operating activities was approximately $74.1 million and $38.5 million, respectively. The $35.6 million increase was due to natural gas sales, higher crude oil prices and the sale of our California onshore property, offset by Harvest Vinccler’s purchase of two WTI crude oil puts and the loss of $2.9 million on the early repayment of 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, 2004 and 2003, we had drilling and production-related capital expenditures of approximately $39.1 million and $60.9 million, respectively. The decrease in capital expenditures is due to the completion of our gas project in 2003 and the 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 largely at our discretion, although PDVSA has recently attempted to limit Harvest Vinccler’s capital spending (see Risk Factors). Our remaining capital commitments worldwide support our search for new acquisitions, are relatively minimal and are substantially at our discretion. 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, Harvest Vinccler

25

repaid all of its Bolivar denominated debt ($2.2 million) and $1.2 million of its U.S. Dollar debt, which was an acceleration of the next two principal payments.

          Contractual Obligations. We have a lease obligation of approximately $17,000 per month for our Houston office space. This lease runs through 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 Board of Directors Deferred Compensation Plan at December 31, 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.

          While we can give no assurance, we currently believe that our cash flow from operations coupled with our cash on hand will provide sufficient capital resources and liquidity to fund our planned capital expenditures, investments in and advances to affiliates, and quarterly 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 disruptions or limitations on our production and that PDVSA will pay our invoices timely. Actual results could be materially affected if there is a significant change in our expectations or assumptions (see Risk Factors). Future cash flows are subject to a number of variables including, but not limited to, the level of production and prices, as well 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.

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 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. See Note 1 – Derivatives and Hedging.

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

          Within the United States, inflation has had a minimal effect on us, but it is potentially an important factor in results of operations in Venezuela. With respect to 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, while a minor amount of local transactions in Venezuela are conducted in local currency. If the rate of increase in the value of the U.S. Dollar compared with the Bolivar continues to be less than the rate of inflation in Venezuela, then inflation could be expected to have an adverse effect on Harvest Vinccler.

          During the year ended December 31, 2004, our net foreign exchange loss attributable to our international operations was $0.6 million. The U.S. Dollar and Bolivar exchange rates were fixed in February 2003 and adjusted in February 2004. No gains or losses were recognized from February 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. 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.

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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 accounted 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, Harvest Vinccler invoices PDVSA based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. Dollar contract service fees per barrel.

Property and Equipment

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

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

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Income Taxes

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

Foreign Currency

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

New Accounting Pronouncements

          In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard 123 (revised 2004) Share-Based Payment (“SFAS 123R”), an amendment to Statement of Accounting Standards 123 and 95. SFAS 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. Public companies with a calendar year end will be required to adopt the provisions of the standard effective for periods beginning after June 15, 2005. We do not expect SFAS 123R to have a material effect on our consolidated financial 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 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 off-balance sheet arrangements.

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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 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. Harvest 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. See Note 1 – Derivatives and Hedging for a complete discussion of our derivative activity. We had no hedging transactions in place for our 2004 production.

Interest Rates

          Total short-term debt at December 31, 2004 of $11.8 million consisted of Harvest Vinccler U.S. Dollar denominated variable rate loans. A hypothetical 10 percent adverse change in the interest rate would not have a material affect on our results of operations.

Foreign Exchange

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

Item 8. Financial Statements and Supplementary Data

          The information required by this item is included herein on pages S-1 through S-33.

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

          None.

Item 9A. Controls and Procedures

          The 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.

29

     Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures to ensure that material information relating to us, including our consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the Board of Directors.

     Based on their evaluation as of December 31, 2004, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) 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 our internal control 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 issued an attestation report which is included herein.

Item 9B. Other Information

     None.

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PART III

Item 10. Directors and Executive Officers of the Registrant

     Please refer to the information under the captions “Election of Directors” and “Executive Officers” in our Proxy Statement for the 2005 Annual Meeting of Shareholders.

Item 11. Executive Compensation

     Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the 2005 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 2005 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 2005 Annual Meeting of Shareholders.

Item 14. Principal Accounting Fees and Services

     Please refer to the information under the caption “Independent Registered Public Accounting Firm” in our Proxy Statement for the 2005 Annual Meeting of Shareholders.

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PART IV

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

32

33

(b) Reports on Form 8-K

On November 4, 2004, we filed a Report on Form 8-K with the Securities and Exchange Commission in which we furnished a press release announcing our results for the third 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 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 December 14, 2004, we filed a Report on Form 8-K with the Securities and Exchange Commission in which we furnished a press release providing financial and operating guidance assumptions for 2005.

34

REPORT OF INDEPENDENT REGISTERED 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)(1) present fairly, in all material respects, the financial position of Harvest Natural Resources, Inc. and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the 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
February 22, 2005

S-1

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

See accompanying notes to consolidated financial statements.

S-2

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

See accompanying notes to consolidated financial statements.

S-3

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)

See accompanying notes to consolidated financial statements.

S-4

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)