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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No.: 1-10762

HARVEST NATURAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)


Delaware		77-0196707
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)
1177 Enclave Parkway, Suite 300
Houston, Texas		77077
(Address of principal executive offices)		(Zip Code)

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

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


Title of each class		Name of each exchange on which registered

Common Stock, $.01 Par Value		NYSE

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


Title of each class		Name of each exchange on which registered

None		None

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. Large Accelerated Filer o Accelerated Filer þ Non-Accelerated Filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

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, 2005: $415,711,721.

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 10, 2006, shares outstanding: 37,093,595.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for the 2006 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.

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 reserves, successful conversion of Venezuelan assets to a mixed company, 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 natural gas properties, the permitting and the 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 natural gas properties that meet its objectives, changes in operating costs, overall economic conditions, political stability, 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 Item 1A — Risk Factors and 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 natural 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 of the People’s Republic of China (“China”). Currently, all of our producing operations are conducted through our 80 percent-owned Venezuelan subsidiary, Harvest Vinccler, C.A. (“Harvest Vinccler”), which operates the South Monagas Unit in Venezuela under an operating service agreement with Petroleos de Venezuela S.A. (“PDVSA”). During 2005, the government of Venezuela initiated a series of actions to compel companies with operating service agreements to convert those agreements into new companies in which PDVSA has a majority interest. These actions adversely affected our operations in Venezuela in a number of ways. See Item 1 – Business, Operations, Item 1A — Risk Factors, and Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations for a complete description of these and other events during 2005.

Due to the actions taken by the government of Venezuela, we were unable to carry out our planned development program for 2005. Moreover, our ability to carry out future programs is uncertain. As a consequence, we have reduced our proved reserves by approximately 50 percent and we estimate that the discounted future net cash flows from our proved reserves has been reduced by approximately 60 percent. As a result of this reduction, as of December 31, 2005, we had total estimated proved reserves in the South Monagas Unit, net of minority interest, of 36 million barrels of oil equivalent (“MMBoe”), and a standardized measure of discounted future net cash flows of $329 million. See the discussion in Item 1 – Business, Operations below, for a more detailed discussion of our proved reserves and the reserve reduction.

As of December 31, 2005, we had total assets of $400.8 million. We had cash in the amount of $163.0 million, no long-term debt, total revenues of $236.9 million and net cash provided by operating activities of $114.7 million. For the year ended December 31, 2004, we had total assets of $367.5 million. We had cash in the amount of $84.6 million, no long-term debt, total revenues of $186.1 million and net cash provided by operating activities of $74.1 million.

Our business strategy is to be a growing international company that seeks and develops large known resources in countries perceived as politically challenged. Our strategy is to segregate and diversify risk by adding fields in other countries. In executing our business strategy, we strive to:

	•		maintain financial prudence and rigorous investment criteria;

	•		enhance access to capital markets;

	•		create a diversified portfolio of large assets;

	•		maximize cash flows from existing operations;

	•		use our experience, skills to acquire new projects; and

	•		keep our organizational capabilities in line with our rate of growth.

While our strategy does not focus on unexplored areas, we will consider appropriate exploration opportunities that have large potential scale and the cost of failure is low.

In Venezuela, we seek to deliver maximum operating cash flow through the efficient management of our capital expenditure programs and cost structure. Our Venezuelan producing properties generate net cash from operating activities in excess of projected capital expenditures.

We have substantial cash flow due to current oil prices, current production levels for both oil and natural gas and the current capital reinvestment restrictions in Venezuela. We believe this provides us with the ability to pursue growth opportunities in Russia and other countries while at the same time maintaining a strong balance sheet. However, in 2005 and to date in 2006, we have been unable to obtain permits from the Ministry of Energy and Petroleum (“MEP”) to drill wells, which are critical to our ability to fully execute our drilling and facilities program. These difficulties have adversely affected our production and may affect our ability to pursue growth opportunities in Russia and other countries.

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 1A – Risk Factors, Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations and other information set forth elsewhere in this Form 10-K for a description of these and other risk factors.

Effective October 1, 2005, James A. Edmiston was elected President and Chief Executive Officer. The election follows the retirement of Dr. Peter J. Hill, who remains on our Board of Directors. Mr. Edmiston joined us in September 2004 when he was named Executive Vice President and Chief Operating Officer. Mr. Edmiston was elected to the Board of Directors at the May 2005 Annual Meeting of Stockholders.

In September 2005, Byron A. Dunn was elected Senior Vice President, Corporate Development. Mr. Dunn resigned his position on the Board of Directors where he served from October 2000 until March 2002 and again from December 2003 until September 2005.

In November 2005, J. Michael Stinson was elected to our Board of Directors.

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.

Operations

During 2005, Harvest Vinccler was not able to execute its budgeted facilities and drilling program due to the refusal of PDVSA and MEP to process and grant necessary permits. As a result, Harvest Vinccler suspended its drilling program for the year, and completed only one new well. Due to the lack of drilling in 2005, daily production of oil and natural gas volumes declined. Crude oil sales volumes were also affected by a curtailment of our oil deliveries during the first part of 2005. In August 2005, we submitted a proposed 2006 work program and budget to PDVSA which, under circumstances where we have reasonable assurances that PDVSA will adhere to the provisions of our operating service agreement, would enable Harvest Vinccler to increase deliveries through an accelerated drilling program. Under the terms of the existing operating service agreement, Harvest Vinccler’s 2006 work program and budget was deemed approved in October 2005. There are ongoing discussions between Harvest Vinccler and PDVSA on the terms for commencing the 2006 work program. In 2005, Harvest Vinccler was also notified by the MEP that it considered all operating service agreements in Venezuela to be illegal and that the agreements must be converted into incorporated companies in which PDVSA will have a controlling interest (a “mixed company”). MEP has stated that the deadline for conversion of the agreements into mixed companies is March 31, 2006. While Harvest Vinccler is engaged in good faith negotiations with MEP and PDVSA on converting to a mixed company, significant issues remain open, and the timing or outcome is uncertain. The resumption of any significant drilling operations in Venezuela is unlikely until these uncertainties are resolved.

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, 2005, 2004 and 2003. All Venezuelan reserves are attributable to an operating service agreement between Harvest Vinccler and Petroleos de Venezuela S.A. 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.


	Harvest Vinccler
	Year Ended December 31,
	2005		2004		2003
	(Dollars in 000’s)
RESERVE INFORMATION:
Proved Reserves (MBoe)		36,105		84,418		96,364
Standardized measure of discounted future net cash flows	$	329,438	$	544,980	$	366,770
DRILLING AND PRODUCTION ACTIVITY:
Gross wells drilled		1		16		3
Average daily production (Boe)		35,732		36,418		20,130
FINANCIAL DATA:
Oil and natural gas revenues	$	236,941	$	186,066	$	106,095
Expenses:
Operating expenses and taxes other than on income		39,969		33,297		31,445
Depletion		41,175		34,108		19,599
Income tax expense		65,943		38,968		12,158

Total expenses		147,087		106,373		63,202

Results of operations from oil and natural gas producing activities	$	89,854	$	79,693	$	42,893

Due to the actions of the Venezuelan government, the 2005 reserve information shown above has been reduced to exclude reserves formerly classified as proved undeveloped. Under SEC standards for the reporting of oil and natural gas reserves, proved reserves are estimated quantities of crude oil and natural gas “which geological data and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.” (Emphasis added). Our quantities of proved reserves have been reduced to remove undeveloped reserves because the actions taken by the Venezuelan government in 2005 under our operating service agreement have created uncertainty as to whether those reserves will be recovered under the economic and operating conditions which currently exist in Venezuela. For ease of reference, the reduced reserves are hereafter referred to as “Contractually Restricted Reserves”. The following table is a reconciliation of the impact of the reduction of our year-end proved reserves.


	Proved Reserves
	Total			Developed			Undeveloped
	(amounts in thousands)
Total MBoe (net of minority interest)
Proved Reserves beginning of the year		84,418			47,176			37,242
Revisions of previous estimates^(a)		(37,880	)		(638	)		(37,242	)
Production		(10,433	)		(10,433	)		—

Proved Reserves end of the year		36,105			36,105			—


(a)		Includes primarily Contractually Restricted Reserves as well as other minor revisions.

We disposed of our 34 percent interest in LLC Geoilbent (“Geoilbent”), a Russian company, in 2003. We accounted for Geoilbent under the equity method and included its ownership interest in our consolidated financial statements for the periods in which we owned the investment. Our year-end financial information contains results from our Russian operation based on a twelve-month period ending September 30. Accordingly, our results of operations for the year ended December 31, 2003 reflect results from Geoilbent until it was sold on September 25, 2003. The following table presents our proportionate share of Geoilbent’s proved reserves at September 30, 2003, drilling and production activity, and financial operating data for the period until it was sold on that date.


	Geoilbent
	Year Ended
	September 30, 2003
	(Dollars in 000’s)
RESERVE INFORMATION:
Proved Reserves		(a	)
Standardized measure of discounted future net cash flows		(a	)
DRILLING AND PRODUCTION ACTIVITY:
Gross development wells drilled		(a	)
Net development wells drilled		(a	)
Average daily production		5,242
FINANCIAL DATA:
Oil and natural gas revenues	$	27,876
Expenses:
Operating, selling and distribution expenses and taxes other than on income		16,088
Depletion		6,215
Write-down of oil and gas properties		32,300
Income tax expense		2,073

Total expenses		56,676

Results of operations from oil and natural gas producing activities	$	(28,800	)


(a)		Geoilbent was sold on September 25, 2003.

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 (the “operating service agreement” or “OSA”). 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:

	•		mergers;

	•		consolidations;

	•		sales of substantially all of its corporate assets;

	•		change of business; and

	•		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. In August 2005, Harvest Vinccler entered into a Transitory Agreement with PDVSA (the “Transitory Agreement”). The Transitory Agreement provides that effective January 1, 2005, the total amounts paid under the OSA will not exceed 66.67 percent of the total value of the crude oil as determined under an Annex to the Transitory Agreement. Historically, our maximum total fee under the OSA averaged approximately 48 percent of the price of West Texas Intermediate (“WTI”). Under the fee limit in the Transitory Agreement, the new fee has historically averaged approximately 47 percent of the price of WTI.

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 thousand standard cubic feet (“Mcf”). For 2005, natural gas sales averaged 70 million cubic feet (“MMcf”) per day. In addition, Harvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil (“MMBbls”) stipulated as additional volumes resulting from the natural 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. The operating service agreement stipulates invoice amounts and payments are to be denominated in U.S. Dollars. Notwithstanding these contractual requirements, PDVSA paid the fee for first quarter 2005 deliveries 50 percent in U.S. Dollars and 50 percent in Venezuelan Bolivars (“Bolivars”). Subsequent quarterly payments for 2005 have been received 75 percent in U.S. Dollars and 25 percent in Bolivars. U.S. Dollar payments are wire transferred into Harvest Vinccler’s account in a commercial bank in the United States and the Bolivar payments are deposited in a bank in Venezuela. PDVSA’s payment for the first quarter of 2005 was late by 28 days and was short $9.8 million. Upon signing the Transitory Agreement, the underpayment, to the extent of the new limit on service fees, was paid.

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. 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 in the future 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 1A – Risk Factors and Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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, 2005, proved reserves attributable to our Venezuelan operations were 45 MMBoe (36 MMBoe net to Harvest). This represented 100 percent of our proved reserves at year end. The 2005 reserve information does not include Contractually Restricted Reserves. See Item 1 – Business, Operations. Harvest Vinccler has been primarily developing the Oficina sands in the Uracoa Field. The Uracoa Field contains 73 percent of the South Monagas Unit’s proved reserves.

Drilling and Development Activity

Harvest Vinccler drilled one well and had 108 wells on production in all fields at year end 2005 in the South Monagas Unit.

Uracoa Field

Harvest Vinccler has been developing the South Monagas Unit since 1992, beginning with the Uracoa Field. There are currently 80 oil and natural gas producing wells in the field.

Harvest Vinccler processes the oil, water and natural gas in the Uracoa central processing unit and transports 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 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 to PDVSA pursuant to an amendment to the operating service agreement. 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 storage of up to 75 MBbls of crude oil. All natural gas presently being sold by Harvest Vinccler is produced from the Uracoa Field.

Tucupita Field

There are currently 24 oil producing wells and five water injection wells at Tucupita. The Tucupita production facility has capacity to process 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 MBbls per day capacity oil pipeline 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 production from the wells was halted until the produced natural gas could be sold. There are currently four oil producing wells in the West Bombal Field. The fluid produced from West Bombal Field flows through a six mile pipeline and is tied into the 31-mile Tucupita oil pipeline to the Uracoa plant facilities. Development of this field has been postponed due to the refusal of PDVSA and MEP to process and grant necessary permits. See Item 1 — Business and Item 1A – Risk Factors. Natural gas from this field was intended to be used to supplement natural gas sales 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 252 local employees and one expatriate. 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 7 – Russian Operations.

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

General

Location and Geology

The WAB-21 contract area is located in the West Wan’an Basin (Nam Con Son) on the South China Sea. Its western edge lies approximately 50 miles southeast of the Dai Hung (Big Bear) Oil Field, which recently discovered additional oil reserves in deeper Miocene zones. The block is adjacent to the east of British Petroleum’s giant natural gas discoveries at Lan Tay and Lan Do, which are estimated to contain two trillion cubic feet of natural gas. It is also adjacent to the 2005 Thien Ung discovery which tested oil and natural gas. The contract area covers several similar structural trends involving similar geological formations, each with potential for hydrocarbon reserves in possible multiple pay zones.

Drilling and Development Activity

Due to the border dispute 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, 2007. While no assurance can be given, we believe we will continue to receive license extensions so long as the border disputes persist.

Activities by Area

The following table summarizes our consolidated activities by area.


			Other		Total
(in thousands)	Venezuela		Foreign		Foreign		United States		Total
Year ended December 31, 2005
Oil and natural gas sales	$	236,941		—	$	236,941		—	$	236,941
Total Assets	$	258,268	$	317	$	258,585	$	142,213	$	400,798

Year ended December 31, 2004
Oil and natural gas sales	$	186,066		—	$	186,066		—	$	186,066
Total Assets	$	309,794	$	385	$	310,179	$	57,307	$	367,486

Year ended December 31, 2003
Oil and natural gas sales	$	106,095		—	$	106,095		—	$	106,095
Total Assets	$	241,855	$	237	$	242,092	$	132,256	$	374,348

Reserves

Estimates of our proved reserves as of December 31, 2005 and 2004 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, 2005, which are all in Venezuela. 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 agreement between Harvest Vinccler and PDVSA under which all mineral rights are owned by the Government of Venezuela. The Ryder Scott report states: “The reserve report is prepared following SEC’s definitions and guidelines. One specific guideline is the estimation of proved reserves requires a demonstration with reasonable certainty that the proved reserves are recoverable in future years under existing economic and operating conditions. This year’s report does not include reserves in the proved undeveloped category due solely to the uncertainty in future capital spending by Harvest Vinccler C.A. to drill and develop this category of reserves is a result of the actions and statements of the Venezuelan authorities during the year 2005.” (For management’s discussion of the reserve reduction, see Item 1 – Business, Operations above.) A detailed reconciliation of proved reserves and values can be found on Table IV and Table V of the Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) under Item 15.


	Venezuela
Net Crude Oil and Condensate (MBbls) – Proved		28,249
Net Natural Gas (MMcf) – Proved		47,134

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;

	•		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; and

	•		assumptions concerning contractual rights to develop reserves and whether those rights will be honored.

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.

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, contracting policies, taxation or other policies;

	•		contract sanctity; 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 natural 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, 2005, we reported $412 million ($329 million net to us) of discounted future net cash flows from proved reserves based on the SEC’s required calculations.

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, 2005, 2004 and 2003. The presentation for Venezuela includes 100 percent of the production, without deduction for minority interest. Geoilbent (34 percent ownership), which is accounted for under the equity method, has been included at its 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, 2005, 2004 and 2003 reflect results from Geoilbent until it was sold on September 25, 2003.


	Year Ended December 31,
	2005			2004			2003
Venezuela(a)
Crude Oil Production (Bbls)		8,762,687			8,152,261			7,347,399
Natural Gas Production (Mcf)		25,677,460			31,059,416			2,660,241
Average Crude Oil Sales Price ($per Bbl)(b)	$	24.02		$	18.90		$	14.07
Average Natural Gas Sales Price ($ per Mcf)	$	1.03		$	1.03		$	1.03
Average Operating Expenses ($ per Boe)	$	3.05		$	2.50		$	4.00
Russia
Geoilbent(c)(d)
Net Crude Oil Production (Bbls)		(d	)		(d	)		1,913,187
Average Crude Oil Sales price ($per Bbl)		(d	)		(d	)	$	14.52
Average Operating Expenses ($per Bbl)		(d	)		(d	)	$	2.83


(a)		Information represents 100 percent of production.

(b)		Average crude oil sales price after hedging activity.

(c)		Information represents our ownership interest.

(d)		Geoilbent was sold on September 25, 2003.

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;

	•		tax, environmental, safety and other laws relating to the petroleum industry;

	•		changes in laws relating to the petroleum industry;

	•		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 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 Bolivar and the U.S. Dollar and restrict the ability to exchange Bolivars for U.S. Dollars and vice versa. Oil companies such as Harvest Vinccler are allowed to receive payments for oil and natural gas sales in U.S. Dollars and pay U.S. Dollar-denominated expenses from those payments. Notwithstanding the contractual provisions of our operating service agreement which requires all payments to be in U.S. Dollars, PDVSA paid 50 percent of 2005 first quarter oil and natural gas sales in Bolivars. Subsequent quarterly payments for 2005 were paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar, but Harvest Vinccler projects that it will be able to utilize its Bolivars to meet local obligations. 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 2004 or 2005. 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. During 2005 and continuing into 2006, PDVSA and MEP have refused to approve or issue permits and, as a result, Harvest Vinccler suspended its drilling and facilities program in 2005. 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) $9.0 million, $39.2 million and $58.3 million in 2005, 2004 and 2003, respectively. Included in these numbers is $8.9 million, $33.5 million and $43.6 million for the development of proved undeveloped reserves in 2005, 2004 and 2003, respectively.

We have participated in the drilling of wells as follows:


	Year Ended December 31,
	2005				2004				2003
	Gross		Net		Gross		Net		Gross		Net
Wells Drilled:
Development:
Crude oil		1		0.8		16		12.8		3		2.4

Average Depth of Wells (Feet)		—		4,349		—		5,443		—		6,095

Producing Wells⁽¹⁾:
Crude Oil		108		86.4		124		99.2		111		88.8


⁽¹⁾		The information related to producing wells reflects wells we drilled, wells we participated in drilling and producing wells we acquired.

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

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, 2005:


	Developed				Undeveloped
	Gross		Net		Gross		Net
Venezuela		11,726		9,381		146,117		116,894
China		—		—		7,470,080		7,470,080

Total		11,726		9,381		7,616,197		7,586,974

Competition

We encounter substantial competition from major, national and independent oil and natural gas companies 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 natural 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, 2005, our Houston office had 15 full-time employees. Harvest Vinccler had 252 employees and our Moscow office had 10 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 border dispute between China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with a third party. The border 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 1A. 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 interests in Venezuela may be unlawfully expropriated by the Venezuelan government. All of our production and operating revenues are derived from Harvest Vinccler through its operations of the South Monagas Unit under the operating service agreement with PDVSA. The government of Venezuela has announced that all operating service agreements will cease to exist in 2006 and that operations under those agreements will be converted to mixed companies in which PDVSA has a controlling interest. The government has stated that it will reclaim the interests of operators who do not convert to a mixed company. While we are engaged in good faith negotiations with MEP and PDVSA for the conversion of Harvest Vinccler’s operating service agreement to a mixed company, there is no assurance that a conversion will be possible under acceptable terms. Based upon the government’s statements and actions, there is a risk that if Harvest Vinccler is unable to agree with Venezuela on the terms of a mixed company, its interests may be unlawfully expropriated or actions may be taken to prevent or render impossible continued operations. Expropriatory acts by Venezuela would likely cause us to seek international arbitration for the loss of our investment.

Our only source of production may be reduced further by actions of the Venezuelan government. Harvest Vinccler began the year with average oil deliveries of 29,000 barrels of oil per day (“Bopd”) and is currently averaging about 22,000 Bopd. Natural gas deliveries at the beginning of the year were averaging 79 million cubic feet a day (MMCFpd), and are currently averaging about 56 MMCFpd. The decline is due to PDVSA’s refusal to allow us to carry out our drilling and facilities program for 2005 and the natural decline of the field. In August 2005, we submitted a proposed 2006 work program and budget to PDVSA which, under circumstances where we have reasonable assurances that PDVSA will adhere to the provisions of our operating service agreement, would enable Harvest Vinccler to increase deliveries through an accelerated drilling program. Under the terms of our existing operating service agreement, Harvest Vinccler’s 2006 work program and budget were deemed approved in October 2005. There are discussions on going between Harvest Vinccler and PDVSA on the terms for commencing the 2006 program. Without the ability to drill new wells, crude oil and natural gas volumes will continue to decline.

Crude oil volumes for 2005 were also affected by PDVSA’s curtailment of our crude oil deliveries during the first part of the year. PDVSA may curtail us again in the future.

Future Payments to Harvest Vinccler may be adversely affected by actions of the Venezuelan government. Harvest Vinccler was paid 28 days late for deliveries in the first quarter of 2005. In addition, the payment was paid 50 percent in Bolivars, notwithstanding the provisions of the operating service agreement which requires all payments to be in U.S. Dollars. Subsequent 2005 quarterly payments for oil and natural gas sales were paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar; however, at 25 percent Bolivar payment levels, Harvest Vinccler projects that it will be able to utilize its Bolivars to meet local obligations.

At the direction of MEP, PDVSA imposed a limit on our maximum total fee equal to two-thirds of the total value of the crude oil delivered to PDVSA beginning January 1, 2005. This caused an underpayment to Harvest Vinccler for deliveries in the first quarter of 2005. In August 2005, Harvest Vinccler signed the Transitory Agreement with PDVSA which included a two-thirds limit on fees, and PDVSA paid the underpaid amount to the extent of that limit.

Harvest Vinccler has been paid for oil and natural gas deliveries made through December 31, 2005 and expects to be paid for first quarter 2006 deliveries. Venezuela has not indicated how it intends to pay for deliveries after March 31, 2006, as it has stated that all operating service agreements must be converted to mixed companies by that date.

Failure or refusal of PDVSA to pay Harvest Vinccler’s services fees, significant underpayment or withholding of fees, substantial payments by PDVSA in Bolivars, or the inability to convert the Bolivars into U.S. Dollars could, individually or in the aggregate, have a further material adverse effect on our financial position, results of operations and cash flows.

Actions by SENIAT to collect claimed back taxes could threaten the viability of our Venezuelan operations. In 2005, the Venezuelan income tax authority (the “SENIAT”) announced that the income tax rate paid by companies with operating service agreements would be retroactively increased from 34 percent to 67 percent for 2001 and from 34 percent to 50 percent for all years thereafter. The SENIAT completed a tax audit of Harvest Vinccler for the tax years 2001 through 2004, and in July 2005, the SENIAT issued a preliminary tax assessment of 184 billion Bolivars or approximately $85 million at the current exchange rate. In addition, the SENIAT imposed penalties equal to 10 percent of the preliminary tax assessment. A significant part of the preliminary tax assessment received relates to the retroactive increase in taxes above the existing rate of 34 percent. The assessment also relates to the disallowance of some deductions and attribution of additional income. Upon review of the preliminary tax assessment, and after discussions with officials in the SENIAT, Harvest Vinccler determined not to contest two elements of the preliminary tax assessment and made payments totaling $5.3 million. In September and October 2005, Harvest Vinccler filed an answer and evidentiary support with the SENIAT contesting all other elements of the preliminary tax assessment. The SENIAT and Harvest Vinccler have formed a working group to review the tax assessment for possible resolution of these claims.

The SENIAT has up to one year to consider Harvest Vinccler’s answer and to determine whether, or to what extent, to issue a final tax assessment. A final tax assessment by the SENIAT may also include additional penalties between 25 percent and 200 percent of the unpaid tax. We are advised that the average penalty imposed by the SENIAT historically has been 112.5 percent of the unpaid tax unless extenuating or aggravating circumstances apply. If a final tax assessment is issued, Harvest Vinccler may file a further administrative appeal with the SENIAT. During the period of review by the SENIAT, any payment obligation is suspended. However, during this period the SENIAT may seek a court order allowing it to take precautionary measures such as attaching assets. After exhausting administrative appeals, Harvest Vinccler may either pay the tax or file a judicial appeal. If a judicial appeal is filed, the payment obligation may be suspended at the discretion of the court. While there are no established rules regarding payment suspension, we understand it is often granted only if the taxpayer posts a bond or other security equal to 210 percent of the final tax assessment. In the event we initiate an international arbitration, we may also seek to include the tax assessment as part of that proceeding.

The SENIAT may also be considering additional tax audits of operating companies such as Harvest Vinccler. Despite a four year statute of limitations on tax claims, in January 2006, the head of the SENIAT stated consideration was being given to extending the audits back to 1993.

At the current level of the tax assessment and considering possible interest and penalties, attachment of assets by the SENIAT, a determination of the need to take a charge against Harvest Vinccler’s earnings for the tax liability or a requirement to pay the taxes or post security will have a material adverse effect on Harvest Vinccler’s financial condition. A requirement to pay taxes, interest and penalties may exceed Harvest Vinccler’s cash balance. To the extent such events would cause the liabilities of Harvest Vinccler to exceed its assets, Harvest Vinccler would be insolvent. In addition, the implementation of a 50 percent tax rate or other changes in the interpretation or application of the tax laws, without compensating values, will have a material adverse effect on Harvest Vinccler’s financial position, results of operations or cash flows. We believe that these actions would not impact the cash or cash equivalent position of Harvest Natural Resources, Inc. or its other subsidiaries, which totaled $140.0 million at December 31, 2005.

We believe Harvest Vinccler has met its tax obligations in all material respects. We intend to take all measures necessary to protect Harvest Vinccler’s rights, and will vigorously challenge all elements of any tax assessment that are not supported by Venezuelan law.

The actions of the Venezuelan government may cause us to file for international arbitration. As a result of the actions taken by PDVSA, MEP and the SENIAT, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank. An arbitration proceeding may take a number of years to conclude and we can provide no assurances as to outcome. It is uncertain how the Venezuelan government might react to an arbitration filing, but it is possible it could lead to a shut down of Harvest Vinccler’s operations.

Harvest Vinccler may not be able to reach agreement on the terms of a mixed company and there is a risk any agreement will not receive the necessary approvals. We remain hopeful of reaching a mutually acceptable agreement with the government of Venezuela on converting the operating service agreement to a mixed company while preserving the value of our investment in Harvest Vinccler. We are actively engaged in discussions with government representatives and believe progress has been made. However, significant issues remain and it is not possible to give any assurances as to outcome. In addition, any agreement with PDVSA will require the approval of the Venezuelan National Assembly and of our shareholders. While no assurance can be provided, we believe these approvals would be obtained for any agreement supported by PDVSA, MEP, the SENIAT and us.

Our strategy to focus on Russia and other countries perceived to be politically challenging carries deal execution, operating, financial, legal and political risks. While we believe our established presence in countries perceived to be politically challenging and our experience and skills from prior operations position us well for future projects, doing business in Russia and other countries perceived to be politically challenging 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 local partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, the legal systems of these countries are not mature and their reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and natural gas projects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy 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 focus on countries perceived to be politically challenging limits our 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 countries perceived to be politically challenging 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.

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 has been 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 service fee payments from PDVSA for all revenue receipts. We do not own the hydrocarbons and do not sell oil and natural 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 has been considered a highly inflationary economy. Results of operations in highly inflationary countries 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 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 Bolivars. Most of our operating and capital expenditures are in U.S. Dollars. For a discussion of currency controls in Venezuela, see Capital Resources and Liquidity under Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations. Successful acquisition of projects in any international country 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 $24.02 per Bbl for the year ended December 31, 2005, compared with $18.90 per Bbl for the year ended December 31, 2004. 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 and oil consuming 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 natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural 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 natural 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 natural 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 2005 in the consolidated financial statements of the wholly-owned and majority owned subsidiaries. While our proved reserves were reduced by our Contractually Restricted Reserves as well as other revisions, this did not cause a ceiling limitation write down. Equity in Net Losses of Affiliated Companies includes a $32.3 million (our share) ceiling test write-down recorded by Geoilbent during their fiscal year 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. As a result of the actions of the Venezuelan Government, our Contractually Restricted Reserves have been excluded from our proved reserves. See Item 1 – Business, Operations.

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, the conversion of Harvest Vinccler’s interests to a mixed company in which it is a minority interest owner, 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.

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 natural 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 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 natural 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 are able to include Contractually Restricted Reserves, 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 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;

	•		delays in receipt of permits or access to lands; and

	•		government actions or changes in regulations.

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, national and independent oil and natural gas companies for the acquisition of desirable oil and natural 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 natural 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.

Item 1B. Unresolved Staff Comments

None

Item 2. Properties

In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month. Also during 2004, Harvest Vinccler leased office space in Maturin and Caracas, Venezuela for $13,200 and $4,000 per month, respectively. See also Item 1 – Business for a description of our oil and natural gas properties and reserves.

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. In October 2003, the Court 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.

The SENIAT Tax Assessment. On July 22, 2005, the SENIAT, the Venezuelan income tax authority, issued a preliminary tax assessment to Harvest Vinccler of 184 billion Venezuelan Bolivars related to fiscal years 2001 through 2004. At the official exchange rate of 2,150 Bolivars per U.S. Dollar, the dollar equivalent of the preliminary tax assessment is approximately $85 million. In addition, the SENIAT imposed penalties equal to 10 percent of the preliminary tax assessment claim for a total claim of 202 billion Bolivars, or approximately $94 million. Upon review of the preliminary tax assessment, we determined not to contest two elements of the claim and made payments totaling 11.3 billion Bolivars or $5.3 million in August and September, 2005. In September and October 2005, we filed a response and evidentiary support with the SENIAT contesting all other claims. We believe Harvest Vinccler has met its tax obligations in all material respects. We intend to take all measures necessary to protect our rights, and will vigorously challenge all elements of the tax assessment that are not supported by Venezuelan law.

International Arbitration. As a result of the actions taken by PDVSA, MEP and the SENIAT, in July 2005, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank.

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

None.

PART II


Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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, 2005, there were 36,986,643 shares of common stock outstanding, with approximately 683 stockholders of record. The following table sets forth the high and low sales prices for our Common Stock reported by the NYSE.


Year	Quarter	High		Low
2004	First quarter	$	14.25	$	9.48
	Second quarter		17.00		12.13
	Third quarter		16.60		11.54
	Fourth quarter		18.25		14.67

2005	First quarter		16.92		11.30
	Second quarter		12.48		8.13
	Third quarter		11.68		9.00
	Fourth quarter		10.81		8.57

On February 10, 2006, the last sales price for the common stock as reported by the NYSE was $8.47 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, 2005. 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 and 2001 reflect results from Geoilbent (until sold on September 25, 2003) for the twelve months ended September 30, 2003, 2002 and 2001, and from Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2001.


Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations

We had record financial performance in 2005. Net income for 2005 was $50.8 million compared with 2004 net income of $34.4 million. Net cash provided by operating activities was $114.7 million for 2005 compared with $74.1 million for 2004. Despite these results, our share price suffered significantly in 2005. We believe this decline was primarily a result of the situation in Venezuela and our lack of country asset risk diversification.

In Item 1 — Business and Item 1A — Risk Factors, we discuss the situation in Venezuela and how the actions of the Venezuelan government have and may continue to adversely affect our operations. We have also described how the uncertainty in Venezuela surrounding our ability to conduct future development programs has led to the reduction of our proved reserves by approximately 50 percent, and our estimated discounted future net cash flows from our proved reserves have been reduced by approximately 60 percent. Collectively, the events in Venezuela, both actual and threatened, are having a material adverse effect on our financial condition, results of operations and cash flows. The situation in Venezuela is also having an adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere.

We remain hopeful of reaching a mutually acceptable agreement with the government of Venezuela on converting our operating service agreement to a mixed company while preserving the value of our investment in Harvest Vinccler. The Transitory Agreement we executed in August 2005 provides a platform for our discussions with PDVSA, MEP and the SENIAT, and we are actively engaged with their representatives at a number of levels. We feel we have made progress and continue to work cooperatively with Venezuelan officials. However, until there is clarity and resolution to the situation, uncertainty over the future of our investment in Venezuela will continue to affect our performance. We will also consider alternatives to unlocking the underlying value of our Venezuelan assets for our shareholders. This may include a sale or exchange of all or part of our Venezuelan interests.

We recognize the need to diversify our asset base and that is the primary focus of our strategy. We have a strong balance sheet with $163 million of cash. We will use this cash to build a diversified portfolio of assets in a number of countries that fit our strategic investment criteria. We are pursuing opportunities in a number of areas including Russia, the Commonwealth of Independent States, the Middle East and Asia.

In executing our business strategy, we will strive to:

	•		maintain financial prudence and rigorous investment criteria;

	•		enhance access to capital markets;

	•		create a diversified portfolio of large assets;

	•		maximize cash flows from existing operations;

	•		use our experience, skills to acquire new projects; and

	•		keep our organizational capabilities in line with our rate of growth.

To accomplish our strategy, we intend to:

	•		Diversity our political risk: Acquire large oil and natural gas fields in a number of countries perceived to be politically challenging to diversify and reduce the overall political risk of our international investment portfolio.

	•		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 maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure.

	•		Limit Exploration Activities: While our strategy does not focus on unexplored areas, we will consider appropriate exploration opportunities that have large potential scale and the ability to manage risk without significant initial cost.

	•		Maintain A Prudent Financial Plan: We intend to maintain our financial flexibility by closely monitoring spending, holding sufficient cash reserves, actively seeking opportunities to reduce our weighted average cost of capital and increasing our debt capacity and liquidity.

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 investment in Geoilbent using the equity method. We included Geoilbent in our consolidated financial statements based on a fiscal year ending September 30. Our results of operations for the year ended December 31, 2003 reflect the results of Geoilbent (until sold on September 25, 2003).

You should read the following discussion of the results of operations for each of the years in the three-year period ended December 31, 2005 and the financial condition as of December 31, 2005 and 2004 in conjunction with our Consolidated Financial Statements and related Notes thereto.

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


	Years Ended December 31,
	2005			2004			2003
Operating Expenses		17	%		18	%		29	%
Depletion, Depreciation and Amortization		19			19			20
General and Administrative		10			12			15
Taxes Other Than on Income		3			3			3
Interest Expense		1			4			10

Years Ended 2005 and 2004

We reported net income of $50.8 million, or $1.32 diluted earnings per share, for 2005 compared with net income of $34.4 million, or $0.90 diluted earnings per share for 2004. Below is a discussion of revenues, price and volume variances.


	Year Ended							%
	December 31,				Increase			Increase
*(in millions)*	2005		2004		(Decrease)			(Decrease)			Increase
Revenues
Crude oil	$	210.5	$	154.1	$	56.4			37	%
Natural gas		26.4		32.0		(5.6	)		(18	)

Total Revenues	$	236.9	$	186.1	$	50.8			27	%


The following table reconciles the net change in revenue:

Price and Volume Variances
Crude oil price Variance (per Bbl)	$	24.02	$	18.90	$	5.12		27	%	$	41.6
Volume Variances
Crude oil volumes (MBbls)		8,763		8,152		611		7	%	$	14.7
Natural gas volumes (MMcf)		25,677		31,059		(5,382	)	(17	)		(5.5	)

Total volume variances										$	9.2

Revenue, Crude Oil Price Variance and Volume Variances

Revenues were higher in 2005 compared with 2004 due to increases in world crude oil prices and oil volumes as a result of our second half 2004 drilling program. Price variance is net of the cost of hedges in place during 2005. Natural gas delivery volumes have declined due to the refusal of MEP and PDVSA to issue permits for the drilling of new oil wells and the natural decline of associated natural gas from existing oil wells. Currently, all natural gas deliveries are associated with the Uracoa oil wells.

Total expenses and other non-operating (income) expense:


	Year Ended									%
	December 31,						Increase			Increase
	2005			2004			(Decrease)			(Decrease)
Operating expenses	$	39.7		$	33.3		$	6.4			19	%
Depletion and amortization		41.2			34.2			7.0			20
Depreciation		2.7			1.9			0.8			42
General and administrative		22.8			21.9			0.9			4
Account receivable write-off on retroactive oil price adjustment		4.5			—			4.5			—
Gain on sale of long-lived assets		—			(0.6	)		0.6			—
Bad debt recovery		—			(0.6	)		0.6			—
Taxes other than on income		6.4			5.6			0.8			14
Investment income and other		(4.2	)		(2.1	)		(2.1	)		100
Interest expense		3.4			7.7			(4.3	)		(56	)
Net (gain) loss on exchange rates		(2.8	)		0.6			(3.4	)		—

	$	113.7		$	101.9		$	11.8			12	%

Operating expenses increased as a result of higher oil volumes and maintenance work. Depletion and amortization expense per Boe produced during 2005 was $3.16 versus $2.56 in 2004. The increase was due to the exclusion of Contractually Restricted Reserves in our current proved reserves as well as other minor revisions. General and administrative expense increased primarily due to penalties accrued for the failure to withhold the prescribed amount of value added taxes from payments to vendors in Venezuela in 2005. Taxes other than on income increased due to increased Venezuelan municipal taxes which result from higher oil revenues.

The effective tax rate increased in 2005 to 46 percent from 41 percent in 2004 primarily due to the payment of $5.6 million related to the 2001 through 2004 preliminary tax assessment. Our tax calculations do not include the tax increases recently announced by the SENIAT (see Item 1A – Risk Factors).

Years Ended 2004 and 2003

We reported net income of $34.4 million, or $0.90 diluted earnings per share, for 2004 compared with net income of $27.3 million, or $0.74 diluted earnings per share, for 2003. Below is a discussion of revenues, price and volume variances.


	Year Ended						%
	December 31,				Increase		Increase
*(in millions)*	2004		2003		(Decrease)		(Decrease)			Increase
Revenues
Crude oil	$	154.1	$	103.4	$	50.7		49	%
Natural gas		32.0		2.7		29.3		100

Total Revenues	$	186.1	$	106.1	$	80.0		75	%


The following table reconciles the net change in revenue:

Price and Volume Variances
Crude oil price Variance (per Bbl)	$	18.90	$	14.07	$	4.83		34	%	$	35.5
Volume Variances
Crude oil volumes (MBbls)		8,152		7,347		805		11	%	$	15.2
Natural gas volumes (MMcf)		31,059		2,660		28,399		100			29.3

Total volume variances										$	44.5

Revenue, Crude Oil Price Variance and Volume Variances

Revenues were higher in the for 2004 compared to 2003 due to the addition of a full year of natural gas sales, higher oil volumes and higher crude oil prices. All natural gas deliveries are associated with the Uracoa oil wells.

Total expenses and other non-operating (income) expense:


	Year Ended									%
	December 31,						Increase			Increase
	2004			2003			(Decrease)			(Decrease)
Operating expenses	$	33.3		$	30.9		$	2.4			8	%
Depletion and amortization		34.2			19.6			14.6			74
Depreciation		1.9			1.6			0.3			19
Write-downs of oil and gas properties		—			0.2			(0.2	)		(100	)
General and administrative		21.9			15.7			6.2			39
Gain on sale of long-lived assets		(0.6	)		—			(0.6	)		—
Arbitration settlement		—			1.5			(1.5	)		(100	)
Bad debt recovery		(0.6	)		(0.4	)		(0.2	)		50
Taxes other than on income		5.6			3.4			2.2			65
Investment income and other		(2.1	)		(1.4	)		(0.7	)		50
Interest expense		7.7			10.4			(2.7	)		(26	)
Net (gain) loss on exchange rates		0.6			(0.5	)		1.1			(220	)

	$	101.9		$	81.0		$	20.9			26	%

Operating expenses increased primarily due to higher production volumes, higher workover and maintenance programs and increased insurance costs. Depletion and amortization expense per Boe produced during 2004 was $2.56 versus $2.52 during 2003. The increase was primarily due to increased future development costs. We recognized write-downs for additional capitalized costs associated with former exploration projects during 2003. General and administrative expenses increased for 2004 compared with 2003, 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 was recorded in 2003, and bad debt recoveries were recorded in 2004 and 2003, respectively, related to an allowance for uncollectible accounts in prior years. Taxes other than on income increased due to increased Venezuelan municipal taxes which result from higher oil and natural gas revenues.

Investment income and other increased due to higher interest rates earned on average cash balances. Interest expense decreased due to lower average outstanding debt balances from 2004 compared to 2003. In 2004, we redeemed all $85 million of our 9.375 percent senior unsecured notes due November 1, 2007 (“2007 Notes”), and we repaid all Bolivar denominated debt in March 2003.

Net gain (loss) on exchange rates decreased 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.

The effective tax rate increased in 2004 to 41 percent from 13 percent in 2003 primarily 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.

Equity in net losses of affiliated companies decreased during 2004 compared to 2003. This was due to the elimination of Geoilbent equity losses on September 25, 2003, the date of its sale.

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 Item 1A — Risk Factors). We require capital principally 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.

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 Bolivar and the U.S. Dollar and restrict the ability to exchange Bolivars for U.S. Dollars and vice versa. 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. Notwithstanding the provisions in our operating service agreement which requires all payments to be in U.S. Dollars, PDVSA paid 50 percent of our 2005 first quarter oil and natural gas sales in Bolivars. Subsequent quarterly payments for 2005 oil and natural gas sales were paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar; however, based on current levels of payments in Bolivars, Harvest Vinccler projects that it will be able to utilize its Bolivars to meet local currency obligations. 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.

Our ability to acquire and develop growth opportunities outside of Venezuela is dependent upon the ability of Harvest Vinccler to make loan repayments and dividends to us. However, there have been, and may again be, interruptions in oil and natural gas sales, changes in the amount, timing or currency of payments by PDVSA, or there may be contractual obligations or legal impediments to receiving dividends from Harvest Vinccler, which could affect the ability of Harvest Vinccler to remit funds to us.

Debt Reduction. We have quarterly principal and interest obligations of $1.3 and $0.3 million on the Harvest Vinccler variable rate loans. We have no other debt obligations.

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. The first quarter 2005 payment was nearly a month late and 50 percent was paid in Bolivars. Each subsequent quarter was paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar. As a consequence of the timing of the PDVSA payment inflows, our cash balances can increase and decrease dramatically during the year.

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:


	Year Ended December 31,
	(in thousands)
	2005			2004			2003
Net cash provided by operating activities	$	114,665		$	74,140		$	38,538
Net cash provided by (used in) investing activities		(15,647	)		(39,684	)		38,191
Net cash used in financing activities		(20,599	)		(88,516	)		(2,570	)

Net increase (decrease) in cash	$	78,419		$	(54,060	)	$	74,159

At December 31, 2005, we had current assets of $239.9 million and current liabilities of $61.8 million, resulting in working capital of $178.1 million and a current ratio of 3.9:1. This compares with a working capital of $89.0 million and a current ratio of 2.1:1 at December 31, 2004. The increase in working capital of $89.1 million was primarily due to higher oil sales prices and oil volumes in Venezuela in 2005 offset by the prepayment of the 2007 Notes in 2004.

Cash Flow from Operating Activities. During the years ended December 31, 2005 and 2004, net cash provided by operating activities was approximately $114.7 million and $74.1 million, respectively. The $40.6 million increase was primarily due to the increase in oil sales volumes and oil prices.

Cash Flow from Investing Activities. During the years ended December 31, 2005 and 2004, we had drilling, production-related and administrative capital expenditures of approximately $16.1 million and $39.1 million, respectively. The decrease in capital expenditures is due to completion of the drilling of an oil well and the gathering system and facilities for the South Monagas Unit carried over from 2004. Due to the actions of MEP and PDVSA, no further drilling activity was carried out in 2005.

On a year-to-year basis, the timing and size of capital expenditures for the South Monagas Unit are largely at our discretion, although recent actions by PDVSA have greatly limited our ability to make planned capital expenditures in 2005 and 2006, and could also limit us in the future. We suspended our drilling program in January 2005 because of the refusal of PDVSA and MEP to process and issue necessary permits to drill new wells. We continue to expend funds for workovers, maintenance, gathering systems and facility upgrades for the existing wells. Our remaining worldwide capital commitments 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 2005, Harvest Vinccler repaid $6.4 million of its U.S. Dollar denominated debt (four payments of $0.3 million and four payments of $1.3 million on the variable rate loans). During the year ended 2004, we irrevocably deposited with the Trustee as trust funds $85.0 million plus accrued interest through November 1, 2004 and prepayment call premium of $1.3 million to redeem our 2007 Notes on the redemption date. During the same period, Harvest Vinccler repaid $6.4 million of its U.S. Dollar debt.

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 has lease obligations for office space in Maturin and Caracas, Venezuela for $13,200 and $4,000 per month, respectively.


	Payments (in thousands) Due by Period
			Less than						After 4
Contractual Obligation	Total		1 Year		1-2 Years		3-4Years		Years
Long-Term Debt	$	5,467	$	5,467	$	—	$	—	$	—
Building Lease		2,749		449		407		400		1,493

Total	$	8,216	$	5,916	$	407	$	400	$	1,493

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 and quarterly interest payment obligations for the next 12 months. Our expectation is based upon our current estimate of projected prices, production levels, that there will be no disruptions or limitations on our production and that PDVSA will pay our invoices timely and primarily in U.S. Dollars. Actual results could be materially affected if there is a significant change in our expectations or assumptions (see Item 1A — 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.

As noted above under Capital Resources and Liquidity, Venezuela imposed currency exchange restrictions in February 2003, adjusted the official exchange rate in February 2004 and again in March 2005. 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 local transactions in Venezuela are conducted in Bolivars. 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, 2005, our net foreign exchange gain attributable to our international operations was $2.8 million. The U.S. Dollar and Bolivar exchange rates were adjusted in March 2005. No gains or losses were recognized from February 2004 to February 2005. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, many of which are beyond our control. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan currency to the U.S. Dollar. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.

Critical Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. The equity method of accounting is used for companies and other investments in which we have significant influence. All intercompany profits, transactions and balances have been eliminated. We accounted for our investment in Geoilbent, prior to its sale in September 2003, based on a fiscal year ending September 30.

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 natural 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. Our proved reserves at December 31, 2005 do not include Contractually Restricted Reserves. A large portion of our proved reserves base from consolidated operations is comprised of oil and natural 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 natural gas prices, existing economic conditions, contractual uncertainty, contract term and the corresponding adjustment to the projected economic life of such properties. Prices for oil and natural 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 natural gas properties under the full cost accounting rules of the SEC. These rules generally require that we price our future oil and natural gas production at the oil and natural 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 natural 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 natural gas prices decline significantly in the future, even if only for a short period of time, write-downs of our oil and natural gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities.

Income Taxes

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

Foreign Currency

Our current operations are in Venezuela. The U.S. Dollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in U.S. Dollars, and all currency gains or losses are recorded in the statement of operations. We attempt to manage our operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We have recognized significant exchange gains and losses in the past resulting from fluctuations in the relationship of the 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 March 2005, the Financial Accounting Standards Board (“FASB’) issued Staff Interpretation No. 46(R) — 5 Consolidation of Variable Interest Entities (“FSP FIN 46(R) — 5”), which addresses the consolidation of variable interest entities (“VIEs”) by business enterprises that are the primary beneficiaries. FSP FIN 46(R) — 5 is applicable to both nonpublic and public reporting enterprises. Application is required in financial statements for the first reporting period beginning after March 3, 2005 in accordance with the transition provisions of FSP FIN 46(R) — 5. The adoption of this interpretation will not impact our consolidated financial position, results of operations or cash flows.

In April 2005, the FASB issued Staff Interpretation No. 19-1 (“FSP 19-1”) Accounting for Suspended Well Costs, which provides guidance on the accounting for exploratory well costs and proposes an amendment to FASB Statement No. 19 (“FASB 19”), Financial Accounting and Reporting by Oil and Gas Producing Companies. The guidance in FSP 19-1 applies to enterprises that use the successful efforts method of accounting as described in FASB 19. The guidance in FSP 19-1 will not impact our consolidated financial position, results of operations or cash flows.

In June 2005, the Financial Accounting Standards Board (“FASB’) issued Statement of Financial Accounting Standard 154 – Accounting Changes and Error Corrections (“SFAS 154”), which changes the requirements for the accounting for and reporting of a change in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. Application is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Early adoption is permitted. The adoption of SFAS 154 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.

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. 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. Currently, there are no hedging transactions in place for our 2006 production.

Interest Rates

Total short-term debt at December 31, 2005 of $5.5 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

Under the provisions of our operating service agreement, payments for oil and natural gas sales in Venezuela are to be received in U.S. Dollars. Expenditures are both in U.S. Dollars and Bolivars. For first quarter 2005 oil and natural gas deliveries, Harvest Vinccler was paid 50 percent in Bolivars, and each subsequent quarter

was paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar. We have utilized no currency hedging programs to mitigate any risks associated with operations in Venezuela, and therefore our financial results are subject to favorable or unfavorable fluctuations in exchange rates and inflation in that country. 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-30.


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.

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, 2005, 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, 2005. 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, 2005, and issued an attestation report which is included herein.

Item 9B. Other Information

None.

PART IV

Item 15. Exhibits and Financial Statement Schedules


	Page
(a) 1. Index to Financial Statements:
Report of Independent Registered Public Accounting Firm		S-1

Consolidated Balance Sheets at December 31, 2005 and 2004		S-2

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003		S-3

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2005, 2004 and 2003		S-4

Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		S-5

Notes to Consolidated Financial Statements		S-7

2.		Consolidated Financial Statement Schedules and Other:

		Schedule II — Valuation and Qualifying Accounts

		Financial Statements and Notes for LLC Geoilbent, a significant equity investment

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

3.		Exhibits:

	3.1		Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1(i) to our Form 10-Q filed on August 13, 2002, File No. 1-10762.)

	3.2		Amended and Restated Bylaws as of May 19, 2005. (Incorporated by reference to Exhibit 3.2 to our Form 10-Q filed on April 29, 2005, File No. 1-10762.)

	4.1		Form of Common Stock Certificate. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-26333).)

	4.2		Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.)

	4.3		Second Amended and Restated Rights Agreement, dated as of April 15, 2005, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.3 to our Form 10-Q filed on April 29, 2005, File No. 1-10762.)

	10.1		Operating Service Agreement between Benton Oil and Gas Company and Lagoven, S.A., which has been subsequently combined into PDVSA Petroleo y Gas, S.A., dated July 31, 1992, (portions have been omitted pursuant to Rule 406 promulgated under the Securities Act of 1933 and filed separately with the Securities and Exchange Commission. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-52436).)

	10.2		Note Payable Agreement dated March 8, 2001 between Harvest Vinccler, C.A. and Banco Mercantil, C.A. related to a note in the principal amount of $6,000,000 with interest at LIBOR plus five percent, for financing of Tucupita Pipeline. (Incorporated by reference to Exhibit 10.24 to our Form 10-Q, filed on May 15, 2001, File No. 1-10762.)

	10.3		Alexander E. Benton Settlement and Release Agreement effective May 11, 2001 (Incorporated by reference to Exhibit 10.27 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.).

	10.4		Sale and Purchase Agreement dated February 27, 2002 between Benton Oil and Gas Company and Sequential Holdings Russian Investors Limited regarding the sale of Benton Oil and Gas Company’s 68 percent interest in Arctic Gas Company. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on March 28, 2002, File No. 1-10762.)

	10.5		2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our S-8 (Registration Statement No. 333-85900).)

	10.6		Addendum No. 2 to Operating Service Agreement Monagas SUR dated 19^th September, 2002. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)

	10.7		Bank Loan Agreement between Banco Mercantil, C.A. and Harvest Vinccler C.A. dated October 1, 2002. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)

	10.8		Guaranty issued by Harvest Natural Resources, Inc. dated September 26, 2002. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)

	10.9^†		Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.13 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)

	10.10		Sale and Purchase Agreement dated September 26, 2003, between Harvest Natural Resources, Inc. and Yukos Operational Holding Limited regarding the sale of our 34 percent minority equity investment in LLC Geoilbent. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 10, 2003, File No. 1-10762.)

	10.11^†		Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).)

	10.12^†		Indemnification Agreement between Harvest Natural Resources, Inc. and the Directors and Executive Officers of the Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)

	10.13^†		Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)

	10.14^†		Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)

	10.15^†		Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.22 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)

	10.16		The Transitory Agreement between Harvest Natural Resources, Inc. and PDVSA Petroleo S.A., dated August 4, 2005. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.17^†		Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.18^†		Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.19^†		Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.20^†		Employment Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.21^†		Employment Agreement dated September 26, 2005 between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.22^†		Separation Agreement dated September 30, 2005, between Harvest Natural Resources, Inc. and Dr. Peter J. Hill. (Incorporated by reference to Exhibit 10.7 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.23^†		Consulting Agreement dated October 1, 2005, between Harvest Natural Resources, Inc. and Dr. Peter J. Hill. (Incorporated by reference to Exhibit 10.8 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.24^†		Stock Options Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston.

	10.25^†		Stock Options Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston.

	10.26^†		Stock Options Agreement dated September 26, 2005 between Harvest Natural Resources, Inc. and Byron A. Dunn.

	21.1		List of subsidiaries.

	23.1		Consent of PricewaterhouseCoopers LLP — Houston

	23.2		Consent of ZAO PricewaterhouseCoopers Audit — Moscow

	23.3		Consent of Ryder Scott Company, LP

	31.1		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 executed by James A. Edmiston, President and Chief Executive Officer.

	31.2		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer.

	32.1		Certification accompanying Annual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 executed by James A. Edmiston, President and Chief Executive Officer.

	32.2		Certification accompanying Annual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer.


^†		Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K.

Report of Independent Registered Public Accounting Firm

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

We have completed integrated audits of Harvest Natural Resources, Inc.’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its December 31, 2003 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, 2005 and December 31, 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule 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. Also as discussed in Note 1 to the consolidated financial statements, the Company’s total consolidated revenues relate to operations in Venezuela. As discussed in Note 3 SENIAT, the Venezuelan income tax authority has presented the Company’s Venezuelan subsidiary with preliminary tax assessments for the years 2001 through 2004 totaling approximately USD 94 million (Bolivars 202 billion), including penalties and interest. As discussed in Note 8 the Venezuelan subsidiary has also signed a Transitory Agreement with Petroleos de Venezuela S.A. (PDVSA) which obligates the parties to negotiate in good faith the conversion of the Subsidiary’s Operating Service Agreement to a Mixed Company under the Venezuelan Organic Hydrocarbon Law.

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, 2005 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, 2005, 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 27, 2006

S-1

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2005			2004
	*(in thousands, except per*
	*share data)*
ASSETS

Current Assets:
Cash and cash equivalents	$	163,019		$	84,600
Restricted cash		—			12
Accounts and notes receivable:
Accrued oil and gas sales		60,900			58,937
Joint interest and other, net		10,750			12,780
Put options		—			14,209
Deferred income tax		3,052			251
Prepaid expenses and other		2,149			1,426

Total Current Assets		239,870			172,215
Restricted Cash		—			16
Other Assets		1,600			2,072
Deferred Income Taxes		—			6,034
Property and Equipment:
Oil and gas properties (full cost method-costs of $2,900 excluded from amortization in 2005 and 2004, respectively)		641,684			631,082
Other administrative property		9,568			10,008

		651,252			641,090

Accumulated depletion, depreciation, and amortization		(491,924	)		(453,941	)

Net Property and Equipment		159,328			187,149

	$	400,798		$	367,486


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable, trade and other	$	408		$	8,428
Accounts payable, related party		9,203			11,063
Accrued expenses		21,081			29,426
Deferred revenue		6,728			—
Income taxes payable		18,909			22,475
Current portion of long-term debt		5,467			11,833

Total Current Liabilities		61,796			83,225
Long-Term Debt		—			—
Asset Retirement Liability		2,129			1,941
Commitments and Contingencies		—			—
Minority Interest		39,361			39,131
Stockholders’ Equity:
Preferred stock, par value $0.01 a share; Authorized 5,000 shares; outstanding, none Common stock, par value $0.01 a share; Authorized 80,000 shares at December 31, 2005 and 2004; issued 37,757 shares and 37,544 shares at December 31, 2005 and 2004, respectively		378			375
Additional paid-in capital		188,242			185,183
Retained earnings		112,736			61,897
Accumulated other comprehensive loss		—			(487	)
Treasury stock, at cost, 770 shares and 764 shares at December 31, 2005 and 2004, respectively		(3,844	)		(3,779	)

Total Stockholders’ Equity		297,512			243,189

	$	400,798		$	367,486

See accompanying notes to consolidated financial statements.

S-2

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME


	Years Ended December 31,
	2005			2004			2003
	*(in thousands, except per share data)*
Revenues
Oil sales	$	210,493		$	154,075		$	103,920
Gas sales		26,448			31,991			2,740
Ineffective hedge activity		—			—			(565	)

		236,941			186,066			106,095


Expenses
Operating expenses		39,723			33,324			30,893
Depletion, depreciation and amortization		43,968			36,020			21,188
Write-downs of oil and gas properties and impairments		—			—			165
General and administrative		22,819			21,857			15,746
Account receivable write-off on retroactive oil price adjustments		4,548			—			—
Arbitration settlement		—			—			1,477
Bad debt recovery		—			(598	)		(374	)
Gain on sale of long-lived asset		—			(578	)		—
Taxes other than on income		6,358			5,561			3,373

		117,416			95,586			72,468


Income from Operations		119,525			90,480			33,627
Other Non-Operating Income (Expense)
Gain on disposition of investment		—			—			46,619
Gain (loss) on early extinguishment of debt		—			(2,928	)		—
Investment earnings and other		4,205			2,085			1,418
Interest expense		(3,388	)		(7,749	)		(10,405	)
Net gain (loss) on exchange rates		2,752			(622	)		529

		3,569			(9,214	)		38,161


Income from Consolidated Companies Before Income Taxes and Minority Interest		123,094			81,266			71,788
Income Tax Expense		57,025			33,288			9,657

Income Before Minority Interest		66,069			47,978			62,131
Minority Interest in Consolidated Subsidiary Companies		15,230			13,618			5,968

Income from Consolidated Companies		50,839			34,360			56,163
Equity in Net Losses of Affiliated Company		—			—			(28,860	)

Net Income	$	50,839		$	34,360		$	27,303


Net Income Per Common Share:
Basic	$	1.38		$	0.95		$	0.77

Diluted	$	1.32		$	0.90		$	0.74


Other comprehensive loss:
Unrealized mark to market loss from cash flow hedging activities, net of tax		—			(487	)		—

Comprehensive income	$	50,839		$	33,873		$	27,303

See accompanying notes to consolidated financial statements.

S-3

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)


									Accumulated
	Common				Additional				Other
	Shares		Common		Paid-in		Retained		Comprehensive			Treasury
	Issued		Stock		Capital		Earnings		Gain(Loss)			Stock			Total
Balance at January 1, 2003		35,900	$	359	$	173,559	$	234	$	—		$	(2,835	)	$	171,317

Issuance of common shares:
Exercise of stock options		505		5		1,196		—		—			—			1,201
Employee stock based compensation		—		—		296		—		—			—			296
Treasury stock (80 shares)		—		—		—		—		—			(404	)		(404	)
Net Income		—		—		—		27,303		—			—			27,303


Balance at December 31, 2003		36,405		364		175,051		27,537		—			(3,239	)		199,713

Issuance of common shares:
Exercise of warrants		53		—		600		—		—			—			600
Exercise of stock options		1,001		10		7,381		—		—			—			7,391
Employee stock-based compensation		85		1		2,151		—		—			—			2,152
Treasury stock (34 shares)		—		—		—		—		—			(540	)		(540	)
Accumulated other comprehensive loss		—		—		—		—		(487	)		—			(487	)
Net Income		—		—		—		34,360		—			—			34,360


Balance at December 31, 2004		37,544		375		185,183		61,897		(487	)		(3,779	)		243,189

Issuance of common shares:
Exercise of stock options		240		3		829		—		—			—			832
Employee stock-based compensation		74		—		2,230		—		—			—			2,230
Treasury stock (5 shares)		—		—		—		—		—			(65	)		(65	)
Accumulated other comprehensive gain		—		—		—		—		487			—			487
Net Income		—		—		—		50,839		—			—			50,839


Balance at December 31, 2005		37,858	$	378	$	188,242	$	112,736	$	—		$	(3,844	)	$	297,512

See accompanying notes to consolidated financial statements.

S-4

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)


	Years Ended December 31,
	2005			2004			2003
				*(in thousands)*
Cash Flows From Operating Activities:
Net income	$	50,839		$	34,360		$	27,303
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		43,968			36,020			21,188
Write-down of oil and gas properties and impairment		—			—			165
Amortization of financing costs		—			228			497
Gain on disposition of assets and investments		—			(578	)		(46,619	)
Write off of unamortized financing costs		—			936			—
Account receivable write-off on retroactive oil price adjustments		4,548			—			—
Equity in net losses of affiliated companies		—			—			28,860
Allowance for employee notes and accounts receivable		—			(598	)		(169	)
Deferred compensation expense		(745	)		1,521			306
Non-cash compensation related charges		2,230			2,152			296
Minority interest in consolidated subsidiary companies		15,230			13,618			5,968
Deferred income taxes		2,982			(1,285	)		(667	)
Changes in operating assets and liabilities:
Accounts and notes receivable		(4,481	)		(27,156	)		(7,935	)
Prepaid expenses and other		(723	)		(621	)		2,164
Commodity hedging contract		14,947			(14,947	)		(430	)
Accounts payable		(8,020	)		4,265			359
Accounts payable, related party		(1,860	)		506			4,408
Accrued expenses		(7,600	)		11,409			(382	)
Deferred revenue		6,728			—			—
Asset retirement liability		188			482			1,459
Income taxes payable		(3,566	)		13,828			1,767

Net Cash Provided by Operating Activities		114,665			74,140			38,538

Cash Flows from Investing Activities:
Proceeds from sale of investment		—			—			69,500
Proceeds from sale of long-lived assets		—			578			—
Additions of property and equipment		(16,147	)		(39,106	)		(60,925	)
Investment in and advances to affiliated companies		—			—			2,328
Decrease in restricted cash		28			—			1,800
Purchases of marketable securities		—			—			(256,058	)
Maturities of marketable securities		—			—			283,446
Investment costs		472			(1,156	)		(1,900	)

Net Cash Provided by (Used In) Investing Activities		(15,647	)		(39,684	)		38,191

Cash Flows from Financing Activities:
Net proceeds from issuances of common stock		767			7,451			1,201
Purchase of treasury stock		—			—			(404	)
Payments of note payable		(6,366	)		(91,367	)		(3,367	)
Dividend paid to minority interest		(15,000	)		(4,600	)		—

Net Cash Used In Financing Activities		(20,599	)		(88,516	)		(2,570	)

Net Increase (Decrease) in Cash and Cash Equivalents		78,419			(54,060	)		74,159
Cash and Cash Equivalents at Beginning of Year		84,600			138,660			64,501

Cash and Cash Equivalents at End of Year	$	163,019		$	84,600		$	138,660

Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for interest expense	$	795		$	12,541		$	13,241

Cash paid during the year for income taxes	$	20,991		$	11,705		$	4,254

See accompanying notes to consolidated financial statements.

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Supplemental Schedule of Noncash Investing and Financing Activities:

During the year ended 2005, we issued 0.1 million shares of restricted stock valued at $0.8 million and Dr. Peter J. Hill, our former Chief Executive Officer, elected to pay withholding tax on a 2002 restricted stock grant on a cashless basis. This resulted in 5,497 shares being held as treasury stock at cost.

During the year ended 2004, we issued 0.1 million shares of restricted stock valued at $1.2 million and we wrote-off $0.9 million of unamortized debt financing costs in connection with the redemption and discharge of the 9.375 percent senior unsecured notes due November 1, 2007 (“2007 Notes”). Also during the year ended 2004, the holders of our warrants elected to exercise 45,000 warrants on a cashless basis by delivering Company shares to us. This resulted in the issuance of 34,054 shares which are held as treasury stock at cost.

For the year ended 2003, we recorded an allowance for doubtful accounts related to interest accrued on an account receivable owed to us by a former employee. During the years ended 2004 and 2003, we reversed a portion of such allowance as a result of our collection of certain amounts owed to us including the portions of the note secured by our stock and other properties.

See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Note 1 — Organization and Summary of Significant Accounting Policies

Organization

Harvest Natural Resources, Inc. is engaged in the exploration, development, production and management of oil and natural gas properties. We conduct our business principally in Venezuela through our 80 percent-owned subsidiary Harvest Vinccler C.A. (“Harvest Vinccler”).

Principles of Consolidation

The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. The equity method of accounting is used for companies and other investments in which we have significant influence. All intercompany profits, transactions and balances have been eliminated. We accounted for our investment in LLC Geoilbent (“Geoilbent”), prior to the sale of our interest, based on a fiscal year ending September 30.

Reporting and Functional Currency

The U.S. Dollar is our functional and reporting currency.

Revenue Recognition

Oil and natural gas revenue is accrued monthly based on production and delivery. Each quarter, Harvest Vinccler invoices PDVSA Petroleo S.A., an affiliate of Petroleos de Venezuela S.A. (“PDVSA”), based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. Dollar contract service fees per barrel. The related Operating Service Agreement (“OSA”) with PDVSA provides for Harvest Vinccler to receive an operating fee for each barrel of crude oil delivered and the right to receive a capital recovery fee for certain of its capital expenditures, provided that such operating fee and capital recovery fee cannot exceed the maximum total fee per barrel set forth in the agreement. In August 2005, Harvest Vinccler and PDVSA executed a Transitory Agreement (the “Transitory Agreement”) which provides that the maximum total fee per barrel paid under the OSA could not exceed 66.67 percent of the total value of the crude oil as determined under an Annex to the Transitory Agreement. This limitation was applied retroactively to January 1, 2005 and approximates 47 percent of West Texas Intermediate (“WTI”). The operating fee is subject to quarterly adjustments to reflect changes in the special energy index of the U.S. Consumer Price Index. Each quarter, Harvest Vinccler also invoices PDVSA for natural gas sales based on a fixed price of $1.03 per Mcf. In addition, Harvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the natural gas production (“Incremental Crude Oil”). A portion of the Incremental Crude Oil is invoiced to PDVSA quarterly at a fixed price of $7.00 per Bbl. The invoices are prepared and submitted to PDVSA by the end of the first month following the end of each calendar quarter, and payment is due from PDVSA by the end of the second month following the end of each calendar quarter. Harvest Vinccler invoiced PDVSA for the first and second quarters of 2005 for the delivery of its crude oil and natural gas in accordance with the original OSA terms and recognized its revenue in a manner consistent with prior periods. The retroactive application of the new maximum total fee limitation under the Transitory Agreement resulted in a write-off of $4.5 million of the PDVSA receivable in the third quarter 2005. All oil and natural gas revenues are now recorded based on the Transitory Agreement. However, Harvest Vinccler recorded deferred revenue of $6.7 million pending clarification on the calculation of crude prices under the Transitory Agreement.

Cash and Cash Equivalents

Cash equivalents include money market funds and short term certificates of deposit with original maturity dates of less than three months. At December 31, 2005, Harvest Vinccler had 45.5 billion Venezuela Bolivars (“Bolivars”) which are shown in the December 31, 2005 financial statements as $21.2 million in cash and cash equivalents. Harvest Vinccler expects to be able to utilize the Bolivars received to date. However, to the extent that Harvest Vinccler receives additional Bolivars in excess of its internal needs, there may be limited means to convert excess Bolivars into U.S. Dollars or other foreign currencies, and there would be a loss on any conversion where the exchange rate is above the official rate of 2,150 Bolivars to the U.S. Dollar.

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Credit Risk and Operations

All of our total consolidated revenues relate to operations in Venezuela. During the years ended December 31, 2005 and 2004, our Venezuelan crude oil and natural gas production represented all of our total production from consolidated companies, and our sole source of revenues related to such Venezuelan production is PDVSA, which maintains full ownership of all hydrocarbons in its fields. In February 2003, the Venezuelan Government implemented currency exchange controls aimed at restricting the convertibility of the Bolivar and the transfer of funds out of Venezuela. The current official exchange rate is 2,150 Bolivars for each U.S. Dollar. We believe that we have sufficient cash and do not expect the currency conversion restrictions to adversely affect our ability to meet our short-term obligations and operating requirements for the next twelve months.

Derivatives and Hedging

Statement of Financial Accounting Standards No. 133 (“SFAS 133”), as amended, establishes accounting and reporting standards for derivative instruments and hedging activities. All derivatives are recorded on the balance sheet at fair value. To the extent that the hedge is determined to be effective, changes in the fair value of derivatives for qualifying cash flow hedges are recorded each period in other comprehensive income. Our derivatives have been designated as cash flow hedge transactions in which we hedge the variability of cash flows related to future oil prices for some or all of our forecasted oil production. The changes in the fair value of these derivative instruments have been reported in other comprehensive income because the highly effective test was met, and have been reclassified to earnings in the period in which earnings were impacted by the variability of the cash flows of the hedged item.

Harvest Vinccler hedged a portion of its 2003 oil sales by purchasing a WTI crude oil put option to protect its 2003 cash flow. The put was for 10,000 barrels of oil per day for the period of March 1, 2003 through December 31, 2003. Due to the pricing structure for our Venezuela oil, the put had the economic effect of hedging approximately 20,800 barrels of oil per day. The put cost was $2.50 per barrel, or $7.7 million, and had a strike price of $30.00 per barrel. The notional amount of the financial instrument was based on expected sales of crude oil production from existing and future development wells.

We had no hedging instruments in place for our 2004 production. In August 2004, Harvest Vinccler hedged a portion of its oil sales for calendar year 2005 by purchasing a WTI crude oil put for 5,000 barrels of oil per day. The put cost was $4.24 per barrel, or $7.7 million, and had a strike price of $40.00 per barrel. In September 2004, Harvest Vinccler hedged an additional portion of its calendar year 2005 oil sales by purchasing a second WTI crude oil put for 5,000 barrels of oil per day. The put cost was $3.95 per barrel, or $7.2 million, and had a strike price of $44.40 per barrel. Due to the amended pricing structure as revised by the Transitory Agreement for our Venezuelan oil, these two puts had the economic effect of hedging approximately 21,500 barrels of oil per day for an average of $17.72 per barrel. These puts qualify under the highly effective test and the mark-to-market loss at December 31, 2004 is included in other comprehensive loss.

At December 31, 2004, Accumulated Other Comprehensive Loss consisted of $0.7 million ($0.5 million net of tax) of unrealized losses on our crude oil puts. Oil sales for the year ended 2004 included no losses in settlement of the puts. Oil sales for the year ended 2003 included settlements of $1.7 million as well as the amortization of the put option cost of $7.7 million. Deferred net losses recorded in Accumulated Other Comprehensive Loss at December 31, 2004 were reclassified to earnings during 2005. All hedging instruments expired under their own terms on December 31, 2005.

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

Asset Retirement Liability

Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”) requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. No wells were abandoned in the year ended December 31, 2005 and nine wells were abandoned in year ended December 31, 2004. Changes in asset retirement obligations during the years ended December 31, 2005 and 2004 were as follows:

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	December 31,			December 31,
	2005			2004
Asset retirement obligations beginning of period	$	1,941		$	1,459
Liabilities recorded during the period		96			1,454
Liabilities settled during the period		—			(540	)
Revisions in estimated cash flows		(17	)		(470	)
Accretion expense		109			38

Asset retirement obligations end of period	$	2,129		$	1,941

Accounts and Notes Receivable

Allowance for doubtful accounts related to former employee notes at December 31, 2005 and 2004 was $2.8 million. During 2004, we received $0.5 million through the exercise of stock options and $0.1 million through the excess income provision of a settlement and release agreement.

Other Assets

Other assets consist of investigative costs associated with new projects. New project costs are reclassified to oil and natural gas properties or expensed depending on management’s assessment of the likely outcome of the project.

Property and Equipment

We follow the full cost method of accounting for oil and natural gas properties with costs accumulated in cost centers on a country-by-country basis, subject to a cost center ceiling (as defined by the Securities and Exchange Commission [“SEC”]). All costs associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized as incurred. Only overhead that is directly identified with acquisition, exploration or development activities are capitalized. All costs related to production, general corporate overhead and similar activities are expensed as incurred.

The costs of unproved properties are excluded from amortization until the properties are evaluated. At least quarterly we evaluate our unproved properties on a country by country basis for possible impairment. If we abandon all exploration efforts in a country where no proved reserves are assigned, all exploration and acquisition costs associated with the country are expensed. During 2003, we recognized $0.2 million in impairments associated with the China WAB-21 block. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty.

Excluded costs at December 31, 2005 consisted of property acquisition costs in the amount of $2.9 million which were all incurred prior to 2001. All of the excluded costs at December 31, 2005 relate to the acquisition of Benton Offshore China Company and exploration related to its WAB-21 property. The ultimate timing of when the costs related to the acquisition of Benton Offshore China Company will be included in amortizable costs is uncertain.

All capitalized costs (including oilfield inventory and future abandonment costs under SFAS 143) and estimated future development costs of proved reserves are depleted using the units of production method based on the total proved reserves of the country cost center. Depletion expense, which was substantially all attributable to the Venezuelan cost center for the years ended December 31, 2005, 2004 and 2003 was $41.2 million, $34.1 million and $19.6 million ($3.16, $2.56 and $2.52 per equivalent barrel), respectively.

A gain or loss is recognized on the sale of oil and natural gas properties only when the sale involves a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved property.

Depreciation of furniture and fixtures is computed using the straight-line method with depreciation rates based upon the estimated useful life of the property, generally 5 years. Leasehold improvements are depreciated

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over the life of the applicable lease. Depreciation expense was $2.8 million, $1.9 million and $1.6 million for the years ended December 31, 2005, 2004 and 2003, respectively.

The major components of property and equipment at December 31 are as follows (in thousands):


	2005			2004
Proved property costs	$	630,634		$	621,679
Costs excluded from amortization		2,900			2,900
Oilfield inventories		8,150			6,503
Other administrative property		9,568			10,008

		651,252			641,090
Accumulated depletion, impairment and depreciation		(491,924	)		(453,941	)

	$	159,328		$	187,149

We perform a quarterly cost center ceiling test of our oil and natural gas properties under the full cost accounting rules of the SEC. The consolidated financial statements of the wholly-owned and majority owned subsidiaries do not include ceiling test write-downs in 2005 or 2004.

Stock-Based Compensation

At December 31, 2005 and 2004, we had several stock-based employee compensation plans, which are more fully described in Note 5 – Stock Option and Stock Purchase Plans. Prior to 2003, we accounted for those plans under the recognition and measurement provisions of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Effective January 1, 2003, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards Statement No. 123 (“FAS 123”), Accounting for Stock-Based Compensation as amended by Statement of Financial accounting Standards No. 148 (“SFAS 148”), prospectively to all employee awards granted, modified, or settled after January 1, 2003. Effective January 1, 2005, we adopted Statement of Financial Accounting Standard 123 (revised 2004) Share-Based Payment (“SFAS 123R”) to all employee awards granted, modified, or settled after October 1, 2005. The effect of adopting SFAS 123R was not material. Awards under our plans vest in periodic installments after one year of their grant and expire ten years from grant date. Therefore, the costs related to stock-based employee compensation included in the determination of net income in the years ended December 31, 2005 and 2004 are less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of FAS 123. The following table illustrates the effect on net income and earnings per share if the fair value based method had been applied to all outstanding and unvested awards in each period.


	2005			2004			2003
Net income, as reported	$	50,839		$	34,360		$	27,303

Add: Stock-based employee compensation cost, net of tax		2,635			999			296

Less: Total stock-based employee compensation cost determined under fair value based method, net of tax		(2,711	)		(1,382	)		(1,056	)


Net income – proforma	$	50,763		$	33,977		$	26,543

Net income per common share:
Basic – as reported	$	1.38		$	0.95		$	0.77

Basic – proforma	$	1.37		$	0.94		$	0.75


Diluted – as reported	$	1.32		$	0.90		$	0.74

Diluted – proforma	$	1.32		$	0.89		$	0.72

Stock options of 0.2 million, 1.1 million and 0.5 million were exercised in the years ended December 31, 2005, 2004 and 2003, respectively, with cash proceeds of $0.8 million, $8.0 million and $1.2 million, respectively.

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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 carryforwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

Foreign Currency

We have significant operations outside of the United States, principally in Venezuela and, until September 25, 2003, a minority equity investment in Russia. The U.S. 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 a manner to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan currency to the U.S. Dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates.

Financial Instruments

Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. Cash and cash equivalents are placed with commercial banks with high credit ratings. This diversified investment policy limits our exposure both to credit risk and to concentrations of credit risk. Accounts receivable result from oil and natural gas exploration and production activities and our customers and partners are engaged in the oil and natural gas business. PDVSA pays for 100 percent of our Venezuelan oil and natural gas production under the terms of the operating service agreement and the Transitory Agreement. Although we do not currently foresee a credit risk associated with these receivables, collection is dependent upon the financial stability of PDVSA.

Comprehensive Income

Statement of Financial Accounting Standards No. 130 (“SFAS 130”) requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. We reflected unrealized mark-to-market losses from cash flow hedging activities as other comprehensive loss during the year ended December 31, 2004 and in accordance with SFAS 130, have provided a separate line in the audited consolidated statement of operations and comprehensive income.

Minority Interests

We record a minority interest attributable to the minority shareholder of our Venezuela and Barbados subsidiaries. The minority interests in net income and losses are generally subtracted from or added to arrive at consolidated net income.

New Accounting Pronouncements

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guidance in FSP 19-1 applies to enterprises that use the successful efforts method of accounting as described in FASB 19. The guidance in FSP 19-1 will not impact our consolidated financial position, results of operations or cash flows.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, plant products and natural gas reserve volumes and the future development costs. Actual results could differ from those estimates.

Reclassifications

Certain items in 2003 and 2004 have been reclassified to conform to the 2005 financial statement presentation.

Note 2 — Long-Term Debt and Liquidity

Long-Term Debt

Long-term debt consists of the following (in thousands):


	December 31,		December 31,
	2005		2004
Note payable with interest at 9.0%
See description below	$	300	$	1,500
Note payable with interest at 10.1%		5,167		10,333

		5,467		11,833
Less current portion		5,467		11,833

	$	—	$	—

Our 2007 Notes were redeemed on November 1, 2004, and we were released from all obligations. The redemption of the 2007 Notes triggered an obligation under the terms of Harvest Vinccler’s U.S. Dollar loans from a Venezuelan commercial bank to renegotiate the terms of those loans or, if agreement on renegotiated terms could not be reached within 30 days after November 1, 2004, the loans could be declared due and payable. As a result, the entire amount has been reclassified from long term to current debt. It is possible that agreement will not be reached in negotiated terms and Harvest Vinccler will be required to repay the remaining December 31, 2005 balance of $5.5 million.

In March 2001, Harvest Vinccler borrowed $12.3 million from a Venezuelan commercial bank, for construction of an oil pipeline. The loan is in two parts, with the first part in an original principal amount of $6.0 million that bears interest payable monthly based on 90-day London Interbank Borrowing Rate (“LIBOR”) plus 5 percent with principal payable quarterly for five years. The second part, in the original principal amount of 4.4 billion Venezuelan Bolivars (“Bolivars”) (approximately $6.3 million) was repaid as of March 31, 2003. The loans provide for certain limitations on mergers and sale of assets. We have guaranteed the repayment of the remaining loan.

In October 2002, Harvest Vinccler executed a note and borrowed $15.5 million to fund construction of a gas pipeline and related facilities to deliver natural gas from the Uracoa field to a PDVSA pipeline. The interest rate

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for this loan is 90-day LIBOR plus 6 percentage points. The term is four years with a quarterly amortization of $1.3 million beginning with the first quarter 2004 to coincide with the first payment from our natural gas sales.

We have classified all of our outstanding debt as current at December 31, 2005.

Note 3 — Commitments and Contingencies

We have employment contracts with six executive officers which provide for annual base salaries, eligibility for bonus compensation and various benefits. The contracts provide for a lump sum payment as a multiple of base salary in the event of termination of employment without cause. In addition, these contracts provide for payments as a multiple of base salary and bonus, excise tax reimbursement and a continuation of benefits in the event of termination without cause following a change in control. By providing one year notice, these agreements may be terminated by either party on May 31, 2006 for five of the executives and on May 7, 2007 for the other executive.

In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month. Also during 2004, Harvest Vinccler leased 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, all of which was subleased for rents that approximated our lease costs.

Libertador Municipality Tax Assessment. In April 2005, Harvest Vinccler received a tax assessment from a tax inspector for the Libertador municipality in which part of the South Monagas Unit is located. Harvest Vinccler has submitted a protest to the assessment at the Mayor’s Office, and if no favorable resolution is obtained, it will file a motion with the tax court seeking to enjoin the payment order and dismiss the assessment. We dispute the allegations set forth in the assessment and believe we have a substantial basis for our position. We are unable to estimate the amount or range of any possible loss.

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We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such litigation which will have a material adverse impact on our financial condition, results of operations and cash flows.

Note 4 — Taxes

Taxes Other Than on Income

Harvest Vinccler pays municipal taxes on operating fee revenues it receives for production from the South Monagas Unit. The components of taxes other than on income were (in thousands):


	2005			2004		2003
Venezuelan municipal taxes	$	5,788		$	4,485	$	2,741
Franchise taxes		(70	)		464		341
Payroll and other taxes		640			612		291

	$	6,358		$	5,561	$	3,373

Taxes on Income

The tax effects of significant items comprising our net deferred income taxes as of December 31, 2005 and 2004 are as follows (in thousands):


	2005			2004
Deferred tax assets:
Operating loss carryforwards	$	2,020		$	14,748
Difference in basis of property		25,343			28,753
Other		3,052			3,276
Valuation allowance		(27,363	)		(40,492	)

Net deferred tax asset		3,052			6,285
Less current portion		3,052			251

	$	—		$	6,034

The valuation allowance decreased by $13.1 million as a result of the change in the U.S. deferred tax assets related to the net operating loss carryforward as well as a Venezuelan deferred tax asset impairment. Realization of deferred tax assets associated with net operating loss carryforwards is dependent upon generating sufficient taxable income prior to their expiration. Management believes it is more likely than not that they will not be realized through future taxable income. The difference in interpretation of oil pricing under the Transitory Agreement has been recognized and represents our entire deferred tax asset.

The components of income before income taxes and minority interest are as follows (in thousands):


	2005		2004			2003
Income (loss) before income taxes
United States	$	8,178	$	(16,593	)	$	34,236
Foreign		114,916		97,859			37,552

Total	$	123,094	$	81,266		$	71,788

The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):


	2005		2004			2003
Current:
United States	$	739	$	(8	)	$	1,187
Foreign		53,304		34,581			9,137

		54,043		34,573			10,324

Deferred:
Foreign		2,982		(1,285	)		(667	)

	$	57,025	$	33,288		$	9,657

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A comparison of the income tax expense (benefit) at the federal statutory rate to our provision for income taxes is as follows (in thousands):


	2005			2004			2003
Computed tax expense at the statutory rate	$	43,083		$	28,443		$	15,025
State income taxes		—			25			1,188
Effect of foreign source income and rate differentials on foreign income		16,065			(2,169	)		(15,849	)
Change in valuation allowance		13,129			7,020			9,219
Alternative minimum tax		739			—			—
Net operating loss utilization		(15,567	)		—			—
Other		(424	)		(31	)		74

Total income tax expense	$	57,025		$	33,288		$	9,657

Rate differentials for foreign income result from tax rates different from the U.S. tax rate being applied in foreign jurisdictions and from the effect of foreign currency devaluation in foreign subsidiaries which use the U.S. Dollar as their functional currency.

At December 31, 2005, we had, for federal income tax purposes, operating loss carryforwards of approximately $5.4 million, expiring in the years 2022 through 2025.

We do not provide deferred income taxes on undistributed earnings of international consolidated subsidiaries for possible future remittances as all such earnings are reinvested as part of our ongoing business. The amount of deferred taxes on the undistributed earnings cannot be determined at this time.

Note 5 — Stock Option and Stock Purchase Plans

In May 2004, our shareholders approved the 2004 Long Term Incentive Plan (the “Plan”). The Plan provides for the issuance of up to 1,750,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to eligible participants including employees, non-employee directors and consultants of our Company or subsidiaries. Under the Plan, no more than 438,000 shares may be granted as restricted stock, and no individual may be granted more than 110,000 shares of restricted stock or 438,000 in options over the life of the Plan. The exercise price of stock options granted under the plan must be no less than the fair market value of our common stock on the date of grant. All options granted to date will vest ratably over a three-year period from their dates of grant and expire ten years from grant date. All restricted stock granted to date is subject to a restriction period of 36 months during which the stock will be deposited with the Company and is subject to forfeiture under certain circumstances. The Plan also permits the granting of performance awards to eligible employees and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time of at least one year. Performance awards granted under the Plan may not exceed $5.0 million in a calendar year and may not exceed $2.5 million to any one individual in a calendar year. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become exercisable.

In January 2001, we adopted the Non-Employee Director Stock Purchase Plan (the “Stock Purchase Plan”) to encourage our directors to acquire a greater proprietary interest in us through the ownership of our common stock. Under the Stock Purchase Plan, each non-employee director could elect to receive shares of our common stock for all or a portion of their fee for serving as a director. The number of shares issuable was equal to 1.5 times the amount of cash compensation due the director divided by the fair market value of the common stock on the scheduled date of payment of the applicable director’s fee. The shares have a restriction upon their sale for one year from the date of issuance. As of December 31, 2002, 337,850 shares had been issued from the plan. The Stock Purchase Plan was terminated by the Board of Directors in September 2002.

In July 2001, our shareholders approved the adoption of the 2001 Long Term Stock Incentive Plan. The 2001 Long Term Stock Incentive Plan provides for grants of options to purchase up to 1,697,000 shares of our common stock in the form of Incentive Stock Options and Non-Qualified Stock Options to eligible participants including employees of our company or subsidiaries, directors, consultants and other key persons. The exercise price of stock options granted under the plan must be no less than the fair market value of our common stock on the

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date of grant. No officer may be granted more than 500,000 options during any one fiscal year, as adjusted for any changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date.

Since 1989 we have adopted several other stock option plans under which options to purchase shares of our common stock have been granted to employees, officers, directors, independent contractors and consultants. Options granted under these plans have been at prices equal to the fair market value of the stock on the grant dates. Options granted under the plans are generally exercisable in varying cumulative periodic installments after one year and cannot be exercised more than ten years after the grant dates. Following the adoption of the 2001 Long Term Stock Incentive Plan, no options may be granted under any of these plans.

A summary of the status of our stock option plans as of December 31, 2005, 2004 and 2003 and changes during the years ending on those dates is presented below (shares in thousands):


	2005						2004						2003
	Weighted						Weighted						Weighted
	Average						Average						Average
	Exercise						Exercise						Exercise
	Price			Shares			Price			Shares			Price		Shares
Outstanding at beginning of the year:	$	8.18			3,793		$	7.52			4,523		$	7.42		5,223
Options granted		11.51			922			13.36			378			6.26		246
Options exercised		(3.45	)		(241	)		(7.41	)		(955	)		2.32		(494	)
Options cancelled		(14.24	)		(404	)		(6.31	)		(153	)		11.37		(452	)

Outstanding at end of the year		8.61			4,070			8.18			3,793			7.52		4,523

Exercisable at end of the year		7.40			2,886			7.71			3,236			8.18		3,857

Significant option groups outstanding at December 31, 2005 and related weighted average price and life information follow (in thousands):


	Outstanding								Exercisable
			Weighted-
			Average		Weighted-						Weighted-
Range of	Number		Remaining		Average		Aggregate		Number		Average		Aggregate
Exercise	Outstanding		Contractual		Exercise		Intrinsic		Exercisable		Exercise		Intrinsic
Prices	at 12/31/05		Life		Price		Value		at 12/31/05		Price		Value
$1.55 - $2.75		1,523		1.78	$	1.98	$	10,513		1,523	$	1.98	$	10,513
$4.80 - $7.10		356		3.82		5.66		1,145		291		5.52		975
$8.72 - $10.88		696		5.40		10.30		23		136		8.72		22
$11.50 - $16.90		1,085		3.64		13.04		—		526		13.05		—
$17.88 - $24.13		410		0.14		21.21		—		410		21.21		—

		4,070					$	11,681		2,886			$	11,510

The aggregate intrinsic value in the preceding table represents the total pretax intrinsic value based on our closing stock price of $8.88 as of December 30, 2005, which would have been received by the option holders had all option holders exercised their options as of that date. Of the number outstanding, 733,750 options are pledged to us to secure a repayment of debt.

The value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions:

For options granted during:


	2005			2004			2003
Weighted average fair value	$	6.35		$	10.33		$	4.83
Weighted averaged expected life		7			2-10			5-10
Valuation assumptions:
Expected volatility		50.0%-53.4	%		69.6	%		79.8	%
Risk-free interest rate		3.9%-4.6	%		2.6%-4.8	%		2.8%-4.2	%
Expected dividend yield		0	%		0	%		0	%
Expected annual forfeitures		3	%		0	%		0	%

The Black-Scholes option pricing model was developed for use in estimating the value of traded options that have no vesting restrictions and are fully transferable. In addition, option pricing models require the input of

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highly subjective assumptions, including the expected stock price volatility and expected life. The expected volatility is based on historical volatilities of our stock. Historical data is used to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options are expected to be outstanding. The risk-free rate for the periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. Under the Black-Scholes option pricing model, the weighted-average estimated values of stock options granted during 2005, 2004 and 2003 were $6.35, $10.33 and $4.83, respectively.

A summary of our nonvested shares as of December 31, 2005, and changes during the year ended December 31, 2005, is presented below (in thousands):


				Weighted-Average
				Grant-Date
Nonvested Shares	Shares			Fair Value
Nonvested at January 1, 2005		557		$	8.46
Granted		922			6.73
Vested		(243	)		7.51
Forfeited		(51	)		9.05

Nonvested at December 31, 2005		1,185		$	7.30

As of December 31, 2005, there was $6.5 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under our plans. That cost is expected to be recognized over the next three years. The total fair value of shares vested during the years ended December 31, 2005, 2004 and 2003, was $2.7 million, $1.4 million and $1.1 million, respectively.

In connection with our acquisition of Benton Offshore China Company in December 1996, we adopted the Benton Offshore China Company 1996 Stock Option Plan. Under the plan, Benton Offshore China Company is authorized to issue up to 107,571 options to purchase our common stock for $7.00 per share. The plan was adopted in substitution of Benton Offshore China Company’s stock option plan, and all options to purchase shares of Benton Offshore China Company common stock were replaced under the plan by options to purchase shares of our common stock. All options were issued upon the acquisition of Benton Offshore China Company and vested upon issuance. At December 31, 2005, options to purchase 74,427 shares of common stock were both outstanding and exercisable.

In addition to options issued pursuant to the plans, options have been issued to individuals other than our officers, directors or employees at $11.88 which vest over three years. At December 31, 2005, a total of 10,000 options issued outside of the plans were both outstanding and exercisable.

Note 6 — Operating Segments

We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Revenue from Venezuela is derived primarily from the production and sale of oil and natural gas. Other income from United States and Other is derived primarily from interest earnings on various investments. Operations included under the heading “Russia” include project evaluation costs and other costs to maintain an office in Russia. Operations included under the heading “United States and Other” include corporate management, cash management and financing activities performed in the United States and other countries which do not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the United States and Other segment and are not allocated to other operating segments.

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	2005			2004			2003
Segment Revenues
Oil and gas sales:
Venezuela	$	236,941		$	186,066		$	106,095

Total oil and gas sales		236,941			186,066			106,095


Segment Income (Loss)
Venezuela		64,096			54,469			23,874
Russia		(3,471	)		(3,524	)		(29,620	)
United States and other		(9,786	)		(16,585	)		33,049

Net income	$	50,839		$	34,360		$	27,303


	December 31,			December 31,
	2005			2004
Operating Segment Assets
Venezuela	$	258,268		$	309,794
Russia		317			385
United States and other		161,011			108,408

		419,596			418,587
Intersegment eliminations		(18,798	)		(51,101	)

	$	400,798		$	367,486

Note 7 — Russian Operations

Geoilbent

On September 25, 2003, we sold our minority equity investment in Geoilbent to Yukos Operational Holding Limited for $69.5 million plus the repayment of the subordinated loan and certain payables owed to us by Geoilbent in the amount of $5.5 million. Prior to the sale, we owned 34 percent of Geoilbent, a Russian limited liability company, formed in 1991 to develop, produce and market crude oil from the North Gubkinskoye and South Tarasovskoye Fields in the Western Siberia region of Russia. Our minority equity investment in Geoilbent was accounted for using the equity method and was based on a fiscal year ending September 30. Sales quantities attributable to Geoilbent for the period until it was sold on September 25, 2003 were 5.6 million barrels (3.3 million domestic and 2.3 million export). Prices for crude oil for the period until it was sold on September 25, 2003 averaged $14.52 ($8.61 domestic and $23.05 export) per barrel. Depletion expense attributable to Geoilbent for the period until it was sold on September 25, 2003 was $3.23 per barrel. All amounts represent 100 percent of Geoilbent. Summarized financial information for Geoilbent follows (in thousands):

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Year ended September 30:	2003
Revenues
Oil sales	$	81,724


Expenses
Selling and distribution expenses		5,893
Operating expenses		15,897
Depletion, depreciation and amortization		18,182
Write-downs of oil and gas properties		95,000
General and administrative		9,456
Taxes other than on income		25,626

		170,054


Loss from operations		(88,330	)

Other non-operating income (expense)
Investment earnings and other		1,064
Interest expense		(1,992	)
Net gain on exchange rates		1,566

		638


Loss before income taxes		(87,692	)
Income tax benefit		(3,117	)

		(84,575	)
Effects of change in accounting policy		310

Net loss	$	(84,885	)

Note 8 — Venezuela Operations

On July 31, 1992, we and our partner, Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), signed an operating service agreement to reactivate and further develop three Venezuelan oil fields with Lagoven, S.A., then one of three exploration and production affiliates of the national oil company, PDVSA. The operating service agreement covers the Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit. Under the terms of the operating service agreement, Harvest Vinccler, a Venezuelan corporation owned 80 percent by us and 20 percent by Vinccler, is a contractor for PDVSA and is responsible for overall operations of the South Monagas Unit, including all necessary investments to reactivate and develop the fields comprising the South Monagas Unit. The operating service agreement stipulates that Harvest Vinccler is to receive an operating fee in U.S. Dollars deposited into a U.S. commercial bank account for each barrel of crude oil produced (subject to periodic adjustments to reflect changes in a special energy index of the U.S. Consumer Price Index) and is to be reimbursed according to a prescribed formula in U.S. Dollars for its capital costs, provided that such operating fee and cost recovery fee cannot exceed the maximum dollar amount per barrel set forth in the agreement. On August 4, 2005, Harvest Vinccler entered into the Transitory Agreement with PDVSA. The Transitory Agreement provides that effective January 1, 2005, the total amounts paid under the OSA could not exceed 66.67 percent of the total value of the crude oil as determined under an Annex to the Transitory Agreement. Historically, our maximum total fee under the OSA averaged approximately 48 percent of the price of WTI. Under the fee limit in the Transitory Agreement, the new fee has historically averaged approximately 47 percent of the price of WTI. In the first quarter 2005, PDVSA paid the fee 50 percent in U.S. Dollars and 50 percent in Bolivars. Subsequent quarterly payments have been received 75 percent in U.S. Dollars and 25 percent in Bolivars. The OSA stipulated payment was to be in U.S. Dollars or a currency selected by Harvest Vinccler.

In September 2002, Harvest Vinccler and PDVSA signed an amendment to the OSA, providing for the delivery of up to 198 Bcf of natural gas through July 2012 at a price of $1.03 per Mcf. In addition, Harvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the natural gas production at $7.00 per barrel beginning with our first natural gas sale. We drilled one well in 2005.

The Venezuelan government maintains full ownership of all hydrocarbons in the fields. During 2005, the government of Venezuela initiated a series of actions to compel companies with operating service agreements to convert those agreements into new companies in which PDVSA has a majority interest. As a result of the actions

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taken by the government of Venezuela, we were unable to carry out our planned development program for 2005. Moreover, our ability to carry out future programs is uncertain.

Note 9 — China Operations

In December 1996, we acquired Crestone Energy Corporation, subsequently renamed Benton Offshore China Company. Its principal asset is a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under certain circumstances, and lies within an area which is the subject of a border 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 border 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. WAB-21 represents the $2.9 million excluded from the full cost pool as reflected on our December 31, 2005 balance sheet.

Note 10 — Related Party Transactions

In March 2002, we entered into construction service agreements with Venezolana International, S.A. (“Vinsa”). Vinsa is an affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A., which owns 20 percent of Harvest Vinccler. Vinsa provided $0.3 million and $1.7 million in construction services for our Venezuelan field operations for the years ended December 31, 2004 and 2003, respectively. This agreement was terminated on September 19, 2004.

In August 1997, we entered into a consulting agreement with Oil & Gas Technology Consultants Inc. (“OGTC”) to provide operational and technical assistance in Venezuela. OGTC is an affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A., which owns 20 percent of Harvest Vinccler. Payment for services is due when earnings are not reinvested in Harvest Vinccler operations. Expenses related to this consulting agreement were $1.5 million at December 31, 2003. The consulting agreement was cancelled January 1, 2004.

Note 11 — Earnings Per Share

Basic earnings per common share (“EPS”) are computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. The weighted average number of common shares outstanding for computing basic EPS was 36.9 million, 36.1 million and 35.3 million for the years ended December 31, 2005, 2004 and 2003, respectively. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The weighted average number of common shares outstanding for computing diluted EPS, including dilutive stock options, was 38.4 million, 38.1 million, 36. 8 million for the years ended December 31, 2005, 2004 and 2003, respectively.

An aggregate of 1.9 million options were excluded from the earnings per share calculations because their exercise price exceeded the average price for the year ended December 31, 2005. For the years ended December 31, 2004 and 2003, 0.9 million and 2.5 million options and warrants, respectively, were excluded from the earnings per share calculations because their exercise price exceeded the average price.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

Quarterly Financial Data (unaudited)

Summarized quarterly financial data is as follows:


	Quarter Ended
	March 31			June 30			September 30			December 31
	(amounts in thousands, except per share data)
Year ended December 31, 2005
Revenues	$	60,986		$	56,442		$	61,221		$	58,292
Expenses		(27,300	)		(26,207	)		(32,245	)		(31,664	)
Non-operating income (expense)		3,054			277			(1,827	)		2,065

Income before income taxes and minority interests		36,740			30,512			27,149			28,693
Income tax expense		13,533			11,959			16,332			15,201

Income before minority interests		23,207			18,553			10,817			13,492
Minority interests		5,172			4,402			2,674			2,982

Net income	$	18,035		$	14,151		$	8,143		$	10,510


Net income per common share:
Basic	$	0.49		$	0.38		$	0.22		$	0.28

Diluted	$	0.47		$	0.37		$	0.21		$	0.27


Other comprehensive income (loss)		(6,048	)		1,770			2,287			1,991

Total comprehensive income	$	11,987		$	15,921		$	10,430		$	12,501


	Quarter Ended
	March 31			June 30			September 30			December 31
	(amounts in thousands, except per share data)
Year ended December 31, 2004
Revenues	$	38,797		$	41,397		$	46,053		$	59,819
Expenses		(20,329	)		(20,478	)		(24,697	)		(30,082	)
Non-operating income (expense)		(2,795	)		(2,031	)		(4,779	)		391

Income before income taxes and minority interests		15,673			18,888			16,577			30,128
Income tax expense		5,600			9,902			7,617			10,169

Income before minority interests		10,073			8,986			8,960			19,959
Minority interests		2,566			2,738			3,654			4,660

Net income (loss)	$	7,507		$	6,248		$	5,306		$	15,299


Net income (loss) per common share:
Basic	$	0.21		$	0.17		$	0.15		$	0.42

Diluted	$	0.20		$	0.16		$	0.14		$	0.39


Other comprehensive income (loss)		—			—			(2,357	)		1,870

Total comprehensive income (loss)	$	7,507		$	6,248		$	2,949		$	17,169

Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)

In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS 69”), this section provides supplemental information on our oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

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TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):


					United States
	Venezuela		China		and Other		Total
Year Ended December 31, 2005
Development costs	$	8,912	$	—	$	—	$	8,912
Exploration costs		—		42		—		42

	$	8,912	$	42	$	—	$	8,954


Year Ended December 31, 2004
Development costs	$	39,161	$	—	$	—	$	39,161
Exploration costs		10		53		—		63

	$	39,171	$	53	$	—	$	39,224


Year Ended December 31, 2003
Development costs	$	58,079	$	—	$	2	$	58,081
Exploration costs		11		39		133		183

	$	58,090	$	39	$	135	$	58,264

TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):


	Venezuela			China			Total
Year Ended December 31, 2005
Proved property costs	$	617,137		$	13,497		$	630,634
Costs excluded from amortization		—			2,900			2,900
Oilfield inventories		8,150			—			8,150
Less accumulated depletion and impairment		(473,496	)		(13,497	)		(486,993	)

	$	151,791		$	2,900		$	154,691


Year Ended December 31, 2004
Proved property costs	$	608,225		$	13,454		$	621,679
Costs excluded from amortization		—			2,900			2,900
Oilfield inventories		6,503			—			6,503
Less accumulated depletion and impairment		(432,302	)		(13,454	)		(445,756	)

	$	182,426		$	2,900		$	185,326


December 31, 2003
Proved property costs	$	569,055		$	13,401		$	582,456
Costs excluded from amortization		—			2,900			2,900
Oilfield inventories		8,266			—			8,266
Less accumulated depletion and impairment		(398,206	)		(13,401	)		(411,607	)

	$	179,115		$	2,900		$	182,015

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TABLE III — Results of operations for oil and natural gas producing activities (in thousands):


						United States
	Venezuela		China			and Other			Total
Year ended December 31, 2005
Oil and natural gas revenues	$	236,941	$	—		$	—		$	236,941
Expenses:
Operating, selling and distribution expenses and taxes other than on income		39,969		—			—			39,969
Depletion		41,175		—			—			41,175
Income tax expense		65,943		—			—			65,943

Total expenses		147,087		—			—			147,087

Results of operations from oil and natural gas producing activities	$	89,854	$	—		$	—		$	89,854


Year ended December 31, 2004
Oil and natural gas revenues	$	186,066	$	—		$	—		$	186,066
Expenses:
Operating, selling and distribution expenses and taxes other than on income		33,297		—			214			33,511
Depletion		34,108		—			—			34,108
Income tax expense		38,968		—			—			38,968

Total expenses		106,373		—			214			106,587

Results of operations from oil and natural gas producing activities	$	79,693	$	—		$	(214	)	$	79,479


Year ended December 31, 2003
Oil and natural gas revenues	$	106,095	$	—		$	—		$	106,095
Expenses:
Operating, selling and distribution expenses and taxes other than on income		31,445		—			76			31,521
Write-down of oil and gas properties and impairments		—		23			142			165
Depletion		19,599		—			—			19,599
Income tax expense		12,158		—			1,187			13,345

Total expenses		63,202		23			1,405			64,630

Results of operations from oil and natural gas producing activities	$	42,893	$	(23	)	$	(1,405	)	$	41,465

TABLE IV — Quantities of Oil and Natural Gas Reserves

Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. All Venezuelan reserves are attributable to an operating service agreement between Harvest Vinccler and PDVSA, under which all mineral rights are owned by the government of Venezuela. Venezuelan reserves include production projected through the end of the operating service agreement in July 2012.

The SEC requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data, economic changes and other relevant developments. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.

Proved developed reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well.

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Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves are proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates.

Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for proved undeveloped reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir.

Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.

The evaluations of the oil and natural gas reserves as of December 31, 2005, 2004 and 2003 were prepared by Ryder Scott Company L.P., independent petroleum engineers. The 2005 reserve information shown below has been reduced to exclude reserves formerly classified as proved undeveloped. Under SEC standards for the reporting of oil and natural gas reserves, proved reserves are estimated quantities of crude oil and natural gas “which geological data and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.” (Emphasis added). Our quantities of proved reserves have been reduced to remove undeveloped reserves because the actions taken by the Venezuelan government in 2005 under our operating service agreement have created uncertainty as to whether those reserves will be recovered under the economic and operating conditions which currently exist in Venezuela. For ease of reference, the reclassified reserves are hereafter referred to as “Contractually Restricted Reserves”.

The tables shown below represent our interests in Venezuela in each of the years.


				Minority
				Interest in
	Venezuela			Venezuela			Net Total
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls)
Year ended December 31, 2005
Proved Reserves at beginning of the year		78,142			(15,628	)		62,514
Revisions of previous estimates^(a)		(34,068	)		6,813			(27,255	)
Production		(8,763	)		1,753			(7,010	)

Proved Developed Reserves at end of the year		35,311			(7,062	)		28,249



(a) Includes primarily Contractually Restricted Reserves as well as other minor revisions.

Year ended December 31, 2004
Proved Reserves at beginning of the year		87,872			(17,574	)		70,298
Revisions of previous estimates		(1,578	)		316			(1,262	)
Production		(8,152	)		1,630			(6,522	)

Proved Reserves at end of the year		78,142			(15,628	)		62,514


Year ended December 31, 2003
Proved Reserves beginning of the year		95,168			(19,033	)		76,135
Revisions of previous estimates		(521	)		104			(417	)
Extensions, discoveries and improved recovery		572			(114	)		458
Production		(7,347	)		1,469			(5,878	)

Proved Reserves at end of the year		87,872			(17,574	)		70,298

S-24


				Minority
				Interest in
	Venezuela			Venezuela			Net Total
Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at:
December 31, 2005		35,311			(7,062	)		28,249
December 31, 2004		45,488			(9,098	)		36,390
December 31, 2003		45,860			(9,172	)		36,688
January 1, 2003		53,833			(10,767	)		43,066

Proved Reserves-Natural gas (MMcf)

Year ended December 31, 2005
Proved Reserves beginning of the year		164,282			(32,856	)		131,426
Revisions of previous estimates^(a)		(79,687	)		15,937			(63,750	)
Production		(25,677	)		5,135			(20,542	)

Proved Developed Reserves end of the year		58,918			(11,784	)		47,134



(a) Includes primarily Contractually Restricted Reserves as well as other minor revisions.

Year ended December 31, 2004
Proved Reserves beginning of the year		195,500			(39,100	)		156,400
Revisions of previous estimates		(159	)		32			(127	)
Production		(31,059	)		6,212			(24,847	)

Proved Reserves end of the year		164,282			(32,856	)		131,426


Year ended December 31, 2003
Proved Reserves beginning of the year		198,000			(39,600	)		158,400
Revisions of previous estimates		160			(32	)		128
Production		(2,660	)		532			(2,128	)

Proved Reserves end of the year		195,500			(39,100	)		156,400


Proved Developed Reserves-Natural gas (MMcf) at:
December 31, 2005		58,918			(11,784	)		47,134
December 31, 2004		80,897			(16,179	)		64,718
December 31, 2003		106,147			(21,229	)		84,918
January 1, 2003		105,000			(21,000	)		84,000

TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities

The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.

Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.

The tables shown below represent our interest in Venezuela in each of the years. We report the results of Ryder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan reserves.

S-25


				Minority
				Interest in
	Venezuela			Venezuela			Net Total
	(amounts in thousands)
December 31, 2005^(a)
Future cash inflows from sales of oil and gas	$	1,029,630		$	(205,926	)	$	823,704
Future production costs		(227,079	)		45,416			(181,663	)
Future development costs		(27,917	)		5,583			(22,334	)
Future income tax expenses		(239,386	)		47,877			(191,509	)

Future net cash flows		535,248			(107,050	)		428,198
Effect of discounting net cash flows at 10%		(123,451	)		24,691			(98,760	)

Standardized measure of discounted future net cash flows	$	411,797		$	(82,359	)	$	329,438


December 31, 2004
Future cash inflows from sales of oil and gas	$	1,852,045		$	(370,409	)	$	1,481,636
Future production costs		(342,373	)		68,475			(273,898	)
Future development costs		(141,565	)		28,313			(113,252	)
Future income tax expenses		(428,833	)		85,767			(343,066	)

Future net cash flows		939,274			(187,854	)		751,420
Effect of discounting net cash flows at 10%		(258,049	)		51,609			(206,440	)

Standardized measure of discounted future net cash flows	$	681,225		$	(136,245	)	$	544,980


December 31, 2003
Future cash inflows from sales of oil and gas	$	1,513,525		$	(302,705	)	$	1,210,820
Future production costs		(382,577	)		76,515			(306,062	)
Future development costs		(130,160	)		26,032			(104,128	)
Future income tax expenses		(317,018	)		63,404			(253,614	)

Future net cash flows		683,770			(136,754	)		547,016
Effect of discounting net cash flows at 10%		(225,306	)		45,060			(180,246	)

Standardized measure of discounted future net cash flows	$	458,464		$	(91,694	)	$	366,770


(a)		Proved reserves do not include Contractually Restricted Reserves.

TABLE VI -Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves


	Net Venezuela
	2005			2004			2003
	(amounts in thousands)
Standardized Measure at January 1	$	544,980		$	366,770		$	317,799
Sales of oil and natural gas, net of related costs		(124,638	)		(122,215	)		(59,720	)
Revisions to estimates of proved reserves
Net changes in prices, development and production costs		262,852			333,237			76,037
Quantities		(365,565	)		(7,597	)		(1,584	)
Extensions, discoveries and improved recovery, net of future costs		—			—			4,971
Accretion of discount		80,202			54,531			48,128
Net change in income taxes		109,030			(78,504	)		(15,053	)
Development costs incurred		7,130			31,329			46,463
Changes in timing and other		(184,553	)		(32,571	)		(50,271	)

Standardized Measure at December 31	$	329,438		$	544,980		$	366,770

S-26

Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)
for Russia Equity Affiliate as of September 30, their fiscal year end.

Geoilbent (34 percent ownership until sold September 25, 2003) which was accounted for under the equity method, has been included at its respective ownership interest in the consolidated financial statements and the following Tables based on a fiscal period ending September 30 and, accordingly, results of operations for oil and natural gas producing activities in Russia reflect the year ended September 30, 2003.

TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):


	Geoilbent
Year Ended September 25, 2003
Development costs	$	3,474
Exploration costs		1,034

	$	4,508

TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):


	Geoilbent
September 25, 2003
Proved property costs	$	102,753
Oilfield inventories		2,530
Less accumulated depletion and impairment		(72,333	)

	$	32,950

TABLE III — Results of operations for oil and natural gas producing activities (in thousands):


	Geoilbent
Year ended September 25, 2003
Oil sales	$	27,876
Expenses:
Operating, selling and distribution expenses and taxes other than on income		16,088
Depletion		6,215
Write-down of oil and gas properties		32,300
Income tax expense		2,073

Total expenses		56,676

Results of operations from oil and natural gas producing activities	$	(28,800	)

S-27

TABLE IV — Quantities of Oil and Natural Gas Reserves

Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Geoilbent oil fields are situated on land belonging to the Government of the Russian Federation. It obtained licenses from the local authorities and paid unified production taxes to explore and produce oil from these fields. Geoilbent had licenses to develop the North Gubkinskoye and South Tarasovskoye fields in western Siberia. Our 34 percent equity investment in Geoilbent was sold September 25, 2003.

The SEC requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.

Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.

S-28


	Geoilbent
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls)

Year ended September 30, 2003
Proved reserves beginning of the year		25,356
Revisions of previous estimates		537
Extensions, discoveries and improved recovery		962
Production		(1,942	)
Sales of reserves in place		(24,913	)

Proved reserves at end of the year		—


Proved Developed Reserves at:
September 30, 2003		—
October 1, 2002		13,200

TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities


	Geoilbent
	(amounts in thousands)
September 30, 2003
Future cash inflow	$	481,557
Future production costs		(229,982	)
Future development costs		(36,666	)

Future net revenue before income taxes		214,909
10% annual discount for estimated timing of cash flows		(99,948	)

Discounted future net cash flows before income taxes		114,961
Future income taxes, discounted at 10% per annum		(23,163	)

Standardized measure of discounted future net cash flows	$	91,798

S-29

(PRICEWATERHOUSECOOPERS LOGO)

REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and
Owners of Limited Liability Company Geoilbent

In our opinion, the accompanying balance sheets and the related statements of income, cash flows and changes in stockholders’ equity, present fairly, in all material respects, the financial position of LLC Geoilbent (the “Company”) at 30 September 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended 30 September 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Notes 4 and 10 to the financial statements, the Company has a long-term debt facility for which it is in violation of certain loan covenants and therefore the lender may declare the loan to be in default and can accelerate the maturity. Accordingly, this long-term debt has been classified in the accompanying financial statements as a current liability resulting in a working capital deficit of approximately US$35,772,000 as at 30 September 2003 which raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regards to this matter are also described in Note 4. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

ZAO PricewaterhouseCoopers Audit

Moscow, Russian Federation
2 March 2004

LLC GEOILBENT
BALANCE SHEETS
(expressed in thousand of US Dollars)


			As at			As at
	Notes		30 September 2003			30 September 2002
Assets
Cash and cash equivalents				680			2,001
Restricted cash		10		1,217			1,469
Accounts receivable and advances to suppliers		7		7,161			6,308
Inventories		8		8,018			7,201
Deferred income tax, current		14		966			1,806

Total current assets				18,042			18,785
Oil and gas producing properties, full cost method		9		89,469			185,989
Deferred income tax, non-current		14		—			696
Other long term assets				—			130

Total assets				107,511			205,600

Liabilities and Stockholders’ Equity
Current portion of long-term debt		10		37,500			22,550
Accounts payable				6,559			15,244
Trade advances				993			3,000
Taxes payable		11		7,858			12,354
Other payables and accrued liabilities				904			903

Total current liabilities				53,814			54,051

Long-term debt		10		—			7,500
Asset retirement obligation		3		734			—

Total liabilities				54,548			61,551

Commitments and contingent liabilities		16		—			—
Contributed capital		12		82,518			82,518
Retained earnings (accumulated deficit)				(23,353	)		61,531
Accumulated other comprehensive loss				(6,202	)		—

Total stockholders’ equity				52,963			144,049

Total liabilities and stockholders’ equity				107,511			205,600

The accompanying notes are an integral part of these financial statements.

LLC GEOILBENT
STATEMENTS OF INCOME
(expressed in thousand of US Dollars)


			Year ended			Year ended			Year ended
	Notes		30 September 2003			30 September 2002			30 September 2001
Total sales and other operating revenues		13		82,307			91,598			101,159

Costs and other deductions
Operating expenses				15,801			15,360			11,415
Selling and distribution expenses				5,893			6,696			9,876
General and administrative expenses				9,456			8,335			5,650
Depletion and amortization expense				18,278			27,168			14,918
Impairment of property, plant and equipment		9		95,000			—			—
Taxes other than income tax		14		25,625			27,657			26,011

Total costs and other deductions				170,053			85,216			67,870

Other income and expense
Exchange gain, net				(1,566	)		(2,053	)		(781	)
Interest expense, net				1,992			4,629			7,547
Other non-operating income, net				(481	)		(381	)		(648	)

Total other expense (income)				(55	)		2,195			6,118

Income (loss) before income tax				(87,691	)		4,187			27,171

Income tax expense		14
Current income tax expense				3,542			2,804			6,751
Deferred income tax benefit				(6,659	)		(2,502	)		—

Total income tax expense (benefit)				(3,117	)		302			6,751

Income (loss) before cumulative effect of change in accounting principle, net of tax				(84,574	)		3,885			20,420
Cumulative effect of change in accounting principle, net of tax		3		(310	)		—			—

Net income (loss)				(84,884	)		3,885			20,420

The accompanying notes are an integral part of these financial statements.

LLC GEOILBENT
STATEMENTS OF CASHFLOWS
(expressed in thousand of US Dollars)


	Year ended			Year ended			Year ended
	30 September 2003			30 September 2002			30 September 2001
Cash flows from operating activities
Net income (loss)		(84,884	)		3,885			20,420
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and amortization expense		18,278			27,168			14,918
Impairment of oil and gas properties		95,000			—			—
Amortization of financing costs		130			520			520
Exchange gain		(1,566	)		(2,053	)		(781	)
Deferred tax benefit		(6,659	)		(2,502	)		—
Decrease/(increase) in accounts receivable and advances to suppliers		(631	)		403			85
Decrease/(increase) in inventories		(544	)		6,362			(4,700	)
Increase/(decrease) in accounts payable		(9,030	)		(3,407	)		11,902
Increase/(decrease) in trade advances		(2,070	)		(5,747	)		3,785
Increase/(decrease) in taxes payable		(4,822	)		5,436			4,780
Decrease in other payables and accrued liabilities		(28	)		(1,378	)		(2,386	)

Cash provided by operating activities		3,174			28,687			48,543

Cash flow from investing activities
Capital expenditures		(13,257	)		(26,755	)		(39,874	)
Proceeds on disposal of oil and gas producing properties		1,023			286			191
Disposal/(purchase) of investments		—			367			(129	)

Net cash used in investing activities		(12,234	)		(26,102	)		(39,812	)

Cash flows from financing activities
Payment of short-term borrowings from founders		—			—			(717	)
Payment of short-terms borrowings		—			(3,000	)		(3,845	)
Proceeds from short-term borrowings		—			—			6,446
Proceeds from long-term borrowings from founders		—			7,500			—
Payments of long-term borrowings		(550	)		(18,200	)		(10,455	)
Proceeds from long-term borrowings		8,000			—			—
Decrease in restricted cash		252			8,738			2,153

Net cash provided by (used in) financing activities		7,702			(4,962	)		(6,418	)

Effect of foreign exchange on cash balances		37			(31	)		(37	)

Net decrease in cash and cash equivalents		(1,321	)		(2,408	)		2,276
Cash and cash equivalents, beginning of year		2,001			4,409			2,133

Cash and cash equivalents, end of year		680			2,001			4,409

Supplemental cash flow information
Interest paid		1,977			4,862			7,609
Income taxes paid		2,388			2,747			6,906

The accompanying notes are an integral part of these financial statements.

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 1: Organization

LLC Geoilbent (the “Company”) is engaged in the development and production of oil and gas in the North Gubkinskoye and South Tarasovskoye fields. These fields are located in the West Siberian region of the Russian Federation, approximately 2,000 miles northeast of Moscow. The Company was established in December 1991 by two Russian oil companies, OAO Purneftegas (“PNG”) and OAO Purneftegasgeologia (“PNGG”), and by Harvest Natural Resources, Inc. (“Harvest”, formerly, Benton Oil and Gas Company) of the United States, which contributed 33%, 33% and 34%, respectively, of the Company’s charter capital, in accordance with the Company’s Foundation Document. In January 2002, PNG and PNGG transferred their stakes in the Company to OAO Minley. In September 2003, Harvest sold its interests in the Company to a company affiliated with OAO YUKOS (“YUKOS”).

Note 2: Basis of Presentation

The Company maintains its accounting records and prepares its statutory financial statements in accordance with the Regulations on Accounting and Reporting of the Russian Federation (“RAR”). The accompanying financial statements have been prepared from these accounting records and adjusted as necessary to comply with accounting principles generally accepted in the United States of America (“US GAAP”). The Company has a year ending 30 September for US GAAP reporting purposes.

In preparing the financial statements in conformity with US GAAP, management makes estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from such estimates.

Certain previously presented amounts have been reclassified to conform to the presentation adopted during the current period. These reclassifications had no impact on previously reported net income or stockholders’ equity.

Reporting and functional currency. The Russian Rouble is the functional currency (primary currency in which business is conducted) for the Company’s operations in the Russian Federation. The Company considers the US dollar as its reporting currency.

In November 2002, the International Practices Task Force concluded that Russia ceased being a highly inflationary economy as of 1 January 2003. As a result of the Task Force conclusion, the Company applied the guidance contained in Emerging Issues Task Force (“EITF”) No. 92-4 and EITF No. 92-8 as of 1 January 2003, which address changes in accounting when an economy ceases to be considered highly inflationary. As a result of the application of the guidance in EITF No. 92-4 and No. 92-8, as of 1 January 2003, the Company recognised a deferred tax liability of USD 8.1 million for temporary differences related to its property, plant and equipment and a corresponding amount as a cumulative translation adjustment as a separate component in stockholders’ equity.

Effective 1 January 2003, the measurement currency of the Company is the Russian Rouble. The transactions and balances in the accompanying financial statements have been translated into US dollars in accordance with the relevant provisions of Statement of Financial Accounting Standards (“SFAS”) No. 52, Foreign Currency Translation (“SFAS No. 52”). Consequently, assets and liabilities are translated at closing exchange rates. The statements of income and cash flows have been translated using monthly average exchange rates. Translation differences resulting from the use of these exchange rates have been included as a component of stockholders equity. The amount of such differences for the period beginning 1 January 2003 through 30 September 2003 was approximately USD 1.9 million. The exchange rates at 30 September 2003, and 30 September 2002, were 30.61 and 31.64, respectively, Russian Roubles to the US dollar.

Prior to 1 January 2003, transactions not already measured in US dollars were remeasured into US dollars in accordance with the relevant provisions of SFAS No. 52 as applied to hyperinflationary economies. Consequently, monetary assets and liabilities were translated at closing exchange rates and non-monetary items were translated at historic exchange rates and adjusted for any impairments. The statements of income and cash flows were translated using monthly average exchange rates. Translation differences resulting from the use of these exchange rates were included in the determination of net income and were included in exchange gains/losses in the accompanying statements of income through 31 December 2002.

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 2: Basis of Presentation (continued)

Inflation, exchange restriction and controls. Exchange restrictions and controls exist relating to converting Russian Roubles to other currencies. At present, the Russian Rouble is not a convertible currency outside the Russian Federation. Future movements in the exchange rates between the Russian Rouble and the US dollar will affect the carrying value of the Company’s Russian Rouble denominated assets and liabilities. Such movements may also affect the Company’s ability to realise non-monetary assets represented in US dollars in the accompanying financial statements. Accordingly, any translation of Russian Rouble amounts to US dollars should not be construed as a representation that such Russian Rouble amounts have been, could be, or will in the future be converted into US dollars at the exchange rate shown or at any other exchange rate. At 30 September 2003, the Company was required to sell 25% of its foreign currency receipts within the Russian Federation to the Central Bank for Russian Roubles. Such amounts are subject to certain deductions depending on debt payments on certain hard currency denominated borrowing agreements.

Note 3: Summary of Significant Accounting Policies

Cash and cash equivalents. Cash and cash equivalents include all highly liquid securities with original maturities of three months or less when acquired.

Accounts receivable. Accounts receivable are presented at net realisable value and include value-added and excise taxes which are payable to tax authorities upon collection of such receivables.

Inventories. Crude oil and petroleum products inventories are valued at the lower of cost, using the first-in-first out method, or net realisable value. Materials and supplies inventories are recorded at the lower of average cost or net realisable value.

Property, plant and equipment. The Company follows the full cost method of accounting for oil and gas properties. Under this method, all oil and gas property acquisition, exploration, and development costs including internal costs directly attributable to such activities are capitalized as incurred in the Company’s cost center (full cost pool), which is the Russian Federation. Payroll and other internal costs capitalized include salaries and related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties as well as all other directly identifiable internal costs associated with these activities. Payroll and other internal costs associated with production operations and general corporate activities are expensed in the period incurred.

The full cost pool, including future development costs, estimated asset retirement obligations, net of prior accumulated depletion, is depleted using the unit-of-production method based upon actual production and estimates of proved reserve quantities. Proceeds from sales of oil and gas properties are credited to the full cost pool with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.

Pursuant to full cost accounting rules, capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves discounted at 10 percent; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. During 2003, the Company’s capitalized costs exceeded the ceiling limit resulting in an impairment of oil and gas properties. See Note 9 for additional information.

Pension and post-employment benefits. The Company’s mandatory contributions to the governmental pension scheme are expensed when incurred.

Revenue recognition. Revenue from the sale of crude oil and gas condensate are recognized when dispatched to customers and title has transferred.

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 3: Summary of Significant Accounting Policies (continued)

Income taxes. Deferred income tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, in accordance with SFAS No. 109, Accounting for Income Taxes. Deferred income tax assets and liabilities are measured using enacted tax rates in the years in which these temporary differences are expected to reverse. Valuation allowances are provided for deferred income tax assets when management believes it is more likely than not that the assets will not be realized.

Change in accounting principle. Effective 1 October 2002, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Assets Retirement Obligations (“SFAS No. 143”). SFAS No. 143 requires entities to record the fair value of its asset retirement obligation as a liability in the period in which they are incurred and a corresponding increase in the carrying amount of the related long-lived asset.

SFAS No. 143 differs in several respects from the previous accounting method employed by the Company. Prior to the adoption of SFAS No. 143, the Company included estimated undiscounted asset retirement costs in its calculation for determining depletion expense. Under SFAS 143, the Company recognizes a liability for the fair value of an asset retirement obligation (“ARO”) in the period in which it is incurred, and capitalizes the associated asset retirement cost. In periods subsequent to initial measurement, the Company recognizes period-to-period changes in the liability for an ARO resulting from a) the passage of time and b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows. The Company’s asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities.

The cumulative effect of this change in accounting principle was a reduction in net income of USD 310 thousand, net of tax, which was recorded in the statement of income for the year ended 30 September 2003. The effect of adoption resulted in increases in property, plant and equipment and long-term liabilities of USD 303 thousand and USD 613 thousand as of 1 October 2002, respectively.

The following table provides pro forma information as if SFAS No. 143 has been applied in previous periods:


	Year ended		Year ended		Year ended
Thousands of US dollars	30 September 2003		30 September 2002		30 September 2001
Asset retirement obligations as of the beginning of the period		613		483		358
Liabilities incurred for the period		25		56		79
Accretion expense		96		75		45
Asset retirement obligations as of the end of the period		734		613		483
Net income for the period as reported				3,885		20,420
Pro-forma net income				3,777		20,358

Recent accounting standards. FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities (“FIN 46R”), identifies certain off-balance sheet arrangements that meet the definition of a variable interest entity (“VIE”). FIN 46R requires consolidation of VIEs by primary beneficiaries and requires more extensive disclosures. FIN 46R is applicable to any VIE created after 1 February 2003. The Company does not expect the adoption of this interpretation will have any material effect on its financial position or results of operations.

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 4: Going Concern

During the years ended 30 September 2003 and 2002 the Company took steps to reduce its working capital deficit. These included the repayment of debt, the receipt of subordinated long-term loans from the Company’s stockholders and the repayment of accounts payable, primarily from additional borrowings from the European Bank for Reconstruction and Development (“EBRD”). However, as at 30 September 2003, and 30 September 2002, the current liabilities of the Company exceeded its current assets by USD 35,772 thousand and USD 35,266 thousand, respectively. Included in current liabilities, as at 30 September 2003 and 30 September 2002, are loans repayable to the EBRD of USD 30,000 thousand and USD 22,000 thousand, respectively. This debt has been reclassified as current because the Company is not in compliance with a loan facility covenant related to the required implementation of a new management information system, required by 1 May 2003. The loan facility also requires the Company to maintain a minimum working capital ratio. The Company was not in compliance with the required working capital ratio as of the interim reporting dates during the year ended 30 September 2003, however, it met the minimum required working capital ratio as of 30 September 2003 (see also Note 10). Under the terms of the loan facility the EBRD may declare the loan to be in default and can accelerate the maturity. There can be no assurance that the EBRD will not demand repayment of the loan.

During the year ended 30 September 2003, a substantial portion of the Company’s cash flow was utilised to pay accounts and taxes payable resulting in a reduction in capital expenditures for the year. In order to maintain or increase proved oil and gas reserves, the Company must make substantial capital expenditures in 2004 and subsequently. The Company’s cash flow from operations is dependent on the level of oil prices, which are historically volatile and are significantly impacted by the proportion of production that the Company can sell on the export market. Historically, the Company has supplemented its cash flow from operations with additional borrowings or equity capital and may continue to do so. Should oil prices decline for a prolonged period and should the Company not have access to additional capital, the Company would need to reduce its capital expenditures, which could limit its ability to maintain or increase production and, in turn, meet its debt service requirements. Asset sales and financing are restricted under the terms of debt agreements.

Management plans to further address the Company’s working capital deficit by resolving issues with the EBRD relating to its non compliance with the loan covenants and by reducing certain capital expenditures and funding its 2004 cash requirements with cash flows from existing producing properties and its development drilling program. Management is in the process of implementing the required management information system and expects to have implemented this system during the 2004 reporting year. The accompanying financial statements do not include any adjustments that might result if the Company were unable to continue as a going concern.

Note 5: Cash and Cash Equivalents

Included in cash and cash equivalents as at 30 September 2003, and 2002, respectively, are Russian Rouble denominated amounts totaling RR 19.7 million (USD 643 thousand) and RR 18.3 million (USD 578 thousand).

Restricted cash consists of deposits with lending institutions to pay interest and principal as discussed in Note 10. As at 30 September 2003, the amount of restricted cash was USD 1,217 thousand (2002: USD 1,469 thousand). These accounts are maintained in US Dollar denominated accounts located outside Russia.

Note 6: Financial Instruments

Fair values. The estimated fair values of financial instruments are determined with reference to various market information and other valuation methodologies as considered appropriate, however considerable judgment is required in interpreting market data to develop these estimates. Accordingly, the estimates are not necessarily indicative of the amounts that the Company could realize in a current market transaction. The methods and assumptions used to estimate fair value of each class of financial instrument are presented below.

Cash and cash equivalents, accounts receivable and accounts payable. The carrying amount of these items are a reasonable approximation of their fair value.

Short-term and long-term debt. Loan arrangements have both fixed and variable interest rates that reflect the currently available terms and conditions for similar debt. The carrying value of this debt is a reasonable approximation of its fair value.

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 6: Financial Instruments (continued)

Credit risk. A significant portion of the Company’s accounts receivable are from domestic and foreign customers, and advances are made to domestic suppliers. Although collection of these amounts could be influenced by economic factors affecting these entities, management believes there is no significant risk of loss to the Company beyond the provisions already recorded, provided that the economic situation in the Russian Federation does not deteriorate (Note 16).

Note 7: Accounts Receivable and Advances to Suppliers


Thousands of US dollars	30 September 2003		30 September 2002
Trade accounts receivable		1,531		1,387
Recoverable value-added tax		4,227		3,515
Advances to suppliers		1,286		1,193
Advances to customs		117		137
Other receivables		—		76

Total accounts receivable and advances to suppliers		7,161		6,308

Accounts receivables are presented net of an allowance for doubtful accounts of USD 147 thousand and USD 70 thousand at 30 September 2003 and 2002, respectively.

Note 8: Inventories


Thousands of US Dollars	30 September 2003		30 September 2002
Materials and supplies		7,442		6,905
Crude oil		576		296

Total inventories		8,018		7,201

Note 9: Oil and Gas Producing Properties


Thousands of US dollars	30 September 2003			30 September 2002
Oil and gas producing properties, cost		302,214			278,459
Accumulated depletion and impairment		(212,745	)		(92,470	)

Oil and gas producing properties, net book value		89,469			185,989

The Company’s oil and gas fields are situated on land belonging to the Government of the Russian Federation. The Company obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Licenses will expire in September 2018 for the North Gubkinskoye field, and in March 2023 for the South Tarasovskoye field. However, under Paragraph 4 of the Russian Federal Law 20-FZ, dated 2 January 2000, the licenses may be extended over the economic life of the lease at the Company’s option. Management intends to extend such licenses for properties that are expected to produce subsequent to their expiry dates. Estimates of proved reserves extending past 2018 represent approximately 9 percent of total proved reserves.

At 31 December 2002 and at 31 March 2003, the Company’s capitalized costs for oil and gas producing properties exceeded its full cost accounting ceiling limitation. The Company’s ceiling limitation decreased primarily because of a decline in the Company’s average realized price it received for its oil at those dates. As a result the Company recorded impairments of its oil and gas producing properties in the aggregate amount of USD 95 million (excluding a deferred income tax benefit of USD 7.6 million); this impairment was recorded as an impairment expense in the statement of income for the year ended 30 September 2003.

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 10: Long-term Debt


Thousands of US dollars	30 September 2003			30 September 2002
EBRD		30,000			22,000
IMB		—			550
OAO Minley		5,000			5,000
YUKOS		2,500			—
Harvest Natural Resources		—			2,500
Less: current portion		(37,500	)		(22,550	)

Total long-term debt		—			7,500

EBRD loan. At 30 September 2003, the outstanding balance of loans with the EBRD totaled USD 30 million. On 23 September 2002, the Company signed an amended loan agreement with the EBRD that increased the maximum amount that could be drawn down under the facility with the EBRD to USD 50 million. Under the loan agreement, the use of loan proceeds is restricted to the repayment of accounts payable and development of oil and gas reserves. This loan facility is to be repaid such that the loan balance may not exceed set amounts at certain dates in the future. The interest rate under the loan agreement is linked to the London interbank offer rate (“LIBOR”) and an agreed upon margin. The Company must hold as restricted cash a) principal and interest to be paid at the next repayment date and b) 30 percent of the total of principal and interest to be paid at the following repayment date.

LIBOR interest rates ranged from 1.12 percent to 1.84 percent in 2003 (2002: 1.84 percent to 3.5 percent, 2001: 3.5 percent to 6.94 percent). The annual weighted average interest rates on these loans varied between 5.09 percent and 5.43 percent for the year ended 30 September 2003 (2002: 8.59 percent and 11.71 percent, 2001: 14.93 percent to 15.17 percent). The loan is collaterized by the Company’s immovable assets and crude oil export contracts.

The EBRD loan agreement includes certain covenants which include, among other things, the maintenance of financial ratios. If the Company fails to meet these requirements for two consecutive quarters it will result in an event of default whereby the EBRD may, at its option, demand payment of the outstanding principal and interest. As discussed in Note 4, as of 31 December 2002, 31 March 2003 and 30 June 2003 the Company was in violation of the minimum working capital ratio covenant. As of 30 September 2003, the minimum working capital ratio as defined in the loan facility exceeds the covenant requirements. Additionally, the Company has not completed its implementation of a management information system as required under the terms of the loan. Due to these loan convenant violations, the Company has classified the EBRD debt as a current liability.

In addition, while in default of EBRD covenants, the Company may not declare or pay any dividend, make any distribution on its charter capital, purchase, or redeem any shares of the charter capital of the Company, nor make any payment of principal or interest on subordinated shareholder loans or make any other payment or distribution to any stockholder or any affiliate of any stockholder.

As part of the sale of Harvest’s interest in the Company to YUKOS, as described in Note 1, YUKOS assumed Harvest’s stockholder loan.

Loans from OAO Minley and YUKOS are subordinated, unsecured and repayable commencing from January 2004. Interest rates are 2 percent for the Minley loan, and LIBOR for the YUKOS loan, to January 2004. Repayment of the subordinated loans are subject to approval from the EBRD. If approval is not received, the terms of the loan agreements are not considered to be violated. After January 2004, the interest rates on the YUKOS loan increases to 8 percent for the remainder of 2004, and 12 percent from 2005 onwards.

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 10: Long-term Debt (continued)

While the Company remains in violation of its EBRD loan convenants, further borrowings under the facility are at the sole discretion of the EBRD. The maximum loan facility available under the terms of the EBRD loan and the related aggregate maturities are as follows:


	Maximum loan facility
Thousands of US dollars	outstanding
30 September 2003 to 27 January 2004		50,000
27 January 2004 to 27 July 2004		41,667
27 July 2004 to 27 January 2005		33,333
27 January 2005 to 27 July 2005		25,000
27 July 2005 to 27 January 2006		16,667
27 January 2006 to 27 January 2007		8,333
Thereafter		—

The aggregate maturities of long-term debt outstanding at 30 September 2003 are as follows:


Thousands of US dollars
Year ended 30 September 2004			7,500
Year ended 30 September 2005			5,000
Year ended 30 September 2006			8,333
Year ended 30 September 2007			8,333
Year ended 30 September 2008			8,333

Note 11: Taxes Payable


Thousands of US dollars	30 September 2003		30 September 2002
Value added tax		—		1,445
Income tax		3,777		1,176
Royalty		—		896
Mineral restoration tax		—		152
Road users tax		—		642
Unified production tax		1,552		6,703
Property taxes		586		1,121
Penalties and interest		1,784		219
Other taxes		159		—

Total taxes payable		7,858		12,354

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 12: Contributed Capital

Capital contributions are as follows:


Thousands of US dollars	30 September 2003		30 September 2002
OAO Minley		54,733		54,733
YUKOS		27,785		—
Harvest Natural Resources		—		27,785

Total contributed capital		82,518		82,518

All capital contributions have been made since inception in accordance with the Company’s Foundation Document.

Reserves available for distribution to shareholders are based on the statutory accounting reports of the Company, which are prepared in accordance with Regulations on Accounting and Reporting of the Russian Federation and differ from US GAAP. Russian legislation identifies the basis of distribution as net income. For 2002, the current year statutory net income for the Company as reported in the annual statutory accounting reports was RR 772 million (2001: RR 551 million). However, current legislation and other statutory laws and regulations dealing with distribution rights are open to legal interpretation and, consequently, actual distributable reserves may differ from the amount disclosed. The Company cannot distribute capital while in default of its EBRD loan facility obligations (Note 10).

Note 13: Revenues

Revenues for the years ended 30 September 2003, 2002 and 2001, consisted of the following:


Thousand of US dollars	30 September 2003		30 September 2002		30 September 2001
Crude oil — export (Europe and CIS)		51,949		47,751		83,889
Crude oil — domestic		28,599		40,778		10,900
Gas condensate — domestic		1,176		—		—
Refined products — domestic		—		2,764		6,231
Other operating revenues		583		305		139

Total sales and other operating revenues		82,307		91,598		101,159

Note 14: Taxes

Presented below is a reconciliation between the provision for income taxes and taxes determined by applying the statutory tax rate as applied in the Russian Federation to income before income taxes.


Thousand of US dollars	30 September 2003			30 September 2002			30 September 2001
Income (loss) before income taxes		(87,691	)		4,187			27,171

Theoretical income tax expense (benefit) at statutory rate (24% in 2002 and 2003; 35% in 2001)		(21,046	)		1,005			9,509
Increase (reduction) due to:
Change in valuation allowance		17,192			80			1,810
Non-deductible expenses		1,860			2,894			2,693
Investment tax credits		(593	)		(5,348	)		(6,821	)
Change in statutory tax rate		—			595			(750	)
Tax penalties and interest		442			1,135			517
Other		(972	)		(59	)		(207	)

Total income tax expense (benefit)		(3,117	)		302			6,751

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 14: Taxes (continued)

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for statutory tax purposes. Net deferred tax assets are comprised of the following, at 30 September 2003 and 2002:


Thousand of US dollars	30 September 2003			30 September 2002
Inventories		(313	)		93
Accounts receivable		121			258
Accounts payable and accrued liabilities		1,205			430
Losses carried forward		966			2,502
Property, plant and equipment		4,989			4,810

Total deferred tax assets		6,968			8,093
Less: Valuation allowance		(6,002	)		(5,591	)

Net deferred tax asset		966			2,502

Losses carried forward represent those losses for tax purposes which, according to legislation, the Company is permitted to offset against future taxable earnings in the periods up to 2008, and is subject to limitations of no more than 30% of the Company’s tax liabilities for the tax reporting period.

As at 30 September 2003, management of the Company have assessed the recoverability of the Company’s deferred tax assets and believe that it will be able to realise the tax losses carried forward. Accordingly, the Company has provided a valuation allowance as at 30 September 2003 and 2002, of USD 6,002 thousand and USD 5,591 thousand, respectively, against the remaining deferred tax assets.

Principal movements in the valuation allowance for deferred income tax assets (“DTA”) during the year ended 30 September 2003 are as follows:


Millions of US dollars
Valuation allowance, beginning of period	5.6
Increase related to DTA resulting from the December ceiling test writedown	12.0
Net other increase in DTA movements during the December quarter	1.0
Decrease due to application of EITF No. 92-4 and No. 92-8 effective 1 January 2003	(16.8	)
Increase relating to DTA resulting from the March ceiling test writedown	3.2
Net other increase in DTA movements	1.0

Valuation allowance, end of period	6.0

As a result of the application of EITF No. 92-4 and No. 92-8, the valuation allowance related to property, plant and equipment was reduced to zero and a deferred tax liability of USD 8.1 million recorded on 1 January 2003 (Note 2), with no effect on income as the adjustment was recorded as part of the currency translation adjustment as of 1 January 2003. A subsequent ceiling test writedown in March resulted in the recognition of an additional deferred tax asset of USD 10.8 million of which USD 7.6 million and USD 3.2 million were credited as a deferred tax benefit and an increase to the DTA valuation allowance, respectively.

Deferred income tax assets are classified as follows:


Thousands of US dollars	30 September 2003		30 September 2002
Deferred income tax, current		966		1,806
Deferred income tax, non-current		—		696

Total net deferred tax asset		966		2,502

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 14: Taxes (continued)

Taxes other than income tax. The Company is subject to a number of taxes other than on income which are detailed below.


Thousands of US dollars	30 September 2003			30 September 2002		30 September 2001
Export duties		8,464			5,376		10,922
Excise tax		—			535		1,548
Royalty		—			2,254		4,867
Mineral restoration tax		377			885		4,596
Road users tax		203			860		1,427
Unified production tax		19,056			14,221		—
Property taxes		2,263			1,994		1,424
Taxes recovery		(7,017	)		—		—
Other taxes		2,279			1,532		1,227

Total taxes other than income tax		25,625			27,657		26,011

Beginning 1 January 2002, mineral restoration tax, royalty tax and excise tax on crude oil production were abolished and replaced by the unified natural resources production tax. From 1 January 2004 through 31 December 2006, the base rate for the unified natural resources production tax is set at RR 347 per metric ton of crude oil produced, and is to be adjusted depending on the market price of Urals blend and the RR/USD exchange rate. The tax becomes nil if the Urals blend price falls to or below USD 8.00 per barrel. From 1 January 2007, the unified natural resources production tax rate is set by law at 16.5 percent of crude oil revenues recognized by the Company based on Tax Regulations of the Russian Federation.

During the year ended 30 September 2003, the Company pursued its claim of overpayment of mineral restoration taxes (MRT) paid during the period from 1999 to 2001 of approximately RR 211 million (USD 7.0 million), plus approximately RR 4 million (USD 0.1 million) in related penalties paid. During the year, the regional courts ruled in favour of the Company and, accordingly, the Company and the tax authorities agreed to offset the amounts awarded against the Company’s unified production taxes payable.

Note 15: Related Party Transactions

As of 30 September 2003 and 2002, the Company had the following balances with its stockholders. These balances are included in the balance sheet within accounts receivable, accounts payable and long-term debt as appropriate.


Thousand of US Dollars	30 September 2003		30 September 2002
Accounts receivable
Purneftegasgeologia and affiliated entities		19		63
Accounts payable
Purneftegasgeologia and affiliated entities		183		574
YUKOS		2,111		—
Harvest Natural Resources		—		3,354
Purneftegas and affiliated entities		—		22
Long-term debt
Harvest Natural Resources		—		2,500
YUKOS		2,500		—
Minley		5,000		5,000

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 15: Related Party Transactions (continued)

Harvest Natural Resources/YUKOS. During 2003 and 2002, Harvest provided insurance on behalf of the Company and personnel services to the Company for a total value of approximately USD 1,087 thousand (2002: USD 1,752 thousand). The remaining portion of the accounts payable balance outstanding relates to services provided in prior reporting periods. As part of the sale of Harvest’s interest in the Company to YUKOS, all balances owing by the Company to Harvest were transferred to YUKOS.

Purneftegasgeologia. During 2003, 2002 and 2001, Purneftegasgeologia and affiliated entities provided services to the Company for a total value of approximately nil, USD 2,414 thousand and USD 4,193 thousand, respectively. Services consisted of drilling, well maintenance and other related work. The Company sold crude oil for a total value of USD 19 thousand and USD 24 thousand during 2003 and 2002, respectively, and materials during 2003 and 2002 for a total value of approximately USD 726 thousand and USD 613 thousand, respectively.

Purneftegas. During 2002 and 2001, Purneftegas and affiliated companies provided well maintenance services and supplies to the Company for a total of approximately USD 312 thousand and USD 248 thousand, respectively. The Company sold materials to Purneftegas and affiliated entities during 2002 for a total value of approximately USD 260 thousand.

Minley. During 2002, the Company paid USD 4.9 million to Minley in settlement at face value of promissory notes originally issued to the Company’s suppliers and contractors.

During 2003, interest expense on shareholder loans of USD 99 thousand was incurred with respect to Minley and USD 49 thousand was incurred with respect to Harvest. At 30 September 2003 interest payable to Minley totalled USD 21 thousand (2002: USD 21 thousand) and interest payable to Harvest was USD 65 thousand (2002: USD 14 thousand).

Note 16: Commitments and Contingent Liabilities

Economic and operating environment in the Russian Federation. Whilst there have been improvements in the economic situation in the Russian Federation in recent years, the country continues to display some characteristics of an emerging market. These characteristics include, but are not limited to, the existence of a currency that is not freely convertible in most countries outside of the Russian Federation, restrictive currency controls, and relatively high inflation.

The prospects for future economic stability in the Russian Federation are largely dependent upon the effectiveness of economic measures undertaken by the government, together with legal, regulatory, and political developments.

Taxation. Russian tax legislation is subject to varying interpretations and changes occurring frequently, which may be retroactive. Further, the interpretation of tax legislation by tax authorities as applied to the transactions and activity of the Company may not coincide with that of management. As a result, the tax authorities may challenge transactions and the Company may be assessed additional taxes, penalties and interest, which may be significant. The tax periods remain open to review by the tax and customs authorities for three years. The Company cannot predict the ultimate amount of additional assessments, if any, and the timing of their related settlements with certainty, but expects that additional liabilities, if any, arising will not have a significant effect on the accompanying financial statements.

Environmental matters. Environmental regulations and their enforcement are continually being considered by government authorities and the Company periodically evaluates its obligations related thereto. As obligations are determined, they are provided for over the estimated remaining lives of the related oil and gas reserves, or recognized immediately, depending on their nature. The existence of environmental liabilities under proposed or any future legislation, or as a result of stricter enforcement of existing legislation, cannot reasonably be estimated. Under existing legislation, management believes, there are no liabilities that would have a material adverse effect on the financial position, operating results or liquidity of the Company, and that have not been accrued in the financial statements.

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 16: Commitments and Contingent Liabilities (continued)

Oilfield licenses. The Company is subject to periodic reviews of its activities by governmental authorities with respect to the requirements of its oilfield licenses. Management of the Company correspond with governmental authorities to agree on remedial actions necessary to resolve any findings resulting from these reviews. Failure to comply with the terms of a license could result in fines, penalties or license limitation, suspension or revocation. The Company’s management believes any issues of non-compliance will be resolved through negotiations or corrective actions without any materially adverse effect on the Company’s financial position or results of operations.

Legal contingencies. The Company is claiming additional deductions relating to the fiscal periods from 1999 to 2001 amounting to approximately RR 330 million (USD 10.8 million). Management believe these deductions are permitted for companies operating in the northern regions of the Russian Federation and also deductions for certain interest paid during that period. Although the Company was successful in the initial hearing before the courts, the tax authorities have continued to challenge the Company’s position. As at 30 September 2003, the Company has not recorded any benefit relating to the above claims.

The Company is the named defendant in a number of lawsuits as well as the named party in numerous other proceedings arising in the ordinary course of business. While the outcomes of such contingencies, lawsuits or other proceedings cannot be determined at present, management believes that any resulting liabilities will not have a materially adverse effect on the operating results or the financial position of the Company.

Insurance. At 30 September 2003 and 2002, the Company held limited insurance policies in relation to its assets and operations, or in respect of public liability or other insurable risks. Since the absence of insurance alone does not indicate that an asset has been impaired or a liability incurred, no provision has been made in the financial statements for unspecified losses.

LLC GEOILBENT
Supplemental Information on Oil and Natural Gas Producing Activities(unaudited)
(expressed in thousands US Dollars except as indicated)

Supplemental Information on Oil and Natural Gas Producing Activities(unaudited)

In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS No. 69”), this section provides supplemental information on the Company’s oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities:


	Year ended		Year ended		Year ended
Thousand of US Dollars	30 September 2003		30 September 2002		30 September 2001
Development costs		10,217		25,290		33,774
Exploration costs		3,040		1,465		6,100

Total costs incurred in oil and natural gas acquisition, exploration, and development activities		13,257		26,755		39,874

TABLE II — Capitalized costs related to oil and natural gas producing activities:


	As at			As at
Thousand of US Dollars	30 September 2003			30 September 2002
Proved property costs		302,214			277,659
Costs excluded from amortisation		—			800
Oilfield inventories		7,442			6,905
Less accumulated depletion and impairment		(212,745	)		(92,470	)

Total capitalised costs related to oil and natural gas producing activities		96,911			192,894

TABLE III — Results of operations for oil and natural gas producing activities:

In accordance with SFAS 69, results of operations for oil and natural gas producing activities do not include general corporate overhead and monetary effects, nor their associated tax effects. Income tax is based on statutory rates for the year, adjusted for tax deductions, tax credits and allowances.


	Year ended			Year ended		Year ended
Thousand of US Dollars	30 September 2003			30 September 2002		30 September 2001
Oil and natural gas sales		81,987			91,291		100,768
Expenses:
Operating, selling and distribution expenses and taxes other than on income		47,319			49,713		47,302
Depletion and amortization		18,278			27,168		14,918
Impairment of oil and gas properties		95,000			—		—
Income tax expense		6,098			5,750		11,006
Total expenses		166,695			82,631		73,226

Results of operations from oil and natural gas producing activities		(84,708	)		8,660		27,542

LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in thousands US Dollars except as indicated)

TABLE IV — Quantities of oil and natural gas reserves

The Securities and Exchange Commission requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and the Company considers such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.

Proved developed reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed non producing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well.

Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.

The evaluations of the oil and natural gas reserves were prepared by Ryder-Scott Company, independent petroleum engineers.

LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in thousands US Dollars except as indicated)


Proved reserves-crude oil,
condensate and natural gas	Year ended			Year ended			Year ended
liquids (MBbls)	30 September 2003			30 September 2002			30 September 2001
Proved reserves beginning of year		74,575			87,259			95,924
Revisions of previous estimates		1,580			(10,163	)		(16,454	)
Extensions, discoveries and improved recovery		2,829			4,391			12,974
Production		(5,712	)		(6,912	)		(5,185	)

Proved reserves, end of year		73,272			74,575			87,259

Proved developed reserves		35,344			38,824			46,052

TABLE V — Standardized measure of discounted future net cash flows related to proved oil and natural gas reserve quantities


	Year ended			Year ended			Year ended
Thousand of US Dollars	30 September 2003			30 September 2002			30 September 20
Future cash inflow		1,416,343			1,381,874			1,277,494
Future production costs		(676,419	)		(599,277	)		(739,221	)
Future development costs		(107,841	)		(119,725	)		(108,882	)

Future net revenue before income taxes		632,083			662,872			429,391
10% annual discount for estimated timing of cash flows		(293,965	)		(318,079	)		(190,788	)

Discounted future net cash flows before income taxes		338,118			344,793			238,603
Future income taxes, discounted at 10% per annum		(68,126	)		(71,442	)		(30,815	)

Standardized measure of discounted future net cash flows		269,992			273,351			207,788

EXHIBIT INDEX

3. Exhibits:


3.1		Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1(i) to our Form 10-Q filed on August 13, 2002, File No. 1-10762.)

3.2		Amended and Restated Bylaws as of May 19, 2005. (Incorporated by reference to Exhibit 3.2 to our Form 10-Q filed on April 29, 2005, File No. 1-10762.)

4.1		Form of Common Stock Certificate. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-26333).)

4.2		Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.)

4.3		Second Amended and Restated Rights Agreement, dated as of April 15, 2005, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.3 to our Form 10-Q filed on April 29, 2005, File No. 1-10762.)

10.1		Operating Service Agreement between Benton Oil and Gas Company and Lagoven, S.A., which has been subsequently combined into PDVSA Petroleo y Gas, S.A., dated July 31, 1992, (portions have been omitted pursuant to Rule 406 promulgated under the Securities Act of 1933 and filed separately with the Securities and Exchange Commission. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-52436).)


10.2		Note Payable Agreement dated March 8, 2001 between Harvest Vinccler, C.A. and Banco Mercantil, C.A. related to a note in the principal amount of $6,000,000 with interest at LIBOR plus five percent, for financing of Tucupita Pipeline. (Incorporated by reference to Exhibit 10.24 to our Form 10-Q, filed on May 15, 2001, File No. 1-10762.)

10.3		Alexander E. Benton Settlement and Release Agreement effective May 11, 2001 (Incorporated by reference to Exhibit 10.27 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.).

10.4		Sale and Purchase Agreement dated February 27, 2002 between Benton Oil and Gas Company and Sequential Holdings Russian Investors Limited regarding the sale of Benton Oil and Gas Company’s 68 percent interest in Arctic Gas Company. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on March 28, 2002, File No. 1-10762.)

10.5		2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our S-8 (Registration Statement No. 333-85900).)

10.6		Addendum No. 2 to Operating Service Agreement Monagas SUR dated 19th September, 2002. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)

10.7		Bank Loan Agreement between Banco Mercantil, C.A. and Harvest Vinccler C.A. dated October 1, 2002. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)

10.8		Guaranty issued by Harvest Natural Resources, Inc. dated September 26, 2002. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)

10.9†		Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.13 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)

10.10		Sale and Purchase Agreement dated September 26, 2003, between Harvest Natural Resources, Inc. and Yukos Operational Holding Limited regarding the sale of our 34 percent minority equity investment in LLC Geoilbent. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 10, 2003, File No. 1-10762.)

10.11†		Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).)

10.12†		Indemnification Agreement between Harvest Natural Resources, Inc. and the Directors and Executive Officers of the Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)

10.13†		Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)

10.14†		Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)

10.15†		Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.22 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)

10.16		The Transitory Agreement between Harvest Natural Resources, Inc. and PDVSA Petroleo S.A., dated August 4, 2005. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.17^†		Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.18^†		Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.19^†		Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.20^†		Employment Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.21^†		Employment Agreement dated September 26, 2005 between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.22^†		Separation Agreement dated September 30, 2005, between Harvest Natural Resources, Inc. and Dr. Peter J. Hill. (Incorporated by reference to Exhibit 10.7 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.23^†		Consulting Agreement dated October 1, 2005, between Harvest Natural Resources, Inc. and Dr. Peter J. Hill. (Incorporated by reference to Exhibit 10.8 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

	10.24^†		Stock Options Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston.

	10.25^†		Stock Options Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston.

	10.26^†		Stock Options Agreement dated September 26, 2005 between Harvest Natural Resources, Inc. and Byron A. Dunn.

	21.1		List of subsidiaries.

	23.1		Consent of PricewaterhouseCoopers LLP — Houston

	23.2		Consent of ZAO PricewaterhouseCoopers Audit — Moscow

	23.3		Consent of Ryder Scott Company, LP

	31.1		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 executed by James A. Edmiston, President and Chief Executive Officer.

	31.2		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer.

	32.1		Certification accompanying Annual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 executed by James A. Edmiston, President and Chief Executive Officer.

	32.2		Certification accompanying Annual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer.


^†		Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K.


	Year Ended December 31,
	2005		2004		2003		2002		2001
	(in thousands, except per share data)
Statement of Operations:
Total revenues	$	236,941	$	186,066	$	106,095	$	126,731	$	122,386
Operating income		119,525		90,480		33,627		34,585		28,201
Net income		50,839		34,360		27,303		100,362		43,237
Net income per common share:
Basic	$	1.38	$	0.95	$	0.77	$	2.90	$	1.27

Diluted	$	1.32	$	0.90	$	0.74	$	2.78	$	1.27


Weighted average common shares outstanding
Basic		36,949		36,128		35,332		34,637		33,937
Diluted		38,444		38,122		36,840		36,130		34,008


		Page
Part I

Item 1.	Business		1
Item 1A.	Risk Factors		13
Item 1B.	Unresolved Staff Comments		18
Item 2.	Properties		18
Item 3.	Legal Proceedings		19
Item 4.	Submission of Matters to a Vote of Security Holders		19

Part II

Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		20
Item 6.	Selected Financial Data		20
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		22
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		30
Item 8.	Financial Statements and Supplementary Data		31
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		31
Item 9A.	Controls and Procedures		31
Item 9B.	Other Information		31

Part III

Item 10.	Directors and Executive Officers of the Registrant		32
Item 11.	Executive Compensation		32
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		32
Item 13.	Certain Relationships and Related Transactions		32
Item 14.	Principal Accountant Fees and Services		32

Part IV

Item 15.	Exhibits and Financial Statement Schedules		33

Financial Statements			S-2

Signatures			S-31
Stock Option Agreement dated September 15, 2005 - James A. Edmiston
Stock Option Agreement dated September 15, 2005 - James A. Edmiston
Stock Option Agreement dated September 26, 2005 - Byron A. Dunn
List of Subsidiaries
Consent of PricewaterhouseCoopers LLP - Houston
Consent of ZAO PricewaterhouseCoopers Audit - Moscow
Consent of Ryder Scott Company, LP
Certification pursuant to Section 302, President and CEO
Certification pursuant to Section 302, SVP, CFO and Treasurer
Certification pursuant to Section 906, President and CEO
Certification pursuant to Section 906, SVP, CFO and Treasurer


⁽¹⁾		No cash dividends were declared or paid during the periods presented.


Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters


		HARVEST NATURAL RESOURCES, INC.
		(Registrant)

Date: February 27, 2006	By:	/s/James A. Edmiston

		James A. Edmiston
		Chief Executive Officer


Signature		Title

/s/ James A. Edmiston James A. Edmiston		Director, President and Chief Executive Officer

/s/ Steven W. Tholen Steven W. Tholen		Senior Vice President — Finance, Chief Financial Officer and Treasurer
(Principal Financial Officer)

/s/ Kurt A. Nelson Kurt A. Nelson		Vice President-Controller, Chief Accounting Officer
(Principal Accounting Officer)

/s/ Stephen D. Chesebro’ Stephen D. Chesebro’		Chairman of the Board and Director

/s/ John U. Clarke John U. Clarke		Director

/s/ H. H. Hardee H. H. Hardee		Director

/s/ Peter J. Hill Peter J. Hill		Director

/s/ Patrick M. Murray Patrick M. Murray		Director

/s/ J. Michael Stinson J. Michael Stinson		Director


			Additions
	Balance at					Charged to		Deductions		Balance at
	Beginning		Charged to			Other		From		End of
	of Year		Income			Accounts		Reserves		Year
At December 31, 2005
Amounts deducted from applicable assets
Accounts receivable	$	2,757	$	—		$	—	$	—	$	2,757
Deferred tax valuation allowance		40,492		(13,129	)		—		—		27,363
Investment at cost		1,350		—			—		—		1,350

At December 31, 2004
Amounts deducted from applicable assets
Accounts receivable	$	3,355	$	—		$	—	$	598	$	2,757
Deferred tax valuation allowance		48,365		(7,873	)		—		—		40,492
Investment at cost		1,350		—			—		—		1,350

At December 31, 2003
Amounts deducted from applicable assets
Accounts receivable	$	3,525	$	205		$	—	$	375	$	3,355
Deferred tax valuation allowance		39,146		9,219			—		—		48,365
Investment at cost		1,350		—			—		—		1,350


									Total
	Contributed		Retained earnings			Accumulated other			stockholders'
	Capital		(accumulated deficit)			comprehensive loss			equity
Balance at 30 September 2000		82,518		37,226			—			119,744

Net income and total comprehensive income		—		20,420			—			20,420

Balance at 30 September 2001		82,518		57,646			—			140,164

Net income and total comprehensive income		—		3,885			—			3,885

Balance at 30 September 2002		82,518		61,531			—			144,049

Net loss		—		(84,884	)		—			(84,884	)
Cumulative translation adjustment		—		—			(6,202	)		(6,202	)

Total comprehensive loss										(91,086	)

Balance at 30 September 2003		82,518		(23,353	)		(6,202	)		52,963