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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, 2007


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 (State or other jurisdiction of incorporation or organization)		77-0196707 (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 smaller reporting company. See the definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large Accelerated Filer o		Accelerated Filer þ		Non-Accelerated Filer o		Smaller Reporting Company 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

The aggregate market value of the registrant’s 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 June 29, 2007 was: $444,689,722.

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 March 12, 2008, shares outstanding: 35,050,833.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for the 2008 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 undeveloped reserves, drilling risks, 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 exploration, operation and development of oil and natural gas properties, risks incumbent to being a minority shareholder in a corporation, 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, the Company’s ability to acquire oil and natural gas properties that meet its objectives, availability and cost of drilling rigs, seismic crews, 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, exploration, development, production and disposition of oil and natural gas properties since 1989, when it was incorporated under Delaware law. We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”) through our subsidiary Harvest Vinccler, S.C.A. (“Harvest Vinccler”) and our equity affiliate, Petrodelta S.A. (“Petrodelta”) and have undeveloped acreage offshore of the People’s Republic of China (“China”). In 2007, we executed a sale and purchase agreement for a partial interest in the production sharing contract related to the Dussafu Marin field offshore Gabon in West Africa (“Dussafu PSC”); and a farm-in agreement for a partial interest in the production sharing contract related to the Budong-Budong field onshore Indonesia (“Budong PSC”). All conditions precedent in the agreements are complete except for governmental approvals.

Currently, our only producing asset is in Venezuela. Since 1992, our subsidiary, Harvest Vinccler, has been providing operating services to Petroleos de Venezuela, S.A. (“PDVSA”) for the South Monagas Unit under an Operating Service Agreement (“OSA”). On March 31, 2006, Harvest Vinccler signed a Memorandum of Understanding (the “MOU”) with two affiliates of PDVSA, Corporación Venezolana del Petroleo S.A. (“CVP”) and PDVSA Petroleo S.A. (“PPSA”), to convert the OSA into a minority interest in Petrodelta. On August 16, 2006, the MOU was amended to provide for the addition of the Isleño, El Salto and Temblador fields (“New Fields”) to Petrodelta as additional consideration for the conversion of the OSA to Petrodelta. On December 18, 2006, at our special meeting of the stockholders, the transactions contemplated by the MOU were approved. On September 11, 2007, we signed the Contract of Conversion (“Conversion Contract”), and on October 3, 2007, together with CVP, we formed and funded Petrodelta. On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Uracoa, Tucupita and Bombal fields (“SMU fields”) and the New Fields, subject to the conditions of the Conversion Contract, was published in the Official Gazette. Harvest Vinccler has transferred all of its tangible assets and contracts, permits and rights related to the SMU fields in Venezuela to Petrodelta. In January 2008, a majority of Harvest Vinccler’s employees accepted positions with Petrodelta. Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the SMU Fields and New Fields (collectively “Petrodelta Fields”). HNR Finance B.V. (“HNR Finance”) has a 40 percent ownership interest in Petrodelta. As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta, and our partner, Oil & Gas Technology Consultants

(Netherlands) Coöperatie U.A. (“OGTC”), a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining eight percent interest. CVP owns the remaining 60 percent. At our request, CVP has added HNR Finance as a party to the Conversion Contract. Petrodelta is governed by its own board of directors, charter and bylaws.

In April 2006, the Venezuelan National Assembly passed legislation terminating all operating service agreements and directed the government to take over the operations carried out by the private companies without prejudice to the incorporation of mixed companies for that purpose. This action, coupled with the unfinished conversion to Petrodelta, left Harvest Vinccler without a contractual means recognized by the government of Venezuela to address revenues or costs and expenses from April 1, 2006 until October 25, 2007. As a result of this situation, our consolidated financial statements prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) from April 1, 2006 until September 30, 2007, did not reflect the net results of our producing operations in Venezuela. Since the Conversion Contract terms have been fulfilled, we have recorded the results of operations and economic benefits of our ownership in Petrodelta from April 1, 2006 through December 31, 2007 in the fourth quarter of 2007 as Net Income from Unconsolidated Equity Affiliates.

Since signing the MOU in March 2006, CVP has designated its board members and a General Manager and President for Petrodelta. While Petrodelta has been formed, funded and is the legal owner of the Petrodelta Fields, Harvest Vinccler continued in the day-to-day operations of the Petrodelta Fields until the end of January 2008. During 2007, Harvest Vinccler advanced cash to Petrodelta of $47.7 million to fund its operations of which $8.0 million remains to be repaid as of February 29, 2008.

At December 31, 2007, Harvest Vinccler had one loan outstanding with a Venezuelan bank for a total of 20 billion Venezuela Bolivars (“Bolivars”) (approximately $9.3 million). This loan is cash collateralized by $6.8 million deposited in a U. S. bank. The loan represents the remaining balance originally borrowed in 2006 to pay income tax assessments and related interest to the SENIAT, the Venezuelan income tax authority.

In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method. Although the full cost method of accounting for oil and gas exploration and development continues to be an accepted method of accounting for oil and gas properties, the successful efforts method of accounting as prescribed by SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies is the preferred method. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 154, Accounting Changes and Error Corrections, financial information for prior periods has been restated to reflect retrospective application of the successful efforts method. We believe the successful efforts method provides a more transparent representation of our results of operations and the ability to assess our future investments in oil and gas properties for impairment based on their estimated fair values rather than being required to base valuation on prices and costs as of the balance sheet date. The significant differences between successful efforts and full cost accounting for oil and gas properties relate to the expensing of exploration activities and related unsuccessful exploratory drilling activities. The expensing of these costs can create volatility in the statement of operations. The change in accounting principle resulted in a cumulative, non-cash increase to retained earnings of $52.4 million, net of income tax, as of December 31, 2004. Retained earnings increased due to the reversal of ceiling test write downs in prior years required under the full cost accounting rules of the Securities and Exchange Commission (“SEC”). There were no such impairments under the successful efforts accounting rules. The effect of the accounting change on income from continuing operations for the years ended December 31, 2006 and 2005 was a decrease of $4.9 million and $15.0 million, net of income tax, or $0.13 and $0.39 per diluted share, respectively. The decrease in income from continuing operations was due to an increase in depletion expense. There was no effect on cash and cash equivalents. For additional information on the impact of the change to the successful efforts method of accounting see Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle.

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 more detailed description of these and other events during 2007.

As of December 31, 2007, we had total assets of $413.4 million, unrestricted cash in the amount of $120.8 million and no long-term debt. For the year ended December 31, 2007, we had total revenues of $11.2 million and

net cash used in operating activities of $20.5 million. As of December 31, 2006, we had total assets of $468.4 million, unrestricted cash in the amount of $148.1 million and long-term debt of $67.0 million. For the year ended December 31, 2006, we had total revenues of $59.5 million and net cash used in operating activities of $24.4 million.

Our strategy has broadened from our primary focus on Venezuela to identify, access and integrate hydrocarbon assets to include organic growth through exploration in basins globally with proven hydrocarbon systems. We seek to leverage our Venezuelan experience as well as our recently expanded business development and technical platform to create a diversified resource base. With the addition of technical resources, opening of our London office, the planned 2008 opening of a Singapore office, the redeployment of resources from our Moscow office, as well as our earlier purchase of a 45 percent equity interest in Fusion Geophysical, L.L.C. (“Fusion”), we have made significant investments to provide the necessary foundation and global reach required for an organic growth focus. While exploration will become a larger part of our overall portfolio, we will generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles.

Our goal, with the conversion process in Venezuela completed, is to influence the management and operations of Petrodelta while developing and producing the Petrodelta Fields in the most efficient manner. We expect that amounts available for dividends will be distributed to us on a regular basis after a catch up dividend for the period of April 1, 2006 to December 31, 2007. Then Petrodelta is expected to reinvest a substantial portion of its earnings in its development and producing activities and, accordingly, we expect subsequent dividends to be minimal in the near-term.

We intend to use our available cash to pursue additional growth opportunities in Gabon, Indonesia, China and other countries that meet our strategy. However, the execution of this strategy may be limited by factors including access to additional capital and the receipt of a dividend from Petrodelta as well as the need to preserve adequate development capital in the interim.

The ability to successfully execute our strategy is subject to significant risks including, among other things, payment of Petrodelta dividends, exploration, operating, political, legal 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 Annual Report on Form 10-K for a description of these and other risk factors.

Available Information

We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934 (“Exchange Act”). The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street NE, 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 Exchange Act 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 Corporate 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., 1177 Enclave Parkway, Suite 300, Houston, Texas 77077, Attention: Investor Relations.

Operations

Since April 1, 2006, all of our current operations are conducted through our equity affiliate Petrodelta in Venezuela. Harvest Vinccler, HNR Finance and CVP entered into the Conversion Contract in September 2007. HNR Finance is a Netherlands private company with limited liability. All of the equity interest in HNR Finance and Harvest Vinccler is owned by Harvest-Vinccler Dutch Holding B.V., a Netherlands private company with limited liability. We own an 80 percent equity interest in Harvest-Vinccler Dutch Holding B.V. The remaining 20 percent equity interest is owned by OGTC. In addition, we own 100 percent of the WAB-21 petroleum contract in the South China Sea for which we are the operator. During the fourth quarter of 2007, we entered into a sale and purchase agreement for a 50 percent ownership interest in the Dussafu PSC, which we expect to operate as soon as final approvals are received; and a farm-in agreement for an initial 47 percent ownership interest, which may increase to a 54.65 percent ownership interest, in the Budong PSC, which we may operate during the production phase. See Item I – Business, Dussafu Marin, Offshore Gabon and Budong-Budong, Onshore Indonesia for a more detailed description.

Petrodelta

General

On October 25, 2007, the Venezuelan Presidential Decree which formally transfers to Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract was published in the Official Gazette. Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from October 25, 2007. Petrodelta will undertake its operations in accordance with the Business Plan as set forth in Annex I to the Conversion Contract (“Business Plan”). Under the Conversion Contract, work programs and annual budgets adopted by Petrodelta must be consistent with the Business Plan. The Business Plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. The 2008 budget of Petrodelta’s Business Plan was approved by its shareholders on January 23, 2008.

Petrodelta has adopted policies and procedures governing its operations, including, among others, policies and procedures for safety, health and environment, contracting, maintenance of insurance, accounting, banking and treasury and human resources, following the guidelines established by CVP. To the extent possible, such policies and procedures will be consistent with the policies and procedures of PDVSA and the ultimate parent company of HNR Finance. Petrodelta has hired personnel, largely from Harvest Vinccler; and the Board of Directors of Petrodelta has appointed the management of Petrodelta. Certain of these appointments are made by the shareholders. Effective August 9, 2007, Mr. Karl L. Nesselrode, Vice President, Engineering and Business Development of Harvest Natural Resources, Inc. (“Harvest”), accepted a long-term secondment to Petrodelta as its Operations and Technical Manager. Per Petrodelta’s bylaws, the Operations and Technical Manager’s position is designated as our appointment. Mr. Nesselrode will remain an officer of Harvest. The General Manager of Petrodelta (CVP appointment) has been appointed by the Board of Directors of Petrodelta. This position is in charge of the daily management of the business of Petrodelta and has the power and duties customary to manage, direct and supervise the accounting of Petrodelta.

Petrodelta is governed by a board of directors in accordance with the Charter and Bylaws of Petrodelta as set forth in Annex E to the Conversion Contract (“Charter and Bylaws”). Under the Charter and Bylaws, matters requiring shareholder approval may be approved by a simple majority with the exception of certain specified matters which require the approval by the holders of at least 75 percent of the capital stock. These matters include: most changes to the Charter and Bylaws; changes in the capital stock of Petrodelta that would alter the percentage participation of HNR Finance or CVP; any liquidation or dissolution of Petrodelta; any merger, consolidation or business combination of Petrodelta; disposition of all or any substantial part of the assets of Petrodelta, except in the ordinary course of business; any financing agreement for an amount greater than $10 million; approval or modification of Petrodelta’s financial statements; creation of certain reserve funds; any distribution of dividends or return of paid-in surplus; changes to the policy regarding dividends and other distributions established by the Charter and Bylaws; changes to the Business Plan; changes to the Contract for Sale and Purchase of Hydrocarbons with PPSA; contracts with shareholders or affiliates that are not at market price; any social investment in excess of the amount required by the Venezuelan government; any waiver of material rights or actions with respect to litigation involving more than $1 million; selection of external auditors; appointment of any judicial representative or general agent of Petrodelta; and designation of a liquidator in the event of the liquidation of Petrodelta.

The Board of Directors of Petrodelta consists of five directors, three of whom are appointed by CVP, including the President of the Board, and two of whom are appointed by HNR Finance. Decisions of the Board of Directors are taken by the favorable vote of at least three of its members, except in the case of any decision implementing a decision of the Shareholders’ Meeting relating to any of the matters where a qualified majority is required, in which case, a favorable vote of four members will be required. The Board of Directors has broad powers of administration and disposition expressly granted in the Charter and Bylaws. The powers include: proposing budget and work programs; presenting the annual report to the shareholders; appointing and dismissing personnel; making recommendations regarding financial reserves and utilization of surplus; making proposals on dividends consistent with the Charter and Bylaws; agreeing on contracts consistent with the work programs and budgets; opening and closing bank accounts; making, accepting, endorsing and guaranteeing bank drafts and other commercial instruments consistent with work programs and budgets; and implementing policies and procedures.

The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PPSA signed on January 17, 2008. The form of the agreement is set forth in Annex K to the Conversion Contract. Crude oil delivered from the Petrodelta Fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets, and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make payment to Petrodelta of each invoice within 60 days of the end of the invoiced production month by wire transfer, in United States Dollars (“U.S. Dollars”) in the case of payment for crude oil and natural gas liquids delivered, and in Bolivars in the case of payment for natural gas delivered, in immediately available funds to the bank accounts designated by Petrodelta. Any dividend paid by Petrodelta will be made in U.S. Dollars.

An unofficial English translation of the Conversion Contract is attached to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 filed with the SEC on November 1, 2007.

Location and Geology

South Monagas Unit Fields (“SMU Fields”)

Uracoa Field

There are currently 80 oil and natural gas producing wells and five water injection wells in the field. 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 delivered by Petrodelta is produced from the Uracoa field.

Tucupita Field

There are currently 17 oil producing wells and five water injection wells in the field. 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 of oil per day pipeline from the Tucupita field to the Uracoa plant facilities.

Bombal Field

The East Bombal field was drilled in 1992, and currently has two producing wells. There are currently two 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 the East Bombal field has been incorporated into Petrodelta’s long term development plan.

Infrastructure and Facilities

Petrodelta has a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA’s storage facility, the custody transfer point. The marketing contract specifies that the oil stream may contain no more than one

percent base sediment and one percent water. Quality measurements are conducted both at Petrodelta’s facilities and at PDVSA’s storage facility.

Petrodelta has a 64-mile pipeline with a normal capacity of 70 million cubic feet (“MMcf”) of natural gas per day and a design capacity of 90 MMcf of natural gas per day.

Petrodelta has assumed from Harvest Vinccler as part of the conversion the long-term power purchase agreements for the electrical needs, the long-term agreements for the leasing of compression and the operation and maintenance of the gas treatment and compression facilities at the Uracoa and Tucupita fields through 2012.

Isleño, Temblador and El Salto Fields (“New Fields”)

The New Fields transferred to Petrodelta after conversion are located in the same geographic area and have the same geology and productive formations as the SMU Fields. As with the SMU Fields before Harvest Vinccler’s entry in 1992, there has been minimal development activity in the three fields during the last 20 years.

Isleño Field

The Isleño field was discovered in 1953. 2-D seismic data is available over a portion of the field. Seven oil appraisal wells have been drilled in Isleño which have confirmed the presence of commercial oil deposits. The field is located near existing infrastructure in the SMU Fields. Petrodelta’s Business Plan projects full development of the Isleño field over the next three years.

Temblador Field

The Temblador field was discovered in 1936 and developed in the 1940s and 1950s. Temblador has produced approximately 118 million barrels of oil and 34 billion cubic feet of natural gas from 155 wells since 1936. 3-D seismic is available over the entire Temblador field.

El Salto Field

The El Salto field was discovered in 1936. A total of 31 appraisal wells have been drilled identifying nine productive structures and six productive formations. The field has produced less than 1 million Boe and is currently dormant. 3-D seismic data is available over one-third of the field. We believe the El Salto field has substantial exploration upside from several fault blocks, which have been identified using 2-D seismic data but have not yet been confirmed through drilling.

Business Plan of Petrodelta

Petrodelta’s Business Plan was approved as part of the conversion process.

Petrodelta’s immediate focus will be the resumption of drilling in the Uracoa field which is expected to result in a rapid increase in production. Concurrently, Petrodelta will acquire and process or reprocess existing 3-D seismic over the New Fields. Isleño field production can be integrated into the existing Uracoa field infrastructure providing for early production from the field. Temblador field production would be processed at existing field facilities. The El Salto field is believed to contain substantial undeveloped reserves. Accordingly, we expect to acquire additional 3-D seismic and undergo significant appraisal and development in a timely manner to provide for larger scale development implementation. Overall, production is expected to peak four to six years from commencement of drilling by Petrodelta.

Production, Prices and Lifting Cost Summary

In the following table we have set forth the net production, average sales prices and average operating expenses for the year ended December 31, 2007 and the period April 1, 2006 through December 31, 2006 for Petrodelta. The presentation for Petrodelta includes 100 percent of the production (in thousands, except per unit information).


	Year Ended		Nine Months Ended
	December 31, 2007		December 31, 2006
Venezuela
Crude Oil Sales (Bbls)		5,374		5,211
Natural Gas Sales (Mcf)		13,456		11,519
Average Crude Oil Sales Price ($per Bbl)	$	58.61	$	50.98
Average Natural Gas Sales Price ($per Mcf)	$	1.54	$	1.54
Average Operating Expenses ($per Boe)	$	3.12	$	3.19

Royalty-in-kind paid on gas used as fuel was 3,882 Mcf and 3,285 Mcf for 2007 and 2006, respectively.

Acreage

The following table summarizes the developed and undeveloped acreage that we hold under concession as of December 31, 2007:

Developed

Undeveloped

Gross

Net

Gross

Net

Petrodelta

16,432

6,573

230,672

92,269

We have recorded the results of operations and economic benefits of our ownership in Petrodelta from April 1, 2006 through December 31, 2007 in the fourth quarter of 2007 as Net Income from Unconsolidated Equity Affiliates. Petrodelta’s results and operating information is more fully described in Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 7 – Venezuela Operations – Petrodelta, S.A.

Risk Factors

We face significant risks in our Petrodelta investment. These risks 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.

WAB-21, South China Sea

General

In December 1996, we acquired Crestone Energy Corporation, subsequently renamed Benton Offshore China Company. Its principal asset is a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under certain circumstances, and lies within an area which is 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 WAB-21 area due to the dispute.

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 20 miles to the east of significant natural gas fields at Lan Tay and Lan Do, which are reported to contain two trillion cubic feet of natural gas and commenced production in November 2002. WAB-21 is also adjacent to the 2005 Thien Ung discovery which tested oil and natural gas and lies east of the Dua and Chim Sao (formerly Blackbird) discoveries which successfully tested oil and gas in 2006. The WAB-21

contract area covers several similar structural trends and geological formations, each with potential for hydrocarbon reserves in possible multiple pay zones similar to the known fields and discoveries.

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, 2009. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist.

Undeveloped Acreage

Acreage

The following table summarizes the undeveloped acreage that we hold under concession as of December 31, 2007:


	Undeveloped
	Gross		Net
China		7,470,080		7,470,080

Title to Undeveloped Acreage

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 WAB-21 area due to the 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.

Dussafu Marin, Offshore Gabon

General

Location and Geology

The Dussafu PSC contract area is located offshore Gabon, adjacent to the border with the Republic of Congo. It contains 680,000 acres with water depths to 1,000 feet. The Dussafu PSC has two small oil discoveries in the Gamba and Dentale reservoirs and a small natural gas discovery. Production and infrastructure exists in the blocks contiguous to the Dussafu PSC.

Drilling and Development Activity

The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources (“Republic of Gabon”), recently agreed to enter into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. The second exploration phase is a three-year work commitment which includes the acquisition and processing of 500 kilometers of 2-D seismic, geology and geophysical interpretation, engineering studies and the drilling of a conditional well. Leads in the underexplored syn-rift potential in the M’Baya and Lucina reservoirs that are commercial in immediately adjacent fields have been identified and are expected to be the focus of the 2008 work program, which includes the acquisition and processing of 500 kilometers of 2-D seismic data. The Dussafu PSC partners anticipate prospects can be generated to test these play concepts in 2009.

Budong-Budong, Onshore Indonesia

General

Location and Geology

The Budong PSC covers 1.35 million acres and includes the Lariang and Karama sub-basins which are the eastern onshore extension of the West Sulawesi foldbelt (“WSFB”). Exploration to date in the basin is immature due to previously difficult jungle terrain, which is now accessible with the development of palm oil plantations and their related infrastructure. Field work performed over the last 10 years, as outcrops have been more accessible, has given a new understanding to the presence of Eocene source and reservoir potential that had not previously been recognized. Recent seismic surveys have greatly improved the understanding of the geology and enhanced the prospectivity of the offshore WSFB and, by analogy, the sparsely explored onshore area.

To date, a total of eight leads have been recognized. It will be necessary to acquire a grid of seismic data to confirm the structures and give an indication of Eocene target(s) within the section and to mature these leads into drillable prospects. The two identified sub-basins (Lariang and Karama) provide an opportunity to test prospects in two sub-basins.

Farm-In Agreement Terms

We acquired the 47 percent interest in the Budong PSC by committing to fund the first phase of the exploration program including the acquisition of 2-D seismic and drilling of the first two exploration wells. This commitment is capped at $17.2 million. Prior to drilling the first exploration well, subject to the estimated cost of that well, Tately will have a one-time option to increase the level of the carried interest to $20.0 million, and as compensation for the increase, we will increase our participation to a maximum of 54.65 percent. This equates to a total carried cost for the farm-in of $9.1 million.

Regulation

General

Our operations and our ability to finance and fund our growth strategy 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, sometimes retroactively, 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 and our potential for economic loss.

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, 2007, our Houston office had 18 full-time employees. Our Caracas, Moscow and London offices had 14, 11 and 5 employees, respectively. We augment our employees from time to time with independent consultants, as required. On February 26, 2008, we reduced the staff of our Moscow office to three employees and will be redeploying two of these employees to London. Mr. Robert Speirs will relocate and head our new Singapore office which is planned to open in 2008. The Singapore office will coordinate our eastern operations and business development.

Item 1A. Risk Factors

In addition to other information set forth elsewhere in this Form 10-K, the following factors should be carefully considered when evaluating us.

We may not be able to meet the requirements of the global expansion of our business strategy. We have added a global exploration component to diversify our overall portfolio. In many locations, we may be required to post performance bonds in support of a work program. We also intend to acquire underdeveloped, undeveloped and exploration properties from time to time for which the primary risks may be technical, operational or both.

Our strategy to identify, access and integrate hydrocarbon assets in known hydrocarbon basins globally carries greater deal execution, operating, financial, legal and political risks. The environments in which we operate are 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 productive and transparent 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, often 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 significant influence over operations and financial control.

Operations in areas outside the United States are subject to various risks inherent in foreign operations. Our operations 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, including taxes, 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.

Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves based on our equity investment in Petrodelta. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

The process of estimating oil and natural gas reserves is complex requiring 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. Actual production, revenue, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used, and these variances may be material.

You should not assume that the present value of future net revenues referred to in Part IV, Item 15, Notes to the Consolidated Financial Statements, TABLE V – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities and Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuelan Equity Affiliate as of December 31, 2007 and 2006, TABLE V – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities 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, changes in our ability to produce or changes 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.

Our future operations and our investments in equity affiliates are subject to numerous risks of oil and natural gas drilling and production activities. Oil and natural gas exploration and development 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 availability for drilling rigs, production equipment and related services. We cannot assure you 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.

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 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.

Our cash position and limited ability to access additional capital may limit our growth opportunities. At December 31, 2007, we had $120.8 million of available cash and, until Petrodelta pays a dividend, there will be no additional cash available from operations. Having a Petrodelta dividend as our sole source of cash flow limits our access to additional capital and our concentration of political risk in Venezuela may limit our ability to leverage our assets. In addition, our future cash position depends upon the payment of dividends by Petrodelta, in particular for the period from April 1, 2006 through December 31, 2007. While we believe such dividends, if available, will be paid, there is no assurance this will be the case. These factors may limit our ability to grow through the acquisition of additional oil and gas properties and projects.

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.

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.

We may not receive the required government approvals for the Dussafu PSC and/or the Budong PSC. Although all conditions precedent to the Dussafu PSC sale and purchase agreement and the Budong PSC farm-in agreement have been met, there is no certainty that the Republic of Gabon or Indonesia’s Migas will approve the respective agreements. Without the governmental approvals, we will not have an interest in either asset.

We no longer directly manage operations of Petrodelta. PDVSA, through CVP, exercises substantial control over operations, making Petrodelta subject to some internal policies and procedures of PDVSA as well as being subject to constraints in skilled personnel available to Petrodelta. These issues may have an adverse effect on the efficiency and effectiveness of Petrodelta operations.

Now that the conversion to Petrodelta is completed, we are a minority interest owner in Petrodelta. Even though we have substantial negative control provisions as a minority owner in Petrodelta, our control of Petrodelta is limited to our rights under the Conversion Contract and its annexes and the Charter and Bylaws. As a result, our ability to implement or influence Petrodelta’s Business Plan, assure quality control, and set the timing and pace of development may be adversely affected.

Now that the conversion to Petrodelta is completed, Petrodelta has a new sales contract with PPSA, and we have no experience with PPSA as to the timeliness of their payment of invoices. Under the OSA between Harvest Vinccler and PDVSA, PDVSA had a history of making timely payment of invoices for oil and natural gas deliveries. Even though there is no reason not to believe that PPSA won’t make timely payment of invoices for oil and natural gas deliveries, there is no guarantee that this will be the case.

Petrodelta’s Business Plan will be sensitive to market prices for oil. Petrodelta will be operating under a business plan, the success of which will rely heavily on the market price of oil. To the extent that market values of oil decline, the business plan of Petrodelta may be adversely affected.

A decline in the market price of crude oil could uniquely affect the financial condition of Petrodelta. Under the terms of the Conversion Contract and other governmental documents, Petrodelta is subject to a special advantage tax (“ventajas especiales”) which requires that if in any year the aggregate amount of royalties, taxes and certain other contributions is less than 50 percent of the value of the hydrocarbons produced, Petrodelta must pay the government the difference. In the event of a significant decline in crude prices, the ventajas especiales could force Petrodelta to operate at a loss. Moreover, our ability to control those losses by modifying the Business Plan or restricting the budget is limited under the Conversion Contract.

Oil price declines and volatility could adversely affect Petrodelta’s future, our dividends and profitability. Prices for oil fluctuate widely. Prices also affect the amount of cash flow available for capital expenditures and dividends from Petrodelta. 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 fluctuations in oil prices include:

	•		relatively minor changes in the global supply and demand for oil;

	•		export quotas;

	•		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.

Petrodelta may not be able to pay dividends on its operations. While we continue to maintain cash reserves, our investment in Petrodelta currently represents all of our near-term cash generating capability, and the funds available to pursue our growth strategy may be adversely affected by Petrodelta’s inability to pay a dividend.

The total capital required for development of the New Fields in Venezuela may exceed the ability of Petrodelta to finance. Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Petrodelta’s future capital requirements for the development of the New Fields may exceed the cash available from existing cash flow. Petrodelta’s ability to secure financing is currently limited and uncertain, and has been, and may be, affected by numerous factors beyond its control, including the risks associated with operating in Venezuela. Because of this financial risk, Petrodelta may not be able to secure either the equity or debt financing necessary to meet its future cash needs for investment, which may limit its ability to fully develop the properties, cause delays with their development or require early divestment of all or a portion of those projects. This could negatively impact our investment. If we are called upon to fund Petrodelta’s operations, our failure to do so could be considered a default under the Conversion Contract and cause the forfeiture of some or all our shares in Petrodelta. In addition, CVP may be unable or unwilling to fund its share of capital requirements and our ability to require them to do so is limited.

We may not be able to replace production from Petrodelta 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 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.

The legal or fiscal regime for Petrodelta may change and the Venezuelan government may not honor its commitments. While we believe that the Conversion Contract and Petrodelta provide a basis for a more durable arrangement in Venezuela, the value of the investment necessarily depends upon Venezuela’s maintenance of legal, tax, royalty and contractual stability. Our recent experiences in Venezuela demonstrate that such stability cannot be assured. While we have and will continue to take measures to mitigate our risks, no assurance can be provided that we will be successful in doing so or that events beyond our control will not adversely affect the value of our investment in Venezuela.

Tax claims by municipalities in Venezuela may adversely affect Harvest Vinccler’s financial condition. The municipalities of Uracoa and Libertador have asserted numerous tax claims against Harvest Vinccler which we believe are without merit. However, the reliability of Venezuela’s judicial system is a source of concern and it can be subject to local and political influences.

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 Caracas, Venezuela for approximately $4,000 per month. See also Item 1 – Business for a description of our oil and natural gas properties.

Item 3. Legal Proceedings

Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-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. In April 2007, the Court lifted the abatement and set the case for trial. The trial date has been set for the second quarter of 2008. We dispute Excel’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.

Uracoa Municipality Tax Assessments. Harvest Vinccler has received nine assessments from a tax inspector for the Uracoa municipality in which part of the SMU Fields are located as follows:

	•		Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the capital fee reimbursement and related interest paid by PDVSA under the OSA. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims.

	•		Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the Municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims.

	•		Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest

			Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim.

	•		Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims.

Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.

Libertador Municipality Tax Assessments. Harvest Vinccler has received five assessments from a tax inspector for the Libertador municipality in which part of the SMU Fields are located as follows:

	•		One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the Municipality. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim.

	•		Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claims.

	•		Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claims.

Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the refund of all municipal taxes paid since 2002.

In June 2007, the SENIAT issued an assessment in the amount of $0.4 million for Harvest Vinccler’s failure to withhold value added tax (“VAT”) from vendors during 2005. The SENIAT has recognized a payment made by Harvest Vinccler in 2006 for the underwithheld VAT and has partially confirmed that some of the affected vendors have remitted the underwithheld VAT. Harvest Vinccler has received credit, less penalties and interest, from the SENIAT for the VAT remitted by the vendors. Harvest Vinccler has filed claims against the SENIAT for the portion of VAT not recognized by the SENIAT and believes it has a substantial basis for its position.

Item 4. Submission of Matters to a Vote of Securities 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, 2007, there were 34,793,735 shares of common stock outstanding, with approximately 559 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
2006	First quarter	$	10.68	$	8.00
	Second quarter		14.35		9.89
	Third quarter		14.40		9.71
	Fourth quarter		11.74		9.81

2007	First quarter	$	10.46	$	9.11
	Second quarter		13.50		9.37
	Third quarter		12.89		10.00
	Fourth quarter		14.00		12.13

On March 12, 2008, the last sales price for the common stock as reported by the NYSE was $11.78 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.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

EQUITY COMPENSATION PLAN INFORMATION

DECEMBER 31, 2007

Number of Securities

Remaining

Number of

Available for

Securities to be

Weighted

Future Issuance

Issued upon

Average

Under Equity

Exercise of

Exercise Price

Compensation

Outstanding

Of Outstanding

Plans (Excluding

Options, Warrants

Securities Reflected

And Rights

in Column (a))

PLAN CATEGORY

(a)

(b)

(c)

Equity compensation plans approved by security holders

3,702,160

8.55

620,940

Equity compensation plans not approved by security holders (1)

519,650

2.69

—

Total

4,221,810

7.83

620,940


(1)		See Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 5 – Stock Option and Stock Purchase Plans for a description of options issued to individuals other than our officers, directors or employees. The 1999 Stock Option Plan permits the granting of stock options to purchase up to 2,500,000 shares of our common stock in the form of ISOs, NQSOs or a combination of each, with exercise prices not less than the fair market value of the common stock on the date of the grant, subject to the dollar limitations imposed by the Internal Revenue Code. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. Options granted to employees under the 1999 Stock Option Plan vest 50 percent after the first year and 25 percent after each of the following two years, or they vest ratably over a three-year period, from their dates of grant and expire ten years from grant date or three months after retirement, if earlier. All options granted to outside directors and consultants under the 1999 Stock Option Plan vest ratably over a three-year period from their dates of grant and expire ten years from grant date. These were the only compensation plans in effect that were adopted without the approval of our stockholders.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

STOCK PERFORMANCE GRAPH

The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2007, assuming an investment of $100 on December 31, 2002 in each of Harvest’s common stock, the Dow Jones U.S. Exploration & Production Index and the S&P Composite 500 Stock Index.

This graph assumes that the value of the investment in Harvest stock and each index was $100 at December 31, 2002 and that all dividends were reinvested.

PLOT POINTS
(December 31 of each year)



	2002		2003		2004		2005		2006		2007
Harvest Natural Resources, Inc.	$	100	$	154	$	268	$	138	$	165	$	190
Dow Jones US E&P Index	$	100	$	129	$	182	$	298	$	312	$	403
S&P 500 Index	$	100	$	126	$	138	$	142	$	161	$	167

Total Return Data provided by S&P’s Institutional Market Services, Dow Jones & Company, Inc. is composed of companies that are classified as domestic oil companies under Standard Industrial Classification codes (1300-1399, 2900-2949, 5170-5179 and 5980-5989). The Dow Jones US Exploration & Production Index is accessible at http://www.djindexes.com/mdsidx/index.cfm?event=showTotalMarket.

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, 2007. Financial information for 2003 through 2006 has been restated to reflect the retrospective application of the successful efforts method of accounting. See Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle. 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 and 2002 reflect results from Geoilbent (until sold on September 25, 2003) for the twelve months ended September 30, 2003 and 2002. No cash dividends were declared or paid during the periods presented.


	Year Ended December 31,
	2007⁽¹⁾			2006⁽¹⁾			2005		2004		2003
	(in thousands, except per share data)
Statement of Operations:
Total revenues	$	11,217		$	59,506		$	236,941	$	186,066	$	106,095
Operating income (loss)		(19,536	)		574			104,571		70,547		13,930
Net income from Unconsolidated Equity Affiliates		51,695			—			—		—		—
Net income (loss)		57,237			(62,502	)		38,876		18,414		11,545
Net income (loss) per common share:
Basic	$	1.57		$	(1.68	)	$	1.05	$	0.51	$	0.33

Diluted	$	1.51		$	(1.68	)	$	1.01	$	0.48	$	0.31


Weighted average common shares outstanding
Basic		36,550			37,225			36,949		36,128		35,332
Diluted		37,950			37,225			38,444		38,122		36,840


	Year Ended December 31,
	2007⁽¹⁾		2006⁽¹⁾		2005		2004		2003
	(in thousands)
Balance Sheet Data:
Total assets	$	413,469	$	468,365	$	451,377	$	433,019	$	459,814
Long-term debt, net of current maturities		—		66,977		—		—		96,833
Stockholders’ equity		313,766		281,409		337,975		295,615		268,086


⁽¹⁾		Activities under our OSA are reflected under the equity method of accounting effective April 1, 2006. The results of Petrodelta’s operations from April 1, 2006 until December 31, 2007 are reflected in 2007 when Petrodelta was formed.

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

We had earnings of $57.2 million, or $1.51 per diluted share, for the twelve months ended December 31, 2007 compared with a loss of $62.5 million, or $1.68 per diluted share, for 2006. Net income for the year ended December 31, 2007 includes the net results of Petrodelta’s operations from April 1, 2006 through December 31, 2007 of $52.1 million, the reversal of deferred revenue and deferred income tax recorded by Harvest Vinccler for 2005 and first quarter of 2006 deliveries pending clarification on the calculation of crude prices under a Transitory Agreement (“Transitory Agreement”) which provided 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 of $5.6 million, net, and gains from the exchange of financial securities of $49.6 million. The loss for 2006 was due to the inability to recognize equity earnings for the producing operations in Venezuela since the second quarter of 2006 and charges of $73.8 million for additional taxes and related interest in Venezuela for 2001 through 2006. We completed the formation of Petrodelta and moved forward with our plans to create a diversified portfolio using our existing cash and enhanced technical capabilities which are more fully described in the following sections.

Formation of Petrodelta

On October 25, 2007, the Venezuelan Presidential Decree, which formally transfers to Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract, was published in the Official Gazette. Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from October 25, 2007. Petrodelta will undertake its operations in accordance with the Business Plan. Under the Conversion Contract, work programs and annual budgets adopted by Petrodelta must be consistent with the Business Plan. The Business Plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. The 2008 budget of Petrodelta’s Business Plan was approved by its shareholders on January 23, 2008.

Petrodelta has hired personnel, largely from Harvest Vinccler as well as seconding its technical and financial managers; and the Board of Directors of Petrodelta has appointed the management of Petrodelta. Certain of these appointments are made by the shareholders. Effective August 9, 2007, Mr. Karl L. Nesselrode, Vice President, Engineering and Business Development of Harvest, accepted a long-term secondment to Petrodelta as its Operations and Technical Manager. Per Petrodelta’s bylaws, the Operations and Technical Manager’s position is designated as our appointment. Mr. Nesselrode will remain an officer of Harvest. The General Manager of Petrodelta (CVP appointment) has been appointed by the Board of Directors of Petrodelta and is in charge of the daily management of the business of Petrodelta and has the power and duties customary to manage, direct and supervise the accounting of Petrodelta.

Petrodelta is governed by a board of directors in accordance with the Charter and Bylaws. Under the Charter and Bylaws, matters requiring shareholder approval may be approved by a simple majority with the exception of certain specified matters which require the approval by the holders of at least 75 percent of the capital stock. These matters include: most changes to the Charter and Bylaws; changes in the capital stock of Petrodelta that would alter the percentage participation of HNR Finance or CVP; any liquidation or dissolution of Petrodelta; any merger, consolidation or business combination of Petrodelta; disposition of all or any substantial part of the assets of Petrodelta, except in the ordinary course of business; any financing agreement for an amount greater than $10 million; approval or modification of Petrodelta’s financial statements; creation of certain reserve funds; any distribution of dividends or return of paid-in surplus; changes to the policy regarding dividends and other distributions established by the Charter and Bylaws; changes to the Business Plan; changes to the Contract for Sale and Purchase of Hydrocarbons with PPSA; contracts with shareholders or affiliates that are not at market price; any social investment in excess of the amount required by the Venezuelan government; any waiver of material rights or actions with respect to litigation involving more than $1 million; selection of external auditors; appointment of any judicial representative or general agent of Petrodelta; and designation of a liquidator in the event of the liquidation of Petrodelta.

The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PPSA signed on January 17, 2008. The form of the agreement is set forth in Annex K to the Conversion Contract. Crude oil delivered from the Petrodelta Fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets, and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make payment to Petrodelta of each invoice within 60 days of the end of the invoiced production month by wire transfer, in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered, and in Bolivars in the case of payment for natural gas delivered, in immediately available funds to the bank accounts designated by Petrodelta. Any dividend paid by Petrodelta will be made in U.S. Dollars.

An unofficial English translation of the Conversion Contract is attached to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2007, filed with the SEC on November 1, 2007.

Petrodelta currently has a workover rig performing well maintenance. A drilling rig has been contracted and is expected to begin operations during the first quarter of 2008. Petrodelta is in the bidding and selection process to contract a second drilling rig. The second drilling rig is projected to begin operations during the second or third quarter of 2008. Petrodelta’s plan of development is focused on 1) increasing production, 2) conversion of probable and possible reserves to proved reserves in the New Fields, 3) adding reserves through exploration in El Salto by acquiring and processing 3-D seismic over the remaining two-thirds of the field and drilling identified prospects, and 4) capturing the synergies and scale at all levels of Petrodelta’s operations.

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 continue to adversely affect our operations. The situation in Venezuela has also restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere. Until there is clarity and certainty over receipt of payment for prior crude oil and natural gas deliveries and the payment of dividends by Petrodelta, uncertainty over the future of our investment in Venezuela will continue to affect our performance and limit our growth opportunities.

We will use our available cash and future access to capital markets to expand our diversified strategy in a number of countries that fit our strategic investment criteria. In executing our business strategy, we will strive to:

	•		maintain financial prudence and rigorous investment criteria;

	•		access capital markets;

	•		create a diversified portfolio of assets;

	•		preserve our financial flexibility;

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

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

			To accomplish our strategy, we intend to:

	•		Diversify our political risk: Acquire oil and natural gas fields in a number of countries to diversify and reduce the overall political risk of our 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 Presence Through Joint Venture Partners and the Use of Local Personnel: We seek to establish a presence in the countries and areas we operate through joint venture partners to facilitate stronger governmental and business relationships. In addition, we use local personnel to help us take advantage of local knowledge and experience and to minimize costs.

	•		Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time: We are willing to agree to minimum capital expenditures or development commitments at the outset of new projects, but we endeavor to structure such commitments to 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.

	•		Provide Technical Expertise: We believe there is an advantage in being able to provide geological, geophysical and engineering expertise beyond what many companies or countries possess internally. In addition to our in-house technical capabilities, in January 2007 we acquired a minority interest in Fusion, a technical firm with significant experience in providing leading edge geophysical, geosciences and reservoir engineering services in many places in the world. Through this acquisition we have strategic access to these services.

	•		Maintain A Prudent Financing Plan: We intend to maintain our financial flexibility by closely monitoring spending, holding sufficient cash reserves, minimizing the use of restricted cash, actively seeking opportunities to reduce our weighted average cost of capital and increase our access to debt and equity markets.

	•		Manage Exploration Risks. We seek to manage the higher risk of exploration by diversifying our prospect portfolio, applying state-of-the-art technology for analyzing targets and focusing on opportunities in proven active hydrocarbon systems with infrastructure.

	•		Establish Various Sources of Production. We seek to establish new production from our exploration and development efforts in a number of diverse markets and expect to monetize production through operations or the sale of assets.

Diversification

In 2005 and 2006, we recognized the need to diversify our asset base as part of our strategy. Our strategy has broadened from our primary focus on Venezuela to identify, access and integrate hydrocarbon assets to include organic growth through exploration in basins globally with proven hydrocarbon systems. We seek to leverage our Venezuelan experience as well as our recently expanded business development and technical platform to create a diversified resource base. With the addition of technical resources, opening of our London office, the planned 2008 opening of a Singapore office, the redeployment of resources from our Moscow office as well as our earlier purchase of a 45 percent equity interest in Fusion, we have made significant investments to provide the necessary foundation and global reach required for an organic growth focus. Our organic growth is focused on undeveloped or underdeveloped fields, field redevelopments and exploration. While exploration will become a larger part of our overall portfolio, we will generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles. Exploration will be technically driven with a low entry cost and high resource potential that provides sustainable growth. We will continue to seek opportunities where perceived geopolitical risk may provide high reward opportunities in the long term. We will limit producing property acquisitions as market pricing of

proved producing reserves generally translates into low returns. Our WAB-21, South China Sea asset has been in our portfolio since 1996. Gabon and Indonesia are expected to be additions to our new strategy after receipt of government approvals.

WAB-21, South China Sea

Dussafu Marin, Offshore Gabon

In November 2007, we executed a sale and purchase agreement for the purchase of a 50 percent interest in the Dussafu PSC. All conditions precedent to the sale and purchase agreement are complete except for final government and partner approvals. We anticipate receiving final approvals during the first half of 2008. On receipt of final partner approval, we will become the operator of the Dussafu PSC. The purchase will be recorded in the quarter in which approvals are received. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC contains 680,000 acres with water depths to 1,000 feet. The Dussafu PSC has two small oil discoveries in the Gamba and Dentale reservoirs and a small natural gas discovery. Production and infrastructure exists in the blocks contiguous to the Dussafu PSC. The Dussafu PSC partners and the Republic of Gabon recently agreed to enter into the second exploration phase of the PSC with an effective date of May 28, 2007. The second exploration phase is a three-year work commitment which includes the acquisition and processing of 500 kilometers of 2-D seismic, geology and geophysical interpretation, engineering studies and the drilling of a conditional well. Leads in the underexplored syn-rift potential in the M’Baya and Lucina reservoirs that are commercial in immediately adjacent fields have been identified and are expected to be the focus of the planned 2008 work program which includes the acquisition and processing of 500 kilometers of 2-D seismic data. The Dussafu PSC partners anticipate prospects can be generated to test these play concepts in 2009.

Budong-Budong, Onshore Indonesia

In February 2008, Indonesia’s oil and gas regulatory authority, BP Migas, approved the assignment to us of a 47 percent interest in the Budong PSC located onshore West Sulawesi, Indonesia. Final government approval from Migas is pending. The Budong PSC includes a ten-year exploration period and a 20-year development phase. In the initial three-year exploration phase, which began January 2007, we expect to acquire, process and interpret approximately 500 kilometers of 2-D seismic and drill two exploration wells. Tately will be the operator through the exploration phase as required by the terms of the Budong PSC. We will have control of major decisions and financing for the project with an option to operate in the development and production phase if approved by BP Migas. The Budong PSC covers 1.35 million acres and includes the Lariang and Karama sub-basins which are the eastern onshore extension of the WSFB. Exploration to date in the basin is immature due to previously difficult jungle terrain, which is now accessible with the development of palm oil plantations and their related infrastructure. Field work performed over the last 10 years, as outcrops have been more accessible, has given a new understanding to the presence of Eocene source and reservoir potential that had not previously been recognized. Recent seismic surveys have greatly improved the understanding of the geology and enhanced the prospectivity of the offshore WSFB and, by analogy, the sparsely explored onshore area. To date, a total of eight leads have been recognized. It will be necessary to acquire a grid of seismic data to confirm the structures and give an indication of Eocene target(s) within the section and to mature these leads into drillable prospects. The two identified sub-basins (Lariang and Karama) provide an opportunity to test prospects in two sub-basins.

Results of Operations

We included the results of operations of Harvest Vinccler in our consolidated financial statements and reflected the 20 percent ownership interest of Vinccler as a minority interest in 2005 and the first quarter of 2006. Since April 1, 2006, equity investment in Petrodelta has been reflected under the equity method of accounting. In the fourth quarter of 2007, we recorded the cumulative effect from April 1, 2006 to December 31, 2007. See Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 7 – Venezuela Operations – Petrodelta, S.A. for Petrodelta’s results of operations which reflect the results for the nine month period ending December 31, 2006 and the twelve month period ending December 31, 2007, comparatively.

The following discussion should be read with the results of operations for each of the years in the three-year period ended December 31, 2007 and the financial condition as of December 31, 2007 and 2006 in conjunction with our Consolidated Financial Statements and related Notes thereto.

Years Ended December 31, 2007 and 2006

We reported net income of $57.2 million, or $1.51 diluted earnings per share, for 2007 compared with a net loss of $62.5 million, or $1.68 diluted earnings per share, for 2006.

Revenue recorded for the year ended December 31, 2007 reflects the reversal of deferred revenue recorded by Harvest Vinccler for 2005 and first quarter of 2006 deliveries pending clarification on the calculation of crude prices under the Transitory Agreement. See Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 1 – Organization and Summary of Significant Account Policies – Revenue Recognition. There were no sales of oil and natural gas in 2007 due to the conversion of the OSA to a minority equity interest in Petrodelta.

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


	Year Ended
	December 31,						Increase
	2007			2006			(Decrease)
General and administrative	$	29.7		$	26.4		$	3.3
Contribution to Science and Technology Fund		—			3.9			(3.9	)
Taxes other than on income		0.4			3.9			(3.5	)
Gain on financing transactions		(49.6	)		—			(49.6	)
Investment income and other		(9.1	)		(9.4	)		0.3
Interest expense		8.2			23.2			(15.0	)
Net (gain) loss on exchange rates		—			0.1			(0.1	)

General and administrative expenses increased due to employee related expenses offset by lower contract services. During the year ended December 31, 2007, we recorded a gain of $49.6 million as a result of the purchase and sale of U.S. Dollar indexed Venezuelan government bonds (see Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 12 – Gain on Financing Transaction). There were no such financing transactions entered into during the year ended December 31, 2006. Taxes other than on income decreased due to the elimination of municipal taxes which were based on oil deliveries under the OSA.

Investment earnings and other decreased due to interest earned on lower cash balances. Interest expense decreased due to the payment of Harvest Vinccler’s Bolivar denominated debt in the year ended December 31, 2007.

Income tax expense decreased due to the recording of Harvest Vinccler’s prior period tax assessments in the year ended December 31, 2006 and the reversal of deferred income taxes provided on Harvest Vinccler’s deferred revenue. We have utilized our current United States general and administrative expenses plus our net operating loss carryovers to offset the gains on financing transactions generated during the year ended December 31, 2007. There was no effect on our effective tax rate.

Years Ended December 31, 2006 and 2005

We reported a net loss of $62.5 million, or $1.68 diluted earnings per share, for 2006 compared with net income of $38.9 million, or $1.05 diluted earnings per share, for 2005.

Revenues were lower for the year ended December 31, 2006 compared with the year ended December 31, 2005 due to the conversion of the OSA to a minority equity interest in Petrodelta.

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


	Year Ended
	December 31,						Increase
	2006			2005			(Decrease)
General and administrative	$	26.4		$	22.8			3.6
Contribution to Science and Technology Fund		3.9			—			3.9
Account receivable write-off on retroactive oil price adjustment		—			4.5			(4.5	)
Taxes other than on income		3.9			6.4			(2.5	)
Investment income and other		(9.4	)		(4.2	)		(5.2	)
Interest expense		23.2			3.4			19.8
Net (gain) loss on exchange rates		0.1			(2.8	)		2.9

General and administrative expenses increased due to higher business development costs and employee related expenses. Taxes other than on income decreased due to the elimination of municipal taxes as a result of the conversion of the OSA to Petrodelta. Interest expense increased due to Harvest Vinccler’s estimated liability for interest of $52.9 million on the tax assessments as well as increased borrowings to pay the tax assessments.

In October 2006, the Executive Branch of the Venezuelan government issued the Regulations for the Science and Technology Law which established the methodology for determining the required investment, contribution or expenditure for the 2005 calendar year financial results. After release of the regulations, Harvest Vinccler accrued $3.9 million for the estimated liability for 2005 and the first quarter of 2006 based on its current understanding of the regulations.

Capital Resources and Liquidity

While we can give no assurance, we currently believe that Petrodelta will fund its own operations and pay a dividend prior to December 31, 2008, and that our cash on hand will provide sufficient capital resources and liquidity to fund our exploration and business development expenditures for the next 12 months. In Item 1A – Risk Factors, we discuss a number of variables and risks related to our investment in Petrodelta and exploration projects that could significantly affect our capital resources and liquidity. These risk factors include, but are not limited to, delays or inability of PPSA to pay for past and future crude oil and natural gas deliveries, the ability to implement Petrodelta’s Business Plan, changes in oil prices, fiscal and contractual stability, payment of a Petrodelta dividend and the ability to obtain financing for other projects. We also point out that the total capital required to develop the fields in Venezuela may exceed Petrodelta’s available cash and financing capabilities, and that there may be operational or contractual consequences to this inability. In addition, our ability to explore and develop growth opportunities outside of Venezuela is dependent upon the ability to receive dividends from Petrodelta and access debt and equity markets.

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 exploration and development of new oil and gas properties.

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. The Bolivar is not readily convertible into the U.S. Dollar. We do not expect the Venezuelan currency conversion restriction to adversely affect our ability to meet short-term loan obligations and operating requirements for the foreseeable future.

In March 2007, Venezuela announced that effective January 1, 2008, the currency unit of the monetary system of Venezuela will be redenominated to the equivalent of 1,000 current Bolivars. This means that the Bolivar dropped three zeros effective January 1, 2008. From January 1, 2008, all amounts of money became denominated in a new and smaller scale of Bolivars under the temporary name of Bolívares Fuertes, which after a period of time will bear again the name of Bolivars.

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. Our ability to acquire and develop growth opportunities outside of Venezuela is dependent upon the ability to receive dividends from Petrodelta and access debt and equity markets.

Debt. At December 31, 2007, Harvest Vinccler has debt of 20 billion Bolivars (approximately $9.3 million) which is secured by $6.8 million in restricted cash deposited in a U.S. bank. We have no other debt obligations.

Working Capital. Our capital resources and liquidity are affected by the ability of Petrodelta to pay dividends.

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 except as indicated)
	2007			2006			2005
Net cash provided by (used in) operating activities	$	(20,451	)	$	(24,448	)	$	114,665
Net cash provided by (used in) investing activities		69,756			(90,556	)		(15,647	)
Net cash provided by (used in) financing activities		(76,543	)		100,064			(20,599	)

Net increase (decrease) in cash	$	(27,238	)	$	(14,940	)	$	78,419


Working Capital		111,534			117,564			178,074
Current Ratio		3.6			2.4			3.9
Total Cash, including restricted cash		127,610			236,968			163,019
Total Debt		9,302			104,651			5,467
Percent of total debt to capitalization		3	%		27	%		2	%

The decrease in working capital of $6.0 million was primarily due to the inability to reflect a dividend from Petrodelta or collect the advances made by Harvest Vinccler to PDVSA in our consolidated financial statements for the year ended December 31, 2007 and the charge in the second and third quarters of 2006 of $73.8 million for additional taxes and related interest for the impact of income tax assessments by the SENIAT for 2001 through first quarter of 2006.

Cash Flow from Operating Activities. During the years ended December 31, 2007 and 2006, net cash used in operating activities was approximately $20.5 million and $24.4 million, respectively. The $3.9 million decrease was primarily due to the collection of accrued oil and gas sales receivable in the first quarter of 2006 which was offset by the charge in the second and third quarters of 2006 for the estimated tax assessments and related interest, as well as our inability to reflect a dividend from Petrodelta or collect the advances made by Harvest Vinccler to PDVSA beginning with the second quarter of 2006.

Cash Flow from Investing Activities. During the years ended December 31, 2007 and 2006, we had limited production-related capital expenditures. The reduction in capital expenditures was due to the continued suspension of our drilling program and the fact that our producing properties are now recognized under the equity method of accounting. We continued to advance funds during the period prior to the formation of Petrodelta for maintenance of the existing wells. After the formation of Petrodelta, capital commitments for Petrodelta will be determined by the Business Plan provided for in the Conversion Contract and the annual budget approved by the Petrodelta Board of Directors to implement the Business Plan. Outside of Venezuela, our capital commitments to date support our

business development efforts and are substantially at our discretion. During the year ended December 31, 2007, we invested $4.1 million of investigatory costs in support of our business development.

In January 2007, we purchased a 45 percent interest in Fusion for $4.6 million and HNR Finance funded its 40 percent share of Petrodelta for $2.8 million. During the year ended December 31, 2006, we deposited cash of $94.5 million as collateral for four loans with Venezuelan banks, of which $5.6 million had been returned to us. By December 31, 2006, the restricted cash balance was $88.9 million. During the year ended December 31, 2007, $82.1 million of the restricted cash was released and returned to us.

Cash Flow from Financing Activities. During the year ended December 31, 2007, Harvest Vinccler repaid 205 billion Bolivars (approximately $95.3 million) of its Bolivar denominated debt. Harvest Vinccler repaid the debt using a series of exchange transactions more fully described in Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 12 – Gain on Financing Transactions. During the year ended December 31, 2006, Harvest Vinccler borrowed 11 billion Bolivars (approximately $5.0 million) for short term Bolivar denominated obligations, 105 billion Bolivars (approximately $48.8 million) and 20 billion Bolivars (approximately $9.3 million) for the SENIAT income tax assessments and related interest and 120 billion Bolivars (approximately $55.8 million) for the SENIAT income tax assessments and related interest, to refinance previous borrowings and for operational needs. Also during the year ended December 31, 2006, Harvest Vinccler repaid $5.5 million of its U.S. Dollar debt (one payment of $0.3 million and four payments of $1.3 million each on the variable rate loans) and 31 billion Bolivars (approximately $14.3 million) of its Bolivar debt.

In June 2007, we announced that our Board of Directors had authorized the purchase of up to $50 million of our common stock from time to time through open market transactions. As of December 31, 2007, 3.0 million shares had been purchased under the program for $32.8 million, or an average cost of $11.09 per share, including commissions. At December 31, 2007, we had approximately 34.8 million shares outstanding.

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 Caracas, Venezuela for approximately $4,000 per month. This lease runs through December 2009.


	Payments (in thousands) Due by Period
			Less than						After 4
Contractual Obligation	Total		1 Year		1-2 Years		3-4 Years		Years
Long-Term Debt	$	9,302	$	9,302	$	—	$	—	$	—
Building Lease		1,795		342		333		216		904

Total	$	11,097	$	9,644	$	333	$	216	$	904

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, and 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. Dividends from Petrodelta will be denominated in U.S. Dollars when paid. Within the United States, inflation has had a minimal effect on us, but it is potentially an important factor with respect to results of operations in Venezuela.

In March 2007, Venezuela announced that effective January 1, 2008, the currency unit of the monetary system of Venezuela will be redenominated to the equivalent of 1,000 current Bolivars. This means that the Bolivar will drop three zeros effective January 1, 2008. From January 1, 2008, all amounts of money will become denominated in a new and smaller scale of Bolivars under the temporary name of Bolívares Fuertes, which after a period of time will bear again the name of Bolivars.

During the years ended December 31, 2007 and 2006, our net foreign exchange gains attributable to our international operations were minimal. The U.S. Dollar and Bolivar exchange rates have not been adjusted since March 2005. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, most 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.

An exemption under the Venezuelan Criminal Exchange Law for transactions in certain securities results in an indirect securities transaction market of foreign currency exchange, through which companies may obtain foreign currency legally without requesting it from the Venezuelan government. Publicly available quotes do not exist for the securities transaction exchange rate but such rates may be obtained from brokers. Securities transaction markets are used to move financial securities in and out of Venezuela.

In October 2007, the government of Venezuela announced the application of a new tax on financial transactions (the “TFT”) to private companies. The TFT does not apply to individuals. The tax was set at 1.5 percent of the value of the transaction. The TFT applies to all debits to bank accounts as well as payments of debt outside the banking system and is not tax deductible. The levy will be applied from November 1, 2007 through December 31, 2008. The TFT will not have a material effect on Harvest Vinccler’s financial position, results of operations or cash flows.

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.

Investment in Equity Affiliates

The equity method of accounting is used for companies and other investments in which we have significant influence. In January 2007, we purchased a 45 percent equity interest in Fusion. In October 2007, Petrodelta was formed, and the equity in earnings from April 1, 2006 to December 31, 2007 is reflected in the fourth quarter of 2007 consolidated statement of operations. These investments are increased or decreased by earnings/losses and decreased by dividends paid. No dividends were declared or paid by Fusion or Petrodelta in 2007.

Property and Equipment

In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method. Although the full cost method of accounting for oil and gas exploration and development continues to be an accepted method of accounting for oil and gas properties, the successful efforts method of accounting as prescribed by SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies is the preferred method. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 154 Accounting Changes and Error Corrections, financial information for prior periods has been restated to reflect retrospective application of the successful efforts method. We believe the successful efforts method provides a more transparent representation of our results of operations and the ability to assess our future investments in oil and gas properties for impairment based on their estimated fair values rather than being required to base valuation on prices and costs as of the balance sheet date. The significant differences between successful efforts and full cost accounting for oil and gas properties relate to the expensing of exploration activities and related unsuccessful exploratory drilling activities. The expensing of these costs can create volatility in the statement of operations. The change in accounting principle resulted in a cumulative, non-cash increase to retained earnings of $52.4 million, net of income tax, as of December 31, 2004. Retained earnings increased due to the reversal of ceiling test write downs in prior years required under the full cost accounting rules of the SEC. There were no such impairments under the successful efforts accounting rules. The effect of the accounting change on income from continuing operations for the years ended December 31, 2006 and 2005 was a decrease of $4.9 million and $15.0 million, net of income tax, or $0.13 and $0.39 per diluted share, respectively. The decrease in

income from continuing operations was due to an increase in depletion expense. There was no effect on cash and cash equivalents.

Oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.

Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. Exploratory drilling costs are capitalized when drilling is complete if it is determined that there is economic producibility supported by either actual production, conclusive formation test or by certain technical data. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the projects is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in production of natural gas and crude oil, are capitalized.

Depreciation, depletion, and amortization of the cost of proved oil and natural gas properties are calculated using the unit of production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. With respect to lease and well equipment costs, which include costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.

Assets are grouped in accordance with paragraph 30 of SFAS No. 19 Financial Accounting and Reporting by Oil and Gas Producing Companies. The basis for grouping is reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.

We account for impairments under the provisions of SFAS No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

Inventory held for use in the exploration for and development and production of natural gas and crude oil reserves are carried at cost with adjustments made from time to time to recognize any reductions in value.

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

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.

New Accounting Pronouncements

In February 2008, the FASB issued FASB Staff Position (“FSP”) 157-1 – Application of FASB Statement No. 157 to FASB Statement No. 13 and Its Related Interpretive Accounting Pronouncements That Address Leasing Transactions (“FSP 157-1”), which excludes SFAS 13 Accounting for Leases, and its related interpretive accounting pronouncements from the provisions of SFAS 157. FSP 157-1 is effective with the initial adoption of SFAS 157. FSP 157-1 will not have a material effect on our consolidated financial position, results of operations or cash flows.

In February 2008, the FASB issued FASB Staff Position (“FSP”) 157-2 – Effective Date of FASB Statement No. 157 (“FSP 157-2”), which delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until January 1, 2009. FSP 157-2 will not have a material effect on our consolidated financial position, results of operations or cash flows.

In February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS 159 – The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”), which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. SFAS 159 will not have a material effect on our consolidated financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS 141 (revised 2007) – Business Combinations (“SFAS 141R”). The objective of SFAS 141R is to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. When adopted, SFAS 141R is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS 160 – Noncontrolling Interest in Consolidated Financial Statements – an amendment of ARB No. 51 (“SFAS 160”). The objective of SFAS 160 is to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. When adopted, SFAS 160 is not expected to have a material effect on our consolidated results of operations or cash flows.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk from adverse changes in oil and natural gas prices, interest rates 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 West Texas Intermediate (“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 Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 1 – Organization and Summary of Significant Accounting Policies – Derivatives and Hedging for a complete discussion of our derivative activity. We had no hedging transactions in place for our 2004 or 2006 production.

Interest Rates

Total short-term debt at December 31, 2007 of $9.3 million consisted of Harvest Vinccler’s Bolivar denominated debt, which had a fixed rate for its initial twelve months. Total short-term debt at December 31, 2006 of $37.7 million consisted of Harvest Vinccler U.S. Dollar denominated fixed rate loans. A hypothetical 10 percent adverse change in the interest rate would not have a material effect on our results of operations.

Foreign Exchange

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 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-34.

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

None.

Item 9A. Controls and Procedures

The SEC 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 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. There have not been any changes in our internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter of 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Changes in Internal Control over Financial Reporting. The only changes to our internal controls since December 31, 2004, pertain to the change in accounting policy for our oil and natural gas exploration and development activities to the successful efforts method from the full cost method of accounting and equity accounting of our Unconsolidated Equity Affiliates. The internal controls have been modified as necessary in connection with our adoption of the successful efforts method of accounting and retrospectively revising financial information for prior periods.

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, 2007, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 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 1) recorded, processed, summarized and reported within the time periods as specified in the SEC’s rules and forms and 2) accumulated and communicated to our management, including our principal executive and principal financial officers, to allow timely decisions regarding required disclosure.

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 Rule 13a-15(f) and 15d-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, 2007. The effectiveness of our internal control over financial reporting as of December 31, 2007, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Please refer to the information under the captions “Election of Directors” and “Executive Officers” in our Proxy Statement for the 2008 Annual Meeting of Stockholders.

Item 11. Executive Compensation

Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the 2008 Annual Meeting of Stockholders.


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

Please refer to the information under the caption “Stock Ownership” in our Proxy Statement for the 2008 Annual Meeting of Stockholders.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Please refer to the information under the caption “Certain Relationships and Related Transactions” in our Proxy Statement for the 2008 Annual Meeting of Stockholders.

Item 14. Principal Accounting Fees and Services

Please refer to the information under the caption “Independent Registered Public Accounting Firm” in our Proxy Statement for the 2008 Annual Meeting of Stockholders.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) 1. Index to Financial Statements:


	Page
Report of Independent Registered Public Accounting Firm		S-1

Consolidated Balance Sheets at December 31, 2007 and 2006		S-2

Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005		S-3

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2007, 2006 and 2005		S-4

Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005		S-5

Notes to Consolidated Financial Statements		S-7

2. Consolidated Financial Statement Schedules and Other:


Schedule II — Valuation and Qualifying Accounts		S-36

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

(b) 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			Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on April 23, 2007, File No. 1-10762.)

	4.1			Form of Common Stock Certificate.

	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			Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A filed on October 23, 2007, File No. 1-10762.)

	10.1			2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-8 filed on April 9, 2002 (Registration Statement No. 333-85900).)

	10.2			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).)


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

	10.4	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.)

	10.5	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.)

	10.6	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.)

10.7^†		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.)

10.8^†		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.)

10.9^†		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.)

10.10^†		Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.24 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)

10.11^†		Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)

10.12^†		Stock Option Agreement dated September 26, 2005, between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.26 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)

10.13^†		Employment Agreement dated February 10, 2006 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on April 20, 2006, File No. 1-10762.)

	10.14	Harvest Natural Resources 2006 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on June 1, 2006 [Registration Statement No. 333-134630].)

	10.15	Form of 2006 Long Term Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)

	10.16	Form of 2006 Long Term Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)

	10.17	Form of 2006 Long Term Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)


10.18^†		Stock Unit Award 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 August 9, 2006, File No. 1-10762.)

10.19^†		Stock Unit Award Agreement dated March 2, 2006 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)

	10.20	Note Payable agreement dated November 20, 2006 between Harvest Vinccler, C.A. and Banesco Banco Universal C.A. related to a principal amount of 120 billion Bolivars with interest at 10.0 percent, for refinancing of the SENIAT assessments and operating requirements. (Incorporated by reference to Exhibit 10.32 to our Form 10-K filed on March 13, 2007, File No. 1-10762.)

	10.21	Form of 2006 Long Term Incentive Plan Stock Option Agreement – Five Year Vesting, Seven Year Term. (Incorporated by reference to Exhibit 10.33 to our Form 10-K filed on March 13, 2007, File No. 1-10762.)

	10.22	Amendment to Harvest Natural Resources 2006 Long Term Incentive Plan adopted July 19, 2006. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on May 3, 2007, File No. 1-10762.)

10.23^†		Employment Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)

10.24^†		Stock Option Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)

10.25^†		Employee Restricted Stock Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)

10.26^†		Consulting Agreement dated July 16, 2007 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)

	10.27	Contract for Conversion to a Mixed Company between Corporación Venezolana del Petróleo, S.A., Harvest-Vinccler, S.C.A. and HNR Finance B.V. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on November 1, 2007, File No. 1-10762.)

10.28^†		Separation Agreement dated November 16, 2007 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 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.

Report of Independent Registered Public Accounting Firm

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

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)1 present fairly, in all material respects, the financial position of Harvest Natural Resource, Inc. and its subsidiaries at December 31, 2007 and December 31, 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)2 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for oil and gas producing activities.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP
Houston, Texas
March 17, 2008

S-1

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2007			2006*
	*(in thousands, except per share data)*
ASSETS
Current Assets:
Cash and cash equivalents	$	120,841		$	148,079
Restricted cash		6,769			15,888
Accounts receivable, net		9,418			9,811
Advances to equity affiliate		16,352			19,146
Deferred income tax		—			5,608
Prepaid expenses and other		1,032			1,246

Total Current Assets		154,412			199,778
Restricted Cash		—			73,001
Other Assets		4,301			176
Investment in equity affiliates		251,173			192,090
Property and Equipment:
Oil and gas properties (successful efforts method)		3,163			2,900
Other administrative property		1,481			1,375

		4,644			4,275
Accumulated depletion, depreciation and amortization		(1,061	)		(955	)

Net Property and Equipment		3,583			3,320

	$	413,469		$	468,365


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable, trade and other	$	5,949		$	3,827
Accounts payable, related party		10,093			9,637
Accrued expenses		11,895			12,975
Accrued interest		5,136			6,850
Deferred revenue		—			11,217
Income taxes payable		503			34
Current portion of long-term debt		9,302			37,674

Total Current Liabilities		42,878			82,214
Long-Term Debt		—			66,977
Commitments and Contingencies		—			—
Minority Interest		56,825			37,765
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, 2007 and 2006; issued 38,513 shares and 37,974 shares at December 31, 2007 and 2006, respectively		385			380
Additional paid-in capital		201,938			194,176
Retained earnings		147,934			90,697
Treasury stock, at cost, 3,719 shares at December 31, 2007 and 770 shares at December 31, 2006, respectively		(36,491	)		(3,844	)

Total Stockholders’ Equity		313,766			281,409

	$	413,469		$	468,365


*		Financial information for 2006 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle.

See accompanying notes to consolidated financial statements.

S-2

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2007			2006*			2005*
	*(in thousands, except per share data)*
Revenues
Oil sales (a)	$	11,217		$	54,858		$	210,493
Gas sales		—			4,648			26,448

		11,217			59,506			236,941


Expenses
Operating expenses		—			9,241			39,723
Depletion, depreciation and amortization		384			15,435			58,922
Exploration expense		204			—			—
General and administrative		29,742			26,421			22,819
Contribution to Science and Technology Fund		—			3,887			—
Account receivable write-off on retroactive oil price adjustments		—			—			4,548
Taxes other than on income		423			3,948			6,358

		30,753			58,932			132,370


Income (Loss) from Operations		(19,536	)		574			104,571
Other Non-Operating Income (Expense)
Gain on Financing Transactions		49,623			—			—
Investment earnings and other		9,065			9,406			4,205
Interest expense		(8,224	)		(23,156	)		(3,388	)
Net gain (loss) on exchange rates		(14	)		(121	)		2,752

		50,450			(13,871	)		3,569


Income (Loss) from Consolidated Companies Before Income Taxes and Minority Interest		30,914			(13,297	)		108,140
Income Tax Expense		6,312			60,917			57,025

Income (Loss) Before Minority Interest		24,602			(74,214	)		51,115
Minority Interest in Consolidated Subsidiary Companies		19,060			(11,712	)		12,239

Income (loss) from Consolidated Companies		5,542			(62,502	)		38,876
Net Income from Unconsolidated Equity Affiliates		51,695			—			—

Net Income (Loss)	$	57,237		$	(62,502	)	$	38,876


Net Income (Loss) Per Common Share:
Basic	$	1.57		$	(1.68	)	$	1.05

Diluted	$	1.51		$	(1.68	)	$	1.01


(a)		Recognition of deferred revenue – See Note 1 – Organization and Summary of Significant Accounting Policies – Revenue Recognition.

*		Financial information for 2006 and 2005 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle.

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, 2005		37,544	$	375	$	185,183	$	114,323		$	(487	)	$	(3,779	)	$	295,615

Issuance of common shares:
Exercise of stock options		139		3		829		—			—			—			832
Employee stock-based compensation		74		—		2,230		—			—			—			2,230
Purchase of Treasury Shares		—		—		—		—			—			(65	)		(65	)
Accumulated other comprehensive gain		—		—		—		—			487			—			487
Net Income*		—		—		—		38,876			—			—			38,876


Balance at December 31, 2005		37,757		378		188,242		153,199			—			(3,844	)		337,975

Issuance of common shares:
Exercise of stock options		137		1		879		—			—			—			880
Employee stock-based compensation		80		1		5,055		—			—			—			5,056
Net Loss *		—		—		—		(62,502	)		—			—			(62,502	)


Balance at December 31, 2006		37,974		380		194,176		90,697			—			(3,844	)		281,409

Issuance of common shares:
Exercise of stock options		402		4		1,934		—			—			—			1,938
Employee stock-based compensation		137		1		5,828		—			—			—			5,829
Purchase of Treasury Shares		—		—		—		—			—			(32,647	)		(32,647	)
Net Income		—		—		—		57,237			—			—			57,237


Balance at December 31, 2007		38,513	$	385	$	201,938	$	147,934		$	—		$	(36,491	)	$	313,766


*		Financial information for 2006 and 2005 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle.

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,
	2007			2006*			2005*
	*(in thousands)*
Cash Flows From Operating Activities:
Net income (loss)	$	57,237		$	(62,502	)	$	38,876
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		384			15,435			58,922
Exploration expense		204			—			—
Gain on financing transactions		(49,623	)		—			—
Net income from unconsolidated equity affiliates		(51,695	)		—			—
Account receivable write-off on retroactive oil price adjustments		—			—			4,548
Deferred compensation expense		—			—			(745	)
Non-cash compensation related charges		6,108			5,056			2,230
Minority interest in consolidated subsidiary companies		19,060			(11,712	)		12,239
Deferred income taxes		5,608			(2,556	)		2,982
Changes in operating assets and liabilities:
Accounts and notes receivable		393			61,839			(4,481	)
Advances to equity affiliate		2,794			(19,146	)		—
Prepaid expenses and other		214			903			(723	)
Commodity hedging contract		—			—			14,947
Accounts payable		2,122			3,419			(8,020	)
Accounts payable, related party		456			434			(1,860	)
Accrued expenses		(1,251	)		(5,469	)		(10,165	)
Accrued interest		(1,714	)		4,213			2,565
Deferred revenue		(11,217	)		4,489			6,728
Asset retirement liability		—			24			188
Income taxes payable		469			(18,875	)		(3,566	)

Net Cash Provided By (Used In) Operating Activities		(20,451	)		(24,448	)		114,665

Cash Flows from Investing Activities:
Additions of property and equipment		(851	)		(1,657	)		(16,147	)
Investments in equity affiliates		(7,388	)		(513	)		—
(Increase) decrease in restricted cash		82,120			(88,889	)		28
Investment costs		(4,125	)		503			472

Net Cash Provided By (Used In) Investing Activities		69,756			(90,556	)		(15,647	)

Cash Flows from Financing Activities:
Net proceeds from issuances of common stock		1,938			880			767
Purchase of treasury stock		(32,755	)		—			—
Proceeds from issuance of notes payable		—			118,953			—
Payments of note payable		(45,726	)		(19,769	)		(6,366	)
Dividend paid to minority interest		—			—			(15,000	)

Net Cash Provided By (Used In) Financing Activities		(76,543	)		100,064			(20,599	)

Net Increase (Decrease) in Cash and Cash Equivalents		(27,238	)		(14,940	)		78,419
Cash and Cash Equivalents at Beginning of Year		148,079			163,019			84,600

Cash and Cash Equivalents at End of Year	$	120,841		$	148,079		$	163,019

Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for interest expense	$	7,972		$	23,171		$	795

Cash paid during the year for income taxes	$	201		$	62,505		$	20,991


*		Financial information for 2006 and 2005 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle.

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

On March 31, 2006, Harvest Vinccler signed a Memorandum of Understanding (the “MOU”) with two affiliates of PDVSA, Corporación Venezolana del Petroleo S.A. (“CVP”) and PDVSA Petroleo S.A. (“PPSA”), to convert its Operating Service Agreement (“OSA”) into a minority interest in Petrodelta. On August 16, 2006, the MOU was amended to provide for the addition of the Isleño, El Salto and Temblador fields (“New Fields”) to Petrodelta as additional consideration for the conversion of the OSA to Petrodelta. On December 18, 2006, at our special meeting of the stockholders, the transactions contemplated by the MOU were approved. On September 11, 2007, we signed the Contract of Conversion (“Conversion Contract”), and on October 3, 2007, together with CVP, we formed and funded Petrodelta. On October 25, 2007, the Presidential Decree which formally transferred to Petrodelta the rights to the Uracoa, Tucupita and Bombal fields (“SMU Fields”) and the New Fields, subject to the conditions of the Conversion Contract, was published in the Official Gazette. Harvest Vinccler has transferred all of its tangible assets and contracts, permits and rights related to the SMU Fields in Venezuela to Petrodelta. In January 2008, a majority of Harvest Vinccler’s employees accepted positions with Petrodelta. Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the SMU Fields and New Fields (collectively “Petrodelta Fields”). HNR Finance B.V. (“HNR Finance”) has a 40 percent ownership interest in Petrodelta. As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta, and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining eight percent interest. CVP will own the remaining 60 percent. At our request, CVP has added HNR Finance as a party to the Conversion Contract. Petrodelta is governed by its own charter and bylaws.

Principles of Consolidation

Investment in Equity Affiliates

The equity method of accounting is used for companies and other investments in which we have significant influence. In January 2007, we purchased a 45 percent equity interest in Fusion Geophysical, L.L.C. (“Fusion”). In October 2007, Petrodelta was formed, and the equity in earnings from April 1, 2006 to December 31, 2007 is reflected in the fourth quarter of 2007 consolidated statement of operations. These investments are increased or decreased by earnings/losses and decreased by dividends paid and amortization of basis differential. No dividends were declared or paid by Fusion or Petrodelta in 2007.

Reporting and Functional Currency

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

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Revenue Recognition

Oil and natural gas revenue is accrued monthly based on production and delivery. Until March 31, 2006, each quarter, Harvest Vinccler invoiced 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 OSA with PDVSA provided 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 could not 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 provided 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 approximated 47 percent of West Texas Intermediate (“WTI”). The operating fee was subject to quarterly adjustments to reflect changes in the special energy index of the U.S. Consumer Price Index. Until March 31, 2006, each quarter Harvest Vinccler also invoiced 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 was invoiced to PDVSA quarterly at a fixed price of $7.00 per Bbl. The invoices were prepared and submitted to PDVSA by the end of the first month following the end of each calendar quarter, and payment was due from PDVSA by the end of the second month following the end of each calendar quarter. Harvest Vinccler invoiced PDVSA for the first quarter 2006 delivery of its crude oil and natural gas in accordance with the Transitory Agreement. With the formation of Petrodelta, Harvest Vinccler recognized deferred revenue of $11.2 million for 2005 and first quarter 2006 deliveries that had been deferred 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, 2007, Harvest Vinccler had 4.7 billion Venezuela Bolivars (“Bolivars”) which are shown in the December 31, 2007 financial statements as $2.4 million in cash and cash equivalents.

Restricted Cash

Restricted cash represents cash and cash equivalents held in a U.S. bank used as collateral for Harvest Vinccler’s loan agreement, and is classified as current or non-current based on the terms of the agreement. See Note 2 — Long-Term Debt and Liquidity.

Credit Risk and Operations

All of our total consolidated revenues relate to operations in Venezuela. During the years ended December 31, 2006 and 2005, our Venezuelan crude oil and natural gas production represented all of our total production from consolidated companies. Petrodelta’s sole source of revenues for its production is PPSA, which maintains full ownership of all hydrocarbons in its fields. The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PPSA which was signed on January 17, 2008. As of December 31, 2007, Petrodelta has not been paid by PPSA for its oil and natural gas deliveries from April 1, 2006 through December 31, 2007. Until payment is received for the deliveries or PPSA advances funds on crude oil and natural gas deliveries, Petrodelta will be unable to pay a dividend.

Derivatives and Hedging

Statement of Financial Accounting Standards (“SFAS”) No. 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

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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.

We had no hedging instruments in place for our 2004 or 2006 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 qualified under the highly effective test. There was no mark-to-market gain/loss at December 31, 2005.

Deferred net losses recorded in Accumulated Other Comprehensive Loss at December 31, 2004 were reclassified to earnings during 2005. There was no difference between net income and comprehensive net income for the year ended December 31, 2005. All hedging instruments expired under their own terms on December 31, 2005.

Accounts and Notes Receivable

Allowance for doubtful accounts related to former employee notes at December 31, 2007 and 2006 was $2.8 million.

Other Assets

Other assets consist of investigative costs associated with new business development projects. These 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

In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method. Although the full cost method of accounting for oil and gas exploration and development continues to be an accepted method of accounting for oil and gas properties, the successful efforts method of accounting as prescribed by SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies is the preferred method. In accordance with SFAS No. 154 Accounting Changes and Error Corrections, financial information for prior periods has been restated to reflect retrospective application of the successful efforts method. We believe the successful efforts method provides a more transparent representation of our results of operations and the ability to assess our future investments in oil and gas properties for impairment based on their estimated fair values rather than being required to base valuation on prices and costs as of the balance sheet date. The significant differences between successful efforts and full cost accounting for oil and gas properties relate to the expensing of exploration activities and related unsuccessful exploratory drilling activities. The expensing of these costs can create volatility in the statement of operations. The change in accounting principle resulted in a cumulative, non-cash increase to retained earnings of $52.4 million, net of income tax, as of December 31, 2004. Retained earnings increased due to the reversal of ceiling test write downs in prior years required under the full cost accounting rules of the Securities and Exchange Commission (“SEC”). There were no such impairments under the successful efforts accounting rules. The effect of the accounting change on income from continuing operations for the years ended December 31, 2006 and 2005 was a decrease of $4.9 million and $15.0 million, net of income tax, or $0.13 and $0.39 per diluted share, respectively. The decrease in income from continuing operations was due to an increase in depletion expense. There was no effect on cash and cash equivalents.

Properties and equipment are stated at cost less accumulated depreciation, depletion and amortization (“DD&A”). Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement

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or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if appropriate, gains or losses are recognized in Investment Earnings and Other.

Exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense. Costs of drilling successful exploratory wells, all development wells, and related production equipment and facilities are capitalized and depleted or depreciated using the unit-of-production method as oil and gas is produced.

Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent associated with successful exploration activities. Costs of maintaining and retaining undeveloped leaseholds, as well as amortization and impairment of unsuccessful leases, are included in exploration expense. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties.

Proved oil and gas properties are reviewed for impairment for which identifiable cash flows are independent of cash flows of other assets when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are determined based on estimated future oil and gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these undiscounted estimated future net cash flows is less than the carrying amount of the property, an impairment loss is recognized for the excess, if any, of the property’s carrying amount over its estimated fair value, which is generally based on discounted future net cash flows.

Costs of drilling and equipping successful exploratory wells, development wells, asset retirement costs and costs to construct or acquire offshore platforms and other facilities, are depreciated using the unit-of-production method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved leaseholds, are depleted using the unit-of-production method based on total estimated proved developed and undeveloped reserves. All other properties are stated at historical acquisition cost, net of allowance for impairment, and depreciated using the straight-line method over the useful lives of the assets.

Undeveloped property costs consist of $2.9 million for WAB-21, $0.1 million for the Dussafu Marin exploration production sharing contract (“Dussafu PSC”) and $0.2 million for the Budong-Budong production sharing contract (“Budong PSC”). None of these costs are being amortized and have not been impaired.

Depreciation of furniture and fixtures is computed using the straight-line method with depreciation rates based upon the estimated useful life of the property, generally 5 years. Leasehold improvements are depreciated over the life of the applicable lease. Depreciation expense was $0.4 million, $0.6 million and $2.8 million for the years ended December 31, 2007, 2006 and 2005, respectively.

Stock-Based Compensation

At December 31, 2007 and 2006, 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 SFAS No. 123 (“FAS 123”), Accounting for Stock-Based Compensation as amended by SFAS No. 148 (“SFAS 148”), prospectively to all employee awards granted, modified, or settled after January 1, 2003. Effective January 1, 2005, we adopted SFAS 123 (revised 2004) Share-Based Payment (“SFAS 123R”) to all employee awards granted, modified, or settled after October 1, 2005. The effect of the adoption of 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 year ended December 31, 2005 is less than that which would have been

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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
	(in thousands, except per share data)
Net income, as reported	$	38,876

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

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


Net income — proforma	$	38,800

Net income per common share:
Basic — as reported	$	1.05

Basic — proforma	$	1.05


Diluted — as reported	$	1.01

Diluted — proforma	$	1.01

Stock options of 0.4 million, 0.1 million and 0.2 million were exercised in the years ended December 31, 2007, 2006 and 2005, respectively, with cash proceeds of $1.9 million, $0.9 million and $0.8 million, respectively.

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. With the formation of Petrodelta, Harvest Vinccler recognized the deferred tax related to the deferred revenue discussed above.

Foreign Currency

Most of our operations are outside of the United States. 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.

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.

Minority Interests

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

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Change in Accounting Principle

In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method. Although the full cost method of accounting for oil and gas exploration and development continues to be an accepted method of accounting for oil and gas properties, the successful efforts method of accounting as prescribed by SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies is the preferred method. In accordance with SFAS No. 154 Accounting Changes and Error Corrections, financial information for prior periods has been restated to reflect retrospective application of the successful efforts method. We believe the successful efforts method provides a more transparent representation of our results of operations and the ability to assess our future investments in oil and gas properties for impairment based on their estimated fair values rather than being required to base valuation on prices and costs as of the balance sheet date. The significant differences between successful efforts and full cost accounting for oil and gas properties relate to the expensing of exploration activities and related unsuccessful exploratory drilling activities. The expensing of these costs can create volatility in the statement of operations. The change in accounting principle resulted in a cumulative, non-cash increase to retained earnings of $52.4 million, net of income tax, as of December 31, 2004. Retained earnings increased due to the reversal of ceiling test write downs in prior years required under the full cost accounting rules of the SEC. There were no such impairments under the successful efforts accounting rules. The effect of the accounting change on income from continuing operations for the years ended December 31, 2006 and 2005 was a decrease of $4.9 million and $15.0 million, net of income tax, or $0.13 and $0.39 per diluted share, respectively. The decrease in income from continuing operations was due to an increase in depletion expense. There was no effect on cash and cash equivalents.

New Accounting Pronouncements

In February 2008, the FASB issued FASB Staff Position (“FSP”) 157-1 — Application of FASB Statement No. 157 to FASB Statement No. 13 and Its Related Interpretive Accounting Pronouncements That Address Leasing Transactions (“FSP 157-1”), which excludes SFAS 13 Accounting for Leases, and its related interpretive accounting pronouncements from the provisions of SFAS 157. FSP 157-1 is effective with the initial adoption of SFAS 157. FSP 157-1 will not have a material effect on our consolidated financial position, results of operations or cash flows.

In February 2008, the FASB issued FASB Staff Position (“FSP”) 157-2 — Effective Date of FASB Statement No. 157 (“FSP 157-2”), which delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until January 1, 2009. FSP 157-2 will not have a material effect on our consolidated financial position, results of operations or cash flows.

In February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS 159 — The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”), which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. SFAS 159 will not have a material effect on our consolidated financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS 141 (revised 2007) — Business Combinations (“SFAS 141R”). The objective of SFAS 141R is to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. When adopted, SFAS 141R is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS 160 — Noncontrolling Interest in Consolidated Financial Statements — an amendment of ARB No. 51 (“SFAS 160”). The objective of SFAS 160 is to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning

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on or after December 15, 2008. Early adoption is prohibited. When adopted, SFAS 160 is not expected to have a material effect on our consolidated results of operations or cash flows.

Use of Estimates

The preparation of financial statements in conformity with GAAP 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 and natural gas reserve volumes and future development costs. Actual results could differ from those estimates.

Note 2 — Long-Term Debt and Liquidity

Long-Term Debt

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


	December 31,		December 31,
	2007		2006
Note payable with interest at 10.0%	$	—	$	55,814
Note payable with interest at 10.0%		—		39,535
Note payable with interest at 12.5%		9,302		9,302

		9,302		104,651

Less current portion		9,302		37,674

	$	—	$	66,977

On September 27, 2006, Harvest Vinccler entered into a three-year term loan with a Venezuelan bank for 105 billion Bolivars (approximately $48.8 million). The first principal payment was due 360 days after the funding date in the amount of 21 billion Bolivars (approximately $9.8 million), and 21 billion Bolivars (approximately $9.8 million) every 180 days thereafter. The interest rate for the first year was fixed at 10.0 percent and was renegotiated for the second year subject to a maximum of 95 percent of the average interest rate charged by six major Venezuelan banks. The interest rate was adjusted to 12.5 percent on October 1, 2007. The loan was used to meet income tax assessments and related interest of the SENIAT, the Venezuelan income tax authority. The loan was repaid on October 18, 2007.

On October 3, 2006, Harvest Vinccler entered into a term loan with a Venezuelan bank for 20 billion Bolivars (approximately $9.3 million). The original loan matured on April 2, 2007. At maturity, Harvest Vinccler and the Venezuelan bank agreed to extend the loan for an additional 180 days subject to the same terms and conditions. The extended loan matured September 28, 2007 at a fixed interest rate of 10.0 percent. The loan was repaid on September 28, 2007.

On November 20, 2006, Harvest Vinccler entered into a three-year term loan with a Venezuelan bank for 120 billion Bolivars (approximately $55.8 million). The first principal payment was due 180 days after the funding date in the amount of 20 billion Bolivars (approximately $9.3 million), and 20 billion Bolivars (approximately $9.3 million) every 180 days thereafter. The interest rate for the first 180 days was fixed at 10.0 percent and may be adjusted from time to time thereafter within the limits set forth by the Central Bank of Venezuela or in accordance with the conditions in the financial market. The interest rate was adjusted to 12.5 percent on October 1, 2007. The loan is collateralized by a $6.8 million deposit plus interest in a U.S. bank. The loan was used to meet the SENIAT income tax assessments and related interest, refinance a portion of the 105 billion Bolivar loan and to fund operating requirements.

During the ten months ended October 31, 2007, we exchanged through an intermediary, U.S. government securities for U.S. Dollar indexed Venezuelan government securities that can only be converted into Bolivars. The additional Bolivars were used to pay down Harvest Vinccler’s Bolivar denominated debt. Harvest Vinccler reduced

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its Bolivar denominated debt to 20.0 billion Bolivars (approximately $9.3 million) by October 30, 2007 using exchange transactions as more fully described in Note 12 — Gain on Financing Transaction and in advance of the effective date for the Tax on Financial Transactions described in Note 4 — Taxes.

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, 2008.

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 signed a five-year lease for office space in Caracas, Venezuela for $4,000 per month.

Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-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. In April 2007, the Court lifted the abatement and set the case for trial. The trial date has been set in the second quarter 2008. We dispute Excel’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.

Uracoa Municipality Tax Assessments. Harvest Vinccler has received nine assessments from a tax inspector for the Uracoa municipality in which part of the SMU Fields are located as follows:

	•		Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the capital fee reimbursement and related interest paid by PDVSA under the OSA. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims.

	•		Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the Municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims.

	•		Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim.

	•		Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims.

Libertador Municipality Tax Assessments. Harvest Vinccler has received five assessments from a tax inspector for the Libertador municipality in which part of the SMU Fields are located as follows:

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	•		One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the Municipality. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim.

	•		Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claims.

	•		Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claims.

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 paid municipal taxes through the first quarter 2006 on operating fee revenues it received under the OSA for deliveries from the SMU Fields. In September 2006, PDVSA remitted to the Uracoa municipality an additional $1.0 million in municipal taxes based on the new tax rates from amounts that had been withheld by PDVSA from Harvest Vinccler’s first quarter 2006 oil and natural gas sales for other purposes. The components of taxes other than on income were (in thousands):


	2007		2006		2005
Venezuelan municipal taxes	$	—	$	3,191	$	5,788
Franchise taxes		166		175		(70	)
Payroll and other taxes		257		582		640

	$	423	$	3,948	$	6,358

Contribution to Science and Technology Fund

In 2005, Venezuela modified the Science and Technology Law to require companies doing business in Venezuela to invest, contribute, or spend a percentage of their gross revenue on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. In October 2006, the Executive Branch issued the Regulations for the Science and Technology Law which established the methodology for determining the required investment, contribution or expenditure for the 2005 calendar year financial results. Harvest Vinccler was unable to estimate the corresponding percentage of the gross revenue for 2005 or the first quarter of 2006 until the regulations were released as many aspects of the law were unclear. After release of the regulations, Harvest Vinccler accrued $3.9 million for the estimated liability for 2005 and the first quarter of 2006 based on its current understanding of

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the regulations. Harvest Vinccler did not have any gross revenue subject to this law after March 31, 2006. The regulation provides that the amount that is not invested, contributed or spent must be deposited with an official agency created to administrate the law which has yet to be formed. This liability will be paid in the first quarter of 2008.

Tax on Financial Transactions

Taxes on Income

The tax effects of significant items comprising our net deferred income taxes as of December 31, 2006 are as follows (in thousands):


	2006
Deferred tax assets:
Operating loss carryforwards	$	7,466
Difference in basis of assets		25,343
Deferred revenue		5,608
Valuation allowance		(32,809	)

Net deferred tax asset		5,608
Less current portion		5,608

	$	—

The valuation allowance decreased by $32.8 million as a result of the elimination of the U.S. deferred tax assets related to the net operating loss carryforward and the basis difference on our Venezuelan assets prior to converting to Petrodelta. Realization of deferred tax assets associated with net operating loss carryforwards is dependent upon generating sufficient taxable income prior to their expiration. Management anticipates that additional losses will be generated and that it is more likely than not that they will not be realized through future taxable income.

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


	2007			2006			2005
Income (loss) before income taxes
United States	$	(17,786	)	$	(15,688	)	$	8,178
Foreign		48,700			2,391			99,962

Total	$	30,914		$	(13,297	)	$	108,140

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


	2007		2006			2005
Current:
United States	$	400	$	—		$	739
Foreign		5,912		63,473			53,304

		6,312		63,473			54,043

Deferred:
Foreign		—		(2,556	)		2,982

	$	6,312	$	60,917		$	57,025

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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):


	2007			2006			2005
Computed tax expense (benefit) at the statutory rate	$	10,820		$	(2,930	)	$	43,083
Effect of foreign source income and rate differentials on foreign income		(11,140	)		8,563			16,065
Change in valuation allowance		1,085			5,446			13,129
Alternative minimum tax		—			—			739
Deemed income inclusion		12,942			—			—
Venezuela tax settlement		—			49,793			—
Net operating loss utilization		(7,306	)		—			(15,567	)
Other		(89	)		45			(424	)

Total income tax expense	$	6,312		$	60,917		$	57,025

Rate differentials for foreign income result from tax rates different from the U.S. tax rate being applied in foreign jurisdictions.

The net operating loss carryforwards from 2006 for U.S. federal income tax purposes were fully utilized at December 31, 2007.

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.

FIN 48 Disclosure

In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of SFAS 109, Accounting for Income Taxes (“FIN 48”), to create a single model to address accounting for uncertainty in tax positions. FIN 48 clarifies the accounting for income taxes, by prescribing a minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We have adopted FIN 48 as of January 1, 2007, as required.

We or one of our subsidiaries files income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2004. To date, the Internal Revenue Service (“IRS”) has not performed an examination of our U.S. income tax returns for 2004 through 2006.

The adoption of FIN 48 has not had a significant impact on our consolidated financial position, results of operations or cash flows. We do not have any unrecognized tax benefits.

Note 5 — Stock Option and Stock Purchase Plans

In May 2006, our shareholders approved the 2006 Long Term Incentive Plan (the “2006 Plan”). The 2006 Plan provides for the issuance of up to 1,825,000 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 2006 Plan, no more than 325,000 shares may be granted as restricted stock. No individual may be granted more than 900,000 options or SARs and no more than 175,000 shares of restricted stock during any period of three consecutive calendar years. The exercise price of stock options granted under the 2006 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted through December 31, 2006 vest ratably over a three to five year period from their dates of grant and expire seven to ten years from grant date. Restricted

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stock granted to employees or consultants to date is subject to a restriction period of not less than 36 months during which the stock will be deposited with Harvest Natural Resources, Inc. (“Harvest”) and is subject to forfeiture under certain circumstances. Restricted stock granted to non-employee directors vests as to one-third of the shares on each anniversary of the date of grant of the award provided that he is still a director on that date. The 2006 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. No employee or consultant shall be granted a performance award during a calendar year that could result in a cash payment of more than $5.0 million. 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 May 2004, our shareholders approved the 2004 Long Term Incentive Plan (the “2004 Plan”). The 2004 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 2004 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 2004 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted to date 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 Harvest and is subject to forfeiture under certain circumstances. The 2004 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 July 2001, our shareholders approved the 2001 Long Term Stock Incentive Plan (the “2001 Plan”). The 2001 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 2001 Plan must be no less than the fair market value of our common stock on the date of grant. No officer may be granted more than 500,000 options during any one fiscal year, as adjusted for any 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 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, 2007, 2006 and 2005 and changes during the years ending on those dates is presented below (shares in thousands):


	2007						2006						2005
	Weighted						Weighted						Weighted
	Average						Average						Average
	Exercise						Exercise						Exercise
	Price			Shares			Price			Shares			Price			Shares
Outstanding at beginning of the year:	$	7.70			4,123		$	8.61			4,070		$	8.18			3,793
Options granted		9.63			866			10.62			558			11.51			922
Options exercised		(4.73	)		(397	)		(5.69	)		(65	)		(3.45	)		(241	)
Options cancelled		(13.49	)		(420	)		(19.96	)		(440	)		(14.24	)		(404	)

Outstanding at end of the year		7.80			4,172			7.70			4,123			8.61			4,070

Exercisable at end of the year		5.87			2,372			5.91			2,719			7.40			2,886

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Significant option groups outstanding at December 31, 2007 and related weighted average price and life information follow (shares 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 12/31/07		Life		Price		Value		at 12/31/07		Price		Value
$ 1.55 - $ 2.75		1,295		2.29	$	2.02	$	13,576		1,295	$	2.02	$	13,576
$ 4.86 - $ 7.10		226		4.78		5.82		1,509		226		5.82		1,509
$ 8.72 - $ 10.91		1,906		7.40		9.90		4,958		300		9.32		954
$12.50 - $ 13.90		745		6.89		13.09		—		551		13.06		—

		4,172					$	20,043		2,372			$	16,039

The aggregate intrinsic value in the preceding table represents the total pretax intrinsic value based on our closing stock price of $12.50 as of December 31, 2007, which would have been received by the option holders had all option holders exercised their options as of that date. Of the number outstanding, 408,750 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:


	2007			2006			2005
Weighted average fair value	$	4.67		$	5.98		$	6.35
Weighted averaged expected life		7			7			7
Valuation assumptions:
Expected volatility		47.7-48.7	%		49.9%-53.3	%		50.0%-53.4	%
Risk-free interest rate		4.5%-4.6	%		4.6%-5.2	%		3.9%-4.6	%
Expected dividend yield		0	%		0	%		0	%
Expected annual forfeitures		3	%		3	%		3	%

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 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.

A summary of our nonvested shares as of December 31, 2007, and changes during the year ended December 31, 2007, is presented below (shares in thousands):


				Weighted-Average
				Grant-Date
Nonvested Shares	Shares			Fair Value
Nonvested at January 1, 2007		1,404		$	6.75
Granted		916			4.67
Vested		(420	)		(7.48	)
Forfeited		(50	)		(9.63	)

Nonvested at December 31, 2007		1,850		$	5.83

As of December 31, 2007, there was $5.5 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under our plans. That cost is expected to be recognized

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over the next three to five years. The total fair value of shares vested during the years ended December 31, 2007, 2006 and 2005 was $4.5 million, $4.1 million and $2.7 million, respectively.

In addition to options issued pursuant to the plans, options have been issued to individuals other than our directors or employees at $10.07 which vest over three years. At December 31, 2007, a total of 50,000 options issued outside of the plans were outstanding with none 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. With the formation of Petrodelta, we have recorded the results of operations and economic benefits of our ownership in Petrodelta from April 1, 2006 through December 31, 2007 in the fourth quarter of 2007 as Net Income from Unconsolidated Equity Affiliates. Oil and gas sales for 2007 is the recognition of the deferred revenue recorded by Harvest Vinccler for 2005 and first quarter 2006 deliveries pending clarification on the calculation of crude prices under the Transitory Agreement (see Note 1 — Organization and Summary of Significant Accounting Policies — Revenue Recognition). Operations included under the heading “United States and Other” include corporate management, cash management, business development 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.


	2007			2006			2005
	(in thousands)
Segment Revenues
Oil and gas sales:
Venezuela	$	11,217		$	59,506		$	236,941

Total oil and gas sales		11,217			59,506			236,941


Segment Income (Loss)
Venezuela		76,276			(46,835	)		52,133
United States and other		(19,039	)		(15,667	)		(13,257	)

Net income (loss)	$	57,237		$	(62,502	)	$	38,876


	December 31,			December 31,
	2007			2006
	(in thousands)
Operating Segment Assets
Venezuela	$	303,042		$	351,943
United States and other		126,766			155,973

		429,808			507,916
Intersegment eliminations		(16,339	)		(39,551	)

	$	413,469		$	468,365

Note 7 — Venezuela Operations — Petrodelta S.A.

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Petrodelta has adopted policies and procedures governing its operations, including, among others, policies and procedures for safety, health and environment, contracting, maintenance of insurance, accounting, banking and treasury and human resources, following the guidelines established by CVP. To the extent possible, such policies and procedures will be consistent with the policies and procedures of PDVSA and the ultimate parent company of HNR Finance. Petrodelta has hired personnel, largely from Harvest Vinccler; and the Board of Directors of Petrodelta has appointed the management of Petrodelta. Certain of these appointments are made by the shareholders. Effective August 9, 2007, Mr. Karl L. Nesselrode, Vice President, Engineering and Business Development of Harvest, accepted a long-term secondment to Petrodelta as its Operations and Technical Manager. Per Petrodelta’s bylaws, the Operations and Technical Manager’s position is designated as our appointment. Mr. Nesselrode will remain an officer of Harvest. The General Manager of Petrodelta (CVP appointment) has been appointed by the Board of Directors of Petrodelta. This position is in charge of the daily management of the business of Petrodelta and has the power and duties customary to manage, direct and supervise the accounting of Petrodelta.

The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PPSA signed on January 17, 2008. The form of the agreement is set forth in Annex K to the Conversion Contract. Crude oil delivered from the Petrodelta Fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets, and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference priced and prevailing market conditions. Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make payment to Petrodelta of each invoice within 60 days of the end of the invoiced production month by wire transfer, in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered, and in Bolivars in the case of payment for natural gas delivered, in immediately available funds to the bank accounts designated by Petrodelta. Any dividend paid by Petrodelta will be made in U.S. Dollars.

HNR Finance owns a 40 percent interest in Petrodelta and has recorded its share of the earnings of Petrodelta from April 1, 2006 to December 31, 2007 in the current year in accordance with the Conversion Contact. Summary historical financial information has been presented below at December 31, 2006 and 2007 and for the nine months ended December 31, 2006 and the year ended December 31, 2007 for comparative purposes (in thousands, except per unit information):

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	Year Ended			Nine Months Ended
	December 31, 2007			December 31, 2006
Barrels of oil sold		5,374			5,211
MCF of gas sold		13,456			11,519
Total BOE		7,616			7,131

Average price per barrel	$	58.61		$	50.98
Average price per mcf	$	1.54		$	1.54

Revenues:
Oil sales	$	314,928		$	265,625
Gas sales		20,789			17,796
Royalty		(114,847	)		(96,790	)

		220,870			186,631

Expenses :
Operating expenses		23,752			22,729
Depletion, depreciation and amortization		18,549			17,076
General and administrative		19,880			11,093
Taxes other than on income		2,747			2,029

		64,928			52,927


Income from operations and before income taxes		155,942			133,704

Current income tax expense		85,849			67,188
Deferred income tax benefit		(21,348	)		(23,415	)

Net Income		91,441			89,931
Adjustment to reconcile to reported Net Income from Unconsolidated Equity Affiliate:
Deferred income tax benefit		21,348			23,415

Net Income Equity Affiliate		70,093			66,516
Equity interest in unconsolidated equity affiliate		40	%		40	%

Income before amortization of excess basis in equity affiliate		28,037			26,606
Amortization of excess basis in equity affiliate		(2,530	)		—

Net income from unconsolidated equity affiliate	$	25,507		$	26,606


	December 31,		December 31,
	2007		2006
Current assets	$	464,904	$	206,907
Property and equipment		190,613		200,376
Other assets		38,738		23,415
Current liabilities		287,491		122,896
Other liabilities		5,964		5,420
Net equity		400,800		302,382

Note 8 — China Operations

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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, 2009. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist. WAB-21 represents $2.9 million of oil and gas properties on our December 31, 2007 balance sheet.

Note 9 — Domestic Operations

In January 2007, we purchased a 45 percent interest in Fusion for $4.6 million. Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering. The purchase of Fusion extends our technical ability and global reach to support a more organic growth strategy. Our minority equity investment in Fusion is accounted for using the equity method of accounting. Operating revenue and total assets represent 100 percent of Fusion. Fusion acquired Renegade Geophysical L.L.C. on August 30, 2007 for 9.1 percent of one of Fusion’s subsidiaries’ stock plus $0.5 million. No dividends were declared or paid during the period. Summarized financial information for Fusion follows:


	Year Ended
	December 31,
	2007
	(in thousands)
Operating Revenues	$	7,392


Net Income	$	527
Equity interest in unconsolidated equity affiliate		45	%

Net income from unconsolidated equity affiliate		237
Amortization of fair value of intangibles		(656	)

Net loss from unconsolidated equity affiliate	$	(419	)


		December 31,
		2007
Current assets	$		3,995
Total assets			14,846
Current liabilities			2,100
Total liabilities			2,100

Note 10 — Related Party Transactions

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 indirectly owns 20 percent of Petrodelta. The consulting agreement was cancelled January 1, 2004. At December 31, 2007 and 2006, we owed $10.1 million and $9.6 million, respectively, under the consulting agreement.

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 36.5 million, 37.2 million and 36.9 million for the years ended December 31, 2007, 2006 and 2005, 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 37.9 million, 37.2 million and 38.4 million for the years ended December 31, 2007, 2006 and 2005, respectively.

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An aggregate of 1.1 million options were excluded from the earnings per share calculations because their exercise price exceeded the average price for the year ended December 31, 2007. For the years ended December 31, 2006 and 2005, 1.5 million and 1.9 million options and warrants, respectively, were excluded from the earnings per share calculations because their exercise price exceeded the average price.

Note 12 — Gain on Financing Transaction

In 2006, Harvest Vinccler entered into two Bolivar denominated three-year loans and one Bolivar denominated term loan with Venezuelan banks. The interest and debt service obligations for these loans are denominated in Bolivars. The Bolivar debt was collateralized with U.S. Dollar deposits in banks outside of Venezuela. See Note 2 — Long-Term Debt and Liquidity. Since Harvest Vinccler has no source for Bolivars due to the situation in Venezuela (see Note 7— Venezuela Operations-Petrodelta, S.A.), the consolidated Harvest group of companies evaluated its current options to convert U.S. Dollars to Bolivars and entered into a series of security exchange transactions to effectively convert U.S. Dollars to Bolivars. In these exchange transactions, one Harvest affiliate purchased U.S. government securities and exchanged them for U.S. Dollar indexed debt issued by the Venezuelan government. The U.S. Dollar indexed Venezuelan government securities can only be traded in Venezuela for Bolivars (“Southern Bonds” or “TICC’s”). The exchange was transacted through an intermediary at the securities transaction rate of Bolivars to U.S. Dollars. Harvest Vinccler at the same time purchased a like amount of U.S. government securities and exchanged those securities with the intermediary for the TICCs. Harvest Vinccler converted the TICCs to Bolivars at a local bank at the official exchange rate of 2,150 Bolivars to one U.S. Dollar and used the Bolivars to settle 205 billion Bolivars (approximately $95.4 million) of its Bolivar denominated debt. These security exchange transactions resulted in a $49.6 million gain on financing transactions for the year ended December 31, 2007. There were no such financing transactions entered into during the year ended December 31, 2006.

Note 13 — Subsequent Events

In February 2008, Messrs. R.E. Irelan and Igor Effimoff were elected to our Board of Directors, increasing the number of Board members to eight. Our Board is now composed of seven external and one internal members.

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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, 2007
Revenues	$	—		$	—		$	—		$	11,217
Expenses		(6,951	)		(7,798	)		(6,069	)		(9,935	)
Non-operating income (expense)		(38	)		353			15,076			35,059

Income (loss) before income taxes and minority interests		(6,989	)		(7,445	)		9,007			36,341
Income tax expense		114			52			863			5,283

Income (loss) before minority interests		(7,103	)		(7,497	)		8,144			31,058
Minority interests		(637	)		(736	)		2,524			17,909

Income (loss) from consolidated companies		(6,466	)		(6,761	)		5,620			13,149
Net income (loss) from unconsolidated equity affiliates		(39	)		(137	)		(235	)		52,106

Net income (loss)	$	(6,505	)	$	(6,898	)	$	5,385		$	65,255


Net income (loss) per common share:
Basic	$	(0.17	)	$	(0.18	)	$	0.15		$	1.87

Diluted	$	(0.17	)	$	(0.18	)	$	0.14		$	1.78


	Quarter Ended
	March 31			June 30			September 30			December 31
	(amounts in thousands, except per share data)
Year ended December 31, 2006*
Revenues	$	59,172		$	334		$	—		$	—
Expenses		(33,068	)		(7,796	)		(7,654	)		(10,414	)
Non-operating income (expense)		1,940			(13,419	)		(2,650	)		258

Income (loss) before income taxes and minority interests		28,044			(20,881	)		(10,304	)		(10,156	)
Income tax expense		14,762			40,810			5,338			7

Income (loss) before minority interests		13,282			(61,691	)		(15,642	)		(10,163	)
Minority interests		3,354			(11,409	)		(2,044	)		(1,613	)

Net income (loss)	$	9,928		$	(50,282	)	$	(13,598	)	$	(8,550	)


Net income (loss) per common share:
Basic	$	0.27		$	(1.35	)	$	(0.36	)	$	(0.23	)

Diluted	$	0.26		$	(1.35	)	$	(0.36	)	$	(0.23	)


*		Financial information for 2006 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 — Organization and Summary of Significant Accounting Policies — Property and Equipment and Change in Accounting Principle. The effect of the accounting change on net income for the three months ended March 31, 2006 was a decrease of $3.9 million, net of income tax, or $0.10 per diluted share.

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

The following tables summarize our proved reserves, drilling and production activity, and financial operating data at the end of each year. The Venezuelan reserves are attributable to our consolidated activities prior to the conversion to an equity investment in Petrodelta. Historical costs in Tables I through III provide information prior to the effective date of the conversion to Petrodelta on April 1, 2006.

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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 (in thousands):


					United States
	Venezuela		China		and Other		Total
Year Ended December 31, 2007
Acquisition costs	$	—	$	160	$	304	$	464
Exploration costs		—		204		—		204

	$	—	$	364	$	304	$	668


Year Ended December 31, 2006
Acquisition costs	$	—	$	35	$	—	$	35
Development costs		501		—		—		501

	$	501	$	35	$	—	$	536


Year Ended December 31, 2005
Acquisition costs	$	—	$	42	$	—	$	42
Development costs		8,912		—		—		8,912

	$	8,912	$	42	$	—	$	8,954

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


							United States
	Venezuela^(a)			China^(b)			and Other		Total
Year Ended December 31, 2007
Costs excluded from amortization	$	—		$	2,859		$	304	$	3,163


Year Ended December 31, 2006
Proved property costs	$	—		$	13,532		$	—	$	13,532
Costs excluded from amortization		—			2,900			—		2,900
Oilfield inventories		—			—			—		—
Less accumulated depletion and impairment		—			(13,532	)		—		(13,532	)

	$	—		$	2,900		$	—	$	2,900


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


(a)		Reclassified to investment in equity affiliates effective April 1, 2006.

(b)		See Note 8 — China Operations.

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


	Venezuela
Year ended December 31, 2006^(a)
Oil and natural gas revenues	$	59,506
Expenses:
Operating, selling and distribution expenses and taxes other than on income		9,451
Depletion		9,904
Income tax expense		20,076

Total expenses^(b)		39,431

Results of operations from oil and natural gas producing activities	$	20,075


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

Total expenses		147,087

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


(a)		Reflects oil and natural gas deliveries through March 31, 2006.

(b)		Excludes taxes of $50.3 million recorded in 2006 due to the settlement of the SENIAT tax assessments.

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 the OSA between Harvest Vinccler and PDVSA, under which mineral rights are owned by the government of Venezuela. The Venezuelan government unilaterally terminated the OSA in April 2006. See Note 1 — Organization and Summary of Significant Accounting Policies — Organization.

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.

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

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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 evaluation of the oil and natural gas reserves were prepared by Ryder Scott Company L.P., independent petroleum engineers.

The evaluations of the oil and natural gas reserves as of December 31, 2006 and 2005 were prepared by Ryder Scott Company L.P., independent petroleum engineers. The 2006 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 were reduced to remove undeveloped reserves because the actions taken by the Venezuelan government beginning in 2005 under our OSA 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”. In April 2006, the OSA was unilaterally terminated by the Venezuelan government. See Note 1 — Organization and Summary of Significant Accounting Policies - Organization. Reserves for Petrodelta are reflected in the following section Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela Equity Affiliate as of December 31, 2007 and 2006, TABLE IV — Quantities of Oil and Natural Gas Reserves.

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


				Minority
Proved Reserves-Crude oil, condensate,				Interest in
and natural gas liquids (MBbls)	Venezuela			Venezuela			Net Total
				(in thousands)
Year ended December 31, 2006
Proved Reserves at beginning of the year		35,311			(7,062	)		28,249
Revisions of previous estimates^(a)		(33,417	)		6,683			(26,734	)
Production		(1,894	)		379			(1,515	)

Proved Reserves at end of the year		—			—			—


(a)		All reserves have been removed pending conversion to Petrodelta.

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				Minority
Proved Reserves-Crude oil, condensate,				Interest in
and natural gas liquids (MBbls)	Venezuela			Venezuela			Net Total
				(in thousands)
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.


Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at:
December 31, 2005	35,311		(7,062	)	28,249
January 1, 2005	45,488		(9,098	)	36,390

Proved Reserves-Natural gas (MMcf)

Year ended December 31, 2006
Proved Reserves beginning of the year	58,918		(11,784	)	47,134
Revisions of previous estimates^(a)	(54,412	)	10,883		(43,529	)
Production	(4,506	)	901		(3,605	)

Proved Reserves end of the year	—		—		—


(a)		All reserves have been removed pending conversion to Petrodelta.


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.


Proved Developed Reserves-Natural gas (MMcf) at:
December 31, 2005	58,918	(11,784	)	47,134
January 1, 2005	80,897	(16,179	)	64,718


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 net interest in Petrodelta. We report the results of Ryder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan reserves.

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				Minority
				Interest in
	Venezuela			Venezuela			Net Total
				(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


(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
	2006^(a)			2005
	(in thousands)
Standardized Measure at January 1	$	329,438		$	544,980
Sales of oil and natural gas, net of related costs		(40,361	)		(124,638	)
Revisions to estimates of proved reserves
Net changes in prices, development and production costs		—			262,852
Quantities		—			(365,565	)
Extensions, discoveries and improved recovery, net of future costs		—			—
Accretion of discount		—			80,202
Net change in income taxes		—			109,030
Development costs incurred		501			7,130
Changes in timing and other		(289,578	)		(184,553	)

Standardized Measure at December 31	$	—		$	329,438


(a)		All reserves have been removed pending conversion to Petrodelta.

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Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela Equity Affiliate as of December 31, 2007 and 2006

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.

Petrodelta (32 percent ownership) is accounted for under the equity method, and has been included at its ownership interest in the consolidated financial statements and the following Tables based on a year ending December 31 and, accordingly, results of operations for oil and natural gas producing activities in Venezuela reflect the year ended December 31, 2007 and 2006.

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


	Petrodelta
Year Ended December 31, 2007
Development costs	$	976

Exploration costs		—

	$	976


Year Ended December 31, 2006
Development costs	$	217
Exploration costs		—

	$	217

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


	Petrodelta
December 31, 2007
Proved property costs	$	59,820
Unproved property costs		7,247
Costs excluded from amortization		(976	)
Oilfield inventories		4,426
Less accumulated depletion and impairment		(11,063	)

	$	59,454


December 31, 2006
Proved property costs	$	58,849
Unproved property costs		7,247
Costs excluded from amortization		(217	)
Oilfield inventories		2,650
Less accumulated depletion and impairment		(5,317	)

	$	63,212

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


	Petrodelta
Year ended December 31, 2007
Oil and natural gas revenues	$	107,429
Royalty		(36,751	)

		70,678

Expenses:
Operating, selling and distribution expenses and taxes other than on income		7,601
Depletion		5,746
Income tax expense		23,714

Total expenses		37,061

Results of operations from oil and natural gas producing activities	$	33,617


Year ended December 31, 2006
Oil and natural gas revenues	$	90,695
Royalty		(30,973	)

		59,722

Expenses:
Operating, selling and distribution expenses and taxes other than on income		7,273
Depletion		5,317
Income tax expense		15,430

Total expenses		28,020

Results of operations from oil and natural gas producing activities	$	31,702

TABLE IV — Quantities of Oil and Natural Gas Reserves

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testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

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

The evaluation of the oil and natural gas reserves as of December 31, 2007 was prepared by Ryder Scott Company L.P., independent petroleum engineers.

The tables shown below represents HNR Finance’s interest, net of a 33.33 percent royalty, in Venezuela in each of the years.


				Minority
Proved Reserves-Crude oil, condensate,				Interest in			32%
and natural gas liquids (MBbls)	HNR Finance			Venezuela			Net Total
				(in thousands)
Year ended December 31, 2007
Proved Reserves at January 1, 2007		—			—			—
Additions^(a)		50,085			(10,017	)		40,068
Production		(2,824	)		565			(2,259	)

Proved Reserves at end of the year		47,261			(9,452	)		37,809


(a)		Petrodelta was formed in 2007


Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at:
December 31, 2007	14,779		(2,956	)	11,823

Proved Reserves-Natural gas (MMcf)

Year ended December 31, 2007
Year ended December 31, 2007
Proved Reserves at January 1, 2007	—		—		—
Additions^(a)	50,019		(10,004	)	40,015
Production	(6,935	)	1,387		(5,548	)

Proved Reserves at end of the year	43,084		(8,617	)	34,467


(a)		Petrodelta was formed in 2007


Proved Developed Reserves-Natural gas (MMcf) at:
December 31, 2007	7,755	(1,551	)	6,204

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

The table shown below represents HNR Finance’s net interest in Petrodelta. We report the results of Ryder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan reserves.


				Minority
				Interest in
	HNR Finance			Venezuela			Net Total
	(in thousands)
December 31, 2007
Future cash inflows from sales of oil and gas	$	3,650,110		$	(730,022	)	$	2,920,088
Future production costs		(685,368	)		137,074			(548,294	)
Future development costs		(358,759	)		71,752			(287,007	)
Future income tax expenses		(1,274,005	)		254,801			(1,019,204	)

Future net cash flows		1,331,978			(266,395	)		1,065,583
Effect of discounting net cash flows at 10%		(677,756	)		135,551			(542,205	)

Standardized measure of discounted future net cash flows	$	654,222		$	(130,844	)	$	523,378


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

Not applicable.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.


		HARVEST NATURAL RESOURCES, INC. (Registrant)
Date: March 17, 2008	By:	/s/ James A. Edmiston
		James A. Edmiston
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the 17^th day of March, 2008, on behalf of the registrant and in the capacities indicated:


Signature		Title

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

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

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

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

/s/ Igor Effimoff Igor Effimoff		Director

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

/s/ R. E. Irelan R. E. Irelan		Director

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

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

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Exhibit Index

(b) 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			Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on April 23, 2007, File No. 1-10762.)

	4.1			Form of Common Stock Certificate.

	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			Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A filed on October 23, 2007, File No. 1-10762.)

	10.1			2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-8 filed on April 9, 2002 (Registration Statement No. 333-85900).)

	10.2			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).)


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

	10.4			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.)

	10.5			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.)

	10.6			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.)

	10.7^†			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.)

	10.8^†			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.)

	10.9^†			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.)

	10.10^†			Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.24 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)

	10.11^†			Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)

	10.12^†			Stock Option Agreement dated September 26, 2005, between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.26 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)

	10.13^†			Employment Agreement dated February 10, 2006 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on April 20, 2006, File No. 1-10762.)

	10.14			Harvest Natural Resources 2006 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on June 1, 2006 [Registration Statement No. 333-134630].)

	10.15			Form of 2006 Long Term Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)

	10.16			Form of 2006 Long Term Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)

	10.17			Form of 2006 Long Term Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)


	10.18^†			Stock Unit Award 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 August 9, 2006, File No. 1-10762.)

	10.19^†			Stock Unit Award Agreement dated March 2, 2006 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)

	10.20			Note Payable agreement dated November 20, 2006 between Harvest Vinccler, C.A. and Banesco Banco Universal C.A. related to a principal amount of 120 billion Bolivars with interest at 10.0 percent, for refinancing of the SENIAT assessments and operating requirements. (Incorporated by reference to Exhibit 10.32 to our Form 10-K filed on March 13, 2007, File No. 1-10762.)

	10.21			Form of 2006 Long Term Incentive Plan Stock Option Agreement — Five Year Vesting, Seven Year Term. (Incorporated by reference to Exhibit 10.33 to our Form 10-K filed on March 13, 2007, File No. 1-10762.)

	10.22			Amendment to Harvest Natural Resources 2006 Long Term Incentive Plan adopted July 19, 2006. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on May 3, 2007, File No. 1-10762.)

	10.23^†			Employment Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)

	10.24^†			Stock Option Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)

	10.25^†			Employee Restricted Stock Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)

	10.26^†			Consulting Agreement dated July 16, 2007 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)

	10.27			Contract for Conversion to a Mixed Company between Corporación Venezolana del Petróleo, S.A., Harvest-Vinccler, S.C.A. and HNR Finance B.V. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on November 1, 2007, File No. 1-10762.)

	10.28^†			Separation Agreement dated November 16, 2007 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 Espiñeira, Sheldon y Asociados.

	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 on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by James A. Edmiston, President and Chief Executive Officer.

	32.2			Certification accompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer.


			Page
Part I

Item 1. Business			1
Item 1A. Risk Factors			10
Item 1B. Unresolved Staff Comments			14
Item 2. Properties			14
Item 3. Legal Proceedings			14
Item 4. Submission of Matters to a Vote of Securities Holders			15

Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			16
Item 6. Selected Financial Data			18
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			19
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			29
Item 8. Financial Statements and Supplementary Data			30
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			30
Item 9A. Controls and Procedures			30
Item 9B. Other Information			31

Part III

Item 10. Directors, Executive Officers and Corporate Governance			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, and Director Independence			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-35
Form of Common Stock Certificate
Separation Agreement
List of Subsidiaries
Consent of PricewaterhouseCoopers LLP - Houston
Consent of Ryder Scott Company LP
Certification of James A. Edmiston, President & CEO, Pursuant to Section 302
Certification of Steven W. Tholen, SVP, CFO, & Treasurer, Pursuant to Section 302
Certification of James A. Edmiston, President & CEO, Pursuant to Section 1350
Certification of Steven W. Tholen, SVP, CFO, & Treasurer, Pursuant to Section 1350


^†		Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15(a) and (b) of Form 10-K.


			Additions
	Balance at					Charged to Other		Deductions From		Balance at End of
	Beginning of Year		Charged to Income			Accounts		Reserves		Year
At December 31, 2007
Amounts deducted from applicable assets
Accounts receivable	$	2,757	$	—		$	—	$	—	$	2,757
Deferred tax valuation allowance		32,809		32,809			—		—
Investment at cost		1,350		—			—		—		1,350
At December 31, 2006
Amounts deducted from applicable assets
Accounts receivable	$	2,757	$	—		$	—	$	—	$	2,757
Deferred tax valuation allowance		27,363		5,446			—		—		32,809
Investment at cost		1,350		—			—		—		1,350
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