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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, 2008


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) 1177 Enclave Parkway, Suite 300 Houston, Texas (Address of principal executive offices)		77-0196707 (I.R.S. Employer Identification Number) 77077 (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: Preferred Share Purchase Rights

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. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o
(Do not check if a smaller reporting company)

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 30, 2008 was: $375,922,267.

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 9, 2009, shares outstanding: 32,942,525.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for the 2009 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.

Restatement

Harvest Natural Resources, Inc. (“Harvest” or the “Company”) is restating its historical financial statements for the year ended December 31, 2007 and quarterly information for the quarters ended December 31, 2007, March 31, 2008, June 30, 2008 and September 30, 2008 (see Part IV, Item 15, Notes to Consolidated Financial Statements, Note 1 — Organization and Summary of Significant Accounting Policies — Restatement and Exhibits and Financial Statement Schedules, Quarterly Financial Data (unaudited)). The restatements relate to the correction of an error in the deferred tax adjustment to reconcile our share of Petrodelta S.A.’s (“Petrodelta”) Net Income reported under International Financial Reporting Standards (“IFRS”) to that required under accounting principles generally accepted in the United States of America (“GAAP”) and recorded within our Net income from unconsolidated equity affiliates. We are presenting this restatement in our Annual Report on Form 10-K for the year ended December 31, 2008.

The adjustment to record our share of Petrodelta’s Net Income under GAAP should have been limited to deferred tax adjustments related to non-monetary temporary differences impacted by inflationary adjustments under Venezuela law. During the 2008 year end close process, we determined that restatements were necessary because since October 1, 2007 both the monetary and non-monetary temporary differences recorded in Petrodelta’s IFRS financial statements had been adjusted in arriving at our GAAP consolidated financial statements rather than only the non-monetary temporary differences impacted by inflationary adjustments. Accordingly, we had understated our Net income from unconsolidated equity affiliates and Investment in equity affiliates.

For information relating to the effect of the restatements, see the following items:

Part II:

Item 6 – Selected Financial Data

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

Item 8 – Financial Statements and Supplementary Data

Item 9A – Controls and Procedures

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 (particularly those in Venezuela), 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 a petroleum exploration and production company of international scope since 1989, when it was incorporated under Delaware law. Our focus is on acquiring exploration, development and producing properties in geological basins with proven active hydrocarbon systems. Our experienced technical, business development and operating staffs have identified low entry cost exploration opportunities in areas with large hydrocarbon resource potential. We operate from our Houston, Texas, headquarters. We also have an expanded regional/technical office in the United Kingdom, a newly opened eastern hemisphere regional office in Singapore, and small field offices in Jakarta, Indonesia and Roosevelt, Utah to support field operations in the area. We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”) originally through our subsidiary Harvest Vinccler, S.C.A. (“Harvest Vinccler”) and subsequently through our 40 percent equity affiliate, Petrodelta, S. A. (“Petrodelta”) which operates a portfolio of properties in eastern Venezuela including large proven oil fields as well as properties with very substantial opportunities for both development and exploration. We have seconded key technical and managerial personnel into Petrodelta and participate on Petrodelta’s board of directors. Geophysical, geosciences, and reservoir engineering support services are available to our in-house experts through our minority equity investment in Fusion Geophysical, LLC (“Fusion”). Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering headquartered in the Houston area and working around the world. Through the pursuit of technically-based strategies guided by conservative investment philosophies, we are building a portfolio of exploration prospects to complement the low-risk production, development, and exploration prospects we hold in Venezuela. Currently, we hold interests in Venezuela, the Gulf Coast Region of the United States through an Area of Mutual Intent (“AMI”) agreement with a private third party, the Antelope project in the Western United States through a Joint Exploration and Development Agreement (“JEDA”), and exploration acreage offshore of the People’s Republic of China (“China”), offshore of the Republic of Gabon (“Gabon”) and mainly onshore West Sulawesi in the Republic of Indonesia (“Indonesia”).

Currently, our only producing asset is in Venezuela. 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. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petrodelta is governed by its own board of directors, charter and bylaws.

Petrodelta commenced drilling operations in the Uracoa field on April 21, 2008. As of December 31, 2008, Petrodelta had drilled and completed eight successful development wells and suspended one well due to problems with the well. Petrodelta currently has two drilling rigs working in the Uracoa field and one drilling rig in the Temblador field.

In May 2008, Petrodelta declared and paid a dividend of $181 million, $72.5 million net to HNR Finance ($58.0 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under International Financial Reporting Standards (“IFRS”) for the period of April 1, 2006 through December 31, 2007. In October 2008, Petrodelta paid an advance dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the six months ended June 30, 2008. Until Petrodelta’s board of directors declares a dividend for the year ended December 31, 2008, there is a possibility that all or a portion of the advance dividend could be rescinded; therefore, the advance dividend is reflected as a current liability on the consolidated balance sheets at December 31, 2008.

On April 15, 2008, the Venezuelan government published in the Official Gazette the Law of Special Contribution to Extraordinary Prices at the Hydrocarbons International Market (“original Windfall Profits Tax”). The original Windfall Profits Tax was based on prices for Brent crude, and, as instructed by CVP, Petrodelta applied the original Windfall Profits Tax to net production after deduction for royalty barrels. On July 10, 2008, the Venezuelan government published an amendment to the Windfall Profits Tax (“amended Windfall Profits Tax”) to be calculated on the Venezuelan Export Basket (“VEB”) of prices as published by the Ministry of the People’s Power for Energy and Petroleum (“MENPET”). The amended Windfall Profits Tax was made retroactive to April 15, 2008, the date of the original Windfall Profits Tax. As instructed by CVP, Petrodelta has applied the amended Windfall Profits Tax to gross oil production delivered to Petroleos de Venezuela, S.A. (“PDVSA”) since April 15, 2008 when the tax was enacted. During the year ended December 31, 2008, Petrodelta recorded $56.4 million of expense for the amended Windfall Profits Tax.

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-Budong production sharing contract (“Budong PSC”). Final government approval from the Ministry of Energy and Mineral Resources, Migas, was received in April 2008. The Budong PSC is located mainly onshore West Sulawesi, Indonesia.

In September 2008, we spud an exploratory well on the Starks prospect, the first prospect in the Gulf Coast AMI, in Calcasieu Parish, Louisiana. The Harvest Hunter #1 well was drilled to a depth of 12,290 feet and three prospective reservoir horizons were tested. On January 9, 2009, the well was determined to not have commercial quantities of hydrocarbons and was plugged and abandoned.

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. This repurchase program was completed in June 2008. Under this program, we repurchased 4.6 million shares at an average cost of $10.93 per share, including commissions. In July 2008, our Board of Directors authorized the purchase of up to $20 million of our common stock from time to time through open market transactions. We continue to believe that Harvest stock remains undervalued and that the investment in the shares of our Company represents an attractive alternative to holding cash in excess of our needs. As of December 31, 2008, 1.2 million shares of stock have been purchased at an average cost of $10.17 per share for a total cost of $12.2 million of the $20 million authorization. Federal securities laws and the New York Stock Exchange (“NYSE”) regulate the use of public disclosure of corporate inside information. These laws, rules and regulations require that we ensure information about Harvest is not used unlawfully in connection with the purchase and sale of securities. Pursuant to these laws, we are prohibited from purchasing stock while in possession of material non-public information.

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 2008.

As of December 31, 2008, we had total assets of $358.7 million, unrestricted cash in the amount of $97.2 million and no long-term debt. For the year ended December 31, 2008, we had no revenues and net cash provided by operating activities of $50.4 million. As of December 31, 2007, we had total assets of $417.1 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.

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 as an alternative to purchasing proved producing assets. 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 exploration technical resources, opening of our London office, the 2008 opening of our Singapore office, as well as our minority equity investment in 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 generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles.

We intend to use our available cash to pursue additional growth opportunities in Gabon, Indonesia, China, the United States 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 dividends 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 Securities and Exchange Commission (“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 Office of Investor Education and Advocacy at 100 F Street NE, Washington, DC 20549-0213. The public may obtain information on the operation of the Office of Investor Education and Advocacy 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, our Venezuelan operations have been conducted through our equity affiliate Petrodelta which is governed by the Contract of Conversion (“Conversion Contract”) signed on September 11, 2007. All of the equity investment 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 investment in Harvest-Vinccler Dutch Holding B.V. The remaining 20 percent minority equity investment 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. 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, which we may operate during the production phase. In April 2008, we completed the purchase of a 50 percent interest in the production sharing contract related to the Dussafu PSC, and in September 2008, we completed the purchase of an additional 16.667 percent interest in the Dussafu PSC, which brings our total interest in the Dussafu PSC to 66.667 percent. We are the operator of the Dussafu PSC. See Item 1 — Business, Dussafu Marin, Offshore Gabon and Budong-Budong, Onshore Indonesia for a more detailed description. We also have a 55 percent interest in an area of the Gulf Coast Region of the United States covered by an AMI agreement with a private third party, and a 50 percent interest in the Antelope project in the Western United States covered by a JEDA. We are the operator of both United States operations. See Item 1 — Business, United States Operations for a more detailed description.

Petrodelta

General

On October 25, 2007, the Venezuelan Presidential Decree which formally transferred 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 that date. Petrodelta has undertaken its operations in accordance with the Business Plan as set forth in 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. As of February 27, 2009, the 2009 budget for Petrodelta’s Business Plan had not yet been approved by its shareholders.

Petrodelta 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 are consistent with the policies and procedures of PDVSA and the ultimate parent company of HNR Finance.

Petrodelta is governed by a board of directors in accordance with the Charter and Bylaws of Petrodelta as set forth in 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 PDVSA Petroleo S.A. (“PPSA”), a 100 percent owned subsidiary of PDVSA; 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.

Petrodelta’s board of directors 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 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.

Certain actions by PDVSA during 2008 raised contractual questions as to certain operational and financial issues relating to Petrodelta. Operationally, Petrodelta has not received all information regarding production during the conversion period for Temblador in order to invoice all volumes produced in that field during that period. As Temblador production is handled in PDVSA’s system, PDVSA has allocated only partial, estimated production to Petrodelta. As a result, Petrodelta has not received full credit for the Temblador production. Although we believe the amount of production and related revenue to be immaterial to Petrodelta, Petrodelta has not received full payment. Discussions are ongoing to settle figures, and Petrodelta is working to segregate completely Temblador’s production.

Financially, the Conversion Contract and related documents state that Petrodelta will issue invoices monthly to PPSA for hydrocarbon sales, and payment is due from PPSA within 30 days of invoicing. Petrodelta invoiced PPSA for 2006 and 2007 hydrocarbon sales, but PPSA has not made payment against the invoices. The Conversion Contract and related documents also state that PDVSA is to submit invoices to Petrodelta for services and materials rendered to Petrodelta. PDVSA has not been issuing invoices. Since Petrodelta has not received payments from PPSA on the hydrocarbon sales invoices issued for 2006 and 2007, in April 2008, Petrodelta began accruing interest on late payment of invoices under the Conversion Contract provisions. PDVSA has been netting revenues and expenses and advancing funds to Petrodelta sufficient to pay Petrodelta’s operating expenses, capital expenditures and dividends distribution requirements according to financial statements. It is our understanding that PDVSA considers all 2006 and 2007 receivables and payables settled with the payment of the dividend in May 2008. On December 11, 2008, Petrodelta’s Board approved a resolution to settle the 2006 and 2007 hydrocarbon invoices against the account payable to PDVSA for 2006 and 2007 cash advances and the dividend received in May 2008. On January 22, 2009, CVP notified all mixed companies, including Petrodelta, that they must net the outstanding accounts payable balance with PDVSA and CVP against the revenues due from PPSA. The mixed companies were also notified that interest accrued on late payment of invoices would not be recognized or paid. Petrodelta’s December 31, 2008 balance sheet reflects the results of the netting of accounts receivable and accounts payable, and the interest income accrued on late payment of invoices for 2006, 2007 and 2008 has been reversed in its results of operations for the year ended December 31, 2008.

The Conversion Contract also states that the selection of auditor for Petrodelta is a decision of Petrodelta’s board; however, PDVSA issued correspondence stating that they will have final approval of the auditor selected. Even though Petrodelta’s June 2008 Board minutes state that Petrodelta’s auditor would be Espiñeira, Sheldon y Asociados, in November 2008, PDVSA notified Petrodelta that its auditor of record would be HLB PGFA Perales, Pistone & Asociados.

In September 2008, Petrodelta received communication from CVP that the amended Windfall Profits Tax was to be calculated on gross production. Since Petrodelta pays MENPET its royalty in-kind (“royalty barrels”), the royalty barrels are not included in Petrodelta’s production numbers, but Petrodelta is being required to pay amended Windfall Profits Tax on the royalty barrels. Windfall profits tax on royalty barrels was $16.9 million for the year ended December 31, 2008. Our position is that the amended Windfall Profits Tax should only be calculated on the net barrels produced. Based on legal advice, we believe that the amended Windfall Profits Tax should not be calculated on gross barrels; however, Petrodelta applied the amended Windfall Profits Tax to gross production as instructed by CVP. This is not a contractual issue, but it is a point of interpretation that requires discussion.

We have raised all of these issues with appropriate representatives of Petrodelta, CVP and PDVSA. While we continue our discussions to resolve these issues, there currently can be no assurances that CVP and PDVSA will comply with all the applicable contracts and governing documents’ provisions.

Petrodelta shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Given the recent precipitous drop in crude oil prices, the management and board of Petrodelta have taken actions to reduce both operating and capital expenditures. Currently, Petrodelta has two drilling rigs operating in the Uracoa field and one drilling rig in the Temblador field and has released three additional drilling rigs. For 2009, the initial drilling program includes utilizing two rigs to drill both development and appraisal wells for both maintaining production capacity and appraising the substantial resource bases in the presently non-producing Isleño and El Salto fields. We do not expect to receive additional dividends for 2008. We expect to receive future dividends from Petrodelta; however, we expect the amount of any dividends to be minimal over the next two years as Petrodelta reinvests more of its earnings into the company in support of its drilling and appraisal activities. Until oil prices increase, all available cash will be used to meet current operating requirements, including appraisal drilling, and will not be available for dividends.

During 2008, Petrodelta drilled and completed eight successful development wells and suspended one well due to problems with the well, produced approximately 5.5 million barrels of oil and sold 10.7 billion cubic feet (“BCF”) of natural gas. Petrodelta has been advised by the Venezuelan government that 2009 production objective will be approximately 16,000 barrels of oil per day effective January 1, 2009, following the December 17, 2008 Organization of the Petroleum Exporting Countries (“OPEC”) meeting establishing new production quotas. However, Petrodelta’s production output for the first quarter of 2009 is projected to be 18,000 barrels per day to comply with the Venezuelan government’s market allocations of the OPEC quota for the country.

In May 2008, Petrodelta declared and paid a dividend of $181 million, $72.5 million net to HNR Finance ($58.0 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the period of April 1, 2006 through December 31, 2007. In October 2008, Petrodelta paid an advance dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the six months ended June 30, 2008. Until Petrodelta’s board of directors declares a dividend for the year ended December 31, 2008, there is a possibility that all or a portion of the advance dividend could be rescinded; therefore, the advance dividend is reflected as a current liability on the consolidated balance sheets at December 31, 2008.

On April 15, 2008, the Venezuelan government published in the Official Gazette the original Windfall Profits Tax. The original Windfall Profits Tax was based on prices for Brent crude, and, as instructed by CVP, Petrodelta applied the original Windfall Profits Tax to net production after deduction for royalty barrels. On July 10, 2008, the Venezuelan government published the amended Windfall Profits Tax to be calculated on the Venezuelan Export Basket (“VEB”) of prices as published by MENPET. The amended Windfall Profits Tax was made retroactive to April 15, 2008, the date of the original Windfall Profits Tax. As instructed by CVP, Petrodelta has applied the amended Windfall Profits Tax to gross oil production delivered to PDVSA since April 15, 2008 when the tax was enacted.

The amended Windfall Profits Tax established a special 50 percent tax to the Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar manner, the percentage is increased from 50 percent to 60 percent when the average price of the VEB exceeds $100 per barrel. The amended Windfall Profits Tax is reported as expense on the income statement and is deductible for Venezuelan tax purposes. Petrodelta recorded for the year ended December 31, 2008 $56.4 million for the amended Windfall Profits Tax.

In 2005, Venezuela modified the Science and Technology Law (referred to as “LOCTI” in Venezuela) 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. LOCTI requires major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law to contribute two percent of their gross revenue generated in Venezuela from activities specified in the Law. The contribution is based on the previous year’s gross revenue and is due the following year. Based on legal advice from CVP, Petrodelta’s management concluded that for 2006 Petrodelta was not a legal entity and therefore did not generated any gross income subject to LOCTI. Based on this opinion, Petrodelta did not accrue a liability in 2007 under LOCTI. During 2008, Petrodelta accrued $12.4 million, $6.2 million net of tax, ($2.0 million net to our 32 percent interest) for contributions to LOCTI. On January 22, 2009, CVP notified all mixed companies, including Petrodelta, that PDVSA would be filing a consolidated declaration to LOCTI on the position that PDVSA had incurred sufficient qualifying expenses to cover all of its and its consolidating entities liability. The mixed companies were instructed to reverse any accrued contributions for LOCTI based on PDVSA’s filing position. Based on this notice from CVP, in December 2008, Petrodelta reversed the $12.4 million accrual to LOCTI.

The notice from CVP was supported by communication from the LOCTI regulator dated March 2008 which provided a waiver to PDVSA to submit a consolidated return, comprising PDVSA and all its subsidiaries, for the 2007 contributions. Per this communication, however, the waiver was only applicable to companies that did not file separate tax returns. We have received confirmation from CVP that LOCTI has again issued a waiver to PDVSA to submit a consolidated return for the 2008 contributions. Based on past history, we believe that the likelihood is remote that PDVSA will have to pay LOCTI in excess of internally generated science and tax credits on Petrodelta’s behalf. However, since Petrodelta files a separate tax return, until the final communication from LOCTI is received for the 2008 contributions (which is expected in late March 2009), there is a risk that the waiver will not include Petrodelta, and LOCTI could issue a claim against Petrodelta for failure to remit its contribution.

Due to the recent precipitous drop in crude oil prices, our minority equity investment in Petrodelta was reviewed for impairment under Accounting Principles Board (“APB”) Opinion 18 — The Equity Method of Accounting for Investments in Common Stock. In performing this review, future net cash flows were determined based on estimated future oil and gas sales revenue less future expenditures necessary to develop and produce the reserves. Based on this review, there was no impairment to the carrying value of our minority equity investment in Petrodelta.

Location and Geology

Petrodelta Fields

Uracoa Field

There are currently 87 oil and natural gas producing wells and six 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 16 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. 3-D seismic is available over the entire field and is currently being reprocessed and reinterpreted.

Bombal Field

East Bombal was drilled in 1992, and currently remains underdeveloped. The West Bombal field is currently inactive, with five shut-in wells pending facility and pipeline upgrades. Development of East Bombal and West Bombal has been incorporated into Petrodelta’s Business Plan.

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 the Uracoa field existing infrastructure. Petrodelta’s Business Plan projects full development of the Isleño field over the next three years. The development of the Isleño field could take longer than the three years due to budget constraints caused by the decline in the price per barrel of oil.

Temblador Field

The Temblador field was discovered in 1936 and developed in the 1940s and 1950s. There are currently 15 oil producing wells in the field. The fluid produced from Temblador field flows through two flow stations operated by Petrodelta to the EPT-1 plant operated by PDVSA. 3-D seismic is available over the entire field and is currently being reprocessed and reinterpreted.

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 barrels of oil equivalent (“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.

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. Temblador production is currently delivered to the sales point in the EPT-1 PDVSA facility through gathering systems integrated with the Jobo and Pilon fields operated by PDVSA and is allocated to Petrodelta based on well tests. Petrodelta is working to segregate completely Temblador’s production.

Petrodelta has a 64-mile pipeline from Uracoa 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 agreements in place for purchase of power for the electrical needs, leasing of compression, and operation and maintenance of the gas treatment and compression facilities at the Uracoa and Tucupita fields through 2012.

Business Plan of Petrodelta

Petrodelta’s immediate focus has been the resumption of drilling in the Uracoa field which resulted in an increase in production. Petrodelta is reprocessing existing 3-D seismic over Petrodelta’s fields. Isleño field production can be integrated into the existing Uracoa field infrastructure providing for early production from the field. Temblador field production is processed at existing field facilities. The El Salto field is believed to contain substantial undeveloped and unexplored reserves. 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 approximately ten 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 years ended December 31, 2008 and December 31, 2007 for Petrodelta. The presentation for Petrodelta includes 100 percent of the production (in thousands, except per unit information).


	Year Ended		Year Ended
	December 31, 2008		December 31, 2007
Venezuela
Crude Oil Sales (Bbls)		5,505		5,374
Natural Gas Sales (Mcf)		10,700		13,456
Average Crude Oil Sales Price ($ per Bbl)	$	83.22	$	58.61
Average Natural Gas Sales Price ($ per Mcf)	$	1.54	$	1.54
Average Operating Expenses ($ per Boe)*	$	7.26	$	2.80


*		Excludes workovers.

Royalty-in-kind paid on gas used as fuel was 3,830 Mcf and 3,882 Mcf for 2008 and 2007, respectively.

Acreage

The following table summarizes the developed and undeveloped acreage that we hold under concession as of December 31, 2008:

Developed

Undeveloped

Gross

Net

Gross

Net

Petrodelta

21,800

8,720

225,313

90,125

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. The year ended December 31, 2008 includes net income from unconsolidated equity affiliates for Petrodelta on a current basis. Petrodelta’s results and operating information is more fully described in Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 7 — Investment in Equity Affiliates — Petrodelta, S.A.

Risk Factors

We face significant risks in our minority equity investment in Petrodelta. 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 (“China”) and Socialist Republic of Vietnam (“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 Bei Basin (Nam Con Son) of the South China Sea. Its western edge lies approximately 20 miles to the east of significant producing natural gas fields, Lan Tay and Lan Do, which are reported to contain two trillion cubic feet (“Tcf”) of natural gas and commenced production in November 2002. Also located to the west of WAB-21 are the Dua and Chim Sao (formerly Blackbird) discoveries. The Chim Sao oil field has recently received development approval. The WAB-21 contract area covers a large unexplored area of the Wan’ an Bei basin where the same successful Lower Miocene through to Upper Miocene plays to the west are present. Exploration success in the basin to date has resulted in discoveries estimated to total in excess of 500 million barrels of oil and 7.5 Tcf of natural gas. Several similar structural trends and

geological formations, each with significant potential for hydrocarbon reserves in traps with multiple pay zones similar to the known fields and discoveries to the west are present within WAB-21.

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. We are in the process of scheduling a meeting with CNOOC for March 2009 to discuss another extension for our license. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist.

Undeveloped Acreage

The following table summarizes the undeveloped acreage that we hold under concession as of December 31, 2008:


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

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.

United States Operations

During 2008, we initiated a domestic exploration program in two different basins. We are the operator of both exploration programs and have complemented our existing personnel with the addition of highly experienced management and technical personnel and with the acquisition of our minority equity investment in Fusion.

Gulf Coast

General

In March 2008, we executed an AMI agreement with a private third party for an area in the upper Gulf Coast Region of the United States. We are the operator and have initial working interests of 55 percent in Starks, the first prospect in the AMI, and 50 percent in West Bay, the second prospect in the AMI.

Location and Geology

The AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana, including state waters. The private third party contributed two prospects, including the leases and proprietary 3-D seismic data sets, and numerous leads generated over the last three decades of regional geological focus. We will fund the first $20 million of new lease acquisitions, geological and geophysical studies, seismic reprocessing and drilling costs. All subsequent costs will be shared pursuant to the terms of the AMI. The parties focused on two initial prospects for evaluation and completed essentially all leasing of each prospect area during 2008. The other party is obligated to evaluate and present additional opportunities at their sole cost. As each prospect is accepted it will be covered by the AMI. At year end 2008, we have met $16.4 million of the total $20 million funding obligation under the terms of the AMI. After the remainder of the $20 million funding obligation is met, all subsequent costs will be shared by the parties in proportion to their working interests as defined in the AMI agreement.

Drilling and Development Activity

In September 2008, we spud an exploratory well on the Starks prospect in Calcasieu Parish, Louisiana. The Harvest Hunter #1 well was drilled to a depth of 12,290 feet and three prospective reservoir horizons were tested. On January 9, 2009, the well was determined to not have commercial quantities of hydrocarbons and was plugged and abandoned.

During the year ended December 31, 2008, operational activities in the West Bay prospect included re-processing of 3-D seismic, site surveying, and preparation of preliminary engineering documents. On December 8, 2008, we submitted an Application to Install Structures to Drill and Produce Oil and Gas with the U. S. Army Corps of Engineers — Galveston District (“Corps of Engineers”). At December 31, 2008, the permit application was under review by the Corps of Engineers. Drilling is expected to commence upon receipt of the requisite permit from the Corps of Engineers, which we expect to obtain in late 2009 or early 2010.

Undeveloped Acreage

The following table summarizes the Gulf Coast area undeveloped acreage that we hold under lease as of December 31, 2008:


	Undeveloped
	Total		Harvest
	Gross		Net

Starks		7,732		4,221
West Bay		11,928		5,070

		19,660		9,291

Western United States — Antelope

General

In November 2008, we entered into a Letter Agreement/Amendment of the JEDA (the “Letter Agreement”) with the private party. The Letter Agreement clarifies several open issues in the JEDA, such as classification of $2.7 million of prepaid land costs for the Antelope project as a note receivable, addition of a requirement for the private party to partially assign leases to us prior to meeting the lease earning obligation, and clarification of the parties’ cost obligations for any shallow wells to be drilled on the project prior to the initial deep test well.

Drilling and Development Activity

Operational activities during 2008 on the Antelope project were focused primarily on leasing. Leases acquired during 2008 include fee leases from private landowners, as well as leases obtained from Allottees of the Ute Indian Tribe. The Allottee leases are administered by the Bureau of Indian Affairs Fort Duchesne, Utah office. In addition to leasing activities, other operational activities during 2008 were focused on preparations for anticipated drilling in 2009. We opened a small field office and hired two employees in Roosevelt, Utah in September 2008 to support field activities. Other activities included surveying, preliminary engineering, and

preparations for permitting. In December 2008, we filed Applications for Permits to Drill eight shallow oil wells with the State of Utah Department of Natural Resources Division of Oil, Gas and Mining. The permit applications were still being processed as of February 27, 2009. The cost of the eight shallow oil wells will be borne 50 percent by us and 50 percent by the other party participating in the project. Drilling of the shallow oil wells will not materially contribute to meeting our lease earning obligation under the JEDA.

Undeveloped Acreage

The following table summarizes the undeveloped acreage that we hold under lease as of December 31, 2008:


	Undeveloped
	Total		Harvest
	Gross		Net
Antelope		77,525		14,542

In January 2009, we increased the total gross undeveloped acreage that we hold under lease to 94,814 acres (22,292 net to us).

Earning of Undeveloped Acreage

The acreage summary above reflects the acreage that will be earned by us upon completion of the drilling and testing of the first deep natural gas test well on the project. We anticipate drilling this well and completing the lease earning obligation in 2009. If, however, the earning well is not ultimately drilled and completed in accordance with the requirements of the JEDA, we will have an obligation to assign our interest in the acreage back to the private party in accordance with the terms of the Letter Agreement.

Budong-Budong, Onshore Indonesia

General

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 mainly onshore West Sulawesi, Indonesia. Final government approval from the Ministry of Energy and Mineral Resources, Migas, was received in April 2008. Our partner 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 become operator, if approved by BP Migas, in the subsequent development and production phase.

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.

Drilling and Development Activity

The Budong PSC includes a ten-year exploration period and a 20-year development phase. In November 2008, we opened a small field office in Jakarta, Indonesia and hired four employees to support field activities. In December 2008, the acquisition program of 650 kilometers of 2-D seismic was completed. The data is currently being processed. Interpretation of the data and well planning will take place in the first quarter of 2009. It is expected that the first of two exploration wells will spud in the second half of 2009.

Undeveloped Acreage

The following table summarizes the undeveloped acreage that we hold under concession as of December 31, 2008:


	Undeveloped
	Gross		Net
Indonesia		1,357,723		638,130

Title to Undeveloped Acreage

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, our partner 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.

Dussafu Marin, Offshore Gabon

General

In April 2008, we completed the purchase of a 50 percent interest in the Dussafu PSC for $4.5 million. In September 2008, we completed the purchase of an additional 16.667 percent interest in the Dussafu PSC for $1.5 million. This acquisition brings our total interest in the Dussafu PSC to 66.667 percent. We are the operator of the Dussafu PSC.

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”), entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. The second exploration phase comprises 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. In October 2008, the acquisition of 650 kilometers of 2-D seismic was completed which is now being processed to define the syn-rift potential similar to the adjacent and on-trend Lucina and M’Baya fields. In addition, during the three months ended December 31, 2008, we commenced the reprocessing of 1,076 square kilometers of existing 3-D seismic to define the sub-salt structure to unlock the potential of the Gamba play that is producing in the Etame field to the north. We expect the seismic to mature the prospect inventory to make a decision in 2009 for a well in 2010.

Undeveloped Acreage

The following table summarizes the undeveloped acreage that we hold under concession as of December 31, 2008:


	Undeveloped
	Gross		Net
Gabon		685,470		456,982

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, 2008, our Houston office had 22 full-time employees. Our Utah, Caracas, London, Singapore, Jakarta and Moscow offices had 2, 15, 7, 3, 4 and 2 employees, respectively. We augment our employees from time to time with independent consultants, as required. We plan to close our Moscow office on March 31, 2009.

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 significant 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 minority 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 Petrodelta S.A. as of December 31, 2008, 2007 and 2006, TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities (unaudited) 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 give any assurance that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs.

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, 2008, we had $97.2 million of available cash and, until Petrodelta pays a dividend or other sources of revenue are captured, 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 or success with our exploration program. 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 or exploration 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 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.

We are a minority interest owner in Petrodelta. Even though we have substantial negative control provisions as a minority equity investor 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. In addition, the majority partner, CVP, has initiated and undertaken numerous unilateral decisions that can impact our minority equity investment as more fully disclosed in Item 1 — Business, Petrodelta above.

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.

An increase in oil prices could affect Petrodelta’s future, our dividends and profitability. Prices for oil fluctuate widely. On July 10, 2008, the Venezuelan government published the amended Windfall Profits Tax to be calculated on the VEB of prices as published by MENPET. The amended Windfall Profits Tax was made retroactive to April 15, 2008, the date of the original Windfall Profits Tax. The amended Windfall Profits Tax established a special 50 percent tax to the Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar manner, the percentage is increased from 50 percent to 60 percent when the average price of the VEB exceeds $100 per barrel. The amended Windfall Profits Tax is reported as expense on the income statement and is deductible for Venezuelan tax purposes. Petrodelta recorded for the year ended December 31, 2008 $56.4 million for the amended Windfall Profits Tax.

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.

The total capital required for development of Petrodelta’s assets 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 its assets 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 minority equity investment. If we are called upon to fund our share of 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 give any assurance 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 minority equity investment in Petrodelta.

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.

Global market and economic conditions, including those related to the credit markets, could have a material adverse effect on our business, financial condition and results of operations. A general slowdown in economic activity caused by the current recession could adversely affect our business by impacting our ability to access additional capital, the receipt of dividends from Petrodelta as well as the need to preserve adequate development capital in the interim.

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. In December 2008, we signed a five-year lease for additional office space in Houston, Texas, for approximately $15,000 per month. In November 2008, Harvest Vinccler extended its lease for office space in Caracas, Venezuela for two years for approximately $8,000 per month. In August 2008, we signed a two-year lease in Roosevelt, Utah for approximately $6,000 per month. In October 2008, we signed a two-year lease for office space in Singapore for approximately $18,000 per month. See Item 1 — Business for a description of our oil and 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 April 2007, the Court set the case for trial. The

trial date, reset for the first quarter of 2009, has been stayed indefinitely. 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 Uracoa, Tucupita and Bombal 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 Operating Service Agreement (“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, the Venezuelan income tax authority, 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 Uracoa, Tucupita and Bombal 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 protest with the Mayor’s Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. On April 10, 2008, the Tax Court suspended the case pending a response from the Mayor’s Office to the protest. If the Municipality’s response is to confirm the assessment, Harvest Vinccler will defer to the competent Tax Court 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 both 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 both 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 for taxes in the amount of $0.4 million for Harvest Vinccler’s failure to withhold VAT from vendors during 2005. Also, the SENIAT imposed penalties and interest in the amount of $1.3 million for Harvest Vinccler’s failure to withhold VAT. In July 2008, the SENIAT adjusted the assessment for penalties and interest to the change in tax units as mandated by the Venezuelan tax code and issued a new assessment for $2.3 million. The change in assessment resulted in an additional $1.0 million expense recorded in the year ended December 31, 2008. A tax court has ruled against the SENIAT stating that penalties and interest cannot be calculated on tax units. The case is currently pending a decision in the Venezuelan Supreme Court. 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. In August 2008, Harvest Vinccler filed an appeal in the tax courts and presented a proposed settlement with the SENIAT. In October 2008, after consideration of our proposed settlement, the SENIAT offered a counter-proposal which Harvest Vinccler has tentatively accepted. In January 2009, the case was suspended while the tax court notified the Venezuelan General Attorney’s Office of our intention to settle the case. The Venezuelan Tax Code establishes that once the taxpayer files a request to settle a case, the tax court will admit the request and suspend the filing for 60 consecutive days following the notification of the General Attorney’s Office. The 60 days are for the taxpayer and General Attorney’s Office to agree on the terms of settlement to be proposed to the tax court. In Harvest Vinccler’s case, the wording of the settlement is in the advanced stages and the amounts are already agreed upon. We are waiting on the tax courts to confirm the settlement.

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.

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 NYSE under the symbol “HNR”. As of December 31, 2008, there were 32,683,989 shares of common stock outstanding, with approximately 543 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

	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

	2008	First quarter		13.02		10.32
		Second quarter		12.84		9.03
		Third quarter		11.31		9.06
		Fourth quarter		9.59		3.84

On March 9, 2009, the last sales price for the common stock as reported by the NYSE was $2.70 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, 2008

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

3,629,334

8.82

161,515

Equity compensation plans not approved by security holders (1)

514,050

8.36

—

Total

4,143,384

8.77

161,515


(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.

PURCHASES OF EQUITY SECURITIES

During the year ended December 31, 2008, we repurchased shares of our common stock on the open market as follows:


					Total Number
					of Shares		Maximum Number (or
					Purchased as		Approximate Dollar Value)
	Total				Part of Publicly		of Shares that May Yet Be
	Number of		Average		Announced		Purchased Under the Plans
	Shares		Price Paid		Plans or		or Programs
Period	Purchased		Per Share		Programs		(in millions)
May 2008		1,365,955	$	10.41		1,365,955	$	3.0
June 2008		250,128	$	11.91		250,128	$	—

Total⁽¹⁾		1,616,083	$	10.64		1,616,083	$	—


August 2008		414,900	$	10.70		414,900	$	15.6
September 2008		640,600	$	10.53		640,600	$	8.8
November 2008		145,000	$	7.05		145,000	$	7.8

Total⁽²⁾		1,200,500	$	10.17		1,200,500	$	7.8


(1)		In June 2007, our Board of Directors authorized the purchase of up to $50 million of our common stock from time to time through open market transactions. For 2008, we repurchased 1.6 million of our ordinary shares at a cost of $17.2 million, and from inception, we have purchased a total of 4.6 million of our ordinary shares at a total cost of $50 million.

(2)		In July 2008, our Board of Directors authorized the purchase of up to $20 million of our common stock from time to time through open market transactions. The repurchase program does not have an established expiration date and may be suspended or discontinued at any time. From inception through December 31, 2008, we have repurchased a total of 1.2 million of our ordinary shares at a total cost of $12.2 million of the $20.0 million authorization.

STOCK PERFORMANCE GRAPH

The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2008, assuming an investment of $100 on December 31, 2003 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, 2003 and that all dividends were reinvested.

PLOT POINTS
(December 31 of each year)


	2003		2004		2005		2006		2007		2008
Harvest Natural Resources, Inc.	$	100	$	174	$	89	$	107	$	126	$	43
Dow Jones US E&P Index	$	100	$	144	$	239	$	251	$	352	$	205
S&P 500 Index	$	100	$	111	$	116	$	135	$	142	$	90

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, 2008. 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. Financial information for 2007 has been restated to reflect the correction of an error related to deferred tax adjustments to reconcile our share of Petrodelta’s Net Income reported under IFRS to that required under accounting principles generally accepted in the United States of America (“GAAP”) and recorded within our Net income from unconsolidated equity affiliates. See Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 1 — Organization and Summary of Significant Accounting Policies — Restatement. 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.


	Year Ended December 31,
	2008⁽¹⁾			2007⁽¹⁾⁽³⁾ (restated)			2006⁽¹⁾			2005		2004
	(in thousands, except per share data)
Statement of Operations:
Total revenues	$	—		$	11,217		$	59,506		$	236,941	$	186,066
Operating income (loss)		(54,440	)		(19,536	)		574			104,571		70,547
Net income from Unconsolidated Equity Affiliates		34,576			55,297			—			—		—
Net income (loss)		(21,464	)		60,118			(62,502	)		38,876		18,414
Net income (loss) per common share:
Basic	$	(0.63	)	$	1.65		$	(1.68	)	$	1.05	$	0.51

Diluted	$	(0.63	)	$	1.59		$	(1.68	)	$	1.01	$	0.48

Weighted average common shares outstanding
Basic		34,073			36,550			37,225			36,949		36,128
Diluted		34,073			37,950			37,225			38,444		38,122


	Year Ended December 31,
			2007⁽¹⁾⁽³⁾
	2008⁽¹⁾		Restated		2006⁽¹⁾		2005		2004
	(in thousands)
Balance Sheet Data:
Total assets	$	362,266	$	417,071	$	468,365	$	451,377	$	433,019
Long-term debt, net of current maturities		—		—		66,977		—		—
Stockholders’ equity ⁽²⁾		273,242		316,647		281,409		337,975		295,615


⁽¹⁾		Activities under our former OSA in Venezuela 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.

⁽²⁾		No cash dividends were declared or paid during the periods presented.

⁽³⁾		See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations for information on the restatement of 2007 information recorded in this Annual report on Form 10-K for the year ended December 31, 2008.

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

Restatement

As discussed in Part IV, Item 15, Notes to Consolidated Financial Statements, Note 1 – Organization and Summary of Significant Accounting Policies — Restatement and Exhibits and Financial Statement Schedules, Quarterly Financial Data (unaudited), we are restating our historical financial statements for the year ended December 31, 2007 and quarterly information for the quarters ended December 31, 2007, March 31, 2008, June 30, 2008 and September 30, 2008. The restatements relate to the correction of an error in the deferred tax adjustment to reconcile our share of Petrodelta’s Net Income reported under IFRS to that required under GAAP and recorded within Net income from unconsolidated equity affiliates. We are presenting this restatement herein.

The following tables set forth the effect of the adjustments described above on the consolidated statement of operations for the year ended December 31, 2007 and for the consolidated balance sheet as of December 31, 2007. There was no impact on net cash used in operating activities in the consolidated statements of cash flows.

Consolidated Statements of Operations


	December 31, 2007
	As Previously					as
	Reported		Adjustment			Restated
	*(in thousands, except per share data)*
Income before income taxes and minority interest	$	30,914	$	—		$	30,914
Income tax expense		6,312		—			6,312

Income before minority interest		24,602		—			24,602
Minority interest in consolidated subsidiary		19,060		721			19,781

Income from consolidated companies		5,542		(721	)		4,821
Net income from unconsolidated equity affiliates		51,695		3,602			55,297

Net income	$	57,237	$	2,881		$	60,118


Net Income Per Common Share:
Basic	$	1.57	$	0.08		$	1.65
Diluted	$	1.51	$	0.08		$	1.59

Consolidated Balance Sheets


	December 31, 2007
	As Previously				as
	Reported		Adjustment		Restated
	*( in thousands)*
Investment in equity affiliates	$	251,173	$	3,602	$	254,775
Total assets		413,469		3,602		417,071
Minority interest		56,825		721		57,546
Retained earnings		147,934		2,881		150,815
Total shareholders’ equity		313,766		2,881		316,647
Total liabilities and shareholders’ equity		413,469		3,602		417,071

Operations

We had a loss of $21.5 million, or $0.63 per diluted share, for the twelve months ended December 31, 2008 compared to earnings of $60.1 million, or $1.59 per diluted share, for 2007. Net loss for the year ended December 31, 2008 includes $16.4 million of exploration expense, $10.8 million of dry hole expense and the net equity income from Petrodelta’s operations of $35.9 million. Net income for the year ended December 31, 2007 includes the net equity income from Petrodelta’s operations from April 1, 2006 through December 31, 2007 of $55.7 million, and gains from the exchange of financial securities of $49.6 million.

Petrodelta — Venezuela

During 2008, Petrodelta drilled and completed eight successful development wells and suspended one well due to problems with the well, produced approximately 5.5 million barrels of oil and sold 10.7 billion cubic feet (BCF) of natural gas. Petrodelta has been advised by the Venezuelan government that the 2009 production objective will be approximately 16,000 barrels of oil per day effective January 1, 2009, following the December 17, 2008 OPEC meeting establishing new production quotas. Petrodelta’s production output for the first quarter of 2009 is projected to be 18,000 barrels per day to comply with the Venezuelan government’s market allocations of the OPEC quota for the country.

Petrodelta shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. The management and board of Petrodelta have taken actions to reduce both operating and capital expenditures. Currently, Petrodelta has two drilling rigs operating in the Uracoa field and one drilling rig in the Temblador field and has released three additional drilling rigs. For 2009, the initial drilling program includes utilizing two rigs to drill development and appraisal wells for both maintaining production capacity and appraising the substantial resource bases in the presently non-producing Isleño and El Salto fields. Petrodelta’s results and operating information is more fully described in Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 7 — Investment in Equity Affiliates — Petrodelta, S.A.

Diversification

Beginning in 2005, we recognized the need to diversify our asset base as part of our strategy. We broadened our strategy 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 2008 opening of our Singapore office, as well as our minority equity investment 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. Our exploration expense increased due to a project screening effort which culminated in the opening of our Singapore office and the increase in staff to manage our new United States activities. In 2008, we acquired very attractive exploration assets in Gabon, Indonesia and the United States that fit our strategy.

United States

The parties focused on two initial prospects for evaluation and completed essentially all leasing of each prospect area during 2008. The other party is obligated to evaluate and present additional opportunities at their sole cost. As each prospect is accepted it will be covered by the AMI. At year end 2008, we have met $16.4 million of the total $20 million funding obligation under the terms of the AMI. After the remainder of the $20 million funding obligation is met, all subsequent costs will be shared by the parties in proportion to their working interests as defined in the AMI agreement.

During the year ended December 31, 2008, operational activities in the West Bay prospect, the second exploratory prospect in the AMI, included re-processing of 3-D seismic, site surveying, and preparation of preliminary engineering documents. On December 8, 2008, we submitted an Application to Install Structures to Drill and Produce Oil and Gas with the U. S. Army Corps of Engineers — Galveston District. At December 31, 2008, the permit application was under review by the Corps of Engineers. Drilling is expected to commence upon receipt of the requisite permit from the Corps of Engineers, which we expect to obtain in late 2009 or early 2010. During the year ended December 31, 2008, we incurred $5.4 million for land acquisition, seismic, surveying and permitting. The expected budget for this project in 2009 is $0.5 million.

In October 2007, we entered into the JEDA with a private party to pursue a lease acquisition program and drilling program on the Antelope project in the Western United States. We are the operator and have a working interest of 50 percent in the project. The other party is obligated to assemble the lease position on the project. We will earn our 50 percent working interest in the project by compensating the other party for leases acquired in accordance with terms defined in the JEDA, and by drilling one deep natural gas test well at our sole expense. The Antelope project is targeted to explore for and develop oil and natural gas from multiple reservoir horizons in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties. Leads and/or prospects have been identified in three prospective reservoir horizons in preparation for anticipated drilling of one or more prospects in 2009. Operational activities during 2008 on the Antelope project were focused primarily on leasing. In addition to leasing activities, other operational activities during 2008 were focused on preparations for anticipated drilling in 2009. We opened a small field office and hired two employees in Roosevelt, Utah in September 2008 to support field activities. Other activities included surveying, preliminary engineering, and preparations for permitting. In December 2008, we filed Applications for Permits to Drill eight shallow oil wells with the State of Utah Department of Natural Resources Division of Oil, Gas, and Mining. The permit applications were still being processed as of February 27, 2009. The cost of the eight shallow oil wells will be borne 50 percent by us and 50 percent by the other party participating in the project. Drilling of the shallow oil wells will not materially contribute to meeting our lease earning obligation under the Agreement. Through December 31, 2008, we have incurred $8.4 million for lease acquisition and permitting. The projected 2009 budget for leasehold acquisition and exploratory drilling is $18.3 million.

Budong-Budong Project, Indonesia

In November 2008, we opened a small field office in Jakarta, Indonesia and hired four employees to support field activities. In December 2008, the acquisition program of 650 kilometers of 2-D seismic was completed. The data is currently being processed. Interpretation of the data and well planning will take place in the first quarter of 2009. It is expected that the first of two exploration wells will spud in the second half of 2009. In accordance with the farm-in agreement, we expect to fund 100 percent of the well expenditures to earn our 47 percent working interest up to a cap of $10.7 million; thereafter, we will pay in proportion to our working interest. During the year ended December 31, 2008, we incurred $7.7 million including the carry obligation for the 2-D seismic acquisition and other costs. The projected 2009 project expenditures (net to us including our funding commitment) for the exploratory well drilling are $8.1 million.

Dussafu Project — Gabon

In October 2008, the acquisition of 650 kilometers of 2-D seismic was completed which is now being processed to define the syn-rift potential similar to the Lucina and M’Baya fields. In addition, during the three months ended December 31, 2008, we commenced the reprocessing of 1,076 square kilometers of existing 3-D seismic to define the sub-salt structure to unlock the potential of the Gamba play that is producing in the Etame field to the north. We expect the seismic to mature the prospect inventory to make a decision in 2009 for a well in 2010. During the year ended December 31, 2008, we incurred $8.8 million for acreage acquisition and exploration activity. The projected 2009 project expenditures (net to our working interest) for exploration activities are $2.2 million. This includes $1.8 million of well planning and long-lead well items if the decision is made to drill a well.

Other Exploration Projects

Relating to other projects, we incurred $2.7 million during the year ended December 31, 2008. We have budgeted to spend $2.0 million in leasehold acquisition costs, $4.5 million in seismic acquisition and processing costs, $2.8 million on other project related costs in 2009 and $0.4 million in office and computer systems.

Either one of the two exploratory wells to be drilled in 2009 on the Antelope project and the Budong PSC can have a significant impact on our ability to obtain financing, record reserves and generate cash flow in 2010 and beyond.

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 recent precipitous drop in oil crude oil prices and the expectation that dividends from Petrodelta will be minimal over the next two years has restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere.

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;

	•		continue to 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, we acquired a minority equity investment 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.

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 OGTC as a minority interest in 2005 and the first quarter of 2006. Since April 1, 2006, our minority equity investment in Petrodelta has been reflected under the equity method of accounting. We recorded the cumulative effect from April 1, 2006 to December 31, 2007 in the three months ended December 31, 2007. The year ended December 31, 2008 includes net income from unconsolidated equity affiliates for Petrodelta on a current basis. See Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 7 — Investment in Equity Affiliates — Petrodelta, S.A. for Petrodelta’s results of operations which reflect the results for the years ended December 31, 2008 and 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, 2008 and the financial condition as of December 31, 2008 and 2007 in conjunction with our Consolidated Financial Statements and related Notes thereto.

Years Ended December 31, 2008 and 2007

We reported a net loss of $21.5 million, or $0.63 diluted earnings per share, for 2008 compared to net income of $60.1 million, or $1.59 diluted earnings per share, for 2007.

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 2008 or 2007 due to the conversion of the OSA to a minority equity investment in Petrodelta.

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


	Year Ended
	December 31,						Increase
	2008			2007			(Decrease)
Exploration expense	$	16.4		$	0.9		$	15.5
Dry hole costs		10.8			—			10.8
General and administrative		27.2			29.1			(1.9	)
Taxes other than on income		(0.2	)		0.4			(0.6	)
Gain on financing transactions		(3.4	)		(49.6	)		46.2
Investment income and other		(3.7	)		(9.1	)		5.4
Interest expense		1.7			8.2			(6.5	)
Income tax expense		—			6.3			(6.3	)

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. During the year ended December 31, 2008, we incurred $16.4 million of exploration costs related to the purchase and re-processing of seismic related to our United States operations, acquisition of seismic related to our Indonesia operations, and other general business development activities. Also during the year ended December 31, 2008, we incurred $10.8 million of dry hole costs related to the Harvest Hunter #1 well, which in January 2009 was determined to have no commercial quantities of hydrocarbons and was plugged and abandoned. The balance of any costs incurred for the drilling of the Harvest Hunter #1 well will be expensed in 2009 and are not expected to be material. During the year ended December 31, 2007, we incurred $0.9 million of exploration costs related to other foreign general business development.

General and administrative costs were lower in the year ended December 31, 2008, than in the year ended December 31, 2007, primarily due to employee related expenses and lower contract services. Taxes other than income for the year ended December 31, 2008, were lower than the year ended December 31, 2007 due to the reversal of a $1.1 million franchise tax provision that is no longer required.

During the years ended December 31, 2008 and 2007, we entered into securities exchange transactions exchanging U.S. government securities for U.S. Dollar indexed debt issued by the Venezuelan government. These security exchange transactions resulted in a $3.4 million and $49.6 million gain on financing transactions for the years ended December 31, 2008 and 2007, respectively.

Investment earnings and other decreased in the year ended December 31, 2008, as compared to the same period of the prior year due to lower interest rates earned on lower cash balances. Interest expense decreased due to the payment of Harvest Vinccler’s Venezuelan Bolivar (“Bolivar”) denominated debt in July of 2008.

For the year ended December 31, 2008, income tax expense, which is comprised of income tax on our foreign activities and withholding tax on interest income from Harvest Vinccler, was lower than that of the year ended December 31, 2007, partially due to the $49.6 million gain on financing transactions occurring in the year ended December 31, 2007 compared to a $3.4 million gain on financing transactions occurring in the year ended December 31, 2008. The reduction in income tax expense was also partially due to the reduction in the rate of withholding tax on the Venezuela interest, which went from 10 percent to 5 percent under the Netherlands-Venezuela double tax treaty. No income tax benefit is recorded for the net operating losses incurred as a full valuation allowance has been placed on the related deferred tax asset as management believes that is more likely than not that additional net losses will not be realized through future taxable income. There was no utilization of net operating loss carryforwards in the year ended December 31, 2008.

Years Ended December 31, 2007 and 2006

We reported net income of $60.1 million, or $1.59 diluted earnings per share, for 2007 compared with a net loss of $62.5 million, or $1.68 diluted earnings per share, for 2006.

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)
Exploration expense	$	0.9		$	—		$	0.9
General and administrative		29.1			26.4			2.7
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	)		(9.3	)		0.2
Interest expense		8.2			23.2			(15.0	)
Income tax expense		6.3			60.9			(54.6	)

General and administrative expenses increased due to employee related expenses offset by lower contract services. Harvest Vinccler accrued $3.9 million in the year ended December 31, 2006 for the estimated 2006 and 2007 Science and Technology contribution liability which was based on gross revenues for 2005 and 2006. Harvest Vinccler did not have any gross revenue subject to this law after March 31, 2006. Taxes other than on income decreased due to the elimination of municipal taxes which were based on oil deliveries under the OSA.

During the year ended December 31, 2007, we entered into securities exchange transactions exchanging U.S. government securities for U.S. Dollar indexed debt issued by the Venezuelan government. These security exchange transactions resulted in a $49.6 million gain on financing transactions for the year ended December 31, 2008. There were no such financing transactions entered into during the year ended December 31, 2006.

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.

Capital Resources and Liquidity

For calendar year 2009, we have preliminarily established an exploration and drilling budget of approximately $38.8 million. We are concentrating a substantial portion of this budget on the development of our Antelope project and Budong PSC. While we can give no assurance, we believe that our cash on hand will provide sufficient capital resources and liquidity to fund our exploration and business development expenditures for at least the next 12 months. We also currently believe that Petrodelta will fund its own operations and continue to pay dividends. In Item 1A — Risk Factors, we discuss a number of variables and risks related to our minority equity investment in Petrodelta and exploration projects that could significantly utilize our cash balances, affect our capital resources and liquidity. 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 due to this inability.

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 partially 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. The Venezuelan currency conversion restriction has not adversely affected our ability to meet short-term loan obligations and operating requirements for the foreseeable future.

Working Capital. Our capital resources and liquidity are affected by the ability of Petrodelta to pay dividends. In May 2008, Petrodelta declared and paid a dividend of $181 million, $72.5 million net to HNR Finance ($58 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the period of April 1, 2006 through December 31, 2007. In October 2008, Petrodelta paid an advance dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the six months ended June 30, 2008. We expect to receive future dividends from Petrodelta; however, we expect the amount of any future dividends to be much lower over the next several years as Petrodelta reinvests more of its earnings into the company in support of its drilling and appraisal activities. In addition to reinvesting earnings into the company in support of its drilling and appraisal activities, the recent decline in the price per barrel affects Petrodelta’s ability to pay dividends. Until oil prices increase, all available cash will be used to meet current operating requirements and will not be available for dividends. See Item 1 — Business, Item 1A — Risk Factors and Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Our current cash and cash equivalents include money market funds and short term certificates of deposits with original maturity dates of less than three months. These investments are highly liquid and should not be impacted by the current credit crisis.

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)
	2008			2007 (restated)			2006
Net cash provided by (used in) operating activities	$	50,380		$	(20,655	)	$	(24,448	)
Net cash provided by (used in) investing activities		(23,055	)		69,960			(90,556	)
Net cash provided by (used in) financing activities		(51,001	)		(76,543	)		100,064

Net decrease in cash	$	(23,676	)	$	(27,238	)	$	(14,940	)


Working Capital		77,010			111,534			117,564
Current Ratio		3.0			3.6			2.4
Total Cash, including restricted cash		97,165			127,610			236,968
Total Debt		—			9,302			104,651

The decrease in working capital of $34.5 million was primarily due to the payment of the accounts payable related party, repurchase of treasury stock, payment of a dividend to our minority equity partner in Harvest-Vinccler Dutch Holding, B.V., expenditures for drilling of an exploratory well and lease acquisition costs offset by the receipts of a $72.5 million dividend net to HNR Finance ($58 million net to our 32 percent interest) from our unconsolidated equity affiliate and payment of advances by PDVSA.

Cash Flow from Operating Activities. During the year ended December 31, 2008, net cash provided by operating activities was approximately $50.4 million. During the year ended December 31, 2007, net cash used in operating activities was approximately $20.7 million. The $71.1 million increase was primarily due to the receipts of a $72.5 million dividend net to HNR Finance ($58.0 million net to our 32 percent interest) and advance dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest) from our unconsolidated equity affiliate and payment of advances by PDVSA offset by payment of the accounts payable related party, repurchase of treasury stock, payment of a dividend to our minority equity partner in Harvest-Vinccler Dutch Holding, B.V., expenditures for drilling of an exploratory well and lease acquisition costs.

Cash Flow from Investing Activities. During the year ended December 31, 2008, we had cash capital expenditures of approximately $26.3 million. Of the 2008 expenditures, $0.1 million was attributable to exploration activity on the Budong PSC, $5.3 million was attributable to exploration activity on the Dussafu PSC, $4.2 million was attributable to exploration activity on the Antelope project, $4.7 million was attributable to exploration activity on the Gulf Coast prospects, $10.8 million was attributable to drilling costs for the Harvest Hunter #1 exploration well, and $1.2 million was for other projects. During the year ended December 31, 2007, we had limited production-related expenditures due to the pending formation of Petrodelta. In January 2007, we purchased a 45 percent minority equity interest in Fusion for $4.6 million. In October 2008, we increased our minority equity investment in Fusion by purchasing an additional two percent interest for $2.2 million. During the years ended December 31, 2008 and 2007, we had $6.8 million and $82.1 million, respectively, of restricted cash returned to us. We no longer have any cash that is restricted to our use. We incurred $1.3 million and $4.1 million of investigatory costs related to various international and domestic exploration studies during the years ended December 31, 2008 and 2007, respectively.

With the conversion to Petrodelta, Petrodelta’s capital commitments will be determined by its business plan. Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. Our budgeted capital expenditures of $38.8 million for 2009 for Gabon, Indonesia and United States operations will be funded through our existing cash balances and future Petrodelta dividends.

Cash Flow from Financing Activities. During year ended December 31, 2008, Harvest Vinccler repaid 20 million Bolivars (approximately $9.3 million) of its Bolivar denominated debt, and we redeemed the 20 percent minority interest in our Barbados affiliate. We also incurred $1.1 million in legal fees associated with prospective financing, and we paid a dividend of $14.9 million to our minority equity partner in Harvest-Vinccler Dutch Holding, B.V. During the year ended December 31, 2007, Harvest Vinccler repaid 205 million Bolivars (approximately $95.3 million) of its Bolivar denominated 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. This repurchase program was completed in June 2008. Under this program, we repurchased 4.6 million shares at an average cost of $10.93 per share, including commissions. In July 2008, our Board of Directors authorized the purchase of up to $20 million of our common stock from time to time through open market transactions. We continue to believe that Harvest stock remains undervalued and that the investment in the shares of our Company represents an attractive alternative to holding cash in excess of our needs. As of December 31, 2008, 1.2 million shares of stock have been purchased at an average cost of $10.17 per share for a total cost of $12.2 million of the $20 million authorization. Federal securities laws and the NYSE regulate the use of public disclosure of corporate inside information. These laws, rules and regulations require that we ensure information about Harvest is not used unlawfully in connection with the purchase and sale of securities. Pursuant to these laws, we are prohibited from purchasing stock while in possession of material non-public information.

Contractual Obligations

We have a lease obligation of approximately $32,000 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 $8,000 per month. This lease runs through December 2010. We also have lease commitments for an office in Utah for approximately $6,000 per month and an office in Singapore for approximately $18,000 per month. These leases expire in August and October 2010, respectively.


	Payments (in thousands) Due by Period
			Less than						After 4
Contractual Obligation	Total		1 Year		1-2 Years		3-4 Years		Years

Office Leases	$	4,334	$	1,109	$	932	$	615	$	1,678

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.

Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004 and again in March 2005. The currency conversion restrictions or the adjustment in the exchange rate have not had 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.

During the years ended December 31, 2008 and 2007, 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.

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

Investments in unconsolidated companies in which we have less than a 50 percent interest and have significant influence are accounted for under the equity method of accounting. Investment in Equity Affiliates is increased by additional investment and earnings and decreased by dividends and losses. We review our Investment in Equity Affiliates for impairment under APB 18 whenever events and circumstances indicate a decline in the recoverability of its carrying value.

We own a 49 percent minority equity interest in Fusion and a 40 percent minority equity interest in Petrodelta through our 80 percent owned subsidiary HNR Finance. Petrodelta was formed in October 2007, and the net income from unconsolidated equity affiliates from April 1, 2006 to December 31, 2007 was reflected in the three months ended December 31, 2007 consolidated statements of operations. The year ended December 31, 2008 includes net income from unconsolidated equity affiliates for Petrodelta on a current basis. No dividends were declared or paid by Fusion in the years ended December 31, 2008 or 2007. In May 2008, Petrodelta declared and paid a dividend of $181 million, $72.5 million net to HNR Finance ($58.0 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the period of April 1, 2006 through December 31, 2007. In October 2008, Petrodelta paid an advance dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the six months ended June 30, 2008. Until Petrodelta’s board of directors declares a dividend for

the year ended December 31, 2008, there is a possibility that all or a portion of the advance dividend could be rescinded; therefore, the advance dividend is reflected as a current liability on the consolidated balance sheets at December 31, 2008.

Property and Equipment

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 the wells have discovered proved commercial reserves. Exploratory drilling costs are capitalized when drilling is completed 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 for leasehold acquisition costs and the cost to acquire proved properties includes only proved developed reserves. With respect to lease and well equipment costs, which include costs and successful exploration drilling costs, the reserve base is the sum of proved developed reserves and proved undeveloped 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 Statement of Financial Accounting Standard (“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 amortized 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 amortized 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.

Reporting and Functional Currency

The U.S. Dollar is our reporting and functional currency. Amounts denominated in non-U.S. Dollar currencies are re-measured in U.S. Dollars, and all currency gains or losses are recorded in the consolidated 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 December 2007, the SEC issued Staff Accounting Bulletin (“SAB”) No. 110 (“SAB 110”) which expresses the views of the staff regarding the use of a “simplified” method, as discussed in SAB No. 107, in developing an estimate of expected term of “plain vanilla” share options in accordance with FAS 123 (revised) — Share Based Payment. The staff will continue to accept, under certain circumstances, the use of the simplified method beyond December 31, 2007. SAB 110 was effective January 1, 2008. SAB 110 will not have a material effect on our consolidated financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (“SFAS Non 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, Business Combinations. SFAS No. 141(R) establishes principles and requirements for how the acquirer recognized and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. SFAS No. (141(R) also recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and determines what information to disclose in the financial statements. SFAS No. 141(R) 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. We adopted SFAS No. 141(R) effective January 1, 2009. The adoption of SFAS No. 141(R) did not impact our consolidated financial statements, but may have material impact on our financial statements for businesses we acquire post-adoption.

In December 2007, the FASB issued SFAS 160 — Noncontrolling Interest in Consolidated Financial Statements — an amendment of Accounting Research Bulletin (“ARB”) No. 51 (“SFAS 160”). This new standard requires all entities to report noncontrolling interest in subsidiaries as equity in the consolidated financial statements. SFAS 160 is effective beginning with our first quarter 2009 financial reporting. We adopted SFAS No. 160 effective January 1, 2009. We do not expect the adoption of SFAS 160 will have a material impact on our results of operations, financial position or cash flows.

In March 2008, the Financial Accounting Standards Board (“FASB”) issued FAS 161 — Disclosures about Derivative Instruments and Hedging Activities (“FAS 161”) which changes the disclosure requirements for derivative instruments and hedging activities. FAS 161 is intended to enhance the current disclosure framework in FAS 133 — Accounting for Derivative Instruments and Hedging Activities. FAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. FAS 161 will not have a material effect on our consolidated financial position, results of operations or cash flows.

In May 2008, the Financial Accounting Standards Board (“FASB”) issued FAS 162 — The Hierarchy of Generally Accepted Accounting Principles (“FAS 162”) which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presenting in conformity with accounting principles generally accepted in the United States of America (“GAAP”). FAS 162 is effective 60 days following the SEC approval of the Public Company Accounting Oversight Board (“PCAOB”) amendments to AU Section 411, The Meaning of “Present Fairly” in Conformity With

Generally Accepted Accounting Principles. The adoption of FAS 162 will not have a material effect on our consolidated financial position, results of operation or cash flows.

On December 31, 2008, the SEC issued its revised disclosure requirements for oil and gas reserves contained in its Regulation S-K and Regulation S-X under the Securities Act of 1933, the Securities Exchange Act of 1934 and Industry Guide 2. The final rule and interpretation was published in the Federal Register on January 14, 2009 and is effective January 1, 2010. Voluntary early compliance is not permitted. In short, the rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves. We are assessing the effect, if any, the rule will have in future years on our consolidated financial position, results of operation and cash flows. The SEC is discussing the rule with the FASB staff to align FASB accounting standards with the new SEC rules. These discussions may delay the required compliance date. Absent any change in the effective date, we will comply with the disclosure requirements in our Annual Report on Form 10-K for the year ended December 31, 2009.

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 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.

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 Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, 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-38.


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

None.


Item 9A.		Controls and Procedures

Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures that are designed to ensure the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on their evaluation as of December 31, 2008, 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) were not effective because of the material weakness described in Management’s Report on Internal Control Over Financial Reporting.

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 Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. The Company did not maintain effective controls over the period-end financial reporting process as of December 31, 2008. Specifically, effective controls did not exist to ensure that the deferred tax adjustments to reconcile net income reported by Petrodelta under IFRS to that required by GAAP were completely and accurately identified and that the necessary adjustments were appropriately analyzed and recorded on a timely basis. This control deficiency resulted in the misstatement of our net income from unconsolidated equity affiliates and minority interest in consolidated subsidiary companies on our consolidated statement of operations, our investment in equity affiliate and minority interest on our consolidated balance sheet and related financial statement disclosures, and the restatements of the Company’s consolidated financial statements for the year ended December 31, 2007, and each of the first three quarters of 2008. Additionally, this control deficiency could result in misstatements of the aforementioned accounts and disclosures that would result in a material misstatement of the consolidated financial statements that would not be prevented or detected. Accordingly, our management has determined that this control deficiency constitutes a material weakness. Because of this material weakness, management concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2008.

The effectiveness of our internal control over financial reporting as of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Management’s Remediation Efforts. Management has enhanced the controls over its equity investment to ensure that adequate information regarding Petrodelta’s tax temporary differences is obtained and that a comprehensive analysis of such information is performed. Specifically, management has requested further information related to the nature of each tax temporary difference which enables management to determine the impact on the deferred tax adjustment to reconcile net income reported by Petrodelta under IFRS to that required under GAAP. The enhanced controls have enabled management to ensure that the deferred tax adjustment to reconcile net income reported by Petrodelta under IFRS to that required under GAAP is completely and accurately reconciled and identified.

Subsequent to December 31, 2008, management further enhanced the Company’s period end financial reporting controls to ensure that all necessary adjustments are appropriately analyzed and recorded on a timely basis. However, the material weakness will not be considered remediated until the enhancements are in place and operating effectively for a sufficient period of time.

Changes in Internal Control over Financial Reporting. There have been no changes in our internal control over financial reporting during our most recent quarter ended December 31, 2008 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.


Item 9B.		Other Information

None.

PART IV

Item 15. Exhibits and Financial Statement Schedules


	Page
(a) 1. Index to Financial Statements:
Report of Independent Registered Public Accounting Firm		S-1
Consolidated Balance Sheets at December 31, 2008 and 2007		S-2
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006		S-3
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2008, 2007 and 2006		S-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006		S-5
Notes to Consolidated Financial Statements		S-7
2. Consolidated Financial Statement Schedules and Other:
Schedule II — Valuation and Qualifying Accounts		S-40
Schedule III — Financial Statements and Notes for Petrodelta, S.A.		S-41

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. (Incorporated by reference to Exhibit 4.1 to our Form 10-K filed on March 17, 2008, File No. 1-10762.)

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 Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

10.8^†		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.)

10.9^†		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.)

10.10^†		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.)

10.11^†		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.)

10.12		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].)

10.13		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.)

10.14		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.)

10.15		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.)

10.16^†		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.)

10.17^†		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.)


10.18		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.)

10.19		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.)

10.20^†		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.)

10.21^†		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.)

10.22^†		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.)

10.23		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.)

10.24^†		Employment Agreement dated April 14, 2008 between Harvest Natural Resources, Inc. and Patrick R. Oenbring. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on May 1, 2008, File No. 1-10762.)

10.25^†		Stock Option Agreement dated April 14, 2008 between Harvest Natural Resources, Inc. and Patrick R. Oenbring. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on May 1, 2008, File No. 1-10762.)

10.26^†		Employee Restricted Stock Agreement dated April 14, 2008 between Harvest Natural Resources, Inc. and Patrick R. Oenbring. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on May 1, 2008, File No. 1-10762.)

10.27^†		Employment Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and Stephen C. Haynes. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)

10.28^†		Stock Option Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and Stephen C. Haynes. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)

10.29^†		Employee Restricted Stock Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and Stephen C. Haynes. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)

10.30^†		Employment Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and G. Michael Morgan. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)

10.31^†		Stock Option Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and G. Michael Morgan. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)


10.32^†		Employee Restricted Stock Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and G. Michael Morgan. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)

10.33^†		Separation Agreement dated May 31, 2008 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.7 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)

10.34^†		Separation Agreement dated May 31, 2008 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.8 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)

10.35^†		Consulting Agreement dated May 31, 2008 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.9 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)

10.36^†		Consulting Agreement dated May 31, 2008 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.10 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)

21.1		List of subsidiaries.

23.1		Consent of PricewaterhouseCoopers LLP.

23.2		Consent of Ryder Scott Company, LP.

23.3		Consent of HLB PGFA Perales, Pistone & Asociados — Caracas, Venezuela.

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 Stephen C. Haynes, 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 Stephen C. Haynes, Vice President, Chief Financial Officer and Treasurer.


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

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 Resources, Inc. and its subsidiaries at December 31, 2008 and December 31, 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 as Schedule II in 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 did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because a material weakness in internal control over financial reporting related to the period-end financial reporting process existed as of that date. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. We considered this material weakness in determining the nature, timing, and extent of audit tests applied in our audit of the 2008 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements. 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 referred to above. 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 of the consolidated financial statements, the Company has restated its 2007 consolidated financial statements to correct an error.

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 13, 2009

S-1

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS


	December 31,
	2008			2007* (restated)
	*(in thousands, except per share data)*
ASSETS
Current Assets:
Cash and cash equivalents	$	97,165		$	120,841
Restricted cash		—			6,769
Accounts and notes receivable, net		11,570			9,418
Advances to equity affiliate		3,732			16,352
Prepaid expenses and other		3,964			1,032

Total Current Assets		116,431			154,412
Other Assets		3,316			4,301
Investment in equity affiliates		218,982			254,775
Property and Equipment:
Oil and gas properties (successful efforts method)		22,328			3,163
Other administrative property		2,368			1,481

		24,696			4,644
Accumulated depreciation and amortization		(1,159	)		(1,061	)

Net Property and Equipment		23,537			3,583

	$	362,266		$	417,071


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable, trade and other	$	1,662		$	5,949
Accounts payable, related party		—			10,093
Advance from equity affiliate		20,750			—
Accrued expenses		12,241			11,895
Accrued interest		4,691			5,136
Income taxes payable		77			503
Current portion of long-term debt		—			9,302

Total Current Liabilities		39,421			42,878
Commitments and Contingencies		—			—
Minority Interest		49,603			57,546
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, 2008 and 2007; issued 39,128 shares and 38,513 shares at December 31, 2008 and 2007, respectively		391			385
Additional paid-in capital		208,868			201,938
Retained earnings		129,351			150,815
Treasury stock, at cost, 6,444 shares at December 31, 2008 and 3,719 shares at December 31, 2007, respectively		(65,368	)		(36,491	)

Total Stockholders’ Equity		273,242			316,647

	$	362,266		$	417,071


*		See Note 1 — Organization and Summary of Significant Accounting Policies — Restatement.

See accompanying notes to consolidated financial statements.

S-2

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


	Years Ended December 31,
	2008			2007* (restated)			2006
	*(in thousands, except per share data)*

Revenues
Oil sales (a)	$	—		$	11,217		$	54,858
Gas sales		—			—			4,648

		—			11,217			59,506


Expenses
Operating expenses		—			—			9,241
Depletion, depreciation and amortization		201			384			15,435
Exploration expense		16,402			850			—
Dry hole costs		10,828			—			—
General and administrative		27,215			29,096			26,421
Contribution to Science and Technology Fund		—			—			3,887
Taxes other than on income		(206	)		423			3,948

		54,440			30,753			58,932


Income (Loss) from Operations		(54,440	)		(19,536	)		574
Other Non-Operating Income (Expense)
Gain on Financing Transactions		3,421			49,623			—
Investment earnings and other		3,663			9,051			9,285
Interest expense		(1,730	)		(8,224	)		(23,156	)

		5,354			50,450			(13,871	)


Income (Loss) from Consolidated Companies Before Income Taxes and Minority Interest		(49,086	)		30,914			(13,297	)
Income Tax Expense		25			6,312			60,917

Income (Loss) Before Minority Interest		(49,111	)		24,602			(74,214	)
Minority Interest in Consolidated Subsidiary Companies		6,929			19,781			(11,712	)

Income (loss) from Consolidated Companies		(56,040	)		4,821			(62,502	)
Net Income from Unconsolidated Equity Affiliates		34,576			55,297			—

Net Income (Loss)	$	(21,464	)	$	60,118		$	(62,502	)


Net Income (Loss) Per Common Share:
Basic	$	(0.63	)	$	1.65		$	(1.68	)

Diluted	$	(0.63	)	$	1.59		$	(1.68	)


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

*		See Note 1 — Organization and Summary of Significant Accounting Policies — Restatement.

See accompanying notes to consolidated financial statements.

S-3

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


	Common				Additional
	Shares		Common		Paid-in		Retained			Treasury
	Issued		Stock		Capital		Earnings			Stock			Total

Balance at January 1, 2006		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 as previously reported		38,513		385		201,938		147,934			(36,491	)		313,766

Restatement adjustment		—		—		—		2,881			—			2,881

Balance at December 31, 2007 as restated*		38,513		385		201,938		150,815			(36,491	)		316,647
Issuance of common shares:
Exercise of stock options		547		5		1,560		—			—			1,565
Employee stock-based compensation		68		1		5,370		—			—			5,371
Purchase of Treasury Shares		—		—		—		—			(28,877	)		(28,877	)
Net Loss		—		—		—		(21,464	)		—			(21,464	)


Balance at December 31, 2008		39,128	$	391	$	208,868	$	129,351		$	(65,368	)	$	273,242

See Note 1 — Organization and Summary of Significant Accounting Policies — Restatement.

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*
	2008			restated			2006
				*(in thousands)*
Cash Flows From Operating Activities:
Net income (loss)	$	(21,464	)	$	60,118		$	(62,502	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		201			384			15,435
Dry hole costs		10,828			—			—
Gain on financing transactions		(3,421	)		(49,623	)		—
Net income from unconsolidated equity affiliates		(34,576	)		(55,297	)		—
Non-cash compensation related charges		6,061			6,108			5,056
Minority interest in consolidated subsidiary companies		6,929			19,781			(11,712	)
Deferred income taxes		—			5,608			(2,556	)
Dividend received from equity affiliate		72,530			—			—
Changes in operating assets and liabilities:
Accounts and notes receivable		548			393			61,839
Advances to equity affiliate		12,620			2,794			(19,146	)
Prepaid expenses and other		(5,632	)		214			903
Accounts payable		(2,957	)		2,122			3,419
Accounts payable, related party		(10,093	)		456			434
Advance from equity affiliate		20,750			—			—
Accrued expenses		(1,073	)		(1,251	)		(5,445	)
Accrued interest		(445	)		(1,714	)		4,213
Deferred revenue		—			(11,217	)		4,489
Income taxes payable		(426	)		469			(18,875	)

Net Cash Provided By (Used In) Operating Activities		50,380			(20,655	)		(24,448	)

Cash Flows from Investing Activities:
Additions of property and equipment		(26,317	)		(647	)		(1,657	)
Investments in equity affiliates		(2,161	)		(7,388	)		(513	)
(Increase) decrease in restricted cash		6,769			82,120			(88,889	)
Investment costs		(1,346	)		(4,125	)		503

Net Cash Provided By (Used In) Investing Activities		(23,055	)		69,960			(90,556	)

Cash Flows from Financing Activities:
Net proceeds from issuances of common stock		1,565			1,938			880
Purchase of treasury stock		(29,416	)		(32,755	)		—
Proceeds from issuance of notes payable		—			—			118,953
Financing costs		(1,075	)		—			—
Payments of note payable		(7,211	)		(45,726	)		(19,769	)
Dividend paid to minority interest		(14,864	)		—			—

Net Cash Provided By (Used In) Financing Activities		(51,001	)		(76,543	)		100,064

Net Decrease in Cash and Cash Equivalents		(23,676	)		(27,238	)		(14,940	)
Cash and Cash Equivalents at Beginning of Year		120,841			148,079			163,019

Cash and Cash Equivalents at End of Year	$	97,165		$	120,841		$	148,079

Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for interest expense	$	768		$	7,972		$	23,171

Cash paid during the year for income taxes	$	456		$	201		$	62,505


*		See Note 1 — Organization and Summary of Significant Accounting Policies — Restatement.

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

Harvest Natural Resources, Inc. (“Harvest”) 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 significant interests in the Bolivarian Republic of Venezuela (“Venezuela”) through our ownership in Petrodelta, S.A. (“Petrodelta”). 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 equity interest. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petrodelta is governed by its own charter and bylaws. In March 2008, we executed an Area of Mutual Intent (“AMI”) agreement with a private third party for an area of the Gulf Coast Region of the United States and entered into a Joint Exploration and Development Agreement (“JEDA”) in the Antelope project in the Western United States. We also have exploration acreage offshore of the People’s Republic of China (“China”), offshore of the Republic of Gabon (“Gabon”) and mainly onshore West Sulawesi in the Republic of Indonesia (“Indonesia”). See Note 9 — United States Operations, Note 10 — Indonesia and Note 11 — Gabon.

Restatement

We are restating our historical financial statements for the year ended December 31, 2007 and quarterly information for the quarters ended December 31, 2007, March 31, 2008, June 30, 2008 and September 30, 2008 (See Exhibits and Financial Statement Schedules, Quarterly Financial Data (unaudited)). The restatements relate to the correction of an error in the deferred tax adjustment to reconcile our share of Petrodelta’s Net Income reported under International Financial Reporting Standards (“IFRS”) to that required under accounting principles generally accepted in the United States of America (“GAAP”) and recorded within Net income from unconsolidated equity affiliates.

Consolidated Statements of Operations


	December 31, 2007
	As Previously					as
	Reported		Adjustment			Restated
	*(in thousands, except per share data)*
Income before income taxes and minority interest	$	30,914	$	—		$	30,914
Income tax expense		6,312		—			6,312

Income before minority interest		24,602		—			24,602
Minority interest in consolidated subsidiary		19,060		721			19,781

Income from consolidated companies		5,542		(721	)		4,821
Net income from unconsolidated equity affiliates		51,695		3,602			55,297

Net income	$	57,237	$	2,881		$	60,118


Net Income Per Common Share:
Basic	$	1.57	$	0.08		$	1.65
Diluted	$	1.51	$	0.08		$	1.59

Consolidated Balance Sheets


	December 31, 2007
	As Previously				as
	Reported		Adjustment		Restated
	*( in thousands)*
Investment in equity affiliates	$	251,173	$	3,602	$	254,775
Total assets		413,469		3,602		417,071
Minority interest		56,825		721		57,546
Retained earnings		147,934		2,881		150,815
Total shareholders’ equity		313,766		2,881		316,647
Total liabilities and shareholders’ equity		413,469		3,602		417,071

Principles of Consolidation

Investment in Equity Affiliates

Investments in unconsolidated companies in which we have less than a 50 percent interest and have significant influence are accounted for under the equity method of accounting. Investment in Equity Affiliates is increased by additional investments and earnings and decreased by dividends and losses. We review our Investment in Equity Affiliates for impairment under Accounting Principles Board (“APB”) Opinion 18 — The equity Method of Accounting for Investments in Common Stock (“APB 18”) whenever events and circumstances indicate a decline in the recoverability of its carrying value.

We own a 49 percent minority equity interest in Fusion Geophysical, LLC (“Fusion”) and a 40 percent minority equity interest in Petrodelta through our 80 percent owned subsidiary HNR Finance. Petrodelta was formed in October 2007, and the net income from unconsolidated equity affiliates from April 1, 2006 to December 31, 2007 was reflected in the three months ended December 31, 2007 consolidated statements of operations. The year ended December 31, 2008 includes net income from unconsolidated equity affiliates for Petrodelta on a current basis. No dividends were declared or paid by Fusion in the years ended December 31, 2008 or 2007. In May 2008, Petrodelta declared and paid a dividend of $181 million, $72.5 million net to HNR Finance ($58.0 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the period of April 1, 2006 through December 31, 2007. In October 2008, Petrodelta paid an advance dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the six months ended June 30, 2008. Until Petrodelta’s board of directors declares a dividend for the year ended December 31, 2008, there is a possibility that all or a portion of the advance dividend could be rescinded; therefore, the advance dividend is reflected as a current liability on the consolidated balance sheets at December 31, 2008.

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Reporting and Functional Currency

Revenue Recognition

Oil and natural gas revenue under the Operating Service Agreement (“OSA”) was 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.

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.

Fair Value Measurements

We adopted Statement of Financial Accounting Standard (“SFAS”) No. 157, “Fair Value Measurements,” (“SFAS No. 157”) effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) No.157-2, which delayed the effective date of SFAS No.157 by one year for non-financial assets and liabilities. As defined in SFAS No.157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The adoption of SFAS No. 157 had no impact on our consolidated financial position, results of operations or cash flows.

At December 31, 2008, cash and cash equivalents include $88.6 million in a money market fund comprised of high quality, short term investments with minimal credit risk which are reported at fair value. The fair value measurement of these securities is based on quoted prices in active markets for identical assets which are defined as “Level 1” of the fair value hierarchy based on the criteria in SFAS No. 157.

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Credit Risk and Operations

All of our total consolidated revenues in 2007 and 2006 related to operations in Venezuela. During the year ended December 31, 2006, 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 PDVSA Petroleo S.A. (“PPSA”), a 100 percent owned subsidiary of PDVSA, 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.

Accounts and Notes Receivable

Notes receivable relate to prospect leasing cost financing arrangements, bear interest and can have due dates that are less than one year or more than one year. Amounts outstanding under the notes bear interest at a rate based on the current prime rate and are recorded at face value. Interest is recognized over the life of the note. We may or may not require collateral for the notes.

Each note is analyzed to determine if it is impaired pursuant to FAS No. 114 — Accounting by Creditors for Impairment of a Loan. A note is impaired if it is probable that we will not collect all principal and interest contractually due. We do not accrue interest when a note is considered impaired. All cash receipts on impaired notes are applied to reduce the accrued interest on the note until the interest is made current and, thereafter, applied to reduce the principal amount of such notes.

During the three months ended December 31, 2008, we reclassified $2.7 million of prepaid land costs for the Antelope project to notes receivable. The note is due in less than one year and bears interest at a rate of 12 percent.

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. At December 31, 2008, $1.2 million was reclassified to exploration expense.

Property and Equipment

We have $22.3 million and $3.2 million in oil and gas properties as of December 31, 2008 and 2007, respectively, all of which is unproved property. 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.

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 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

S-9

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.

During the year ended December 31, 2008, we incurred $13.9 million of exploration costs related to the purchase and re-processing of seismic for our United States operations, acquisition of seismic for our Indonesia and Gabon operations, $2.5 million of other general business development activities and $10.8 million of dry hole exploratory well costs. During the year ended December 31, 2007, we incurred $0.9 million of exploration costs related to other general business development activities. During year ended December 31, 2008, we reclassified $3.8 million of lease investigatory costs associated with our United States operations from other assets to oil and gas properties. See Note 9 — United States Operations.

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 liabilities and costs to construct or acquire offshore platforms and other facilities, are depreciated using the unit-of-production method based on total estimated proved 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 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 $13.2 million for the Gulf Coast and Western United States operations, $3.0 million for WAB-21, $5.9 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.

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 $0.2 million, $0.4 million and $0.6 million for the years ended December 31, 2008, 2007 and 2006, 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.

S-10

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 Petrodelta. The minority interest in net income and losses is subtracted or added to arrive at consolidated net income.

New Accounting Pronouncements

In December 2007, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 110 (“SAB 110”) which expresses the views of the staff regarding the use of a “simplified” method, as discussed in SAB No. 107, in developing an estimate of expected term of “plain vanilla” share options in accordance with FAS 123 (revised) — Share Based Payment. The staff will continue to accept, under certain circumstances, the use of the simplified method beyond December 31, 2007. SAB 110 was effective January 1, 2008. SAB 110 will not have a material effect on our consolidated financial position, results of operations or cash flows.

S-11

In May 2008, the Financial Accounting Standards Board (“FASB”) issued FAS 162 — The Hierarchy of Generally Accepted Accounting Principles (“FAS 162”) which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presenting in conformity with GAAP. FAS 162 is effective 60 days following the SEC approval of the Public Company Accounting Oversight Board (“PCAOB”) amendments to AU Section 411, The Meaning of “Present Fairly” in Conformity With Generally Accepted Accounting Principles. The adoption of FAS 162 will not have a material effect on our consolidated financial position, results of operation 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.

Reclassifications

Certain items in 2007 have been reclassified to conform to the 2008 financial statement presentation.

Note 2 — Long-Term Debt and Liquidity

All of our debt has been classified as current (in thousands):


	December 31,		December 31,
	2008		2007
Current portion of note payable with interest at 12.5%	$	—	$	9,302

On November 20, 2006, Harvest Vinccler entered into a three-year term loan with a Venezuelan bank for 120 million Venezuela Bolivars (“Bolivars”) (approximately $55.8 million). The first principal payment was due

S-12

180 days after the funding date in the amount of 20 million Bolivars (approximately $9.3 million), and 20 million 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 was collateralized by a $6.8 million deposit plus interest in a U.S. bank. The loan was used to meet the SENIAT, the Venezuelan income tax authority, income tax assessments and related interest, refinance a portion of a 105 million Bolivar loan and to fund operating requirements. On July 9, 2008, the loan was repaid in full and the cash collateral returned to us. See Note 13 — Gain on Financing Transactions. We have no other debt obligations.

We have incurred $1.3 million in costs related to negotiation for future financing. If successful, these costs will be amortized over the life of the financial instrument.

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 or after May 31, 2009.

	•		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.

S-13

•

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.

	•		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 protest with the Mayor’s Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. On April 10, 2008, the Tax Court suspended the case pending a response from the Mayor’s Office to the protest. If the Municipality’s response is to confirm the assessment, Harvest Vinccler will defer to the competent Tax Court 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 both 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 both claims.

S-14

Note 4 — Taxes

Taxes Other Than on Income

The components of taxes other than on income were (in thousands):


	2008			2007		2006
Venezuelan municipal taxes	$	—		$	—	$	3,191
Franchise taxes		(951	)		166		175
Payroll and other taxes		745			257		582

	$	(206	)	$	423	$	3,948

During the year ended December 31, 2008, we reversed a $1.1 million franchise tax provision that is no longer required.

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 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 was paid in the first quarter of 2008.

Taxes on Income

The tax effects of significant items comprising our net deferred income taxes as of December 31, 2008, are as follows (in thousands):


	2008
Deferred tax assets:
Operating loss carryforwards	$	7,547
Dry hole costs		4,060
Stock options		1,680
Valuation allowance		(7,841	)

Net deferred tax asset		5,446
Deferred tax liability:
Tax on undistributed earnings		(5,446	)

Net deferred tax asset (liability)	$	—

We currently have undistributed earnings from foreign affiliates of $40.0 million at our Netherlands Antilles subsidiary, HNR Energia B.V. Of that amount, $15.5 million would be subject to United States income tax if distributed to us. We have provided for income tax on the undistributed earnings; however, as a result of our deferred tax assets, the recording of the income tax did not have an impact on our earnings.

S-15

The valuation allowance increased by $7.8 million as a result of additional net operating losses and tax benefits that we do not expect to fully realize through future taxable income. Realization of deferred tax assets associated with net operating loss carryforwards is dependent upon generating sufficient taxable income prior to their expiration.

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


	2008			2007			2006
Income (loss) before income taxes
United States	$	(34,760	)	$	(17,786	)	$	(15,688	)
Foreign		(14,326	)		48,700			2,391

Total	$	(49,086	)	$	30,914		$	(13,297	)

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


	2008			2007		2006
Current:
United States	$	(128	)	$	400	$	—
Foreign		153			5,912		63,473

		25			6,312		63,473

Deferred:
Foreign		—			—		(2,556	)

	$	25		$	6,312	$	60,917

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


	2008			2007			2006
Computed tax expense (benefit) at the statutory rate	$	(17,180	)	$	10,820		$	(2,930	)
Effect of foreign source income and rate differentials on foreign income		5,167			(11,140	)		8,563
Change in valuation allowance		6,059			1,085			5,446
Tax on undistributed earnings		5,446			—			—
Deemed income inclusion under Subpart F		968			12,942			—
Venezuela tax settlement		—			—			49,793
Net operating loss utilization		—			(7,306	)		—
Foreign disregarded entities		(268	)		—			—
Return to accrual adjustment		(166	)		—			—
Other		(1	)		(89	)		45

Total income tax expense	$	25		$	6,312		$	60,917

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

At December 31, 2008, we had, for federal income tax purposes, operating loss carryforwards of approximately $21.5 million, expiring in the years 2026 through 2028.

FIN 48 Disclosure

Effective January 1, 2007, we adopted FASB 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.

S-16

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 2005. To date, the Internal Revenue Service (“IRS”) has not performed an examination of our U.S. income tax returns for 2005 through 2007.

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 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 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.

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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, 2008, 2007 and 2006 and changes during the years ending on those dates is presented below (shares in thousands):


	2008						2007						2006
	Weighted						Weighted						Weighted
	Average						Average						Average
	Exercise						Exercise						Exercise
	Price			Shares			Price			Shares			Price			Shares
Outstanding at beginning of the year:	$	7.80			4,172		$	7.70			4,123		$	8.61			4,070
Options granted		10.28			444			9.63			866			10.62			558
Options exercised		(2.86	)		(548	)		(4.73	)		(397	)		(5.69	)		(65	)
Options cancelled		(11.34	)		(285	)		(13.49	)		(420	)		(19.96	)		(440	)

Outstanding at end of the year		8.54			3,783			7.80			4,172			7.70			4,123

Exercisable at end of the year		7.23			2,147			5.87			2,372			5.91			2,719

Significant option groups outstanding at December 31, 2008 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 12/31/08		Life		Price		Value		at 12/31/08		Price		Value
$1.55 - $2.75		844		1.4	$	2.11	$	1,846		844	$	2.11	$	1,846
$4.86 - $7.10		176		3.7		5.74		—		176		5.74		—
$8.72 - $10.91		2,177		6.8		10.03		—		602		9.69		—
$12.50 - $13.90		586		5.9		13.13		—		525		13.12		—

		3,783					$	1,846		2,147			$	1,846

The aggregate intrinsic value in the preceding table represents the total pretax intrinsic value based on our closing stock price of $4.30 of December 31, 2008, which would have been received by the option holders had all option holders exercised their options as of that date. Of the number outstanding, 318,750 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:	2008			2007			2006

Weighted average fair value	$	5.85		$	4.67		$	5.98
Weighted averaged expected life		7			7			7
Valuation assumptions:
Expected volatility		46.6-49.7	%		47.7-48.7	%		49.9%-53.3	%
Risk-free interest rate		3.0-3.9	%		4.5%-4.6	%		4.6%-5.2	%
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

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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 options as of December 31, 2008, and changes during the year ended December 31, 2008, is presented below (shares in thousands):


				Weighted-Average
				Grant-Date
Nonvested Shares	Shares			Fair Value
Nonvested at January 1, 2008		1,850		$	5.83
Granted		754			5.85
Vested		(624	)		(5.87	)
Forfeited		(1	)		(5.62	)

Nonvested at December 31, 2008		1,979		$	5.80

As of December 31, 2008, there was $5.8 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under our plans. That cost is expected to be recognized over the next three to five years. The total fair value of shares vested during the years ended December 31, 2008, 2007 and 2006 was $4.0 million, $4.5 million and $4.1 million, respectively.

In addition to options issued pursuant to the plans, options have been issued to new hire employees as employment inducement grants under a New York Stock Exchange (“NYSE”) exception. These options were granted in 2007 and 2008 between $10.07 and $12.63 and vest over three years. At December 31, 2008, a total of 360,000 options issued outside of the plans were outstanding and 16,667 options were exercisable.

Stock options of 0.5 million were exercised in the year ended December 31, 2008 resulting in cash proceeds of $1.6 million. Stock options of 0.4 million were exercised in the year ended December 31, 2007, resulting in cash proceeds of $1.9 million.

Treasury Stock Buy-Back Program

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. The results of operations and economic benefits of our minority equity investment in Petrodelta from April 1, 2006 through December 31, 2007 were recorded in the three months ended December 31, 2007 as Net Income from Unconsolidated Equity Affiliates. See Note 7 — Investment in Equity Affiliates, Petrodelta S.A. 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

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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.


	2008			2007 (restated)			2006
	(in thousands)
Segment Revenues
Oil and gas sales:
Venezuela	$	—		$	11,217		$	59,506

Total oil and gas sales		—			11,217			59,506

Segment Income (Loss)
Venezuela		33,020			79,878			(46,835	)
Indonesia		(8,966	)		(7	)		—
United States and other		(45,518	)		(19,753	)		(15,667	)

Net income (loss)	$	(21,464	)	$	60,118		$	(62,502	)


	December 31,			December31,
	2008			2007 (restated)
	(in thousands)
Operating Segment Assets
Venezuela	$	231,755		$	306,644
Indonesia		1,556			26
United States and other		152,184			126,747

		385,495			433,417
Intersegment eliminations		(23,229	)		(16,346	)

	$	362,266		$	417,071

Note 7 — Investment in Equity Affiliates

Petrodelta, S.A.

On October 25, 2007, the Venezuelan Presidential Decree which formally transferred 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 that date. Petrodelta has undertaken its operations in accordance with the Business Plan as set forth in 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 2009 budget for Petrodelta’s Business Plan has not yet been approved by its shareholders.

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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 PDVSA Petroleo S.A. (“PPSA”), a 100 percent owned subsidiary of PDVSA; 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 Conversion Contract and related documents state that Petrodelta will issue invoices monthly to PPSA for hydrocarbon sales, and payment is due from PPSA within 30 days of invoicing. Petrodelta invoiced PPSA for 2006 and 2007 hydrocarbon sales, but PPSA has not made payment against the invoices. The Conversion Contract and related documents also state that PDVSA is to submit invoices to Petrodelta for services and materials rendered to Petrodelta. PDVSA has not been issuing invoices. Since Petrodelta has not received payments from PPSA on the hydrocarbon sales invoices issued for 2006 and 2007, in April 2008, Petrodelta began accruing interest on late payment of invoices under the Conversion Contract provisions. PDVSA has been netting revenues and expenses and advancing funds to Petrodelta sufficient to pay Petrodelta’s operating expenses, capital expenditures and dividends distribution requirements according to financial statements. It is our understanding that PDVSA considers all 2006 and 2007 receivables and payables settled with the payment of the dividend in May 2008. On December 11, 2008, Petrodelta’s Board approved a resolution to settle the 2006 and 2007 hydrocarbon invoices against the account payable to PDVSA for 2006 and 2007 cash advances and the dividend received in May 2008. On January 22, 2009, CVP notified all mixed companies, including Petrodelta, that they must net the outstanding accounts payable balance with PDVSA and CVP against the revenues due from PPSA. The mixed companies were also notified that interest accrued on late payment of invoices would not be recognized or paid. Petrodelta’s December 31, 2008 balance sheet reflects the results of the netting of accounts receivable and accounts payable, and the interest income accrued on late payment of invoices for 2006, 2007 and 2008 has been reversed in its results of operations for the year ended December 31, 2008.

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$51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the six months ended June 30, 2008. Until Petrodelta’s board of directors declares a dividend for the year ended December 31, 2008, there is a possibility that all or a portion of the advance dividend could be rescinded; therefore, the advance dividend is reflected as a current liability on the consolidated balance sheets at December 31, 2008.

On April 15, 2008, the Venezuelan government published in the Official Gazette the Law of Special Contribution to Extraordinary Prices at the Hydrocarbons International Market (“original Windfall Profits Tax”). The original Windfall Profits Tax was based on prices for Brent crude, and, as instructed by CVP, Petrodelta applied the original Windfall Profits Tax to net production after deduction for royalty barrels. On July 10, 2008, the Venezuelan government published an amendment to the Windfall Profits Tax (“amended Windfall Profits Tax”) to be calculated on the Venezuelan Export Basket (“VEB”) of prices as published by the Ministry of the People’s Power for Energy and Petroleum (“MENPET”). The amended Windfall Profits Tax was made retroactive to April 15, 2008, the date of the original Windfall Profits Tax. As instructed by CVP, Petrodelta has applied the amended Windfall Profits Tax to gross oil production delivered to PDVSA since April 15, 2008 when the tax was enacted.

In 2005, Venezuela modified the Science and Technology Law (referred to as “LOCTI” in Venezuela) 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. LOCTI requires major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law to contribute two percent of their gross revenue generated in Venezuela from activities specified in the Law. The contribution is based on the previous year’s gross revenue and is due the following year. Based on legal advice from CVP, Petrodelta management concluded that for 2006 Petrodelta was not a legal entity and therefore did not generated any gross income subject to LOCTI. Based on this opinion, Petrodelta did not accrue a liability in 2007 under LOCTI. During 2008, Petrodelta accrued $12.4 million, $6.2 million net of tax, ($2.0 million net to our 32 percent interest) for contributions to LOCTI. On January 22, 2009, CVP notified all mixed companies, including Petrodelta, that PDVSA would be filing a consolidated declaration to LOCTI on the position that PDVSA had incurred sufficient qualifying expenses to cover all of its and its consolidating entities liability. The mixed companies were instructed to reverse any accrued contributions for LOCTI based on PDVSA’s filing position. Based on this notice from CVP, in December 2008, Petrodelta reversed the $12.4 million accrual to LOCTI.

Due to the recent precipitous drop in crude oil prices, our minority equity investment in Petrodelta was reviewed for impairment under APB 18. In performing this review, future net cash flows were determined based on estimated future oil and gas sales revenue less future expenditures necessary to develop and produce the reserves. Based on this review, there was no impairment to the carrying value of our minority equity investment in Petrodelta.

HNR Finance owns a 40 percent interest in Petrodelta and recorded its share of the earnings of Petrodelta from April 1, 2006 to December 31, 2007 in the three months ended December 31, 2007. The year ended December 31, 2008 includes net income from unconsolidated equity affiliates for Petrodelta on a current basis.

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Petrodelta’s financial information is prepared in accordance with IFRS which we have adjusted to conform to GAAP. All amounts through Net Income Equity Affiliate represent 100 percent of Petrodelta. Summary financial information has been presented below at December 31, 2008 and 2007, and for the years ended December 31, 2008 and 2007 (in thousands, except per unit information):


				Year Ended			Nine Months
	Year Ended			December 31,			Ended
	December 31, 2008			2007 (restated)			December 31, 2006
Barrels of oil sold		5,505			5,374			5,211
MCF of gas sold		10,700			13,456			11,519
Total Boe		7,288			7,616			7,131

Average price per barrel	$	83.22		$	58.61		$	50.98
Average price per mcf	$	1.54		$	1.54		$	1.54

Revenues:
Oil sales	$	458,113		$	314,928		$	265,625
Gas sales		16,506			20,789			17,796
Royalty		(168,790	)		(114,847	)		(96,790	)

		305,829			220,870			186,631

Expenses:
Operating expenses		52,946			21,352			22,729
Workovers		24,663			2,400			—
Depletion, depreciation and amortization		25,509			18,549			17,076
General and administrative		5,974			19,880			11,093
Windfall profits tax		56,377			—			—
Taxes other than on income		—			2,747			2,029

		165,469			64,928			52,927


Income from Operations		140,360			155,942			133,704
Interest expense		(2,329	)		—			—

Income before Income Tax		138,031			155,942			133,704

Current income tax expense		69,374			85,849			67,188
Deferred income tax benefit		(52,560	)		(21,348	)		(23,415	)

Net Income		121,217			91,441			89,931
Adjustment to reconcile to reported Net Income from Unconsolidated Equity Affiliate:
Deferred income tax benefit		34,827			12,343			23,415

Net Income Equity Affiliate		86,390			79,098			66,516
Equity interest in unconsolidated equity affiliate		40	%		40	%		40	%

Income before amortization of excess basis in equity affiliate		34,556			31,639			26,606
Amortization of excess basis in equity affiliate		(1,155	)		(2,530	)		—
Conform depletion expense to GAAP		2,533			—			—

Net income from unconsolidated equity affiliate	$	35,934		$	29,109		$	26,606

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	December 31,		December 31,
	2008		2007

Current assets	$	311,017	$	464,904
Property and equipment		211,760		190,613
Other assets		97,323		38,738
Current liabilities		260,234		287,491
Other liabilities		19,174		5,964
Net equity		340,692		400,800

Fusion Geophysical, LLC (“Fusion”)

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 and exploration strategy. Our 49 percent minority equity investment in Fusion is accounted for using the equity method of accounting. In October 2008, we increased our minority equity investment in Fusion from 45 percent to 49 percent for $2.2 million. Operating revenue and total assets represent 100 percent of Fusion. No dividends were declared or paid during the years ended December 31, 2008 and 2007, respectively. Summarized financial information for Fusion follows:


	Year Ended			Year Ended
	December 31,			December, 31
	2008			2007
	(in thousands)

Operating Revenues	$	13,063		$	7,392

Net Income (Loss)	$	(1,290	)	$	527
Equity interest in unconsolidated equity affiliate		49	%		45	%

Net income (loss) from unconsolidated equity affiliate		(632	)		237
Amortization of fair value of intangibles		(726	)		(656	)

Net loss from unconsolidated equity affiliate	$	(1,358	)	$	(419	)


	December 31,		December, 31
	2008		2007

Current assets	$	7,864	$	3,995
Total assets		30,633		14,846
Current liabilities		7,294		2,100
Total liabilities		8,281		2,100

Approximately 26 percent and seven percent of Fusion’s revenue for the years ended December 31, 2008 and 2007, respectively, was earned from Harvest or equity affiliates.

Note 8 — China Operations

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with CNOOC for March 2009 to discuss another extension for our license. 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 $3.0 million of oil and gas properties on our December 31, 2008 balance sheet.

Note 9 — United States Operations

Gulf Coast

In March 2008, we executed an AMI agreement with a private third party for an area in the upper Gulf Coast Region of the United States. We are the operator and have an initial working interest of 55 percent in the AMI. The AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana, including state waters. The private third party contributed two prospects, including the leases and proprietary 3-D seismic data sets, and numerous leads generated over the last three decades of regional geological focus. We will fund the first $20 million of new lease acquisitions, geological and geophysical studies, seismic reprocessing and drilling costs. All subsequent costs will be shared pursuant to the terms of the AMI. The parties focused on two initial prospects for evaluation and completed essentially all leasing of each prospect area during 2008. The other party is obligated to evaluate and present additional opportunities at their sole cost. As each prospect is accepted it will be covered by the AMI. At year end 2008, we have met $16.4 million of the total $20 million funding obligation under the terms of the AMI. After the remainder of the $20 million funding obligation is met, all subsequent costs will be shared by the parties in proportion to their working interests as defined in the AMI agreement.

In July 2008, we and our partners in the AMI acquired 6,510 acres of state leases representing all or part of 12 separate tracts from the State of Texas General Land Office for $2.7 million. This lease acquisition completes planned lease acquisition in the area and covers the West Bay prospect, which is the second exploratory prospect in the AMI. During the year ended December 31, 2008, operational activities in the West Bay prospect included re-processing of 3-D seismic, site surveying, and preparation of preliminary engineering documents. On December 8, 2008, we submitted an Application to Install Structures to Drill and Produce Oil and Gas with the U. S. Army Corps of Engineers — Galveston District (“Corps of Engineers”). At December 31, 2008, the permit application was under review by the Corps of Engineers. Drilling is expected to commence upon receipt of the requisite permit from the Corps of Engineers, which we expect to obtain in late 2009 or early 2010. During the year ended December 31, 2008, we incurred $5.4 million for land acquisition seismic, surveying and permitting.

Western United States — Antelope

In October 2007, we entered into a JEDA with a private party to pursue a lease acquisition program and drilling program on the Antelope project in the Western United States. We are the operator and have a working interest of 50 percent in the project. The other party is obligated to assemble the lease position on the project. We will earn our 50 percent working interest in the project by compensating the other party for leases acquired in accordance with terms defined in the JEDA, and by drilling one deep natural gas test well at our sole expense. In November 2008, we entered into a Letter Agreement/Amendment of the JEDA (the “Letter Agreement”) with the private party. The Letter Agreement clarifies several open issues in the JEDA, such as classification of $2.7 million of prepaid land costs for the Antelope project as a note receivable, addition of a requirement for the private party to partially assign leases to us prior to meeting the lease earning obligation, and clarification of the parties’ cost obligations for any shallow wells to be drilled on the project prior to the initial deep test well.

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The Antelope project is targeted to explore for and develop oil and natural gas from multiple reservoir horizons in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties. Leads and/or prospects have been identified in three prospective reservoir horizons in preparation for anticipated drilling of one or more prospects in 2009. Operational activities during 2008 on the Antelope project were focused primarily on leasing. Leases acquired during 2008 include fee leases from private landowners, as well as leases obtained from Allottees of the Ute Indian Tribe. The Allottee leases are administered by the Bureau of Indian Affairs Fort Duchesne, Utah office. In addition to leasing activities, other operational activities during 2008 were focused on preparations for anticipated drilling in 2009. We opened a small field office and hired two employees in Roosevelt, Utah in September 2008 to support field activities. Other activities included surveying, preliminary engineering, and preparations for permitting. In December 2008, we filed Applications for Permits to Drill eight shallow oil wells with the State of Utah Department of Natural Resources Division of Oil, Gas and Mining. The permit applications were still being processed as of February 25, 2009. The cost of the eight shallow oil wells will be borne 50 percent by us and 50 percent by the other party participating in the project. Drilling of the shallow oil wells will not materially contribute to meeting our lease earning obligation under the JEDA. Through December 31, 2008, we incurred $8.4 million for lease acquisition and permitting.

Note 10 — 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-Budong production sharing contract (“Budong PSC”) located mainly onshore West Sulawesi, Indonesia. Final government approval from the Ministry of Energy and Mineral Resources, Migas, was received in April 2008. We acquired our 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, our partner 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. Our partner 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 become operator if approved by BP Migas in the subsequent development and production phase.

The Budong PSC includes a ten-year exploration period and a 20-year development phase. During the initial three-year exploration phase, which began January 2007, we plan to acquire, process and interpret 2-D seismic and drill two exploration wells. In November 2008, we opened a small field office in Jakarta, Indonesia and hired four employees to support field activities. In December 2008, the acquisition program of 650 kilometers of 2-D seismic was completed. The data is currently being processed. Interpretation of the data and well planning will take place in the first quarter of 2009. It is expected that the first of two exploration wells will spud in the second half of 2009. During the year ended December 31, 2008, we incurred $7.7 million including the carry obligation for the 2-D seismic acquisition and other costs.

Note 11 — Gabon

In April 2008, we completed the purchase of a 50 percent interest in the production sharing contract related to the Dussafu Marin Permit offshore Gabon in West Africa (“Dussafu PSC’) for $4.5 million. In September 2008, we completed the purchase of an additional 16.667 percent interest in the Dussafu PSC for $1.5 million. This acquisition brings our total interest in the Dussafu PSC to 66.667 percent. We are the operator of the Dussafu PSC. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC contains 680,000 acres with water depths up 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.

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acquisition of 650 kilometers of 2-D seismic was completed which is now being processed to define the syn-rift potential similar to the Lucina and M’Baya fields. In addition, during the three months ended December 31, 2008, we commenced the reprocessing of 1,076 square kilometers of existing 3-D seismic to define the sub-salt structure to unlock the potential of the Gamba play that is producing in the Etame field to the north. We expect the seismic to mature the prospect inventory to make a decision in 2009 for a well in 2010. During the year ended December 31, 2008, we incurred $8.8 million for acreage acquisition and exploration activity.

Note 12 — 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 34.1 million, 36.5 million and 37.2 million for the years ended December 31, 2008, 2007 and 2006, 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 34.1 million, 37.9 million and 37.2 million for the years ended December 31, 2008, 2007 and 2006, respectively.

An aggregate of 1.7 million options were excluded from the earnings per share calculations because their exercise price exceeded the average price for the year ended December 31, 2008. For the years ended December 31, 2007 and 2006, 1.1 million and 1.5 million options, respectively, were excluded from the earnings per share calculations because their exercise price exceeded the average price.

Note 13 — Gain on Financing Transaction

During the years ended December 31, 2008 and 2007, Harvest Vinccler entered into security exchange transactions to effectively convert U.S. Dollars to Bolivars as Harvest Vinccler has no source for Bolivars. In these exchange transactions, one of Harvest’s affiliates 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 exchanges were 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 2.15 Bolivars to one U.S. Dollar and used the Bolivars for operating expenses and to settle 10 million Bolivars (approximately $4.6 million) of its Bolivar denominated debt. During the year ended December 31, 2008, these security exchanges resulted in a gain on financing transactions of $3.4 million. During the year ended December 31, 2007, these security exchanges resulted in a gain on financing transactions of $49.6 million.

Note 14 — 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. On July 18, 2008, the account payable, related party was repaid in full.

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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 (restated)			June 30 (restated)			September 30 (restated)			December 31
	(amounts in thousands, except per share data)
Year ended December 31, 2008
Expenses	$	(7,869	)	$	(9,530	)	$	(10,621	)	$	(26,420	)
Non-operating income		2,002			1,582			1,100			670

Loss before income taxes and minority interests		(5,867	)		(7,948	)		(9,521	)		(25,750	)
Income tax expense (benefit)		64			37			(20	)		(56	)

Loss before minority interests		(5,931	)		(7,985	)		(9,501	)		(25,694	)
Minority interests		1,673			2,057			1,045			2,154

Loss from consolidated companies		(7,604	)		(10,042	)		(10,546	)		(27,848	)
Net income from unconsolidated equity affiliates		8,809			9,409			5,309			11,049

Net income (loss)	$	1.205		$	(633	)	$	(5,237	)	$	(16,799	)

Net income (loss) per common share:
Basic	$	0.03		$	(0.02	)	$	(0.16	)	$	(0.51	)

Diluted	$	0.03		$	(0.02	)	$	(0.16	)	$	(0.51	)


	Quarter Ended
	March 31			June 30			September 30			December 31 (restated)
	(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			18,630

Income (loss) from consolidated companies		(6,466	)		(6,761	)		5,620			12,428
Net income (loss) from unconsolidated equity affiliates		(39	)		(137	)		(235	)		55,708

Net income (loss)	$	(6,505	)	$	(6,898	)	$	5,385		$	68,136


Net income (loss) per common share:
Basic	$	(0.17	)	$	(0.18	)	$	0.15		$	1.95

Diluted	$	(0.17	)	$	(0.18	)	$	0.14		$	1.86

Restatement

As discussed in Note 1 — Organization and Summary of Significant Accounting Policies, we are restating our historical financial statements for the year ended December 31, 2007 and quarterly information for the quarters ended December 31, 2007, March 31, 2008, June 30, 2008 and September 30, 2008. The restatements relate to the correction of an error in the deferred tax adjustment to reconcile our share of Petrodelta’s net income reported under International Financial Reporting Standards (“IFRS”) to that required under accounting principles generally accepted in the United States of America (“GAAP”) and recorded within Net income from unconsolidated equity affiliates.

The adjustment to record our share of Petrodelta’s net income under GAAP should have been limited to deferred tax adjustments related to non-monetary temporary differences impacted by inflationary adjustments under Venezuela law. During the 2008 year end close process, we determined that restatements were necessary because since October 1, 2007 both the monetary and non-monetary temporary differences recorded in Petrodelta’s IFRS financial statements had been adjusted in arriving at our GAAP consolidated financial statements rather than only the non-monetary temporary differences impacted by inflationary adjustments. Accordingly, we had understated our Net income from unconsolidated equity affiliates and Investment in equity affiliates.

The following tables set forth the effect of the adjustments described above for the quarterly periods from the fourth quarter of 2007 to the third quarter of 2008.

Increase (Decrease) in Quarterly Net Income


	December		March 31,		June 30,			September
(Dollars in millions)	31, 2007		2008		2008			30, 2008
Net income from unconsolidated equity affiliates as previously reported	$	52,106	$	7,558	$	11,243		$	4,534
Total adjustment		3,602		1,251		(1,834	)		775

Net income from unconsolidated equity affiliates as restated	$	55,708	$	8,809	$	9,409		$	5,309

Net income (loss) as previously reported	$	65,255	$	204	$	834		$	(5,857	)
Total adjustment		2,881		1,001		(1,467	)		620

Net income (loss) as restated	$	68,136	$	1,205	$	(633	)	$	(5,237	)

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.

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

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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
	China		Gabon		Indonesia		and Other		Total

Year Ended December 31, 2008
Acquisition costs	$	87	$	5,792	$	71	$	13,215	$	19,165
Exploration costs		41		3,016		7,647		13,979		24,683

	$	128	$	8,808	$	7,718	$	27,194	$	43,848


Year Ended December 31, 2007
Acquisition costs	$	160	$	136	$	168	$	—	$	464
Exploration costs		204		—		—		—		204

	$	364	$	136	$	168	$	—	$	668


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

	$	35	$	—	$	—	$	501	$	536

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


								United States
	China*			Gabon		Indonesia		and Other		Total

Year Ended December 31, 2008
Costs excluded from amortization	$	2,947		$	5,927	$	239	$	13,215	$	22,328


Year Ended December 31, 2007
Costs excluded from amortization	$	2,859		$	136	$	168	$	—	$	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


*		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


(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.

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 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.

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

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 due to the conversion to Petrodelta effective April 1, 2006.


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 due to the conversion to Petrodelta effective April 1, 2006.

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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.

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


	Net Venezuela
	2006^(a)
	(in thousands)
Standardized Measure at January 1	$	329,438
Sales of oil and natural gas, net of related costs		(40,361	)
Revisions to estimates of proved reserves Net changes in prices, development and production costs		—
Quantities		—
Extensions, discoveries and improved recovery, net of future costs		—
Accretion of discount		—
Net change in income taxes		—
Development costs incurred		501
Changes in timing and other		(289,578	)

Standardized Measure at December 31	$	—


(a)		All reserves have been removed due to the conversion to Petrodelta effective April 1, 2006.

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Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Petrodelta S.A. as of December 31, 2008, 2007 and 2006

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, 2008, 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, 2008
Development costs	$	7,791
Exploration costs		—

	$	7,791


Year Ended December 31, 2007
Development costs	$	972
Exploration costs		—

	$	972


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

	$	217

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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		23,566

Total expenses		36,156

Results of operations from oil and natural gas producing activities	$	23,566

TABLE IV — Quantities of Oil and Natural Gas Reserves

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.

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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, 2008 and 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
				Interest in			32%
	HNR Finance			Venezuela			Net Total
				(in thousands)
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls)

Year ended December 31, 2008
Proved Reserves at January 1, 2008		47,261			(9,452	)		37,809
Revisions/Additions		(2,984	)		597			(2,387	)
Production		(1,468	)		294			(1,174	)

Proved Reserves at end of the year		42,809			(8,561	)		34,248


Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at:
December 31, 2008		13,415			(2,683	)		10,732

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, 2008
Proved Reserves at January 1, 2008	43,084		(8,617	)	34,467
Additions	27,574		(5,515	)	22,059
Production	(2,854	)	571		(2,283	)

Proved Reserves at end of the year	67,804		(13,561	)	54,243


Proved Developed Reserves-Natural gas (MMcf) at:
December 31, 2008	30,168		(6,034	)	24,135
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, 2008
Future cash inflows from sales of oil and gas	$	1,576,312		$	(315,262	)	$	1,261,050
Future production costs		(557,043	)		111,409			(445,634	)
Future development costs		(306,500	)		61,300			(245,200	)
Future income tax expenses		(355,746	)		71,149			(284,597	)

Future net cash flows		357,023			(71,404	)		285,619
Effect of discounting net cash flows at 10%		(217,822	)		43,564			(174,258	)

Standardized measure of discounted future net cash flows	$	139,201		$	(27,840	)	$	111,361


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

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INDEPENDENT AUDITOR’S REPORT

To the Stockholders and Board of Director of
Petrodelta, S.A.

We have audited the accompanying financial statements of PETRODELTA, S.A., which comprise the statement of financial position as at December 31, 2008, and the statement of comprehensive income, statement of changes in equity and cash flow statement for the year then ended, and a summary of significant accounting policies and other explanatory notes. The financial statements as of December 31, 2007, were audited by another auditor whose report dated March, 13 2008, expressed an unqualified opinion on those statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial Reporting Standards. This responsibility includes: designing, implementing and maintaining internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error; selecting and applying appropriate accounting policies; and making accounting estimates that are reasonable in the circumstances.

Auditor’s Responsibility

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. These standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

Urbanización Valles de Camoruco. Las 4 Avenidas. Reda Building. Torre B. Oficina 5-11. Valencia. Carabobo. Venezuela.
Telfs: 58-241 8253518 / 8255337 Fax: 8259828. RIF: J-30785734-0

PGFA Perales, Pistone & Asociados es firma miembro de (HLB LOGO)

International

PETRODELTA, S.A
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Cash Flow Statements
(Expressed In Thousands)


	Years ended December 31^st,
		2008			2007			2008			2007
	Note	U.S. Dollars						Bolivars

Cash flow from operating activities
Net income			121,217			91,441			260,617			196,597

Adjustments to reconcile net income to net cash (used in) provided by operating activities —
Depletion, depreciation and amortization			25,508			18,550			54,843			39,883
Net change in provision for abandonment cost			(10,866	)		15			(23,362	)		32
Deferred income tax			(52,560	)		(21,348	)		(113,004	)		(45,898	)
Financial cost on provision for abandonment cost			2,344			544			5.039			1,170
Net changes in operating assets —
Accounts receivable			(133,756	)		116,067			(287,575	)		249,544
Material and supplies Inventories			(10,833	)		(5,549	)		(23,291	)		(11,930	)
Prepaid expenses and other assets			(20,604	)		(873	)		(44,299	)		(1,877	)
Net changes in operating liabilities
Accounts payable			321,555			(311,010	)		691,343			(668,671	)
Income taxes payable			(153,037	)		85,849			(329,030	)		184,575
Accruals and other liabilities			132,090			29,567			283,994			63,569


Total adjustments			99,841			(88,188	)		214,658			(189,603	)


Net cash (used in) provided by operating activities			221,058			3,253			475,275			6,994


Net cash used in investing activities:

Acquisition of property, plant and equipment			(39,347	)		(3,253	)		(84,596	)		(6,994	)


Net cash used in investing activities			(39,347	)		(3,253	)		(84,596	)		(6,994	)


Net cash provided by (used in) financing activities:
Paid dividends			(181,325	)		—			(389,849	)		—
Initial and additional capital contributions			—			6,977			—			15,000


Net cash provided by (used in) financing activities			(181,325	)		6,977			(389,849	)		15,000


Net cash increase			386			6,977			830			15,000

Cash and equivalents at the beginning of the period			6,977			—			15,000			—


Cash and equivalents at the end of the period			7,363			6,977			15,830			15,000

The accompanying notes from 1 to 21 are an integral part of these financial statements

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

(1)		Reporting Entity

		Petrodelta, S.A. (the Company) was incorporated in Venezuela in October 2007, as published in Official Gazette No. 38,786. Its business objective is primary exploration to discover oil reserves, extraction of oil in its natural state, and its subsequent collection, transportation and storage pursuant to Article No. 9 of the Venezuelan Hydrocarbon Law (LOH). The Company operates within an area of approximately 1,000 square kilometers in the Uracoa, Bombal and Tucupita fields (formerly the Monagas Sur Unit) and in the El Salto, El Isleño and Temblador fields in the Monagas and Delta Amacuro states in Venezuela (the assigned operating area).

		The Company was created as a result of the process for conversion into mixed-capital companies of the Operating Agreement signed on July 31, 1992 between PDVSA Petróleo, S.A. (PDVSA Petróleo) (formerly Lagoven, S.A.), Harvest Natural Resources, Inc. (Harvest) (formerly Benton Oil and Gas Company) and Venezolana de Inversiones y Construcciones Clérico, C.A. (Vinccler). As part of this process, on March 31, 2006, PDVSA Petróleo, S.A., Corporación Venezolana del Petróleo (CVP) and Harvest Vinccler, S.C.A. (HVSCA), the agreement operator and a related company of Harvest and Vinccler, signed a memorandum of understanding for conversion into a mixed company. In June 2007, the National Assembly of the Bolivarian Republic of Venezuela approved the incorporation of the mixed company Petrodelta, S.A. In August 2006, the National Assembly approved the inclusion of the Temblador, El Isleño and El Salto areas into the Monagas Sur Unit for further development of the Company’s primary activities. An agreement for conversion into a mixed company was signed between CVP and HNR Finance B.V. (HNR Finance) in September 2007. The Company will operate for 20 years as from October 2007 when the decree for transfer of field operations was published in the Official Gazette.

		Petrodelta, S.A. is 60%-owned by CVP, a wholly owned subsidiary of Petróleos de Venezuela, S.A. (PDVSA), and 40%-owned by HNR Finance.

		The Company was incorporated and is domiciled in Venezuela. Its legal address is: Avenida Veracruz con Calle Cali, Urbanización Las Mercedes, Edificio Pawa, Piso 5, Caracas, Distrito Capital. Its main offices are located at Avenida Alirio Ugarte Pelayo, Edificio Harvest Vinccler, Ala Norte, Planta Baja in Maturín, Monagas State.

		On February 26, 2009, the Board of Directors of the Company approved the issuance of the financial statements under International Financial Reporting Standards and submitted said financial statements to the Shareholders of the Company for approval purposes. Once the aforementioned financial statements are duly approved and issued, no amendment of which applies.

		Company management considers that it operates in a single business segment (hydrocarbons) in one country, the Bolivarian Republic of Venezuela, in conformity with its social statutes.

		During the transition period from April 1, 2006 to December 31, 2007, Harvest Vinccler, S.C.A. (HVSCA) was in charge of managing and developing the Company’s activities and provided its

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

		financial and operational structure for this purpose. The Company’s operating costs during this period were paid by HVSCA and CVP and subsequently charged to PDVSA Petróleo, which, in turn, will bill the Company. These costs were recognized in the income statements for the respective periods and include, but are not limited to, general, administrative, operating and capital expenses required to continue activities in the assigned operating area.

		During the years ended December 31, 2008 and 2007, the Company has operated with employees assigned by its shareholders or their related companies since it has no direct employees. At December 31, 2008, the Company had 318 employees assigned by its shareholders or their related companies. During the first quarter of 2008, 238 employees were transferred from HVSCA to PDVSA.

		Applicable regulations

		The Company’s main activities are regulated by the Venezuelan Hydrocarbon Law (LOH), effective from January 2002. Gas-related operations are regulated by the Venezuelan Gaseous Hydrocarbon Law of September 1999 and its Regulations of June 2000.

		Below are the main regulations included in the LOH:

	a)		A 30% royalty on volumes of hydrocarbon extracted.

	b)		A Partial Reform of the Extraction Tax was enacted and published in Official Gazette No. 38,443 of May 24, 2006, establishing a rate equivalent to one-third of the value of all liquid hydrocarbons extracted from any reservoir, calculated on the same basis as royalties. The taxpayer has the right to deduct from the extraction tax any sum payable as royalties (30%), including the additional royalty paid for special advantages (3.33%). At December 31, 2008 and 2007, this tax was lower than that paid and accrued by the Company for royalties and special advantages.

	c)		A surface tax equivalent to 100 tax units for each square kilometer or fraction thereof per year for licensed areas that are not under production. This tax will increase by 2% during the first five years, and by 5% during all subsequent years. Company management considers that there are no nonproductive areas.

	d)		An internal consumption tax equivalent to 10% of the value of each cubic meter of hydrocarbon derivatives produced and consumed as fuel in internal operations, calculated on the final selling price. Company management considers that, other than associated gas, no hydrocarbon derivatives are consumed.

		Hydrocarbon purchase sale agreement

		The Company signed a hydrocarbon purchase sale agreement with PDVSA Petróleo, whereby the Company undertakes to sell to the latter all hydrocarbons produced within the delimited operating area that are not being used in its operations. The Company may assign or transfer

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

this agreement, or any rights and obligations thereunder, to another company in accordance with Article No. 27 of the LOH. This agreement is for 20 years.

(2)

Basis of Preparation

	*(a)*		*Statement of compliance*

			The financial statements as of December 31, 2008 and 2007 are prepared in accordance with International Financial Reporting Standards (IFRS) adopted by the International Accounting Standards Board (IASB) and their interpretations, issued by the International Financial Reporting Interpretations Committee (IFRIC) of the IASB.

			The financial statements for the year ended December 31, 2007 have been prepared and are presented for purposes of comparison with the financial statements for the year ended December 31, 2008.

	*(b)*		*Basis of measurement*

			The financial statements have been prepared on the historic cost basis, except for certain assets and liabilities measured at fair value. Assets measured and stated at fair value are: long-term accounts receivable, recoverable tax credits, accounts receivable and cash.

			The methods used for measuring fair value are discussed in Note 5.

	*(c)*		*Functional and presentation currency*

			The financial statements are presented in U.S. dollars, the Company’s functional currency, since the main economic environment in which the Company operates is the international market for crude oil and its products. In addition, a significant portion of its revenues, as well as most costs, expenses and investments are denominated in this currency.

			The financial statements in bolivars are presented for statutory purposes. The Company’s financial statements are translated into bolivars, a currency other than the functional currency, in accordance with International Accounting Standard No. 21 The Effects of Changes in Foreign Exchange Rates. This standard requires each entity to determine its functional currency based on an analysis of the primary economic environment in which the entity operates, which is normally the one in which it primarily generates and expends cash.

			The financial statements are translated into bolivars based on the following criteria:

	•		Assets and liabilities of each statement of financial position at the exchange rates in effect at date.

	•		Income and expenses at the average exchange rate for each year.

	•		Exchange gains or losses resulting from translation are recognized as a separate equity component under Cumulative translation adjustment. During the years ended December

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

31, 2008 and 2007 the official exchange rate did not change. Consequently, a cumulative translation adjustment was not originated.

			All financial information presented in U.S. dollars has been rounded in thousands.

	*(d)*		*Currency redenomination*

			In accordance with the Decree Law for Currency Redenomination published on March 6, 2007 in Official Gazette No. 38,638, financial statements at December 31, 2008 and for the year then ended are expressed in the new monetary unit of the Bolivarian Republic of Venezuela (bolívar fuerte — BsF). All information presented for periods prior to January 1, 2008 has been expressed in this currency for comparative purposes, based on Section 5 of the Official Notice published by the Central Bank of Venezuela (BCV) on January 24, 2008, and on the pronouncement on the redenomination process issued by the Venezuelan Federation of Public Accountants on July 26, 2007.

	*(e)*		*Estimates, risks and uncertainty*

			The preparation of financial statements in conformity with IFRS requires management to make estimates, judgments and assumptions that affect the application of accounting policies and the amounts of assets, liabilities, income and expense. The Company applies its best estimates and judgments; however, actual results may differ from initial estimates.

			The related estimates and assumptions are based on experience and other factors which are considered reasonable under current circumstances and form the basis for making judgments on the carrying value of assets and liabilities not easily determined by other means. Estimates and assumptions are reviewed periodically, and revisions to accounting estimates are recognized in the period in which the estimate is revised and in any future periods affected.

			Significant areas of uncertainty affecting management’s estimates and judgment in the application of accounting policies, which significantly affect financial statement amounts are:

	•		Note 8 — depletion, depreciation and amortization

	•		Note 7 — deferred income tax

	•		Note 9 — provision for abandonment costs

	•		Note 17 — Valuation of financial instruments

	•		Note 3-r — measurement of contract-based retirement benefit obligations and other post-retirement benefits other than pensions, which are being calculated by PDVSA for subsequent billing to the Company.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

•

Note 18 — Liabilities, contingencies and accruals in respect of environmental issues

The Company’s operations may be affected by the political, legislative, regulatory and legal environment, both at the national and international level. In addition, significant changes in prices or availability of crude oil and its products may have an impact on the Company’s results of operations in any given year.

(3)		Summary of Significant Accounting Policies

		The accounting policies used for the preparation of these financial statements have been applied consistently for all periods presented.

		Certain reclassifications have been made to the 2007 financial statements to conform to the 2008 presentation.

	*(a)*		*Transactions in currencies other than the U.S dollar*

			Transactions in currencies other than the U.S. dollar are translated into the Company’s functional currency using the exchange rate in effect at the transaction date. Monetary assets and liabilities denominated in currencies other than the U.S. dollar are translated into U.S. dollars using the exchange rate prevailing at the date of the statement of financial position. Exchange gains or losses on monetary items in currencies other than the U.S. dollar represent the difference between the net cost in the functional currency at the beginning of the year, adjusted by the effective interest rate and payments made during the year, and the net cost in currencies other than the U.S. dollar translated using the year-end exchange rate. Nonmonetary assets and liabilities in currencies other than the U.S. dollar stated at fair value are retranslated to the functional currency using the exchange rate prevailing at the date fair value was determined. Exchange gains or losses resulting from retranslation are recognized in the statement of comprehensive income.

	*(b)*		*Financial instruments*

			Non-derivative financial instruments consist of cash and cash equivalents, recoverable tax credits, notes and accounts receivable, long-term accounts receivable, accounts payable to suppliers, financial debt and other liabilities.

			Non-derivate financial instruments classified as at fair value through profit or loss are initially recognized at fair value, plus any direct transaction costs.

			A financial instrument is recorded when the Company engages or commits to the contractual clauses thereof. Financial assets are reversed if the Company’s contractual rights over the asset’s cash flows expire or if the Company transfers the financial asset to another entity without retaining control or a significant portion of the asset’s risks and rewards. Regular purchases and sales of financial assets are accounted for at trade date, which is generally the date on which the Company commits to purchase or sell the asset.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

			Financial liabilities are derecognized when the Company’s specific contractual obligation expires or is paid.

			During the years ended December 31, 2008 and 2007, the Company conducted no transactions with derivative instruments.

	*(c)*		*Property, plant and equipment*

			Property, plant and equipment is stated at cost, net of accumulated depreciation and impairment losses (See Note 8). The successful efforts accounting method is used for exploration and production activities of crude oil and natural gas. All costs for development wells, related plant and equipment, and property used for oil recovery are capitalized. Costs of exploratory wells are capitalized until it is determined whether they are commercially feasible; otherwise, such costs are charged to operating expenses. Other exploratory expenditures, including geological and geophysical costs, are expensed as incurred. Costs for major maintenance or general repairs are capitalized when identified as a separate component of the asset to which such maintenance and repair corresponds and are depreciated between one maintenance period and the other. Disbursements for minor maintenance, repairs and renewals incurred to maintain facilities in operating conditions are expensed. Gains or losses arising from asset retirement or disposal are included in the income statement.

			The cost of property, plant and equipment also includes, when relevant, the amounts associated with asset retirement obligations (See Note 8).

			Finance costs of projects requiring major investments over long-term construction periods and those incurred for specific projects are capitalized and amortized over the estimated useful lives of the related assets.

			The cost of assets built by the Company includes materials and direct labor, as well as any other direct cost attributable to bringing the asset to working condition. Costs for dismantling and removal from the construction site are also included. All disbursements relating to construction or purchase of property, plant and equipment in the stage prior to implementation are stated at cost as work in progress. Once the assets are ready for use, they are transferred to the respective component of property, plant and equipment and depreciation or amortization commences.

			When parts of a property, plant and equipment asset have different useful lives, they are recorded separately as a significant component of that asset.

			Gains or losses on disposal of a property, plant and equipment item are determined by the difference between the proceeds from disposal, if any, and the net carrying amount of the asset, and is recognized under other income (expense), net in the statement of comprehensive income.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

			Depreciation and amortization of capitalized costs related to wells and facilities for the production of crude oil and gas are determined by the units of production method by field, based on proved developed reserves. The rates used are reviewed annually based on an analysis of reserves and are applied retroactively at the beginning of the year. Capitalized costs of other plant and equipment are depreciated over their estimated useful lives, mainly using the straight-line method with an average useful life of 15 years for administrative buildings and between 3 and 5 years for the remaining assets. Ordinary withdrawals are eliminated against the respective accumulated depreciation; net gains or losses from extraordinary withdrawals are included in the statement of comprehensive income.

			Depreciation methods and average useful lives of property, plant and equipment are reviewed annually.

	*(d)*		*Inventories*

			Inventories are stated at the lower of cost and net realizable value. The cost of inventories of crude oil and its products is determined using the average cost method. Materials and supplies are valued mainly at average cost, less an allowance for possible losses, and are classified into two groups: current assets and non-current assets.

			Net realizable value is the estimated selling price in the normal course of business, less costs to complete and estimated selling costs.

	*(e)*		*Trade accounts receivable*

			Trade accounts receivable are accounted for according to price formulas established in the hydrocarbon purchase sale agreement between the mixed companies and PDVSA Petróleo, whereby the former undertake to sell and PDVSA Petróleo undertakes to buy all hydrocarbons produced that are not being used in their operations within the delimited operating areas. At December 31, 2008 and 2007, the Company does not expect to incur losses on uncollectible accounts and, therefore, has not set aside a provision in this connection.

	*(f)*		*Cash and cash equivalent*

			Petrodelta, S.A. considers as cash and cash equivalents placements and time deposits maturing within three months that are readily convertible.

	*(g)*		*Impairment in the value of long-lived assets*

			Financial assets

			The Company assesses possible impairment in the value of its financial assets at each reporting date. A financial asset is impaired if there is objective evidence that one or more events have had a negative effect on the estimated future cash flows of the asset.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

			Significant financial assets are assessed individually to determine their impairment. All other financial assets sharing similar credit risk characteristics are evaluated as a group.

			Impairment losses are recognized in the statement of comprehensive income. An impairment loss is reversed if it can be objectively associated with an event occurring after the impairment loss was recognized.

			Non-financial assets

			The carrying value of non-financial assets, excluding inventories and deferred tax, is reviewed for possible impairment at each reporting date. The recoverable amount of the asset is estimated if evidence of impairment exists.

			An impairment loss is recognized for the amount by which the asset’s carrying amount or its cash-generating unit exceeds its recoverable amount. A cash-generating unit is the assets grouped at the lowest levels for which there are separately identifiable cash flows. Recoverability of assets to be held and used is measured by comparing their carrying amount to the net discounted future cash flows expected to be generated by these assets. If the carrying amount of the assets exceeds the estimated value of discounted future cash flows, an impairment loss is recognized in the income statement in the amount of such excess. The asset cost is shown net of this impairment charge. Impairment is determined by the Company based on cash-generating units, in accordance with its business segments, geographical locations and the final use of the production generated by each unit. Impairment losses may be reversed only if there has been a change in the estimates used after the impairment loss was recognized.

	*(h)*		*Costs associated with asset retirement obligations*

			The Company capitalizes estimated costs associated with obligations from retirement of assets used for exploration and crude oil and natural gas production activities, based on the future retirement plan for those assets. Cost is capitalized as part of the related long-lived asset and is amortized over its useful life with a charge to operating costs.

			Obligations associated with the retirement of long-lived assets are recorded at fair value as incurred, based on discounted future cash flows. Fair value is determined based on current regulations and technologies.

	*(i)*		*Income tax*

			Income tax expense comprises current and deferred tax. Income tax expense is recognized in the results for each year, except for items that should be directly recognized in other comprehensive income. Current tax is the estimated amount payable based on taxable income for the year, using the tax rate and the methodology established in current

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

			regulations at the balance sheet date and any adjustment to taxes payable from previous years.

			Deferred income tax is accounted for using the balance sheet method. Deferred assets and liabilities are recognized for future tax consequences attributable to differences between the carrying amounts of assets and liabilities and their respective tax bases, and operating loss and tax credit carryforwards. The value of deferred assets and liabilities is determined based on tax rates expected to be applicable to taxable income for the year in which temporary differences will be recovered or settled pursuant to law. The effect on deferred assets and liabilities of changes in tax rates is recorded in the results for the year in which such changes become effective.

			A deferred tax asset is recognized only to the extent that future taxable income will be available for offsetting. Deferred tax assets are reviewed at each reporting date and reduced to the extent that it is no longer probable that the related tax benefit will be realized.

	*(j)*		*Provisions*

			A provision is recorded if as a result of a past event the Company has a present legal or constructive obligation that can be reliably estimated and it is probable that an outflow of economic benefits will be required to settle the obligation.

			In conformity with the environmental policy established by PDVSA and current legislation, the Company recognizes a liability when costs are likely and can be reasonably estimated. Environmental expenditures that relate to income from current or future operations are recorded as expenses or assets, as applicable. Expenditures that relate to past operations that do not contribute to current or future revenue generation are expensed. These provisions are created when an obligation related to environmental remediation is identified, in respect of which the Company has the necessary information to determine a reasonable estimate of the related cost. Subsequent adjustments, if required, will be made upon receipt of additional information.

	*(k)*		*Revenue recognition*

			Income from sales of crude oil and gas is recorded in the statement of comprehensive income when risks and significant rights of ownership are transferred to PDVSA Petróleo and MPPEP as stipulated in the hydrocarbon purchase sale agreement. Income is recognized when it can be reasonably measured and it is probable that future economic benefits will flow to the Company. Income from activities other than the Company’s main business is recognized when realized. Income is not recognized when there is significant uncertainty as to the recoverability of the obligation acquired by the buyer. All of the Company results are from continuing operations.

	*(l)*		*Capital stock*

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

	*(n)*		*Legal reserve*

			The Venezuelan Code of Commerce requires companies to set aside 5% of their net income each year to a legal reserve until it reaches an amount equivalent to at least 10% of their capital stock in bolivars (See Note 14).

	*(o)*		*Dividend distribution*

			Dividend distribution to the Company’s shareholders is recognized as a liability in the financial statements in the period in which the dividends are approved by the shareholders.

	*(p)*		Accounting estimates requiring a high degree of judgment

			The Company continually evaluates judgments used to record its accounting estimates, which are recorded based on historical experience and other factors, including expectation of future events that are believed to be reasonable under the circumstances. Significant future changes to assumptions established by management may significantly affect the carrying value of assets and liabilities.

			Below is a summary of the most significant accounting estimates made by the Company:

			*Estimates of oil reserves*

			Oil and gas reserves are key elements in the Company’s decision-making process. They are also important in evaluating impairment in the carrying amount of long-lived assets. Calculation of depreciation, amortization and depletion of property, plant and equipment accounts related to hydrocarbon production requires quantification of proved developed hydrocarbon reserves expected to be recovered by the Company in the future. Reserve estimates are only approximate amounts due to the high degree of judgment and specialization required to develop the information. Reserves are calculated by specialized technical departments at Petróleos de Venezuela, S.A. (PDVSA) (related company that owns the Company’s main shareholder) and results are submitted for approval by MPPEP in order to guarantee the reasonableness of the information. Additionally, reserve studies are regularly updated to guarantee that any change in estimates is timely recorded in the Company’s financial statements.

			To date, PDVSA and an independent reserves specialist are currently reviewing, updating, and certifying oil and gas reserves assigned to the Company.

			*Assessment of impairment in the value of property, plant and equipment*

			Management annually assesses impairment in the value of property, plant and equipment. The main key assumptions considered by management to determine the recoverable amount of property, plant and equipment were income projections, oil prices, royalties, operating and capital costs and the discount rate. Projections include proved developed reserves to be produced during the development period of production activities in the

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

			assigned fields. At December 31, 2008 and 2007, the Company has not identified impairment in the carrying value of property, plant and equipment as a result of these estimates.

			*Abandonment cost calculation*

			The Company’s financial statements include an asset and a provision for property, plant and equipment used in hydrocarbon production that is expected to be abandoned in the future and in relation to which the Company will make future disbursements. Assumptions considered for the calculation of this asset and the provision for abandonment (asset abandonment costs, date of abandonment, and inflation and discount rates) may vary depending on factors such as performance in the field, changes in technology and legal requirements. Assumptions made by the Company are recorded based on technical studies and management’s experience and are regularly reviewed (See Note 9).

	*(q)*		*Related party transactions*

			The Company does not disclose, as part of balances and transactions with related companies (See Note 19), transactions with government entities conducted in the normal course of business, the terms and conditions of which are consistently applied to other public and private entities and for which there are no other suppliers, i.e., electricity, telecommunications, taxes, etc.

	*(r)*		*Accrual for employee benefits*

			Following corporate instructions from PDVSA, the related company PDVSA, S.A. assumed the employer role for employees who accepted the transfer, and are working as assigned employees to Petrodelta, S.A. operations. According to this, PDVSA Petróleo, S.A. administer and prepare those employees’ payroll and invoice direct payroll and benefits of the Company, which recognize those costs against a liability to PDVSA Petróleo, S.A. The direct payroll and benefits costs are determined by PDVSA according the following policies:

			*Termination benefits*

			The Company accrues for its liability in respect of employee termination benefits based on the provisions of the Venezuelan Labor Law and the prevailing oil-sector collective labor agreement. Under certain circumstances, the Law provides for an additional indemnity for unjustified dismissals. Most of this accrual for indemnification has been deposited in trust accounts in the name of each employee.

			On October 11, 2007, PDVSA entered into a Collective Labor Agreement, effective through 2009, so improving salaries and labor benefits for staff in the contract payroll in Venezuela. Those liabilities resulting of the application of said Collective Labor Agreement are in full effect as from November 2007.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

			*Profit sharing and bonuses*

			Liabilities in respect of labor benefits and bonuses for staff, vacation leaves, and other benefits are accounted for as incurred along with the staff’s provision of services.

			During the years ended December 31, 2008 and 2007, the Company has not had direct employees and, therefore, has not recorded liabilities derived from these labor-related benefits.

			*Retirement Plan*

			Net liabilities in respect of the retirement plan as defined in the contract are accounted for separately per each participant in said plan, by estimating the amount of future benefits to be acquired by staff versus their length of service during current and prior periods; said benefits are discounted in order to determine their current value, then it is deducted the fair market value of those assets associated to the plan. The discount rate should reflect the yield rate that, as of the date of the financial statements, is reported through financial instruments issued by credit institutions with high ratings and maturity dates that are in line with those due dates applicable to said liabilities. This calculation is made by an actuary by using the projected unit credit method.

			Improvements made to the plan’s benefits, in connection with past service cost, are expensed in the statement of profit and loss per the estimated period that, on average, will last until the moment said benefits will be paid in full. As said benefits fall under irrevocable acquired rights after approval, said expense is recorded, immediately, in the statement of income and loss.

			It is accounted for as income or expense the share corresponding to the total of unrecorded actuarial earnings or loss in excess of 10% of the greater of these sums: a) the current value of liabilities in respect of those benefits defined as of that date; and b) the reasonable value of the plan’s assets as of that date. Said caps are computed and apply separately per each plan’s benefit so defined.

			*Post-retirement benefits other than retirement*

			Net liabilities in respect of post-retirement benefits other than retirement, as defined in the contract, equal the total of future benefits earned by staff along with their length of service during current and prior periods. Said benefits include mainly: health and dental plans, burial and funeral insurance, and food electronic card. Said liabilities are computed by using the projected unit credit method; then they are deducted to reflect their current value and, if applicable, the fair market value of related assets is deducted as well. The discount rate should reflect the yield rate that, as of the date of the financial statements, is reported through financial instruments issued by credit institutions with high ratings and maturity dates that are in line with those due dates applicable to said liabilities.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

			Past service cost and the actuarial income or loss are recorded by using the method set out in the retirement plan per the contract.

	*(s)*		*New accounting standards not yet adopted*

			Certain new standards, amendments and interpretations to existing standards were not effective for the year ended December 31, 2008 and have not been applied in the preparation of the Company’s financial statements. The most important standards, amendments and interpretations for the Company are as follows:

	•		In May 2008, the IASB published the annual IFRS improvement project that included amendments to certain existing standards and interpretations not effective for the year ended December 31, 2008. The most important standards and interpretations for the Company are: IFRS 5, Non Current Assets Held for Sale and Discontinued Operations; IFRS 7, Financial Instruments: Disclosures; IAS 1, Presentation of Financial Statements; IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors; IAS 10, Events after the Reporting Period; IAS 18, Revenue; IAS 16, Property, Plant and Equipment; IAS 19, Employee Benefits; IAS 23, Borrowing Costs; IAS 27, Consolidated and Separate Financial Statements; IAS 28, Investments in Associates; IAS 29, Financial Reporting in Hyperinflationary Economies; IAS 31, Interest in Joint Ventures; IAS 34, Interim Financial Reporting; IAS 36, Impairment of Assets; IAS 39, Financial Instruments: Recognition and Measurement.

			The Company analyzed these improvements and determined no significant effects on its financial statements.

	•		In January 2008, the IASB issued revised IAS 32, Financial Instruments: Disclosure and Presentation, which requires certain financial instruments to be classified as equity when they are available and impose an obligation on the Company’s equity. This standard will be effective for accounting periods beginning on or after January 1, 2009.

			The Company analyzed this standard and determined no significant effects on its financial statements.

	•		In November 2006, the IASB issued IFRS 8, Operating Segments, effective for accounting periods beginning on or after January 1, 2009. IFRS 8 introduces the “management approach” to reporting by segment and requires the disclosure of operating segments based on internal reports that are reviewed regularly by executives or different committees in charge of the Company’s operating decision-making process for purposes of assessing segment information.

			The Company analyzed this standard and determined no significant effects on its financial statements.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

	*(t)*		*Recently adopted accounting pronouncements*

			The following standards and interpretations became effective during 2008:

	•		Interpretation No. 14 (IFRIC 14), IAS 19 — The Limit on a Defined Benefit Asset, Minimum Funding Requirements and their Interaction explains when refunds or reductions in future contributions related to a defined benefit asset are considered available, and also provides guidance on the impact of minimum funding requirements on these assets. Likewise, it clarifies when a minimum funding requirement may give rise to a liability.

	•		Interpretation No. 16 (IFRIC 16), Hedges of a Net Investment in a Foreign Operation defines conditions to identify risks that should be accounted for as hedging financial instruments under IAS 39.

			In addition, during 2008, the Company resolved to early adopt application of the following revised standards effective for accounting periods beginning on or after January 1, 2009:

	•		Revised IAS 1, Presentation of Financial Statements introduces a statement of comprehensive income, which includes the profit or loss for the period and other comprehensive income containing income and expense items not recognized in the results for the period due to requirements of other standards. In addition, according to this standard, the balance sheet will become the statement of financial position since it better reflects the function of the statement and is consistent with the terms used in the Concept Framework of International Accounting Standards.

	•		Revised IAS 23, Borrowing Costs eliminates the option to expense borrowing costs and requires capitalization of borrowing costs directly attributable to the acquisition, construction or production of a qualifying asset as part of the cost of that asset.

The Company’s accounting policies have been revised and modified, when necessary, to adopt the requirements established in these new standards or interpretations. Adoption of these standards and interpretations did not significantly affect the Company’s financial statements.

(4)

Exchange Agreement with the Central Bank of Venezuela (BCV)

On November 21, 2005, the Ministry of Finance and BCV published Exchange Agreement No. 9, which establishes that foreign currency obtained from hydrocarbon exports, including gaseous hydrocarbons, must be sold to BCV, except for foreign currency earmarked for activities conducted by PDVSA in conformity with the BCV Law Reform. Under this agreement, PDVSA and its subsidiaries may not maintain foreign currency funds in Venezuela for more than 48 hours, and establishes how these funds will be used by PDVSA and monthly information to be

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

		presented to BCV in respect of foreign currency flows generated by its activities, asset and liability positions in foreign currency, and payments made by PDVSA abroad.

		Exchange Agreement No. 2 of February 6, 2004 was amended on March 2, 2005 to establish exchange rates of Bs. 2,144.60/US$1 (Bs.F. 2.14) (purchase) and Bs. 2,150/US$1 (Bs.F. 2.15) (sale).

(5)

Determination of Fair Values

		Certain of the Company’s accounting policies and disclosures require the determination of fair values for financial and non-financial assets and liabilities. Fair values have been estimated for purposes of valuation and disclosure using available market information and appropriate valuation methods. Additional information on fair value estimates is disclosed in the specific notes to the assets and liabilities.

		The fair value of property, plant and equipment recognized as a result of a business acquisition is essentially based on market values and other suitable valuation methods. The market value of assets is the estimated amount at which these assets could be exchanged on the valuation date between a willing buyer and seller in an arm’s length transaction wherein the parties had each acted knowledgeably, prudently and without compulsion.

		The fair value of recoverable tax credits and other liabilities has been determined by discounting net cash flows expected to be generated by the asset, using interest rates applicable in the monetary market.

		The carrying value of cash and cash equivalents, notes and accounts receivable, prepaid expenses and other assets, and accounts payable to suppliers approximates their estimated fair value due to the short-term maturities of these instruments.

		The net carrying value of the account payable to PDVSA approximates the estimated fair value since its payment depends on the volume and nature of transactions conducted by the Company with the Parent Company and its subsidiaries.

(6)

Financial Risk Management

		Local and international conditions, i.e., recession periods, inflation, interest rates, devaluation, and hydrocarbon price volatility may have a significant effect on the Company’s financial position. The Company is exposed to a variety of financial risks: market risk (including exchange rate fluctuation risk, interest rate risk and price risk), liquidity risk and capital risk. Financial instruments exposed to concentration of credit risk consist primarily of cash and trade accounts receivable.

		At December 31, 2008 and 2007, the Company’s cash is placed with a local and foreign financial institution. In addition, there is some concentration of credit risk in trade accounts receivable since all crude oil and gas produced is sold to PDVSA Petróleo.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

		*Market risk*

		The Company’s general risk management focuses on the uncertainty surrounding financial markets and seeks to minimize the potential adverse effects on the Company’s performance. At December 31, 2008 and 2007, the Company is exposed to the following market risks:

		*Exchange rate fluctuation risk*

		The Company operates in Venezuela and is exposed to foreign exchange risk from variations in the exchange rate of the Venezuelan bolivar relative to the U.S. dollar. Foreign exchange risk is mainly derived from future commercial operations and assets and liabilities shown in bolivars.

		*Price risk*

		The Company is exposed to risks stemming from changes in the sale price of hydrocarbons, which depend on external market factors. At December 31, 2008 and 2007, hydrocarbon sales prices are calculated based on predetermined formulas that consider the price of hydrocarbons in different international markets. Price fluctuations may have a significant impact on the Company’s income. At December 31, 2008 and 2007, the Company has no mechanisms in place to protect against exposure to hydrocarbon sales price fluctuations.

		*Interest rate fluctuation risk*

		The Company has accounts receivable from PDVSA which earn interest and are, therefore, exposed to interest rate fluctuation.

		*Capital risk management*

		The Company is focused on safeguarding its ability to continue as a going concern in order to provide returns for the shareholders and maintain an optimal capital structure to reduce capital costs. In order to maintain or adjust the capital structure, the Company may adjust the amount of dividends paid to shareholders, return capital to shareholders or issue new shares.

(7)

Taxes

Below is a summary of taxes affecting the Company’s operations, stated in thousands:


	Years ended December 31,
	2008		2007		2008		2007
	U.S. Dollars				Bolivars
Income tax		16,814		64,501		36,150		138,677
Royalties (See Note 19)		149,605		101,929		321,651		219,146

Total		166,419		166,430		357,801		357,824

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

	*(a)*		*Income tax*

			Net income tax expense is summarized below, stated in thousands:


	Years ended December 31,
	2008			2007			2008			2007
	U.S. Dollars						Bolivars
Estimated income tax expense		(69,374	)		(85,849	)		(149,154	)		(184,575	)
Deferred income tax		52,560			21,348			113,004			45,898

Total		(16,814	)		(64,501	)		(36,150	)		(138,677	)

Reconciliation between the nominal and the effective income tax rates for each year is shown below:


	Years ended December 31,
	2008									2007
				Thousands									Thousands
				U.S.									U.S.
	%			Dollars			Bolivar’s			%			Dollars			Bolivars
Income tax:
Net income					121,217			260,617						91,441			196,597
Income tax					16,814			36,150						64,501			138,677

Net income before income tax					138,031			296,767						155,942			335,274

Oil-sector nominal income tax rate		50			69,016			148,383			50			77,971			167,638
Tax inflation adjustment and effect from translation into U.S. dollars		(28	)		(38,697	)		(83,199	)		0			19			40
Deferred income tax		(38	)		(52,560	)		(113,004	)		(14	)		(21,348	)		(45,898	)
Non-deductible provisions and other		28			39,055			83,970			5			7,859			16,897

Effective rate		12			16,814			36,150			41			64,501			138,677

			The partial reform of the Income Tax Law, published in Official Gazette No. 38,529 on September 25, 2006, repealed investment tax credits applicable to companies engaged in hydrocarbon production and related activities, and prohibits application of tax credits available for activities other than those related to hydrocarbons.

			Prevailing and former Venezuelan Income Tax Law allows tax losses to be carried forward for three years to offset taxable income, except losses arising from the annual inflation adjustment, which may be carried forward for only one year.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

			Venezuelan Income Tax Law requires an initial inflation adjustment to compute taxable income. The Law provides that the initially adjusted values of property, plant and equipment should be depreciated or amortized for tax purposes over the remaining useful lives of such assets. The Law also requires that an annual inflation adjustment be included in income tax reconciliation as a taxable or deductible item.

			According to the Income Tax Law, taxpayers subject to this tax that conduct import, export and loan transactions with related parties abroad are required to calculate income, costs and deductions applying the methodology set out in the Law. The Company conducts no transactions with related parties abroad.

			Official Gazette No. 38,529 of the Bolivarian Republic of Venezuela, published on September 25, 2006, modifies Article No. 11 of the Law regarding the rate applicable to companies engaged in hydrocarbon production and related activities, establishing a 50% general rate. However, only companies that conduct integrated or non-integrated activities related to exploration and production of non-associated gas, and processing, transportation, distribution, storage, marketing and export of gas and its components, or those exclusively engaged in refining of hydrocarbons or enhancement of heavy and extra-heavy crude oil are subject to a 34% tax rate. Therefore, application of the 34% rate for companies incorporated under the joint venture agreements executed under the superseded Law Reserving Hydrocarbon Trade and Industry to the State is eliminated.

			The components of deferred income tax expense at December 31, 2007 and 2008 shown in the results of each year are as follows (in thousands):


			Benefit
	2007		Recognized		2008
	Assets		in results		Assets
*In U.S. dollars-*
Property, plant and equipment		33,453		32,551		66,004
Inventories		2,303		2,881		5,184
Accruals and other payables		9,007		17,128		26,135

		44,763		52,560		97,323

*In bolivars-*
Property, plant and equipment		71,924		69,985		141,909
Inventories		4,951		6,194		11,145
Accruals and other payables		19,366		36,825		56,190

		96,241		113,004		209,244

	*(b)*		*Royalties*

			Royalties are paid based on crude oil produced and associated natural gas processed in Venezuela. Volumes of hydrocarbons produced in traditional areas are taxed with a 30% rate.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

			The partial reform of the Hydrocarbon Law was approved in May 2006, whereby operators should pay 33.33% of the wellhead value of each barrel to the Venezuelan government by means of royalties and additional taxes.

			On November 14, 2006, a new calculation of royalties was established for companies that conduct primary oil activities in the country requiring that contents of sulphur and API gravity of liquid hydrocarbons extracted be measured on a monthly basis and be reported together with taxed production. This information will be part of the royalty payment price and will be used for calculation of any special advantage. This information will result in adjustments for gravity and sulphur, which will be published by Ministry for Energy and Oil (MPPEP).

			The Company pays MPPEP a 30% royalty in kind for crude oil produced and associated natural gas transferred to PDVSA Petróleo, S.A. Royalty expenses for 2008 and 2007 amounted to US$149,605 thousands and US$101,929 thousands (Bs 321,651 thousands and Bs 219,146 thousands), respectively, included in the income statement under Royalties.

			The Company is subject to special advantage taxes, which are determined based on: a) an interest as additional royalty of 3.33% on volumes of hydrocarbons extracted in the delimited areas and delivered to Petróleos de Venezuela, S.A. and b) an amount equivalent to the difference, if any, between (i) 50% of the value of the hydrocarbons extracted in the delimited areas and delivered to Petróleos de Venezuela, S.A. in each calendar year and (ii) the sum of payments made by the mixed companies to the Bolivarian Republic of Venezuela, for activities developed during the calendar year, for royalties on hydrocarbons and investments in endogenous development projects, equivalent to 1% of pre-tax income. Taxes for special advantages must be paid before April 20 of each year, pursuant to Exhibit F of the Agreement for Conversion into a Mixed Company. During 2008 and 2007, the Company incurred US$16,030 thousands and US$7,554 thousands (Bs 34,464 thousands and Bs 16,241 thousands), respectively, in this connection, included in the statements of comprehensive income under Royalties.

			Following a detail of the caused royalties is shown:


	Years ended December 31,
	2008		2007		2008		2007
	Dollars				Bolivars

Royalty on oil production		138,311		94,696		297,369		203,595
Royalty on gas production		11,294		7,233		24,282		15,551
Royalty for the municipalities		10,687		5,036		22,977		10,827
Other royalties		5,343		2,518		11,487		5,414
Surface tax		1,596		—		3,431		—
Windfall tax		56,377		—		121,211		—
Accrual for investments in social project		1,559		5,364		3,352		11,532

		225,167		114,847		484,109		246,919

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

	*(c)*		*Extraction tax*

			The Venezuelan Hydrocarbon Law Reform establishes a rate equivalent to 33.33% of the value of all liquid hydrocarbons extracted from any reservoir, calculated on the same basis as for royalties. The taxpayer may deduct from the extraction tax any sum payable as royalties, including the additional royalty paid as special advantage. This tax is effective since 2006. The Company incurred no tax in this connection for 2008 and 2007.

	*(d)*		*Value added tax (VAT)*

			A Partial Reform of the Value Added Tax Law was published in Official Gazette No. 38,632 on February 26, 2007 changing the applicable tax rate from 14% to 11% as from March 1 until June 30, 2007 and to 9% as from July 1, 2007.

			The VAT Law establishes an exemption on trading of certain hydrocarbon-derived fuels. Recoverable amounts bear no interest.

			Below is a summary of the movement of recoverable tax credits (in thousands):


	December 31,
	2008		2007		2008		2007
	U.S. dollars				Bolivars

Recoverable amounts at the beginning of the year		—		—		—		—
Generate during the year		9,604		—		20,649		—

Recoverable amounts at end of the year		9,604		—		20,649		—

	*(e)*		*Law on Special Contributions over Extraordinary Prices of the International Hydrocarbons Market*

			In April 2008, the Venezuelan government, by means of a decree-law, established a special contribution over extraordinary prices of the international hydrocarbons market, amended in July 2008, which levies the sale of crude oil whenever the average price for the month in question of the Venezuelan oil production exceeds the price of US$70/barrel. The amount of said contribution equals 50% of the difference resulting of the average price per month and the aforementioned cap of US$70/barrel. In addition, this decree-law sets forth that whenever the average price per month exceeds the price of US$100/barrel, the total amount of said special contribution will be equivalent to 60% of the above defined difference.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

Bolivars —


	Wells and			Machinery
	Production			And		Construction
	Facilities			Equipment		in Progress			Total
Cost:
Balances at December 31, 2006		444,085			5,633		—			449,718
Additions		6,562			432		—			6,994
Strategic Inventories		12,885			—		—			12,885
Assets retirement obligations		(32	)		—		—			(32	)

Balances at December 31, 2007		463,500			6,065		—			469,565
Additions		—			1,969		82,627			84,596
Transfers		16,093			—		(16,093	)		—
Strategic inventories		9,200			—		—			9,200
Asset retirement obligations		23,362			—		—			23,362

Balances at December 31, 2008		512,155			8,034		66,534			586,723


Depreciation and amortization:
Balances at December 31, 2006		35,724			989		—			36,713
Depreciation and amortization		37,435			1,278		—			38,713
Assets retirement obligations		1,170			—		—			1,170

Balances at December 31, 2007		74,329			2,267		—			76,596
Depreciation and amortization		46,606			1,570		—			48,176
Assets retirement obligations		6,667			—		—			6,667

Balances at December 31, 2008		127,602			3,837		—			131,439

Total net cost at December 31, 2008		384,553			4,197		66,534			455,284

Total net cost at December 31, 2007		389,171			3,798		—			392,969

		As a result of the migration process of operating agreements to mixed companies, during 2008 and 2007, the Company made additions to production assets and construction in progress for approximately US$39,347 thousands and US$3,253 thousands (Bs 84,596 thousands and Bs 6,994 thousands), respectively.

		During 2008 and 2007, the Company assessed asset impairment, taking into account new market and business conditions, and determined that there was no evidence of impairment of production assets.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

		At December 31, 2008 and 2007, accruals and other payables include US$10,866 thousands and US$15 thousands (Bs 23,362 thousands and Bs 32 thousands), respectively, in respect of the accrual for asset retirement obligations (See Note 9).

		The balance of construction in progress mainly comprises investment projects for exploration and production activities related to drilling, maintenance, electrical systems, pipelines, well reconditioning and adaptation, expansion and infrastructure aimed at maintaining production capacity and adapting the infrastructure to production levels set out in the Corporation’s business plan. At December 31, 2008, the balance of construction in progress for investments related to the aforementioned activities amounts to approximately US$30,946 thousands (Bs 66,534 thousands).

(9)		Accrual for Asset Retirement Obligations

		The movement of the accrual for asset retirement obligations at December 31 is shown below (in thousands):


	U.S. dollars		Bolivars

Balance at December 31, 2007		5,964		12,823

Change on estimation		10,866		23,362
Financial cost		2,344		5,039

Balance at December 31, 2008		19,174		41,224

		During 2008, Company management reviewed, based on new information, estimates on assumptions used for calculating the provision for abandonment costs.

		The variation of the estimation in the provision for well abandonment cost of US$10,866 thousands (Bs 23,362 thousands) includes the balance of Property, plant and equipment (See Note 8). The Petrodelta, S.A. business plan as of December 31, 2008, contemplates the realization of hydrocarbons drilling and production activities until the year 2025; therefore, the accrual for asset retirement obligations was calculated based on the disbursements for this concept during this period.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

(13)		Cash and its equivalents

		Cash and cash equivalent comprises the following (in thousands):


	December 31,
	2008		2007		2008		2007
	U.S. Dollars				Bolivars
Cash on hand		2		—		4		—
Cash at banks		7,361		6,977		15,826		15,000

		7,363		6,977		15,830		15,000

(14)		Equity

		Capital stock

		At December 31, 2008, the Company’s nominal capital stock is represented by 1,500,000 common shares, fully authorized and paid in, with a par value of US$5 each (Bs 10 each).

		The Company’s capital stock is divided into two types of shares: Class “A” and Class “B” shares. Only the Venezuelan government or Venezuelan state-owned companies can own Class “A” shares. In October 2007, when the Company was incorporated, shareholders made an initial capital contribution of approximately Bs 1,000 thousands (US$465,000). Capital stock has been fully subscribed and paid in as follows:


									Share
	Type of		Number of						of
Shareholders	shares		shares		US$		Bs.		equity

Corporación Venezolana del Petróleo, S.A. (CVP)		A		900,000		4,186,200		9,000,330		60	%
HNR Finance, B.V. (HNR Finance)		B		600,000		2,790,800		6,000,220		40	%

				1,500,000		6,977,000		15,000,550		100	%

		Contributions for future capital increases

		In November 2007, the shareholders made contributions for future capital increases of approximately US$6,512 thousands, equivalent to approximately Bs 14,000 thousands.

		In August 2008, this contribution was capitalized in compliance with Article No. 1, Paragraph 1.4 of the Agreement for Conversion into a Mixed Company.

		Legal reserve

		Venezuelan companies are required to set aside a legal reserve. According to Venezuelan Law, the legal reserve is not available for dividend distribution.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

		At December 31, 2008 and 2007, the Company has set aside a legal reserve of approximately US$651 thousands, equivalent to Bs 1,400 thousands (US$47 thousands, equivalent to Bs 100 thousands, in 2007), equivalent to 10% of capital stock.

		Share premium

		The share premium is in respect of contributions of fixed assets and inventories made by shareholders in conformity with the Agreement for Conversion into a Mixed Company, whose value exceeds the par value of common shares issued. At December 31, 2008 and 2007, the share premium amounts to approximately US$212,451 thousands, equivalent to approximately Bs 456,770 thousands, included in equity.

		Class “A” share premiums are in respect of fixed assets contributed by CVP. The value of this share premium amounts to approximately US$191,206 thousands, equivalent to approximately Bs 411,093 thousands, pursuant to Exhibit H of the Agreement for Conversion into a Mixed Company.

		Class “B” share premiums are in respect of fixed assets and inventories contributed by HNR Finance. The value of this share premium amounts to approximately US$21,245 thousands, equivalent to approximately Bs 45,677 thousands, pursuant to Exhibit G of the Agreement for Conversion into a Mixed Company.

		In conformity with the Company’s bylaws, in case of Company liquidation, all assets will be transferred only to the Class “A” shareholder.

		Dividends

		On May 2008, the shareholders resolved to pay dividends of US$181,325 thousands, equivalent to Bs 389,846 thousands, out of unappropriated retained earnings for December 2007.

		In August, the shareholders resolved to pay dividends in advance based on retained earnings for June 2008 of US$51,876 thousands, equivalent to Bs 111,533 thousands.


(15)		Accounts Payable

		Accounts payable comprise the following (in thousands):


	December 31,
	2008		2007		2008		2007
	U.S. dollars				Bolivars

Trade		8,536		—		18,353		—
Related parties (See Note 19)		80,568		84,548		173,221		181,779

Total		89,104		84,548		191,574		181,779

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

Foreign currency and liquidity risk exposure in respect of accounts payable to suppliers is shown in Note 17.

(16)		Accruals and Other Payables

		Accruals and other payables at December 31 comprise the following:


	December 31,
	2008		2007		2008		2007
	U.S. dollars				Bolivars
Royalties		44,017		24,074		94,637		51,759
Accrual for asset retirement obligations (See Note 9)		19,174		5,964		41,224		12,823
Endogenous and social development		4,347		9,905		9,346		21,296
LOCTISEP		3,056		1,832		6,570		3,939
Other		119,710		14,095		257,377		30,304

		190,304		55,870		409,154		120,121

Less: Non current portion of accruals and other payables		19,174		5,964		41,224		12,823

Short-term portion		171,130		49,906		367,930		107,298

		At December 31, 2008 and 2007, accruals and other payables include US$19,174 thousands and US$5,964 thousands (Bs 41,224 thousands and Bs 12,823 thousands) in respect of the accruals for retirement obligations for exploration and production assets. Asset retirement costs and obligations related to the main structures used in drilling activities were not estimated because these assets have an indefinite useful life as a result of maintenance and major repairs and no information is available to reasonably determine their retirement date.

		Additionally, under other, it is included the accruals in respect of drilling services and infrastructure totaling US$50,845 thousands (Bs 109,317 thousands), approximately, and a special contribution over the extraordinary prices of the international hydrocarbons market totaling US$56,377 thousands (Bs 121,211 thousands), as of December 2008.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

Below are the movements of accruals and other payables during 2008 (in thousands):


	Balance at							Balance at
	December							December		Current		Long-term
	31, 2007		Increase		Decrease			31, 2008		portion		portion
U.S. dollars

Royalties		24,074		19,943		—			44,017		44,017		—
Accrual for asset retirement obligations (See Note 9)		5,964		13,210		—			19,174		—		19,174
Endogenous and social development		9,905		—		(5,558	)		4,347		4,347		—
LOCTISEP		1,832		1,224		—			3,056		3,056		—
Other		14,095		105,615		—			119,710		119,710		—

Total accruals and other payables		55,870		139,992		(5,558	)		190,304		171,130		19,174


Bolivars

Royalties		51,759		42,877		—			94,637		94,637		—
Accrual for asset retirement obligations (See Note 9)		12,823		28,402		—			41,224		—		41,224
Endogenous and social development		21,296		—		(11,950	)		9.346		9.346		—
LOCTISEP		3,939		2,632		—			6,570		6,570		—
Other		30,304		227,072		—			257,377		257,377		—

Total accruals and other payables		120,121		300,983		(11,950	)		409,154		367,930		41,224

(17)		Financial Instruments

		Credit Risk

		Exposure to Credit Risk

		The book value of financial assets represents the highest level of credit risk exposure. A breakdown is shown below (in thousands):


	December 31,
	2008		2007		2008		2007
	U.S. dollars				Bolivars
Accounts receivable related parties (Note 12)		257,292		444,737		553,178		956,187
Recoverable tax credits (See Note 7)		9,604		—		20,649		—
Accounts receivable other (See Note 12)		890		6,292		1,913		13,527
Cash and cash equivalents		7,363		6,977		15,830		15,000

		275,149		458,006		591,570		984,714

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

The year-end exchange rate, the average exchange rate for the year and the interannual increases in the exchange rate and the Consumer Price Index (CPI), as published by BCV, were as follows:


	December 31,
	2008		2007
Exchange rate at year end (Bs./US$1)		2.15		2.15

Average exchange rate for the year (Bs./US$1)		2.15		2.15

Interannual increase in the CPI (%)		30.90		22.46

		Fair Value of Financial Instruments

		The following estimated amounts do not necessarily reflect the amounts at which the instruments could be exchanged in the current market. The use of different market assumptions and valuation methods can significantly affect the estimated fair values. The bases for determining the fair value are disclosed in Note 5 (in thousands):


	December 31,								December 31,
	2008				2007				2008				2007
	Book value		Fair value		Book value		Fair value		Book value		Fair value		Book value		Fair value
	U.S. dollars								Bolivars
Assets:
Accounts receivable		257,292		257,292		444,737		444,737		553,178		553,178		956,187		956,187
Recoverable tax credits		9,604		9,604		—		—		20,649		20,649		—		—
Accounts receivable		890		890		6,292		6,292		1,913		1,913		13,527		13,527
Cash and cash equivalents		7,363		7,363		6,977		6,977		15,830		15,830		15,000		15,000

Liabilities:
Accounts payable to suppliers		8,536		8,536		—		—		18,353		18,353		—		—
Other liabilities (included in accruals and other payables)		171,130		171,130		49,906		49,906		367,930		367,930		107,298		107,298
Accounts payable to PDVSA		80,568		80,568		84,548		84,548		173,221		173,221		181,778		181,778

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

(18)

Commitments, Contingencies and Claims

		At December 31, 2008 and 2007, the Company has not set aside a provision for litigations and other claims. Should the outcome of existing lawsuits and claims be unfavorable to the Company, it could have a material adverse effect on its results of operations. Although it is not possible to predict the outcome, Company management, based in part on the opinion of its legal advisors, does not believe it is likely that losses related to the aforementioned legal procedures will exceed recognized estimated amounts or generate significant amounts that could affect the Company’s financial position or results of operations.

		*Environmental Protection*

		The subsidiaries of CVP are subject to different environmental laws and regulations which may require significant expenditures to modify facilities and prevent or remedy the environmental effects from waste disposal and spills of pollutants.

		Petrodelta, S.A. and its parent company CVP are taking steps to prevent environmental risks, protect employee health and preserve the integrity of their facilities.

		Conditions that require additional expenditures may exist at various sites including, but not limited to, CVP’s operating complexes and crude oil storage terminals. Company management believes that these matters, in the normal course of operations, will not significantly affect the Company’s financial position or liquidity in the results of its operations.

		*Agreements with the Organization of Petroleum Exporting Countries (OPEC)*

		The Bolivarian Republic of Venezuela is a member of OPEC, an organization mainly dedicated to establishing agreements to maintain stable crude oil prices by setting production quotas. To date, the reduction in crude oil production resulting from changes in the production quotas set by OPEC and price fluctuations has not significantly affected the Company’s results of operations, cash flows or financial results.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

(19)		Related Party Transactions

		Petrodelta, S.A. considers its shareholders and related subsidiaries and affiliates, Company directors and executives, as well as other governmental institutions, as related parties.

		Transactions with PDVSA and its subsidiaries are recorded in the PDVSA account. These balances are interest-free and have no fixed maturity. CVP provides the funding needed for Petrodelta, S.A. to conduct its activities and cover its obligations.

		A summary of transactions and balances with related parties is shown below (in thousands):


	December 31,
	2008		2007		2008		2007
	U.S. dollars				Bolivars
Activities for the year:
Crude oil and natural gas sales		474,619		335,717		1,020,431		721,792

Operating expenses		21,298		23,752		45,791		51,067

General, administrative and selling expenses		3,506		17,956		7,538		38,605

Royalties (See Note 7)		149,605		101,929		321,651		219,146

Reimbursement of expenses		272,852		—		586,632		—

Balances at the end of the year:
Accounts receivable (See Note 12)		236,533		444,737		508,546		956,187

Prepaid dividends-B Partners (See Note 12)		20,759		—		44,632		—

Accounts payable to suppliers (See Note 15)		2,327		—		5,003		—

Accounts payable to PDVSA (See Note 15)		78,241		84,548		168,218		181,779

		As of April 2006, due to the migration of operating agreements to mixed companies, PDVSA Petróleo signed purchase sale agreements with these companies, which set out that mixed companies will notify PDVSA Petróleo of the estimated volume of hydrocarbons expected to be delivered the following month. PDVSA Petróleo must pay the mixed companies for delivered volumes, net of volumes for royalties in kind and paid to the Venezuelan government.

		In conformity with the terms and conditions of the agreements, CVP mixed companies agree to sell and deliver to PDVSA Petróleo, and the latter agrees to purchase and receive from these mixed companies, crude oil and natural gas produced in the delimited areas that are not used for primary activities or for payment of royalties in kind to the Venezuelan government.

		During the years ended December 31, 2008 and 2007, the Company sold crude oil and natural gas to PDVSA Petróleo for US$474,619 thousands and US$335,717 thousands (Bs 1,020,431 thousands and Bs 721,790 thousands), respectively, included in the income statement under Income. At December 31, 2008 and 2007, the income statement includes US$236,533

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

		thousands and US$444,737 thousands (Bs 508,546 thousands and Bs 956,187 thousands) of accounts receivable in this connection.

		During 2008 and 2007, PDVSA Petróleo charged Petrodelta, S.A. US$370,000 thousands and US$85,000 thousands (Bs 798,000 thousands and Bs 183,000 thousands), respectively, for labor and other costs, included in general, administrative and selling expenses.

		Certain Company directors hold key positions in other related entities; some of their attributions include influencing the operational and financial policies of these entities.

		At December 31, 2008 and 2007, transactions with related parties do not necessarily reflect the results that would have been obtained had these transactions been held with third parties.

		At a Board of Directors’ Meeting in December 2008, it was resolved to offset receivables and payables with PDVSA. In this regard, it was established that 75% of accounts receivable and 100% of accounts payable and billed to PDVSA would be recorded with no interest charges. Subsequently, in December 2008, CVP agreed to offset the remaining unbilled accounts payable. As a result, accounts payable in respect of reimbursement of capital costs and operating expenses were offset against accounts receivable in respect of estimated hydrocarbons extracted and transferred to PDVSA in accordance with the purchase sale agreement.

(20)

Laws, Resolutions and Legal Contributions

	a)		*Laws Decreed within the Framework of the Enabling Law*

			On July 31, 2008, 26 laws were decreed within the framework of the Enabling Law concerning economic, social, legal, and military matters. The following are among the most important laws approved in the social, administrative and financial areas:

	•		Decree No. 6,071 for the Agro-Food Security and Sovereignty Law published in Official Gazette No. 5,889.

	•		Decree No. 6,128 for the Law for the Creation of the Social Fund Aimed at Gathering and Disposing of Excess Resources of Government Entities published in Official Gazette No. 5,890.

	•		Decree No. 6,215 for the Law for Fostering and Developing Small and Medium-sized Industries and Units of Social Property published in Official Gazette No. 5,890.

	•		Decree No. 6,217 for the Public Administration Law published in Official Gazette No. 5,890.

	•		Decree No. 6,233 for the Reform of the Public Sector Financial Administration Law published in Official Gazette No. 5,891.

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

•

Decree No. 6,265 for the Law for the Simplification of Administrative Formalities published in Official Gazette No. 5,891.

			Company management and its legal advisors are assessing the possible impact of these laws on PDVSA.

	b)		*Law for Special Contributions on Extraordinary International Hydrocarbon Market Prices*

			On April 15, 2008, the Law for Special Contributions on Extraordinary International Hydrocarbon Market Prices was published in Official Gazette No. 38,910. Subsequently, Resolutions No. 151 and No. 195 of MPPEP were published in Official Gazette No. 38,939 of May 27, 2008 and Official Gazette No. 38,970 of July 10, 2008. This Law and its resolutions require entities that export or transport liquid hydrocarbons and hydrocarbon derivatives abroad to pay a special monthly contribution. The contribution will be equivalent to: a) 50% of the difference between the average monthly price of the Venezuelan crude oil basket and the threshold price of US$70 per barrel and b) 60% of the difference between the average monthly price of the Venezuelan crude oil basket and the threshold price over US$100 per barrel. This contribution shall be paid on every barrel of oil exported or transported abroad and shall be collected and paid monthly by MPPEP to FONDEN for execution of infrastructure development projects, production and social development projects aimed at strengthening Communal Power. This Law became effective on April 15, 2008.

	c)		*Law on Narcotic and Psychotropic Substances*

			The Law on Narcotic and Psychotropic Substances was published in Official Gazette No. 38,287 on December 16, 2005. This Law repeals the previous Law of September 30, 1993 and requires all companies, public or private, with 50 or more employees to earmark 1% of their annual net income for social programs for the prevention of illegal drug consumption and traffic, one-half of which is to be set aside for child welfare protection programs. During the years ended December 31, 2008 and 2007, the Company recorded an expense of approximately US$1 million and US$1 million (Bs 3 million and Bs 2 million), respectively, in this connection, included in the income statement for each year under General and administrative expenses, net.

	d)		*Financial Transaction Tax Law*

			On October 5, 2007, the Venezuelan government enacted by Decree the Tax on Financial Transactions for Incorporated and Unincorporated Entities. This tax is levied upon all financial transactions performed by incorporated and unincorporated entities. The tax rate was set at 1.5% as from November 1, 2007 until December 31, 2008.

	e)		*Enabling Law*

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

			On February 1, 2007, the National Assembly approved the Enabling Law granting the Venezuelan president special powers for 18 months to pass decrees governing different areas of national interest, including transformation of state institutions, popular, economic and social participation, as well as financial, tax and energy-related matters.

	f)		*Currency Redenomination Law*

			On March 6, 2007, the Currency Redenomination Law was published in Official Gazette No. 38,638. This law established that, as from January 1, 2008, the unit of the Venezuelan monetary system would be redenominated at a conversion rate of one thousand current bolivars to one new bolivar. Therefore, all amounts expressed in local currency before January 1, 2008 were converted to the new unit on that date by dividing them by one thousand and rounding them to the nearest cent.

			On June 21, 2007, the Board of Directors of the Central Bank of Venezuela (BCV) issued Resolution No. 07-06-02 related to the Rules Governing Monetary Redenomination and Rounding. Article No. 6 of this Resolution establishes that financial statements for periods ending before January 1, 2008 that are approved after that date shall be prepared and presented in current bolivars in accordance with generally accepted accounting principles. For purposes of comparison with subsequent periods, the balances of such financial statements shall be converted as prescribed by Article No. 1 of the Currency Redenomination Law.

			PDVSA has applied technological, administrative and financial mechanisms to guarantee compliance with the aforementioned Law. Costs and processes involved in adopting this new Law did not significantly affect the financial statements at December 31, 2008.

(21)		Supplementary Information on Oil and Gas Exploration and Production Activities (unaudited)

		The following tables provide supplementary information on oil and gas exploration, development and production activities. All exploration and production activities are conducted mainly by CVP and Mixed Companies in Venezuela.

		Table I — Crude Oil and Natural Gas Reserves

		All crude oil and natural gas reserves located in Venezuela are owned by the Bolivarian Republic of Venezuela. Crude oil and natural gas reserves are estimated by PDVSA and reviewed by the People’s Power Ministry for Energy and Oil using reserve criteria that are consistent with those prescribed by the American Petroleum Institute (API) of the United States of America.

		Proved reserves are the estimated quantities of crude oil and gas which, with reasonable certainty, are recoverable in future years from known deposits under existing economic and

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

		perating conditions. Due to the inherent uncertainties and limited nature of reservoir data, reserve estimates are subject to changes over time, as additional information becomes available. Proved reserves do not include additional volumes which may result from the extension of currently explored areas or from the application of secondary recovery processes not yet tested and determined to be economically feasible.

		Proved developed oil and gas reserves are the quantities that can be recovered from existing wells with existing equipment and methods. Proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage or from existing wells.

		A summary of annual changes in proved crude oil and natural gas reserves is shown below:

		*(a) Conventional Crude Oil (in thousands of barrels)*


	Years ended December 31,
	2008			2007
Proved developed and undeveloped reserves of conventional crude oil at January 1		220,163			225,537
Revisions		—			—
Expansions and discoveries		—			—
Production		(5,505	)		(5,374	)

Proved developed and undeveloped reserves of conventional crude oil at December 31		214,658			220,163

Proved developed reserves of conventional crude oil at December 31 (included on the previous amount)		47,298			52,803

		At December 31, 2008 and 2007, certified reserves assigned to the Company amounted to 214,658 thousands and 220,163 thousands barrels, respectively. Production for the year ended December 31, 2008 was 5,505 thousands barrels.

		*(b) Natural Gas Reserves (in millions of cubic feet*)


	Years ended December 31,
	2008			2007
Proved developed and undeveloped reserves of natural gas at January 1		283,981			297,437
Revisions		—			—
Expansions and discoveries		—			—
Production		(10,700	)		(13,456	)

Proved developed and undeveloped reserves of natural gas at December 31		273,281			283,981

Proved developed reserves of natural gas at December 31 (included on the previous amount)		32,630			43,330

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

		Natural gas production is shown on the basis of actual volumes before the extraction of liquefiable hydrocarbons.

		Table II — Costs Incurred in Exploration and Development Activities

		Exploration costs include costs incurred from geological and geophysical activities, and drilling and equipping exploratory wells. The Company did not conduct exploration activities in 2008. Development costs include those for drilling and equipping development wells, enhanced recovery projects and facilities to extract, treat and store crude oil and natural gas. Annual costs, summarized below, include amounts both expensed and capitalized for the Company’s conventional crude oil reserves (In thousands):


	Conventional Crude
	U.S. dollars				Bolivars
	2008		2007		2008		2007
Development costs		7,485		3,052		16,093		6,592

Total costs incurred from development activities		7,485		3,052		16,093		6,592

		Table III — Costs Recorded as Assets in Oil and Gas Production Activities

		Costs recorded as assets for oil and gas exploration and production activities, as well as the related accumulated depreciation and amortization at December 31 for PDVSA’s conventional and extra-heavy crude oil reserves are summarized below (In thousands):


	Conventional Crude
	U.S. dollars						Bolivars
	2008			2007			2008			2007
Assets used in production		238,211			215,581			512,156			463,500
Equipment and facilities		3,737			2,821			8,034			6,065

		241,948			218,402			520,190			469,565
Accumulated Depletion, depreciation and amortization		(61,134	)		(35,626	)		(131,439	)		(76,596	)
Construction in progress		30,946			—			66,532			—

Total net costs capitalized as assets		211,760			182,776			455,283			392,969

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements

December 31, 2008 and 2007

Table IV — Results of Operations for Oil and Gas Production Activities for Each Year (In thousands):


	Conventional Crude
	Years ended December 31
	U.S. Dollar						Bolivars
	2008			2007			2008			2007
Net production income
Sales		474,619			335,717			1,020,431			721,790
Production costs		(84,314	)		(46,215	)		(181,275	)		(99,362	)
Royalties		(225,167	)		(114,847	)		(484,109	)		(246,919	)
Depletion, depreciation and amortization		(24,778	)		(17,956	)		(53,273	)		(38,605	)

Results of operation before income Tax		140,360			156,699			301,774			336,904
Income tax		(70,180	)		(78,350	)		(150,887	)		(168,452	)

Results production operation		70,180			78,349			150,887			168,452

		Income from oil production is calculated at international market price as if all production were sold.

		Production costs are lifting costs incurred to operate and maintain productive wells and related facilities and equipment, including operating labor costs, materials, supplies, fuel consumed in operations and operating costs of natural liquid gas plants.

		Depreciation and amortization expenses relate to assets used in exploration and production activities. Income tax expense is computed using the statutory rate for the year. For these purposes, the results of production operations do not include finance costs and corporate overhead nor their associated tax effects.

		A summary of average per unit sale prices and production costs is shown below:


	Years ended December 31
	2008		2007		2008		2007
	U.S. dollar				Bolivars
Average sale price
Crude oil per barrel		84.52		58.61		181.72		126.01

Natural gas per barrel		1.54		1.20		3.31		2.58

Average production cost per BOE		11.57		5.59		24.88		12.02


		Page
Part I

Item 1.	Business	1
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	18
Item 2.	Properties	18
Item 3.	Legal Proceedings	18
Item 4.	Submission of Matters to a Vote of Securities Holders	20

Part II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
Item 6.	Selected Financial Data	23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 8.	Financial Statements and Supplementary Data	36
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	36
Item 9A.	Controls and Procedures	36
Item 9B.	Other Information	37

Part III

Item 10.	Directors, Executive Officers and Corporate Governance	38
Item 11.	Executive Compensation	38
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	38
Item 13.	Certain Relationships and Related Transactions, and Director Independence	38
Item 14.	Principal Accountant Fees and Services	38

Part IV

Item 15.	Exhibits and Financial Statement Schedules	39

Financial Statements		S-2

Signatures		S-39
EX-21.1
EX-23.1
EX-23.2
EX-23.3
EX-31.1
EX-31.2
EX-32.1
EX-32.2


Item 10.		Directors, Executive Officers and Corporate Governance


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


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


	HARVEST NATURAL RESOURCES, INC. (Registrant)
Date: March 13, 2009	By:	/s/ James A. Edmiston
		James A. Edmiston
		Chief Executive Officer


Signature		Title

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

/s/ Stephen C. Haynes Stephen C. Haynes		Vice President — Finance, Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer)

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

Stephen D. Chesebro’

/s/ Igor Effimoff		Director

Igor Effimoff

/s/ H. H. Hardee		Director

H. H. Hardee

/s/ R. E. Irelan		Director

R. E. Irelan

/s/ Patrick M. Murray		Director

Patrick M. Murray

/s/ J. Michael Stinson		Director

J. Michael Stinson


			Additions
	Balance at					Charged		Deductions		Balance
	Beginning		Charged to			to Other		From		at End of
	of Year		Income			Accounts		Reserves		Year
At December 31, 2008
Amounts deducted from applicable assets Accounts receivable	$	2,757	$	—		$	—	$	—	$	2,757
Deferred tax valuation allowance		1,782		6,059			—		—		7,841
Investment at cost		1,350		—			—		—		1,350
At December 31, 2007
Amounts deducted from applicable assets Accounts receivable	$	2,757	$	—		$	—	$	—	$	2,757
Deferred tax valuation allowance		33,704		(31,922	)		—		—		1,782
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		28,258		5,446			—		—		33,704
Investment at cost		1,350		—			—		—		1,350


		Pages

INDEPENDENT AUDITOR’S REPORT		1 - 2

FINANCIAL STATEMENTS AS OF DECEMBER 31 2008 AND 2007

Statements of financial position		3
Statements of comprehensive income		4
Statements of changes in equity (in thousands of US dollars)		5
Statements of changes in equity (in thousands of US bolivars)		6
Cash flow statements		7

Notes to the financial statement

Note 1	Reporting Entity	8
Note 2	Basis of Preparation	10
Note 3	Summary of Significant Accounting Policies	12
Note 4	Exchange Agreement with the Central Bank of Venezuela (BCV)	22
Note 5	Determination of Fair Values	23
Note 6	Financial Risk Management	23
Note 7	Taxes	24
Note 8	Property, Plant and Equipment, Net	29
Note 9	Accrual for Asset Retirement Obligations	31
Note 10	Prepaid Expenses and Other Assets	32
Note 11	Inventories	32
Note 12	Accounts Receivable	32
Note 13	Cash and cash equivalents	33
Note 14	Equity	33
Note 15	Accounts Payable	34
Note 16	Accruals and Other Payables	35
Note 17	Financial Instruments	36
Note 18	Commitments, Contingencies and Claims	39
Note 19	Related Party Transactions	40
Note 20	Laws, Resolutions and Legal Contributions	41
Note 21	Supplementary Information on Oil and Gas Exploration and
	Production Activities (unaudited)	43


	December 31^st,
				2008		2007		2008		2007
	Note			U.S. Dollars				Bolivars


Assets
Property, plant and equipment, net		8			211,760		182,776		455,284		392,969
Deferred income tax		7-	(a)		97,323		44,763		209,244		96,241

Total non-current assets					309,083		227,539		664,528		489,210

Prepaid taxes and expenses		10			21,477		873		46,176		1,873
Inventories		11			14,391		7,837		30,941		16,848
Accounts receivable		12			267,786		451,029		575,740		969,714
Cash and cash equivalents		13			7,363		6,977		15,830		15,000

Total current asset					311,017		466,716		668,687		1,003,435

Total assets					620,100		694,255		1,333,215		1,492,645


Equity
Equity, see statements of changes in equity		14			340,692		400,800		732,487		861,716


Liabilities
Provision for abandonment cost		9 & 16			19,174		5,964		41,224		12,824

Total non-current liabilities					19,174		5,964		41,224		12,824

Accounts payable		15			89,104		84,548		191,574		181,779
Accruals and other liabilities		16			171,130		49,906		367,930		107,298
Income tax payable		7			—		153,037		—		329,028

Total current liabilities					260,234		287,491		559,504		618,105

Total liabilities					279,408		293,455		600,728		630,929

Total equity and liabilities					620,100		694,255		1,333,215		1,492,645


										Retained Earnings
			Capital		Shareholder			Share		Legal
	Note		Stock		Contribution			Premium		Reserve		Distributable			Total

Balances at December 31, 2006				—		—			212,451		—		89,931			302,382

Net income				—		—			—		—		91,441			91,441

Initial capital contribution		14		465		—			—		—		—			465

Contribution for capital increases		14		—		6,512			—		—		—			6,512

Appropriation to legal reserve		14		—		—			—		47		(47	)		—


Balances at December 31, 2007				465		6,512			212,451		47		181,325			400,800

Net income				—		—			—		—		121,217			121,217

Shareholders contribution capitalization		14		6,512		(6,512	)		—		—		—			—

Appropriation to legal reserve		14		—		—			—		651		(651	)		—

Dividends		14		—		—			—		—		(181,325	)		(181,325	)


Balances at December 31, 2008				6,977		—			212,451		698		120,566			340,692

			Common shares are classified as equity. For the years ended December 31, 2008 and 2007, the Company has no preferred shares (See Note 14).

	*(m)*		*Share premium*

			The Company recognizes as share premium any excess in the value of contributions made by shareholders for Company incorporation over the par value at the incorporation date (See Note 14).

(8)		Property, Plant and Equipment, Net

		Property, plant and equipment, net at December 31 comprises the following (in thousands):

		U.S. dollars —

(11)		Inventories

		A summary of inventories is shown below (in thousands):

(12)		Accounts Receivable

		Accounts receivable comprise the following (in thousands):

		Liquidity risk

		Maturity of financial liabilities, including estimated interest payments and excluding the impact of offset agreements, is shown below (in thousands):

		Foreign Currency Risk

		Petrodelta, S.A. has the following monetary assets and liabilities denominated in currencies other than the U.S. dollar, which were converted into U.S. dollars at the exchange rate in effect at the balance sheet date (in thousands):


		Jurisdiction
Name		of Incorporation

Harvest-Vinccler Dutch Holding B.V.*		The Netherlands

HNR Energia B.V.		The Netherlands

	1.		I have reviewed this report on Form 10-K of Harvest Natural Resources, Inc.;

	2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

	3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

	4.		The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	a.		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b.		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

	c.		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	d.		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	a.		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b.		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



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



	/s/ Stephen C. Haynes
	Stephen C. Haynes
	Vice President — Finance, Chief Financial Officer and Treasurer