HARVEST NATURAL RESOURCES, INC. - FORM 10-K

HARVEST NATURAL RESOURCES, INC. - FORM 10-K - March 16, 2010

Attached files

Attached files

file	filename
EX-31.1 - EX-31.1 - HARVEST NATURAL RESOURCES, INC.	h70116exv31w1.htm
EX-32.1 - EX-32.1 - HARVEST NATURAL RESOURCES, INC.	h70116exv32w1.htm
EX-31.2 - EX-31.2 - HARVEST NATURAL RESOURCES, INC.	h70116exv31w2.htm
EX-23.3 - EX-23.3 - HARVEST NATURAL RESOURCES, INC.	h70116exv23w3.htm
EX-23.1 - EX-23.1 - HARVEST NATURAL RESOURCES, INC.	h70116exv23w1.htm
EX-99.1 - EX-99.1 - HARVEST NATURAL RESOURCES, INC.	h70116exv99w1.htm
EX-23.2 - EX-23.2 - HARVEST NATURAL RESOURCES, INC.	h70116exv23w2.htm
EX-32.2 - EX-32.2 - HARVEST NATURAL RESOURCES, INC.	h70116exv32w2.htm
EX-21.1 - EX-21.1 - HARVEST NATURAL RESOURCES, INC.	h70116exv21w1.htm
EX-99.2 - EX-99.2 - HARVEST NATURAL RESOURCES, INC.	h70116exv99w2.htm

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, 2009


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

Commission File No.: 1-10762

HARVEST NATURAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)


Delaware		77-0196707
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

1177 Enclave Parkway, Suite 300
Houston, Texas		77077
(Address of principal executive offices)		(Zip Code)

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

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


Title of each class		Name of each exchange on which registered

Common Stock, $.01 Par Value		NYSE

Securities registered pursuant to Section 12(g) of the Act: 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 whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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, or a smaller reporting company. See the definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large Accelerated Filer o	Accelerated Filer þ	Non-Accelerated Filer o	Smaller Reporting Company o
		(Do not check if a smaller reporting company)

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, 2009 was: $144,812,960.

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, 2010, shares outstanding: 33,260,554.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for the 2010 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission, not later than 120 days after the close of the registrant’s fiscal year, pursuant to Regulation 14A, are incorporated by reference into Items 10, 11, 12, 13 and 14 of Part III of this annual report.

HARVEST NATURAL RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS


			Page
Part I

	Item 1.	Business		1
	Item 1A.	Risk Factors		16
	Item 1B.	Unresolved Staff Comments		21
	Item 2.	Properties		21
	Item 3.	Legal Proceedings		22
	Item 4.	[Reserved]

Part II

	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		23
	Item 6.	Selected Financial Data		25
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		39
	Item 8.	Financial Statements and Supplementary Data		39
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		39
	Item 9A.	Controls and Procedures		40
	Item 9B.	Other Information		40

Part III

	Item 10.	Directors, Executive Officers and Corporate Governance		40
	Item 11.	Executive Compensation		41
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		41
	Item 13.	Certain Relationships and Related Transactions, and Director Independence		41
	Item 14.	Principal Accountant Fees and Services		41

Part IV

	Item 15.	Exhibits and Financial Statement Schedules		42

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
EX-99.1
EX-99.2

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”, “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 holding a noncontrolling interest 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 and seismic crews, overall economic conditions, political stability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in governmental policy, availability of sufficient financing including the Company’s ability to obtain the Islamic (sukuk) financing described in Item 1A — Risk Factors, changes in weather conditions, and ability to hire, retain and train management and personnel. See Item 1A — Risk Factors and Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 1. Business

Executive Summary

Harvest Natural Resources, Inc. is an international petroleum exploration and production company incorporated under Delaware law in 1989. 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 regional/technical offices in the United Kingdom and Singapore, and small field offices in Jakarta, Indonesia, Muscat, Sultanate of Oman (“Oman”) and Roosevelt, Utah to support field operations in those areas. We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”) 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. 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 project 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 two private third parties, the Antelope prospect in the Western United States through a Joint Exploration and Development Agreement (“JEDA”), and exploration acreage mainly onshore West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in Oman and offshore of the People’s Republic of China (“China”).

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.

On April 11, 2009, we signed an Exploration and Production Sharing Agreement (“EPSA”) with Oman for the Al Ghubar / Qarn Alam license (“Block 64 EPSA”).

On April 23, 2009, Petrodelta’s board of directors declared a 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 International Financial Reporting Standards (“IFRS”) for the six months ended June 30, 2008. HNR Finance received the cash related to this dividend in the form of an advance dividend in October 2008.

In June 2009, drilling operations commenced on a deep natural gas test well (the Bar F #1-20-3-2 [“Bar F”]). The Bar F was drilled as a tight hole and was permitted to 18,000 feet. Drilling was completed in the fourth quarter of 2009 at a depth of 17,566 feet and production casing has been run. Production testing of the well commenced in November 2009 and continues in the first quarter of 2010. The testing program is expected to be completed by the end of the first quarter of 2010.

In December 2009, drilling operations commenced in an eight well appraisal and development drilling program to produce oil and natural gas from the Green River formation on the southern portion of our Antelope land position. As of March 1, 2010, all eight wells have been drilled. Seven wells are currently on production. One additional well is waiting on completion operations and is anticipated to commence production in early March 2010.

During the year ended December 31, 2009, Petrodelta drilled and completed 14 successful development wells, suspended one well due to problems with the well and drilled two appraisal wells. Petrodelta currently has one drilling rig working in the Uracoa field.

On January 28, 2010, we entered into an agreement with one of the private third parties in our AMI for an option to participate in a new project. We paid $1.5 million for the option to acquire up to a 50 percent interest in the new project. If we exercise our option to participate, we will participate in this project with essentially the same terms as the other existing projects in the AMI. The option to participate expires on June 1, 2010.

On February 17, 2010, we closed a debt offering of $32 million in aggregate principal amount of our 8.25 percent senior convertible notes due 2013, which resulted in net proceeds to us, after deducting underwriting discounts, commissions and estimated offering expenses, of approximately $30 million.

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 2009.

As of December 31, 2009, we had total assets of $348.8 million, unrestricted cash of $32.3 million and no long-term debt. For the year ended December 31, 2009, we had revenues of $0.2 million and net cash used in operating activities of $34.9 million. Subsequent to December 31, 2009, we offered and issued $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes due 2013. As of December 31, 2008, we had total assets of $362.3 million, unrestricted cash 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.

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 and Singapore offices, 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 the United States, Indonesia, Gabon, Oman, China and other countries that meet our strategy. However, the execution of this strategy may be limited by factors including access to additional capital and the receipt of dividends from Petrodelta as well as the need to preserve adequate development capital in the interim. As described in Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Capital Resources and Liquidity, on February 17, 2010, we incurred indebtedness of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. As a result of this offering, we received net proceeds, after deduction of underwriting discounts, commissions and estimated offering expenses, of approximately $30.0 million. We intend to use these net proceeds to fund capital expenditures and for working capital needs and general corporate purposes.

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 our 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, S.C.A. (“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 noncontrolling interest is owned by OGTC. In addition, we have an interest varying from 50 to 55 percent by prospect in an area of the Gulf Coast Region of the United States covered by an AMI agreement with private third parties, a 60 percent interest in the Antelope prospect in the Western United States covered by a JEDA, a 47 percent interest in the Budong-Budong production sharing contract (“Budong PSC”) which we may operate during the production phase, a 66.667 percent interest in the production sharing contract related to the Dussafu Marin Permit production sharing contract (“Dussafu PSC”) for which we are the operator, a 100 percent interest in an Exploration and Production Sharing Agreement (“EPSA”) with Oman for the Al Ghubar/Qarn Alam license, and a 100 percent interest in the WAB-21 petroleum contract in the South China Sea for which we are the operator. See Item 1 — Business, United States; Budong-Budong, Onshore Indonesia; Dussafu Marin, Offshore Gabon, Block 64 Project, Oman, and WAB-21, South China Sea for a more detailed description.

Reserves

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. The primary impacts of the SEC’s final rule on our reserve estimates include:

	•		In Venezuela, the use of the unweighted 12-month average of the first-day-of-the-month contracted reference price of $56.83 per barrel for oil compared to the year-end contracted reference price of $69.87 per barrel, and

	•		In the United States, the use of the unweighted 12-month average of the first-day-of-the-month reference prices of $48.21 per barrel for oil and $3.31 per Mcf for gas compared to year-end reference prices of $61.73 per barrel of oil and $4.25 per Mcf for gas.

	•		The disclosure of probable and possible reserves.

Under the SEC’s final rule, prior period reserves were not restated.

The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided for, management reviews and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Arts in Engineering Science, a Master of Science in Petroleum Engineering, has more than 25 years of experience in reservoir engineering and is a member of the Society of Petroleum Engineers.

All reserve information in this report is based on estimates prepared by Ryder Scott Company L.P. (“Ryder Scott”), independent petroleum engineers. The technical personnel responsible for preparing the reserve estimates at Ryder Scott meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

The following table shows, by country and in the aggregate, a summary of our proved, probable and possible oil and gas reserves as of December 31, 2009. Probable and possible reserves are not reported for Domestic — Utah due to the ongoing evaluation of assets within these categories.


	Oil and		Natural
	Condensate		Gas		Total
	(MBls)		(MMcf)		(MBls)⁽¹⁾
Proved Developed Reserves:
Domestic — Utah		131		653		240
International — Venezuela⁽²⁾		14,242		24,015		18,244

Total Proved Developed		14,373		24,668		18,484


Proved Undeveloped Reserves:
Domestic — Utah		95		473		174
International — Venezuela ⁽²⁾		33,177		38,695		39,626

Total Proved Undeveloped		33,272		39,168		39,800


Total Proved Reserves		47,645		63,836		58,284

Probable Developed Reserves:
International — Venezuela⁽²⁾		118		93		134

Probable Undeveloped Reserves:
International — Venezuela⁽²⁾		43,689		14,593		46,121


Total Probable Reserves		43,807		14,686		46,255


Possible Developed Reserves:
International — Venezuela⁽²⁾		11		—		11

Possible Undeveloped Reserves:
International — Venezuela⁽²⁾		168,506		46,434		176,245


Total Possible Reserves		168,517		46,434		176,256


⁽¹⁾		MBls is determined using the ratio of one barrel of crude oil or condensate to six Mcf of natural gas.

⁽²⁾		Information represents HNR Finance’s 40 percent interest.

Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2009, 2008 and 2007 and changes in proved reserves during the last three years are contained in Part IV, Item 15 — Supplemental Information on Oil and Natural Gas Producing Activities (unaudited). See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies for additional information on our reserves.

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 its business plan as set forth in the Conversion Contract. Under the Conversion Contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. On February 4, 2010, Petrodelta’s board of directors endorsed a capital budget of $205 million for Petrodelta’s 2010 business plan.

Petrodelta shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Currently, Petrodelta has one drilling rig operating in the Uracoa field. For 2010, the planned 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 El Salto field and presently non-producing Isleño field.

During 2009, Petrodelta drilled and completed 14 successful development wells and two appraisal wells, produced approximately 7.8 million barrels of oil and sold 4.4 billion cubic feet (“BCF”) of natural gas. Petrodelta was advised by the Venezuelan government that the 2009 production target was approximately 16,000 barrels of oil per day following the December 17, 2008 Organization of the Petroleum Exporting Countries (“OPEC”) meeting establishing new production quotas. However, Petrodelta was allowed to produce at capacity to help fulfill other companies’ production shortfalls, thus averaging 21,464 barrels of oil per day during 2009.

Petrodelta began the appraisal and testing of its large portfolio of undeveloped resources in the second quarter of 2009. During the second quarter 2009, Petrodelta drilled two successful appraisal wells in the El Salto field, and pilot production commenced from one of the appraisal wells through temporary facilities. The well commenced production on July 18, 2009 and has produced 349,000 barrels of oil through the end of 2009. The second appraisal well is still waiting on permits from the Ministry of Energy and Petroleum (“MENPET”) for testing.

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 (the “original Windfall Profits Tax”). The original Windfall Profits Tax was based on prices for Brent crude. 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 Petroleos de Venezuela S.A. (“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 $0.9 million and $56.4 million for the years ended December 31, 2009 and 2008, respectively, for the amended Windfall Profits Tax.

During the fourth quarter of 2009, PDVSA completed an updated actuarial study as of December 31, 2009. This study was based on a further refinement of assumptions for each of the mixed companies, including Petrodelta and a new allocation methodology as PDVSA gathered during 2009 all relevant information for each of the mixed companies. The revised pension obligation allocated to Petrodelta resulted in a decrease of $8.4 million ($2.7 million net to our 32 percent interest) to the pension and retirement plan costs as compared to those previously recorded to Petrodelta in May 2009. This change in management’s estimate related to the pension and retirement plan costs was recorded in December 2009. Pension costs at December 31, 2009 reasonably reflect Petrodelta’s employee demographic and plan conditions. The additional pension cost is not tax deductible until future periods when the pension is settled in cash. The provision for the pension plan is subject to future revisions, both upwards and downwards, based on changes in assumptions, the terms of the relevant plans, the allocation methodology or other prospective amendments or changes as determined by PDVSA.

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 (“OHL”) to contribute two percent of their gross revenue generated in Venezuela from activities specified in the OHL. The contribution is based on the previous year’s gross revenue and is due the following year. LOCTI requires that each company file a separate declaration stating how much has been contributed; however, waivers have been granted in the past to allow PDVSA to file a declaration on a consolidated basis covering all of its and its consolidating entities liabilities. Since Petrodelta expects PDVSA to continue requesting and receiving waivers, Petrodelta has not accrued a liability to LOCTI for the year ended December 31, 2009. The potential exposure to LOCTI for the year ended December 31, 2009 is $9.5 million, $4.8 million net of tax ($1.5 million net to our 32 percent interest).

In our Annual Report on Form 10-K for the year ended December 31, 2008, we reported that Petrodelta had not received all information regarding production and operating costs during the conversion period for the Temblador field in order to invoice all volumes produced in that field during that period. As Temblador production was processed through the PDVSA system, PDVSA had allocated only partial, estimated production to Petrodelta. As a result, Petrodelta had not, and still has not, received full credit for the Temblador field production nor has Petrodelta been invoiced for the related operating costs. Although we believe the amount of production, related revenue and operating costs to be immaterial to Petrodelta, discussions are ongoing to settle figures. During the third quarter of 2009, Petrodelta completed the facilities and pipelines to segregate approximately 80 percent of the Temblador field’s production into Petrodelta’s system.

PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors. As a result, Petrodelta has experienced, and may continue to experience, difficulty in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is having an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.

On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement which establishes new exchange rates for the Venezuela Bolivar (“Bolivar”)/United States Dollar (“U.S. Dollar”) currencies that will enter into force on January 11, 2010. Each exchange rate will be applied to foreign currency sales and purchases conducted through the Foreign Currency Administration Commission (“CADIVI”), in the cases expressly provided in the Exchange Agreement. In this regard, the exchange rates established in the Agreement are: 2.60 Bolivars per U.S. Dollar and 4.30 Bolivars per U. S. Dollar. The 2.60 Bolivar exchange rate applies to the food, health, medical and technology sectors. The 4.30 Bolivar exchange rate applies to all other sectors not expressly established by the 2.60 Bolivar exchange rate. The U.S. Dollar is the functional reporting currency for both Petrodelta and Harvest Vinccler.

Location and Geology

Petrodelta Fields

Uracoa Field

There are currently 78 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 four 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 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 were drilled by PDVSA prior to the field being contributed to Petrodelta 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 four years.

Temblador Field

The Temblador field was discovered in 1936 and developed in the 1940s and 1950s. There are currently 19 oil producing wells in the field. The fluid produced from Temblador field flows through two flow stations operated by Petrodelta. Approximately 80 percent of the Temblador field’s production flows through Petrodelta pipelines directly into PDVSA’s system. The remaining 20 percent of the Temblador field’s production flows through the EPT-1 plant operated by PDVSA. 3-D seismic is available over the entire field.

El Salto Field

The El Salto field was discovered in 1936. Currently there is one oil producing well in the field. A total of 31 appraisal wells were drilled by PDVSA prior to the field being contributed to Petrodelta, identifying nine productive structures and six productive formations. Pilot production from the one producing well commenced in the second quarter of 2009 through temporary facilities. The second appraisal well will be tested after the permitting process with MENPET is completed. 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. Approximately 20 percent of the 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 focus in 2009 was the resumption of drilling in the Uracoa field, development drilling in the Temblador field and appraisal drilling in the El Salto field which resulted in an increase in production. Petrodelta is reprocessing existing 3-D seismic over Petrodelta’s fields. Temblador field production is processed at existing field facilities. El Salto production is being process through temporary 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. Isleño field production can be integrated into the existing Uracoa field infrastructure providing for early production from the field. Overall, production is expected to peak in approximately ten years under Petrodelta’s 2010 business plan.

Risk Factors

We face significant risks in holding a 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.

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. The private third party contributed these 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 agreed to fund the first $20 million of new lease acquisitions, geological and geophysical studies, seismic reprocessing and drilling costs. At June 30, 2009, we had met the $20 million funding obligation under the terms of the AMI. All costs incurred after June 30, 2009 are being shared by the parties in proportion to their working interests as defined in the AMI. In August 2009, the AMI became a three party arrangement when the private third party restructured and assigned a portion of its interest to one of its affiliates.

The private third parties are obligated to evaluate and present additional opportunities at their sole cost. As each prospect is accepted it will be covered by the AMI. Although several additional potential prospects had been screened and evaluated within the AMI since its inception, we had not pursued leasing or drilling on any new projects within the AMI as of December 31, 2009. On January 28, 2010, we entered into an agreement with one of the private third parties in our AMI for an option to participate in a new project. We paid $1.5 million for the option to acquire up to a 50 percent interest in the new project. If we exercise our option to participate, we will participate in this project with essentially the same terms as the other existing projects in the AMI. The option to participate expires on June 1, 2010.

Location and Geology

The AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana, including state waters.

Drilling and Development Activity

We drilled an exploratory dry hole on the Starks prospect in 2008. In December 2009, we wrote off the remaining carrying value of $0.7 million of the Starks prospect as we have no plans for further activities relating to this prospect.

During the year ended December 31, 2009, operational activities in the West Bay prospect included the interpretation of 3-D seismic, site surveying, and preparation of engineering documents. Interpretation of 3-D seismic data on the West Bay project was completed in 2009 and resulted in the identification of a set of drilling leads and prospects for the project. On July 14, 2009, we, along with our partner in the AMI, acquired 880 acres of shallow water offshore bay leases representing two separate tracts from the State of Texas General Land Office at a state lease sale for a total gross cost of $0.5 million. Acquisition of these two tracts completes the planned land acquisition activities on the project.

The AMI participants are currently continuing to evaluate the leads and prospects to determine priorities and drilling plans for the West Bay project and have identified the likely initial drilling prospect. Land, regulatory, and surface access preparations are currently in progress focused on taking the initial drilling prospect to drill-ready status. Current plans are to drill the initial well in 2011.

Western United States — Antelope

In October 2007, we entered into a JEDA with a private third party to pursue a lease acquisition program and drilling program on the Antelope prospect in the Western United States. We are the operator and had an initial working interest of 50 percent in the Antelope prospect. The private third party is obligated to assemble the lease position on the Antelope prospect. The JEDA provides that we would earn our initial 50 percent working interest in the Antelope prospect by compensating the private third party for leases acquired in accordance with terms defined in the JEDA, and by drilling and completing one deep natural gas test well (the Bar F) at our sole expense. In November 2008, we entered into a Letter Agreement/Amendment of the JEDA (the “Letter Agreement”) with the private third 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 prospect as a note receivable, addition of a requirement for the private third party to partially assign leases to us prior to meeting the lease earning obligation, and clarification of the private third party’s cost obligations for any shallow wells to be drilled on the Antelope prospect prior to the Bar F. Per the Letter Agreement, payment of the $2.7 million note receivable was due from the private third party on or by spud date of the Bar F. Since payment was not received prior to the Bar F spud date, our interest in the Antelope prospect was increased to 60 percent, with the incremental 10 percent working interest being earned by drilling and completing the Bar F. The note receivable remains outstanding and will be collected through sales revenues taken from a portion of the private third party’s net revenue from the Bar F provided the Bar F is commercial.

Activities are in progress on two separate projects on the Antelope prospect in Duchesne County, Utah.

Mesaverde

General

The Mesaverde 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 were identified in three prospective reservoir horizons in preparation for drilling.

Drilling and Development Activity

of multiple potential reservoir horizons is now in progress. To date, testing has been focused on the evaluation of the natural gas potential of the Mesaverde tight gas reservoir over a prospective interval from 14,000 to 17,400 feet. Completion activities consisted of hydraulic fracturing of eight separate reservoir intervals in the Mesaverde and multiple extended flow tests of the individual fractured intervals, along with a flow test of the commingled eight intervals. While the results to date have not definitively determined the commerciality of a stand-alone development of the Mesaverde, we believe these results indicate progress toward that determination and that the Mesaverde reservoir remains potentially prospective over a portion of our land position.

Earning of Undeveloped Acreage

Acreage for Mesaverde 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 completing the lease earning obligation in 2010. If, however, the earning well is not 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 third party in accordance with the terms of the Letter Agreement.

Monument Butte

General

The Monument Butte project is an eight well appraisal and development drilling program to produce oil and natural gas from the Green River formation on the southern portion of our Antelope land position. The Monument Butte project is non-operated and we hold a 43 percent working interest. The parties have formed a 320 acre AMI which contained the eight drilling locations.

Drilling and Development Activity

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

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 a maximum of $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 2008, we completed the purchase of a 66.667 percent interest in the Dussafu PSC for $6.0 million. 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. Operational activities during 2009 focused on completion of the processing and reprocessing of 1,330 kilometers of 2-D seismic and the pre-stack depth reprocessing of 1,076 square kilometers of 3-D seismic data. The improved imaging from this work has allowed the interpretation to mature the prospect inventory to provide the partnership a number of prospective targets in the sub-salt section, in both the Gamba and Syn-rift plays that are productive in the nearby Etame, Lucina and M’Bya fields. Subject to drilling rig availability, we expect to drill an exploration well in the third quarter of 2010.

Oman

General

On April 11, 2009, we signed an Exploration and Production Sharing Agreement (“EPSA”) with Oman for the Al Ghubar/Qarn Alam license. We have a 100 percent working interest in Block 64 EPSA during the exploration phase. Oman Oil Company has the option to back-in to up to a 20 percent interest in Block 64 EPSA after the discovery of gas.

Location and Geology

Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate which the Oman Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). The 3,867 square kilometer (955,600 acres) block is located in the gas and condensate rich Ghaba Salt Basin in close proximity to the Barik, Saih Rawl and Saih Nihayda gas and condensate fields.

Drilling and Development Activity

PDO will continue to produce oil from several fields within Block 64 EPSA area. We have an obligation to drill two wells over a three year period with a funding commitment of $22.0 million. Current activities include the compilation of existing data, over two prospect areas of approximately 1,000 square kilometers and geological studies to determine drillable prospects. Well planning is expected to commence in 2010 for exploration drilling in 2011.

WAB-21, South China Sea

General

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 and the discovery in 2009 of Ca’ Rong. 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, 2011. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist. Recently, Vietnam, along with the company that is the party to the agreement with Vietnam, announced plans for exploration drilling during 2010. While no assurance can be given, we believe this announcement may provide some resolution with the border disputes, although we do not know in what manner any resolution might appear.

Production, Prices and Lifting Cost Summary

In the following table we have set forth, by country, our net production, average sales prices and average operating expenses for the years ended December 31, 2009, 2008 and 2007. The presentation for Venezuela

includes 100 percent of Petrodelta’s production. The United States is presented at our ownership interest. In thousands, except per unit information:


	Year Ended December 31,
	2009		2008		2007
Venezuela(a)
Crude Oil Production (Bbls)		7,835		5,505		5,374
Natural Gas Production (Mcf)(b)		4,397		10,700		13,456
Average Crude Oil Sales Price ($per Bbl)	$	57.62	$	83.22	$	58.61
Average Natural Gas Sales Price ($ per Mcf)	$	1.54	$	1.54	$	1.54
Average Operating Expenses ($ per Boe)(c)	$	8.46	$	10.90	$	4.20
United States
Monument Butte(d)
Net Crude Oil Production (Bbls)		3		—		—
Natural Gas Production (Mcf)		6		—		—
Average Crude Oil Sales price ($per Bbl)	$	61.61	$	—	$	—
Average Natural Gas Sales Price ($ per Mcf)	$	2.77	$	—	$	—
Average Operating Expenses ($ per Boe)	$	—	$	—	$	—


(a)		Information represents 100 percent of production.

(b)		Royalty-in-kind paid on gas used as fuel was 3,323 Mcf and 3,830 Mcf for 2009 and 2008, respectively.

(c)		Net of royalty and excluding workovers.

(d)		Information represents our ownership interest.

Drilling and Undeveloped Acreage

For acquisitions of leases, development and exploratory drilling, we spent approximately (excluding our share of capital expenditures incurred by equity affiliates) $28.0 million, $26.3 million and $0.6 million in 2009, 2008 and 2007, respectively. These numbers do not include any costs for the development of proved undeveloped reserves in 2009, 2008 or 2007.

We have participated in the drilling of wells as follows:


	Year Ended December 31,
	2009				2008				2007
	Gross		Net		Gross		Net		Gross		Net
Wells Drilled:
Venezuela (Petrodelta)
Development		15		4.8		9		2.9		—		—
Appraisal		2		0.6		—		—		—		—
United States
Development		5		2.1		—		—		—		—
Exploration		1		1.0		1		1.0		—		—

Average Depth of Wells (Feet)
Venezuela (Petrodelta)
Crude Oil		—		6,500		—		6,500		—		—
United States
Crude Oil		—		6,751		—		—		—		—
Natural Gas		—		17,566		—		12,290		—		—

Producing Wells⁽¹⁾:
Venezuela (Petrodelta)
Crude Oil		114		36.5		118		37.8		97		31.0
United States
Crude Oil		2		0.7		—		—		—		—


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

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

Acreage

The following table summarizes the developed and undeveloped acreage that we owned, leased or held under concession as of December 31, 2009:


	Developed				Undeveloped
	Gross		Net		Gross		Net
Venezuela — Petrodelta		23,050		9,220		224,063		89,625
China		—		—		7,470,080		7,470,080
United States:
West Bay		—		—		12,808		6,316
Antelope		212		90		111,457		36,536
Indonesia		—		—		1,357,723		638,130
Gabon		—		—		685,470		456,982
Oman		—		—		955,600		955,600

Total		23,262		9,310		10,817,201		9,653,269

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, 2009, our Houston office had 23 full-time employees. Our Utah, Caracas, London, Singapore, Jakarta and Muscat offices had 1, 14, 7, 3, 4 and 3 employees, respectively. We augment our employees from time to time with independent consultants, as required. We closed our Moscow office on March 31, 2009.

Item 1A. Risk Factors

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

Our cash position and limited ability to access additional capital may limit our growth opportunities. At December 31, 2009, we had $32 million of available cash and, until Petrodelta pays a dividend or the revenue from our U.S. operations increases substantially, cash available from operations will not be sufficient to meet operational requirements. Having a Petrodelta dividend as our primary 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 that Petrodelta will reinvest any excess cash which might be available for payment of dividends into Petrodelta in 2010 and 2011, there is no assurance this will be the case, nor that if the cash is not reinvested that it will be paid as dividends. These factors could have a material adverse effect on our financial condition and liquidity and may limit our ability to grow through the acquisition or exploration of additional oil and gas properties and projects.

We have incurred long-term indebtedness obligations, which significantly increased our leverage. On February 17, 2010, we closed a debt offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes due 2013. Prior to the offering, we had no long-term debt obligations. The degree to which we are leveraged could, among other things:

	•		make it difficult for us to make payments on the notes;

	•		make it difficult for us to obtain financing for working capital, acquisitions or other purposes on favorable terms, if at all;

	•		make us more vulnerable to industry downturns and competitive pressures; and

	•		limit our flexibility in planning for, or reacting to changes in, our business.

Our ability to meet our debt service obligations will depend upon our future performance, which will be subject to financial, business and other factors affecting our operations, many of which are beyond our control. Additionally, the covenants contained in the indenture governing the notes restrict, among other things, our ability to incur certain indebtedness. Any failure to comply with these covenants could result in an event of default under the indenture, which could permit acceleration of the indebtedness under the notes. If our indebtedness were to be accelerated, we cannot assure you that we would be able to repay it.

We may incur significant indebtedness in the near future. We continually assess our need for additional sources of financing based on our operational, working capital and other needs from time to time. In addition, we are currently contemplating one particular additional source of financing through an Islamic (sukuk) financing, in which one of our subsidiaries would form and contribute certain assets to a partnership and subsequently sell a minority interest in the partnership to one or more third parties for approximately $250 million. Although the terms of this transaction have not been finalized, we anticipate that the terms would include our agreement to pay all or a substantial portion of the future dividends paid by Petrodelta over the next five or six years to reacquire all of the third-party partnership interests, including premiums thereon. While we may be able to consummate this financing transaction during the first half of 2010, there can be no assurances that this transaction will be consummated, and we may consider alternative forms of additional financing if we deem necessary or advisable with respect to our operations from time to time.

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 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.

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.

Operations on the Uintah and Ouray Reservation of the Ute Indian Tribe in the western United States are subject to various risks similar to those for foreign operations. Similar to our operations in foreign jurisdictions, our operations on the Uintah and Ouray Reservation of the Ute Indian Tribe are subject to certain risks. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as civil unrest, strikes and other political risks, increases in taxes or fees, being subject to tribal laws, changes in tribal laws and policies and other uncertainties arising out of tribal sovereignty.

Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This Annual Report on Form 10-K contains estimates of our oil and natural gas reserves. 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 — Supplemental Information on Oil and Natural Gas Producing Activities (unaudited), TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on the unweighted average price of the first day of the month during the 12-month period before the ending date of the period covered by the reserve report 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.

We may not be able to replace production with new reserves. In general, production rates and remaining reserves from oil and natural gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. Our 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.

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;

	•		delays in receiving partner approvals;

	•		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 the 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.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Exploration and development and the production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

	•		the amounts and types of substances and materials that may be released into the environment;

	•		response to unexpected releases to the environment;

	•		reports and permits concerning exploration, drilling, production and other operations;

	•		the spacing of wells;

	•		unitization and pooling of properties;

	•		calculating royalties on oil and gas produced under federal and state leases; and

	•		taxation.

Under these laws, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs, natural resource damages and other environmental damages. We also could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action orders. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition, results of operations or cash flows.

Potential regulations regarding climate change could alter the way we conduct our business. Governments around the world are beginning to address climate change matters. This may result in new

environmental regulations that may unfavorably impact us, our suppliers and our customers. The cost of meeting these requirements may have an adverse impact on our financial condition, results of operations and cash flows.

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 Petrodelta’s 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’s operations.

We hold a minority equity investment 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 Petrodelta’s 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.

Petrodelta’s business plan will be sensitive to market prices for oil. Petrodelta operates 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 of Venezuela 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 Petrodelta’s business plan or restricting the budget is limited under the Conversion Contract.

An increase in oil prices could result in increased tax liability in Venezuela affecting Petrodelta’s operations and profitability, which in turn could affect 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 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. Any increase in the taxes payable by Petrodelta, including the Windfall Profits Tax, as a result of increased oil prices will reduce cash available for dividends to us and our partner, CVP.

Oil price declines and volatility could adversely affect Petrodelta’s operations and profitability, which in turn could affect our dividends and profitability. Prices for oil 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 such developments. 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.

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.

PDVSA’s failure to timely pay contractors could have an adverse affect on Petrodelta. PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors. As a result, Petrodelta has experienced, and may continue to experience, difficulty in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is having an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.

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

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

office space in Singapore for approximately $19,000 per month. In April 2009, we signed a two-year lease for office space in Indonesia for approximately $5,000 per month. In September 2009, we signed a two-year lease for office space in Oman for approximately $5,000 per month. In November 2009, we signed a one-year lease for office space in London for approximately $24,000 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, had been stayed indefinitely. On October 20, 2009, the stay was lifted. A trial date of November 1, 2010 has been set. 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. Our Venezuelan subsidiary, 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. 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 accepted. Throughout 2009, the General Attorney Office and Harvest Vinccler agreed several times to resuspend the case while the Finance Minister and the SENIAT confirmed their acceptance to the proposed settlement. On December 30, 2009, Harvest Vinccler settled the case for 3.1 million Bolivars (approximately $1.4 million) for penalties and interest and closed the case with the SENIAT’s concurrence. As a result of the settlement, in December 2009, Harvest Vinccler reversed $0.9 million of accrued penalties and interest previously accrued based on notices received from the SENIAT.

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.

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, 2009, there were 33,281,385 shares of common stock outstanding, with approximately 515 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
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

2009	First quarter		4.69		2.70
	Second quarter		5.66		3.25
	Third quarter		6.64		4.24
	Fourth quarter		6.39		4.90

On March 9, 2010, the last sales price for the common stock as reported by the NYSE was $5.48 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.

STOCK PERFORMANCE GRAPH

The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2009, assuming an investment of $100 on December 31, 2004 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, 2004 and that all dividends were reinvested.

PLOT POINTS
(December 31 of each year)


	2004		2005		2006		2007		2008		2009
Harvest Natural Resources, Inc.	$	100	$	51	$	62	$	72	$	25	$	31
Dow Jones US E&P Index	$	100	$	166	$	174	$	244	$	142	$	201
S&P 500 Index	$	100	$	105	$	121	$	128	$	81	$	102

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, 2009. 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. 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,
	2009			2008			2007⁽¹⁾			2006⁽¹⁾			2005
	(in thousands, except per share data)
Statement of Operations:
Total revenues	$	181		$	—		$	11,217		$	59,506		$	236,941
Operating income (loss)		(30,959	)		(54,440	)		(19,536	)		574			104,571
Net income from Unconsolidated Equity Affiliates		35,757			34,576			55,297			—			—
Net income (loss) attributable to Harvest		(3,107	)		(21,464	)		60,118			(62,502	)		38,876
Net income (loss) attributable to Harvest per common share:
Basic	$	(0.09	)	$	(0.63	)	$	1.65		$	(1.68	)	$	1.05

Diluted	$	(0.09	)	$	(0.63	)	$	1.59		$	(1.68	)	$	1.01

Weighted average common shares outstanding
Basic		33,084			34,073			36,550			37,225			36,949
Diluted		33,084			34,073			37,950			37,225			38,444


	Year Ended December 31,
	2009		2008		2007⁽¹⁾		2006⁽¹⁾		2005
	(in thousands)
Balance Sheet Data:
Total assets	$	348,779	$	362,266	$	417,071	$	468,365	$	451,377
Long-term debt, net of current maturities		—		—		—		66,977		—
Total Harvest’s Stockholders’ equity ⁽²⁾		274,593		273,242		316,647		281,409		337,975


⁽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.

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

Operations

We had a net loss attributable to Harvest of $3.1 million, or $(0.09) per diluted share, for the twelve months ended December 31, 2009 compared with a net loss attributable to Harvest of $21.5 million, or $(0.63) per diluted share, for the twelve months ended December 31, 2008. Net loss attributable to Harvest for the year ended December 31, 2009 includes $7.8 million of exploration expense and the net equity income from Petrodelta’s operations of $40.7 million. Net loss attributable to Harvest 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.

Petrodelta – Venezuela

During 2009, Petrodelta drilled and completed 14 successful development wells, suspended one well due to problems with the well and drilled two appraisal wells, produced approximately 7.8 million barrels of oil and sold 4.4 billion cubic feet (“BCF”) of natural gas. Petrodelta was advised by the Venezuelan government that the 2009 production target was approximately 16,000 barrels of oil per day following the December 17, 2008 OPEC meeting establishing new production quotas. However, Petrodelta was allowed to produce at capacity to help fulfill other companies’ production shortfalls, thus averaging 21,464 barrels of oil per day during 2009.

Petrodelta began the appraisal and testing of its large portfolio of undeveloped resources in the second quarter of 2009. During the second quarter 2009, Petrodelta drilled two successful appraisal wells in the El Salto field, and pilot production commenced from one of the appraisal wells through temporary facilities. The well commenced production on July 18, 2009 and has produced 349,000 barrels of oil through the end of 2009. The second appraisal well will be tested after the permitting process with MENPET is completed.

Petrodelta shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Currently, Petrodelta has one drilling rig operating in the Uracoa field. On February 4, 2010, Petrodelta’s board of directors endorsed a capital budget of $205 million for Petrodelta’s 2010 business plan. For 2010, the planned 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 El Salto field and presently non-producing Isleño field.

On April 23, 2009, Petrodelta’s board of directors declared a dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest). HNR Finance received the cash related to this dividend in the form of an advance dividend in October 2008. We expect to receive future dividends from Petrodelta; however, we expect the amount of any future dividends to be lower in the near term as Petrodelta reinvests most of its earnings into the company in support of its drilling and appraisal activities. 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 and Singapore offices, 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. In 2009, we acquired an exploration asset in Oman that fit our strategy and began production at Monument Butte described below.

United States

Gulf Coast – West Bay

The AMI participants are currently evaluating the leads and prospects to determine priorities and drilling plans for the West Bay project. Depending on the selected drilling prospects and locations, the drilling may or may not require permit(s) from the U.S. Army Corps of Engineers – Galveston District (“Corps of Engineers”). We expect to firm up plans for initial drilling on the West Bay project during 2010, with the expectation of initial drilling on the West Bay project in 2011. During the year ended December 31, 2009, we incurred $0.4 million for lease acquisition, surveying, permitting and site preparation and $1.5 million for seismic data interpretation. The 2010 budget for the West Bay project is $0.1 million.

Western United States – Antelope

Activities are in progress on two separate projects on the Antelope prospect in Duchesne County, Utah.

Mesaverde

The Mesaverde 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 prospects have been identified in three prospective reservoir horizons and initial drilling activities commenced in 2009 on one prospect.

Operational activities during 2009 on the Mesaverde project focused on continuing leasing activities on private, Allottee, and tribal land, and surveying, preliminary engineering, permitting preparations, and conducting drilling operations on a deep natural gas test well (the Bar F) that commenced drilling on June 15, 2009. The Bar F was permitted to 18,000 feet. The Bar F was drilled to a total depth of 17,566 feet and an extended production test is now in progress. To date, testing has been focused on the evaluation of the natural gas potential of the Mesaverde tight gas reservoir over a prospective interval from 14,000 to 17,400 feet. Completion activities consisted of hydraulic fracturing of eight separate reservoir intervals in the Mesaverde and multiple extended flow tests of the individual fractured intervals, along with a flow test of the commingled eight intervals. While the results to date have not definitively determined the commerciality of a stand-alone development of the Mesaverde, we believe these results indicate progress toward that determination and that the Mesaverde reservoir remains potentially prospective over a portion of our land position. During the year ended December 31, 2009, we incurred $23.4 million for drilling, lease acquisition, surveying, permitting and site preparation and $0.3 million for seismic data program planning. The 2010 budget for the Mesaverde project is $5.7 million; however, contingent on successful results of the Bar F and availability of funds, we plan to increase this budget to $33.0 million.

Monument Butte

Monument Butte project is non-operated and we hold a 43 percent working interest. The parties have formed a 320 acre AMI which contained the eight drilling locations.

Operational activities during 2009 on the Monument Butte project focused on resolution of forced pooling issues with a non-consenting interest, negotiations and finalization of an agreement with the operator for the joint drilling operations. As of March 1, 2010, all eight wells have been drilled. Seven wells are currently on production. One additional well is waiting on completion operations and is anticipated to commence production in early March 2010. During the year ended December 31, 2009, we incurred $1.8 million for drilling (including drilling accruals), lease acquisition, surveying, permitting and site preparation. The 2010 budget for the Monument Butte project is $1.1 million which has already been spent in the first quarter of 2010. We are currently evaluating the potential expansion of this drilling program. Contingent on the successful results of this evaluation, negotiation with the operator and availability of funds, this budget could be increased to $4.6 million.

Budong-Budong Project, Indonesia

Operational activities during 2009 focused on the interpretation of 650 kilometers of 2-D seismic and well planning. Two drill sites have been selected. Currently, the locations for the two test wells are being constructed and the rig and ancillary equipment is being mobilized to the area. It is expected that the first of two exploration wells will spud early in the second quarter of 2010. 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, 2009, we incurred $0.3 million for surveying, permitting, engineering and well planning and $1.8 million for seismic data processing and interpretation. The 2010 budget for the Budong PSC is $14.9 million. Contingent on the successful results of the two exploratory test wells and availability of funds, this budget could be increased to $28.0 million.

Dussafu Project — Gabon

Operational activities during 2009 focused on completion of the processing and reprocessing of 1,330 kilometers of 2-D seismic and the pre-stack depth reprocessing of 1,076 square kilometers of 3-D seismic data. The improved imaging from this work has allowed the interpretation to mature the prospect inventory to provide the partnership a number of prospective targets in the sub-salt section, in both the Gamba and Syn-rift plays that are productive in the nearby Etame, Lucina and M’Bya fields. Subject to drilling rig availability, we expect to drill an exploration well in the third quarter of 2010. During the year ended December 31, 2009, we incurred $1.2 million for seismic data processing and reprocessing. The 2010 budget for the Dussafu PSC is $2.2 million. Contingent on rig availability and successful results from the exploration well and availability of funds, this budget could be increased to $20.1 million.

Block 64 EPSA Project — Oman

On April 11, 2009, we signed an EPSA with Oman for the Block 64 EPSA. Current activities include the compilation of existing data over two prospect areas of approximately 1,000 square kilometers and geological studies to determine drillable prospects. Well planning is expected to commence in 2010 for exploration drilling in 2011. We incurred $2.3 million for costs associated with signing the license, including signature bonus and data compilation and $0.5 million for seismic data processing and reprocessing. The 2010 budget for the Block 64 EPSA is $2.8 million. Contingent on the availability of funds, an additional $1.9 million are planned for this project.

WAB-21 Project – China

The WAB-21 petroleum contract lies within an area which is the subject of a border dispute between China and Vietnam. 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. However, Vietnam, along with the company that is the party to the agreement with Vietnam, recently announced plans for exploration drilling during 2010. While no assurance can be given, we believe this announcement may provide some resolution with the border disputes, although we do not know in what manner any resolution might appear.

Other Exploration Projects

Relating to other projects, we incurred $1.3 million during the year ended December 31, 2009. The 2010 budget for other projects is $0.3 million. Contingent upon successful test results in Utah and Indonesia and availability of funds, we may increase this budget to $20.4 million.

Either one of the two exploratory wells to be drilled in 2010 on the Budong PSC or the completion of the well on the Mesaverde project 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. Low 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

The following discussion should be read with the results of operations for each of the years in the three-year period ended December 31, 2009 and the financial condition as of December 31, 2009 and 2008 in conjunction with our consolidated financial statements and related notes thereto.

Years Ended December 31, 2009 and 2008

We reported a net loss attributable to Harvest of $3.1 million, or $(0.09) diluted earnings per share, for the year ended December 31, 2009, compared with a net loss attributable to Harvest of $21.5 million, or $(0.63) diluted earnings per share, for the year ended December 31, 2008.

Revenues were higher for the year ended December 31, 2009 compared with the year ended December 31, 2008 due to the Monument Butte wells coming on production in December 2009.

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


	Year Ended
	December 31,						Increase
	2009			2008			(Decrease)
Depletion, depreciation and amortization	$	0.4		$	0.2		$	0.2
Exploration expense		7.8			16.4			(8.6	)
Dry hole costs		—			10.8			(10.8	)
General and administrative		21.9			27.2			(5.3	)
Taxes other than on income		1.0			(0.2	)		1.2
Gain on financing transactions		—			(3.4	)		3.4
Investment earnings and other		(1.1	)		(3.7	)		2.6
Interest expense		—			1.7			(1.7	)
Income tax expense		1.2			—			1.2

Depletion and amortization expense per Boe produced during 2009 was $6.59.

Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2009, we incurred $4.3 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, $2.8 million related to other general business development activities and $0.7 million related to the write off of the remaining carrying value of the Starks prospect. During the year ended December 31, 2008, we incurred $16.4 million of exploration costs related to the purchase and re-processing of seismic data related to our U.S. operations, acquisition of seismic data 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.

General and administrative costs were lower in the year ended December 31, 2009, than in the year ended December 31, 2008, primarily due to employee related expenses, lower general operations and office costs, and the reversal of accruals no longer required, including penalties and interest of $0.9 million on the resolved SENIAT

assessments. Taxes other than on income for the year ended December 31, 2009, were higher than the year ended December 31, 2008 due to the reversal in 2008 of a $1.1 million franchise tax provision that was no longer required.

We did not participate in any security exchange transactions in the year ended December 31, 2009. During the year ended December 31, 2008, we entered into a securities exchange transaction exchanging U.S. government securities for U.S. Dollar indexed debt issued by the Venezuelan government. This security exchange transaction resulted in a $3.4 million gain on financing transactions for the year ended December 31, 2008.

Investment earnings and other decreased in the year ended December 31, 2009 compared to the year ended December 31, 2008 due to lower interest rates earned on lower average cash balances. Interest expense was lower for the year ended December 31, 2009 compared to the year ended December 31, 2008 due to the repayment of debt in 2008.

For the year ended December 31, 2009, income tax expense was higher than that of the year ended December 31, 2008 primarily due to additional income tax assessed in the Netherlands of $0.7 million as a result of financing activities, which was recorded in the first quarter of 2009, and additional current income tax in the Netherlands of $0.5 million due to interest income earned from loans to affiliates and on cash balances. 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, 2009.

Net income from unconsolidated equity affiliates includes two non-recurring adjustments:

	•		During the second quarter of 2009, Petrodelta recorded additional pension expense of $15.6 million ($5.0 million net to our 32 percent interest) in the three month period ended June 30, 2009 based on an actuarial study commissioned by PDVSA which was finalized during the second quarter of 2009. During the fourth quarter of 2009, Petrodelta received a revised allocation of its pension obligation from PDVSA which reflected an update to the actuarial study based on a further refinement of assumption and a revised allocation methodology as a result of an analysis of more detailed census data specific to each mixed company not previously available. This revised allocation resulted in a decrease of $8.4 million ($2.7 million net to our 32 percent interest) to the pension and retirement plan costs as compared to those previously recorded to Petrodelta in May 2009. This change in management’s estimate related to the pension and retirement plan costs was recorded in December 2009.

	•		Based on cash flow projections and considering Fusion’s current liquidity, we performed a review at December 31, 2009 for impairment of our minority equity investment in Fusion. Based on this review, we concluded that Fusion’s potential business opportunities did not support its on-going cash flow requirements; and therefore, we recorded a $1.6 million charge to fully impair the carrying value of our equity investment in Fusion at December 31, 2009.

See Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 7 – Investment in Equity Affiliates for additional information.

Years Ended December 31, 2008 and 2007

We reported a net loss attributable to Harvest of $21.5 million, or $(0.63) diluted earnings per share, for the year ended December 31, 2008 compared to net income attributable to Harvest of $60.1 million, or $1.59 diluted earnings per share, for the year end December 31, 2007.

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 noncontrolling 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, 2009, 2008 and 2007, comparatively.

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)
Depreciation	$	0.2		$	0.4		$	(0.2	)
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 earnings 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 data related to our U.S. operations, acquisition of seismic data 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. 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 on 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 was 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 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.

Capital Resources and Liquidity

The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks (see Item 1A — Risk Factors). We require capital principally to fund the exploration and development of new oil and gas properties. For calendar year 2010, we have preliminarily established an exploration and drilling budget of approximately $27.1 million. We are concentrating a substantial portion of this budget on the development of our Antelope prospect and Budong PSC. Contingent upon the successful test results of the exploratory well drilled on the Antelope prospect, the exploratory wells to be drilled on the Budong PSC and availability of funds, we have planned capital expenditures of up to $110.8 million to evaluate and develop our prospect portfolio in the United States and international locations, excluding Venezuela’s self funding program. We currently believe that Petrodelta will fund its own operations and continue to pay dividends although no dividends are expected in 2010 based on our current forecast. 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.

Based on our cash balance of $32 million at December 31, 2009, we will be required to raise additional funds in order to fund our future operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration projects and to a lesser extent general and administrative costs. Through December 31, 2009, our exploration expenditures outside of Venezuela have resulted in a modest amount of new proved reserves in Utah in the United States. If we are not able to raise additional capital or prove up additional sources of revenue, there will be a need to reduce our projected expenditures which could limit our ability to operate our business. Currently, our primary source of cash is dividends from Petrodelta. However, there is no certainty that Petrodelta will pay dividends in 2010 or 2011. Our lack of cash flow and the unpredictability of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance adequate financing can be raised. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, exploration of our properties worldwide, and cost reductions. In addition, we could delay discretionary capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, if necessary. There can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.

On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. Under the terms of the notes, we will pay interest semi-annually and the notes will mature on March 1, 2013, unless earlier redeemed, repurchased or converted. The notes are convertible into shares of our common stock at a conversion rate of 175.2234 shares of common stock per $1,000 principal amount of convertible notes, equivalent to a conversion price of approximately $5.71 per share of common stock, subject to adjustment. The notes are our general unsecured obligations, ranking equally with all of our other unsecured senior indebtedness, if any, and senior in right of payment to any of our subordinated indebtedness, if any. The notes are also redeemable in certain circumstances at our option and may be repurchased by us at the purchaser’s option in connection with occurrence of certain events. The net proceeds of the offering to us were approximately $30.0 million, after deducting underwriting discounts, commissions and estimated offering expenses. We intend to use these net proceeds to fund capital expenditures and for working capital needs and general corporate purposes.

In addition, we are currently contemplating one particular additional source of financing through an Islamic (sukuk) financing, in which one of our subsidiaries would form and contribute certain assets to a partnership and subsequently sell a minority interest in the partnership to one or more third parties for approximately $250 million. Although the terms of this transaction have not been finalized, we anticipate that the terms would include our agreement to pay all or a substantial portion of the dividends paid by Petrodelta to which we are entitled over the next five or six years to reacquire all of the third-party partnership interests, including premiums thereon. While we may be able to consummate this financing transaction during the first half of 2010, there can be no assurances that this transaction will be consummated, and we may consider alternative forms of additional financing if we deem necessary or advisable with respect to our operations from time to time.

On February 5, 2003, Venezuela imposed currency controls and created CADIVI 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 U.S. Dollar and Bolivar exchange rates had not been adjusted since March 2005 until January 8, 2010 when the Venezuelan government adjusted the exchange rate from 2.15 Bolivars per U.S. Dollar to 2.60 Bolivars per U. S. Dollar for the food, health, medical and technology sectors; and 4.30 Bolivars per U. S. Dollar for all other sectors not expressly established by the 2.60 Bolivar exchange rate. The U.S. Dollar is the functional reporting currency for both Petrodelta and Harvest Vinccler. 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. On April 23, 2009, Petrodelta’s board of directors declared a dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest). HNR Finance received the cash related to this dividend in the form of an advance dividend in October 2008. We expect to receive future dividends from Petrodelta; however, we expect the amount of any future dividends to be lower in the near term as Petrodelta reinvests most of its earnings into the company in support of its drilling and appraisal activities. In June 2009, CVP issued instructions to all mixed companies regarding the accounting for deferred tax assets. The mixed companies have been instructed to set up a reserve within the equity section of the balance sheet for deferred tax assets. The setting up of the reserve had no effect on Petrodelta’s financial position, results of operation or cash flows. However, the new reserve could have a negative impact on the amount of dividends received in the future. In addition to reinvesting earnings into the company in support of its drilling and appraisal activities, the decline in the price per barrel affects Petrodelta’s ability to pay dividends. All available cash will be used to meet current operating requirements and will not be available for dividends. See Item 1 — Business, Petrodelta and Item 1A — Risk Factors for a more complete description of the situation in Venezuela and other matters.

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)
	2009			2008			2007
Net cash provided by (used in) operating activities	$	(34,945	)	$	50,380		$	(20,655	)
Net cash provided by (used in) investing activities		(28,603	)		(23,055	)		69,960
Net cash used in financing activities		(1,300	)		(51,001	)		(76,543	)

Net decrease in cash	$	(64,848	)	$	(23,676	)	$	(27,238	)


Working Capital		34,206			77,010			111,534
Current Ratio		3.0			3.0			3.6
Total Cash, including restricted cash		32,317			97,165			127,610
Total Debt		—			—			9,302

The decrease in working capital of $42.8 million was for capital expenditures and administrative expenses.

Cash Flow from Operating Activities. During the year ended December 31, 2009, net cash used in operating activities was approximately $34.9 million. During the year ended December 31, 2008, net cash provided by operating activities was approximately $50.4 million. The $85.3 million decrease was primarily due to the receipts in 2008 of a $72.5 million dividend net to HNR Finance ($58.0 million net to our 32 percent interest) and advance dividend of $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 the noncontrolling interest in Harvest-Vinccler Dutch Holding, B.V., and capital expenditures.

Cash Flow from Investing Activities. During the year ended December 31, 2009, we had cash capital expenditures of approximately $28.0 million. Of the 2009 expenditures, $0.4 million was attributable to the West Bay project, $23.7 million was attributable to the Antelope prospect, $0.3 million was attributable to exploration

activity on the Budong PSC, $2.3 million was attributable to the Block 64 EPSA project and $1.3 million on other projects. During the year ended December 31, 2008, we had cash capital expenditures of approximately $26.3 million. Of the 2008 expenditures, $4.7 million was attributable to the Gulf Coast prospects, $10.8 million was attributable to the Harvest Hunter #1 exploration well, $4.2 million was attributable to the Antelope prospect, $0.1 million was attributable to the Budong PSC, $5.3 million was attributable to the Dussafu PSC, and $1.2 million on other projects. During the year ended December 31, 2008, we increased our minority equity investment in Fusion by purchasing an additional two percent interest for $2.2 million. During the year ended December 31, 2008, $6.8 million of restricted cash used as collateral for loans which were repaid was returned to us. During the year ended December 31, 2009 and 2008, we incurred $0.6 million and $1.3 million, respectively, of investigatory costs related to various international and domestic exploration studies.

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 $27.1 million for 2010 for U.S., Indonesia, Gabon and Oman operations will be funded through our existing cash balances, the February 2010 debt offering, other financing sources, accessing equity and debt markets, and cost reductions. In addition, we could delay discretionary capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, as warranted.

Cash Flow from Financing Activities. During the year ended December 31, 2009 we incurred $1.7 million in legal fees associated with prospective financing. During year ended December 31, 2008, Harvest Vinccler repaid 20 million Bolivars (approximately $9.3 million) of its Bolivar denominated debt, we redeemed the 20 percent minority interest in our Barbados affiliate, incurred $1.1 million in legal fees associated with prospective financing, and we paid a dividend of $14.9 million to the noncontrolling interest in Harvest-Vinccler Dutch Holding, B.V.

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. As of December 31, 2008, 1.2 million shares of stock had been purchased at an average cost of $10.17 per share for a total cost of $12.2 million of the $20 million authorization. During the year ended December 31, 2009, no stock was purchased under the program.

Contractual Obligations

We have a lease obligation of approximately $32,000 per month for our Houston office space. This lease runs through July 2014. In addition, Harvest Vinccler has lease obligations for office space in Caracas, Venezuela for approximately $10,000 per month. This lease runs through November 2010. We also have lease commitments for an office in Utah for approximately $6,000 per month, an office in Singapore for approximately $19,000 per month, an office space in Indonesia for approximately $5,000 per month, an office in Oman for approximately $5,000 per month and an office in London for approximately $24,000 per month. These leases expire in September 2010, October 2010, March 2011, August 2011 and November 2010, respectively. Our London office space is leased on a month-to-month basis with no long term commitment. We do not have any long-term contractual commitments for any of our projects.


	Payments (in thousands) Due by Period
			Less than						After 4
Contractual Obligation	Total		1 Year		1-2 Years		3-4 Years		Years
Office Leases	$	2,674	$	1,215	$	459	$	407	$	593
Asset Retirement Obligation		50		—		—		—		50

Total Contractual Obligations	$	2,724	$	1,215	$	459	$	407	$	643

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, March 2005 and again in January 2010. 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 and other countries in which we conduct business, 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, 2009 and 2008, our net foreign exchange gains attributable to our international operations were minimal. The U.S. Dollar and Bolivar exchange rates have not been adjusted from March 2005 until January 2010. 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.

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.

The U.S. Dollar is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta.

Revenue Recognition

We record revenue for our U.S. oil and natural gas operations when we deliver our production to the customer and collectability is reasonably assured. Revenues from the production of oil and natural gas on properties in which we have joint ownership are recorded under the sales method. Differences between these sales and our entitled share of production are not significant.

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 whenever events and circumstances indicate a decline in the recoverability of its carrying value.

Property and Equipment

We follow the successful efforts method of accounting for our oil and gas properties. Under this method, 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 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 reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved 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 is proved reserves. With respect to lease and well equipment costs, which include costs and successful exploration drilling costs, the reserve base is proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.

Assets are grouped in accordance with paragraph 30 of the accounting standard for 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 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 of proved propertied under the provisions of the accounting standard for 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.

Reserves

In December 2009, we adopted revised oil and gas reserve estimation and disclosure requirements which conforms the definition of proved, probable and possible reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The new accounting standard requires that the unweighted average, first-day-of-the-month price during the 12-month period preceding the end of the year, rather than the year-end price, be used when estimating reserve quantities and permits the use of reliable technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Prior-year data are presented in accordance with FASB oil and gas disclosure requirements effective during those periods.

Proved reserves are those quantities of oil and gas which by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, government regulations, etc., i.e., at prices as described above and costs as of the date the estimates are made. Prices include consideration of changes in existing prices provided only by contractual arrangements, and do not include adjustments based upon expected future conditions. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves which are less certain to be recovered than probable reserves and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

Reserves may be estimated using probabilistic methods in which there is at least a 90 percent probability of recovery of proved reserves, at least a 50 percent probability of recovery of probable reserves, and at least a 10 percent probability of recovery of possible reserves. Our probable reserves were calculated using probabilistic methods and represent the 50 percent probability that the actual quantities recovered will be equal to or greater than the proved plus probable estimate. The larger quantity of proved reserves plus probable reserves, as compared to proved reserves only, is attributable largely to using a less conservative interpretation of reservoir size and recovery factor in estimating probable reserves.

The estimate of reserves is made using available geological and reservoir data as well as production performance data. These estimates are prepared by an independent third party petroleum engineering consulting firm and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits earlier. A material adverse change in the estimated volumes of proved reserves could have a negative impact on DD&A expense and could result in the recognition of an impairment.

Accounting for Asset Retirement Obligation

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record a liability (an asset retirement obligation or “ARO”) on our consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation assuming the normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for our Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis within the related asset group. Accretion is included in operating expenses and depreciation is included in depreciation, depletion and amortization on our consolidated statement of income.

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.

New Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (“FASB”) issued an accounting standard for subsequent events which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. This standard is effective for interim or annual periods ending after June 15, 2009. We adopted this standard effective June 15, 2009. The adoption of this standard did not have an effect on our consolidated financial position, results of operations or cash flows.

In June 2009, the FASB issued an accounting standard for accounting for transfers of financial assets. The objective in issuing this standard is to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. This standard is effective for annual periods beginning after November 15, 2009. The adoption of this standard did not have a material impact on our consolidated financial position, results of operations or cash flows.

In June 2009, the FASB issued an amendment to the financial interpretation to improve financial reporting by enterprises involved with variable interest entities. This amendment is effective for annual periods beginning after November 15, 2009. This amendment did not have a material impact on our consolidated financial position, results of operations or cash flows.

not included in this standard is now nonauthoritative. This standard is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of this standard did not have an impact on our consolidated financial position, results of operations or cash flows.

In December 2009, the FASB issued its final updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure requirements of Extractive Industries — Oil and Gas (Topic 932) with the requirements in the SEC’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and is effective as of 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-40.


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.

Management of the Company, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures. Based on their evaluation as of December 31, 2009, 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 effective.

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. Based on our evaluation under the Internal Control Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2009. The effectiveness of our internal control over financial reporting as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Management’s Remediation Efforts. In our Annual Report on Form 10-K for the year ended December 31, 2008, management concluded that 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.

During 2009, management has enhanced the controls over its equity investment to ensure that the adequate information regarding Petrodelta’s temporary deferred tax 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 temporary deferred tax 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 identified and completely and accurately reconciled.

During the year ended December 31, 2009, management further enhanced the controls necessary to ensure that all necessary adjustments are appropriately analyzed and recorded on a timely basis. These enhancements were in place and operating effectively as of December 31, 2009.

Changes in Internal Control over Financial Reporting. There have been no changes in internal control over financial reporting during the quarter ended December 31, 2009 that have materially affected or are reasonably likely to materially affect that Company’s internal control over financial reporting.


Item 9B.		Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Please refer to the information under the captions “Election of Directors” and “Executive Officers” in our Proxy Statement for the 2010 Annual Meeting of Stockholders.


Item 11.		Executive Compensation

Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the 2010 Annual Meeting of Stockholders.


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

Please refer to the information under the caption “Stock Ownership” in our Proxy Statement for the 2010 Annual Meeting of Stockholders.


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

Please refer to the information under the caption “Certain Relationships and Related Transactions” in our Proxy Statement for the 2010 Annual Meeting of Stockholders.

Item 14. Principal Accountant Fees and Services

Please refer to the information under the caption “Independent Registered Public Accounting Firm” in our Proxy Statement for the 2010 Annual Meeting of Stockholders.

PART IV

Item 15. Exhibits and Financial Statement Schedules


(a)	1.	Index to Financial Statements:	Page


		Report of Independent Registered Public Accounting Firm	S-1

		Consolidated Balance Sheets at December 31, 2009 and 2008	S-2

		Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008 and 2007	S-3

		Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2009, 2008 and 2007	S-4

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007	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 May 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.)

	4.4		Indenture dated as of February 17, 2010, between Harvest Natural Resources, Inc. and U.S. Bank National Association, as trustee. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on February 18, 2010, File No. 1-10762.)

	4.5		First Supplemental Indenture dated as of February 17, 2010 between Harvest Natural Resources, Inc. and U.S. Bank National Association, as trustee. (Incorporated by reference to Exhibit 4.2 to our Form 8-K filed on February 18, 2010, File No. 1-10762.)

	4.6		Form of 8.25% Senior Convertible Notes due 2013. (Incorporated by reference to Exhibit 4.3 to our Form 8-K filed on February 18, 2010, 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		Placement Agent Agreement dated February 10, 2010, by and among Harvest Natural Resources, Inc., as issuer, and Lazard Capital Markets LLC and Madison Williams and Company LLC, as placement agents, relating to the 8.25% Senior Convertible Notes due 2013. (Incorporated by reference to Exhibit 10.1 to our Form 8-K filed on February 11, 2010, File No. 1-10762.)

	10.34		Form of Standard Subscription Agreement, to be entered into by and among Harvest Natural Resources, Inc. and certain purchasers signatory thereto. (Incorporated by reference to Exhibit 10.2 to our Form 8-K filed on February 11, 2010, File No. 1-10762.)

	10.35		Form of Subscription Agreement, to be entered into by and among Harvest Natural Resources, Inc. and certain purchasers signatory thereto. (Incorporated by reference to Exhibit 10.3 to our Form 8-K filed on February 11, 2010, 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.

	99.1		Reserve report dated February 26, 2009 between Harvest (US) Holdings, Inc. and Ryder Scott Company.

	99.2		Reserve report dated February 26, 2009 between HNR Finance B.V. and Ryder Scott Company.


^†		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, 2009 and December 31, 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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 maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, the financial statement schedule and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for noncontrolling interests effective January 1, 2009. As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it estimates the quantities of proved oil and natural gas reserves in 2009.

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.

S-1

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2009			2008
	*(in thousands, except per share data)*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	32,317		$	97,165
Accounts and notes receivable, net		11,478			11,570
Advances to equity affiliate		4,927			3,732
Prepaid expenses and other		2,214			3,964

TOTAL CURRENT ASSETS		50,936			116,431

OTHER ASSETS		3,613			3,316
INVESTMENT IN EQUITY AFFILIATES		233,989			218,982
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		58,543			22,328
Other administrative property		3,085			2,368

		61,628			24,696
Accumulated depreciation and amortization		(1,387	)		(1,159	)

		60,241			23,537

	$	348,779		$	362,266

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable, trade and other	$	696		$	1,662
Advance from equity affiliate		—			20,750
Accrued expenses		10,253			12,241
Accrued interest		4,691			4,691
Income taxes payable		1,090			77

TOTAL CURRENT LIABILITIES		16,730			39,421

ASSET RETIREMENT LIABILITY		50			—

COMMITMENTS AND CONTINGENCIES		—			—

EQUITY
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, 2009 and 2008; issued 39,495 shares and 39,128 shares at December 31, 2009 and 2008, respectively		395			391
Additional paid-in capital		213,337			208,868
Retained earnings		126,244			129,351
Treasury stock, at cost, 6,448 shares and 6,444 shares at December 31, 2009 and 2008, respectively		(65,383	)		(65,368	)

TOTAL HARVEST STOCKHOLDERS’ EQUITY		274,593			273,242
NONCONTROLLING INTEREST		57,406			49,603

TOTAL EQUITY		331,999			322,845

	$	348,779		$	362,266

See accompanying notes to consolidated financial statements.

S-2

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2009			2008			2007
	*(in thousands, except per share data)*
Revenues
Oil sales	$	160		$	—		$	11,217	*
Gas sales		21			—			—

		181			—			11,217


Expenses
Depletion, depreciation and amortization		436			201			384
Exploration expense		7,824			16,402			850
Dry hole costs		—			10,828			—
General and administrative		21,854			27,215			29,096
Taxes other than on income		1,026			(206	)		423

		31,140			54,440			30,753


Loss from Operations		(30,959	)		(54,440	)		(19,536	)
Other Non-Operating Income (Expense)
Gain on Financing Transactions		—			3,421			49,623
Investment earnings and other		1,085			3,663			9,051
Interest expense		(5	)		(1,730	)		(8,224	)

		1,080			5,354			50,450


Income (Loss) from Consolidated Companies Before Income Taxes		(29,879	)		(49,086	)		30,914
Income Tax Expense		1,182			25			6,312

Income (Loss) from Consolidated Companies		(31,061	)		(49,111	)		24,602
Net Income from Unconsolidated Equity Affiliates		35,757			34,576			55,297

Net Income (Loss)		4,696			(14,535	)		79,899

Less: Net Income Attributable to Noncontrolling Interest		7,803			6,929			19,781


Net Income (Loss) Attributable to Harvest	$	(3,107	)	$	(21,464	)	$	60,118


Net Income (Loss) Attributable to Harvest Per Common Share:
Basic	$	(0.09	)	$	(0.63	)	$	1.65

Diluted	$	(0.09	)	$	(0.63	)	$	1.59


*		Recognition of deferred revenue in 2007 – See Note 1 – Organization and Summary of Significant Accounting Policies – Revenue Recognition.

See accompanying notes to consolidated financial statements.

S-3

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands)


	Common				Additional								Non-
	Shares		Common		Paid-in		Retained			Treasury			Controlling			Total
	Issued		Stock		Capital		Earnings			Stock			Interest			Equity
Balance at January 1, 2007		37,974	$	380	$	194,176	$	90,697		$	(3,844	)	$	37,765		$	319,174

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		—		—		—		60,118			—			19,781			79,899


Balance at December 31, 2007		38,513		385		201,938		150,815			(36,491	)		57,546			374,193

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	)
Distribution to noncontrolling Interests		—		—		—		—			—			(14,872	)		(14,872	)
Net Income (Loss)		—		—		—		(21,464	)		—			6,929			(14,535	)


Balance at December 31, 2008		39,128		391		208,868		129,351			(65,368	)		49,603			322,845

Issuance of common shares:
Exercise of stock options		205		2		384		—			—			—			386
Employee stock-based compensation		162		2		4,085		—			—			—			4,087
Purchase of Treasury Shares		—		—		—		—			(15	)		—			(15	)
Net Income (Loss)		—		—		—		(3,107	)		—			7,803			4,696


Balance at December 31, 2009		39,495	$	395	$	213,337	$	126,244		$	(65,383	)	$	57,406		$	331,999

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,
	2009			2008			2007
				*(in thousands)*
Cash Flows From Operating Activities:
Net income (loss)	$	4,696		$	(14,535	)	$	79,899
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		436			201			384
Dry hole costs		—			10,828			—
Gain on financing transactions		—			(3,421	)		(49,623	)
Net income from unconsolidated equity affiliates		(35,757	)		(34,576	)		(55,297	)
Non-cash compensation related charges		4,087			6,061			6,108
Deferred income taxes		—			—			5,608
Dividend received from equity affiliate		—			72,530			—
Changes in operating assets and liabilities:
Accounts and notes receivable		92			548			393
Advances to equity affiliate		(1,195	)		12,620			2,794
Prepaid expenses and other		(1,055	)		(5,632	)		214
Accounts payable		(966	)		(2,957	)		2,122
Accounts payable, related party		—			(10,093	)		456
Advance from equity affiliate		—			20,750			—
Accrued expenses		(6,296	)		(1,073	)		(1,251	)
Accrued interest		—			(445	)		(1,714	)
Deferred revenue		—			—			(11,217	)
Income taxes payable		1,013			(426	)		469

Net Cash Provided By (Used In) Operating Activities		(34,945	)		50,380			(20,655	)

Cash Flows from Investing Activities:
Additions of property and equipment		(28,022	)		(26,317	)		(647	)
Investments in equity affiliates		—			(2,161	)		(7,388	)
(Increase) decrease in restricted cash		—			6,769			82,120
Investment costs		(581	)		(1,346	)		(4,125	)

Net Cash Provided By (Used In) Investing Activities		(28,603	)		(23,055	)		69,960

Cash Flows from Financing Activities:
Net proceeds from issuances of common stock		386			1,565			1,938
Purchase of treasury stock		—			(29,416	)		(32,755	)
Financing costs		(1,686	)		(1,075	)		—
Payments of note payable		—			(7,211	)		(45,726	)
Dividend paid to minority interest		—			(14,864	)		—

Net Cash Used In Financing Activities		(1,300	)		(51,001	)		(76,543	)

Net Decrease in Cash and Cash Equivalents		(64,848	)		(23,676	)		(27,238	)
Cash and Cash Equivalents at Beginning of Year		97,165			120,841			148,079

Cash and Cash Equivalents at End of Year	$	32,317		$	97,165		$	120,841

Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for interest expense	$	5		$	768		$	7,972

Cash paid during the year for income taxes	$	169		$	456		$	201

See accompanying notes to consolidated financial statements.

S-5

Supplemental Schedule of Noncash Investing and Financing Activities:

During the year ended December 31, 2009, we issued 0.2 million shares of restricted stock valued at $0.7 million. Also, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 3,757 shares being added to treasury stock at cost.

During the year ended December 31, 2008, we issued 0.2 million of restricted stock valued at $2.0 million; most of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 14,457 shares being added to treasury at cost; and 106,000 shares held in treasury were reissued as restricted stock.

During the year ended December 31, 2007, we issued 0.3 million shares of restricted stock valued at $2.6 million; most of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 16,042 shares being added to treasury stock at cost; and 20,000 shares held in treasury were reissued as restricted stock.

See accompanying notes to consolidated financial statements.

S-6

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Note 1 — Organization and Summary of Significant Accounting Policies

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. We have exploration acreage in the Gulf Coast Region of the United States, the Antelope prospect in the Western United States, mainly onshore in West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in the Sultanate of Oman (“Oman”), and offshore of the People’s Republic of China (“China”). We also have production from the Monument Butte project in the Antelope prospect. See Note 8 – United States, Note 9 – Indonesia, Note 10 – Gabon, Note 11 – Oman and Note 12 – China.

Principles of Consolidation

The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. 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 investments and earnings and decreased by dividends and losses. We review our Investment in Equity Affiliates for impairment whenever events and circumstances indicate a decline in the recoverability of its carrying value.

Reporting and Functional Currency

The United States Dollar (“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.

The U.S. Dollar is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta.

Revenue Recognition

Until March 31, 2006, each quarter, Harvest Vinccler, S.C.A. (“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. With the formation of Petrodelta in 2007, 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 a transitory agreement signed in August 2005 between Harvest Vinccler and PDVSA.

S-7

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.

Fair Value Measurements

We adopted the accounting standard for fair value measurements for financial assets as of January 1, 2008 and for non-financial assets and liabilities as of January 1, 2009. This standard provides guidance for using fair value to measure assets and liabilities. This standard also clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing the asset or liability and establishes a fair value hierarchy, giving the highest priority to quoted prices in active markets and the lowest priority to unobservable data. The standard applies whenever other standards require assets or liabilities to be measured at fair value. The adoption of this standard had no impact on our consolidated financial position, results of operations or cash flows.

At December 31, 2009 and 2008, cash and cash equivalents include $26.8 million and $88.6 million, respectively, 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 the accounting standard for fair value measurements.

Credit Risk and Operations

All of our total consolidated revenues in 2007 related to operations in Venezuela. 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 natural 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 the accounting standard for 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 year 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 and is secured by a revenue interest in a well currently being evaluated. At December 31, 2009, notes receivable plus accrued interest was approximately $3.3 million.

Other Assets

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

S-8

of the project. During the year ended December 31, 2009, $1.4 million was reclassified to oil and gas properties and $1.7 million was reclassified to exploration expense. During the year ended December 31, 2008, $3.8 million was reclassified to oil and gas properties and $1.2 million was reclassified to exploration expense.

Property and Equipment

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


	2009			2008
Proved property costs	$	1,646		$	—
Unproved property costs		54,111			20,960
Oilfield inventories		2,786			1,368
Furniture and fixtures		3,085			2,368

		61,628			24,696
Accumulated depletion, impairment and depreciation		(1,387	)		(1,159	)

	$	60,241		$	23,537

Properties and equipment are stated at cost less accumulated depletion, depreciation 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.

We follow the successful efforts method of accounting for our oil and gas properties. Under this method, exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense. During the year ended December 31, 2008, we charged to exploration expense $10.8 million of exploratory well costs associated with the Harvest Hunter #1. 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. Depletion expense, which was all attributable to the Monument Butte project, for the year ended December 31, 2009, was $0.03 million ($6.59 per equivalent barrel).

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

Proved oil and gas properties are reviewed for impairment at a level 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. No impairment of proved oil and gas properties was required in 2009.

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 developed reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved leaseholds, are depleted using the unit-of-production method

S-9

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, including oilfield inventories, consist of $3.1 million for West Bay, $36.4 million for Mesaverde, $2.0 million for the Budong-Budong production sharing contract (“Budong PSC”), $6.9 million for the Dussafu Marin exploration production sharing contract (“Dussafu PSC”), $3.8 million for the Oman exploration and production sharing agreement (“Block 64 EPSA”), $3.0 million for WAB-21, and $1.7 million for other projects.

Depreciation of furniture and fixtures is computed using the straight-line method with depreciation rates based upon the estimated useful life of the property, generally 5 years. Leasehold improvements are depreciated over the life of the applicable lease. Depreciation expense was $0.4 million, $0.2 million and $0.4 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Reserves

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. In January 2010, the Financial Accounting Standards Board (“FASB”) issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Such a change is accounted for prospectively under the authoritative accounting guidance. Comparative disclosures applying the new for periods before the adoption of the FASB’s final rule are not required.

The adoption of the FASB’s final rule on December 31, 2009 impacted our financial statements and other disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009, as follows:

•

All oil and gas reserves volumes presented as of and for the year ended December 31, 2009 were prepared using the updated reserves rules and are not on a basis comparable with prior periods. The change in comparability occurred because the FASB’s final rule requires the use of the unweighted 12-month average of the first-day-of-the-month reference price for the prior twelve month period and permits the use of reliable technologies to support reserve estimates. Under the previous reserve estimation rules, which are no longer in effect, our reserves would have been calculated using end of period prices.

•

The impairment review of our proved oil and gas properties used undiscounted estimated future net cash flows models for our estimated proved developed reserves which were calculated using the FASB’s final rule.

•

We historically have applied a policy of using our year-end proved reserves to calculate our fourth quarter depletion rate. As a result, the estimate of proved reserves for determining our deletion rate and resulting expense for the fourth quarter of 2009 is not on a basis comparable to the prior quarters of prior years.

The impact of the adoption of the FASB’s final rule on our financial statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.

S-10

forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

Asset Retirement Liability

The accounting for asset retirement obligations standard requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. No wells were abandoned in the year ended December 31, 2009. Changes in asset retirement obligations during the year ended December 31, 2009 were as follows (in thousands):


	December 31,
	2009
Asset retirement obligations beginning of period	$	—
Liabilities recorded during the period		50
Liabilities settled during the period		—
Revisions in estimated cash flows		—
Accretion expense		—

Asset retirement obligations end of period	$	50

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.

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.

Noncontrolling Interests

We adopted the accounting standard for noncontrolling interests in consolidated financial statements as of January 1, 2009. This standard establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. This standard also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owner. The retrospective adoption of this standard impacted the presentation of our consolidated financial position, results of operations and cash flows.

New Accounting Pronouncements

S-11

In June 2009, the FASB issued an accounting standard that codifies and modifies the hierarchy of generally accepted accounting principles. This standard is the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This standard superseded all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in this standard is now nonauthoritative. This standard is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of this standard did not have an impact on our consolidated financial position, results of operations or cash flows.

In December 2009, the FASB issued its final updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure requirements of Extractive Industries – Oil and Gas (Topic 932) with the requirements in the SEC’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and is effective for the year ended December 31, 2009. We have complied with the disclosure requirements in our Annual Report on Form 10-K for the year ended December 31, 2009.

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 2008 have been reclassified to conform to the 2009 financial statement presentation.

Note 2 — Long-Term Debt and Liquidity

In November 2006, Harvest Vinccler entered into a three-year term loan with a Venezuelan bank to pay the SENIAT, the Venezuelan income tax authority, income tax assessments and related interest, refinance a portion of a 105 million Venezuela Bolivar (“Bolivar”) loan and to fund operating requirements. The loan was collateralized by a $6.8 million deposit plus interest in a U.S. bank. On July 9, 2008, the loan was repaid in full and the cash collateral returned to us. We have no other debt obligations.

We have incurred $2.8 million in costs related to ongoing negotiations for a future financing. If successful, these costs will be amortized over the life of the financial instrument.

Liquidity — Based on our cash balance of $32.3 million at December 31, 2009, we will be required to raise additional funds in order to fund our future operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration projects and to a lesser extent general and administrative costs. Currently, our primary source of cash is dividends from Petrodelta. However, there is no certainty that

S-12

Petrodelta will pay dividends in 2010 or 2011. Our lack of cash flow and the unpredictability of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance adequate financing can be raised. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, exploration of our properties worldwide, and cost reductions. In addition, we could delay discretionary capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, if necessary. There can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.

Note 3 — Commitments and Contingencies

We have employment contracts with seven 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, outplacement services 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, 2010.

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 $10,000 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 $19,000 per month. In April 2009, we signed a two-year lease for office space in Indonesia for approximately $5,000 per month. In September 2009, we signed a two-year lease for office space in Oman for approximately $5,000 per month. In November 2009, we signed a one-year lease for office space in London for approximately $24,000 per month. We do not have any long-term contractual commitments for any of our projects.

Uracoa Municipality Tax Assessments. Our Venezuelan subsidiary, 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.

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.

•

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.

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. 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 accepted. Throughout 2009, the General Attorney Office and Harvest-Vinccler agreed several times to resuspend the case while the Finance Minister and the SENIAT confirmed their acceptance to the proposed settlement. On December 30, 2009, Harvest Vinccler settled the case for 3.1 million Bolivars (approximately $1.4 million) for penalties and interest and closed the case with the SENIAT’s concurrence. As a result of the settlement, in December 2009, Harvest Vinccler reversed $0.9 million of accrued penalties and interest previously accrued based on notices received from the SENIAT.

S-14

Note 4 — Taxes

Taxes Other Than on Income

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


	2009		2008			2007
Franchise taxes	$	182	$	(951	)	$	166
Severance taxes		11		—			—
Payroll and other taxes		833		745			257

	$	1,026	$	(206	)	$	423

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

Taxes on Income

The tax effects of significant items comprising our net deferred income taxes as of December 31, 2009, are as follows (in thousands):


	2009			2008
Deferred tax assets:
Operating loss carryforwards	$	15,599		$	7,547
Dry hole costs		—			4,060
Stock options		1,426			1,680
Valuation allowance		(17,025	)		(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 $5.9 million at our Netherlands Antilles subsidiary, HNR Energia B.V. The full amount would be subject to United States income tax if distributed to us.

The valuation allowance increased by $9.2 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. Management anticipates that additional losses will be generated and that it is more likely than not that they will not be realized through future taxable income. Management further anticipates that any unremitted foreign earnings will be reinvested outside of the U.S.

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


	2009			2008			2007
Income (loss) before income taxes
United States	$	(22,357	)	$	(34,760	)	$	(17,786	)
Foreign		(7,522	)		(14,326	)		48,700

Total	$	(29,879	)	$	(49,086	)	$	30,914

S-15

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


	2009		2008			2007
Current:
United States	$	39	$	(128	)	$	400
Foreign		1,143		153			5,912

		1,182		25			6,312
Deferred:
Foreign		—		—			—

	$	1,182	$	25		$	6,312

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


	2009			2008			2007
Computed tax expense (benefit) at the statutory rate	$	(10,458	)	$	(17,180	)	$	10,820
Effect of foreign source income and rate differentials on foreign income		3,775			5,167			(11,140	)
Change in valuation allowance		9,184			6,059			1,085
Tax on undistributed earnings		—			5,446			—
Deemed income inclusion under Subpart F		—			968			12,942
Net operating loss utilization		—			—			(7,306	)
Foreign disregarded entities		21			(268	)		—
Return to accrual adjustment		(1,093	)		(166	)		—
Other		(247	)		(1	)		(89	)

Total income tax expense	$	1,182		$	25		$	6,312

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

At December 31, 2009, we had, for federal income tax purposes, operating loss carryforwards of approximately $44.4 million, expiring in the years 2026 through 2029.

Accounting for Uncertainty in Income Taxes

Effective January 1, 2007, we adopted the interpretation for accounting for uncertainty in income taxes which was an interpretation of the accounting standard accounting for income taxes. This interpretation created a single model to address accounting for uncertainty in tax positions. This interpretation 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.

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 prior to 2006. To date, the Internal Revenue Service (“IRS”) has not performed an examination of our U.S. income tax returns for 2006 through 2008.

We do not have any unrecognized tax benefits or loss contingencies.

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

S-16

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. 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 (as amended). The 2004 Plan also permits the granting of performance awards to eligible employees and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time of at least one year. Performance awards granted under the Plan may not exceed $5.0 million in a calendar year and may not exceed $2.5 million to any one individual in a calendar year. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become exercisable.

In July 2001, our shareholders approved the 2001 Long Term Stock Incentive Plan (the “2001 Plan”). The 2001 Plan provides for grants of options to purchase up to 1,697,000 shares of our common stock in the form of Incentive Stock Options and Non-Qualified Stock Options to eligible participants including employees of our company or subsidiaries, directors, consultants and other key persons. The exercise price of stock options granted under the 2001 Plan must be no less than the fair market value of our common stock on the date of grant. No officer may be granted more than 500,000 options during any one fiscal year, as adjusted for any changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date.

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

S-17

A summary of the status of our stock option plans as of December 31, 2009, 2008 and 2007 and changes during the years ending on those dates is presented below (shares in thousands):


	2009						2008						2007
	Weighted						Weighted						Weighted
	Average						Average						Average
	Exercise						Exercise						Exercise
	Price			Shares			Price			Shares			Price			Shares
Outstanding at beginning of the year:	$	8.54			3,783		$	7.80			4,172		$	7.70			4,123
Options granted		4.60			118			10.28			444			9.63			866
Options exercised		(2.11	)		(205	)		(2.86	)		(548	)		(4.73	)		(397	)
Options cancelled		(2.95	)		(333	)		(11.34	)		(285	)		(13.49	)		(420	)

Outstanding at end of the year		9.35			3,363			8.54			3,783			7.80			4,172

Exercisable at end of the year		9.09			2,066			7.23			2,147			5.87			2,372

Significant option groups outstanding at December 31, 2009 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 12/31/09		Life		Price		Value		at 12/31/09		Price		Value
$1.55 - $2.07		336		0.6	$	1.71	$	1,205		336	$	1.71	$	1,205
$4.60 - $7.10		274		4.2		5.31		107		156		5.86		25
$8.78 - $10.91		2,167		5.0		10.02		—		1,001		9.75		—
$12.25 - $13.90		586		3.6		13.13		—		573		13.15		—

		3,363					$	1,312		2,066			$	1,230

The aggregate intrinsic value in the preceding table represents the total pretax intrinsic value based on our closing stock price of $5.29 of December 31, 2009, which would have been received by the option holders had all option holders exercised their options as of that date.

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:	2009			2008			2007
Weighted average fair value	$	4.60		$	5.85		$	4.67
Weighted averaged expected life		7			7			7
Valuation assumptions:
Expected volatility		68.9	%		46.6-49.7	%		47.7-48.7	%
Risk-free interest rate		3.5	%		3.0-3.9	%		4.5%-4.6	%
Expected dividend yield		0	%		0	%		0	%
Expected annual forfeitures		3	%		3	%		3	%

The Black-Scholes option pricing model was developed for use in estimating the value of traded options that have no vesting restrictions and are fully transferable. In addition, option pricing models require the input of highly subjective assumptions, including the expected stock price volatility and expected life. The expected volatility is based on historical volatilities of our stock. Historical data is used to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options are expected to be outstanding. The risk-free rate for the periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant.

A summary of our nonvested options as of December 31, 2009, and changes during the year ended December 31, 2009, is presented below (shares in thousands):

S-18


				Weighted-Average
	Nonvested			Grant-Date
	Options			Fair Value
Nonvested at January 1, 2009		1,979		$	5.80
Granted		118			3.13
Vested		(567	)		(5.82	)
Forfeited		(10	)		(5.64	)

Nonvested at December 31, 2009		1,520			5.59

As of December 31, 2009, there was $3.7 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 four years. The total fair value of shares vested during the years ended December 31, 2009, 2008 and 2007 was $2.6 million, $4.0 million and $4.5 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, 2009, a total of 360,000 options issued outside of the plans were outstanding and 136,666 options were exercisable.

Stock options of 0.2 million were exercised in the year ended December 31, 2009 resulting in cash proceeds of $0.4 million. Stock options of 0.5 million were exercised in the year ended December 31, 2008 resulting in cash proceeds of $1.6 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. Oil and gas sales for 2007 is the recognition of the deferred revenue recorded by Harvest Vinccler for 2005 and first quarter 2006 deliveries pending clarification on the calculation of crude prices under the Transitory Agreement (see Note 1 – Organization and Summary of Significant Accounting Policies, Revenue Recognition). Operations included under the heading “United States and Other” include U.S. operations, 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.

S-19


	2009			2008			2007
				(in thousands)
Segment Revenues
Oil and gas sales:
United States and other	$	181		$	—		$	—
Venezuela		—			—			11,217

Total oil and gas sales		181			—			11,217

Segment Income (Loss) Attributable to Harvest
Venezuela		39,696			33,020			79,878
Indonesia		(5,124	)		(8,966	)		(7	)
United States and other		(37,679	)		(45,518	)		(19,753	)

Net income (loss) attributable to Harvest	$	(3,107	)	$	(21,464	)	$	60,118


	December 31,
	2009			2008
	(in thousands)
Operating Segment Assets
Venezuela	$	249,484		$	231,755
Indonesia		5,893			1,556
United States and other		113,555			152,184

		368,932			385,495
Intersegment eliminations		(20,153	)		(23,229	)

	$	348,779		$	362,266

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 Petrodelta’s business plan as set forth in the Conversion Contract. Under the Conversion Contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. On February 4, 2010, Petrodelta’s board of directors endorsed a capital budget of $205 million for Petrodelta’s 2010 business plan.

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.

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. 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. 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 $0.9 million and $56.4 million of expense for the amended Windfall Profits Tax during the years ended December 31, 2009 and 2008, respectively.

S-20

During the second quarter of 2009, PDVSA completed an actuarial study for their pension and retirement plan. This pension and retirement plan covers all PDVSA employees and mixed companies employees. Petrodelta is not required to reimburse the pension costs to PDVSA until PDVSA pays the pension benefits to employees. In May 2009, upon completion of the review of this actuarial study, PDVSA sent a statement to Petrodelta for its respective costs associated with the pension and retirement plan. Petrodelta recorded additional pension expense of $15.6 million ($5.0 million net to our 32 percent interest) in the three month period ended June 30, 2009 based on the statement received. The pension adjustment resulted from the completion of the first full actuary study by PDVSA related to its employees that provide services to the mixed companies and a refinement of management’s assumptions related to credit for past service costs covering the period from January 2008, when the Harvest Vinccler employees were migrated to PDVSA payroll, through May 2009. At this time PDVSA did not have specific benefit information related to each individual mixed company and thus allocated the pension obligation to each mixed company assuming that the employees serving each of the mixed companies had the same characteristics. The pension adjustment was a change in Petrodelta management’s estimate based on the new information provided by PDVSA.

During the fourth quarter of 2009, PDVSA completed an updated actuarial study as of December 31, 2009. This study was based on a further refinement of assumptions for each of the mixed companies, including Petrodelta and a new allocation methodology as PDVSA gathered during 2009 all relevant information for each of the mixed companies. The revised pension obligation allocated to Petrodelta resulted in a decrease of $8.4 million ($2.7 million net to our 32 percent interest) to the pension and retirement plan costs as compared to those previously recorded to Petrodelta in May 2009. This change in management’s estimate related to the pension and retirement plan costs was recorded in December 2009. Pension costs at December 31, 2009 reasonably reflect Petrodelta’s employee demographic and plan conditions. The additional pension cost is not tax deductible until future periods when the pension is settled in cash. The provision for the pension plan is subject to future revisions, both upwards and downwards, based on changes in assumptions, the terms of the relevant plans, the allocation methodology or other prospective amendments or changes as determined by PDVSA.

In June 2009, CVP issued instructions to Petrodelta to set up a reserve within the equity section of the balance sheet for deferred tax assets. Petrodelta’s bylaws state that Petrodelta’s shareholders are required to approve the setting up of special reserves. In August 2009, Petrodelta’s board of directors approved the setting up of the reserve. Although this reserve has no effect on Petrodelta’s financial position, results of operation or cash flows, it has the effect of limiting future dividends to net income adjusted for deferred tax assets. Past dividends received from Petrodelta represented Petrodelta’s net income as reported under IFRS. However, Article 307 of the Venezuelan Commerce Code states that distributions and payments of dividends must meet two conditions: 1) the retained earnings of the entity should be liquid and realizable, and 2) the entity has enough cash to pay and distribute the dividend. Deferred taxes are not liquid or realizable as cash until the items giving rise to the deferred tax are recognized in the entity’s tax return. Therefore, CVP’s instructions are to ensure future dividends are declared and paid as stated under Venezuelan law. Article 307 also states that shareholders are not obligated to restore dividends that have been distributed in good faith according to the entity’s balances and sets the statute of limitations for an entity to claim restoration of dividends at five years.

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 (“OHL”) to contribute two percent of their gross revenue generated in Venezuela from activities specified in the OHL. The contribution is based on the previous year’s gross revenue and is due the following year. LOCTI requires that each company file a separate declaration stating how much has been contributed; however, waivers have been granted in the past to allow PDVSA to file a declaration on a consolidated basis covering all of its and its consolidating entities liabilities. Since Petrodelta expects PDVSA to continue requesting and receiving waivers, Petrodelta has not accrued a liability to LOCTI for the year ended December 31, 2009. The potential exposure to LOCTI for the year ended December 31, 2009 is $9.5 million, $4.8 million net of tax ($1.5 million net to our 32 percent interest).

Petrodelta’s reporting and functional currency is the U.S. Dollar. 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 years ended December 31, 2009 and 2008 include net income from unconsolidated equity affiliates for Petrodelta on a current basis. 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, 2009, 2008 and 2007, and for the years ended December 31, 2009, 2008 and 2007:

S-21


	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Barrels of oil sold		7,835			5,505			5,374
MCF of gas sold		4,397			10,700			13,456
Total Boe		8,568			7,288			7,616

Average price per barrel	$	57.62		$	83.22		$	58.61
Average price per mcf	$	1.54		$	1.54		$	1.54

Revenues:
Oil sales	$	451,473		$	458,113		$	314,928
Gas sales		6,778			16,506			20,789
Royalty		(156,799	)		(168,790	)		(114,847	)

		301,452			305,829			220,870

Expenses:
Operating expenses		48,311			52,946			21,352
Workovers		—			24,663			2,400
Depletion, depreciation and amortization		33,666			25,509			18,549
General and administrative		9,746			5,974			19,880
Windfall profits tax		882			56,377			—
Taxes other than on income		—			—			2,747

		92,605			165,469			64,928


Income from Operations		208,847			140,360			155,942
Interest expense		(3,617	)		(2,329	)		—

Income before Income Tax		205,230			138,031			155,942

Current income tax expense		105,868			69,374			85,849
Deferred income tax benefit		(43,922	)		(52,560	)		(21,348	)

Net Income		143,284			121,217			91,441
Adjustment to reconcile to reported Net Income from Unconsolidated Equity Affiliate:
Deferred income tax benefit		38,516			34,827			12,343

Net Income Equity Affiliate		104,768			86,390			79,098
Equity interest in unconsolidated equity affiliate		40	%		40	%		40	%

Income before amortization of excess basis in equity affiliate		41,907			34,556			31,639
Amortization of excess basis in equity affiliate		(1,356	)		(1,155	)		(2,530	)
Conform depletion expense to GAAP		183			2,533			—

Net income from unconsolidated equity affiliate	$	40,734		$	35,934		$	29,109


	December 31,		December 31,
	2009		2008
	(in thousands)
Current assets	$	404,825	$	311,017
Property and equipment		265,442		211,760
Other assets		141,245		97,323
Current liabilities		345,812		260,234
Other liabilities		33,600		19,174
Net equity		432,100		340,692

S-22

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, 2009, 2008 and 2007, respectively. Summarized financial information for Fusion follows:


	Year Ended December 31,
	2009			2008			2007
				(in thousands)
Operating Revenues	$	11,089		$	13,063		$	7,392
Net Income (Loss)	$	(4,798	)	$	(1,290	)	$	527
Equity interest in unconsolidated equity affiliate		49	%		49	%		45	%

Net income (loss) from unconsolidated equity affiliate		(2,351	)		(632	)		237
Amortization of fair value of intangibles		(995	)		(726	)		(656	)
Impairment of investment		(1,631	)		—			—

Net loss from unconsolidated equity affiliate	$	(4,977	)	$	(1,358	)	$	(419	)


	December 31,		December, 31
	2009		2008
Current assets	$	2,726	$	7,864
Total assets		30,205		30,633
Current liabilities		8,024		7,294
Total liabilities		12,242		8,281

Approximately 29 percent, 26 percent and 7 percent of Fusion’s revenue for the years ended December 31, 2009, 2008 and 2007, respectively, was earned from Harvest or equity affiliates.

On April 9, 2009, we entered into a service agreement with Fusion whereby we prepaid $1.5 million for certain services to be performed in connection with certain projects as defined in the service agreement. The services are to be performed in accordance with the existing consulting agreement. Upon written notice to Fusion, the projects and types of services can be amended. The unapplied portion of the prepayment advance bears interest at an annual rate of 12 percent which will be added to the prepayment advance balance and used to offset future service invoices from Fusion. Services rendered have been applied against the prepayment, and as of December 31, 2009, the balance for prepaid services was approximately $1.0 million.

As of December 31, 2009, we updated the review for impairment of our minority equity investment in Fusion. In preparing this update, future net cash flows prepared by Fusion based on different business opportunities that Fusion is currently pursuing were updated for current activities. These business opportunities were weighted with a probability of success. Based on these cash flow projections and considering Fusion’s current liquidity, we concluded that the potential business opportunities did not support Fusion’s on-going cash flow requirements; and therefore, we recorded a $1.6 million charge to fully impair the carrying value of our equity investment in Fusion at December 31, 2009.

Note 8 – United States

S-23

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. The AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana, including state waters. 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. The private third party contributed these 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 agreed to fund the first $20 million of new lease acquisitions, geological and geophysical studies, seismic reprocessing and drilling costs. At June 30, 2009, we had met the $20 million funding obligation under the terms of the AMI. All costs incurred after June 30, 2009 are being shared by the parties in proportion to their working interests as defined in the AMI. In August 2009, the AMI became a three party arrangement when the private third party restructured and assigned a portion of its interest to one of its affiliates.

The private third 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. Although several additional potential prospects had been screened and evaluated within the AMI since its inception, we had not pursued leasing or drilling on any new projects within the AMI as of December 31, 2009. On January 29, 2010, we entered into an agreement with one of the private third parties in our AMI for an option to participate in a new project (see Note 14 – Subsequent Events).

Starks Project

West Bay Project

The AMI participants are currently continuing to evaluate the leads and prospects to determine priorities and drilling plans for the West Bay project and have identified the likely initial drilling prospect. Land, regulatory, and surface access preparations are currently in progress focused on taking the initial drilling prospect to drill-ready status. The West Bay project represents $3.1 million and $2.9 million of unproved oil and gas properties on our December 31, 2009 and 2008 balance sheets, respectively.

Western United States – Antelope

S-24

spud date of the Bar F. Since payment was not received prior to the Bar F spud date, our interest in the Antelope prospect was increased to 60 percent, with the incremental 10 percent working interest being earned by drilling and completing the Bar F. The note receivable remains outstanding and will be collected through sales revenues taken from a portion of the private third party’s net revenue from the Bar F provided the Bar F is commercial.

Activities are in progress on two separate projects on the Antelope prospect in Duchesne County, Utah.

Mesaverde

Operational activities during 2009 on the Mesaverde project focused on continuing leasing activities on private, Allottee, and tribal land, and surveying, preliminary engineering, permitting preparations, and conducting drilling operations on a deep natural gas test well (the Bar F) that commenced drilling on June 15, 2009. The Bar F was permitted to 18,000 feet. The Bar F was drilled to a total depth of 17,566 feet and an extended production test of multiple potential reservoir horizons is now in progress. To date, testing has been focused on the evaluation of the natural gas potential of the Mesaverde tight gas reservoir over a prospective interval from 14,000 to 17,400 feet. Completion activities consisted of hydraulic fracturing of eight separate reservoir intervals in the Mesaverde and multiple extended flow tests of the individual fractured intervals, along with a flow test of the commingled eight intervals. While the results to date have not definitively determined the commerciality of a stand-alone development of the Mesaverde, we believe these results indicate progress toward that determination and that the Mesaverde reservoir remains potentially prospective over a portion of our land position. The Mesaverde project represents $36.4 million and $8.3 million of unproved oil and gas properties on our December 31, 2009 and 2008 balance sheets, respectively.

Monument Butte

Operational activities during 2009 on the Monument Butte project focused on resolution of forced pooling issues with non-consenting interests, negotiations and finalization of an agreement with the operator for the joint drilling operations. As of December 31, 2009, five wells had been drilled: two of the five wells were on production, and three wells waiting on completion. These three wells were placed on production in the first quarter 2010. The three additional wells were drilled by the end of February 2010: two wells had been placed on production and the one remaining well was waiting on completion operations. The Monument Butte project represents $1.6 million of proved oil and gas properties and $0.3 million of unproved oil and gas properties on our December 31, 2009 and 2008 balance sheets, respectively.

Note 9 – Indonesia

In 2008, we acquired a 47 percent interest in the Budong-Budong Production Sharing Contract (“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. The commitment is comprised of $6.5 million for the acquisition of seismic and $10.7 million for the drilling of the first two exploratory wells. After the commitment of each component is met, all subsequent costs will be shared by the parties in proportion to their ownership interests. The $6.5 million carry obligation for the 2-D seismic acquisition was met in December 2008. 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 a maximum of $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

S-25

with an option to become operator if approved by BP Migas, Indonesia’s oil and gas regulatory authority, in the subsequent development and production phase.

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. 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, operational activities during 2009 focused on the interpretation of 650 kilometers of 2-D seismic and well planning. Two drill sites have been selected. Currently, the locations for the two test wells are being constructed and the rig and ancillary equipment is being mobilized to the area. It is expected that the first of two exploration wells will spud early in the second quarter of 2010. 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. The Budong PSC represents $2.0 million and $0.2 million, respectively, of unproved oil and gas properties on our December 30, 2009 and 2008 balance sheets.

Note 10 – Gabon

We are the operator of the Dussafu Marin Permit offshore Gabon in West Africa (“Dussafu PSC”) with a 66.667 percent interest in 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.

Note 11 – Oman

On April 11, 2009, we signed an Exploration and Production Sharing Agreement (“EPSA”) with Oman for the Al Ghubar / Qarn Alam license. We have a 100 percent working interest in Block 64 EPSA during the exploration phase. Oman Oil Company has the option to back-in to up to a 20 percent interest in Block 64 EPSA after the discovery of gas.

Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate which the Oman Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). PDO will continue to produce oil from several fields within Block 64 EPSA area. The 3,867 square kilometer (955,600 acres) block is located in the gas and condensate rich Ghaba Salt Basin in close proximity to the Barik, Saih Rawl and Saih Nihayda gas and condensate fields. We have an obligation to drill two wells over a three year period with a funding commitment of $22.0 million. Current activities include the compilation of existing data, over two prospect areas of approximately 1,000 square kilometers and geological studies to determine drillable prospects. Well planning is expected to commence in 2010 for exploration

S-26

drilling in 2011. During the year ended December 31, 2009, we incurred $1.6 million for costs associated with negotiating Block 64 EPSA and $2.2 million for costs associated with signing the license, including signature bonus and data compilation. The Block 64 EPSA represents $3.8 million of unproved oil and gas properties on our December 31, 2009 balance sheet.

Note 12 — China

In December 1996, we acquired 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. 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, 2011. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist. Recently, Vietnam, along with the company that is the party to the agreement with Vietnam, announced plans for exploration drilling during 2010. While no assurance can be given, we believe this announcement may provide some resolution with the border disputes, although we do not know in what manner any resolution might appear. WAB-21 represents $3.0 million of unproved oil and gas properties on our December 31, 2009 and 2008 balance sheets, respectively.

Note 13 — Earnings Per Share

Basic earnings per common share (“EPS”) are computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. The weighted average number of common shares outstanding for computing basic EPS was 33.1 million, 34.1 million and 36.5 million for the years ended December 31, 2009, 2008 and 2007, 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 33.1 million, 34.1 million and 37.9 million for the years ended December 31, 2009, 2008 and 2007, respectively.

An aggregate of 3.7 million options were excluded from earnings per share calculations because there exercise price exceeded the average price for the year ended December 31, 2009. An aggregate of 4.0 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 year ended December 31, 2007, 1.1 million was excluded from the earnings per share calculations because their exercise price exceeded the average price.

Note 14 – Subsequent Events

We conducted our subsequent events review up through the date of the issuance of this Annual Report on Form 10-K.

On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement which establishes new exchange rates for the Bolivar/U.S. Dollar currencies that will enter into force on January 11, 2010. Each exchange rate will be applied to foreign currency sales and purchases conducted through the Foreign Currency Administration Commission (“CADIVI”), in the cases expressly provided in the Exchange Agreement. In this regard, the exchange rates established in the Agreement are: 2.60 Bolivars per U.S. Dollar and 4.30 Bolivars per U. S. Dollar. The 2.60 Bolivar exchange rate applies to the food, health, medical and technology sectors. The 4.30 Bolivar exchange rate applies to all other sectors not expressly established by the 2.60 Bolivar exchange rate. The U.S. Dollar is the functional reporting currency for both Petrodelta and Harvest Vinccler.

S-27

On February 17, 2010, we closed an offering of $32 million in aggregate principal amount of our 8.25 percent senior convertible notes due 2013, which resulted in net proceeds to us, after deducting underwriting discounts, commissions and estimated offering expenses, of approximately $30 million.

S-28

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

Quarterly Financial Data (unaudited)

Summarized quarterly financial data is as follows:


	Quarter Ended
	March 31			June 30			September 30			December 31
	(amounts in thousands, except per share data)
Year ended December 31, 2009
Revenues	$	—		$	—		$	—		$	181
Expenses		(7,825	)		(10,217	)		(7,286	)		(5,812	)
Non-operating income		331			296			224			229

Loss from consolidated companies before income taxes		(7,494	)		(9,921	)		(7,062	)		(5,402	)
Income tax expense		889			147			109			37

Loss from consolidated companies		(8,383	)		(10,068	)		(7,171	)		(5,439	)
Net income from unconsolidated equity affiliates		4,410			7,476			9,890			13,981

Net income (loss)		(3,973	)		(2,592	)		2,719			8,542
Less: Net income attributable to noncontrolling interest		803			1,597			1,936			3,467

Net income (loss) attributable to Harvest	$	(4,776	)	$	(4,189	)	$	783		$	5,075


Net income (loss) attributable to Harvest per common share:
Basic	$	(0.15	)	$	(0.13	)	$	0.02		$	0.15

Diluted	$	(0.15	)	$	(0.13	)	$	0.02		$	0.15


	Quarter Ended
	March 31			June 30			September 30			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 (expense)		2,002			1,582			1,100			670

Loss from consolidated companies before income taxes		(5,867	)		(7,948	)		(9,521	)		(25,750	)
Income tax expense (benefit)		64			37			(20	)		(56	)

Loss from consolidated companies		(5,931	)		(7,985	)		(9,501	)		(25,694	)
Net income from unconsolidated equity affiliates		8,809			9,409			5,309			11,049

Net income (loss)		2,878			1,424			(4,192	)		(14,645	)
Less: Net income attributable to noncontrolling interest		1,673			2,057			1,045			2,154

Net income (loss) attributable to Harvest	$	1,205		$	(633	)	$	(5,237	)	$	(16,799	)


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

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

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. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

S-29


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


							United States
	Oman		Gabon		Indonesia		and Other		Total
Year Ended December 31, 2009
Acquisition costs	$	3,757	$	941	$	1,800	$	28,170	$	34,668
Exploration costs		459		225		1,793		2,563		5,040
Development costs		—		—		—		1,547		1,547

	$	4,216	$	1,166	$	3,593	$	32,280	$	41,255


Year Ended December 31, 2008
Acquisition costs	$	—	$	5,792	$	71	$	13,302	$	19,165
Exploration costs		—		3,016		7,647		14,020		24,683

	$	—	$	8,808	$	7,718	$	27,322	$	43,848


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

	$	—	$	136	$	168	$	364	$	668


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


							United States
	Oman		Gabon		Indonesia		and Other			Total
Year Ended December 31, 2009
Proved property costs	$	—	$	—	$	—	$	1,646		$	1,646
Unproved property costs		3,757		6,869		670		42,815			54,111
Oilfield Inventories		—		—		1,369		1,417			2,786
Less accumulated depletion		—		—		—		(29	)		(29	)

	$	3,757	$	6,869	$	2,039	$	45,849		$	58,514


Year Ended December 31, 2008
Unproved property costs	$	—	$	5,927	$	239	$	16,162		$	22,328


Year Ended December 31, 2007
Unproved property costs	$	—	$	136	$	168	$	2,859		$	3,163

We regularly evaluate our unproved properties to determine whether impairment has occurred. We have excluded from amortization our interest in unproved properties and the cost of uncompleted exploratory activities. The principal portion of such costs, excluding those related the acquisition of WAB-21, are expected to be included in amortizable costs during the next two to three years. The ultimate timing of when the costs related to the acquisition of WAB-21 will be included in amortizable costs is uncertain.

Unproved property costs at December 31, 2009 consisted of the following by year incurred (in thousands):


	Total		2009		2008		2007		Prior
Property acquisition costs	$	56,897	$	34,569	$	19,165	$	263	$	2,900

S-30


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


	United States
Year Ended December 31, 2009
Revenues:
Oil and natural gas revenues	$	181

Expenses:
Operating, selling, and distribution expenses and taxes other than on income		15
Depletion		29
Income Tax expense		—

Total expenses		44

Results of operations from oil and natural gas producing activities	$	137


TABLE IV	—	Quantities of Oil and Natural Gas Reserves

Estimating oil and gas reserves is a very complex process requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may change substantially over time as a result of numerous factors such as production history, additional development activity and continual reassessment of the viability of production under various economic and political conditions. Consequently, material upward or downward revisions to existing reserve estimates may occur from time to time; although, every reasonable efforts is made to ensure that reported results are the most accurate assessment available. We ensure that the data provided to our external independent experts, and their interpretation of that data, corresponds with our development plans and management’s assessment of each reservoir. The significance of subjective decisions required and variances in available data make estimates generally less precise than other estimates presented in connection with financial statement disclosures.

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, prior period reserves were not restated. For the United States, the primary impacts of the SEC’s final rule on our reserve estimates include:

	•		The use of the unweighted 12-month average of the first-day-of-the-month reference price of $48.21 per barrel for oil compared to year-end reference price of $61.73 per barrel, and

	•		The use of the unweighted 12-month average of the first-day-of-the-month reference price of $3.31 per Mcf for gas compared to year-end reference price of $4.25 per Mcf.

The impact of the adoption of the SEC’s final rule on our financial statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.

S-31

by the Society of Petroleum Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

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, 2009, 2008 and 2007, TABLE IV — Quantities of Oil and Natural Gas Reserves.

The table shown below represents our interests in the United States. All of our other properties are unproved and have no associated reserves. There were no reserves prior to December 31, 2009 and all amounts are reflected as discoveries. During 2009, we identified and approved the development of eight locations in the Monument Butte project in Utah. At year end 2009, we have drilled and moved to the proved developed category three of these locations. At year end 2009, we have five identified proved undeveloped (“PUD”) locations. All PUD locations have subsequently been converted to proved developed (“PDP”) locations or are scheduled to be converted to PDP locations by the end of the first quarter 2010. These reserves are in a new geographic area for us.


	As of
	December 31, 2009
	Oil		Gas
	(MBbls)		(MMcf)
	(in thousands)
Proved
Developed
United States		131		653

Undeveloped
United States		95		473

Total Proved		226		1,126


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 the accounting standard on disclosures about oil and gas producing activities. 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 an applying the average price during the 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the contract, to the estimated future production of year-end proved reserves. Our average prices used were $48.21 per barrel for oil and $3.31 per Mcf for gas. 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 table shown below represents our net interest at December 31, 2009. This is the first year to report our reserves in the United States, based on the results of Ryder Scott Company L.P.

S-32


	United States
	(in thousands)
December 31, 2009
Future cash inflows from sales of oil and gas	$	14,626
Future production costs		(3,674	)
Future development costs		(1,171	)
Future income tax expenses		(3,147	)

Future net cash flows		6,634
Effect of discounting net cash flows at 10%		(1,911	)

Standardized measure of discounted future net cash flows	$	4,723


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


	United States
Standardized Measure at January 1	$	—
Sales of oil and natural gas, net of related costs		(166	)
Extensions, discoveries and improved recovery, net of future costs		6,978
Net change in income taxes		(2,089	)

Standardized Measure at December 31	$	4,723

S-33

Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Petrodelta S.A. as of December 31, 2009, 2008 and 2007

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, 2009, 2008 and 2007.


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


	Year ended December 31,
	2009		2008		2007
Development costs	$	26,605	$	17,144	$	972
Exploration costs		—		—		—

	$	26,605	$	17,744	$	972


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


	Year ended December 31,
	2009			2008			2007
Proved property costs	$	108,696		$	79,807		$	64,415
Unproved property costs		163			3,036			2,653
Oilfield inventories		10,748			7,892			4,426
Less accumulated depletion and impairment		(27,089	)		(16,966	)		(11,063	)

	$	92,518		$	73,769		$	60,431


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


	Year Ended December 31,
	2009			2008			2007
Revenue:
Oil and natural gas revenues	$	146,640		$	151,878		$	107,429
Royalty		(50,176	)		(54,013	)		(36,751	)

		96,464			97,865			70,678

Expenses:
Operating, selling and distribution expenses and taxes other than on income		15,742			42,876			7,601
Depletion		10,123			5,903			5,746
Income tax expense		35,300			23,530			28,666

Total expenses		61,165			72,309			42,013

Results of operations from oil and natural gas producing activities	$	35,299		$	25,556		$	28,665


TABLE IV –		Quantities of Oil and Natural Gas Reserves

S-34

of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, prior period reserves were not restated. For Petrodelta, the primary impact of the SEC’s final rule on our reserve estimates include:

•

The use of the unweighted 12-month average of the first-day-of-the-month contracted reference price of $56.83 per barrel for oil compared to the year-end contracted reference price of $69.87 per barrel for oil.

Petrodelta is producing from, and continuing to develop, the Petrodelta Fields. Petrodelta has both developed and undeveloped oil and gas reserves identified in all six fields. Petrodelta produces the fields in accordance with a business plan defined by its conversion contract executed in late 2007. Proved Undeveloped (“PUD”) oil and gas reserves are drilled in accordance with Petrodelta’s business plan, but can be revised where drilling results indicate a change is warranted. This was the case when two wells drilled in El Salto in 2009 justified a modification to the El Salto PUD program.

As of year end 2009, Petrodelta has a total of 164 PUD (39,626 Boe) locations identified. Since the implementation of its business plan, Petrodelta has drilled 24 gross wells (2008 nine wells [1,743 Boe] and 2009 15 wells [2,498 Boe]) which have moved to the proved developed producing (“PDP”) category. Of these 24 locations, 17 (3,511 Boe) represent the movements of PUD locations to PDP locations. The other seven new producing wells (731 Boe) were previously classified Probable, Possible or un-defined. All above Boe represent HNR Finance’s interest, net of a 33.33 percent royalty.

All PUD locations are scheduled to be drilled by 2014; however, there are some PUD locations that are scheduled to be drilled in the sixth year after the PUD locations were first identified. Petrodelta has a track record of identifying, executing and converting its PUD locations to PDP locations, and there are special circumstances to account for this drilling delay. Petrodelta commenced drilling operations in the second quarter of 2008; however, shortly thereafter Petrodelta was advised by the Venezuelan government that Petrodelta’s 2009 production target was to be approximately 16,000 barrels of oil per day following the December 17, 2008 Organization of the Petroleum Exporting Countries (“OPEC”) meeting establishing new production quotas. Subsequently, Petrodelta was allowed to produce at capacity to help fulfill other companies’ production shortfalls. Also, PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. As a result, Petrodelta has experienced difficulty in retaining contractors who provide equipment and/or services for Petrodelta’s operations. Inability to retain contractors or to pay them on a timely basis is having an adverse effect on Petrodelta’s ability to carry out its business plan. These events have been outside of the control of Petrodelta. Petrodelta has recently taken specific actions to improve its ability to execute on its established business plan in a timely manner.

In summary, Petrodelta has a demonstrated track record of identifying, executing and converting its PUD locations to PDP locations. PUD locations are expected to be drilled at a similar pace with 27 wells drilled in 2010 and an average 36 wells per year in 2011 through 2014.

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

S-35


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

As of December 31, 2009
Proved Reserves at January 1, 2009		42,809			(8,561	)		34,248
Revisions		(875	)		175			(700	)
Extensions		7,574			(1,515	)		6,059
Production		(2,089	)		418			(1,671	)

Proved Reserves at end of the year		47,419			(9,483	)		37,936


As of December 31, 2009 Proved
Developed		14,242			(2,848	)		11,394
Undeveloped		33,177			(6,635	)		26,542

Total Proved		47,419			(9,483	)		37,936


As of December 31, 2008
Proved Reserves at January 1, 2008		47,261			(9,452	)		37,809
Revisions		(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

As of 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)

As of December 31, 2009
Proved Reserves at January 1, 2009	67,804		(13,561	)	54,243
Revisions	(5,862	)	1,172		(4,690	)
Extensions	1,941		(388	)	1,553
Production	(1,173	)	235		(938	)

Proved Reserves at end of the year	62,710		(12,542	)	50,168

S-36


				Minority
				Interest in			32%
	HNR Finance			Venezuela			Net Total
				(in thousands)
As of December 31, 2009 Proved
Developed		24,015			(4,803	)		19,212
Undeveloped		38,695			(7,739	)		30,956

Total Proved		62,710			(12,542	)		50,168


As of 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	)		24,134

As of 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


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

Future cash inflows were estimated by an applying the average price during the 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the contract, to the estimated future production of year-end proved reserves. Our average prices used were $56.83 per barrel for oil and $1.54 per Mcf for gas. 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 table shown below represents HNR Finance’s net interest in Petrodelta.

S-37


				Minority
				Interest in
	HNR Finance			Venezuela			Net Total
				(in thousands)
December 31, 2009
Future cash inflows from sales of oil and gas	$	2,772,840		$	(554,568	)	$	2,218,272
Future production costs		(630,225	)		126,045			(504,180	)
Future development costs		(282,306	)		56,461			(225,845	)
Future income tax expenses		(886,622	)		177,324			(709,298	)

Future net cash flows		973,687			(194,738	)		778,949
Effect of discounting net cash flows at 10%		(473,317	)		94,663			(378,654	)

Standardized measure of discounted future net cash flows	$	500,370		$	(100,075	)	$	400,295


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

TABLE VI – Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (in thousands):


	Net Venezuela
	2009			2008
Standardized Measure at January 1	$	111,361		$	523,378
Sales of oil and natural gas, net of related costs		(80,725	)		(54,988	)
Revisions to estimates of proved reserves
Net changes in prices, development and production costs		408,054			(673,320	)
Quantities		(25,424	)		(119,678	)
Extensions, discoveries and improved recovery, net of future costs		187,636			50,515
Accretion of discount		24,940			106,481
Net change in income taxes		(262,214	)		457,582
Development costs incurred		26,756			7,791
Changes in estimated development costs		(429	)		13,128
Timing differences and other		10,340			(199,528	)

Standardized Measure at December 31	$	400,295		$	111,361

S-38

SIGNATURES

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


	HARVEST NATURAL RESOURCES, INC. (Registrant)
Date: March 16, 2010	By:	/s/ James A. Edmiston
		James A. Edmiston
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the 16^th day of March, 2010, on behalf of the registrant and in the capacities indicated:


Signature				Title


/s/ James A. Edmiston				Director, President and Chief Executive Officer
James A. Edmiston				(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’ Stephen D. Chesebro’				Chairman of the Board and Director

/s/ Igor Effimoff Igor Effimoff				Director

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

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

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

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

S-39

SCHEDULE II

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

Valuation and Qualifying Accounts

(in thousands)


			Additions
	Balance at					Charged to Other		Deductions From		Balance at End of
	Beginning of Year		Charged to Income			Accounts		Reserves		Year
At December 31, 2009
Amounts deducted from applicable assets
Accounts receivable	$	2,757	$	—		$	2,757	$	—	$	—
Deferred tax valuation allowance		7,841		9,184			—		—		17,025
Investment at cost		1,350		—			—		—		1,350
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

S-40

SCHEDULE III

Financial Statements and Notes

for Petrodelta, S.A.

S-41

PETRODELTA, S.A.

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Financial Statements at December 31, 2009 and 2008
and Independent Auditor’s Report

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)

Index


	Pages
INDEPENDENT AUDITOR’S REPORT		1 - 2

FINANCIAL STATEMENTS AS OF DECEMBER 31 2009 AND 2008

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

Notes to the financial statement

Nota 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		22
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		32
Note 10 Prepaid Expenses and Other Assets		33
Note 11 Inventories		33
Note 12 Accounts Receivable		33
Note 13 Cash and cash equivalents		34
Note 14 Equity		34
Note 15 Accounts Payable		36
Note 16 Accruals and Other Payables		37
Note 17 Financial Instruments		38
Note 18 Commitments and Contingencies		41
Note 19 Related Party Transactions		42
Note 20 Laws, Resolutions and Legal Contributions		44
Note 21 Subsequent events		46
Note 22 Subsequent events after Independent Accountants Opinion		47
Note 23 Supplementary Information on Oil and Gas Exploration and Production Activities (unaudited)		47

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, 2009 and 2008, and the statements of comprehensive income, statements of changes in equity and statements of cash flow for the years then ended, and a summary of significant accounting policies and other explanatory notes.

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 audits 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.
Telf.: 58-241 8253518 / 8255337 Fax: 8259828. RIF: J-30785734-0
PGFA Perales, Pistone & Asociados es firma miembro de (HLB LOGO)

International

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements present fairly, in all material respects, the financial position of Petrodelta, S.A. as of December 31, 2009 and 2008, and of its financial performance and its cash flows for the year then ended in accordance with International Financial Reporting Standards.

Emphasis of matter

Without qualifying our opinion as indicated in Note 19 to the financial statements, the Company belongs to a group of related companies and conducts transactions and maintains balances for significant amounts with other members of the group, with significant effects on the results of its operations and financial position. Because of those relationships, these transactions may have taken place on terms other than those that would characterize transactions between unrelated companies.

Por PGFA PERALES, PISTONE & ASOCIADOS

José G. Perales S.
C.P.C. Nº 9.578

Valencia, January 22, 2010

Except for the matters indicated in Note 22, whose date is February 26, 2010

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)

Statements of Financial Position
(Expressed In Thousands)


	December 31^st,
	Note			2009		2008		2009		2008
				U.S. dollars				Bolivars
Assets

Property, plant and equipment, net		8			265,442		211,760		570,698		455,284
Deferred income tax		7-	(a)		141,245		97,323		303,676		209,244


Total non-current assets					406,687		309,083		874,374		664,528


Prepaid expenses and other assets		10			559		21,477		1,202		46,176
Inventories		11			21,472		14,391		46,167		30,941
Accounts receivable		12			379,732		267,786		816,425		575,740
Cash and cash equivalents		13			3,062		7,363		6,582		15,830


Total current asset					404,825		311,017		870,376		668,687


Total assets					811,512		620,100		1,744,750		1,333,215


Equity
Equity, see statements of changes in equity		14			432,100		340,692		929,013		732,487


Liabilities

Provision for abandonment cost		9 y 16			24,416		19,174		52,492		41,224
Provision for retirement benefits		16			9,184		1,306		19,746		2,808


Total non-current liabilities					33,600		20,480		72,238		44,032


Accounts payable		15			105,332		89,104		226,465		191,574
Dividends payable		14			31,126		—		66,921		—
Accruals and other liabilities		16			154,863		169,824		332,956		365,122
Income tax payable		7			54,491		—		117,157		—


Total current liabilities					345,812		258,928		743,499		556,696


Total liabilities					379,412		279,408		815,737		600,728


Total equity and liabilities					811,512		620,100		1,744,750		1,333,215

The accompanying notes from 1 to 23 are an integral part of these financial statements

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)

Statements of Comprehensive Income
(Expressed In Thousands)


	Years ended December 31^st,
	Note			2009			2008			2009			2008
				U.S. dollars						Bolivars
Income

Sales of crude oil					451,473			458,113			970,667			984,943
Sales of gas					6,778			16,506			14,572			35,488

		19			458,251			474,619			985,239			1,020,431


Cost and expenses

Operational cost					(48,311	)		(77,609	)		(103,869	)		(166,859	)
Depletion, depreciation and amortization		8			(32,571	)		(24,778	)		(70,029	)		(53,273	)
Sales, general and administrative expenses					(10,841	)		(6,705	)		(23,307	)		(14,416	)
Royalties		7 —	(b)		(157,681	)		(225,167	)		(339,014	)		(484,109	)
Financial expenses					(3,617	)		(2,329	)		(7,777	)		(5,007	)

					(253,021	)		(336,588	)		(543,996	)		(723,664	)


Profit before tax					205,230			138,031			441,243			296,767

Income tax expense		7 —	(a)		(61,946	)		(16,814	)		(133,184	)		(36,150	)


Profit and total comprehensive income for the year					143,284			121,217			308,059			260,617

The accompanying notes from 1 to 23 are an integral part of these financial statements

PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of changes in equity

Years ended December 31, 2009 and 2008
(Expressed In Thousands of US dollar)


										Retained earnings
					Shareholder					Legal reserve and
	Note		Capital stock		contribution			Share premium		other reserves		Distributable			Total
Balances at December 31, 2007				465		6,512			212,451		47		181,325			400,800

Profit and total comprehensive income for the year				—		—			—		—		121,217			121,217

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

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

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


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

Profit and total comprehensive income for the year				—		—			—		—		143,284			143,284

Appropriation to other reserves		14		—		—			—		141,245		(141,245	)		—

Dividends declared		14		—		—			—		—		(51,876	)		(51,876	)


Balances at December 31, 2009				6,977		—			212,451		141,943		70,729			432,100

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 16, 2010