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EX-99.2 - EX-99.2 - HARVEST NATURAL RESOURCES, INC.h80470aexv99w2.htm
EX-32.1 - EX-32.1 - HARVEST NATURAL RESOURCES, INC.h80470aexv32w1.htm
EX-31.2 - EX-31.2 - HARVEST NATURAL RESOURCES, INC.h80470aexv31w2.htm
EX-99.1 - EX-99.1 - HARVEST NATURAL RESOURCES, INC.h80470aexv99w1.htm
EX-32.2 - EX-32.2 - HARVEST NATURAL RESOURCES, INC.h80470aexv32w2.htm
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K/A
Amendment No. 1
(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
or
     
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
(Address of principal executive offices)
  77077
(Zip Code)
Registrant’s telephone number, including area code: (281) 899-5700
Securities registered pursuant to Section 12(b) of the Act:
     
Title of each class   Name of each exchange on which registered
Common Stock, $.01 Par Value   NYSE
Securities registered pursuant to Section 12(g) of the Act: Preferred Share Purchase Rights
Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark 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
(Do not check if a smaller reporting company)
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 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.
 
 

 


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Explanatory Note — Amendment
           Harvest Natural Resources, Inc. and Subsidiaries (collectively, “we”, “us”, “our”, “Harvest” or “the Company”) is filing this Amendment No. 1 to its Annual Report on Form 10-K/A (this “Amendment”) to reflect changes made in response to comments received by us from the Staff of the Securities and Exchange Commission (the “Staff”), in connection with the Staff’s review of Harvest’s original Annual Report on Form 10-K for the year ended December 31, 2009, as filed with the Securities and Exchange Commission on March 16, 2010 (the “Original Form 10-K”). We are only filing the items of our Original Form 10-K that have been revised in response to the Staff’s comment letter:
           Item 1 — Business
           Item 1A — Risk Factors
           Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
           Item 10 — Directors, Executive Officers and Corporate Governance
           Item 15 — Exhibits
All other information in our Original Form 10-K remains unchanged. Accordingly, this Amendment should be read in conjunction with our Original Form 10-K and any Harvest filings with the SEC subsequent to the filing of the Original Form 10-K. Revised reserve reports from Ryder Scott Company, L.P. are attached as Exhibits 99.1 and 99.2. The revised reserve reports address the limitations on reliance by third parties.
           Pursuant to the Rules of the SEC, currently dated certifications from our Chief Executive Officer and Chief Financial Officer as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 are filed or furnished herewith, as applicable.

 


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HARVEST NATURAL RESOURCES, INC.
FORM 10-K
TABLE OF CONTENTS
         
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 EX-23.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-99.1
 EX-99.2

 


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PART I
Harvest Natural Resources, Inc. (“Harvest” or the “Company”) cautions that any forward-looking statements (as such term is defined in the Private Securities Litigation Reform Act of 1995, as amended [the “PSLRA”]) 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 PSLRA, 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 a 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 personnel 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. 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.
           We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through HNR Finance, B.V. (“HNR Finance”). Our ownership of HNR Finance is through several corporations in all of which we have direct controlling interests. Through these corporations, we indirectly own 80 percent of HNR Finance 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 20 percent interest of HNR Finance. HNR Finance owns 40 percent of Petrodelta, S.A. (“Petrodelta”). As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta (80 percent of 40 percent), and Vinccler indirectly owns eight percent (20 percent of 40 percent). Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petrodelta is governed by its own charter and bylaws and 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. HNR Finance has a direct controlling interest in Harvest Vinccler S.C.A. (“Harvest Vinccler”). Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with Petroleos de Venezuela S.A. (“PDVSA”). We do not have a business relationship with Vinccler outside of Venezuela.

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           Through the pursuit of technically-based strategies guided by conservative investment philosophies, we are building a portfolio of exploration prospects to complement the low-risk production, development and exploration prospects we hold in Venezuela. In addition to our interests in Venezuela, we hold exploration acreage in the Gulf Coast Region of the United States through an Area of Mutual Intent (“AMI”) agreement with two private third parties, the Antelope project in the Western United States through a Joint Exploration and Development Agreement (“JEDA”), 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”).
           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

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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

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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. 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.
           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.

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    Oil and     Natural        
    Condensate     Gas     Total  
    (MBls)     (MMcf)     (MBOE)(1)  
Proved Developed Reserves:
                       
Domestic — Utah
    131       653       240  
International — Venezuela(2)
    11,394       19,212       14,596  
 
                 
Total Proved Developed
    11,525       19,865       14,836  
 
                 
Proved Undeveloped Reserves:
                       
Domestic — Utah
    95       473       174  
International — Venezuela (2)
    26,542       30,956       31,701  
 
                 
Total Proved Undeveloped
    26,637       31,429       31,875  
 
                 
Total Proved Reserves
    38,162       51,294       46,711  
 
                 
Probable Developed Reserves:
                       
International — Venezuela(2)
    94       74       106  
Probable Undeveloped Reserves:
                       
International — Venezuela(2)
    34,951       11,674       36,897  
 
                 
Total Probable Reserves
    35,045       11,748       37,003  
 
                 
Possible Developed Reserves:
                       
International — Venezuela(2)
    9             9  
Possible Undeveloped Reserves:
                       
International — Venezuela(2)
    134,805       37,147       140,996  
 
                 
Total Possible Reserves
    134,814       37,147       141,005  
 
                 
 
(1)   MBOE (thousand barrels of oil equivalent) is determined using the approximate heat content ratio of one barrel of crude oil or condensate to six Mcf of natural gas, which ratio does not necessarily reflect price equivalency.
 
(2)   Information represents our net 32 percent ownership interest in Petrodelta.
           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.

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           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 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

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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. Article 307 of the Venezuelan Commerce Code 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).
           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. Per the Exchange Agreement, 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. See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Operations, Venezuela for a description of the effect the Exchange Agreements are having on our Venezuela operation.

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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.

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           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.

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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
           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

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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.
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
           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 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.
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.

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Drilling and Development Activity
           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.
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.

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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
           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. It is uncertain when or how this dispute will be resolved, and under what terms the various countries and parties to the agreements may participate in the resolution.
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. Venezuela is presented at our net 32 percent ownership interest in Petrodelta. The United States is presented at our ownership interest.

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    Year Ended December 31,
    2009   2008   2007
Venezuela
                       
Crude Oil Production (MBbls)(b)
    1,671       1,174       2,259  
Natural Gas Production (MMcf)(a)(c)
    938       2,283       5,548  
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)(d)
  $ 5.64     $ 10.65     $ 3.12  
 
                       
United States
                       
Monument Butte
                       
Net Crude Oil Production (MBbls)
    3              
Natural Gas Production (MMcf)
    6              
Average Crude Oil Sales price ($ per Bbl)
  $ 61.57     $     $  
Average Natural Gas Sales Price ($ per Mcf)
  $ 2.77     $     $  
Average Operating Expenses ($ per Boe)
  $     $     $  
 
(a)   Royalty-in-kind paid on gas used as fuel was 1,063 MMcf, 1,226 MMcf and 1,242 MMcf for 2009, 2008 and 2007, respectively, net to our 32 percent ownership interest in Petrodelta.
 
(b)   Crude oil production for Petrodelta at 100 percent was 7,835 MBbls, 5,505 MBbls and 5,374 MBbls for 2009, 2008 and 2007, respectively.
 
(c)   Natural gas production for Petrodelta at 100 percent was 4,397 MMcf, 10,700 MMcf and 13,456 MMcf for 2009, 2008 and 2007, respectively.
 
(d)   Before royalties and including workovers. Average operating expenses per Boe for Petrodelta net of royalties and workovers was $8.46, $10.90 and $4.20 for 2009, 2008 and 2007, respectively. Petrodelta is not subject to ad valorem or severance taxes.
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:

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    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;

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    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

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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. Sukuk financing is an Islamic financial certificate, similar to a bond in Western finance, that complies with Sharia, Islamic religious law. Trading debt is prohibited under Sharia. As such, financing under Sharia must only be raised for identifiable assets. The issuer of a sukuk buys an asset from an investor group, who then rents the asset from the issuer for a predetermined fee. Under the sukuk, one of our subsidiaries would form and contribute certain assets to a partnership and subsequently sell a minority interest in the partnership to the sukuk issuers 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 sukuk issuers partnership interests, including premiums thereon. While we may be able to consummate this financing transaction in the near future, there can be no assurances that this transaction will be consummated at all, 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

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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

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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.

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           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;

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    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 effect 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.

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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.
Venezuela
           On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement, which established new exchange rates for the Bolivar/U.S. Dollar currencies that went into effect on January 11, 2010. Per the Exchange Agreement, each exchange rate is applied to foreign currency sales and purchases conducted through 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 applied to the food, health, medical and technology sectors. The 4.30 Bolivar exchange rate applied to all other sectors not expressly established by the 2.60 Bolivar exchange rate. The 4.30 Bolivar exchange rate applied to the oil and gas sector. Article 5 of the January 8, 2010 Exchange Agreement established:
    Operations for the sale of foreign currency will be at 2.5935 Bolivars per U.S. Dollar and 4.2893 Bolivars per U.S. Dollar exchange rates. The 2.5935 Bolivars per U.S. Dollar rate applies to at least 30 percent of the currency. The 30/70 percent split in sales of foreign currency between the two exchange rates creates a blended third exchange rate of 3.81 Bolivars per U.S. Dollar.
 
    The Central Bank is entitled to adjust the proportion of sales of foreign currency at each exchange rate to attend market needs.
           As an alternative to the use of the official exchange rate, an exemption under the Venezuelan Criminal Exchange Law for transactions in certain securities resulted in an indirect securities transaction market of foreign currency exchange, through which companies could obtain foreign currency legally without requesting it from CADIVI. Publicly available quotes did not exist for the securities transaction exchange rate but such rates could be obtained from brokers. Securities transaction markets were used to move financial securities into and out of Venezuela. In May 2010, the government of Venezuela effectively eliminated this indirect market of foreign currency exchange and established the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) for exchanging Bolivars. SITME’s purpose is to assist companies and individuals requiring foreign currency (U.S. Dollars) for the import of goods and services into Venezuela. SITME may also be used for buying or selling of Venezuela’s bonds. The elimination of the indirect market for foreign currency exchange and the establishment of SITME have not had, nor is it expected to have, an impact on our business in Venezuela.
           Harvest Vinccler’s and Petrodelta’s functional and reporting currency is the U.S. Dollar, and they do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Harvest Vinccler and Petrodelta do not have, and have not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate.
           At December 31, 2009, Harvest Vinccler and Petrodelta remeasured the appropriate monetary assets and liabilities at the official exchange rate of 2.15 Bolivars per U.S. Dollar that was in effect at that time. On January 31, 2010, Harvest Vinccler and Petrodelta remeasured the appropriate monetary assets and liabilities at the

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new official exchange rate of 4.30 Bolivars per U.S. Dollar. In January 2010, Harvest Vinccler estimated a $1.5 million remeasurement loss and Petrodelta estimated a $120.5 million remeasurement gain on revaluation of monetary assets and liabilities. The revaluation of Bolivars to U.S. Dollars was calculated as the difference between the old official exchange rate of 2.15 Bolivars per U.S. Dollar and the new official exchange rate of 4.30 Bolivars per U.S. dollar. The primary factor in Harvest Vinccler’s loss on currency exchange rates is that Harvest Vinccler had substantially higher Bolivar denominated monetary assets than Bolivar denominated monetary liabilities. The primary factor in Petrodelta’s gain on currency exchange rates is that Petrodelta had substantially higher Bolivar denominated monetary liabilities than Bolivar denominated monetary assets. At December 31, 2009, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 7.9 million and BsF 1.9 million, respectively. At December 31, 2009, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 84.5 million and BsF 780.8 million, respectively.
           The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PDVSA Petroleo S.A. (“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. Merey 16 published prices are quoted and sold in U.S. Dollars. 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 in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered. Natural gas deliveries are paid in Bolivars, but the pricing for natural gas is referenced to the U.S. Dollar. Major contracts for capital expenditures and lease operating expenditures are denominated in U.S. Dollars. Any dividend paid by Petrodelta will be made in U.S. Dollars.
           Since payment for crude oil is in U.S. Dollars under the contract, we do not expect the recent currency exchange developments in Venezuela to have an impact on Petrodelta’s operations or on the reserves economic productability price of $56.83 per barrel of oil in relation to the Venezuelan reserves. In addition, prices used to derive our reserves economic productability average prices are quoted and sold in U.S. Dollars.
           In Item 1A — Risk Factors, we disclosed that PDVSA’s failure to timely pay contractors, including Petrodelta, was having an adverse effect on Petrodelta. When oil prices fell sharply at the end of 2008, PDVSA had already begun showing delays in timely paying its contractors. Petrodelta also experienced delays in receiving payment for its crude oil and natural gas deliveries. As a result, debt to contractors under direct contract with Petrodelta increased. Petrodelta’s operations have been affected by PDVSA’s slow payment of debt. Petrodelta has been required to delay operational activities such as workovers and field maintenance partly due to cash issues and partly due to compliance with PDVSA budgeting.
           Starting in early 2009, PDVSA began re-negotiating the outstanding debts of its large contractors. PDVSA successfully re-negotiated a majority of the large contractor debt and successfully placed two large bond issues ($7.5 billion). These two events allowed PDVSA to pay a substantial portion of the outstanding debt to its smaller contractors, which included contractors providing services to Petrodelta through PDVSA’s umbrella contracts and to Harvest Vinccler, who is a contractor to Petrodelta. As a Petrodelta contractor, Harvest Vinccler assessed the possibility of recording an allowance for doubtful accounts on its receivable from Petrodelta. After considering many factors, including the slow but continuous payments received from Petrodelta, Harvest Vinccler determined that an allowance for doubtful accounts is not required.
           We are unable to provide an indication of when PDVSA will become and remain current in its payment obligations. However, we believe that PDVSA’s debt will not disappear completely in the short term, but the risk of contractor work stoppage is minimal due to PDVSA guaranteeing payments as publicly stated by top officials. Increased costs due to PDVSA’s debt financing are already imbedded in current contractor’s rates.
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

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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
           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.
Gulf Coast — West Bay
           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 the second quarter 2009 and resulted in the identification of a revised set of drilling leads and prospects for the project.
           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

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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
           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.
           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.

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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:

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    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.

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           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

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      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

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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

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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:

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    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.

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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. 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     3-4Years     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.
           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 had 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. 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.
           Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004, March 2005, and again in January 2010. On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement, which established new exchange rates for the Bolivar/U.S. Dollar currencies that went into effect on January 11, 2010.
           Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). However, in October 2010, Harvest Vinccler exchanged approximately $0.2 million through SITME and received an exchange rate of 5.19 Bolivars per U.S. Dollar. The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Harvest Vinccler and Petrodelta do not have, and have not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate.
           See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Operations, Venezuela for a more complete discussion of the exchange agreements and their effects on our Venezuelan operations.
           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.

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Critical Accounting Policies
Principles of Consolidation
           The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. The equity method of accounting is used for companies and other investments in which we have significant influence. All intercompany profits, transactions and balances have been eliminated.
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.
           There are many factors we consider when evaluating our equity investments for possible impairment. Currency devaluations, inflationary economies and cash flow analysis are some of the factors we consider in our evaluation. Since the Venezuelan currency devaluations have not significantly affected Petrodelta’s business and any dividends declared by Petrodelta are required to be paid in U.S. Dollars per the conversion contract, we do not believe an impairment of the investment of the asset is warranted at this time. See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Venezuela for a complete description of the situation in Venezuela and other matters. At December 31, 2009 and 2010, there were no events that caused us to evaluate our investment in Petrodelta for impairment.
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

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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.
           The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

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           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.
           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 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

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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.

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PART III
Item 10. Directors, Executive Officers and Corporate Governance
DIRECTORS
           The following table provides information regarding each of our directors.
     
Stephen D. Chesebro’
Appointed Director in October 2000
Age 68
  Mr. Chesebro’ has served as the Chairman of the Board of Harvest Natural Resources, Inc. since 2001. From December 1998 until he retired in 1999, he served as President and Chief Executive Officer of PennzEnergy, the independent oil and gas exploration and production company that was formerly a business unit of Pennzoil Company. From February 1997 to December 1997, Mr. Chesebro’ served as Group Vice President — Oil and Gas and from December 1997 until December 1998 he served as President and Chief Operating Officer of Pennzoil Company, an integrated oil and gas company. From 1993 to 1996, Mr. Chesebro’ was Chairman and Chief Executive Officer of Tenneco Energy, a $4 billion global energy company. Tenneco Energy was part of Tenneco, Inc., a worldwide corporation that owned diversified holdings in six major industries. Mr. Chesebro’ is an advisory director to Preng & Associates, an executive search consulting firm. In 1964, Mr. Chesebro’ graduated from the Colorado School of Mines. He was awarded the school’s Distinguished Achievement Medal in 1991 and received his honorary doctorate from the institution in 1998. He currently serves on the school’s visiting committee for petroleum engineering, and is a member of the Colorado School of Mines Foundation Board of Governors. In 1994, Mr. Chesebro’ was the first American awarded the H. E. Jones London Medal by the Institution of Gas Engineers, a British professional association. Since December 2005, he has served as the President of the Chesebro’ Foundation, Inc., a private charitable foundation incorporated in Delaware.
 
   
James A. Edmiston
Elected Director in May 2005
Age 50
  Mr. Edmiston was elected President and Chief Executive Officer of Harvest Natural Resources, Inc. on October 1, 2005. He joined the Company as Executive Vice President and Chief Operating Officer on September 1, 2004. Prior to joining Harvest, Mr. Edmiston was with Conoco and ConocoPhillips for 22 years in various management positions including President, Dubai Petroleum Company (2002-2004), a ConocoPhillips affiliate company in the United Arab Emirates and General Manager, Petrozuata, C.A., in Puerto La Cruz, Venezuela (1999-2001). Prior to 1999, Mr. Edmiston also served as Vice President and General Manager of Conoco Russia and then as Asset Manager of Conoco’s South Texas Lobo Trend gas operations. Mr. Edmiston earned a Bachelor of Science degree in Petroleum Engineering from the Texas Tech University and a Masters of Business Administration from the Fuqua School of Business at Duke University. Mr. Edmiston was inducted into the Petroleum Engineering Academy and was recognized as a Distinguished Engineer by the Texas Tech College of Engineering in 2009. Mr. Edmiston is a Member of the Society of Petroleum Engineers.
 
   
Dr. Igor Effimoff
Appointed Director in February 2008
Age 64
  Dr. Igor Effimoff is founder and principal of a firm which provides upstream and midstream consulting services since 2005. From 2002 until 2005 he was Chief Operating Officer for Teton Petroleum Company. Between 1996 and 2001, he was President of Pennzoil Caspian Corporation, managing their interests in the Caspian Region. Between 1994 and 1996 he was the Chief Executive Officer of Larmag Energy, NV, a privately held Dutch oil and gas production company with its primary assets in the Caspian Sea. He has served in senior executive roles with Ashland Exploration Inc., Zilkha Energy Company and Kriti Exploration, Inc. Dr. Effimoff

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  has authored numerous technical and business articles. He is a member of American Association of Petroleum Geology, the Society of Petroleum Engineers, the Society of Exploration Geophysicists and the Geological Society of America. He has a Doctorate in Geology from the University of Cincinnati and completed the Harvard Advanced Management Program.
 
   
H. H. Hardee
Appointed Director in October 2000
Age 55
  Mr. Hardee is a Senior Vice President—Financial Consultant with RBC Wealth Management, since 1994. From 1991 through 1994, Mr. Hardee was a Senior Vice President with Kidder Peabody. From 1977 through 1991, Mr. Hardee was a Senior Vice President at Rotan Mosle/Paine Webber Inc. During his tenure at RBC Wealth Management, he was in the top 1% of his peer group and has been a member of the Chairman’s Council since joining the firm. Mr. Hardee is a licensed investment advisor and has served in various board capacities including investment policy. Mr. Hardee was named as one of America’s best financial advisors for 2009 by Barron’s financial newspaper. He was awarded designation to Reuter’s Advice Point Top Advisors of 2008 and named to RBC Wealth Management Senior Portfolio Manager Group. He currently advises/manages over $400 million in assets. Mr. Hardee’s expertise is advising high net worth individuals and small to mid sized corporations. Mr. Hardee is a former director of the Bank of Almeda and Gamma Biologicals. He is also a former limited partner and advisory director of the Houston Rockets of the National Basketball Association. Mr. Hardee has a finance degree from the University of Texas McCombs School of Business. He holds an Accredited Wealth Management designation, as well as a certification of director education from the NACD Corporate Directors Institute.
 
   
Robert E. Irelan
Appointed Director in February 2008
Age 63
  Mr. Irelan has over 37 years of experience in the oil and gas industry. He retired from Occidental Petroleum as Executive Vice President of Worldwide Operations in April 2004, having started there in 1998. Prior to Occidental Petroleum, Mr. Irelan held various positions at Conoco, Inc., from 1967 until 1998. Upon his retirement he opened his own company, Naleri Investments LLC. He also partnered in several entrepreneurial ventures including Rapid Retail Solutions LLC, BISS Product Development LLC and All About Baby LLC. Mr. Irelan earned his Professional Engineering degree in Petroleum Engineering from Colorado School of Mines. He also has advanced studies in Mineral Economics. He was awarded the Distinguished Achievement Award from the school in 1998.
 
   
Patrick M. Murray
Appointed Director in October 2000
Age 67
  In 2007, Mr. Murray retired from Dresser, Inc. He had been the Chairman of the Board and Chief Executive Officer since 2004. Dresser, Inc. is an energy infrastructure and oilfield products and services company. From 2000 until becoming Chairman of the Board, Mr. Murray served as President and Chief Executive Officer of Dresser, Inc. Mr. Murray was President of Halliburton Company’s Dresser Equipment Group, Inc.; Vice President, Strategic Initiatives of Dresser Industries, Inc.; and Vice President, Operations of Dresser, Inc. from 1996 to 2000. Mr. Murray has also served as the President of Sperry-Sun Drilling Services from 1988 through 1996. Mr. Murray joined NL Industries in 1973 as a Systems Application Consultant and served in a variety of increasingly senior management positions. Mr. Murray currently serves on the board of Precision Drilling Corporation, a publicly held contract drilling company and Wellstream Holdings PLC, a manufacturer of flexible pipe. Mr. Murray is also on the board of the World Affairs Council of Dallas Fort Worth. He is on the board of advisors for the Maguire Energy Institute at the Edwin L. Cox School of Business, Southern Methodist University, and a member of the Board of Regents of Seton Hall University. Mr. Murray holds a B.S. degree in

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  Accounting and a Master of Business Administration from Seton Hall University. He served for two years in the U.S. Army as a commissioned officer.
 
   
J. Michael Stinson
Appointed Director in November 2005
Age 66
  Since September 2006, Mr. Stinson has been Chairman of TORP Terminal LP, the U.S. unit of a Norwegian LNG technology company. From 2004 until November of 2009, he served as a director of Enventure Global Technology, Inc., an oil equipment company, most recently as the Chairman of their Audit and Finance Committee. From January 2005 until November 2007, he was Chairman of the Board of Paulsson Geophysical Services, Inc., a vertical seismic profiling technology company. From February through August 2004, Mr. Stinson served with the U.S. Department of Defense and the Coalition Provisional Authority as Senior Advisor to the Iraqi Ministry of Oil. From 1965 to 2003, Mr. Stinson was with Conoco and ConocoPhillips in a number of assignments in operations and management. His last position at ConocoPhillips was as Senior Vice President, Government Affairs in which he was responsible for government relations with particular emphasis on developing and facilitating international business development opportunities in various countries. Previous positions included Senior Vice President — Business Development, Vice President — Exploration and Production, Chairman and Managing Director of Conoco (UK) Limited, Vice President/General Manager of International Production for Europe, Africa and the Far East, and President and Managing Director of Conoco Norway, Inc. Mr. Stinson earned a Bachelor of Science degree in Industrial Engineering from Texas Tech University and a Masters of Business Administration from Arizona State University. He is a member of the Society of Petroleum Engineers, the American Association of Petroleum Geologists, and the Society of Exploration Geophysicists.
EXECUTIVE OFFICERS
           The following table provides information regarding each of our executive officers.
             
Name   Age   Position
 
           
James A. Edmiston *
    50     President and Chief Executive Officer
 
           
Stephen C. Haynes
    53     Vice President, Finance, Chief Financial Officer and Treasurer
 
           
Keith L. Head
    52     Vice President, General Counsel and Corporate Secretary
 
           
G. Michael Morgan
    56     Vice President, Business Development
 
           
Karl L. Nesselrode
    52     Vice President
 
           
Patrick R. Oenbring
    58     Vice President, Western Operations
 
           
Robert Speirs
    54     Vice President, Eastern Operations
 
*   See Mr. Edmiston’s biography on page 38.
           Stephen C. Haynes has served as our Vice President, Chief Financial Officer and Treasurer since May 19, 2008. Mr. Haynes performed various financial consulting engagements from January 1, 2008, until his appointment with Harvest. Previously, he served as Chief Financial Officer for Cygnus Oil and Gas Corporation for the period February 1, 2006 through December 31, 2007. Before joining Cygnus, Mr. Haynes was the Corporate Controller with Carrizo Oil and Gas for the period January 1, 2005 through January 31, 2006. Mr. Haynes served as an

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independent consultant from March 2001 through end of 2004. From March 1990 through December 2000, Mr. Haynes served in a series of increasing responsibilities in international managerial and executive positions with British Gas, culminating in his appointments as Vice President-Finance of Atlantic LNG, a joint venture of British Gas and several industry partners in Trinidad and Tobago. Mr. Haynes is a Certified Public Accountant, holds a Master of Business Administration degree with a concentration in Finance from the University of Houston and a Bachelor of Business Administration degree in Accounting from Sam Houston State University. He also attended the Executive Development Program at Harvard University.
           Keith L. Head has served as our Vice President, General Counsel and Corporate Secretary since May 7, 2007. He joined Texas Eastern upon graduation from law school and remained with the same organization through mergers with Panhandle Eastern, Duke Energy Corporation and Cinergy Corp. Mr. Head held various business development positions with Duke Energy Corporation from 1995 to 2001. His corporate development work included the identification, evaluation and negotiation of acquisitions in Latin America, North America and the United Kingdom. Mr. Head was Senior Vice President and General Counsel at Duke Energy North America from 2001 to 2004 and Associate General Counsel of Duke Energy Corporation from 2004 through December 2006. After leaving Duke Energy, Mr. Head joined Harvest in May 2007. Mr. Head holds a Bachelor of Science degree in Business Administration from the University of North Carolina. He received both a Juris Doctorate and Masters in Business Administration from the University of Texas in 1983.
           G. Michael Morgan has served as Vice President, Business Development since May 19, 2008. Prior to joining Harvest, Mr. Morgan served as Corporate Vice President of International Affairs at Sempra Energy from 2006 until retirement in June 2008. From 2000 to 2006 at Sempra, he was Vice President — Special Projects and President and General Manager — South America Operations. Before joining Sempra, Mr. Morgan was Vice President Latin America New Ventures for Unocal Corporation and held various international and domestic positions at Enron Corporation, Tenneco Corporation, Shell International and Gulf Oil. He has served as a director on the board of several energy companies based in Latin America. Mr. Morgan holds a Bachelor of Science degree in geology from the University of Texas.
           Karl L. Nesselrode has served as Vice President of the Company since November 17, 2003. From August 9, 2007 to August 2, 2010, he accepted a long-term secondment to Petrodelta as its Operations and Technical Manager while remaining an officer of Harvest. From February 2002 until November 2003, Mr. Nesselrode was President of Reserve Insights, LLC, a strategy and management consulting company for oil and gas. He was employed with Anadarko Petroleum Corporation as Manager Minerals and Special Projects from July 2000 to February 2002. Mr. Nesselrode served in various managerial positions with Union Pacific Resources Company from August 1979 to July 2000. Mr. Nesselrode earned a Bachelor of Science in Petroleum Engineering from the University of Tulsa in 1979 and completed Harvard Business School Program for Management Development in 1995.
           Patrick R. Oenbring has served as Vice President, Western Operations since April 14, 2008. Mr. Oenbring has 34 years of experience in the oil and gas business in both technical and management positions. From October 2007 until coming to Harvest, he worked as an independent consultant. He was the Chief Operating Officer for Cygnus Oil and Gas Company (formerly Touchstone Resources) from March 2006 until September 2007. Technip Offshore, Inc. employed Mr. Oenbring as Senior Project Manager from May 2005 until February 2006. He began his career with Conoco in 1974 and served in several capacities with responsibilities on the North Slope of Alaska, the Gulf of Mexico, the North Sea, the Middle East, the Far East, Canada, Nigeria and the United States. Mr. Oenbring joined Occidental Petroleum Corporation (Occidental) in 1997, as President and General Manager, Occidental Petroleum of Qatar and subsequently, returned to the United States in 2000 as President and General Manager, Occidental Permian. In 2003, Mr. Oenbring retired from Occidental and became an independent consultant to the oil and gas industry, serving diverse clients in West Texas, Colombia, India, and Houston. While Mr. Oenbring was the Chief Operating Officer at Cygnus, Cygnus filed for bankruptcy protection in 2007. Mr. Oenbring holds a Bachelor of Science degree in Chemical Engineering from the University of Kansas. He is a graduate of the University of Pittsburgh executive development program and is a registered Professional Engineer in the State of Texas.
           Robert Speirs has served as Vice President, Eastern Operations since December 6, 2007. He joined Harvest in June 2006 as President and General Manager, Russia. Previously Mr. Speirs was President of Marathon Petroleum Russia and General Director of their wholly-owned subsidiary, KhantyMansciskNefte Gas Geologia from March 2004 through May 2006. Prior to joining Marathon, Mr. Speirs was Executive Vice President of YUKOS EP

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responsible for engineering and construction from June 2001. During both these periods, Mr. Speirs spent considerable time in West Siberia where he oversaw substantial increases in production at both companies. From November 1997 until March 2001, Mr. Speirs resided in Jakarta where he served as President of Premier Oil Indonesia. During this period, Premier was active in all phases of the Upstream business, culminating in the commissioning of the West Natuna Gas Project. Prior to 1997, Mr. Speirs was with Conoco for 21 years in various leadership positions in the US, UK, Russia, Indonesia, Singapore and Dubai, UAE. Mr. Speirs earned a Bachelor of Science degree with Honors in Engineering Science from the University of Edinburgh. He also attended the Executive Management Program at INSEAD.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
           Section 16(a) of the Securities Exchange Act of 1934 (“Section 16(a)”) requires our directors, executive officers and beneficial holders of more than 10% of our common stock to file reports with the Securities and Exchange Commission (“SEC”) regarding their ownership and changes in ownership of our stock. To our knowledge, during fiscal 2009, our officers, directors and 10% stockholders complied with all Section 16(a) filing requirements. In making this statement, we have relied upon the written representations of our directors and officers.
CORPORATE GOVERNANCE
           Corporate governance is part of our culture and a guiding principle in our behavior. The Board has adopted Guidelines for Corporate Governance which require that independent directors comprise a majority of the Board and that the Chairman of the Board be elected from the independent directors. In addition, the Guidelines for Corporate Governance require that each standing committee of the Board be comprised solely of independent directors. Other matters included in the Guidelines for Corporate Governance are Board and director responsibilities, director qualifications, operation of the Board, director compensation, the operation and responsibilities of Board committees and management responsibilities.
           The Board has also adopted a Code of Business Conduct and Ethics which applies to all of our directors, officers and employees. The Board last amended the Code of Business Conduct and Ethics in December 2006. The Board reviewed the Code of Business Conduct and Ethics in December 2009 and made no changes. The Board has not granted any waivers to the Code of Business Conduct and Ethics.
           The Guidelines for Corporate Governance, the Code of Business Conduct and Ethics and the charters of all the Board committees are accessible on our website under the Corporate Governance section at http://www.harvestnr.com. Any amendments to or waivers of the Code of Conduct and Business Ethics will also be posted on our website.
THE AUDIT COMMITTEE
           The Board has a standing Audit Committee comprised of Messrs. Effimoff, Hardee, Murray and Stinson.
           The Audit Committee assists the Board in oversight of:
    our accounting and financial reporting policies and practices;
 
    the integrity of our financial statements;
 
    the independent registered public accounting firm’s qualifications, independence and objectivity;
 
    the performance of our internal audit function and our independent registered public accounting firm; and
 
    our compliance with legal and regulatory requirements.
           The Audit Committee acts as a liaison between our independent registered public accounting firm and the Board, and it has the sole authority to appoint or replace the independent registered public accounting firm and to approve any non-audit relationship with the independent registered public accounting firm. Our internal auditor and the independent registered public accounting firm report directly to the Audit Committee.

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           Our Audit Committee has established procedures for our employees or consultants to make a confidential, anonymous complaint or raise a concern over accounting, internal accounting controls or auditing matters concerning us or any of our companies and is responsible for the proper implementation of such procedures. The Audit Committee is also responsible for understanding and assessing our processes and policies for communications with stockholders, institutional investors, analysts and brokers.
           The Audit Committee has access to our records and employees, and has the sole authority to retain independent legal, accounting or other advisors for committee matters. We will provide appropriate funding for the payment of the independent registered public accounting firm and any advisors employed by the Audit Committee.
           The Audit Committee makes regular reports to the Board. Each year the Audit Committee assesses the adequacy of its charter and conducts a self-assessment review to determine its effectiveness.
           The Board has determined that each member of the Audit Committee meets the independence standards of the SEC’s requirements, the rules of the New York Stock Exchange and the Company Guidelines for Corporate Governance. No member of the Audit Committee serves on the audit committee of more than three public companies. The Board has further determined that each member of the Audit Committee is financially literate and that Mr. Murray qualifies as an audit committee financial expert, as defined in Item 407(d)(5) of SEC Regulation S-K. Information on the relevant experience of Mr. Murray is set forth above under the caption “Directors”.
           The Audit Committee operates pursuant to a written charter. The charter is accessible in the Corporate Governance section of our website (http://www.harvestnr.com).

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PART IV
Item 15. Exhibits and Financial Statement Schedules
(b) 3. Exhibits:
23.1   Consent of Ryder Scott Company, LP.
 
31.1   Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 executed by James A. Edmiston, President and Chief Executive Officer.
 
31.2   Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 executed by 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, 2010 between Harvest (US) Holdings, Inc. and Ryder Scott Company.
 
99.2   Reserve report dated February 26, 2010 between HNR Finance B.V. and Ryder Scott Company.

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SIGNATURES
           Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
         
  HARVEST NATURAL RESOURCES, INC.
(Registrant)
 
 
Date: March 16, 2011  By:   /s/ James A. Edmiston    
    James A. Edmiston   
    Chief Executive Officer   
 

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