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EX-23.1 - EX-23.1 - HARVEST NATURAL RESOURCES, INC.h80534exv23w1.htm
EX-32.1 - EX-32.1 - HARVEST NATURAL RESOURCES, INC.h80534exv32w1.htm
EX-23.2 - EX-23.2 - HARVEST NATURAL RESOURCES, INC.h80534exv23w2.htm
EX-99.1 - EX-99.1 - HARVEST NATURAL RESOURCES, INC.h80534exv99w1.htm
EX-31.2 - EX-31.2 - HARVEST NATURAL RESOURCES, INC.h80534exv31w2.htm
EX-23.3 - EX-23.3 - HARVEST NATURAL RESOURCES, INC.h80534exv23w3.htm
EX-31.1 - EX-31.1 - HARVEST NATURAL RESOURCES, INC.h80534exv31w1.htm
EX-21.1 - EX-21.1 - HARVEST NATURAL RESOURCES, INC.h80534exv21w1.htm
EX-32.2 - EX-32.2 - HARVEST NATURAL RESOURCES, INC.h80534exv32w2.htm
EX-99.2 - EX-99.2 - HARVEST NATURAL RESOURCES, INC.h80534exv99w2.htm
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
(Mark One)
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
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
(State or other jurisdiction of incorporation or organization)
  77-0196707
(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, 2010 was: $244,559,410.
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, 2011, shares outstanding: 33,974,691.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s Proxy Statement for the 2011 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission, not later than 120 days after the close of the registrant’s fiscal year, pursuant to Regulation 14A, are incorporated by reference into Items 10, 11, 12, 13 and 14 of Part III of this annual report.
 
 

 


 

HARVEST NATURAL RESOURCES, INC.
FORM 10-K
TABLE OF CONTENTS
         
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 EX-21.1
 EX-23.1
 EX-23.2
 EX-23.3
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-99.1
 EX-99.2

 


Table of Contents

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 being a noncontrolling interest shareholder in a corporation, the permitting and the drilling of oil and natural gas wells, the availability of materials and supplies necessary to projects and operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, the Company’s ability to acquire oil and natural gas properties that meet its objectives, availability and cost of drilling rigs, seismic crews, overall economic conditions, political stability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in governmental policy, availability of sufficient financing, changes in weather conditions, and ability to hire, retain and train management and personnel. See Item 1A — Risk Factors and Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Item 1. Business
Executive Summary
          Harvest Natural Resources, Inc. is 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, Republic of Indonesia (“Indonesia”); Muscat, Sultanate of Oman (“Oman”); and Roosevelt, Utah to support field operations in those areas.
          We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). 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.
          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 Interest (“AMI”) agreement with two private third

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parties, mainly onshore West Sulawesi in the Indonesia, offshore of the Republic of Gabon (“Gabon”), onshore in Oman and offshore of the People’s Republic of China (“China”). We also have developed acreage in the Antelope project in the Western United States through a Joint Exploration and Development Agreement (“JEDA”) in the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”) and Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) where we have established production.
          From time to time we learn of possible third party interests in acquiring ownership in certain assets within our property portfolio. We evaluate these potential opportunities taking into consideration our overall property mix, our operational and liquidity requirements, our strategic focus and our commitment to long-term shareholder value. For example, we have received such expressions of interest in acquiring some of our international and domestic producing and exploration assets, and we are currently evaluating these potential opportunities. These considerations are at a very preliminary stage, and there can be no assurances that our discussions will continue or that any transaction may ultimately result from our discussions. In September 2010, we announced the retention of Bank of America Merrill Lynch to provide advisory services to assist us in exploring a broad range of strategic alternatives for enhancing shareholder value. These alternatives could include, but are not limited to, certain extraordinary transactions, including, possibly, a sale of assets or a sale or merger of the Company.
          As of December 31, 2010, we had total assets of $488.2 million, unrestricted cash of $58.7 million and $81.2 long-term debt. For the year ended December 31, 2010, we had revenues of $10.7 million and net cash used in operating activities of $5.3 million. 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.
          In the United States during the year ended December 31, 2010, we completed the Bar F #1-20-3-2 (“Bar F”) in the Lower Green River/Upper Wasatch. We also drilled, completed, and placed on production two delineation wells and had five additional wells in various stages of drilling and completion in the Lower Green River/Upper Wasatch. In the Monument Butte Extension, we completed the non-operated eight well appraisal and development drilling program and began an additional six well non-operated expansion program. Also in the Monument Butte Extension, we commenced drilling of one Harvest operated delineation well.
          In Venezuela during the year ended December 31, 2010, Petrodelta drilled and completed 16 development wells. Petrodelta is currently utilizing two drilling rigs and one workover rig.
          We received our first comprehensive reserve report covering the Uinta Basin reserves in Utah. Proved and Probable Reserves (“2P”) net to Harvest in Utah increased to 15.3 million barrels of oil equivalent (“MMBOE”) at December 31, 2010, compared to 0.4 MMBOE at year end 2009. Proved Reserves in Utah net to Harvest increased to 4.6 MMBOE at December 31, 2010, compared to 0.4 MMBOE at year end 2009. Proved, Probable and Possible (“3P”) reserves net to Harvest in Utah increased to 86.4 MMBOE at December 31, 2010, compared to 0.4 MMBOE at year end 2009. These reserve additions are the result of our successful Antelope project delineation drilling programs conducted during 2010 and ongoing in 2011 in the Lower Green River/Upper Wasatch and Monument Butte Extension.
          In addition, we are reporting a reserve increase attributed to Petrodelta. 2P reserves, net to our 32 percent interest, have increased to 103.6 MMBOE at December 31, 2010, a 24 percent increase over year end 2009. Proved reserves, net to our 32 percent interest, increased to 50.0 MMBOE at December 31, 2010, an eight percent increase over year end 2009. 3P reserves remain virtually unchanged from last year. These reserve additions are the result of successful recent drilling and the extension of Block 5, a previously unproven fault block in the El Salto field and recent development drilling success in other fields.
          In February 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes due March 1, 2013, which resulted in net proceeds to us, after deducting underwriting discounts, commissions and estimated offering expenses, of approximately $30.0 million.
          In May 2010, our shareholders approved the 2010 Long Term Incentive Plan (the “2010 Plan”). The Plan provides for the issuance of up to 1,700,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”), restricted stock, restricted stock units (“RSUs”) and other stock-based awards to eligible participants including employees, non-employee directors and consultants of our Company or subsidiaries.

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See Item 15 — Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 7 — Stock Option and Stock Purchase Plans for a description of the terms of the 2010 Plan.
          In July 2010, we executed a farm-out agreement with the private third party in the JEDA for the acquisition of an incremental 10 percent interest in the Antelope Project with an effective date of July 1, 2010. This acquisition includes all leases, the Mesaverde, the Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) and the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”). The acquisition excludes the initial eight wells previously drilled in the Monument Butte Extension. This acquisition increases our ownership in the Antelope project to 70 percent.
          In August 2010, Petrodelta’s board of directors declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received October 22, 2010. The dividend represents 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under International Financial Reporting Standards (“IFRS”) for the year ended December 31, 2009.
          In September 2010, our partner in the Budong-Budong Production Sharing Contract (“Budong PSC”) exercised their option to increase our acquisition commitment carry obligation by $2.7 million from $17.2 million to a total of $19.9 million ($7.9 million for acquisition of seismic and $12.0 million for drilling). The additional carry increases our ownership by 7.4 percent to 54.4 percent. The change in ownership interest was approved on March 3, 2011 by the Government of Indonesia and BPMIGAS, Indonesia’s oil and gas regulatory authority.
          In October 2010, we announced the closing of a $60.0 million term loan facility with MSD Energy Investments Private II, LLC (“MSD Energy”), an affiliate of MSD Capital, L.P., as the sole lender under the term loan facility. Under the terms of the term loan facility, interest is paid on a monthly basis at the initial rate of 10 percent and the term loan will mature on October 28, 2012. The net proceeds of the term loan facility were approximately $59.5 million, after deducting fees related to the transaction.
          In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under IFRS for the year ended December 31, 2009. This dividend is subject to shareholder approval, and will not be accrued on our consolidated balance sheet until Petrodelta shareholder approval is received. Shareholder approval was received on March 14, 2011.
          On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator of the Budong PSC to a third party, which has allowed us to acquire an additional 10 percent equity in the Budong PSC. Closing of this acquisition, which is subject to the approval of the Government of Indonesia and BPMIGAS, will increase our interest in the Budong PSC to 64.4 percent.
          On January 28, 2011, our minority equity investment in Fusion Geophysical, L.L.C.’s (“Fusion”) 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. We received $1.3 million for our equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full of the outstanding balance of the prepaid service agreement, short term loan and accrued interest.
          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 2010.
          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 and the opening of our London and Singapore offices, we have made significant investments to provide the necessary foundation and global reach required for an organic growth focus. While exploration will become a larger part of our overall portfolio, we generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles.
          We intend to use our available cash to pursue additional growth opportunities in the United States, Indonesia, Gabon, Oman, China and other countries that meet our strategy. However, the execution of this strategy may be limited by factors including access to additional capital and the receipt of dividends from Petrodelta as well as the need to preserve adequate development capital in the interim. As described in Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity, in February 2010, we incurred indebtedness of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes, and in October 2010, we announced the closing of a $60.0 million term loan facility with MSD

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Energy as the sole lender under the term loan facility. We intend to use the net proceeds from the senior convertible notes and the term loan facility to fund capital expenditures, 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.
Reserves
          In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting. Under the SEC’s final rule, reserves reported prior to 2009 were not restated. The primary impact of the SEC’s final rule on our reserve estimates is 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.
          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.

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          In Venezuela during 2010, Petrodelta drilled 16 wells. Six of the wells were previously identified Proved Undeveloped (“PUD”) locations and ten wells were previously classified Probable, Possible or undefined. In 2010, an additional 24 PUD locations were identified through drilling activity. At December 31, 2010, Petrodelta had a total of 182 PUD locations identified. Petrodelta’s 2010 business plan, as approved by PDVSA, contemplates sustained drilling activities through the year 2024 to fully develop the El Salto and Temblador fields. In accordance with this revised development plan for Petrodelta, HNR Finance has elected to report a portion of their PUDs to be developed past a five year window. Most PUD locations are scheduled to be drilled within five years of their first identification; however, there are some PUD locations that are scheduled to be drilled more than five years after the PUD locations were first identified. At December 2010, the proportion of proved reserves expected to be drilled in the sixth year after initial booking is 21 percent of Proved (BOE) reserves and the proportion drilled in the seventh year is two percent of Proved (BOE) reserves. As a noncontrolling interest shareholder in Petrodelta, HNR Finance has limited ability to control the development plans that are periodically prepared and/or approved by the Venezuelan government. Since this constraint represents a hindrance to development not experienced by typical operations, inclusion of a portion of the activities planned for year six and seven represents a fair comparison to operators with assets covered by more flexible regulatory conditions where increasing rig count can ameliorate a slow development plan.
          In the United States, at December 31, 2009, we had three Proved Developed wells and five PUD locations identified in the Monument Butte area. During 2010, we identified and approved the development of 41 further locations. A total of 13 wells have been moved to Proved Developed Producing (“PDP”) in 2010 including the five PUDs identified at December 31, 2009, and eight other wells. This results in a total of 16 PDP wells and 43 identified PUD locations at December 31, 2010. We do not have PUDs to be developed past a five year window as this is a relatively new geographic area for us. We have been developing the area since 2009.
          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, 2010.

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    Oil and     Natural        
    NGLs     Gas     Total  
    (MBls)     (MMcf)     (MBOE)(1)  
Proved Developed Reserves:
                       
Domestic — Utah
    658       2,476       1,071  
International — Venezuela(2)
    13,074       18,281       16,121  
 
                 
Total Proved Developed
    13,732       20,757       17,192  
 
                 
 
                       
Proved Undeveloped Reserves:
                       
Domestic — Utah
    2,856       4,016       3,525  
International — Venezuela(2)
    28,610       31,774       33,906  
 
                 
Total Proved Undeveloped
    31,466       35,790       37,431  
 
                 
 
                       
Total Proved Reserves
    45,198       56,547       54,623  
 
                 
 
                       
Probable Developed Reserves:
                       
Domestic — Utah
    46       95       62  
International — Venezuela(2)
    132       54       141  
 
                 
Total Probable Developed
    178       149       203  
 
                 
 
                       
Probable Undeveloped Reserves:
                       
Domestic — Utah
    8,496       12,709       10,614  
International — Venezuela(2)
    50,909       15,339       53,466  
 
                 
Total Probable Undeveloped
    59,405       28,048       64,080  
 
                 
 
                       
Total Probable Reserves
    59,583       28,197       64,283  
 
                 
 
                       
Possible Developed Reserves:
                       
Domestic — Utah
    91       207       126  
International — Venezuela(2)
    9             9  
 
                 
Total Possible Developed
    100       207       135  
 
                 
 
                       
Possible Undeveloped Reserves:
                       
Domestic — Utah
    52,526       110,616       70,962  
International — Venezuela(2)
    111,548       32,371       116,943  
 
                 
Total Possible Undeveloped
    164,074       142,987       187,905  
 
                 
 
                       
Total Possible Reserves
    164,174       143,194       188,040  
 
                 
 
(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 as of December 31, 2010, 2009 and 2008 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 Operation — Critical Accounting Policies for additional information on our reserves.
Operations
          Since April 1, 2006, our Venezuelan operations have been conducted through our equity affiliate Petrodelta which is governed by the Contract of Conversion (“Conversion Contract”) signed on September 11, 2007. All of the equity investment in HNR Finance and Harvest Vinccler is owned by Harvest-Vinccler Dutch Holding B.V., a Netherlands private company with limited liability. We own an 80 percent equity investment in Harvest-Vinccler Dutch Holding B.V. The remaining 20 percent noncontrolling interest is owned by Vinccler. 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 to 70 percent interest in the Antelope prospect in the

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Western United States covered by a JEDA, a 54.4 percent interest in the 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. See Item 1 — Business, United States; Budong-Budong, Onshore Indonesia; Dussafu Marin, Offshore Gabon, Block 64 Project, Oman, and WAB-21, South China Sea for a more detailed description.
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. 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. As of March 7, 2011, the 2011 budget for Petrodelta’s business plan had not yet been approved by its shareholders. Since Petrodelta only executed approximately 50 percent its 2010 budget primarily due to lack of funding by PDVSA, we do not believe that PDVSA will be able to provide the support required to execute Petrodelta’s proposed 2011 budget.
          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.
          Petrodelta shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Petrodelta’s focus in 2010 included utilizing two rigs to drill both development and appraisal wells for both maintaining production capacity and appraising the substantial resource base in the El Salto field. Petrodelta contracted a workover rig in October 2010. Petrodelta began engineering work for expanded production facilities to handle the expected production from the development and appraisal wells that were expected to be drilled in 2010.
          During 2010, Petrodelta drilled and completed 16 development wells, produced approximately 8.6 million barrels (“MBbl”) of oil and sold 2.2 billion cubic feet (“BCF”) of natural gas. Petrodelta produced an average of 23,455 barrels of oil per day (“BOPD”) during 2010. Petrodelta also began the pre-engineering work for production facilities required for the full development of the El Salto field. Due to delays in rig availability, El Salto facilities project execution and lack of funding by PDVSA, Petrodelta only spent $101.8 million of its 2010 capital budget of $205.0 million.
          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 expected PDVSA to continue requesting and receiving waivers, Petrodelta did not accrue a liability to LOCTI for the year ended December 31, 2009. For filing years 2007 and 2008, PDVSA

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provided Petrodelta with a copy of the waiver acceptance letter from LOCTI. PDVSA has stated that a waiver was granted for filing year 2009; however, LOCTI has not yet issued the acceptance letter to PDVSA for the 2009 filing year. The potential exposure to LOCTI for the year ended December 31, 2009 after devaluation is $4.8 million, $2.4 million net of tax ($0.8 million net to our 32 percent interest). In January 2011, PDVSA informed its consolidating entities, including Petrodelta, that effective with the 2010 reporting year it would no longer be requesting waivers to file the LOCTI declaration on a consolidated basis. Based on this information, Petrodelta accrued the 2010 liability to LOCTI in the amount of $4.6 million, $2.3 million net of tax ($0.7 million net to our 32 percent interest). In December 2010, LOCTI was modified to reduce the amount of contributions beginning January 2011 to one percent of gross revenues for companies owned by individuals or corporations and 0.5 percent for companies owned by Venezuela. Petrodelta’s rate of contribution starting in 2011 will be 0.5 percent.
          In 2008, the Venezuelan government published in the Official Gazette the Law of Special Contribution to Extraordinary Prices at the Hydrocarbons International Market (“Windfall Profits Tax”). The Windfall Profits Tax is to be calculated on the Venezuelan Export Basket (“VEB”) of prices as published by the Ministry of the People’s Power for Energy and Petroleum (“MENPET”). As instructed by CVP, Petrodelta has applied the Windfall Profits Tax to gross oil production delivered to PDVSA. The 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 Windfall Profits Tax is reported as expense on the income statement and is deductible for Venezuelan tax purposes. Petrodelta recorded $14.1 million and $0.9 million of expense for the Windfall Profits Tax for the years ended December 31, 2010 and 2009, respectively.
          In 2009, under instructions issued by CVP, Petrodelta set up a reserve within the equity section of the balance sheet for deferred tax assets. 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. Dividends received prior to 2009 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.
          On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement, which established new exchange rates for the Venezuela Bolivar (“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 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 4.30 Bolivar exchange rate applies to the oil and gas sector. On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate with an effective date of January 1, 2011. 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.
          In August 2010, Petrodelta’s board of directors declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received October 22, 2010. The dividend represents 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under IFRS for the year ended December 31, 2009.
          In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under IFRS for the year ended December 31, 2009. This dividend is subject to shareholder approval, and will not be accrued on our consolidated balance sheet until Petrodelta shareholder approval is received. Shareholder approval was received on March 14, 2011.

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Location and Geology
Petrodelta Fields
Uracoa Field
          There are currently 83 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 14 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.
Bombal Field
          East Bombal was drilled in 1992, and currently remains underdeveloped. During 2010, three oil producing wells were reactivated and are producing in the West Bombal field. The oil is transported through Petrodelta’s pipelines from the West Bombal field to the Uracoa plant facilities. 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 25 oil producing wells in the field. The fluid produced from Temblador field flows through two flow stations operated by Petrodelta. During 2010, Petrodelta completed the pipeline network necessary to completely segregate all of Petrodelta’s production out of PDVSA’s system. As of October 1, 2010, 100 percent of the Temblador field’s production was flowing through Petrodelta pipelines directly into PDVSA’s sales delivery facilities. 3-D seismic is available over the entire field.
El Salto Field
          The El Salto field was discovered in 1936. Currently there are three oil producing wells 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. During 2010, the ELS-33 well was drilled and completed in the Lower Jobo sand and began producing on September 1, 2010. The ELS-33 also drilled a pilot hole which encountered a full column of oil in a block that was previously unpenetrated and represented a significant expansion of Block 5 in El Salto field not included in the 2009 reserve report. The ELS-34 well was drilled and completed in the Lower Jobo sand of the newly identified Block 5 extension and began production in September 2010. The produced oil is transported through temporary facilities to Uracoa plant facilities. The ELS-33 and ELS-34 wells were restricted in their production rate due to limitations in the temporary facilities.
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.

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          Petrodelta has a 64-mile pipeline from Uracoa with a nominal 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
          As of March 7, 2011, the 2011 budget for Petrodelta’s business plan had not yet been approved by its shareholders. Since Petrodelta only executed approximately 50 percent its 2010 budget primarily due to lack of funding by PDVSA, we do not believe that PDVSA will be able to provide the support required to execute Petrodelta’s proposed 2011 budget. However, Petrodelta’s 2011 proposed business plan includes a planned drilling program to utilize two rigs to drill both development and appraisal wells for maintaining production capacity, the continued appraisal of the substantial resource base in the El Salto field and appraising the presently non-producing Isleño field. It also includes engineering work for production facilities required for the full development of the El Salto field.
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
          In 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.
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. 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. We are the operator and have an initial working interest of 50 percent in West Bay, the second prospect in the AMI. The first prospect in the AMI was abandoned in 2009 after a dry hole was drilled. The private third party contributed these two prospects, including 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. The funding obligation was met during 2009, and all costs are now being shared by the parties in proportion to their working interests as defined in the AMI.
          The private third party is obligated to evaluate and present additional opportunities at their sole cost. As each prospect is accepted, it will be covered by the AMI.
Location and Geology
          The AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana, including state waters. In February 2011, the previously existing Alligator Point Unit (as approved by the Texas General Land Office [“GLO”]) expired. We have obtained from the GLO an extension until September 1, 2011 of a smaller version of the Alligator Point Unit defined more specifically by the drilling prospects currently existing on the project. As a result of the GLO approval of the smaller Alligator Point Unit and the anticipated expiry of five leases previously held by the larger unit, we expect our lease position on the West Bay project to be reduced from approximately 13,000 acres in February 2011 to approximately 10,050 acres in August 2011.

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Drilling and Development Activity
          During the year ended December 31, 2010, operational activities in the West Bay prospect focused on firming up plans for drilling on the identified initial drilling prospect and continuing to evaluate the other leads and prospects in the project. Land, regulatory and surface access preparations currently in progress are focused on taking the initial drilling prospect to drill-ready status. During 2010, we finalized a 3-D seismic data trade with a third party and merged the data set with our existing seismic data. The acquisition and merging of the additional 3-D seismic data allows for more complete technical evaluation of the leads and prospects identified in the project. Based on the merged seismic data set, we now have four identified drilling prospects on our acreage. Preliminary work is underway on a drilling barge concept that will be utilized to drill the first two exploration wells. Current plans are to drill the first exploration well in 2011, pending required surface access agreements with a private landowner and pending receipt of necessary permits from the U.S. Army Corps of Engineers.
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 was obligated to assemble the initial 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.
          In July 2010, we executed a farm-out agreement with the private third party in the JEDA for the acquisition of an incremental 10 percent interest in the Antelope Project with an effective date of July 1, 2010. This acquisition includes all leases, the Mesaverde, the Lower Green River/Upper Wasatch and the Monument Butte Extension. The acquisition excludes the initial eight wells previously drilled in the Monument Butte Extension. Total consideration for the incremental 10 percent interest is $20.0 million, of which (1) $3.0 million was paid on August 2, 2010 (the closing date of the acquisition); (2) $3.0 million to be used as a credit against future joint interest billings or if joint interest billings do not accumulate to $3.0 million by October 1, 2010, at the sole election of the private third party, the balance is to be paid by us within 15 days of receipt of written request from the private third party; and (3) a capped $14.0 million carry of a portion of our partner’s exploration and development cost obligations in the upcoming Lower Green River/Upper Wasatch and Monument Butte Extension drilling programs in the Antelope project. On October 1, 2010, the private third party elected to receive in cash the remaining balance of the joint interest billing credit of $2.4 million. At December 31, 2010, the outstanding balance on the $14.0 million exploration and development cost obligation carry is $8.4 million. Based on current plans, we anticipate the full carry obligation will be met in the first half of 2011. This acquisition increases our ownership in the Antelope project to 70 percent.
General
          The Antelope project is targeted to explore for and develop oil and natural gas from multiple reservoir horizons in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties. Leads and/or prospects were identified in three prospective reservoir horizons in preparation for drilling.

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Mesaverde
Drilling and Development Activity
          Operational activities during the year ended December 31, 2010 included completion of the initial testing activities on the Mesaverde horizons in the deep natural gas test well (the Bar F) that commenced drilling on June 15, 2009. The Bar F was drilled to a total depth of 17,566 feet and an extended production test of the Mesaverde has been completed. Testing was 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. Gas was tested at flow rates of 1.5-2 million cubic feet per day (“MMCFD”) from selected intervals. While the results to date have not definitively determined the commerciality of a stand-alone development of the Mesaverde in the current gas price environment, we believe that the test results confirm that the Mesaverde formation exhibits sufficient quantities of hydrocarbons and reservoir over-pressure to justify potential development, and we are actively pursuing efforts to assess whether reserves can be attributed to this reservoir. The Mesaverde reservoir remains potentially prospective over a portion of our land position. Exploratory drilling costs for the Mesaverde have been suspended pending further evaluation.
Lower Green River/Upper Wasatch
General
          The Lower Green River/Upper Wasatch is a second prospective horizon that is being pursued in the Antelope project. After completion of the initial testing program on the Mesaverde deep gas in the Bar F well as described above, we moved uphole in the same well to test multiple oil bearing intervals at depths from 8,200 feet to 9,500 feet in the Lower Green River and Upper Wasatch formations. Extended flow testing of the well conducted during the second quarter of 2010 indicated that a commercial oil discovery was made in the Lower Green River and Upper Wasatch. A five-well Lower Green River/Upper Wasatch delineation and development drilling program was planned to further delineate and appraise the extent of the Lower Green River/Upper Wasatch discovery made in the Bar F, and to establish additional production from the Lower Green River/Upper Wasatch reservoirs in at least some of the five appraisal wells. Based on results of the initial wells in the five well delineation and development drilling program, an additional sixth well was added to the program to be drilled in early 2011.
          On December 21, 2010, we and our partner in the Antelope project entered into a contract with El Paso Midstream Group, Inc. (“EPMG”) whereby EPMG will provide the capital to build and operate a 25-mile, low-pressure gas gathering pipeline which will provide capacity for our current and future production from the Lower Green River/Upper Wasatch Development project. We will provide capital to build flowlines to connect the produced gas from our wells into the EPMG header system. As part of the contract arrangement, we and our partner have dedicated approximately 75 percent of our Antelope leasehold to the El Paso contract for 10 years, with a Harvest option to extend the dedication for up to an additional nine years without any change in contract terms. The area dedication is limited stratigraphically to the top of the Mesaverde formation, resulting in the Mesaverde deep gas not being included in the dedication.
Location and Geology
          The Lower Green River/Upper Wasatch covers approximately 37,000 Harvest net acres located on the northern portion of our Antelope land position and includes the Lower Green River/Upper Wasatch formations. The Lower Green River/Upper Wasatch formations are productive in the Altamont/Bluebell oil field approximately six miles north of the Bar F well.
Drilling and Development Activity
          The five-well delineation and development drilling program was initiated in the third quarter of 2010. The original five wells were in varying stages of completion and drilling and production facilities installation as of December 31, 2010:
    Two wells, the Kettle #1-10-3-1 and the ON Moon #1-27-3-2, are completed and currently on production.

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    One well, the Dart #1-12-3-2, is drilled and being hydraulically fractured.
 
    One well, the Giles #1-19-3-2, is drilled and waiting on fracturing.
 
    One well, the Yergensen #1-9-3-1, was spud using a spud rig and is waiting on the drilling rig.
          Three additional wells have been incorporated into our planning for the next round of development drilling in the Lower Green River/Upper Wasatch. Two of the additional wells, the Lamb #1-19-3-1 and the Yergensen #1-18-3-1, were spud using a spud rig and have been drilled to surface casing depth only and surface casing installed.
          During the fourth quarter of 2010, we also initiated permitting activities on a planned 170 square mile 3-D seismic acquisition program which is expected to be acquired in late 2011 and which will be targeted at imaging the Green River and Wasatch formations over the northern portion of our acreage.
Monument Butte
General
          The Monument Butte Extension was initiated in the fourth quarter of 2009 with an eight well appraisal and development drilling program to produce oil and natural gas from the Green River formation. The parties participating in the wells formed a 320 acre AMI, which contained the initial eight drilling locations.
          As a follow up to the successful completion of the initial eight well program that was drilled in late 2009 and early 2010, a six well appraisal and development drilling program was approved during 2010. The six well expansion is on acreage immediately adjacent to the initial eight well program.
          The first 14 wells in the Monument Butte Extension (as defined above) are non-operated. We hold a 43 percent working interest in the initial eight wells and an approximate 37 percent working interest in the follow-up six wells.
          During 2010, an additional Harvest operated well, the K Moon #2-13-4-3, was added to the project. We have an approximate 60 percent working interest in the well. As of December 31, 2010, the K Moon #2-13-4-3 had been spud using a spud rig, drilled to casing depth only and surface casing installed.
Location and Geology
          The Monument Butte Extension covers approximately 12,000 Harvest net acres located on the southern portion of our Antelope land position primarily in the Green River formation.
Drilling and Development Activity
          Operational activities during 2010 for the Monument Butte Extension consisted of completion of drilling and completion of wells followed by routine production operations from the initial eight wells and implementation of the six well expansion program in third quarter 2010. Five of the six wells were drilled and four were on production as of December 2010. The sixth and final well spud on February 3, 2011. Also, in the fourth quarter of 2010, we spud the Harvest operated K Moon #2-13-4-3 with a spud rig.
Budong-Budong, Onshore Indonesia
General
          In December 2007, we entered into a Farmout Agreement to acquire a 47 percent interest in the Budong PSC located mostly onshore West Sulawesi, Indonesia. In April 2008, the Government of Indonesia approved the assignment to us of the 47 percent interest in the Budong PSC. Our partner is the operator through the exploration phase as required by the terms of the Budong PSC, and we have an option to become operator, if approved by Government of Indonesia and BPMIGAS in any subsequent development and production phase.

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          We acquired our original 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, under a Farmout Agreement with the operator of the Budong PSC. Under the Farmout Agreement, the initial commitment was to fund the first phase of the exploration program up to a cap of $17.2 million. The commitment cap was comprised of $6.5 million for the acquisition of seismic and $10.7 million for the drilling of the first two exploratory wells. After the commitment cap of each component was met, all subsequent costs are shared by the parties in proportion to their ownership interests. Prior to drilling the first exploration well, our partner had a one-time option to increase the level of the carried interest to a maximum of $20.0 million. On September 15, 2010, our partner exercised their option to increase the carry obligation by $2.7 million to a total of $19.9 million ($7.9 million for acquisition of seismic and $12.0 million for drilling). The additional carry increased our ownership by 7.4 percent to 54.4 percent. The change in ownership interest was approved on March 3, 2011 by the Government of Indonesia and BPMIGAS. As of February 28, 2011, we had fulfilled all funding obligations to earn our 54.4 percent interest in the Budong PSC.
          On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator to a third party, to acquire an additional ten percent equity in the Budong PSC for a consideration of $3.7 million payable ten business days after completion of the first exploration well. Closing of this acquisition will increase our interest in the Budong PSC to 64.4 percent. The change in ownership interest is subject approval from the Government of Indonesia and BPMIGAS.
Location and Geology
          During the initial exploration period, the Budong PSC covered 1.35 million acres. The term of the Budong PSC is for 30 years and provides for an exploration period of up to ten years. Pursuant to the Budong PSC, at the end of the first three-year exploration phase, 35 percent of the original area was relinquished to BPMIGAS. The second three-year exploration phase began in January 2010 covering 0.88 million acres. The Budong PSC includes the Lariang and Karama sub-basins, which are the eastern onshore extension of the West Sulawesi foldbelt (“WSFB”). Exploration activity to date in the basins 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 ten 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 offshore seismic surveys have greatly improved the understanding of the geology and enhanced the prospectivity of the offshore WSFB and, by analogy, the sparsely explored onshore area.
Drilling and Development Activity
          Operational activities during 2010 focused on well planning, construction for two exploratory well sites, and mobilization of rig and ancillary equipment to the first drill site. After delays in acquiring permits to mobilize the drilling rig from its port location to the drilling pad, the first exploratory well, the Lariang-1 (“LG-1”), was spud on January 6, 2011.
Dussafu Marin, Offshore Gabon
General
          We are the operator of the Dussafu PSC with a 66.667 percent ownership interest.
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.

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Drilling and Development Activity
          The Dussafu PSC partners and Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources, entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. It was agreed that the second three-year exploration phase be extended until May 27, 2011, at which time the partners can elect to enter a third exploration phase. Operational activities during 2010 included the maturation of the prospect inventory and well planning. We have issued purchase orders for long lead items required for drilling. Other drilling contracts are being tendered in preparation to spud the exploration well in the second quarter of 2011. The exploratory well to be drilled in the second quarter of 2011 will test stacked reservoir potential in the pre-salt section. A Letter of Intent has been agreed for a semi-submersible rig to commence a contract in April 2011 to drill the Ruche Marin prospect. In order to be able to complete the drilling activities, a six month extension to November 27, 2011 of the second Exploration Period has been requested.
Oman
General
          In 2009, we signed an EPSA with Oman for the Al Ghubar/Qarn Alam license (“Block 64 EPSA”). We have a 100 percent working interest in Block 64 EPSA during the exploration phase. Oman Oil Company has the option to back-in to up to a 20 percent interest in Block 64 EPSA after the discovery of gas.
Location and Geology
          Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate which the Oman Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). The 955,600 acre 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 shallow oil 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. Operational activities during 2010 included geological studies, baseline environmental and social study, and 3-D pre-stack depth migration reprocessing of approximately 1,150 square kilometers of existing 3-D seismic data. During 2011, geological and geophysical interpretation of the reprocessed 3-D seismic data will take place to mature drilling locations. Well planning and procurement of long lead items is expected to commence in 2011 in anticipation of drilling the first of the two exploratory wells.
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 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. Although 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, there has been a small increase in exploration activity in the area starting in 2009.
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)

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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 MBl 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. We are in the process of obtaining a new license extension and believe that it will be granted. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist.
          In 2009, Vietnam, along with the company that is the party to the agreement with Vietnam, announced plans for exploration drilling during 2010. In the first quarter of 2010, the planned 2010 exploration drilling was postponed due to internal funding constraints. Vietnam has also stated that seismic was shot during 2010 and additional seismic may be shot in 2011. While no assurance can be given, we believe these activities 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, 2010, 2009 and 2008. The presentation for 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,  
    2010     2009     2008  
Venezuela
                       
Crude Oil Production (MBbls)(b)
    1,826       1,671       1,174  
Natural Gas Production (MMcf)(a)(c)
    470       938       2,283  
Average Crude Oil Sales Price ($per Bbl)
  $ 70.57     $ 57.62     $ 83.22  
Average Natural Gas Sales Price ($per Mcf)
  $ 1.54     $ 1.54     $ 1.54  
Average Operating Expenses ($per BOE)(d)
  $ 6.01     $ 5.64     $ 10.65  
United States
                       
Monument Butte
                       
Net Crude Oil Production (MBbls)
    106       3        
Natural Gas Production (MMcf)
    417       6        
Average Crude Oil Sales Price ($per Bbl)
  $ 64.85     $ 61.57     $  
Average Natural Gas Sales Price ($  per Mcf)
  $ 3.43     $ 2.77     $  
Average Operating Expenses ($  per BOE)(e)
  $ 4.26     $     $  
Lower Green River/Upper Wasatch
                       
Net Crude Oil Production (MBbls)
    34              
Natural Gas Production (MMcf)
    6              
Average Crude Oil Sales Price ($per Bbl)
  $ 69.63     $     $  
Average Natural Gas Sales Price ($  per Mcf)
  $ 3.97     $     $  
Average Operating Expenses ($  per BOE)(e)
  $ 25.41     $     $  
 
(a)   Royalty-in-kind paid on gas used as fuel by Petrodelta net to our 32 percent interest was 1,015 MMcf, 1,063 MMcf and 1,226 MMcf for 2010, 2009 and 2008, respectively.
 
(b)   Crude oil sales net to our 32 percent interest after deduction of royalty. Crude oil sales for Petrodelta at 100 percent was 8,561 MBbls, 7,835 MBbls and 5,505 MBbls for 2010, 2009 and 2008, respectively.
 
(c)   Natural gas sales net to our 32 percent interest after deduction of royalty. Natural gas sales for Petrodelta at 100 percent was 2,204 MMcf, 4 397 MMcf and 10,700 MMcf for 2010, 2009 and 2008, respectively.
 
(d)   Before royalties and including workovers. Petrodelta is not subject to ad valorem or severance taxes. Average operating expenses per BOE net of royalties and workovers was $7.52, $8.46 and $10.90 for 2010, 2009 and 2008, respectively.
 
(e)   Excluding ad valorem and 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) $59.6 million, $28.0 million and $26.3 million in 2010, 2009 and 2008, respectively. These numbers do not include any costs for the development of proved undeveloped reserves in 2010, 2009 or 2008.

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     We have participated in the drilling of wells as follows:
                                                 
    Year Ended December 31,  
    2010     2009     2008  
    Gross     Net     Gross     Net     Gross     Net  
Wells Drilled:
                                               
Venezuela (Petrodelta)
                                               
Development
    16       5.1       15       4.8       9       2.9  
Appraisal
                2       0.6              
United States
                                               
Development
    8       2.6       5       2.1              
Exploration
    3       1.0       1       1.0       1       1.0  
 
                                               
Average Depth of Wells (Feet) Venezuela (Petrodelta)
                                               
Crude Oil
          6,839             6,500             6,500  
United States
                                               
Crude Oil
          7,938             6,751              
Natural Gas
                      17,566             12,290  
 
                                               
Producing Wells (1):
                                               
Venezuela (Petrodelta)
                                               
Crude Oil
    127       40.6       114       36.5       118       37.8  
United States
                                               
Crude Oil
    16       8.3       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, 2010:
                                 
    Developed     Undeveloped  
    Gross     Net     Gross     Net  
Venezuela — Petrodelta
    24,330       7,786       222,783       71,291  
China
                7,470,080       7,470,080  
United States:
                               
West Bay
                12,808       6,437  
Antelope
    2,422       1,549       136,362       46,842  
Indonesia
                883,636       480,698  
Gabon
                685,470       456,982  
Oman
                955,600       955,600  
 
                       
Total
    26,752       9,335       10,366,739       9,487,930  
 
                       
          Our intention is to renew all leases that are due to expire in the next three years.

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Regulation
General
          Our operations and our ability to finance and fund our growth strategy are affected by political developments and laws and regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are affected by:
    change in governments;
 
    civil unrest;
 
    price and currency controls;
 
    limitations on oil and natural gas production;
 
    tax, environmental, safety and other laws relating to the petroleum industry;
 
    changes in laws relating to the petroleum industry;
 
    changes in administrative regulations and the interpretation and application of such rules and regulations; and
 
    changes in contract interpretation and policies of contract adherence.
          In any country in which we may do business, the oil and natural gas industry legislation and agency regulation are periodically changed, sometimes retroactively, for a variety of political, economic, environmental and other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and our potential for economic loss.
Competition
          We encounter substantial competition from major, national and independent oil and natural gas companies in acquiring properties and leases for the exploration and development of crude oil and natural gas. The principal competitive factors in the acquisition of such oil and natural gas properties include staff and data necessary to identify, investigate and purchase such properties, the financial resources necessary to acquire and develop such properties, and access to local partners and governmental entities. Many of our competitors have influence, financial resources, staffs, data resources and facilities substantially greater than ours.
Leases
          A significant number of our domestic oil and gas leases cover tribal and allottee mineral interests, with the leases being administered by the Bureau of Indian Affairs (the “BIA”). The Bureau of Land Management (the “BLM”) oversees and approves certain activities/operations of the leases. BIA leases contain relatively standardized terms and require compliance with detailed BLM or BIA regulations. Many leases contain stipulations limiting activities that may be conducted on the lease. Some stipulations are unique to particular geographic areas and may limit the time during which activities on the lease may be conducted, the manner in which certain activities may be conducted or, in some cases, may ban surface activity. Under certain circumstances, the BLM or the BIA, as applicable, may require that our operations on leases be suspended or terminated. Any such suspension or termination could materially and adversely affect our consolidated financial condition, results of operations or cash flows.
State and Local Regulation of Drilling and Production
          We own interests in properties located in Utah and Texas. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells.

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Environmental Regulations
          Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The cost of compliance could be significant. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial and damage payment obligations, or the issuance of injunctive relief (including orders to cease operations). Environmental laws and regulations are complex, and have tended to become more stringent over time. We also are subject to various environmental permit requirements. Onshore drilling in certain areas has been opposed by environmental groups and, in certain areas, has been restricted. Moreover, some environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties. To the extent laws are enacted or other governmental action is taken that prohibits or restricts onshore drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected.
          The Resource Conservation and Recovery Act (“RCRA”), generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy,” the Environmental Protection Agency (“EPA”) and state agencies may regulate these wastes as solid wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.
International Regulations
          Our exploration and production operations outside the United States are subject to various types of regulations similar to those described above imposed by the respective governments of the countries in which we operate, and may affect our operations and costs within that country. We currently have operations in Indonesia, Gabon, Oman and China.
Employees
          At December 31, 2010, our Houston office had 25 full-time employees. Our Utah, Caracas, London, Singapore, Jakarta and Muscat offices had 3, 14, 7, 2, 4 and 3 employees, respectively. We augment our employees from time to time with independent consultants, as required.
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, 2010, we had $58.7 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 capital 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, success with our exploration program, possible delay of discretionary capital spending to future periods, or possible sale, farm-out or otherwise monetization of assets as necessary to maintain the liquidity required to run our operations. While we believe that Petrodelta will reinvest any excess cash which might be available for payment of dividends into Petrodelta in 2011 and 2012, 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. On October 29, 2010, we closed a $60.0 million term loan facility that will mature on October 28, 2012 and has an initial rate of interest of 10 percent. The initial rate of interest increases to 15 percent on July 28, 2011. Prior to February 2010, 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 debt;
 
    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;
 
    limit our flexibility in planning for, or reacting to, changes in our business; and
 
    require the use of a substantial portion of working capital.
          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.
          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 or the work program may include minimum funding requirements to keep the contract. We may not have the funds available to meet the minimum funding requirements when they come due and be required to forfeit the contracts.
          Our strategy to identify, access and integrate hydrocarbon assets in known hydrocarbon basins globally carries greater deal execution, operating, financial, legal and political risks. The environments in which we operate are often difficult and the ability to operate successfully will depend on a number of factors, including our ability to control the pace of development, our ability to apply “best practices” in drilling and development, and the fostering of productive and transparent relationships with local partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, often the legal systems of these countries are not mature and their reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and natural gas projects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy depends on our ability to have significant influence over operations and financial control.
          Operations in areas outside the United States are subject to various risks inherent in foreign operations. Our operations are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and governmental royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts or tribunals, renegotiation of contracts with governmental entities, changes in laws and policies, including taxes, governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign policy, foreign trade, taxation and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States.
          Operations on the Uintah and Ouray Reservation of the Ute Indian Tribe in the western United States are subject to various risks similar to those for foreign operations. Similar to our operations in foreign jurisdictions, our operations on the Uintah and Ouray Reservation of the Ute Indian Tribe are subject to certain risks. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as

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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.
          There is limited refining capacity for our yellow and black wax crude oil, which may limit our ability to sell our current production or to increase our production at Lower Green River/Upper Wasatch and Monument Butte in the Uinta Basin. Most of the crude oil we produce in the Uinta Basin is known as “yellow wax” or “black wax” because it has higher paraffin content than crude oil found in most other major North American basins. Due to its wax content, most of the oil is transported by truck to refiners in the Salt Lake City area. We currently have agreements in place that provide a reasonable certainty of base load sales of substantially all of our expected production in the Uinta Basin through the end of 2011. In the current economic environment, there is a risk that they may fail to satisfy their obligations to us under those contracts. An extended loss of our largest purchaser could have a material adverse effect on us because there are limited purchasers of our black and yellow wax crudes. We continue to work with refiners to expand the market for our existing yellow and black wax crude oil production and to secure additional capacity to allow for production growth. However, without additional refining capacity, our ability to increase production from the fields may be limited.
          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

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gas reservoirs will be found. The cost of drilling and completing wells is often uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
    unexpected drilling conditions;
 
    pressure or irregularities in formations;
 
    equipment failures or accidents;
 
    weather conditions;
 
    shortages in experienced labor;
 
    delays in receiving necessary governmental permits;
 
    delays in receiving partner approvals;
 
    shortages or delays in the delivery of equipment;
 
    delays in receipt of permits or access to lands; and
 
    government actions or changes in regulations.
          The prevailing price of oil also affects the cost of and availability for drilling rigs, production equipment and related services. We cannot give any assurance that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs.
          Our oil and natural gas operations are subject to various governmental regulations that materially affect our operations. Our oil and natural gas operations are subject to various governmental regulations. These regulations may be changed in response to economic or political conditions. Matters regulated may include permits for discharges of wastewaters and other substances generated in connection with drilling operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on oil and natural gas production. In order to conserve or limit supplies of oil and natural gas, these agencies have restricted the rates of the flow of oil and natural gas wells below actual production capacity. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.
          We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Exploration and development and the production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:
    the amounts and types of substances and materials that may be released into the environment;
 
    response to unexpected releases to the environment;
 
    reports and permits concerning exploration, drilling, production and other operations;
 
    the spacing of wells;
 
    unitization and pooling of properties;
 
    calculating royalties on oil and natural 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.
     The oil and gas business involves many operating risks that can cause substantial losses, and insurance may not protect us against all of these risks. We are not insured against all risks. Our oil and gas

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exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the risk of:
    fires and explosions;
 
    blow-outs;
 
    uncontrollable or unknown flows of oil, gas, formation water or drilling fluids;
 
    adverse weather conditions or natural disasters;
 
    pipe or cement failures and casing collapses;
 
    pipeline ruptures;
 
    discharges of toxic gases;
 
    build up of naturally occurring radioactive materials; and
 
    vandalism.
          If any of these events occur, we could incur substantial losses as a result of:
    injury or loss of life;
 
    severe damage or destruction of property and equipment, and oil and gas reservoirs;
 
    pollution and other environmental damage;
 
    investigatory and clean-up responsibilities;
 
    regulatory investigation and penalties;
 
    suspension of our operations; and
 
    repairs to resume operations.
          If we experience any of these problems, our ability to conduct operations could be adversely affected.
          We maintain insurance against some, but not all, of these potential risks and losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not insurable.
          Potential regulations regarding climate change could alter the way we conduct our business. Changes to existing regulations or the adoption of new regulations may unfavorably impact us, our suppliers or our customers. For example, governments around the world have become increasingly focused on climate change matters. In the United States, legislation that directly impacts our industry has been proposed covering areas such as emission reporting and reductions, hydraulic fracturing, the repeal of certain oil and gas tax incentives and tax deductions, and the regulation of over-the-counter commodity hedging activities. These and other potential regulations could increase our costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business, negatively impacting our financial condition, results of operations and cash flows.
          In response to the recent oil spill in the Gulf of Mexico, the United States Congress is considering a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore that could result in significant additional laws or regulations governing our operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990.
          Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Additional costs or operating restrictions associated with legislation or regulations could have a material adverse effect on our operating results and cash flows, in addition to the demand for the natural gas and other hydrocarbon products that we produce.
          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

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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 do not directly manage operations of Petrodelta. PDVSA, through CVP, exercises substantial control over Petrodelta’s operations, making Petrodelta subject to some internal policies and procedures of PDVSA as well as being subject to constraints in skilled personnel available to Petrodelta. These issues may have an adverse effect on the efficiency and effectiveness of Petrodelta’s operations.
          We hold a minority equity investment in Petrodelta. Even though we have substantial negative control provisions as a minority equity investor in Petrodelta, our control of Petrodelta is limited to our rights under the Conversion Contract and its annexes and Petrodelta’s charter and bylaws. As a result, our ability to implement or influence Petrodelta’s business plan, assure quality control, and set the timing and pace of development may be adversely affected. In addition, the majority partner, CVP, has initiated and undertaken numerous unilateral decisions that can impact our minority equity investment.
          Petrodelta’s business plan will be sensitive to market prices for oil. Petrodelta operates under a business plan, the success of which will rely heavily on the market price of oil. To the extent that market values of oil decline, the business plan of Petrodelta may be adversely affected.
          A decline in the market price of crude oil could uniquely affect the financial condition of Petrodelta. Under the terms of the Conversion Contract and other governmental documents, Petrodelta is subject to a special advantage tax (“ventajas especiales”) which requires that if in any year the aggregate amount of royalties, taxes and certain other contributions is less than 50 percent of the value of the hydrocarbons produced, Petrodelta must pay the government of Venezuela the difference. In the event of a significant decline in crude prices, the ventajas especiales could force Petrodelta to operate at a loss. Moreover, our ability to control those losses by modifying Petrodelta’s business plan or restricting the budget is limited under the Conversion Contract.
          An increase in oil prices could result in increased tax liability in Venezuela affecting Petrodelta’s operations and profitability, which in turn could affect our dividends and profitability. Prices for oil fluctuate widely. On July 10, 2008, the Venezuelan government published the amended Windfall Profits Tax to be calculated on the VEB of prices as published by MENPET. The amended Windfall Profits Tax established a special 50 percent tax to the Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar manner, the percentage is increased from 50 percent to 60 percent when the average price of the VEB exceeds $100 per barrel. Any increase in the taxes payable by Petrodelta, including the Windfall Profits Tax, as a result of increased oil prices will reduce cash available for dividends to us and our partner, CVP.
          Oil price declines and volatility could adversely affect Petrodelta’s operations and profitability, which in turn could affect our dividends and profitability. Prices for oil also affect the amount of cash flow available for capital expenditures and dividends from Petrodelta. Lower prices may also reduce the amount of oil that we can produce economically and lower oil production could affect the amount of natural gas we can produce. We cannot predict future oil prices. Factors that can cause fluctuations in oil prices include:
    relatively minor changes in the global supply and demand for oil;
 
    export quotas;
 
    market uncertainty;
 
    the level of consumer product demand;
 
    weather conditions;
 
    domestic and foreign governmental regulations and policies;
 
    the price and availability of alternative fuels;
 
    political and economic conditions in oil-producing and oil consuming countries; and
 
    overall economic conditions.
     The total capital required for development of Petrodelta’s assets may exceed the ability of Petrodelta to finance such developments. Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Petrodelta’s future capital requirements for the development of its assets may exceed the cash available from existing cash flow. Petrodelta’s ability to secure financing is currently limited and uncertain, and has been, and may be, affected by numerous factors beyond its control, including the risks associated with

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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. Since Petrodelta only executed approximately 50 percent of its 2010 budget primarily due to lack of funding by PDVSA, we do not believe that PDVSA will be able to provide the support required to execute Petrodelta’s proposed 2011 budget.
          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.
Item 1B. Unresolved Staff Comments
     None.
Item 2. Properties
     In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month. In December 2008, we signed a five-year lease for additional office space in Houston, Texas, for approximately $15,000 per month. In August 2010, we relinquished a portion of our office space in Houston, Texas, for an approximate $1,600 per month reduction of cost. In December 2010, Harvest Vinccler extended its lease for office space in Caracas, Venezuela for one year for approximately $7,000 per month. In October 2010, we signed a two-year lease in Roosevelt, Utah for approximately $6,000 per month. In October 2010, we signed a two-year lease for office space in Singapore for approximately $7,000 per month. In April 2009, we signed a two-year lease for office space in Indonesia for approximately $5,000 per month. In September 2009, we signed a two-year lease for office space in Oman for approximately $5,000 per month. In September 2010, we signed a five-year lease for office space in London for approximately $9,000 per month. See Item 1 — Business for a description of our oil and gas properties.

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Item 3. Legal Proceedings
          Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc., Branta Exploration & Production, LLC, Ute Energy LLC, Cameron Cuch, Paula Black, Johnna Blackhair, and Elton Blackhair in the United States District Court for the District of Utah. This suit was served in April 2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the defendants, among other things, intentionally interfered with Plaintiffs’ employment agreement with the Ute Indian Tribe — Energy & Minerals Department and intentionally interfered with Plaintiffs’ prospective economic relationships. Plaintiffs seek actual damages, punitive damages, costs and attorney’s fees. We dispute Plaintiffs’ claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.
          Uracoa Municipality Tax Assessments. Our Venezuelan subsidiary, Harvest Vinccler has received nine assessments from a tax inspector for the Uracoa municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:
    Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the capital fee reimbursement and related interest paid by PDVSA under the Operating Service Agreement (“OSA”). Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims.
 
    Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims.
 
    Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim.
 
    Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims.
Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s, the Venezuelan income tax authority, interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.
          Libertador Municipality Tax Assessments. Harvest Vinccler has received five assessments from a tax inspector for the Libertador municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:
    One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Mayor’s Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. On April 10, 2008, the Tax Court suspended the case pending a response from the Mayor’s Office to the protest. If the municipality’s response is to confirm the assessment, Harvest Vinccler will defer to the competent Tax Court to enjoin and dismiss the claim.
 
    Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.

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    Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.
Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the refund of all municipal taxes paid since 2002.
          We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such litigation which will have a material adverse impact on our financial condition, results of operations and cash flows.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
          Our common stock is traded on the NYSE under the symbol “HNR”. As of December 31, 2010, there were 33,933,025 shares of common stock outstanding, with approximately 481 stockholders of record. The following table sets forth the high and low sales prices for our Common Stock reported by the NYSE.
                         
Year     Quarter   High     Low  
  2009    
First quarter
    4.69       2.70  
       
Second quarter
    5.66       3.25  
       
Third quarter
    6.64       4.24  
       
Fourth quarter
    6.39       4.90  
       
 
               
  2010    
First quarter
    7.80       4.36  
       
Second quarter
    9.00       7.10  
       
Third quarter
    10.42       6.54  
       
Fourth quarter
    14.02       10.44  
          On March 9, 2011, the last sales price for the common stock as reported by the NYSE was $16.25 per share.
          Our policy is to retain earnings to support the growth of our business. Accordingly, our Board of Directors has never declared a cash dividend on our common stock.
STOCK PERFORMANCE GRAPH
          The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2010, assuming an investment of $100 on December 31, 2005 in each of Harvest’s common stock, the Dow Jones U.S. Exploration & Production Index and the S&P Composite 500 Stock Index.
          This graph assumes that the value of the investment in Harvest stock and each index was $100 at December 31, 2005 and that all dividends were reinvested.

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Stock Performance Graph
(GRAPHS)
PLOT POINTS
(December 31 of each year)
                                                 
    2005     2006     2007     2008     2009     2010  
Harvest Natural Resources, Inc
  $ 100     $ 120     $ 141     $ 48     $ 60     $ 137  
Dow Jones US E&P Index
  $ 100     $ 105     $ 147     $ 86     $ 121     $ 145  
S&P 500 Index
  $ 100     $ 116     $ 122     $ 77     $ 97     $ 112  
          Total Return Data provided by S&P’s Institutional Market Services, Dow Jones & Company, Inc. is composed of companies that are classified as domestic oil companies under Standard Industrial Classification codes (1300-1399, 2900-2949, 5170-5179 and 5980-5989). The Dow Jones US Exploration & Production Index is accessible at http://www.djindexes.com/mdsidx/index.cfm?event=showTotalMarket.
Item 6. Selected Financial Data
SELECTED CONSOLIDATED FINANCIAL DATA
          The following table sets forth our selected consolidated financial data for each of the years in the five-year period ended December 31, 2010. In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method. The selected consolidated financial data have been derived from and should be read in conjunction with our annual audited consolidated financial statements, including the notes thereto.

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    Year Ended December 31,  
    2010     2009     2008     2007(1)     2006(1)  
            (in thousands, except per share data)          
Statement of Operations:
                                       
Total revenues
  $ 10,696     $ 181     $     $ 11,217     $ 59,506  
Operating income (loss)
    (30,691 )     (30,959 )     (54,440 )     (19,536 )     574  
Net income from Unconsolidated Equity Affiliates
    66,164       35,757       34,576       55,297        
Net income (loss) attributable to Harvest
    15,340       (3,107 )     (21,464 )     60,118       (62,502 )
Net income (loss) attributable to Harvest per common share:
                                       
Basic
  $ 0.46     $ (0.09 )   $ (0.63 )   $ 1.65     $ (1.68 )
 
                             
Diluted
  $ 0.43     $ (0.09 )   $ (0.63 )   $ 1.59     $ (1.68 )
 
                             
 
                                       
Weighted average common shares outstanding
                                       
Basic
    33,541       33,084       34,073       36,550       37,225  
Diluted
    39,331       33,084       34,073       37,950       37,225  
                                         
    As of December 31,  
    2010     2009     2008     2007(1)     2006(1)  
                    (in thousands)                  
Balance Sheet Data:
                                       
Total assets
  $ 488,244     $ 348,779     $ 362,266     $ 417,071     $ 468,365  
Long-term debt, net of current maturities
    81,237                         66,977  
Total Harvest’s Stockholders’ equity (2)
    306,804       274,593       273,242       316,647       281,409  
 
(1)   Activities under our former OSA in Venezuela are reflected under the equity method of accounting effective April 1, 2006. The results of Petrodelta’s operations from April 1, 2006 until December 31, 2007 are reflected in 2007 when Petrodelta was formed.
 
(2)   No cash dividends were declared or paid during the periods presented.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Operations
          We had net income attributable to Harvest of $15.3 million, or $0.43 per diluted share, for the year ended December 31, 2010 compared to a net loss attributable to Harvest of $3.1 million, or $(0.09) per diluted share, for the year ended December 31, 2009. Net income attributable to Harvest for the year ended December 31, 2010 includes $8.0 million of exploration expense and the net equity income from Petrodelta’s operations of $66.2 million. 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.
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.
          The January 8, 2010 Exchange Agreement also established exchange rates for the sale of foreign currency: 2.5935 Bolivars per U.S. Dollar and 4.2893 Bolivars per U.S. Dollar. The 2.5935 Bolivars per U.S. Dollar rate applies to at least 30 percent of the currency. The Central Bank is entitled to adjust the proportion of sales of foreign currency at each exchange rate to attend market needs. Early in 2010, the Central Bank, in responding to needs of import requirements of goods and services under each of the controlled exchange rates, adjusted the percentage from 30 percent to 40 percent for the 2.5935 Bolivars per U.S. Dollar. The 40/60 percent split in sales of foreign currency between the two exchange rates creates a blended third exchange rate of 3.61 Bolivars per U.S. Dollar. During 2010, PDVSA sold foreign currency to the Central Bank in return for Bolivars. These foreign currency sales were for PDVSA and PDVSA’s subsidiaries. In December 2010, PDVSA invoiced Petrodelta $19.5 million related to sales of foreign currency for Bolivars at the blended exchange rate of 3.61 Bolivars per U.S. Dollar. The $19.5 million is calculated as the difference between U.S. Dollar invoices remeasured at the official exchange rate of 4.30 Bolivars per U.S. Dollar and the same invoices remeasured at the blended exchange rate of 3.61 Bolivars per U.S. Dollar.
          On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate with an effective date of January 1, 2011. The January 2011 Exchange Agreement eliminated the Central Bank’s entitlement to require the sale of foreign currency at specific rates. All sales of foreign currency will be at the 4.2893 Bolivars per U.S. Dollar exchange rate.
          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). However, in October 2010, Harvest Vinccler exchanged

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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. Petrodelta does not have, and has not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. Harvest Vinccler currently does not have 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 new official exchange rate of 4.30 Bolivars per U.S. Dollar. During the year ended December 31, 2010, Harvest Vinccler recorded a $1.5 million remeasurement loss and Petrodelta recorded an $84.4 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, 2010, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 2.9 million and BsF 3.2 million, respectively. At December 31, 2010, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 87.0 million and BsF 1,423.0 million, respectively.
          In June 2010, Petrodelta’s board of directors approved the offsetting of accounts payable to PDVSA and its affiliates, including CVP, for 2010 royalties, taxes and operation expenditures against the receivable from PDVSA and its affiliates, including CVP, for 2010 oil and gas deliveries at the exchange rate prevailing as of that date. During February 2011, per instructions received from CVP, Petrodelta proceeded to offset accounts receivable and payables between PDVSA and its affiliates, including CVP, outstanding as of December 31, 2009 at the exchange rate prevailing as of that date. The revised revaluation reduced Petrodelta’s remeasurement gain $36.1 million from $120.5 million in January 2010 to $84.4 million in December 2010.
          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 $70.43 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. During the year ended December 31, 2010, PDVSA began making regular payments to Petrodelta to enable Petrodelta to reduce the outstanding debt to contractors. Some of the payments received from PDVSA were designated to be used to repay Harvest Vinccler (Advances to Equity Affiliates). During the year ended December 31, 2010, Petrodelta repaid $4.8 million to Harvest Vinccler for costs related to contractors and seconded employees. 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.

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          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
          During 2010, Petrodelta drilled and completed 16 development wells, produced approximately 8.6 MBl of oil and sold 2.2 BCF of natural gas. Petrodelta produced an average of 23,455 BOPD during the year ended December 31, 2010.
          Petrodelta’s focus in 2010 included utilizing two rigs to drill both development and appraisal wells for both maintaining production capacity and appraising the substantial resource base in the El Salto field. Petrodelta contracted a workover rig in October 2010. Petrodelta began engineering work for expanded production facilities to handle the expected production from the development and appraisal wells that were expected to be drilled in 2010. Due to delays in rig availability, El Salto facilities project execution and lack of funding by PDVSA, Petrodelta only spent $101.8 million of its 2010 capital budget of $205 million.
          As discussed above, 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.
          As of March 7, 2011, the 2011 budget for Petrodelta’s business plan had not yet been approved by its shareholders. Since Petrodelta only executed approximately 50 percent its 2010 budget primarily due to lack of funding by PDVSA, we do not believe that PDVSA will be able to provide the support required to execute Petrodelta’s proposed 2011 budget. However, Petrodelta’s 2011 proposed business plan includes a planned drilling program to utilize two rigs to drill both development and appraisal wells for maintaining production capacity, the continued appraisal of the substantial resource base in the El Salto field and appraising the presently non-producing Isleño field. It also includes engineering work for production facilities required for the full development of the El Salto field.
          The appraisal and development activity in the El Salto field exceeded expectations. During 2010, the ELS-33 well was drilled and completed in the Lower Jobo sand and began producing on September 1, 2010. The ELS-33 tested at rates of 1,800 barrels of oil per day (“BOPD”). The ELS-33 also drilled a pilot hole which encountered a full column of oil in a block that was previously unpenetrated and represented a significant expansion of Block 5 in El Salto field not included in the 2009 reserve report. The ELS-34 well was drilled and completed in the Lower Jobo sand of the newly identified Block 5 extension and began production in September 2010. The ELS-34 has tested at rates of 2,150 BOPD with indicated potential of over 3,000 BOPD based on bottom-hole-pressures. The ELS-33 and ELS-34 wells were restricted in their production rate until additional oil transportation trucks are contracted by Petrodelta to service the expanded production capacity from El Salto.
          As of December 31, 2010, we are reporting a reserve increase attributed to Petrodelta. 2P reserves, net to our 32 percent interest, have increased to 103.6 MMBOE at December 31, 2010, a 24 percent increase over year end 2009. Proved reserves, net to our 32 percent interest, increased to 50.0 MMBOE at December 31, 2010, an eight percent increase over year end 2009. 3P reserves remain virtually unchanged from last year. These reserve additions are the result of successful recent drilling and the extension of Block 5, a previously unproven fault block in the El Salto field and recent development drilling success in other fields.
          In 2005, Venezuela modified LOCTI 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

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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 expected PDVSA to continue requesting and receiving waivers, Petrodelta did not accrue a liability to LOCTI for the year ended December 31, 2009. For filing years 2007 and 2008, PDVSA provided Petrodelta with a copy of the waiver acceptance letter from LOCTI. PDVSA has stated that a waiver was granted for filing year 2009; however, LOCTI has not yet issued the acceptance letter to PDVSA for the 2009 filing year. The potential exposure to LOCTI for the year ended December 31, 2009 after devaluation is $4.8 million, $2.4 million net of tax ($0.8 million net to our 32 percent interest). In January 2011, PDVSA informed its consolidating entities, including Petrodelta, that effective with the 2010 reporting year it would no longer be requesting waivers to file the LOCTI declaration on a consolidated basis. Based on this information, Petrodelta accrued the 2010 liability to LOCTI in the amount of $4.6 million, $2.3 million net of tax ($0.7 million net to our 32 percent interest). In December 2010, LOCTI was modified to reduce the amount of contributions beginning January 2011 to one percent of gross revenues for companies owned by individuals or corporations and 0.5 percent for companies owned by Venezuela. Petrodelta’s rate of contribution starting in 2011 will be 0.5 percent.
          In 2008, the Venezuelan government published in the Official Gazette the Windfall Profits Tax. The Windfall Profits Tax is to be calculated on the VEB of prices as published by MENPET. As instructed by CVP, Petrodelta has applied the Windfall Profits Tax to gross oil production delivered to PDVSA. The 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 Windfall Profits Tax is reported as expense on the income statement and is deductible for Venezuelan tax purposes. Petrodelta recorded $14.1 million and $0.9 million of expense for the Windfall Profits Tax for the years ended December 31, 2010 and 2009, respectively.
          In 2009, under instructions issued by CVP, Petrodelta set up a reserve within the equity section of the balance sheet for deferred tax assets. 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. Dividends received prior to 2009 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 August 2010, Petrodelta’ board of directors declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received October 22, 2010. The dividend represents 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under IFRS for the year ended December 31, 2009.
          In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under IFRS for the year ended December 31, 2009. This dividend is subject to shareholder approval, and will not be accrued on our consolidated balance sheet until Petrodelta shareholder approval is received. Shareholder approval was received on March 14, 2011. Petrodelta’s results and operating information is more fully described in Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 9 — Investment in Equity Affiliates — Petrodelta, S.A.

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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 and the opening of our London and Singapore offices, 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.
United States
Gulf Coast — West Bay
          During the year ended December 31, 2010, operational activities in the West Bay prospect focused on firming up plans for drilling on the identified initial drilling prospect and continuing to evaluate the other leads and prospects in the project. Land, regulatory and surface access preparations currently in progress are focused on taking the initial drilling prospect to drill-ready status. During 2010, we finalized a 3-D seismic data trade with a third party and merged the data set with our existing seismic data. The acquisition and merging of the additional 3-D seismic data allows for more complete technical evaluation of the leads and prospects identified in the project. Based on the merged seismic data set, we now have four identified drilling prospects on our acreage. Preliminary work is underway on a drilling barge concept that will be utilized to drill the first two exploration wells. Current plans are to drill the first exploration well in 2011, pending required surface access agreements with a private landowner and pending receipt of necessary permits from the U.S. Army Corps of Engineers. During the year ended December 31, 2010, we had cash capital expenditures of $0.2 million for leasing activities and $0.2 million for seismic data processing on the West Bay project. The 2011 budget for West Bay is minimal consisting of costs required to maintain the leases.
          In February 2011, the previously existing Alligator Point Unit (as approved by the GLO) expired. We have obtained from the GLO an extension until September 1, 2011 of a smaller version of the Alligator Point Unit defined more specifically by the drilling prospects currently existing on the project. As a result of the GLO approval of the smaller Alligator Point Unit and the anticipated expiry of five leases previously held by the larger unit, we expect our lease position on the West Bay project to be reduced from approximately 13,000 acres in February 2011 to approximately 10,050 acres in August 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. In November 2008, we entered into 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, among other things. 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.
          In July 2010, we executed a farm-out agreement with the private third party in the JEDA for the acquisition of an incremental 10 percent interest in the Antelope Project with an effective date of July 1, 2010. This acquisition includes all leases, the Mesaverde, the Lower Green River/Upper Wasatch and the Monument Butte Extension. The acquisition excludes the initial eight wells previously drilled in the Monument Butte Extension. Total consideration for the incremental 10 percent interest is $20.0 million. This acquisition increases our ownership in the Antelope project to 70 percent.

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          During year ended December 31, 2010, we had cash capital expenditure of $12.9 million for leasing activities on the Antelope prospect. The 2011 budget for leasing activity in the Antelope prospect is $0.9 million.
          Drilling, completion and testing activities were conducted during 2010 on three separate projects on the Antelope prospect in Duchesne and Uintah Counties, Utah.
Mesaverde
          The Mesaverde Gas Exploration and Appraisal Project (“Mesaverde”) is targeted to explore for and develop natural gas in the Mesaverde formation in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties. Operational activities during the year ended December 31, 2010 included completion of the initial testing activities on the Mesaverde horizons in the deep natural gas test well, the Bar F, that commenced drilling on June 15, 2009. The Bar F was drilled to a total depth of 17,566 feet and an extended production test of the Mesaverde has been completed. Testing was 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. Gas was tested at flow rates of 1.5-2 million cubic feet per day (“MMCFD”) from selected intervals. While the results to date have not definitively determined the commerciality of a stand-alone development of the Mesaverde in the current gas price environment, we believe that the test results confirm that the Mesaverde formation exhibits sufficient quantities of hydrocarbons and reservoir over-pressure to justify potential development, and we are actively pursuing efforts to assess whether reserves can be attributed to this reservoir. The Mesaverde reservoir remains potentially prospective over a portion of our land position. Exploratory drilling costs for the Mesaverde have been suspended pending further evaluation. See Note 2 — Summary of Significant Accounting Policies, Property and Equipment. During the year ended December 31, 2010, we incurred $5.1 million for drilling, completion and testing activities of the Mesaverde. Our 2011 budget currently does not include costs to further delineate the Mesaverde.
Lower Green River/Upper Wasatch
          The Lower Green River/Upper Wasatch is a second prospective horizon that is being pursued in the Antelope project. After completion of the initial testing program on the Mesaverde deep gas in the Bar F well as described above, we moved uphole in the same well to test multiple oil bearing intervals at depths from 8,200 feet to 9,500 feet in the Lower Green River and Upper Wasatch. Extended flow testing of the well conducted during the second quarter of 2010 indicated that a commercial oil discovery was made in the Lower Green River and Upper Wasatch. A five-well Lower Green River/Upper Wasatch delineation and development drilling program was planned to further delineate and appraise the extent of the Lower Green River/Upper Wasatch discovery made in the Bar F, and to establish additional production from the Lower Green River/Upper Wasatch reservoirs in at least some of the five appraisal wells. Based on results of the initial wells in the five well delineation and development drilling program, an additional sixth well was added to the program to be drilled in early 2011.
          Operational activities during the year ended December 31, 2010 included completion of testing of the Bar F, completion of the Bar F, including installation of an electric submersible pump, completion of production facilities for the Bar F and routine production operations of the Bar F. During the year ended December 31, 2010, we had cash capital expenditure of $6.8 million in drilling, completion and testing activities for the Bar F in the Lower Green River/Upper Wasatch formation.
          The five-well delineation and development drilling program was initiated in the third quarter of 2010, and as of December 31, 2010, five wells were in varying stages of completion, drilling, and production facilities installation. Three additional wells have been incorporated into our planning for the next round of development drilling in the Lower Green River/Upper Wasatch. As of March 4, 2011, we had eight wells in the delineation and development drilling program in varying stages of completion, drilling and production facilities installation:
    Three wells, the Kettle #1-10-3-1, the ON Moon #1-27-3-2 and the Dart #1-12-3-2, were completed and on production.
 
    One well, the Giles #1-19-3-2, has been hydraulically fractured and completed and will be placed on production soon.

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    One well, the Yergensen #1-9-3-1, has been drilled and being hydraulically fractured.
 
    One well, the Evans #1-4-3-3, is currently drilling.
 
    Two wells, the Lamb #1-19-3-1 and the Yergensen #1-18-3-1, were spud using a spud rig and have been drilled to surface casing depth only and surface casing installed.
          During the year ended December 31, 2010, we had cash capital expenditure of $17.3 million in well planning, drilling and completion costs and $0.1 million for engineering costs. The 2011 budget for the Lower Green River/Upper Wasatch is $11.2 million.
          During the fourth quarter of 2010, we also initiated permitting activities on a planned 170 square mile 3-D seismic acquisition program which is expected to be acquired in late 2011 and which will be targeted at imaging the Green River and Wasatch formations over the northern portion of our acreage.
          On December 21, 2010, we and our partner in the Antelope project entered into a contract with EPMG whereby EPMG will provide the capital to build and operate a 25-mile, low-pressure gas gathering pipeline which will provide capacity for our current and future production from the Lower Green River/Upper Wasatch Development project. We will provide capital to build flowlines to connect the produced gas from our wells into the EPMG header system. As part of the contract arrangement, we and our partner have dedicated approximately 75 percent of our Antelope leasehold to the El Paso contract for 10 years, with a Harvest option to extend the dedication for up to an additional nine years without any change in contract terms. The area dedication is limited stratigraphically to the top of the Mesaverde formation, resulting in the Mesaverde deep gas not being included in the dedication.
          As of December 31, 2010, we received our first comprehensive reserve report covering the Uinta Basin reserves in Utah. 2P reserves net to Harvest in Utah increased to 15.3 MMBOE at year end 2010, compared to 0.4 MMBOE at year end 2009. Proved Reserves net to Harvest increased to 4.6 MMBOE at December 31, 2010, compared to 0.4 MMBOE at year end 2009. 3P reserves net to Harvest in Utah increased to 86.4 MMBOE at December 31, 2010, compared to 0.4 MMBOE at year end 2009. These reserve additions are the result of our successful Antelope project delineation drilling programs conducted during 2010 and ongoing in 2011 in the Lower Green River/Upper Wasatch and Monument Butte Extension.
Monument Butte
          The Monument Butte Extension was initiated with 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 Extension is non-operated, and we hold a 43 percent working interest in the initial eight wells. The parties participating in the wells formed a 320 acre AMI, which contained the initial eight drilling locations. Operational activities on these eight wells during the year ended December 31, 2010 consisted of completion of drilling and completion of wells followed by routine production operations from the wells. During year ended December 31, 2010, we had cash capital expenditure of $3.6 million in well costs. There is no 2011 budget for the initial eight well program.
          As a follow up to the successful completion of the initial eight well program that was drilled in late 2009 and early 2010, a six well appraisal and development drilling program was approved. The six well expansion is non-operated and is located on acreage immediately adjacent to the initial eight well program. We have an approximate 37 percent working interest in the six wells. At December 31, 2010, five of the six wells had been drilled and four were on production. The sixth and final well in this program spud on February 3, 2011. During the year ended December 31, 2010, we had cash capital expenditures of $1.8 million in well costs and $0.1 million for geological and geophysical costs.
          The Harvest-operated K Moon #2-13-4-3 well was spud in November 2010 and commenced production on February 16, 2011. We have an approximate 60 percent working interest in this well.

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          The 2011 budget for Monument Butte is $1.3 million which includes the planned drilling of the one remaining well in the six-well expansion project and the completion of the K Moon #2-13-4-3.
Budong-Budong Project, Indonesia
          We acquired our initial 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. The initial commitment to fund the first phase of the exploration program was capped at $17.2 million. The commitment cap is comprised of $6.5 million for the acquisition of seismic and $10.7 million for the drilling of the first two exploratory wells. After the commitment cap of each component was met, all subsequent costs are shared by the parties in proportion to their ownership interests. Prior to drilling the first exploration well, our partner had a one-time option to increase the level of the carried interest to a maximum of $20.0 million. On September 15, 2010, our partner exercised their option to increase the carry obligation by $2.7 million to a total of $19.9 million ($7.9 million for acquisition of seismic and $12.0 million for drilling). The additional carry increased our ownership by 7.4 percent to 54.4 percent. As of February 28, 2011, we had fulfilled all funding obligations to earn our 54.4 percent interest in the Budong PSC. On March 3, 2011, we received notice that the Government of Indonesia and BPMIGAS had approved this change in ownership interest.
          On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator to a third party, to acquire an additional ten percent equity in the Budong PSC for a consideration of $3.7 million payable ten business days after completion of the first exploration well. Closing of this acquisition will increase our interest in the Budong PSC to 64.4 percent. The change in ownership interest is subject approval from the Government of Indonesia and BPMIGAS.
          During the initial exploration period, the Budong PSC covered 1.35 million acres. The term of the Budong PSC is for 30 years and provided for an exploration period of up to ten years. Pursuant to the terms of the Budong PSC, at end of the first three-year exploration phase, 35 percent of the original area was relinquished to BPMIGAS. The second three-year exploration phase began in January 2010 covering 0.88 million acres.
          Operational activities during 2010 focused on well planning, construction for two test well sites, and mobilization of rig and ancillary equipment to the first drill site. After delays in acquiring permits to mobilize the drilling rig from its port location to the drilling pad, the first exploratory well, the Lariang-1 (“LG-1”), was spud on January 6, 2011. The well is to be drilled to a depth of approximately 7,200 feet. As of March 2, 2011, the well had reached approximately 4,500 feet in the Miocene, the secondary objective, and has logged and wireline tested several oil and gas sands. During the year ended December 31, 2010, we incurred $8.5 million for surveying, permitting, engineering and well planning and $4.3 million for seismic, geological and geophysical, and exploration support costs. The 2011 budget for the Budong PSC is $15.5 million.
Dussafu Project — Gabon
          Operational activities during 2010 included the maturation of the prospect inventory and well planning. We have purchased all long lead items required for drilling, and they are either on drill site or en route to the drill site. Other drilling contracts are being tendered in preparation to spud the exploration well which is expected to occur at the beginning of the second quarter of 2011. The exploratory well to be drilled in the second quarter of 2011 will test stacked reservoir potential in the pre-salt section. A Letter of Intent has been agreed for a semi-submersible rig to commence a contract in April 2011 to drill the Ruche Marin prospect. In order to be able to complete the drilling activities, a six month extension to November 27, 2011 of the second Exploration Period has been requested. During the year ended December 31, 2010, we incurred $2.6 million for prospect inventory and well planning and $0.5 million for seismic data processing and reprocessing. The 2011 budget for the Dussafu PSC is $15.6 million.
Block 64 EPSA Project — Oman
          Operational activities during the year ended December 31, 2010 included geological studies, baseline environmental and social study and 3-D pre-stack depth migration reprocessing of approximately 1,150 square kilometers of existing 3-D seismic data. During 2011 geological and geophysical interpretation of the reprocessed 3-D will take place to mature drilling locations. Well planning and procurement of long lead items will commence in the first half of 2011 to enable the first of the two exploratory wells to commence drilling in the fourth quarter of

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2011. We incurred $0.4 million for costs associated with signing the license, including signature bonus and data compilation and $1.2 million for seismic data processing and reprocessing. We expect to drill the first of two exploratory wells in the second half of 2011. The 2011 budget for the Block 64 EPSA is $2.0 million.
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. As a result, we have obtained license extensions, with the current extension in effect until May 31, 2011. We are in the process of obtaining a new license extension and believe that it will be granted. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist. Operational activities during 2010 include costs related to maintenance of the license. The 2011 budget for WAB 21 is minimal consisting of costs required to maintain the license.
Other Exploration Projects
          Relating to other projects, we incurred $0.4 million during the year ended December 31, 2010. The 2011 budget for other projects is minimal consisting of costs required to complete projects started in 2010.
          Any of the exploratory wells to be drilled in 2011 on the Budong PSC and the Dussafu PSC could have a significant impact on our ability to obtain financing, record reserves and generate cash flow in 2011 and beyond.
Fusion Geophysical, LLC (“Fusion”)
          On January 28, 2011, Fusion’s 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. We received $1.3 million for our equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full of the outstanding balance of the prepaid service agreement, short term loan and accrued interest. The Agreement and Plan of Merger includes an Earn Out provision wherein we would receive an additional payment of up to a maximum of $2.7 million if FusionGeo, Inc.’s 2011 gross profit exceeds $5.6 million. The Earn Out payment will not be determined until early in 2012. We can give no assurance that we will receive any Earn Out payment. See Item 15 — Exhibits and Financial Statement Schedules — Notes to Consolidated Financial Statements, Note 9 — Investment in Equity Affiliates — Fusion Geophysical LLC.
          In Item 1 — Business and Item 1A — Risk Factors, we discuss the situation in Venezuela and how the actions of the Venezuelan government have and continue to adversely affect our operations. The expectation that dividends from Petrodelta will be minimal over the next two years has restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere.
          We will use our available cash and future access to capital markets to expand our diversified strategy in a number of countries that fit our strategic investment criteria. In executing our business strategy, we will strive to:
    maintain financial prudence and rigorous investment criteria;
 
    access capital markets;
 
    continue to create a diversified portfolio of assets;
 
    preserve our financial flexibility;
 
    use our experience and skills to acquire new projects; and
 
    keep our organizational capabilities in line with our rate of growth.
               To accomplish our strategy, we intend to:
    Diversify our Political Risk: Acquire oil and natural gas fields in a number of countries to diversify and reduce the overall political risk of our investment portfolio.

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    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.
 
    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, 2010 and the financial condition as of December 31, 2010 and 2009 in conjunction with our consolidated financial statements and related notes thereto.
Years Ended December 31, 2010 and 2009
          We reported net income attributable to Harvest of $15.3 million, or $0.43 diluted earnings per share, for the year ended December 31, 2010, compared with a net loss attributable to Harvest of $3.1 million, or $(0.09) diluted earnings per share, for the year ended December 31, 2009.
          Revenues were higher for the year ended December 31, 2010 compared with the year ended December 31, 2009 due to production from the Monument Butte Extension wells and the Lower Green River/Upper Wasatch wells. Production for the two areas for the years ended December 31, 2010 and 2009 were:

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    December 31, 2010     December 31, 2009  
    Lower Green     Monument     Lower Green     Monument  
    River/Upper     Butte     River/Upper     Butte  
    Wasatch     Extension     Wasatch     Extension  
Barrels of oil sold
    33,932       106,094             2,683  
Thousand cubic feet of gas sold
    6,257       416,779             5,780  
Total barrels of oil equivalent
    34,975       175,558             3,646  
Average price per barrel
  $ 69.63     $ 64.85     $     $ 61.57  
Average price per thousand cubic feet
  $ 3.97     $ 3.43     $     $ 2.77  
    Total expenses and other non-operating (income) expense (in millions):
                         
    Year Ended        
    December 31,     Increase  
    2010     2009     (Decrease)  
Lease operating and production taxes
  $ 1.8     $     $ 1.8  
Depletion, depreciation and amortization
    3.8       0.4       3.4  
Exploration expense
    8.0       7.8       0.2  
General and administrative
    26.7       21.9       4.8  
Taxes other than on income
    1.0       1.0        
Investment earnings and other
    (0.6 )     (1.2 )     0.6  
Interest expense
    2.7             2.7  
Other non-operating expense
    4.0             4.0  
Loss on exchange rates
    1.6       0.1       1.5  
Income tax expense
    (0.2 )     1.2       (1.0 )
          Lease operating costs were higher for the year ended December 31, 2010 compared to the year ended December 31, 2009 due to the inception of domestic oil and natural gas operations beginning in late December 2009. Costs incurred were primarily for water disposal, gas gathering transportation and processing, fuel and other routine oil production activities. Depletion expense, which was entirely attributable to U.S. production, was $3.3 million and $0.03 million ($16.71 and $6.59 per BOE) for the years ended December 31, 2010 and 2009, respectively.
          Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2010, we incurred $6.4 million of exploration costs related to seismic, geological and geophysical, and exploration support costs and $1.6 million related to other general business development activity. Included in the $6.4 million of exploration costs is the one-time charge of $1.2 million for acquisition of seismic data for the Budong PSC related to our partner in the Budong PSC exercising their option to increase the carry obligation. 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 first prospect in the AMI.
          General and administrative costs were higher in the year ended December 31, 2010, than in the year ended December 31, 2009, primarily due to higher employee related costs of $3.8 million and by a reversal in 2009 of $1.3 million of accruals no longer required offset by a reduction in other general office costs of $0.3 million. Taxes other than on income for the year ended December 31, 2010, were consistent with the year ended December 31, 2009.
          Investment earnings and other decreased in the year ended December 31, 2010 compared to the year ended December 31, 2009 due to lower interest rates earned on lower average cash balances. Interest expense was higher for the year ended December 31, 2010 compared to the year ended December 31, 2009 due to interest associated with our $32.0 million senior convertible note offering in February 2010, our $60.0 million term loan facility occurring in October 2010 and amortization of discount on the term loan facility related to the warrants issued in connection with the $60 million term loan facility offset by interest capitalized to oil and gas properties of $1.8 million. Other non-operating expense was higher in the year ended December 31, 2010 compared to the year ended

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December 31, 2009 due to the expensing of $2.9 million of costs related to a future financing which is no longer being pursued and $1.1 million of costs related to other strategic alternatives.
          Income tax expense was lower for the year ended December 31, 2010 compared to the year ended December 31, 2009 due to the receipt a $1.0 million income tax refund related to the recovery of alternative minimum tax for the tax years 2005 and 2007, $0.2 million reversal of a tax provision no longer needed, and lower tax assessed in the Netherlands of $0.7 million offset by $0.5 million of additional income taxes assessed to Harvest Vinccler in 2010 for the 2007 and 2008 tax years. The 2010 tax assessment was the result of a tax audit conducted by the SENIAT.
          Net income from unconsolidated equity affiliates includes an $84.4 million remeasurement gain on revaluation of monetary assets and liabilities due to the Bolivar devaluation in January 2010 and a $19.5 million financing charge related to the blended exchange rate charged by the Central Bank of Venezuela for the purchase of foreign currency. See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Operations, Venezuela.
          At December 31, 2009, we recorded a $1.6 million charge to fully impair the carrying value of our equity investment in Fusion. For the year ended December 31, 2010 and 2009, Fusion reported a net loss of $2.4 million and $4.8 million ($1.2 million and $2.4 million net to our 49 percent interest), respectively. The loss for 2010 is not reported in the year ended December 31, 2010 net income from unconsolidated equity affiliates as reporting it would take our equity investment into a negative position. On January 28, 2011, our minority equity investment in Fusion’s 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. We received $1.3 million for our equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full of the outstanding balance of the prepaid service agreement, short term loan and accrued interest.
Years Ended December 31, 2009 and 2008
          We reported a net loss attributable to Harvest of $3.1 million, or $(0.09) diluted earnings per share, for the year ended December 31, 2009, compared with a net loss attributable to Harvest of $21.5 million, or $(0.63) diluted earnings per share, for the year ended December 31, 2008.
          Revenues were higher for the year ended December 31, 2009 compared with the year ended December 31, 2008 due to the Monument Butte wells coming on production in December 2009.
          Total expenses and other non-operating (income) expense (in millions):
                         
    Year Ended        
    December 31,     Increase  
    2009     2008     (Decrease)  
Depletion, depreciation and amortization
  $ 0.4     $ 0.2     $ 0.2  
Exploration expense
    7.8       16.4       (8.6 )
Dry hole costs
          10.8       (10.8 )
General and administrative
    21.9       27.2       (5.3 )
Taxes other than on income
    1.0       (0.2 )     1.2  
Gain on financing transactions
          (3.4 )     3.4  
Investment earnings and other
    (1.2 )     (3.8 )     2.6  
Interest expense
          1.7       (1.7 )
Loss on exchange rate
    0.1       0.2       (0.1 )
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

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general business development activities. Also during the year ended December 31, 2008, we incurred $10.8 million of dry hole costs related to the Harvest Hunter #1 well, which in January 2009 was determined to have no commercial quantities of hydrocarbons and was plugged and abandoned.
          General and administrative costs were lower in the year ended December 31, 2009, than in the year ended December 31, 2008, primarily due to employee related expenses, lower general operations and office costs, and the reversal of accruals no longer required, including penalties and interest of $0.9 million on the resolved SENIAT assessments. Taxes other than on income for the year ended December 31, 2009, were higher than the year ended December 31, 2008 due to the reversal in 2008 of a $1.1 million franchise tax provision that was no longer required.
          We did not participate in any security exchange transactions in the year ended December 31, 2009. During the year ended December 31, 2008, we entered into a securities exchange transaction exchanging U.S. government securities for U.S. Dollar indexed debt issued by the Venezuelan government. This security exchange transaction resulted in a $3.4 million gain on financing transactions for the year ended December 31, 2008.
          Investment earnings and other decreased in the year ended December 31, 2009 compared to the year ended December 31, 2008 due to lower interest rates earned on lower average cash balances. Interest expense was lower for the year ended December 31, 2009 compared to the year ended December 31, 2008 due to the repayment of debt in 2008.
          For the year ended December 31, 2009, income tax expense was higher than that of the year ended December 31, 2008 primarily due to additional income tax assessed in the Netherlands of $0.7 million as a result of financing activities, which was recorded in the first quarter of 2009, and additional current income tax in the Netherlands of $0.5 million due to interest income earned from loans to affiliates and on cash balances. No income tax benefit is recorded for the net operating losses incurred as a full valuation allowance has been placed on the related deferred tax asset as management believes that is more likely than not that additional net losses will not be realized through future taxable income. There was no utilization of net operating loss carryforwards in the year ended December 31, 2009.
          Net income from unconsolidated equity affiliates includes two non-recurring adjustments:
    During the second quarter of 2009, Petrodelta recorded additional pension expense of $15.6 million ($5.0 million net to our 32 percent interest) in the three month period ended June 30, 2009 based on an actuarial study commissioned by PDVSA which was finalized during the second quarter of 2009. During the fourth quarter of 2009, Petrodelta received a revised allocation of its pension obligation from PDVSA which reflected an update to the actuarial study based on a further refinement of assumption and a revised allocation methodology as a result of an analysis of more detailed census data specific to each mixed company not previously available. This revised allocation resulted in a decrease of $8.4 million ($2.7 million net to our 32 percent interest) to the pension and retirement plan costs as compared to those previously recorded to Petrodelta in May 2009. This change in management’s estimate related to the pension and retirement plan costs was recorded in December 2009.
 
    Based on cash flow projections and considering Fusion’s current liquidity, we performed a review at December 31, 2009 for impairment of our minority equity investment in Fusion. Based on this review, we concluded that Fusion’s potential business opportunities did not support its on-going cash flow requirements; and therefore, we recorded a $1.6 million charge to fully impair the carrying value of our equity investment in Fusion at December 31, 2009.
          See Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 9 — Investment in Equity Affiliates for additional information.

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Capital Resources and Liquidity
     Our liquidity outlook has changed since December 31, 2009 primarily as a result of funding requirements of our exploration projects and development of our oil and gas properties. The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. In Item 1A — Risk Factors, we discuss a number of variables and risks related to our exploration projects and our minority equity investment in Petrodelta 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.
     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. We require capital principally to fund the exploration and development of new oil and gas properties. For calendar year 2011, we have established a preliminary exploration and drilling budget of approximately $46.5 million. We are concentrating a substantial portion of this budget on the development of our Antelope project, the Budong PSC and the Dussafu PSC. As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. Currently, we have a work commitment of $22.0 million which is a minimum amount to be spent on the Block 64 EPSA for the drilling of two wells over a three-year period which expires in May 2012. We currently plan to fund this commitment in 2012, and we may be required to raise capital to do so. We also have minimum work commitments during the various phases of the exploration periods in the Budong PSC and Dussafu PSC.
     As a petroleum exploration and production company, our revenue, profitability, cash flows, and future rate of growth are substantially dependent on the condition of the oil and gas industry generally, our success with our exploration program, and the belief that Petrodelta will fund its own operations and continue to pay dividends. Because our revenues are generated from customers with the same economic interests, our operations are also susceptible to market volatility resulting from economic, cyclical, weather or other factors related to the energy industry. Changes in the level of operating and capital spending in the industry, decreases in oil or gas prices, or industry perceptions about future oil and gas prices could adversely affecting our financial position, results of operations and cash flows. Based on our current level of cash flow from operations, we will be required to raise capital to meet our general and administrative costs and fund our oil and gas programs.
     Revenues from the Monument Butte Extension and Lower Green River/Upper Wasatch projects have increased significantly during 2010; however, our primary source of cash still remains to be dividends from Petrodelta and funding from debt financing. In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under IFRS for the year ended December 31, 2009. This dividend is subject to shareholder approval, and will not be paid by Petrodelta until Petrodelta shareholder approval is received. Shareholder approval was received on March 14, 2011. We expect to receive future dividends from Petrodelta; however, we expect that in the near term Petrodelta will reinvest most of its earnings into the company in support of its drilling and appraisal activities. Therefore, there is uncertainty that Petrodelta will pay additional dividends in 2011 or 2012.
     Additionally, any dividend received from Petrodelta carries a liability to our non-controlling interest holder, Vinccler, for its 20 percent share. Dividends declared and paid by Petrodelta are paid to HNR Finance, our consolidated subsidiary. HNR Finance must declare a dividend in order for us and our non-controlling interest holder, Vinccler, to receive our respective shares of Petrodelta’s dividends. A dividend from HNR Finance is due upon demand. Currently, Vinccler has not demanded its respective share of the two most recent Petrodelta dividends and has waived such a demand until at least April 2012. As of December 31, 2010, Vinccler’s share of the undistributed dividends is $9.0 million inclusive of the unpaid November 2010 dividend. See Item 15 — Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 16 — Related Party Transactions.
     We have incurred significant debt during 2010 which has imposed restrictions on us and increased our vulnerability to adverse economic and industry conditions. Our monthly and semi-annual interest expense has increased significantly, and our senior convertible notes and term loan facility impose new restrictions on us. Our senior convertible notes and term loan facility impose covenant restrictions on us that limit our ability to obtain additional financing. Our ability to meet these covenants is primarily dependent on meeting customary affirmative covenant clauses, including providing consolidated statements to be audited and accompanied by a report and opinion of an independent certified public accountant, which report and opinion shall not be subject to any “going concern” or like qualification. Our inability to satisfy the covenants contained in our long term debt arrangements would constitute an event of default, if not waived. An uncured default could result in our outstanding debt becoming immediately due and payable. If this were to occur, we may not be able to obtain waivers or secure alternative financing to satisfy our obligations, either of which would have a material adverse impact on our business. As of December 31, 2010, we were in compliance with all of our long term debt covenants.
     At December 31, 2010, we had cash on hand of $58.7 million. We believe that this cash plus cash generated from Petrodelta dividends and funding from debt financing combined with our ability to vary the timing of our capital expenditures is sufficient to fund our operations and capital commitments through at least December 31, 2011. However, if the Petrodelta dividend payment is not received as expected or our cash sources and requirements are different than expected, it could have a material adverse effect on our operations.
     In order to increase our liquidity to levels sufficient to meet our commitments, we are currently pursuing a number of actions including possible delay of discretionary capital spending to future periods, possible farm-out or sale of assets, or other monetization of asset as necessary to maintain the liquidity required to run our operations. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, increasing production in our producing assets, and cost reductions. Although we believe that we will have adequate liquidity to meet our future operating requirements and to remain compliant with the covenants under our long term debt arrangements, the factors described above create uncertainty. 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. Accordingly, there can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.

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          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. The notes are general unsecured obligations, ranking equally with all 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. The net proceeds are being used to fund capital expenditures and for working capital needs and general corporate purposes.
          In September 2010, we announced the retention of Bank of America Merrill Lynch to provide advisory services to assist us in exploring a broad range of strategic alternatives for enhancing shareholder value. These alternatives could include, but are not limited to, certain extraordinary transactions, including, possibly, a sale of assets or a sale or merger of the Company.
          On October 29, 2010, we announced the closing of a $60.0 million term loan facility with MSD Energy, an affiliate of MSD Capital, L.P., as the sole lender under the term loan facility. Under the terms of the term loan facility, interest is paid on a monthly basis at the initial rate of 10 percent and the term loan will mature on October 28, 2012. The initial rate of interest increases to 15 percent on July 28, 2011, the Bridge Date. The Bridge Date may be extended at our option for three months by paying a fee to MSD Energy in the amount of five percent of the initial principal amount of the term loan facility. The net proceeds of the term loan facility are approximately $59.5 million, after deducting fees related to the transaction. The net proceeds of the term loan facility are being used to fund capital expenditures and for working capital needs and general corporate purposes. The term loan facility is a general unsecured obligation, ranking equally with all other unsecured senior indebtedness and senior in right of payment to our subordinated indebtedness, if any. MSD Energy Investments, L.P., an affiliate of MSD Capital, L.P., is currently a shareholder and a convertible note holder of Harvest.
          In connection with the term loan, we issued to MSD Energy (1) 1.2 million warrants exercisable at any time on or after the closing date for a period of five years from the closing date on a cashless exercise basis at $15 per share until the Bridge Date, at which time the exercise price per share will equal the lower of $15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date; (2) 0.4 million warrants exercisable at any time on or after the closing date for a period of five years from the closing date on a cashless exercise basis at $20 per share until the Bridge Date, at which time the exercise price per share will equal the lower of $15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date; and (3) 4.4 million warrants exercisable at any time on or after the Bridge Date for a period of five years from the Bridge Date on a cashless exercise basis at the lower of $15 per share or 120 percent of the average closing price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date. The 4.4 million warrants may be redeemed by Harvest for $0.01 per share at any time prior to the Bridge Date in conjunction with the repayment of the loan prior to the Bridge Date.
          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. On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate with an effective date of January 1, 2011. 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. We expect to receive future dividends from Petrodelta; however, we expect that in the near term Petrodelta will reinvest most of its earnings into the company in support of its drilling and appraisal activities. At

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CVP’s instructions, Petrodelta set up a reserve within the equity section of its balance sheet for deferred tax assets. The setting up of the reserve had no effect on Petrodelta’s financial position, results of operations or cash flows. However, the new reserve could have a negative impact on the amount of dividends received in the future. It was anticipated that all of Petrodelta’s available cash generated during 2010, and is still anticipated for 2011, would be used to meet Petrodelta’s current operating requirements and would not be available for dividends. However, in August 2010, Petrodelta’s board of directors declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received on October 22, 2010. Petrodelta’s board of directors declared another dividend in November 2010 of $30.6 million. This dividend is pending approval by Petrodelta’s shareholders and will not be paid until approval is received. Shareholder approval was received on March 14, 2011. There is no certainty that Petrodelta will pay additional dividends in 2011 or 2012. See Item 1A — Risk Factors and Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations for a complete description of the situation in Venezuela and other matters.
          The net funds raised and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:
                         
    Year Ended December 31,  
    (in thousands except as indicated)  
    2010     2009     2008  
Net cash provided by (used in) operating activities
  $ (5,296 )   $ (34,945 )   $ 50,380  
Net cash used in investing activities
    (59,061 )     (28,603 )     (23,055 )
Net cash provided by (used in) used in financing activities
    90,743       (1,300 )     (51,001 )
 
                 
Net increase (decrease) in cash
  $ 26,386     $ (64,848 )   $ (23,676 )
 
                 
 
                       
Working Capital
    45,199       34,539       77,010  
Current Ratio
    2.6       3.1       3.0  
Total Cash, including restricted cash
    58,703       32,317       97,165  
Total Debt
    81,237              
          The increase in working capital of $10.7 million was primarily a result of increases in long-term debt of $92.0 million and oil and gas revenue of $10.5 million offset by the dividend received from Petrodelta of $12.2 million, capital expenditures of $59.6 million, net decrease in other current assets of $4.5 million, net increase in accounts payable and other accrued expenses of $4.2 million and administrative expenses, including interest on debt, of $11.2 million.
          Cash Flow from Operating Activities. During the years ended December 31, 2010 and 2009, net cash used in operating activities was approximately $5.3 million and $34.9 million, respectively. The $29.6 million increase was primarily due to net working capital increases of $17.0 million primarily related to increased oil and gas operations in Utah and Indonesia, increase in oil and gas revenue of $10.5 million, increase in earnings of unconsolidated affiliate of $18.2 million, offset by an increase in administrative expenses of $11.2 million.
          Cash Flow from Investing Activities. During the year ended December 31, 2010, we had cash capital expenditures of approximately $59.6 million. Of the 2010 expenditures, $47.8 million was attributable to activity on the Antelope projects, $8.5 million was attributable to activity on the Budong PSC, $2.6 million was attributable to activity on the Dussafu PSC and $0.7 million was attributable to other projects. 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, 2010, we expensed $0.5 million of investigative costs related to new business development projects and $2.9 million of costs related to a future financing neither of which are currently being pursued. During the year ended December 31, 2009, we incurred $0.6 million of investigative 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 $46.5 million for 2011 for U.S., Indonesia, Gabon and Oman operations will be funded through our existing cash balances, accessing equity and debt markets, and cost reductions. In addition, we could delay the discretionary portion of our capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, as warranted.

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          Cash Flow from Financing Activities. During the year ended December 31, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes as well as a $60.0 million term loan facility, incurred $2.9 million in deferred financings costs related to the $32.0 million convertible debt offering and the $60.0 million term loan facility that are being amortized over the life of the financial instruments. During the year ended December 31, 2009 we incurred $1.7 million in legal fees associated with prospective financing.
Contractual Obligations
          We have a lease obligation of approximately $30,400 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 $7,000 per month. This lease runs through November 2011. We also have lease commitments for an office in Utah for approximately $6,000 per month, an office in Singapore for approximately $7,000 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 $9,000 per month. These leases expire in September 2012, October 2012, March 2011, August 2011 and September 2015, respectively.
                                         
    Payments (in thousands) Due by Period  
            Less than                     After 4  
Contractual Obligation   Total     1 Year     1-2 Years     3-4 Years     Years  
Debt:
                                       
8.25% Senior Convertible Note Due 2013
  $ 32,000     $     $     $ 32,000     $  
10.00% Term Loan Facility Due 2012
    60,000             60,000              
 
                             
Total Debt
    92,000             60,000              
 
                             
 
                                       
Other obligations:
                                       
Interest payments
    20,350       10,140       9,763       447        
Asset retirement obligation
    663                         663  
Oil and gas activities(1)
    22,650       650       22,000              
Office leases
    2,435       764       651       542       478  
 
                             
Total other obligations
    46,098       11,554       32,414       989       1,141  
 
                             
 
Total contractual obligations
  $ 138,098     $ 11,554     $ 92,414     $ 32,989     $ 1,141  
 
                             
 
(1)   As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. At December 31, 2010, we had $0.7 million of commitments related to a drilling rig and other equipment for our domestic operations. The commitment for the drilling rig of $0.6 million was met in January 2011. We also have a funding commitment of $22.0 million on the Block 64 EPSA for the drilling of two wells over a three-year period which expires in May 2012.
          We have minimum work funding commitments during the various phases of the exploration periods in the Budong PSC and Dussafu PSC. Due to the uncertainty of when these commitments will be incurred, these minimum work funding commitments are not included in the above table.
Senior Convertible Note
          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, interest is payable semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2010. The senior convertible notes will mature on March 1, 2013, unless earlier redeemed, repurchased or converted. See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity.

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Term Loan Facility
          On October 29, 2010, we announced the closing of a $60.0 million term loan facility with MSD Energy, an affiliate of MSD Capital, L.P., as the sole lender under the term loan facility. The net proceeds of the term loan facility are approximately $59.5 million, after deducting fees related to the transaction. Under the terms of the term loan facility, interest is paid on a monthly basis at the initial rate of 10 percent and the term loan will mature on October 28, 2012. See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity.
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.
          Our net foreign exchange losses attributable to our international operations were $1.6 million for the year ended December 31, 2010. 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, January 2010 and again in January 2011. 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. On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate with an effective date of January 1, 2011.
          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.
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

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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, 2010 and 2009, there were no events that caused us to evaluate our investment in Petrodelta for impairment.
Capitalized Interest
          We capitalize interest costs for qualifying oil and gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation.
Property and Equipment
          We follow the successful efforts method of accounting for our oil and gas properties. Under this method, oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
          Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered proved reserves. Exploratory drilling costs are capitalized when drilling is completed if it is determined that there is economic producibility supported by either actual production, conclusive formation test or by certain technical data. If proved reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the projects is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in production of natural gas and crude oil, are capitalized.

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          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 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 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.
          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

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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 January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, which is included in the Accounting Standards Codification (“ASC”) under 820, “Fair Value Measurements and Disclosures” (“ASC 820”). This update requires the disclosure of transfers between the observable input categories and activity in the unobservable input category for fair value measurements. The guidance also requires disclosures about the inputs and valuation techniques used to measure fair value and became effective for our interim and annual reporting periods beginning January 1, 2010. The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows.
          In February 2010, the FASB issued ASU No. 2010-09, which is included in the Codification under ASC 855, “Subsequent Events” (“ASC 855”). This update removes the requirement for an SEC filer to disclose the date through which subsequent events have been evaluated and became effective for our interim and annual reporting periods beginning January 1, 2010. The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows.
          In March 2010, the FASB issued ASU No. 2010-11, which is included in the Codification under ASC 815, “Derivatives and Hedging” (“ASC 815”). This update clarifies the type of embedded credit derivative that is exempt from embedded derivative bifurcation requirements. Only an embedded credit derivative that is related to the subordination of one financial instrument to another qualifies for the exemption. This guidance became effective for our interim and annual reporting periods beginning January 1, 2010. The adoption of this guidance did not have a material impact on our consolidated financial position, results of operations or cash flows.
          In May 2010, the FASB issued ASU No. 2010-19, which is included in ASC under 830, “Foreign Currency” (“ASC 830”). This update addresses the multiple foreign currency exchange rates and the impact of highly inflationary accounting in Venezuela. Since the U.S. Dollar is the functional and reporting currency for all of our Venezuela entities, the adoption of this update did not have an impact on our consolidated financial position, results of operations or cash flows.
          In July 2010, the FASB issued ASU 2010-20 Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses (“ASU 2010-20”), which amends existing guidance by requiring more robust and disaggregated disclosures by an entity about the credit quality of its financing receivables and its allowance for credit losses. These disclosures will provide financial statement users with

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additional information about the nature of credit risks inherent in financing receivables, how credit risks are analyzed and assessed in determining allowance for credit losses, and reasons for any changes made in allowance for credit losses. This update is generally effective for interim and annual reporting periods ending on or after December 15, 2010; however, certain aspects of the update pertaining to activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. The adoption of ASU 2010-20 did not have a material impact on our consolidated financial position, results of operations or cash flows.
Off-Balance Sheet Arrangements
          We do not have any off-balance sheet arrangements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
          We are exposed to market risk from adverse changes in oil and natural gas prices and foreign exchange risk, as discussed below.
Oil Prices
          As an independent oil producer, our revenue, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control. Historically, prices received for oil production have been volatile and unpredictable, and such volatility is expected to continue.
          We currently do not have any oil production that is hedged. While hedging limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements.
Interest Rates
          Total long-term debt at December 31, 2010 consisted of $32 million of fixed-rate unsecured senior convertible notes maturing in 2013 unless earlier redeemed, purchased or converted and $60 million of fixed-rate unsecured term loan facility maturing in 2012. A hypothetical 10 percent adverse change in the floating rate would not have a material effect on our results of operations for the year ended December 31, 2010.
Foreign Exchange
          The Bolivar is not readily convertible into the U.S. Dollar. We have utilized no currency hedging programs to mitigate any risks associated with operations in Venezuela, and therefore our financial results are subject to favorable or unfavorable fluctuations in exchange rates and inflation in that country. Venezuela has imposed currency exchange controls (See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity above).
Item 8. Financial Statements and Supplementary Data
          The information required by this item is included herein on pages S-1 through S-40.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
          None.
Item 9A. Controls and Procedures
          Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures that are designed to ensure the information required to be disclosed by us in the reports that we file or

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submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
          Management of the Company, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures. Based on their evaluation as of December 31, 2010, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) were effective.
          Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the Internal Control Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2010. The effectiveness of our internal control over financial reporting as of December 31, 2010, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
          Changes in Internal Control over Financial Reporting. There have been no changes in internal control over financial reporting during the quarter ended December 31, 2010 that have materially affected or are reasonably likely to materially affect that Company’s internal control over financial reporting.
Item 9B. Other Information
          None.

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PART III
Item 10. Directors, Executive Officers and Corporate Governance
          Please refer to the information under the captions “Election of Directors” and “Executive Officers” in our Proxy Statement for the 2011 Annual Meeting of Stockholders.
Item 11. Executive Compensation
          Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the 2011 Annual Meeting of Stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
          Please refer to the information under the caption “Stock Ownership” in our Proxy Statement for the 2011 Annual Meeting of Stockholders.
Item 13. Certain Relationships and Related Transactions, and Director Independence
          Please refer to the information under the caption “Certain Relationships and Related Transactions” in our Proxy Statement for the 2011 Annual Meeting of Stockholders.
Item 14. Principal Accountant Fees and Services
          Please refer to the information under the caption “Independent Registered Public Accounting Firm” in our Proxy Statement for the 2011 Annual Meeting of Stockholders.

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PART IV
Item 15. Exhibits and Financial Statement Schedules
         
    Page  
       
 
       
    S-1  
 
       
    S-2  
 
       
    S-3  
 
       
    S-4  
 
       
    S-5  
 
       
    S-7  
 
       
       
 
       
    S-45  
     All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto.
(b) 3.   Exhibits:
  3.1   Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.)
 
  3.2   Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on May 23, 2007, File No. 1-10762.)
 
  4.1   Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.1 to our Form 10-K filed on March 17, 2008, File No. 1-10762.)
 
  4.2   Certificate of Designation, Rights and Preferences of the Series B Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.2 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.)
 
  4.3   Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A filed on October 23, 2007, File No. 1-10762.)
 
  4.4   Amendment to Third Amended and Restated Rights Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
 
  4.5   Indenture dated as of February 17, 2010, between Harvest Natural Resources, Inc. and U.S. Bank National Association, as trustee. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on February 18, 2010, File No. 1-10762.)
 
  4.6   First Supplemental Indenture dated as of February 17, 2010 between Harvest Natural Resources, Inc. and U.S. Bank National Association, as trustee. (Incorporated by reference to Exhibit 4.2 to our Form 8-K filed on February 18, 2010, File No. 1-10762.)

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  4.7   Form of 8.25% Senior Convertible Notes due 2013. (Incorporated by reference to Exhibit 4.3 to our Form 8-K filed on February 18, 2010, File No. 1-10762.)
 
  4.8   Warrant Purchase Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.2 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
 
  4.9   Common Stock Purchase Warrant No. W-1, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.3 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
 
  4.10   Common Stock Purchase Warrant No. W-2, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.4 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
 
  4.11   Common Stock Purchase Warrant No. W-3, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.5 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
 
  10.1   2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-8 filed on April 9, 2002 (Registration Statement No. 333-85900).)
 
  10.2   Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).)
 
  10.3   Form of Indemnification Agreement between Harvest Natural Resources, Inc. and each Director and Executive Officer of the Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
 
  10.4   Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
 
  10.5   Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
 
  10.6   Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.22 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
 
  10.7   Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
 
  10.8   Employment Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
 
  10.9   Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.24 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)
 
  10.10   Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)

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  10.11   Stock Option Agreement dated September 26, 2005, between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.26 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)
 
  10.12   Harvest Natural Resources 2006 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on June 1, 2006 [Registration Statement No. 333-134630].)
 
  10.13   Form of 2006 Long Term Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
 
  10.14   Form of 2006 Long Term Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
 
  10.15   Form of 2006 Long Term Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
 
  10.16   Stock Unit Award Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
 
  10.17   Stock Unit Award Agreement dated March 2, 2006 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
 
  10.18   Form of 2006 Long Term Incentive Plan Stock Option Agreement — Five Year Vesting, Seven Year Term. (Incorporated by reference to Exhibit 10.33 to our Form 10-K filed on March 13, 2007, File No. 1-10762.)
 
  10.19   Amendment to Harvest Natural Resources 2006 Long Term Incentive Plan adopted July 19, 2006. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on May 3, 2007, File No. 1-10762.)
 
  10.20   Employment Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)
 
  10.21   Stock Option Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)
 
  10.22   Employee Restricted Stock Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)
 
  10.23   Contract for Conversion to a Mixed Company between Corporación Venezolana del Petróleo, S.A., Harvest-Vinccler, S.C.A. and HNR Finance B.V. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on November 1, 2007, File No. 1-10762.)
 
  10.24   Employment Agreement dated April 14, 2008 between Harvest Natural Resources, Inc. and Patrick R. Oenbring. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on May 1, 2008, File No. 1-10762.)
 
  10.25   Stock Option Agreement dated April 14, 2008 between Harvest Natural Resources, Inc. and Patrick R. Oenbring. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on May 1, 2008, File No. 1-10762.)

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  10.26   Employee Restricted Stock Agreement dated April 14, 2008 between Harvest Natural Resources, Inc. and Patrick R. Oenbring. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on May 1, 2008, File No. 1-10762.)
 
  10.27   Employment Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and Stephen C. Haynes. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)
 
  10.28   Stock Option Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and Stephen C. Haynes. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)
 
  10.29   Employee Restricted Stock Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and Stephen C. Haynes. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)
 
  10.30   Employment Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and G. Michael Morgan. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)
 
  10.31   Stock Option Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and G. Michael Morgan. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)
 
  10.32   Employee Restricted Stock Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and G. Michael Morgan. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.)
 
  10.33   Placement Agent Agreement dated February 10, 2010, by and among Harvest Natural Resources, Inc., as issuer, and Lazard Capital Markets LLC and Madison Williams and Company LLC, as placement agents, relating to the 8.25% Senior Convertible Notes due 2013. (Incorporated by reference to Exhibit 10.1 to our Form 8-K filed on February 11, 2010, File No. 1-10762.)
 
  10.34   Form of Standard Subscription Agreement, to be entered into by and among Harvest Natural Resources, Inc. and certain purchasers signatory thereto. (Incorporated by reference to Exhibit 10.2 to our Form 8-K filed on February 11, 2010, File No. 1-10762.)
 
  10.35   Form of Subscription Agreement, to be entered into by and among Harvest Natural Resources, Inc. and certain purchasers signatory thereto. (Incorporated by reference to Exhibit 10.3 to our Form 8-K filed on February 11, 2010, File No. 1-10762.)
 
  10.36   2010 Long Term Incentive Plan. (Incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed with the Securities and Exchange Commission on April 9, 2010, File No. 1-10762.)
 
  10.37   Form of 2010 Long Term Incentive Plan Employee Restricted Stock Award Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2010, File No. 1-10762.)
 
  10.38   Form of 2010 Long Term Incentive Plan Stock Option Award Agreement. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2010, File No. 1-10762.)
 
  10.39   Form of 2010 Long Term Incentive Plan Director Restricted Stock Award Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2010, File No. 1-10762.)

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  10.40   Credit Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 10.1 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
 
  10.41   Guaranty, dated as of October 28, 2010, by Harvest (US) Holdings, Inc., Harvest Natural Resources, Inc. (UK) and Harvest Offshore China Company in favor of MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 10.2 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
 
  10.42   Term Note, dated as of October 28, 2010, of Harvest Natural Resources, Inc. in favor of MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 10.3 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
 
  21.1   List of subsidiaries.
 
  23.1   Consent of PricewaterhouseCoopers LLP.
 
  23.2   Consent of Ryder Scott Company, LP.
 
  23.3   Consent of HLB PGFA Perales, Pistone & Asociados — Caracas, Venezuela.
 
  31.1   Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 executed by James A. Edmiston, President and Chief Executive Officer.
 
  31.2   Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 executed by Stephen C. Haynes, Vice President, Chief Financial Officer and Treasurer.
 
  32.1   Certification accompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by James A. Edmiston, President and Chief Executive Officer.
 
  32.2   Certification accompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by Stephen C. Haynes, Vice President, Chief Financial Officer and Treasurer.
 
  99.1   Reserve report dated February 24, 2011 between Harvest (US) Holdings, Inc. and Ryder Scott Company.
 
  99.2   Reserve report dated February 24, 2011 between HNR Finance B.V. and Ryder Scott Company.
 
  Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15(a) and (b) of Form 10-K.

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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Harvest Natural Resources, Inc.:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)1 present fairly, in all material respects, the financial position of Harvest Natural Resources, Inc. and its subsidiaries at December 31, 2010 and December 31, 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing as Schedule II in Item 15(a)2 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, the financial statement schedule and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 16, 2011

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
                 
    December 31,  
    2010     2009  
    (in thousands, except per share data)  
ASSETS
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 58,703     $ 32,317  
Accounts and notes receivable, net
               
Oil and gas revenue receivable
    1,907       166  
Joint interest and other
    2,325       8,047  
Note receivable
    3,420       3,265  
Advances to equity affiliate
    1,706       4,927  
Prepaid expenses and other
    4,793       2,214  
 
           
TOTAL CURRENT ASSETS
    72,854       50,936  
 
               
OTHER ASSETS
    2,477       3,613  
INVESTMENT IN EQUITY AFFILIATES
    287,933       233,989  
PROPERTY AND EQUIPMENT:
               
Oil and gas properties (successful efforts method)
    126,781       58,543  
Other administrative property
    3,209       3,085  
 
           
 
    129,990       61,628  
Accumulated depreciation and amortization
    (5,010 )     (1,387 )
 
           
 
    124,980       60,241  
 
           
 
  $ 488,244     $ 348,779  
 
           
LIABILITIES AND EQUITY
               
CURRENT LIABILITIES:
               
Joint interest and royalty payable
  $ 675     $  
Accounts payable, trade and other
    2,530       696  
Accounts payable — carry obligation
    8,395        
Accrued expenses
    15,087       9,920  
Accrued interest
    896       4,691  
Income taxes payable
    72       1,090  
 
           
TOTAL CURRENT LIABILITIES
    27,655       16,397  
OTHER LONG TERM LIABILITIES
    1,834       333  
LONG TERM DEBT
    81,237        
ASSET RETIREMENT LIABILITY
    663       50  
COMMITMENTS AND CONTINGENCIES (See Note 4)
           
 
               
EQUITY
               
STOCKHOLDERS’ EQUITY:
               
Preferred stock, par value $0.01 a share; authorized 5,000 shares; outstanding, none
           
Common stock, par value $0.01 a share; authorized 80,000 shares at December 31, 2010 and 2009; issued 40,103 shares and 39,495 shares at December 31, 2010 and 2009, respectively
    401       395  
Additional paid-in capital
    230,362       213,337  
Retained earnings
    141,584       126,244  
Treasury stock, at cost, 6,475 shares and 6,448 shares at December 31, 2010 and 2009, respectively
    (65,543 )     (65,383 )
 
           
TOTAL HARVEST STOCKHOLDERS’ EQUITY
    306,804       274,593  
NONCONTROLLING INTEREST
    70,051       57,406  
 
           
TOTAL EQUITY
    376,855       331,999  
 
           
 
  $ 488,244     $ 348,779  
 
           
See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
                         
    Years Ended December 31,  
    2010     2009     2008  
    (in thousands, except per share data)  
Revenues
                       
Oil sales
  $ 9,243     $ 165     $  
Gas sales
    1,453       16        
 
                 
 
    10,696       181        
 
                 
 
                       
Expenses
                       
Lease operating costs and production taxes
    1,846              
Depletion, depreciation and amortization
    3,817       436       201  
Exploration expense
    8,016       7,824       16,402  
Dry hole costs
                10,828  
General and administrative
    26,660       21,854       27,215  
Taxes other than on income
    1,048       1,026       (206 )
 
                 
 
    41,387       31,140       54,440  
 
                 
 
                       
Loss from Operations
    (30,691 )     (30,959 )     (54,440 )
Other Non-Operating Income (Expense)
                       
Gain on Financing Transactions
                3,421  
Investment earnings and other
    557       1,168       3,849  
Interest expense
    (2,689 )     (5 )     (1,730 )
Other non-operating expense
    (3,952 )            
Loss on exchange rates
    (1,588 )     (83 )     (186 )
 
                 
 
    (7,672 )     1,080       5,354  
 
                 
 
                       
Loss from Consolidated Companies Before Income Taxes
    (38,363 )     (29,879 )     (49,086 )
Income Tax Expense (Benefit)
    (184 )     1,182       25  
 
                 
Loss from Consolidated Companies
    (38,179 )     (31,061 )     (49,111 )
Net Income from Unconsolidated Equity Affiliates
    66,164       35,757       34,576  
 
                 
Net Income (Loss)
    27,985       4,696       (14,535 )
 
                       
Less: Net Income Attributable to Noncontrolling Interest
    12,645       7,803       6,929  
 
                 
 
                       
Net Income (Loss) Attributable to Harvest
  $ 15,340     $ (3,107 )   $ (21,464 )
 
                 
 
                       
Net Income (Loss) Attributable to Harvest Per Common Share:
                       
Basic
  $ 0.46     $ (0.09 )   $ (0.63 )
 
                 
Diluted
  $ 0.43       (0.09 )   $ (0.63 )
 
                 
See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)
                                                         
    Common             Additional                     Non-        
    Shares     Common     Paid-in     Retained     Treasury     Controlling     Total  
    Issued     Stock     Capital     Earnings     Stock     Interest     Equity  
Balance at January 1, 2008
    38,513     $ 385     $ 201,938     $ 150,815     $ (36,491 )   $ 57,546     $ 374,193  
 
                                                       
Issuance of common shares:
                                                       
Exercise of stock options
    547       5       1,560                         1,565  
Employee stock-based compensation
    68       1       5,370                         5,371  
Purchase of treasury shares
                            (28,877 )           (28,877 )
Distribution to noncontrolling Interests
                                  (14,872 )     (14,872 )
Net Income (Loss)
                      (21,464 )           6,929       (14,535 )
 
                                         
 
                                                       
Balance at December 31, 2008
    39,128       391       208,868       129,351       (65,368 )     49,603       322,845  
 
Issuance of common shares:
                                                       
Exercise of stock options
    205       2       384                         386  
Employee stock-based compensation
    162       2       4,085                         4,087  
Purchase of Treasury Shares
                            (15 )           (15 )
Net Income (Loss)
                      (3,107 )           7,803       4,696  
 
                                         
 
                                                       
Balance at December 31, 2009
    39,495       395       213,337       126,244       (65,383 )     57,406       331,999  
 
Issuance of common shares:
                                                       
Exercise of stock options
    419       4       1,670                         1,674  
Employee stock-based compensation
    189       2       4,233                         4,235  
Discount on debt
                11,122                         11,122  
Purchase of treasury shares
                            (160 )           (160 )
Net Income
                      15,340             12,645       27,985  
 
                                         
 
                                                       
Balance at December 31, 2010
    40,103     $ 401     $ 230,362     $ 141,584     $ (65,543 )   $ 70,051     $ 376,855  
 
                                         
See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
                         
    Years Ended December 31,  
    2010     2009     2008  
            (in thousands)          
Cash Flows From Operating Activities:
                       
Net income (loss)
  $ 27,985     $ 4,696     $ (14,535 )
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
                       
Depletion, depreciation and amortization
    3,817       436       201  
Amortization of debt financing costs
    793              
Write off of deferred financing costs
    2,795              
Amortization of discount on debt
    359              
Dry hole costs
                10,828  
Gain on financing transactions
                (3,421 )
Net income from unconsolidated equity affiliates
    (66,164 )     (35,757 )     (34,576 )
Non-cash compensation related charges
    4,234       4,087       6,061  
Dividend received from equity affiliate
    12,220             72,530  
Changes in operating assets and liabilities:
                       
Accounts and notes receivable
    3,826       92       548  
Advances to equity affiliate
    3,221       (1,195 )     12,620  
Prepaid expenses and other
    (2,579 )     (1,055 )     (5,632 )
Joint interest and royalty payable
    675              
Accounts payable
    1,835       (966 )     (2,957 )
Accounts payable, related party
                (10,093 )
Advance from equity affiliate
                20,750  
Accrued expenses
    5,738       (6,629 )     (1,073 )
Accrued interest
    (4,534 )           (445 )
Other long term liabilities
    1,501       333        
Income taxes payable
    (1,018 )     1,013       (426 )
 
                 
Net Cash Provided By (Used In) Operating Activities
    (5,296 )     (34,945 )     50,380  
 
                 
Cash Flows from Investing Activities:
                       
Additions of property and equipment
    (59,619 )     (28,022 )     (26,317 )
Investments in equity affiliates
                (2,161 )
Decrease in restricted cash
                6,769  
Investment costs
    558       (581 )     (1,346 )
 
                 
Net Cash Used In Investing Activities
    (59,061 )     (28,603 )     (23,055 )
 
                 
Cash Flows from Financing Activities:
                       
Net proceeds from issuances of common stock
    1,674       386       1,565  
Proceeds from issuance of long-term debt
    92,000              
Purchase of treasury stock
                (29,416 )
Financing costs
    (2,931 )     (1,686 )     (1,075 )
Payments of note payable
                (7,211 )
Dividend paid to minority interest
                (14,864 )
 
                 
Net Cash Provided By (Used In) Financing Activities
    90,743       (1,300 )     (51,001 )
 
                 
Net Increase (Decrease) in Cash and Cash Equivalents
    26,386       (64,848 )     (23,676 )
Cash and Cash Equivalents at Beginning of Year
    32,317       97,165       120,841  
 
                 
Cash and Cash Equivalents at End of Year
  $ 58,703     $ 32,317     $ 97,165  
 
                 
Supplemental Disclosures of Cash Flow Information:
                       
Cash paid during the year for interest expense (net of capitalization)
  $ 1,380     $ 5     $ 768  
 
                 
Cash paid during the year for income taxes
  $ 834     $ 169     $ 456  
 
                 
See accompanying notes to consolidated financial statements.

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Supplemental Schedule of Noncash Investing and Financing Activities:
          During the year ended December 31, 2010, we issued 0.3 million shares of restricted stock valued at $1.8 million. Also some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis, which resulted in 26,260 shares being added to treasury stock at cost; and 1,000 shares held in treasury that had been reissued as restricted stock were forfeited and returned to treasury.
          During the year ended December 31, 2009, we issued 0.2 million shares of restricted stock valued at $0.7 million. Also, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 3,757 shares being added to treasury stock at cost.
          During the year ended December 31, 2008, we issued 0.2 million of restricted stock valued at $2.0 million; most of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 14,457 shares being added to treasury at cost; and 106,000 shares held in treasury were reissued as restricted stock.
See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Note 1 — Organization
          Harvest Natural Resources, Inc. (“Harvest”) is an independent energy company engaged in the acquisition, exploration, development, production and disposition of oil and natural gas properties since 1989, when it was incorporated under Delaware law.
          We have significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). 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 in 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 substantial opportunities for both development and exploration. 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.
          In addition to our interests in Venezuela, we have exploration acreage in the Gulf Coast Region of the United States, mainly onshore in West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in the Sultanate of Oman (“Oman”), and offshore of the People’s Republic of China (“China”). We also have developed acreage in the Antelope project in the Western United States in the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”) and Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) where we have established production. See Note 10 — United States, Note 11 — Indonesia, Note 12 — Gabon and Note 13 — Oman and Note 14 — China.
Note 2 — Summary of Significant Accounting Policies
Principles of Consolidation
          The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. All intercompany profits, transactions and balances have been eliminated.
Reporting and Functional Currency
          The United States Dollar (“U.S. Dollar”) is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. Amounts denominated in non-U.S. Dollar currencies are re-measured into 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.
          On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement, which established new exchange rates for the Venezuela Bolivar (“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 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

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sectors not expressly established by the 2.60 Bolivar exchange rate. The 4.30 Bolivar exchange rate applies to the oil and gas sector.
          The January 8, 2010 Exchange Agreement also established exchange rates for the sale of foreign currency: 2.5935 Bolivars per U.S. Dollar and 4.2893 Bolivars per U.S. Dollar. The 2.5935 Bolivars per U.S. Dollar rate applies to at least 30 percent of the currency. The Central Bank is entitled to adjust the proportion of sales of foreign currency at each exchange rate to attend market needs. Early in 2010, the Central Bank, in responding to needs of import requirements of goods and services under each of the controlled exchange rates, adjusted the percentage from 30 percent to 40 percent for the 2.5935 Bolivars per U.S. Dollar. The 40/60 percent split in sales of foreign currency between the two exchange rates creates a blended third exchange rate of 3.61 Bolivars per U.S. Dollar. During 2010, PDVSA sold foreign currency to the Central Bank in return for Bolivars. These foreign currency sales were for PDVSA and PDVSA’s subsidiaries. In December 2010, PDVSA invoiced Petrodelta $19.5 million related to sales of foreign currency for Bolivars at the blended exchange rate of 3.61 Bolivars per U.S. Dollar. The $19.5 million is calculated as the difference between U.S. Dollar invoices remeasured at the official exchange rate of 4.30 Bolivars per U.S. Dollar and the same invoices remeasured at the blended exchange rate of 3.61 Bolivars per U.S. Dollar.
          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 has not had, is not expected to have, an impact on our business in Venezuela.
          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. Petrodelta does not have, and has not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. Harvest Vinccler currently does not have 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 remeasured the appropriate monetary assets and liabilities at the official exchange rate of 2.15 Bolivars per U.S. Dollar, Harvest Vinccler’s functional and reporting currency. On January 31, 2010, Harvest Vinccler remeasured the appropriate monetary assets and liabilities at the new official exchange rate of 4.30 Bolivars per U.S. Dollar. During the year ended December 31, 2010, Harvest Vinccler recorded a $1.5 million remeasurement loss on revaluation of monetary assets and liabilities. The remeasurement loss for Harvest Vinccler 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. At December 31, 2010, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 2.9 million and BsF 3.2 million, respectively.
          See Note 9 — Investment in Equity Affiliates — Petrodelta, S.A. for a discussion on the effects of the exchange agreements on Petrodelta’s business.
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

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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.
Cash and Cash Equivalents
          Cash equivalents include money market funds and short term certificates of deposit with original maturity dates of less than three months.
Financial Instruments
          Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. Cash and cash equivalents are placed with commercial banks with high credit ratings. This diversified investment policy limits our exposure both to credit risk and to concentrations of credit risk.
          Total long-term debt at December 31, 2010 consisted of $32 million of fixed-rate unsecured senior convertible notes maturing in 2013 unless earlier redeemed, purchased or converted and $60 million of fixed-rate unsecured term loan facility maturing in 2012. A hypothetical 10 percent adverse change in the floating rate would not have a material effect on our results of operations for the year ended December 31, 2010.
Notes Receivable
          Notes receivable relate to prospect leasing cost financing arrangements, bear interest and can have due dates that are less than one year or more than one year. Amounts outstanding under the notes bear interest at a rate based on the current prime rate and are recorded at face value. Interest is recognized over the life of the note. We may or may not require collateral for the notes.
          Each note is analyzed to determine if it is impaired pursuant to the accounting standard for accounting by creditors for impairment of a loan. A note is impaired if it is probable that we will not collect all principal and interest contractually due. We do not accrue interest when a note is considered impaired. All cash receipts on impaired notes are applied to reduce the accrued interest on the note until the interest is made current and, thereafter, applied to reduce the principal amount of such notes.
          At December 31, 2010, note receivable plus accrued interest was approximately $3.4 million and considered to be fully recoverable.
Other Assets
          Other assets consist of investigative costs of $0.3 million associated with new business development projects and deferred financing costs of $2.2 million. The investigative costs are reclassified to oil and natural gas properties or expensed depending on management’s assessment of the likely outcome of the project. During the year ended December 31, 2010, $2.9 million of costs related to a future financing which we are no longer pursuing was expensed and $0.5 million of investigative costs related to new business development was reclassified to exploration expense. During the year ended December 31, 2009, $1.4 million was reclassified to oil and gas properties and $1.7 million was reclassified to exploration expense.
          Deferred financing costs relate to specific financing and are amortized over the life of the financing to which the costs relate. See Note 3 — Long-Term Debt.
Investment in Equity Affiliates
          Investments in unconsolidated companies in which we have less than a 50 percent interest and have significant influence are accounted for under the equity method of accounting. Investment in Equity Affiliates is increased by additional investments and earnings and decreased by dividends and losses. We review our Investment in Equity Affiliates for impairment whenever events and circumstances indicate a decline in the recoverability of its carrying value.

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          There are many factors to consider when evaluating an equity investment for possible impairment. Currency devaluations, inflationary economies and cash flow analysis are some of the factors we consider in our evaluation for possible impairment. 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. At December 31, 2010 and 2009, there were no events that caused us to evaluate our investment in Petrodelta for impairment.
Property and Equipment
          The major components of property and equipment at December 31 are as follows (in thousands):
                 
    2010     2009  
Proved property costs
  $ 27,355     $ 1,646  
Unproved property costs
    94,026       54,111  
Oilfield inventories
    5,400       2,786  
Other administrative property
    3,209       3,085  
 
           
 
    129,990       61,628  
Accumulated depletion, impairment and depreciation
    (5,010 )     (1,387 )
 
           
 
  $ 124,980     $ 60,241  
 
           
          Properties and equipment are stated at cost less accumulated depletion, depreciation and amortization (“DD&A”). Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if appropriate, gains or losses are recognized in investment earnings and other.
          We follow the successful efforts method of accounting for our oil and gas properties. Under this method, exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that proved reserves, as that term is defined in Securities and Exchange Commission (“SEC”) regulations, have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense. Costs of drilling successful exploratory wells, all development wells, and related production equipment and facilities are capitalized and depleted or depreciated using the unit-of-production method as oil and gas is produced. Depletion expense, which was all attributable to our Utah operations, for the years ended December 31, 2010 and 2009, was $3.3 million and $0.03 million ($16.71 and $6.59 per equivalent barrel), respectively.
          Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent associated with successful exploration activities. Costs of maintaining and retaining undeveloped leaseholds, as well as amortization and impairment of unsuccessful leases, are included in exploration expense. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties.
          Proved oil and gas properties are reviewed for impairment at a level for which identifiable cash flows are independent of cash flows of other assets when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are determined based on estimated future oil and gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these undiscounted estimated future net cash flows is less than the carrying amount of the property, an impairment loss is recognized for the excess of the property’s carrying amount over its estimated fair value, which is generally based on discounted future net cash flows. No impairment of proved oil and gas properties was required in 2010.
          Costs of drilling and equipping successful exploratory wells, development wells, asset retirement liabilities and costs to construct or acquire offshore platforms and other facilities, are depreciated using the unit-of-production method based on total estimated proved developed reserves. Costs of acquiring proved properties, including

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leasehold acquisition costs transferred from unproved leaseholds, are depleted using the unit-of-production method based on total estimated proved reserves. All other properties are stated at historical acquisition cost, net of allowance for impairment, and depreciated using the straight-line method over the useful lives of the assets.
          Undeveloped property costs, excluding oilfield inventories, consist of $3.3 million for West Bay, $64.7 million for Antelope, $9.5 million for the Budong-Budong production sharing contract (“Budong PSC”), $9.2 million for the Dussafu Marin exploration production sharing contract (“Dussafu PSC”), $4.2 million for the Oman exploration and production sharing agreement (“Block 64 EPSA”) and $3.1 million for WAB-21.
          Suspended Exploratory Drilling Costs. At December 31, 2010, oil and gas properties included capitalized suspended exploratory drilling costs of $16.5 million. We did not have any suspended exploratory drilling costs at December 31, 2009. The $16.5 million of suspended exploratory drilling costs relates to drilling in the Mesaverde formation in the Bar F #1-20-3-2 (“Bar F”). The Mesaverde Gas Exploration and Appraisal Project (“Mesaverde”) targeted the Mesaverde formation in the Uintah Basin of Utah. Testing 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. While the results to date have not definitively determined the commerciality of stand-alone development of the Mesaverde in the current gas price environment, we believe that the test results confirm that the Mesaverde formation exhibits sufficient quantities of hydrocarbons and reservoir over-pressure to justify potential development, and we are actively pursuing efforts to assess whether reserves can be attributed to this reservoir. If additional information becomes available that raises substantial doubt as to the economic or operational viability of this project, the associated costs will be expensed at that time.
          Depreciation of other administrative property is computed using the straight-line method with depreciation rates based upon the estimated useful life of the property, generally 5 years. Leasehold improvements are depreciated over the life of the applicable lease. Depreciation expense was $0.5 million, $0.4 million and $0.2 million for the years ended December 31, 2010, 2009 and 2008, respectively.
Capitalized Interest
          We capitalize interest costs for qualifying oil and gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation. During the year ended December 31, 2010, we capitalized interest costs for qualifying oil and gas property additions of $1.8 million. No interest was capitalized for the year ended December 31, 2009.
Fair Value Measurements
          We adopted the accounting standard for fair value measurements for financial assets as of January 1, 2008 and for non-financial assets and liabilities as of January 1, 2009. This standard provides guidance for using fair value to measure assets and liabilities. This standard also clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing the asset or liability and establishes a fair value hierarchy, giving the highest priority to quoted prices in active markets and the lowest priority to unobservable data. The standard applies whenever other standards require assets or liabilities to be measured at fair value. The adoption of this standard had no impact on our consolidated financial position, results of operations or cash flows.
          At December 31, 2010 and 2009, respectively, cash and cash equivalents include $51.0 million and $26.8 million, respectively, in money market funds comprised of high quality, short-term investments with minimal credit risk, which are reported at fair value. The fair value measurement of these securities is based on quoted prices in active markets (level 1 input) for identical assets. The estimated fair value of our senior convertible notes based on observable market information (level 2 input) as of December 31, 2010 was $61.7 million. The estimated fair value of our term loan facility based on internally developed inputs based on management’s best estimate (level 3 input) for identical liabilities as of December 31, 2010 was $60.0 million.
          Our current assets and liabilities accounts include financial instruments, the most significant of which are accounts receivables and trade payables. We believe the carrying values of our current assets and liabilities approximate fair value, with the exception of the note receivable. Because this note receivable is not publicly-traded

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and not easily transferable, the estimated fair value of our notes receivable is based on the market approach and time value of money which approximates the note receivable book value of $3.4 million. The majority of inputs used in the fair value calculation of the note receivable are Level 3 inputs and are consistent with the information used in determining impairment of the note receivable.
Asset Retirement Liability
          The accounting for asset retirement obligations standard requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. No wells were abandoned during the years ended December 31, 2010 or 2009. Changes in asset retirement obligations during the years ended December 31, 2010 and 2009, respectively, were as follows (in thousands):
                 
    December 31,     December 31,  
    2010     2009  
Asset retirement obligations beginning of period
  $ 50     $  
Liabilities recorded during the period
    382       50  
Liabilities settled during the period
           
Revisions in estimated cash flows
    197        
Accretion expense
    34        
 
           
Asset retirement obligations end of period
  $ 663     $ 50  
 
           
Income Taxes
          Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carryforwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Noncontrolling Interests
          We adopted the accounting standard for noncontrolling interests in consolidated financial statements as of January 1, 2009. Our noncontrolling interest relates to Vinccler’s indirectly owned 20 percent interest in HNR Finance (see Note 1 — Organization).
Reserves
          In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting. In January 2010, the Financial Accounting Standards Board (“FASB”) issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Such a change is accounted for prospectively under the authoritative accounting guidance. Comparative disclosures applying the new guidance for periods before the adoption of the FASB’s final rule are not required.
          The adoption of the FASB’s final rule on December 31, 2009 impacted our financial statements and other disclosures in our Annual Report on Form 10-K for the year ended December 31, 2010, as follows:
    All oil and gas reserves volumes presented as of and for the year ended December 31, 2010 and 2009 were prepared using the updated reserves rules and are not on a basis comparable with prior periods. The change in comparability occurred because the FASB’s final rule requires the use of the unweighted 12-month average of the first-day-of-the-month reference price for the prior twelve month period and permits the use of reliable technologies to support reserve estimates. Under the previous reserve estimation rules, which are no longer in effect, our reserves would have been calculated using end of period prices.

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    The impairment review of our proved oil and gas properties used undiscounted estimated future net cash flows models for our estimated proved developed reserves which were calculated using the FASB’s final rule.
          The impact of the adoption of the FASB’s final rule on our financial statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.
New Accounting Pronouncements
          In January 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010-06, which is included in the Accounting Standards Codification (“ASC”) under 820, “Fair Value Measurements and Disclosures” (“ASC 820”). This update requires the disclosure of transfers between the observable input categories and activity in the unobservable input category for fair value measurements. The guidance also requires disclosures about the inputs and valuation techniques used to measure fair value and became effective for our interim and annual reporting periods beginning January 1, 2010. The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows.
          In February 2010, the FASB issued ASU No. 2010-09, which is included in the Codification under ASC 855, “Subsequent Events” (“ASC 855”). This update removes the requirement for an SEC filer to disclose the date through which subsequent events have been evaluated and became effective for our interim and annual reporting periods beginning January 1, 2010. The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows.
          In March 2010, the FASB issued ASU No. 2010-11, which is included in the Codification under ASC 815, “Derivatives and Hedging” (“ASC 815”). This update clarifies the type of embedded credit derivative that is exempt from embedded derivative bifurcation requirements. Only an embedded credit derivative that is related to the subordination of one financial instrument to another qualifies for the exemption. This guidance became effective for our interim and annual reporting periods beginning January 1, 2010. The adoption of this guidance did not have a material impact on our consolidated financial position, results of operations or cash flows.
          In May 2010, the FASB issued ASU No. 2010-19, which is included in ASC under 830, “Foreign Currency” (“ASC 830”). This update addresses the multiple foreign currency exchange rates and the impact of highly inflationary accounting in Venezuela. Since the U.S. Dollar is the functional and reporting currency for all of our Venezuela entities, the adoption of this update did not have an impact on our consolidated financial position, results of operations or cash flows.
          In July 2010, the FASB issued ASU 2010-20 Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses (“ASU 2010-20”), which amends existing guidance by requiring more robust and disaggregated disclosures by an entity about the credit quality of its financing receivables and its allowance for credit losses. These disclosures will provide financial statement users with additional information about the nature of credit risks inherent in financing receivables, how credit risks are analyzed and assessed in determining allowance for credit losses, and reasons for any changes made in allowance for credit losses. This update is generally effective for interim and annual reporting periods ending on or after December 15, 2010; however, certain aspects of the update pertaining to activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. The adoption of ASU 2010-20 did not have a material impact on our consolidated financial position, results of operations or cash flows.
Use of Estimates
          The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserve volumes and future development costs. Actual results could differ from those estimates.

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Reclassifications
     Certain items in 2009 have been reclassified to conform to the 2010 financial statement presentation.
Note 3 — Long-Term Debt
          Long-term debt consists of the following (in thousands):
                 
    December 31,     December 31,  
    2010     2009  
Senior convertible notes, unsecured, with interest at 8.25% See description below
  $ 32,000     $  
Term loan facility with interest at 10% See description below
    60,000        
 
           
 
    92,000        
Discount on term loan facility See description below
    (10,763 )      
Less current portion
           
 
           
 
  $ 81,237     $  
 
           
          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, interest is payable semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2010. The senior convertible 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 senior convertible notes, equivalent to a conversion price of approximately $5.71 per share of common stock. The notes are 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. Financing costs of $1.9 million associated with the senior convertible notes offering are being amortized over the remaining life of the notes. These costs are amortized in Other Assets at December 31, 2010.
          On October 29, 2010, we closed of a $60.0 million term loan facility with MSD Energy Investments Private II, LLC (“MSD Energy”), an affiliate of MSD Capital, L.P., as the sole lender under the term loan facility. Under the terms of the term loan facility, interest is paid on a monthly basis at the initial rate of 10 percent and will mature on October 28, 2012. The initial rate of interest increases to 15 percent on July 28, 2011, the Bridge Date. The Bridge Date may be extended at our option for three months by paying a fee to MSD Energy in the amount of five percent of the initial principal amount of the term loan facility. Financing costs of $0.3 million associated with the term loan facility offering are being amortized over the remaining life of the loan. These costs are amortized in Other Assets at December 31, 2010.
          In connection with the term loan facility, we issued to MSD Energy (1) 1.2 million warrants exercisable at any time on or after the closing date for a period of five years from the closing date on a cashless exercise basis at $15 per share until the Bridge Date, at which time the exercise price per share will equal the lower of $15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date (“Tranche A”); (2) 0.4 million warrants exercisable at any time on or after the closing date for a period of five years from the closing date on a cashless exercise basis at $20 per share until the Bridge Date, at which time the exercise price per share will equal the lower of $15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date (“Tranche B”); and (3) 4.4 million warrants exercisable at any time on or after the Bridge Date for a period of five years from the Bridge Date on a cashless exercise basis at the lower of $15 per share or 120 percent of the average closing price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date (“Tranche C”). The 4.4 million warrants may be redeemed by Harvest for $0.01 per share at any time prior to the Bridge Date in conjunction with the repayment of the loan prior to the Bridge Date.
     The Black-Scholes option pricing model was used in pricing Tranche A and Tranche B. Tranche A was priced at $5.46 per warrant, and Trance B was priced at $4.60 per warrant. The Monte Carlo option pricing model

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was used in pricing Trance C due the pricing and vesting variables in the agreement. Tranche C was priced at $0.62 per warrant. The value of the warrants, $11.1 million, is recorded as Discount on Debt with a corresponding credit to additional paid in capital on our consolidated balance sheet at December 31, 2010. The Discount on Debt is being amortized over the life of the warrants.
          The principal payment requirements for our long-term debt outstanding at December 31, 2010 are as follows (in thousands):
         
2011
  $  
2012
    60,000  
2013
    32,000  
 
     
 
  $ 92,000  
 
     
Note 4 — Liquidity
     Our liquidity outlook has changed since December 31, 2009 primarily as a result of funding requirements of our exploration projects and development of our oil and gas properties. The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. In Item 1A — Risk Factors, we discuss a number of variables and risks related to our exploration projects and our minority equity investment in Petrodelta 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.
     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. We require capital principally to fund the exploration and development of new oil and gas properties. For calendar year 2011, we have established a preliminary exploration and drilling budget of approximately $46.5 million. We are concentrating a substantial portion of this budget on the development of our Antelope project, the Budong PSC and the Dussafu PSC. As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. Currently, we have a work commitment of $22.0 million which is a minimum amount to be spent on the Block 64 EPSA for the drilling of two wells over a three-year period which expires in May 2012. We currently plan to fund this commitment in 2012, and we may be required to raise capital to do so. We also have minimum work commitments during the various phases of the exploration periods in the Budong PSC and Dussafu PSC.
     As a petroleum exploration and production company, our revenue, profitability, cash flows, and future rate of growth are substantially dependent on the condition of the oil and gas industry generally, our success with our exploration program, and the belief that Petrodelta will fund its own operations and continue to pay dividends. Because our revenues are generated from customers with the same economic interests, our operations are also susceptible to market volatility resulting from economic, cyclical, weather or other factors related to the energy industry. Changes in the level of operating and capital spending in the industry, decreases in oil or gas prices, or industry perceptions about future oil and gas prices could adversely affecting our financial position, results of operations and cash flows. Based on our current level of cash flow from operations, we will be required to raise capital to meet our general and administrative costs and fund our oil and gas programs.
     Revenues from the Monument Butte Extension and Lower Green River/Upper Wasatch projects have increased significantly during 2010; however, our primary source of cash still remains to be dividends from Petrodelta and funding from debt financing. In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under IFRS for the year ended December 31, 2009. This dividend is subject to shareholder approval, and will not be paid by Petrodelta until Petrodelta shareholder approval is received. Shareholder approval was received on March 14, 2011. We expect to receive future dividends from Petrodelta; however, we expect that in the near term Petrodelta will reinvest most of its earnings into the company in support of its drilling and appraisal activities. Therefore, there is uncertainty that Petrodelta will pay additional dividends in 2011 or 2012.
     Additionally, any dividend received from Petrodelta carries a liability to our non-controlling interest holder, Vinccler, for its 20 percent share. Dividends declared and paid by Petrodelta are paid to HNR Finance, our consolidated subsidiary. HNR Finance must declare a dividend in order for us and our non-controlling interest holder, Vinccler, to receive our respective shares of Petrodelta’s dividends. A dividend from HNR Finance is due upon demand. Currently, Vinccler has not demanded its respective share of the two most recent Petrodelta dividends and has waived such a demand until at least April 2012. As of December 31, 2010, Vinccler’s share of the undistributed dividends is $9.0 million inclusive of the unpaid November 2010 dividend. See Item 15 — Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 16 — Related Party Transactions.
     We have incurred significant debt during 2010 which has imposed restrictions on us and increased our vulnerability to adverse economic and industry conditions. Our monthly and semi-annual interest expense has increased significantly, and our senior convertible notes and term loan facility impose new restrictions on us. Our senior convertible notes and term loan facility impose covenant restrictions on us that limit our ability to obtain additional financing. Our ability to meet these covenants is primarily dependent on meeting customary affirmative covenant clauses, including providing consolidated statements to be audited and accompanied by a report and opinion of an independent certified public accountant, which report and opinion shall not be subject to any “going concern” or like qualification. Our inability to satisfy the covenants contained in our long term debt arrangements would constitute an event of default, if not waived. An uncured default could result in our outstanding debt becoming immediately due and payable. If this were to occur, we may not be able to obtain waivers or secure alternative financing to satisfy our obligations, either of which would have a material adverse impact on our business. As of December 31, 2010, we were in compliance with all of our long term debt covenants.
     At December 31, 2010, we had cash on hand of $58.7 million. We believe that this cash plus cash generated from Petrodelta dividends and funding from debt financing combined with our ability to vary the timing of our capital expenditures is sufficient to fund our operations and capital commitments through at least December 31, 2011. However, if the Petrodelta dividend payment is not received as expected or our cash sources and requirements are different than expected, it could have a material adverse effect on our operations.
     In order to increase our liquidity to levels sufficient to meet our commitments, we are currently pursuing a number of actions including possible delay of discretionary capital spending to future periods, possible farm-out or sale of assets, or other monetization of asset as necessary to maintain the liquidity required to run our operations. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, increasing production in our producing assets, and cost reductions. Although we believe that we will have adequate liquidity to meet our future operating requirements and to remain compliant with the covenants under our long term debt arrangements, the factors described above create uncertainty. 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. Accordingly, there can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.

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Note 5 — Commitments and Contingencies
          We have employment contracts with seven executive officers which provide for annual base salaries, eligibility for bonus compensation and various benefits. The contracts provide for a lump sum payment as a multiple of base salary in the event of termination of employment without cause. In addition, these contracts provide for payments as a multiple of base salary and bonus, excise tax reimbursement, outplacement services and a continuation of benefits in the event of termination without cause following a change in control. By providing one year notice, these agreements may be terminated by either party on or after May 31, 2011.
          In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month. In December 2008, we signed a five-year lease for additional office space in Houston, Texas, for approximately $15,000 per month. In August 2010, we relinquished a portion of our office space in Houston, Texas, for an approximate $1,600 per month reduction of cost. In December 2010, Harvest Vinccler extended its lease for office space in Caracas, Venezuela for one year for approximately $7,000 per month. In October 2010, we signed a two-year lease in Roosevelt, Utah for approximately $6,000 per month. In October 2010, we signed a two-year lease for office space in Singapore for approximately $7,000 per month. In April 2009, we signed a two-year lease for office space in Indonesia for approximately $5,000 per month. In September 2009, we signed a two-year lease for office space in Oman for approximately $5,000 per month. In September 2010, we signed a five-year lease for office space in London for approximately $9,000 per month. At December 31, 2010, we had $0.7 million of commitments related to a drilling rig and other equipment for our domestic operations. The commitment for the drilling rig of $0.6 million was met in January 2011. We also have minimum work funding commitments during the various phases of the exploration periods in the Budong-Budong Production Sharing Contract (“Budong PSC”), Dussafu Marin Permit offshore Gabon in West Africa (“Dussafu PSC”) and Al Ghubar / Qarn Alam license (“Block 64 EPSA”).
          In April 2009, we signed an Exploration and Production Sharing Agreement (“EPSA”) with Oman for the Block 64 EPSA. We have an obligation to drill two wells over a three-year period with a funding commitment of $22.0 million.
          Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc., Branta Exploration & Production, LLC, Ute Energy LLC, Cameron Cuch, Paula Black, Johnna Blackhair, and Elton Blackhair in the United States District Court for the District of Utah. This suit was served in April 2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the defendants, among other things, intentionally interfered with Plaintiffs’ employment agreement with the Ute Indian Tribe — Energy & Minerals Department and intentionally interfered with Plaintiffs’ prospective economic relationships. Plaintiffs seek actual damages, punitive damages, costs and attorney’s fees. We dispute Plaintiffs’ claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.
          Uracoa Municipality Tax Assessments. Our Venezuelan subsidiary, Harvest Vinccler, has received nine assessments from a tax inspector for the Uracoa municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:
    Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the capital fee reimbursement and related interest paid by PDVSA under the Operating Service Agreement (“OSA”). Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims.

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    Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims.
 
    Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim.
 
    Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims.
Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s, the Venezuelan income tax authority, interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.
          Libertador Municipality Tax Assessments. Harvest Vinccler has received five assessments from a tax inspector for the Libertador municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:
    One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Mayor’s Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. On April 10, 2008, the Tax Court suspended the case pending a response from the Mayor’s Office to the protest. If the municipality’s response is to confirm the assessment, Harvest Vinccler will defer to the competent Tax Court to enjoin and dismiss the claim.
 
    Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.
 
    Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.
Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the refund of all municipal taxes paid since 2002.
          We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such litigation which will have a material adverse impact on our financial condition, results of operations and cash flows.
Note 6 — Taxes
Taxes Other Than on Income
          The components of taxes other than on income were (in thousands):

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    2010     2009     2008  
Franchise taxes
  $ 196     $ 182     $ (951 )
Payroll and other taxes
    852       833       745  
 
                 
 
  $ 1,048     $ 1,026     $ (206 )
 
                 
          During the year ended December 31, 2008, we reversed a $1.1 million franchise tax provision that was no longer required.
Taxes on Income
          The tax effects of significant items comprising our net deferred income taxes as of December 31, 2010, are as follows (in thousands):
                 
    2010     2009  
Deferred tax assets:
               
Operating loss carryforwards
  $ 26,849     $ 15,599  
Alternative minimum tax credit
    1,222        
Stock options
    1,330       1,426  
Return to accrual adjustment
    4,720        
Restricted stock
    256        
Delay rentals
    176        
Valuation allowance
    (28,343 )     (17,025 )
 
           
Net deferred tax asset
    6,210        
Deferred tax liability:
               
Geological and geophysical/seismic
    (505 )      
Intangible drilling costs
    (5,705 )      
 
           
Net deferred tax asset (liability)
  $     $  
 
           
          The valuation allowance increased by $11.3 million as a result of additional net operating losses and tax benefits that we do not expect to fully realize through future taxable income. Realization of deferred tax assets associated with net operating loss carryforwards is dependent upon generating sufficient taxable income prior to their expiration. Management anticipates that additional losses will be generated and that it is more likely than not that they will not be realized through future taxable income. Management further anticipates that any unremitted foreign earnings will be reinvested outside of the U.S.
          The components of income before income taxes are as follows (in thousands):
                         
    2010     2009     2008  
Income (loss) before income taxes United States
  $ (24,743 )   $ (22,357 )   $ (34,760 )
Foreign
    (13,620 )     (7,522 )     (14,326 )
 
                 
Total
  $ (38,363 )   $ (29,879 )   $ (49,086 )
 
                 
          The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):
                         
    2010     2009     2008  
Current:
                       
United States
  $ (1,210 )   $ 39     $ (128 )
Foreign
    1,042       1,143       153  
 
                 
 
    (167 )     1,182       25  
Deferred:
                       
Foreign
    (16 )            
 
                 
 
  $ (184 )   $ 1,182     $ 25  
 
                 
          A comparison of the income tax expense (benefit) at the federal statutory rate to our provision for income taxes is as follows (in thousands):

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    2010     2009     2008  
Computed tax expense (benefit) at the statutory rate
  $ (13,427 )   $ (10,458 )   $ (17,180 )
Effect of foreign source income and rate differentials on foreign income
    6,000       3,775       5,167  
Change in valuation allowance
    11,111       9,184       6,059  
Tax on undistributed earnings
                5,446  
Deemed income inclusion under Subpart F
                968  
Permanent differences
    2,062              
Foreign disregarded entities
          21       (268 )
Return to accrual adjustment
    (4,720 )     (1,093 )     (166 )
Income tax refund
    (1,210 )            
Other
          (247 )     (1 )
 
                 
Total income tax expense
  $ (184 )   $ 1,182     $ 25  
 
                 
          Rate differentials for foreign income result from tax rates different from the U.S. tax rate being applied in foreign jurisdictions.
           Out-of-Period Adjustment — During the fourth quarter of 2010, we recorded an out-of-period adjustment in our consolidated financial statements for the year ended December 31, 2010. This adjustment related to the accounting for an income tax refund of $1.0 million that had not been accrued at September 30, 2010. The refund was applied for on September 15, 2010 and received on October 25, 2010. We recorded the $1.0 million as an income tax benefit in the fourth quarter of 2010; however, the $1.0 million income tax refund should have been recognized as an income tax benefit in the third quarter of 2010. As a result, Accounts and notes receivable — joint interest and other was understated and net income attributable to Harvest was understated by $1.0 million for the third quarter of 2010, or $(0.03) per diluted share, and net income attributable to Harvest was overstated by $1.0 million for the fourth quarter of 2010, or $0.03 per diluted share. Net income attributable to Harvest is correctly stated for the year ended December 31, 2010. The error has no impact to the consolidated statements of cash flows. Management concluded the impact of the error is immaterial to the financial statements in the period in which it occurred as well as the period in which it was corrected.
          At December 31, 2010, we had, for federal income tax purposes, operating loss carryforwards of approximately $90.6 million, expiring in the years 2026 through 2030.
Accounting for Uncertainty in Income Taxes
          We or one of our subsidiaries files income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years prior to 2007. To date, the Internal Revenue Service (“IRS”) has not performed an examination of our U.S. income tax returns for 2007 through 2009.
          We do not have any unrecognized tax benefits or loss contingencies.
Note 7 — Stock Option and Stock Purchase Plans
          In May 2010, our shareholders approved the 2010 Long Term Incentive Plan (the “2010 Plan”). The 2010 Plan provides for the issuance of up to 1,700,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”), restricted stock, restricted stock units (“RSUs”) and other stock-based awards to eligible participants including employees, non-employee directors and consultants of our Company or subsidiaries. Under the 2010 Plan, no more than 500,000 shares may be granted as restricted stock. No individual may be granted more than 1,000,000 options or SARs. The exercise price of stock options granted under the 2010 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted to date will vest in the manner and subject to the conditions specified in the award agreement and expire five years from grant date. Restricted stock granted vest in the manner and subject to the conditions specified in the award agreement. The 2010 Plan also permits the granting of performance awards and other cash-based awards to eligible employees and consultants. Performance awards may be in the form of performance stock, performance units and other form of award established by the Board of Directors’ Human Resource Committee (the “Committee”) with vesting based on the accomplishment of a performance goal. No individual may be awarded performance related cash awards during a calendar year that could result in a cash payment of more than $5.0 million. In the event of a change in control, the Committee shall act to effect one or more of the following alternatives, which may vary among individual holders of awards granted under the 2010 Plan and which may vary among awards held by any individual holder of an award granted under the 2010 Plan: (1) accelerate vesting; (2) require mandatory surrender; (3) assume outstanding awards or have a new award of a similar nature substituted; (4) adjust the number and class of common stock covered by an award; and/or (5) make adjustments deemed appropriate to reflect the change of control.
          In May 2006, our shareholders approved the 2006 Long Term Incentive Plan (the “2006 Plan”). The 2006 Plan provides for the issuance of up to 1,825,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to eligible participants including employees, non-employee directors and consultants of our company or subsidiaries. Under the 2006 Plan, no more than 325,000

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shares may be granted as restricted stock. No individual may be granted more than 900,000 options or SARs and no more than 175,000 shares of restricted stock during any period of three consecutive calendar years. The exercise price of stock options granted under the 2006 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted through December 31, 2006 vest ratably over a three to five year period from their dates of grant and expire seven to ten years from grant date. Restricted stock granted to employees or consultants to date is subject to a restriction period of not less than 36 months during which the stock will be deposited with Harvest and is subject to forfeiture under certain circumstances. Restricted stock granted to non-employee directors vests as to one-third of the shares on each anniversary of the date of grant of the award provided that he is still a director on that date. The 2006 Plan also permits the granting of performance awards to eligible employees and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time of at least one year. No employee or consultant shall be granted a performance award during a calendar year that could result in a cash payment of more than $5.0 million. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become exercisable.
          In May 2004, our shareholders approved the 2004 Long Term Incentive Plan (the “2004 Plan”). The 2004 Plan provides for the issuance of up to 1,750,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to eligible participants including employees, non-employee directors and consultants of our company or subsidiaries. Under the 2004 Plan, no more than 438,000 shares may be granted as restricted stock, and no individual may be granted more than 110,000 shares of restricted stock or 438,000 in options over the life of the Plan. The exercise price of stock options granted under the 2004 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date. Restricted stock granted to employees or consultants to date is subject to a restriction period of not less than 36 months during which the stock will be deposited with Harvest and is subject to forfeiture under certain circumstances. Restricted stock granted to non-employee directors vests as to one-third of the shares on each anniversary of the date of grant of the award provided that he is still a director on that date (as amended). The 2004 Plan also permits the granting of performance awards to eligible employees and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time of at least one year. Performance awards granted under the Plan may not exceed $5.0 million in a calendar year and may not exceed $2.5 million to any one individual in a calendar year. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become exercisable.
          In July 2001, our shareholders approved the 2001 Long Term Stock Incentive Plan (the “2001 Plan”). The 2001 Plan provides for grants of options to purchase up to 1,697,000 shares of our common stock in the form of Incentive Stock Options and Non-Qualified Stock Options to eligible participants including employees of our company or subsidiaries, directors, consultants and other key persons. The exercise price of stock options granted under the 2001 Plan must be no less than the fair market value of our common stock on the date of grant. No officer may be granted more than 500,000 options during any one fiscal year, as adjusted for any changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date.
          Since 1989 we have adopted several other stock option plans under which options to purchase shares of our common stock have been granted to employees, officers, directors, independent contractors and consultants. Options granted under these plans have been at prices equal to the fair market value of the stock on the grant dates. Options granted under the plans are generally exercisable in varying cumulative periodic installments after one year and cannot be exercised more than ten years after the grant dates. Following the adoption of the 2001 Plan, no options may be granted under any of these plans.
          A summary of the status of our stock option plans as of December 31, 2010, 2009 and 2008 and changes during the years ending on those dates is presented below (shares in thousands):

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    2010     2009     2008  
    Weighted                     Weighted                     Weighted              
    Average     Remaining     Aggregate     Average     Remaining     Aggregate     Average     Remaining     Aggregate  
    Exercise     Contractual     Intrinsic     Exercise     Contractual     Intrinsic     Exercise     Contractual     Intrinsic  
    Shares     Price     Life     Value     Shares     Price     Life     Value     Shares     Price     Life     Value  
Outstanding at beginning of the year:
    3,363     $ 9.35                       3,783     $ 8.54                       4,172     $ 7.80                  
Options granted
    467       7.10                       118       4.60                       444       10.28                  
Options exercised
    (419 )     (4.01 )                     (205 )     (2.11 )                     (548 )     (2.86 )                
Options cancelled
    (185 )     (9.62 )                     (333 )     (2.95 )                     (285 )     (11.34 )                
Outstanding at end of the year
    3,226       9.70       3.7       8,522       3,363       9.35       4.2       1,312       3,783       8.54       5.3       1,846  
 
                                                                                   
Exercisable at end of the year
    1,784       10.27       3.8       3,954       2,066       9.09       0.8       1,230       2,147       7.23       1.4       1,846  
 
                                                                                   
          The value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions:
                         
For options granted during:   2010     2009     2008  
Weighted average fair value
  $ 4.23     $ 4.60     $ 5.85  
Weighted averaged expected life
    7       7       7  
Valuation assumptions:
                       
Expected volatility
    57.6 %     68.9 %     46.6-49.7 %
Risk-free interest rate
    2.7 %     3.5 %     3.0-3.9 %
Expected dividend yield
    0 %     0 %     0 %
Expected annual forfeitures
    3 %     3 %     3 %
          The Black-Scholes option pricing model was developed for use in estimating the value of traded options that have no vesting restrictions and are fully transferable. In addition, option pricing models require the input of highly subjective assumptions, including the expected stock price volatility and expected life. The expected volatility is based on historical volatilities of our stock. Historical data is used to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options are expected to be outstanding. The risk-free rate for the periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant.
          A summary of our nonvested options as of December 31, 2010, and changes during the year ended December 31, 2010, is presented below (shares in thousands):
                                                 
    2010     2009     2008  
            Weighted-Average             Weighted-Average             Weighted-Average  
    Nonvested     Grant-Date     Nonvested     Grant-Date     Nonvested     Grant-Date  
    Options     Fair Value     Options     Fair Value     Options     Fair Value  
Nonvested at beginning of the year
    1,297     $ 5.50       1,636     $ 5.74       1,800     $ 5.84  
Granted
    467       4.23       118       3.13       444       5.63  
Vested
    (322 )     (5.09 )     (447 )     (5.75 )     (607 )     (5.88 )
Forfeited
                (10 )     (6.54 )     (1 )     (5.62 )
 
                                         
Nonvested at end of the year
    1,442       5.18       1,297       5.50       1,636       5.74  
 
                                         
          As of December 31, 2010, there was $2.8 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under our plans. That cost is expected to be recognized over the next three to four years. The total fair value of shares vested during the years ended December 31, 2010, 2009 and 2008 was $2.6 million, $2.6 million and $4.0 million, respectively.
          In addition to options issued pursuant to the plans, options have been issued to new hire employees as employment inducement grants under a New York Stock Exchange (“NYSE”) exception. These options were granted in 2007 and 2008 between $10.07 and $12.63 and vest over three years. At December 31, 2010, a total of 0.4 million options issued outside of the plans were outstanding and 0.3 million options were exercisable.

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          Stock options of 0.4 million were exercised in the year ended December 31, 2010 resulting in cash proceeds of $1.7 million. Stock options of 0.2 million were exercised in the year ended December 31, 2009 resulting in cash proceeds of $0.4 million.
Note 8 — Operating Segments
          We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Operations included under the heading “United States and Other” include U.S. operations, corporate management, cash management, business development and financing activities performed in the United States and other countries which do not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the United States and Other segment and are not allocated to other operating segments.
                         
    2010     2009     2008  
    (in thousands)  
Segment Revenues
                       
Oil and gas sales:
                       
United States and other
  $ 10,696     $ 181     $  
 
                 
Total oil and gas sales
    10,696       181        
 
 
                 
Segment Income (Loss) Attributable to Harvest
                       
Venezuela
    62,050       39,696       33,020  
Indonesia
    (7,108 )     (5,124 )     (8,966 )
United States and other
    (39,602 )     (37,679 )     (45,518 )
 
                 
Net income (loss) attributable to Harvest
  $ 15,340     $ (3,107 )   $ (21,464 )
 
                 
                 
    December 31,  
    2010     2009  
    (in thousands)  
Operating Segment Assets
               
Venezuela
  $ 292,023     $ 249,484  
Indonesia
    16,254       5,893  
United States and other
    229,518       132,913  
 
           
 
    537,795       388,290  
Intersegment eliminations
    (49,551 )     (39,511 )
 
           
 
  $ 488,244     $ 348,779  
 
           
Note 9 — Investment in Equity Affiliates
Petrodelta, S.A.
          On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract was published in the Official Gazette. Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from that date.
          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. Natural gas deliveries are paid in Bolivars, but the pricing for natural gas is referenced to the U.S. Dollar. PPSA is obligated to make payment to Petrodelta of each invoice within 60 days of the end of the invoiced production month by wire transfer, in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered, and in Bolivars in the case of payment for natural gas

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delivered, in immediately available funds to the bank accounts designated by Petrodelta. 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.
          On February 4, 2010, Petrodelta’s board of directors endorsed a capital budget of $205 million for Petrodelta’s 2010 business plan. The budget included 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. Petrodelta contracted a workover rig which was mobilized on October 15, 2010. Due to delays in rig availability, El Salto facilities project execution and lack of funding by PDVSA, Petrodelta only spent $101.8 million of its 2010 budget.
          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.
          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 expected PDVSA to continue requesting and receiving waivers, Petrodelta did not accrue a liability to LOCTI for the year ended December 31, 2009. For filing years 2007 and 2008, PDVSA provided Petrodelta with a copy of the waiver acceptance letter from LOCTI. PDVSA has stated that a waiver was granted for filing year 2009; however, LOCTI has not yet issued the acceptance letter to PDVSA for the 2009 filing year. The potential exposure to LOCTI for the year ended December 31, 2009 after devaluation is $4.8 million, $2.4 million net of tax ($0.8 million net to our 32 percent interest). In January 2011, PDVSA informed its consolidating entities, including Petrodelta, that effective with the 2010 reporting year it would no longer be requesting waivers to file the LOCTI declaration on a consolidated basis. Based on this information, Petrodelta accrued the 2010 liability to LOCTI in the amount of $4.6 million, $2.3 million net of tax ($0.7 million net to our 32 percent interest). In December 2010, LOCTI was modified to reduce the amount of contributions beginning January 2011 to one percent of gross revenues for companies owned by individuals or corporations and 0.5 percent for companies owned by Venezuela. Petrodelta’s rate of contribution starting in 2011 will be 0.5 percent.
          In 2008, the Venezuelan government published in the Official Gazette the Law of Special Contribution to Extraordinary Prices at the Hydrocarbons International Market (“Windfall Profits Tax”). The Windfall Profits Tax is to be calculated on the Venezuelan Export Basket (“VEB”) of prices as published by the Ministry of the People’s Power for Energy and Petroleum (“MENPET”). As instructed by CVP, Petrodelta has applied the Windfall Profits Tax to gross oil production delivered to PDVSA. The 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 Windfall Profits Tax is reported as expense on the income statement and is deductible for Venezuelan tax purposes. Petrodelta recorded $14.1 million, $0.9 million and $56.4 million of expense for the Windfall Profits Tax for the years ended December 31, 2010, 2009 and 2008, respectively.
          In 2009, under instructions issued by CVP, Petrodelta set up a reserve within the equity section of the balance sheet for deferred tax assets. 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

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assets. Dividends received prior to 2009 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.
          During the first 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. 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. The pension adjustment was for past service costs covering the period from January 2008, when the Harvest Vinccler employees were migrated to PDVSA payroll, through May 2009. It is a non-recurring adjustment. Pension costs at December 31, 2009 reasonably reflected Petrodelta’s employee demographic and plan conditions. Petrodelta is not required to reimburse the pension costs to PDVSA until PDVSA pays the pension benefits to employees. 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. During the fourth quarter of 2009, PDVSA reassessed the assumptions used in the 2009 actuarial study. This reassessment resulted in a downward revision of $8.4 million ($2.7 million net to our 32 percent interest) of the pension and retirement plan costs charged to Petrodelta in May 2009. The downward revision of the pension and retirement plan costs was recorded in December 2009. The pension cost is not tax deductible until future periods when the pension is settled in cash. The provision for the pension plan is subject to future revisions, both upwards and downwards, based on the assumptions, the terms of the relevant plans and allocation methodology as determined by PDVSA.
          On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement, which established new exchange rates for the Venezuela 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 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 4.30 Bolivar exchange rate applies to the oil and gas sector. During 2010, PDVSA sold foreign currency to the Central Bank in return for Bolivars. These foreign currency sales were for PDVSA and PDVSA’s subsidiaries. In December 2010, PDVSA invoiced Petrodelta $19.5 million related to sales of foreign currency for Bolivars at the blended exchange rate of 3.61 Bolivars per U.S. Dollar. The $19.5 million is calculated as the difference between U.S. Dollar invoices remeasured at the official exchange rate of 4.30 Bolivars per U.S. Dollar and the same invoices remeasured at the blended exchange rate of 3.61 Bolivars per U.S. Dollar. On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate with an effective date of January 1, 2011. The January 2011 Exchange Agreement eliminated the average exchange rate available under the January 2010 Exchange Agreement to oil and gas producers for exchanging dollars through CADIVI. See Note 2 — Summary of Significant Accounting Policies — Reporting and Functional Currency for a description of the changes due to the Exchange Agreement.
          At December 31, 2009, Petrodelta remeasured the appropriate monetary assets and liabilities at the official exchange rate of 2.15 Bolivars per U.S. Dollar, Petrodelta’s functional and reporting currency. During the year ended December 31, 2010, Petrodelta remeasured the appropriate monetary assets and liabilities at the new official exchange rate of 4.30 Bolivars per U.S. Dollar and recorded an $84.4 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 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, 2010, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 87.0 million and BsF 1,423.0 million, respectively.
          In June 2010, Petrodelta’s board of directors approved the offsetting of accounts payable to PDVSA and its affiliates, including CVP, for 2010 royalties, taxes and operation expenditures against the receivable from PDVSA and its affiliates, including CVP, for 2010 oil and gas deliveries at the exchange rate prevailing as of that date. During February 2011, per instructions received from CVP, Petrodelta proceeded to offset accounts receivable and payables between PDVSA and its affiliates, including CVP, outstanding as of December 31, 2009 at the exchange rate prevailing as of that date. The revised revaluation reduced Petrodelta’s remeasurement gain $36.1 million from $120.5 million in January 2010 to $84.4 million in December 2010.

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          In August 2010, Petrodelta’s board of directors declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received October 22, 2010. The dividend represents 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under International Financial Reporting Standards (“IFRS”) for the year ended December 31, 2009.
          In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under IFRS for the year ended December 31, 2009. This dividend is subject to shareholder approval, and will not be accrued on our consolidated balance sheet until Petrodelta shareholder approval is received. Shareholder approval was received on March 14, 2011.
          Petrodelta’s reporting and functional currency is the U.S. Dollar. HNR Finance owns a 40 percent interest in Petrodelta. Petrodelta’s financial information is prepared in accordance with IFRS which we have adjusted to conform to GAAP. All amounts through Net Income Equity Affiliate represent 100 percent of Petrodelta. Summary financial information has been presented below at December 31, 2010, 2009 and 2008, and for the years ended December 31, 2010, 2009 and 2008:
                         
    Year Ended December 31,  
    2010     2009     2008  
    (in thousands)  
Revenues:
                       
Oil sales
  $ 604,173     $ 451,473     $ 458,113  
Gas sales
    3,398       6,778       16,506  
Royalty
    (204,688 )     (156,799 )     (168,790 )
 
                 
 
    402,883       301,452       305,829  
 
                       
Expenses:
                       
Operating expenses
    44,749       48,311       52,946  
Workovers
    8,910             24,663  
Depletion, depreciation and amortization
    40,429       33,666       25,509  
General and administrative
    15,508       9,750       5,974  
Windfall profits tax
    14,116       882       56,377  
 
                 
 
    123,712       92,609       165,469  
 
                 
 
                       
Income from Operations
    279,171       208,843       140,360  
Gain of exchange rate
    84,448              
Investment earnings and other
    3,179       4        
Interest expense
    (26,767 )     (3,617 )     (2,329 )
 
                 
Income before Income Tax
    340,031       205,230       138,031  
 
                       
Current income tax expense
    189,780       105,868       69,374  
Deferred income tax expense (benefit)
    72,568       (43,922 )     (52,560 )
 
                 
Net Income
    77,683       143,284       121,217  
Adjustment to reconcile to reported Net Income from Unconsolidated Equity Affiliate:
                       
Deferred income tax expense (benefit)
    (91,877 )     38,516       34,827  
 
                 
Net Income Equity Affiliate
    169,560       104,768       86,390  
Equity interest in unconsolidated equity affiliate
    40 %     40 %     40 %
 
                 
Income before amortization of excess basis in equity affiliate
    67,824       41,907       34,556  
Amortization of excess basis in equity affiliate
    (1,414 )     (1,356 )     (1,155 )
Conform depletion expense to GAAP
    (246 )     183       2,533  
 
                 
Net income from unconsolidated equity affiliate
  $ 66,164     $ 40,734     $ 35,934  
 
                 

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    December 31,     December 31,  
    2010     2009  
    (in thousands)  
Current assets
  $ 535,225     $ 404,825  
Property and equipment
    321,816       265,442  
Other assets
    67,755       141,245  
Current liabilities
    406,339       345,812  
Other liabilities
    39,224       33,600  
Net equity
    479,233       432,100  
Fusion Geophysical, LLC (“Fusion”)
          Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering. The purchase of Fusion extended our technical ability and global reach to support a more organic growth and exploration strategy. Our 49 percent minority equity investment in Fusion is accounted for using the equity method of accounting. In October 2008, we increased our minority equity investment in Fusion from 45 percent to 49 percent for $2.2 million. Operating revenue and total assets represent 100 percent of Fusion. No dividends were declared or paid during the years ended December 31, 2010, 2009 and 2008, respectively. Summarized financial information for Fusion follows:
                         
    Year Ended December 31,  
    2010     2009     2008  
            (in thousands)          
Operating Revenues
  $ 10,931     $ 11,089     $ 13,063  
Net Loss
  $ (2,378 )   $ (4,798 )   $ (1,290 )
Equity interest in unconsolidated equity affiliate
    49 %     49 %     49 %
 
                 
Net loss from unconsolidated equity affiliate
    (1,165 )     (2,351 )     (632 )
Amortization of fair value of intangibles
          (995 )     (726 )
Impairment of investment
          (1,631 )      
 
                 
Net loss from unconsolidated equity affiliate
  $ (1,165 )   $ (4,977 )   $ (1,358 )
 
                 
                 
    December 31,     December, 31  
    2010     2009  
Current assets
  $ 1,925     $ 2,726  
Total assets
    23,780       30,205  
Current liabilities
    7,447       8,024  
Total liabilities
    7,479       12,242  
          Approximately 16 percent, 29 percent and 26 percent of Fusion’s revenue for the years ended December 31, 2010, 2009 and 2008, respectively, was earned from Harvest or equity affiliates.
          On April 9, 2009, we entered into a service agreement with Fusion whereby we prepaid $1.5 million for certain services to be performed in connection with certain projects as defined in the service agreement. The services are to be performed in accordance with the existing consulting agreement. Upon written notice to Fusion, the projects and types of services can be amended. The unapplied portion of the prepayment advance bears interest at an annual rate of 12 percent which will be added to the prepayment advance balance and used to offset future service invoices from Fusion. Services rendered have been applied against the prepayment, and as of December 31, 2010, the balance for prepaid services was approximately $0.6 million.
          As of December 31, 2009, we updated the review for impairment of our minority equity investment in Fusion. In preparing this update, future net cash flows prepared by Fusion based on different business opportunities that Fusion is currently pursuing were updated for current activities. These business opportunities were weighted with a probability of success. Based on these cash flow projections and considering Fusion’s current liquidity, we concluded that the potential business opportunities did not support Fusion’s on-going cash flow requirements; and

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therefore, we recorded a $1.6 million charge to fully impair the carrying value of our equity investment in Fusion at December 31, 2009. For the year ended December 31, 2010, Fusion had a year to date net loss. Since our investment in Fusion was fully impaired at year-end 2009, Fusion’s 2010 year to date net loss is not reported in the twelve months ended December 31, 2010 net income from unconsolidated equity affiliates as reporting it would take our equity investment in Fusion into a negative position.
          On January 28, 2011, Fusion’s 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. We received $1.3 million for our equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full of the outstanding balance of the prepaid service agreement, short term loan and accrued interest. The Agreement and Plan of Merger includes an Earn Out provision wherein we would receive an additional payment of up to a maximum of $2.7 million if FusionGeo, Inc.’s 2011 gross profit exceeds $5.6 million. The Earn Out payment will not be determined until early in 2012. We can give no assurance that we will receive any Earn Out payment.
Note 10 — United States
          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.
Gulf Coast
          In March 2008, we executed an AMI agreement with a private third party for an area in the upper Gulf Coast Region of the United States. 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. We are the operator and have an initial working interest of 50 percent in West Bay, the second prospect in the AMI. The first prospect in the AMI was abandoned in 2009 after a dry hole was drilled. The private third party contributed these two prospects, including 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. The funding obligation was met during 2009, and all costs are now being shared by the parties in proportion to their working interests as defined in the AMI.
          The private third party is obligated to evaluate and present additional opportunities at their sole cost. As each prospect is accepted, it will be covered by the AMI.
West Bay Project
          During the year ended December 31, 2010, operational activities in the West Bay prospect focused on firming up plans for drilling on the identified initial drilling prospect and continuing to evaluate the other leads and prospects in the project. Land, regulatory and surface access preparations currently in progress are focused on taking the initial drilling prospect to drill-ready status. During 2010, we finalized a 3-D seismic data trade with a third party and merged the data set with our existing seismic data. The acquisition and merging of the additional 3-D seismic data allows for more complete technical evaluation of the leads and prospects identified in the project. Based on the merged seismic data set, we now have four identified drilling prospects on our acreage. Preliminary work is underway on a drilling barge concept that will be utilized to drill the first two exploration wells. Current plans are to drill the first exploration well in 2011, pending required surface access agreements with a private landowner and pending receipt of necessary permits from the U.S. Army Corps of Engineers.
          In February 2011, the previously existing Alligator Point Unit (as approved by the Texas General Land Office [“GLO”]) expired. We have obtained from the GLO an extension until September 1, 2011 of a smaller version of the Alligator Point Unit defined more specifically by the drilling prospects currently existing on the project. As a result of the GLO approval of the smaller Alligator Point Unit and the anticipated expiry of five leases previously held by the larger unit, we expect our lease position on the West Bay project to be reduced from approximately 13,000 acres in February 2011 to approximately 10,050 acres in August 2011.
          The West Bay project represents $3.3 million and $3.1 million of unproved oil and gas properties as of December 31, 2010 and 2009, respectively.

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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 was obligated to assemble the initial 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.
          In July 2010, we executed a farm-out agreement with the private third party in the JEDA for the acquisition of an incremental 10 percent interest in the Antelope Project with an effective date of July 1, 2010. This acquisition includes all leases, the Mesaverde, the Lower Green River/Upper Wasatch and the Monument Butte Extension. The acquisition excludes the initial eight wells previously drilled in the Monument Butte Extension. Total consideration for the incremental 10 percent interest is $20.0 million, of which (1) $3.0 million was paid on August 2, 2010 (the closing date of the acquisition); (2) $3.0 million to be used as a credit against future joint interest billings or if joint interest billings do not accumulate to $3.0 million by October 1, 2010, at the sole election of the private third party, the balance is to be paid by us within 15 days of receipt of written request from the private third party; and (3) a capped $14.0 million carry of a portion of our partner’s exploration and development cost obligations in the upcoming Lower Green River/Upper Wasatch and Monument Butte Extension drilling programs in the Antelope project. On October 1, 2010, the private third party elected to receive in cash the remaining balance of the joint interest billing credit of $2.4 million. At December 31, 2010, the outstanding balance on the $14.0 million exploration and development cost obligation carry is $8.4 million. Based on current plans, we anticipate the full carry obligation will be met in the first half of 2011. This acquisition increases our ownership in the Antelope project to 70 percent.
          The Antelope leasing activities represents $41.1 million and $19.4 million unproved oil and gas properties as of December 31, 2010 and 2009, respectively.
          The Antelope project is targeted to explore for and develop oil and natural gas from multiple reservoir horizons in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties. Leads and/or prospects were identified in three prospective reservoir horizons in preparation for drilling.
Mesaverde
          Operational activities during the year ended December 31, 2010 included completion of the initial testing activities on the Mesaverde horizons in the deep natural gas test well (the Bar F) that commenced drilling on June 15, 2009. The Bar F was drilled to a total depth of 17,566 feet and an extended production test of the Mesaverde has been completed. Testing was 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. Gas was tested at flow rates of 1.5-2 million cubic feet per day (“MMCFD”) from selected intervals. While the results to date have not definitively determined the commerciality of a stand-alone development of the Mesaverde in the current gas price environment, we believe that the test results confirm that the Mesaverde formation exhibits sufficient quantities of hydrocarbons and reservoir over-pressure to justify potential development, and we are actively pursuing efforts to assess whether reserves can be attributed to this reservoir. The Mesaverde reservoir remains potentially prospective

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over a portion of our land position. Exploratory drilling costs for the Mesaverde have been suspended pending further evaluation. The Mesaverde project represents $16.5 million and $11.3 million of unproved oil and gas properties on our December 31, 2010 and 2009 balance sheets, respectively.
Lower Green River/Upper Wasatch
          The Lower Green River/Upper Wasatch is a second prospective horizon that is being pursued in the Antelope project. After completion of the initial testing program on the Mesaverde deep gas in the Bar F well as described above, we moved uphole in the same well to test multiple oil bearing intervals at depths from 8,200 feet to 9,500 feet in the Lower Green River and Upper Wasatch. Extended flow testing of the well conducted during the second quarter of 2010 indicated that a commercial oil discovery was made in the Lower Green River and Upper Wasatch. A five well Lower Green River/Upper Wasatch delineation and development drilling program was planned to further delineate and appraise the extent of the Lower Green River/Upper Wasatch discovery made in the Bar F, and to establish additional production from the Lower Green River/Upper Wasatch reservoirs in at least some of the five appraisal wells. Based on results of the initial wells in the five well delineation and development drilling program, an additional sixth well was added to the program to be drilled in early 2011.
          The five-well delineation and development drilling program was initiated in the third quarter of 2010. Five wells were in varying stages of completion and drilling and production facilities installation as of December 31, 2010.
          During the fourth quarter of 2010, we initiated permitting activities on a planned 170 square mile 3-D seismic acquisition program which is expected to be acquired in late 2011 and which will be targeted at imaging the Green River and Wasatch formations over the northern portion of our acreage.
          On December 21, 2010, we and our partner in the Antelope project entered into a contract with El Paso Midstream Group, Inc. (“EPMG”) whereby EPMG will provide the capital to build and operate a 25-mile, low-pressure gas gathering pipeline which will provide capacity for our current and future production from the Lower Green River/Upper Wasatch Development project. We will provide capital to build flowlines to connect the produced gas from our wells into the EPMG header system. As part of the contract arrangement, we and our partner have dedicated approximately 75 percent of our Antelope leasehold to the El Paso contract for 10 years, with a Harvest option to extend the dedication for up to an additional nine years without any change in contract terms. The area dedication is limited stratigraphically to the top of the Mesaverde formation, resulting in the Mesaverde deep gas not being included in the dedication.
          The Lower Green River/Upper Wasatch represents $21.2 million of proved and $10.5 million of unproved oil and gas properties on our December 31, 2010 balance sheet and $5.6 million of unproved oil and gas properties on our December 31, 2009 balance sheet.
Monument Butte
          The Monument Butte Extension was initiated in the fourth quarter of 2009 with an eight well appraisal and development drilling program to produce oil and natural gas from the Green River formation. The parties participating in the wells formed a 320 acre AMI, which contained the initial eight drilling locations.
          As a follow up to the successful completion of the initial eight well program that was drilled in late 2009 and early 2010, a six well appraisal and development drilling program was approved in 2010. The six well expansion is on acreage immediately adjacent to the initial eight well program.
          The first 14 wells in the Monument Butte Extension (as defined above) are non-operated, and we hold a 43 percent working interest in the initial eight wells and an approximate 37 percent working interest in the follow-up six wells.
          During 2010, an additional Harvest operated well, the K Moon #2-13-4-3, was added to the project. We have an approximate 60 percent working interest in the well.

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          Operational activities during 2010 for the Monument Butte Extension consisted of routine production operations from the initial eight wells and implementation of the six well expansion program in third quarter 2010. Five of the six wells were drilled and four were on production as of December 2010. The sixth and final well spud on February 3, 2011. The Monument Butte Extension represents $6.2 million of proved and $0.7 million of unproved oil and gas properties and $1.6 million of proved and $0.3 million of unproved oil and gas properties on our December 31, 2010 and 2009 balance sheets, respectively.
Note 11 — Indonesia
          In December 2007, we entered into a Farmout Agreement to acquire a 47 percent interest in the Budong PSC located mostly onshore West Sulawesi, Indonesia. In April 2008, the Government of Indonesia approved the assignment to us of the 47 percent interest in the Budong PSC. Our partner is the operator through the exploration phase as required by the terms of the Budong PSC, and we have an option to become operator, if approved by Government of Indonesia and BPMIGAS, the oil and gas regulatory authority, in any subsequent development and production phase.
          We acquired our original 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 under a Farmout Agreement with operator of the Budong PSC. Under the Farmout Agreement, the initial commitment was to fund the first phase of the exploration program up to a cap of $17.2 million. The commitment cap is comprised of $6.5 million for the acquisition of seismic and $10.7 million for the drilling of the first two exploratory wells. After the commitment cap of each component was met, all subsequent costs are shared by the parties in proportion to their ownership interests. Prior to drilling the first exploration well, our partner had a one-time option to increase the level of the carried interest to a maximum of $20.0 million. On September 15, 2010, our partner exercised their option to increase the carry obligation by $2.7 million to a total of $19.9 million ($7.9 million for acquisition of seismic and $12.0 million for drilling). The additional carry increased our ownership by 7.4 percent to 54.4 percent. On March 3, 2011, the Government of Indonesia and BPMIGAS approved this change in ownership interest.
          On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator to a third party, which has allowed us to acquire an additional 10 percent equity in the Budong PSC at a cost of $3.7 million payable ten business days after completion of the first exploration well. Closing of this acquisition, which is subject to the approval of the Government of Indonesia and BPMIGAS, will increase our interest in the Budong PSC to 64.4 percent.
          During the initial exploration period, the Budong PSC covered 1.35 million acres. The term of the Budong PSC is for 30 years which provides for an exploration period of up to ten years. Pursuant to the Budong PSC, at end of the first three-year exploration phase, 35 percent of the original area was relinquished to BPMigas. The second three-year exploration phase began in January 2010 covering 0.88 million acres.
          Operational activities during 2010 focused on well planning, construction for two test well sites, mobilization of rig and ancillary equipment to the first drill site. After delays in acquiring permits to mobilize the drilling rig from its port location to the drilling pad, the first exploratory well, the Lariang-1 (“LG-1”), was spud on January 6, 2011. The Budong PSC represents $10.9 million and $2.0 million of unproved oil and gas properties on our December 31, 2010 and 2009 balance sheets, respectively.
Note 12 — Gabon
          We are the operator of the Dussafu PSC with a 66.667 percent ownership interest. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC covers an area of 680,000 acres with water depths up to 1,000 feet. The Dussafu PSC has two small oil discoveries in the Gamba and Dentale reservoirs and a small natural gas discovery. Production and infrastructure exists in the blocks contiguous to the Dussafu PSC.
          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. It was agreed that the second three-year exploration phase be extended until May 27, 2011, at which time the partners can elect to enter a third exploration phase. Operational

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activities during 2010 included the maturation of the prospect inventory and well planning. We have issued purchase orders for long lead items required for drilling. Other drilling contracts are being tendered in preparation to spud the exploration well in the second quarter of 2011. The exploratory well to be drilled in the second quarter of 2011 will test stacked reservoir potential in the pre-salt section. A Letter of Intent has been agreed for a semi-submersible rig to commence a contract in April 2011 to drill the Ruche Marin prospect. To complete the drilling activities a six month extension to November 27, 2011 of the second Exploration Period has been requested. The Dussafu PSC represents $9.2 million and $6.9 million of unproved oil and gas properties on our December 31, 2010 and 2009 balance sheets, respectively.
Note 13 — Oman
          In April 2009, we signed an EPSA with Oman for the Block 64 EPSA. We have a 100 percent working interest in Block 64 EPSA during the exploration phase. Oman Oil Company has the option to back-in to up to a 20 percent interest in Block 64 EPSA after the discovery of gas.
          Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate, which the Oman Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). PDO will continue to produce oil from several shallow oil fields within Block 64 EPSA area. The 955,600 acre block is located in the gas and condensate rich Ghaba Salt Basin in close proximity to the Barik, Saih Rawl and Saih Nihayda gas and condensate fields. We have an obligation to drill two wells over a three-year period with a funding commitment of $22.0 million. Operational activities during 2010 included geological studies, baseline environmental and social study and 3-D pre-stack depth migration reprocessing of approximately 1,150 square kilometers of existing 3-D seismic data. During 2011, geological and geophysical interpretation of the reprocessed 3-D will take place to mature drilling locations. Well planning and procurement of long lead items will commence in the first half of 2011 to enable the first of the two exploratory wells to commence drilling in the fourth quarter of 2011. The Block 64 EPSA represents $4.2 million and $3.8 million of unproved oil and gas properties on our December 31, 2010 and 2009 balance sheets, respectively.
Note 14 — China
          In December 1996, we acquired a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under certain circumstances, and lies within an area which is the subject of a border dispute between the People’s Republic of China (“China”) and Socialist Republic of Vietnam (“Vietnam”). Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The border dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the dispute. Due to the border dispute between China and Vietnam, we have been unable to pursue an exploration program during Phase One of the contract. As a result, we have obtained license extensions, with the current extension in effect until May 31, 2011. We are in the process of obtaining a new license extension and believe that it will be granted. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist. WAB-21 represents $3.1 million and $3.0 million of unproved oil and gas properties on our December 31, 2010 and 2009 balance sheets, respectively.
Note 15 — Earnings Per Share
          Basic earnings per common share (“EPS”) are computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. The weighted average number of common shares outstanding for computing basic EPS was 33.5 million, 33.1 million and 34.1 million for the years ended December 31, 2010, 2009 and 2008, respectively. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The weighted average number of common shares outstanding for computing diluted EPS, including dilutive stock options, was 39.3 million, 33.1 million and 34.1 million for the years ended December 31, 2010, 2009 and 2008, respectively.
     An aggregate of 2.9 million options and 6.0 million warrants were excluded from earnings per share calculations because their exercise price exceeded the average price for the year ended December 31, 2010. An aggregate of 3.7 million options were excluded from earnings per share calculations because their exercise price

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exceeded the average price for the year ended December 31, 2009. An aggregate of 4.0 million options were excluded from the earnings per share calculations because their exercise price exceeded the average price for the year ended December 31, 2008.
Note 16 — Related Party Transactions
          Dividends declared and paid by Petrodelta are paid to HNR Finance. HNR Finance must declare a dividend in order for the partners, Harvest and Vinccler, to receive their respective shares of Petrodelta’s dividend. Petrodelta has declared two dividends, totaling $33.0 million, which have been received by HNR Finance and for which HNR Finance has not distributed to the partners. At December 31, 2010, Vinccler’s share of the undistributed dividends is $6.6 million.
Note 17 — Subsequent Events
          We conducted our subsequent events review up through the date of the issuance of this Annual Report on Form 10-K.
          On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator to a third party, to acquire an additional ten percent equity in the Budong PSC for a consideration of $3.7 million payable ten business days after completion of the first exploration well. Closing of this acquisition will increase our interest in the Budong PSC to 64.4 percent. The change in ownership interest is subject approval from the Government of Indonesia and BPMIGAS.
          On January 28, 2011, Fusion’s 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. We received $1.3 million for our equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full of the outstanding balance of the prepaid service agreement, short term loan and accrued interest. The Agreement and Plan of Merger includes an Earn Out provision wherein we would receive an additional payment of up to a maximum of $2.7 million if FusionGeo, Inc.’s 2011 gross profit exceeds $5.6 million. The Earn Out payment will not be determined until early in 2012. We can give no assurance that we will receive any Earn Out payment.
          In February 2011, the previously existing Alligator Point Unit (as approved by the GLO) expired. We have obtained from the GLO an extension until September 1, 2011 of a smaller version of the Alligator Point Unit defined more specifically by the drilling prospects currently existing on the project. As a result of the GLO approval of the smaller Alligator Point Unit and the anticipated expiry of five leases previously held by the larger unit, we expect our lease position on the West Bay project to be reduced from approximately 13,000 acres in February 2011 to approximately 10,050 acres in August 2011.
          On March 3, 2011, the Government of Indonesia and BPMIGAS approved our change in ownership interest in the Budong PSC from 47 percent to 54.4 percent.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Quarterly Financial Data (unaudited)
          Summarized quarterly financial data is as follows:
                                 
    Quarter Ended  
    March 31     June 30     September 30     December 31  
    (amounts in thousands, except per share data)  
Year ended December 31, 2010
                               
Revenues
  $ 3,124     $ 2,914     $ 1,919     $ 2,739  
Expenses
    (7,773 )     (9,771 )     (11,078 )     (12,765 )
Non-operating loss
    (1,812 )     (572 )     (92 )     (5,196 )
 
                       
Loss from consolidated companies before income taxes
    (6,461 )     (7,429 )     (9,251 )     (15,222 )
Income tax expense (benefit)
    (19 )     152       699       (1,016 ) (a)
 
                       
Loss from consolidated companies
    (6,442 )     (7,581 )     (9,950 )     (14,206 )
Net income from unconsolidated equity affiliates
    38,367       8,915       6,148       12,734  
 
                       
Net income (loss)
    31,925       1,334       (3,802 )     (1,472 )
Less: Net income attributable to noncontrolling interest
    7,335       1,630       1,189       2,491  
 
                       
Net income (loss) attributable to Harvest
  $ 24,590     $ (296 )   $ (4,991 )   $ (3,963 )
 
                       
 
                               
Net income (loss) attributable to Harvest per common share:
                               
Basic
  $ 0.74     $ (0.01 )   $ (0.15 )   $ (0.12 )
 
                       
Diluted
  $ 0.64     $ (0.01 )   $ (0.15 )   $ (0.12 )
 
                       
 
(a) Includes an out-of-period income tax benefit adjustment of $1.0 million identified during the fourth quarter of 2010 which relates to the third quarter of 2010. See note 6 — Taxes.
                                 
    Quarter Ended  
    March 31     June 30     September 30     December 31  
    (amounts in thousands, except per share data)  
Year ended December 31, 2009
                               
Revenues
  $     $     $     $ 181  
Expenses
    (7,825 )     (10,217 )     (7,286 )     (5,812 )
Non-operating income
    331       296       224       229  
 
                       
Loss from consolidated companies before income taxes
    (7,494 )     (9,921 )     (7,062 )     (5,402 )
Income tax expense
    889       147       109       37  
 
                       
Loss from consolidated companies
    (8,383 )     (10,068 )     (7,171 )     (5,439 )
Net income from unconsolidated equity affiliates
    4,410       7,476       9,890       13,981  
 
                       
Net income (loss)
    (3,973 )     (2,592 )     2,719       8,542  
Less: Net income attributable to noncontrolling interest
    803       1,597       1,936       3,467  
 
                       
Net income (loss) attributable to Harvest
  $ (4,776 )   $ (4,189 )   $ 783     $ 5,075  
 
                       
 
                               
Net income (loss) attributable to Harvest per common share:
                               
Basic
  $ (0.15 )   $ (0.13 )   $ 0.02     $ 0.15  
 
                       
Diluted
  $ (0.15 )   $ (0.13 )   $ 0.02     $ 0.15  
 
                       
Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)
          The following tables summarize our proved reserves, drilling and production activity, and financial operating data at the end of each year. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

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TABLE I —   Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
                                         
                            United States        
    Oman     Gabon     Indonesia     and Other     Total  
Year Ended December 31, 2010
                                       
Acquisition costs
  $     $     $ 2,703     $ 21,757     $ 24,460  
Exploration costs
    1,698       2,763       10,468       27,576       42,505  
Development costs
                      7,667       7,667  
 
                             
 
  $ 1,698     $ 2,763     $ 13,171     $ 57,000     $ 74,632  
 
                             
 
                                       
Year Ended December 31, 2009
                                       
Acquisition costs
  $ 3,757     $ 941     $ 1,800     $ 28,170     $ 34,668  
Exploration costs
    459       225       1,793       2,563       5,040  
Development costs
                      1,547       1,547  
 
                             
 
  $ 4,216     $ 1,166     $ 3,593     $ 32,280     $ 41,255  
 
                             
 
                                       
Year Ended December 31, 2008
                                       
Acquisition costs
  $     $ 5,792     $ 71     $ 13,302     $ 19,165  
Exploration costs
          3,016       7,647       14,020       24,683  
 
                             
 
  $     $ 8,808     $ 7,718     $ 27,322     $ 43,848  
 
                             
TABLE II —   Capitalized costs related to oil and natural gas producing activities (in thousands):
                                         
                            United States        
    Oman     Gabon     Indonesia     and Other     Total  
Year Ended December 31, 2010
                                       
Proved property costs
  $     $     $     $ 27,355     $ 27,355  
Unproved property costs
    4,216       9,177       9,459       71,173       94,025  
Oilfield Inventories
                1,435       3,965       5,400  
Less accumulated depletion
                      (3,327 )     (3,327 )
 
                             
 
  $ 4,216     $ 9,177     $ 10,894     $ 99,166     $ 123,453  
 
                             
 
                                       
Year Ended December 31, 2009
                                       
Proved property costs
  $     $     $     $ 1,646     $ 1,646  
Unproved property costs
    3,757       6,869       670       42,815       54,111  
Oilfield Inventories
                1,369       1,417       2,786  
Less accumulated depletion
                      (29 )     (29 )
 
                             
 
  $ 3,757     $ 6,869     $ 2,039     $ 45,849     $ 58,514  
 
                             
 
                                       
Year Ended December 31, 2008
                                       
Unproved property costs
  $     $ 5,927     $ 239     $ 16,162     $ 22,328  
 
                             
          We regularly evaluate our unproved properties to determine whether impairment has occurred. We have excluded from amortization our interest in unproved properties and the cost of uncompleted exploratory activities. The principal portion of such costs, excluding those related the acquisition of WAB-21, are expected to be included in amortizable costs during the next two to three years. The ultimate timing of when the costs related to the acquisition of WAB-21 will be included in amortizable costs is uncertain.
          Unproved property costs at December 31, 2010 consisted of the following by year incurred (in thousands):
                                         
    Total     2010     2009     2008     Prior  
Property acquisition costs
  $ 94,025     $ 37,184     $ 35,307     $ 18,371     $ 3,163  
 
                             

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  TABLE III — Results of operations for oil and natural gas producing activities (in thousands):
                 
    Year Ended December 31,  
    2010     2009  
Revenue:
               
Oil and natural gas revenues
  $ 10,696     $ 181  
Expenses:
               
Operating, selling and distribution expenses and taxes other than on income
    1,846       15  
Exploration expense
    8,016       7,824  
Depletion
    3,298       29  
Income tax expense
           
 
           
Total expenses
    13,160       7,868  
 
           
Results of operations from oil and natural gas producing activities
  $ (2,464 )   $ (7,687 )
 
           
TABLE IV —   Quantities of Oil and Natural Gas Reserves
          Estimating oil and gas reserves is a very complex process requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may change substantially over time as a result of numerous factors such as production history, additional development activity and continual reassessment of the viability of production under various economic and political conditions. Consequently, material upward or downward revisions to existing reserve estimates may occur from time to time; although, every reasonable efforts is made to ensure that reported results are the most accurate assessment available. We ensure that the data provided to our external independent experts, and their interpretation of that data, corresponds with our development plans and management’s assessment of each reservoir. The significance of subjective decisions required and variances in available data make estimates generally less precise than other estimates presented in connection with financial statement disclosures.
          In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, prior period reserves were not restated.
          The impact of the adoption of the SEC’s final rule on our financial statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.
          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.
          See the following section Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela Equity Affiliate as of December 31, 2010, 2009 and 2008, TABLE IV — Quantities of Oil and Natural Gas Reserves for Petrodelta’s reserves.

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     The table shown below represents our interests in the United States. At December 31, 2009 we had three Proved Developed wells and five Proved Undeveloped (“PUD”) locations identified in the Monument Butte area. During 2010, we identified and approved the development of 41 further locations. A total of 13 wells have been moved to Proved Developed Producing (“PDP”) in 2010 including the five PUD locations identified at December 31, 2009 and eight other wells. This results in a total of 16 PDP wells and 43 identified PUD locations at December 31, 2010.
                                 
    2010     2009  
    Oil and NGL     Gas     Oil and NGL     Gas  
    (MBbls)     (MMcf)     (MBbls)     (MMcf)  
Proved Reserves
                               
United States
                               
Proved Reserves at January 1
    226       1,126              
Revisions
    147       914              
Acquisitions
    15       12       229       1,132  
Extensions
    3,267       4,863              
Production
    (140 )     (423 )     (3 )     (6 )
 
                       
Proved Reserves at December 31
    3,515       6,492       226       1,126  
 
                       
 
                               
As of December 31
                               
United States
                               
Proved
                               
Developed
    659       2,476       131       653  
Undeveloped
    2,856       4,016       95       473  
 
                       
Total Proved
    3,515       6,492       226       1,126  
 
                       
TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities
          The standardized measure of discounted future net cash flows is presented in accordance with the provisions of the accounting standard on disclosures about oil and gas producing activities. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.
          Future cash inflows were estimated by an applying the average price during the 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the contract, to the estimated future production of year-end proved reserves. Our average prices used were $64.45 per barrel for oil and $3.75 per Mcf for gas. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.
          The table shown below represents our net interest at December 31, 2010.

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    United States  
    (in thousands)  
    December 31, 2010     December 31, 2009  
Future cash inflows from sales of oil and gas
  $ 250,712     $ 14,626  
Future production costs
    (75,602 )     (3,674 )
Future development costs
    (62,246 )     (1,171 )
Future income tax expenses
    (37,262 )     (3,147 )
 
           
Future net cash flows
    75,602       6,634  
Effect of discounting net cash flows at 10%
    (45,632 )     (1,911 )
 
           
Standardized measure of discounted future net cash flows
  $ 29,970     $ 4,723  
 
           
TABLE VI — Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves:
                 
    United States  
    (in thousands)  
    2010     2009  
Standardized Measure at January 1
  $ 4,723     $  
Sales of oil and natural gas, net of related costs
    (8,850 )     (166 )
Revisions to estimates of proved reserves:
               
Net changes in prices, net of production costs
    2,766        
Quantities
    3,734        
Purchase and sale of reserves in place
    387        
Extensions, discoveries and improved recovery, net of future costs
    36,211       6,978  
Accretion of discount
    535        
Development costs incurred
    2,427        
Changes in estimated development costs
    (1,256 )      
Net change in income taxes
    (10,707 )     (2,089 )
 
           
Standardized Measure at December 31
  $ 29,970     $ 4,723  
 
           

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Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Petrodelta S.A. as of December 31, 2010, 2009 and 2008
          The following tables summarize the proved reserves, drilling and production activity, and financial operating data at the end of each year for our net 32 percent interest in Petrodelta. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
          Petrodelta (32 percent ownership) is accounted for under the equity method, and has been included at its ownership interest in the consolidated financial statements and the following Tables based on a year ending December 31 and, accordingly, results of operations for oil and natural gas producing activities in Venezuela reflect the year ended December 31, 2010, 2009 and 2008.
TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
                         
    Year ended December 31,  
    2010     2009     2008  
Development costs
  $ 29,976     $ 26,605     $ 17,144  
Exploration costs
                 
 
                 
 
  $ 29,976     $ 26,605     $ 17,744  
 
                 
TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):
                         
    Year ended December 31,  
    2010     2009     2008  
Proved property costs
  $ 139,702     $ 108,696     $ 79,807  
Unproved property costs
    1,365       163       3,036  
Oilfield inventories
    9,630       10,748       7,892  
Less accumulated depletion and impairment
    (43,856 )     (27,089 )     (16,966 )
 
                 
 
  $ 106,841     $ 92,518     $ 73,769  
 
                 
TABLE III — Results of operations for oil and natural gas producing activities (in thousands):
                         
    Year Ended December 31,  
    2010     2009     2008  
Revenue:
                       
Oil and natural gas revenues
  $ 194,423     $ 146,640     $ 151,878  
Royalty
    (65,500 )     (50,176 )     (54,013 )
 
                 
 
    128,923       96,464       97,865  
Expenses:
                       
Operating, selling and distribution expenses and taxes other than on income
    22,359       15,742       42,876  
Depletion
    12,387       10,123       5,903  
Income tax expense
    47,089       35,300       23,530  
 
                 
Total expenses
    81,835       61,165       72,309  
 
                 
Results of operations from oil and natural gas producing activities
  $ 47,088     $ 35,299     $ 25,556  
 
                 
TABLE IV — Quantities of Oil and Natural Gas Reserves
     In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, prior period reserves were not restated.

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          Petrodelta is producing from, and continuing to develop, the Petrodelta Fields. Petrodelta has both developed and undeveloped oil and gas reserves identified in all six fields. Petrodelta produces the fields in accordance with a business plan originally defined by its Conversion Contract executed in late 2007. Proved Undeveloped (“PUD”) oil and gas reserves are drilled in accordance with Petrodelta’s business plan, but can be revised where drilling results indicate a change is warranted. This was the case in 2009 and again in 2010 when the wells drilled in El Salto resulted in a modification to the El Salto program.
          During 2010, Petrodelta drilled 16 wells. Six of the wells were previously identified PUD locations and ten wells were previously classified Probable, Possible or undefined. In 2010, an additional 24 PUD locations were identified through drilling activity. At December 31, 2010, Petrodelta had a total of 182 PUD (33,906 MBOE) locations identified. Since the implementation of its 2007 business plan, Petrodelta has drilled 40 gross wells (2008 nine wells [1,394 MBOE], 2009 15 wells [1,999 MBOE] and 2010 16 wells [1,954MBOE]) which have moved to the proved developed producing (“PDP”) category. Of these 40 locations drilled since 2008, 23 (3,730 MBOE) represent the movements of PUD locations to PDP locations. The other 17 new producing wells (1,617 MBOE) were previously classified Probable, Possible or un-defined. All above MBOE represent our net 32 percent interest, net of a 33.33 percent royalty.
          Petrodelta has a track record of identifying, executing and converting its PUD locations to PDP locations in accordance with the business plan defined by the conversion contract executed in 2007 and subsequent updates. However, the timing and pace of the development is controlled by the majority owner, PDVSA through CVP, although we have substantial negative control provisions as a noncontrolling interest shareholder. In 2010, Petrodelta submitted a revised business plan to PDVSA which substantially increases the total projected drilling activity and production volumes compared to the 2007 business plan, but which is otherwise consistent with the 2007 business plan. The 2010 business plan, as approved by PDVSA, contemplates sustained drilling activities through the year 2024 to fully develop the El Salto and Temblador fields. In accordance with this revised development plan for Petrodelta, HNR Finance has elected to report a portion of their PUDs to be developed past a five year window. Most PUD locations are scheduled to be drilled within five years of their first identification; however, there are some PUD locations that are scheduled to be drilled more than five years after the PUD locations were first identified. At December 2010, the proportion of proved reserves expected to be drilled in the sixth year after initial booking is 21 percent of Proved (BOE) reserves and the proportion drilled in the seventh year is two percent of Proved (BOE) reserves. As a noncontrolling interest shareholder in Petrodelta, HNR Finance has limited ability to control the development plans that are periodically prepared and/or approved by the Venezuelan government. Since this constraint represents a hindrance to development not experienced by typical operations, inclusion of a portion of the activities planned for year six and seven represents a fair comparison to operators with assets covered by more flexible regulatory conditions where increasing rig count can ameliorate a slow development plan.
          From 2008 through 2010, a number of factors adversely affected the pace of development of the fields. Petrodelta commenced drilling operations in the second quarter of 2008; however, shortly thereafter Petrodelta was advised by the Venezuelan government that Petrodelta’s 2009 production target was to be approximately 16,000 barrels of oil per day following the December 17, 2008 Organization of the Petroleum Exporting Countries (“OPEC”) meeting establishing new production quotas. Subsequently, Petrodelta was allowed to produce at capacity to help fulfill other companies’ production shortfalls. Since early 2009, PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. As a result, Petrodelta has experienced difficulty in retaining contractors who provide equipment and/or services for Petrodelta’s operations. Inability to retain contractors or to pay them on a timely basis continues to have an adverse effect on Petrodelta’s ability to carry out its business plan. These events have been outside of our control.
          In summary, Petrodelta has operated the Petrodelta Fields since October 2007 when the Conversion Contract was signed. The business plan, as defined by the Conversion Contract, defines the development of the Petrodelta Fields. Under its business plan, Petrodelta has demonstrated a track record of identifying, executing and converting its PUD locations to PDP locations. However, the timing and pace of the development is controlled by the majority owner, PDVSA through CVP, and as a noncontrolling interest shareholder in Petrodelta, HNR Finance has limited ability to control the development plans that are periodically prepared and or approved by PDVSA and CVP.

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          The tables shown below represent HNR Finance’s 40 percent ownership interest and our net 32 percent ownership interest, both net of a 33.33 percent royalty, in Venezuela in each of the years.
                         
            Minority        
Proved Reserves-Crude oil, condensate,           Interest in     32%  
and natural gas liquids (MBbls)   HNR Finance     Venezuela     Net Total  
As of December 31, 2010
                       
Proved Reserves at January 1, 2010
    47,419       (9,483 )     37,936  
Revisions
    (230 )     45       (185 )
Extensions
    7,199       (1,440 )     5,759  
Production
    (2,283 )     457       (1,826 )
 
                 
Proved Reserves at end of the year
    52,105       (10,421 )     41,684  
 
                 
 
                       
As of December 31, 2010
                       
Proved
                       
Developed
    16,342       (3,268 )     13,074  
Undeveloped
    35,763       (7,153 )     28,610  
 
                 
Total Proved
    52,105       (10,421 )     41,684  
 
                 
 
                       
As of December 31, 2009
                       
Proved Reserves at January 1, 2009
    42,809       (8,561 )     34,248  
Revisions
    (875 )     175       (700 )
Extensions
    7,574       (1,515 )     6,059  
Production
    (2,089 )     418       (1,671 )
 
                 
Proved Reserves at end of the year
    47,419       (9,483 )     37,936  
 
                 
 
                       
As of December 31, 2009
                       
Proved
                       
Developed
    14,242       (2,848 )     11,394  
Undeveloped
    33,177       (6,635 )     26,542  
 
                 
Total Proved
    47,419       (9,483 )     37,936  
 
                 
 
                       
As of December 31, 2008
                       
Proved Reserves at January 1, 2008
    47,261       (9,452 )     37,809  
Revisions
    (2,984 )     597       (2,387 )
Production</