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Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
     
(Mark One)    
     
þ   Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period Ended June 30, 2011 or
     
o   Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
     
    for the transition period from                      to                     
Commission File No. 1-10762
 
Harvest Natural Resources, Inc.
(Exact Name of Registrant as Specified in Its Charter)
     
Delaware   77-0196707
(State or Other Jurisdiction of Incorporation or Organization)   (IRS Employer Identification No.)
     
1177 Enclave Parkway, Suite 300    
Houston, Texas   77077
(Address of Principal Executive Offices)   (Zip Code)
(281) 899-5700
(Registrant’s Telephone Number, Including Area Code)
Not Applicable
(Former name, former address and former fiscal year, if changed since last report)
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 Web site, 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 þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large Accelerated Filer o   Accelerated Filer þ   Non-Accelerated Filer o   Smaller Reporting Company o
    (Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ
At July 22, 2011, 34,125,368 shares of the Registrant’s Common Stock were outstanding.
 
 

 


 

HARVEST NATURAL RESOURCES, INC.
FORM 10-Q
TABLE OF CONTENTS
             
          Page  
PART I FINANCIAL INFORMATION        
 
           
  Financial Statements        
 
  Unaudited Consolidated Balance Sheets at June 30, 2011 and December 31, 2010     3  
 
  Unaudited Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2011 and 2010     4  
 
  Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010     5  
 
  Notes to Consolidated Financial Statements     6  
 
           
  Management's Discussion and Analysis of Financial Condition and Results of Operations     23  
 
           
  Quantitative and Qualitative Disclosures About Market Risk     35  
 
           
  Controls and Procedures     35  
 
           
PART II OTHER INFORMATION        
 
           
  Legal Proceedings     36  
 
           
  Risk Factors     36  
 
           
  Defaults Upon Senior Securities     36  
 
           
  Exhibits     36  
 
           
Signatures     38  
 EX-10.1
 EX-10.2
 EX-10.3
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT

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Table of Contents

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                 
    June 30,     December 31,  
    2011     2010  
    (in thousands)  
ASSETS
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 136,032     $ 58,703  
Restricted cash
    7,323        
Accounts and notes receivable, net:
               
Oil and gas revenue receivable
          1,907  
Dividend receivable — equity affiliate
    12,200        
Joint interest and other
    7,203       2,325  
Note receivable
    3,335       3,420  
Advances to equity affiliate
    2,002       1,706  
Assets held for sale (See Note 3)
          88,774  
Prepaid expenses and other
    1,732       4,793  
 
           
TOTAL CURRENT ASSETS
    169,827       161,628  
OTHER ASSETS
    2,499       2,477  
INVESTMENT IN EQUITY AFFILIATES
    310,351       287,933  
PROPERTY AND EQUIPMENT:
               
Oil and gas properties (successful efforts method)
    59,814       34,679  
Other administrative property
    3,120       3,209  
 
           
TOTAL PROPERTY AND EQUIPMENT
    62,934       37,888  
Accumulated depletion, depreciation and amortization
    (1,840 )     (1,682 )
 
           
TOTAL PROPERTY AND EQUIPMENT, NET
    61,094       36,206  
 
           
TOTAL ASSET
  $ 543,771     $ 488,244  
 
           
 
               
LIABILITIES AND EQUITY
               
CURRENT LIABILITIES:
               
Accounts payable, trade and other
  $ 11,373     $ 3,205  
Accounts payable, carry obligation
    3,617       8,395  
Accrued expenses
    14,622       15,087  
Liabilities held for sale (See Note 3)
          663  
Accrued interest
    880       896  
Income taxes payable
    5,585       72  
 
           
TOTAL CURRENT LIABILITIES
    36,077       28,318  
OTHER LONG-TERM LIABILITIES
    1,133       1,834  
LONG-TERM DEBT
    32,000       81,237  
COMMITMENTS AND CONTINGENCIES (See Note 5)
           
 
               
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 June 30, 2011 and December 31, 2010, respectively; issued 40,286 shares and 40,103 shares at June 30, 2011 and December 31, 2010, respectively
    402       401  
Additional paid-in capital
    230,718       230,362  
Retained earnings
    232,404       141,584  
Treasury stock, at cost, 6,505 shares and 6,475 shares at June 30, 2011 and December 31, 2010, respectively
    (65,925 )     (65,543 )
 
           
TOTAL HARVEST STOCKHOLDERS’ EQUITY
    397,599       306,804  
NONCONTROLLING INTEREST
    76,962       70,051  
 
           
TOTAL EQUITY
    474,561       376,855  
 
           
TOTAL LIABILITIES AND EQUITY
  $ 543,771     $ 488,244  
 
           
See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
    (in thousands, except per share data)  
EXPENSES
                               
Depreciation and amortization
  $ 119     $ 142     $ 243     $ 243  
Exploration expense
    4,650       1,491       5,839       2,737  
General and administrative
    6,742       5,829       13,068       10,846  
Taxes other than on income
    307       198       656       498  
 
                       
 
    11,818       7,660       19,806       14,324  
 
                       
 
                               
LOSS FROM OPERATIONS
    (11,818 )     (7,660 )     (19,806 )     (14,324 )
 
                               
OTHER NON-OPERATING INCOME (EXPENSE)
                               
Investment earnings and other
    240       140       385       271  
Interest expense
    (1,704 )     (688 )     (3,916 )     (1,104 )
Loss on extinguishment of debt
    (9,682 )           (9,682 )      
Other non-operating expenses
    (244 )           (675 )      
Foreign currency transaction loss
    (32 )     (24 )     (43 )     (1,551 )
 
                       
 
    (11,422 )     (572 )     (13,931 )     (2,384 )
 
                       
 
                               
LOSS FROM CONSOLIDATED COMPANIES CONTINUING OPERATIONS BEFORE INCOME TAXES
    (23,240 )     (8,232 )     (33,737 )     (16,708 )
 
                               
INCOME TAX EXPENSE
    260       152       482       133  
 
                       
LOSS FROM CONSOLIDATED COMPANIES CONTINUING OPERATIONS
    (23,500 )     (8,384 )     (34,219 )     (16,841 )
 
                               
NET INCOME FROM UNCONSOLIDATED EQUITY AFFILIATES
    17,899       8,915       36,003       47,282  
 
                       
 
                               
NET INCOME (LOSS) FROM CONTINUING OPERATIONS
    (5,601 )     531       1,784       30,441  
 
                               
DISCONTINUED OPERATIONS:
                               
Income (loss) from discontinued operations
    480     803       (2,786 )     2,818  
Gain on sale of assets
    103,933             103,933        
Income tax expense on gain
    (5,200 )           (5,200 )      
 
                       
Income from discontinued operations
    99,213       803       95,947       2,818  
 
                       
 
                               
NET INCOME
    93,612       1,334       97,731       33,259  
 
                               
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
    3,562       1,630       6,911       8,965  
 
                       
 
                               
NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST
  $ 90,050     $ (296 )   $ 90,820     $ 24,294  
 
                       
 
                               
NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST PER COMMON SHARE:
                               
(See Note 2 — Summary of Significant Accounting Policies, Earnings Per Share):
                               
Basic
  $ 2.65     $ (0.01 )   $ 2.67     $ 0.73  
 
                       
Diluted
  $ 2.24     $ (0.01 )   $ 2.28     $ 0.65  
 
                       
See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                 
    Six Months Ended June 30,  
    2011     2010  
    (in thousands)  
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net income
  $ 97,731     $ 33,259  
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
               
Depletion, depreciation and amortization
    1,053       1,825  
Impairment of long-lived assets
    4,707        
Amortization of debt financing costs
    530       329  
Amortization of discount on debt
    816        
Gain on sale of assets
    (103,933 )      
Loss on early extinguishment of debt
    7,533        
Net income from unconsolidated equity affiliate
    (36,003 )     (47,282 )
Share-based compensation-related charges
    2,673       1,844  
Changes in operating assets and liabilities:
               
Accounts and notes receivable
    (2,887 )     3,115  
Advances to equity affiliate
    (296 )     2,730  
Prepaid expenses and other
    3,061       263  
Accounts payable
    8,168       2,474  
Accrued expenses
    (2,469 )     363  
Accrued interest
    (418 )     (3,723 )
Other long-term liabilities
    (701 )      
Income taxes payable
    5,513       (353 )
 
           
NET CASH USED IN OPERATING ACTIVITIES
    (14,922 )     (5,156 )
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Proceeds from sale of assets
    217,833        
Additions of property and equipment
    (28,067 )     (23,913 )
Additions to assets held for sale
    (31,742 )      
Proceeds from sale of equity affiliate
    1,385        
Increase in restricted cash
    (7,323 )     (1,000 )
Investment costs
    (62 )     (36 )
 
           
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES
    152,024       (24,949 )
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Net proceeds from issuances of common stock
    416       115  
Proceeds from issuance of long-term debt
          32,000  
Payments of long-term debt
    (60,000 )      
Financing costs
    (189 )     (2,818 )
 
           
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
    (59,773 )     29,297  
 
           
 
               
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    77,329       (808 )
 
               
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    58,703       32,317  
 
           
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 136,032     $ 31,509  
 
           
Supplemental Schedule of Noncash Investing and Financing Activities:
     During the six months ended June 30, 2011, we issued 0.2 million shares of restricted stock valued at $2.0 million. Also, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 30,373 shares being added to treasury stock at cost.
     During the six months ended June 30, 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.
See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2011 and 2010 (unaudited)
Note 1 — Organization
Interim Reporting
     The accompanying unaudited consolidated financial statements contain all adjustments necessary for a fair statement of the financial position as of June 30, 2011, and the results of operations for the three and six months ended June 30, 2011 and 2010, and cash flows for the six months ended June 30, 2011 and 2010. The unaudited consolidated financial statements are presented in accordance with the requirements of Form 10-Q and do not include all disclosures normally required by accounting principles generally accepted in the United States of America (“GAAP”). Reference should be made to our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2010, which include certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year.
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, and Vinccler indirectly owns eight percent. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. HNR Finance also 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 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”). Until March 1, 2011, we had developed and undeveloped 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 had established production. See Note 3 — Dispositions, Note 9 — United States Operations, Note 10 — Indonesia, Note 11 — Gabon and Note 12 — Oman.
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.

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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 in U.S. Dollars, and all currency gains or losses are recorded in the consolidated statement of operations. We attempt to manage our operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence.
     Harvest Vinccler does not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”) (4.30 Bolivars per U.S. Dollar). However, during the three and six months ended June 30, 2011, Harvest Vinccler exchanged approximately $0.1 million and $0.4 million, respectively through Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) and received an average exchange rate of 5.21 Bolivars and 5.19 Bolivars, respectively, per U.S. Dollar. During the three and six months ended June 30, 2010, no such exchanges took place. Harvest Vinccler currently does not have any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate.
     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. At June 30, 2011, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 3.1 million Bolivars and 4.3 million Bolivars, respectively.
     See Note 8 — Investment in Equity Affiliates — Petrodelta for a discussion of currency exchange risk 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 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. See Note 3 — Dispositions.
Cash and Cash Equivalents
     Cash equivalents include money market funds and short-term certificates of deposit with original maturity dates of less than three months.
Restricted Cash
     Restricted cash is classified as current or non-current based on the terms of the agreement. Restricted cash at June 30, 2011 represents cash held in a U.S. bank used as collateral for two standby letters of credit issued in support of the drilling of the Dussafu Ruche Marin-1 (“DRM-1”) exploratory well on the Dussafu Marin Permit (“Dussafu PSC”) (see Note 11 — Gabon).
Financial Instruments
     Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents, accounts receivable, and notes payable. 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 June 30, 2011 consisted of $32 million of fixed-rate unsecured senior convertible notes maturing in 2013 unless earlier redeemed, purchased or converted. At December 31, 2010, total long-term debt 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. See Note 4 — Long-Term Debt.

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Accounts and Notes Receivable
     Notes receivable relate to prospect leasing cost financing arrangements, bear interest and can have due dates that are less than one year or more than one year. Amounts outstanding under the notes bear interest at a rate based on the current prime rate and are recorded at face value. Interest is recognized over the life of the note. We may or may not require collateral for the notes.
     Each note is analyzed to determine if it is impaired pursuant to Accounting Standards Updates (“ASU”) 2010-20. 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 June 30, 2011 and December 31, 2010, note receivable plus accrued interest was approximately $3.3 million and $3.4 million, respectively, and was secured by a portion of the production from the Bar F #1-20-3-2 in Utah. With the sale of our oil and gas assets in Utah’s Uinta Basin (“Antelope Project”) effective March 1, 2011, the note receivable plus accrued interest will be settled upon finalization of certain terms of the Joint Exploration and Development Agreement (“JEDA”) which defined the participating parties’ obligations over our Antelope Project. See Note 3 — Dispositions, Note 5 — Commitments and Contingencies, and Note 9 — United States Operations, Western United States — Antelope.
Other Assets
     At June 30, 2011, other assets consist of investigative costs of $0.4 million associated with new business development projects and deferred financing costs of $1.4 million. The investigative costs are reclassified to oil and gas properties or expensed depending on management’s assessment of the likely outcome of the project. During the six months ended June 30, 2011, no investigative costs related to new business development were reclassified to oil and gas properties or expensed. At December 31, 2010, other assets consisted of investigative costs of $0.3 million associated with new business development projects and deferred financing costs of $2.2 million.
     Deferred financing costs relate to specific financing and are amortized over the life of the financing to which the costs relate. See Note 4 — Long-Term Debt.
     Other Assets at June 30, 2011 also includes a blocked payment of $0.7 million net to our 66.667 percent interest in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”). See Note 5 — Commitments and Contingencies.
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. 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. At June 30, 2011 and December 31, 2010, there were no events that caused us to evaluate our investment in equity affiliates for impairment.
Property and Equipment
     We use the successful efforts method of accounting for oil and gas properties.
Suspended Exploratory Drilling Costs
Budong PSC
     At June 30, 2011, oil and gas properties included capitalized suspended exploratory drilling costs of $13.9 million related to drilling in the Budong-Budong Production Sharing Contract (“Budong PSC”) of the Lariang-1

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(“LG-1”). The LG-1 targeted the Miocene and Eocene reservoirs to a planned depth of approximately 7,200 feet. The LG-1 was drilled to a total depth of 5,311 feet and encountered multiple oil and gas shows within the secondary Miocene objective. At a depth of 5,300 feet, losses of heavy drilling mud into the formation were encountered which, when coupled with the very high formation pressures, led the partners to the decision to discontinue drilling and plug and abandon the well for safety reasons on April 8, 2011. The primary Eocene targets had not been reached, as the well was planned for a total measured depth of approximately 7,200 feet. While the results to date have not definitively determined the commerciality of development of the LG-1, we believe that the well results confirm that the Miocene formation exhibits sufficient quantities of hydrocarbons to justify potential development pending further appraisal. See Note 10 — Indonesia.
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 three and six months ended June 30, 2011, we capitalized interest costs of $0.2 million and $1.0 million, respectively, for qualifying oil and gas property additions. During the three and six months ended June 30, 2010, we capitalized interest costs of $0.2 million, respectively, for qualifying oil and gas property additions.
Fair Value Measurements
     Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
     At June 30, 2011 and December 31, 2010, cash and cash equivalents include $128.4 million and $51.0 million, respectively, in a money market fund comprised of high quality, short term investments with minimal credit risk which are reported at fair value. The fair value measurement of these securities is based on quoted prices in active markets (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 June 30, 2011 and December 31, 2010 was $62.7 million and $61.7 million, respectively. The estimated fair value of our term loan facility based on internally developed discounted cash flow model and inputs based on management’s best estimates (level 3 input) for identical liabilities as of December 31, 2010 was $49.2 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 and not easily transferable, the estimated fair value of our note receivable is based on the market approach and time value of money which approximates the note receivable book value of $3.3 million and $3.4 million at June 30, 2011 and December 31, 2010, respectively. 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.
     The following is a reconciliation of the net beginning and ending balances recorded for financial assets and liabilities classified as Level 3 in the fair value hierarchy.

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    June 30,     December 31,  
    2011     2010  
    (in thousands)  
Financial assets:
               
Beginning balance
  $ 3,420     $ 3,265  
Issuances
          200  
Accrued interest
    200       398  
Payments
    (285 )     (443 )
 
           
Ending balance
  $ 3,335     $ 3,420  
 
           
 
               
Financial liabilities:
               
Beginning balance
  $ 49,237     $  
Debt issuance
          60,000  
Discount on debt
          (11,122 )
Amortization of discount on debt
    10,763       359  
Payments
    (60,000 )      
 
           
Ending balance
  $     $ 49,237  
 
           
Asset Retirement Liability
     Accounting Standards Codification (“ASC”) 410, “Asset Retirement and Environmental Obligations” (“ASC 410”), 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 six months ended June 30, 2011 or the year ended December 31, 2010. Changes in asset retirement obligations during the six months ended June 30, 2011 and the year ended December 31, 2010 were as follows:
                 
    June 30,     December 31,  
    2011     2010  
    (in thousands)  
Asset retirement obligations beginning of period
  $ 663     $ 50  
Liabilities recorded during the period
    52       382  
Liabilities settled during the period
           
Revisions in estimated cash flows
    (120 )     197  
Accretion expense
    4       34  
Reclassify to gain on sale of assets
    (599 )      
 
           
Asset retirement obligations end of period
  $     $ 663  
 
           
Noncontrolling Interests
     Changes in noncontrolling interest during the six months ended June 30, 2011 and 2010, were as follows:
                 
    June 30,     June 30,  
    2011     2010  
    (in thousands)  
Balance at beginning of period
  $ 70,051     $ 57,406  
Net income attributable to noncontrolling interest
    6,911       8,965  
 
           
Balance at end of period
  $ 76,962     $ 66,371  
 
           
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. Diluted EPS reflects the potential dilution that would occur if securities or other contracts to issue common stock were exercised or converted into common stock.

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    Three Months Ended June 30,  
    2011     2010  
    Basic     Diluted     Basic     Diluted  
    (in thousands, except per share data)  
Loss from continuing operations(a)
  $ (9,163 )   $ (9,163 )   $ (1,099 )   $ (1,099 )
Discontinued operations
    99,213       99,213       803       803  
 
                       
Net income (loss) attributable to Harvest
  $ 90,050     $ 90,050     $ (296 )   $ (296 )
 
                       
Weighted average common shares outstanding
    34,039       34,039       33,399       33,399  
Effect of dilutive securities
          6,162              
 
                       
Weighted average common shares, including dilutive effect
    34,039       40,201       33,399       33,399  
 
                       
Per share:
                               
Loss from continuing operations(a)
  $ (0.27 )   $ (0.23 )   $ (0.03 )   $ (0.03 )
Discontinued operations
  $ 2.92     $ 2.47     $ 0.02     $ 0.02  
Net income (loss) attributable to Harvest
  $ 2.65     $ 2.24     $ (0.01 )   $ (0.01 )
                                 
    Six Months Ended June 30,  
    2011     2010  
    Basic     Diluted     Basic     Diluted  
    (in thousands, except per share data)          
Income (loss) from continuing operations(a)
  $ (5,127 )   $ (5,127 )   $ 21,476     $ 21,476  
Discontinued operations
    95,947       95,947       2,818       2,818  
 
                       
Net income attributable to Harvest
  $ 90,820     $ 90,820     $ 24,294     $ 24,294  
 
                       
Weighted average common shares outstanding
    33,992       33,992       33,337       33,337  
Effect of dilutive securities
          5,841             4,038  
 
                       
Weighted average common shares, including dilutive effect
    33,992       39,833       33,337       37,375  
 
                       
Per share:
                               
Income (loss) from continuing operations(a)
  $ (0.15 )   $ (0.13 )   $ 0.64     $ 0.57  
Discontinued operations
  $ 2.82     $ 2.41     $ 0.09     $ 0.08  
Net income attributable to Harvest
  $ 2.67     $ 2.28     $ 0.73     $ 0.65  
 
(a)   Excludes net income attributable to noncontrolling interest.
     For the three months ended June 30, 2011 and 2010, the per share calculations above exclude 0.7 million and 3.8 million options, respectively, because their exercise price exceeded the average stock price for the period. The per share calculations above for the three months ended June 30, 2011 also exclude 1.6 million warrants because their exercise price exceeded the average stock price for the period. For the three months ended June 30, 2010, the per share calculations above exclude 5.6 million convertible shares because they were anti-dilutive. We did not have any warrants outstanding during the three months ended June 30, 2010.
     For the six months ended June 30, 2011 and 2010, the per share calculations above exclude 0.3 million and 3.8 million options, respectively, because their exercise price exceeded the average stock price for the period. The per share calculations above for the six months ended June 30, 2011 also exclude 1.6 million warrants because their exercise price exceeded the average stock price for the period. For the six months ended June 30, 2010, the per share calculations above exclude 5.6 million convertible shares because they were anti-dilutive. We did not have any warrants outstanding during the six months ended June 30, 2010.
     Stock options for 41,666 shares were exercised in the six months ended June 30, 2011 resulting in cash proceeds of $0.4 million. Stock options for 0.1 million shares were exercised in the six months ended June 30, 2010 resulting in cash proceeds of $0.1 million.
New Accounting Pronouncements
     In April 2011, the Financial Accounting Standard Board (“FASB”) issued ASU No. 2011-04, which is included in ASC 820, “Fair Value Measurement” (“ASC 820”). This update explains how to measure fair value. It does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. ASU No. 2011-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early

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adoption is not permitted. The adoption of ASU No. 2011-04 is not expected to have a material impact on our consolidated financial position, results of operation or cash flows.
     In June 2011, the FASB issued ASU No. 2011-05, which is included in ASC 220, “Comprehensive Income” (“ASC 220”). This update requires that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and will be applied restrospectively. Early adoption is permitted. The adoption of ASU No. 2011-05 will impact the presentation of our results of operations.
Revisions
     Net income from discontinued operations for the three months ended March 31, 2011 and 2010 was revised to include approximately $0.4 million and $0.3 million, respectively, of general and administrative expense related to the sale of our Antelope Project. These revisions did not impact consolidated net income for the three months ended March 31, 2011 and 2010, and we concluded the adjustments were not material to our Quarterly Report on Form 10-Q for the three months ended March 31, 2011. These revisions have been reflected in the six months ended June 30, 2011.
Reclassifications
     Certain items in 2010 have been reclassified to conform to the 2011 financial statement presentation.
Note 3 — Dispositions
Assets Held for Sale
     On May 17, 2011, we closed the transaction to sell our Antelope Project (see Note 9 — United States Operations, Western United States — Antelope). The sale has an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale of $103.9 million is reported in discontinued operations in the second quarter of 2011.
     The Antelope Project has been classified as discontinued operations. The Antelope Project assets and liabilities held for sale as of December 31, 2010, are reported in the consolidated balance sheet as follows:
         
    December 31,  
    2010  
    (in thousands)  
Proved oil and gas properties
  $ 31,037  
Unproved oil and gas properties
    57,737  
 
     
Total assets held for sale
  $ 88,774  
 
     
Asset retirement liabilities
  $ 663  
 
     
Total liabilities held for sale
  $ 663  
 
     
Discontinued Operations
     Revenue and net income on these dispositions are shown in the table below:
                                 
    Three Months Ended   Six Months Ended
    June 30,   June 30,
    2011   2010   2011   2010
    (in thousands)
Revenue applicable to discontinued operations
  $ 2,368     $ 2,914     $ 6,488     $ 6,038  
Net income from discontinued operations
  $ 99,213     $ 803     $ 95,947     $ 2,818  

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     Net income from discontinued operations for the three months ended June 30, 2011 includes $0.2 million for employee severance and special accomplishment bonuses and $5.2 million of U.S. income tax related to the sale of our Antelope Project. Net income from discontinued operations for the six months ended June 30, 2011 includes $1.4 million for impairment of inventory from cost to market, $3.6 million for employee severance and special accomplishment bonuses, and $5.2 million of U.S. income tax related to the sale of our Antelope Project. See Note 2 — Summary of Significant Accounting Policies — Revisions for a discussion of adjustments to net income for the three months ended March 31, 2011 and 2010.
     Special accomplishment bonuses of $1.2 million directly related to the sale of the Antelope Project were paid at the closing of the sale. Employee severance costs of $0.1 million were paid in the three months ended June 30, 2011, and $1.3 million is expected to be paid in January 2012. Severance costs for key employees include $0.5 million of restricted stock units which was paid in July 2011. Severance costs for key employees also include 58,000 stock appreciation rights (“SAR”) granted at an exercise price of $4.595 per right. These SARs are exercisable by the key employee for up to one year after termination.
Note 4 — Long-Term Debt
Long-Term Debt
                 
    June 30,     December 31,  
    2011     2010  
    (in thousands)  
Senior convertible notes, unsecured, with interest at 8.25%
               
See description below
  $ 32,000     $ 32,000  
Term loan facility with interest at 10%
               
See description below
          60,000  
 
           
 
    32,000       92,000  
 
               
Discount on term loan facility
               
See description below
          (10,763 )
 
           
 
  $ 32,000     $ 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 senior convertible 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 senior convertible 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 associated with the senior convertible notes offering are being amortized over the remaining life of the notes and are recorded in other assets. The balance for financing costs was $1.4 million and $1.9 million at June 30, 2011 and December 31, 2010, respectively.
     On October 29, 2010, we closed 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 was paid on a monthly basis at the initial rate of 10 percent and had a maturity of October 28, 2012. The initial rate of interest was scheduled to increase to 15 percent on July 28, 2011, the Bridge Date. Financing costs associated with the term loan facility offering were being amortized over the remaining life of the loan and were recorded in other assets. The balance for financing costs was $0.3 million at December 31, 2010.
     The proceeds from the sale of our Antelope Project are considered an “Extraordinary Receipt” as defined in the term loan facility with MSD Energy. Pursuant to the terms of the term loan facility, on May 17, 2011, we paid amounts outstanding under the term loan facility, including principal, accrued and unpaid interest and a prepayment premium of 3.5 percent of the amount outstanding, or an aggregate $62.1 million, with the net cash proceeds received from the sale of our Antelope Project. With the payment of the term loan facility, the balance of the

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financing costs related to the issuance of the term loan facility of $0.3 million was expensed to loss on extinguishment of debt in the six months ended June 30, 2011.
     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 Tranche C 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 May 17, 2011, in connection with the payment of the term loan facility, we repurchased all of the Tranche C warrants at $0.01 per share. The cost to repurchase the warrants ($44,000) was expensed to loss on extinguishment of debt in the six months ended June 30, 2011. On July 28, 2011, the Bridge Date, Tranche A and Tranche B warrants were repriced to $14.78 per warrant which is the lower of $15 or 120 percent of the average closing price of Harvest’s common stock for the 20 trading days immediately preceding 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 Tranche B was priced at $4.60 per warrant. The Monte Carlo option pricing model was used in pricing Tranche C due to the pricing and vesting variables in the agreement. Tranche C was priced at $0.62 per warrant. The value of the warrants was recorded as discount on debt with a corresponding credit to additional paid in capital. On May 17, 2011, in connection with the payment of the term loan facility, the balance of the discount on debt for Tranche A and Tranche B was expensed to loss on extinguishment of debt in the six months ended June 30, 2011. The balance of the discount on debt for Tranche C ($2.7 million) was reversed out of additional paid in capital as the warrants associated with Tranche C were unvested.
Note 5 — Commitments and Contingencies
     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 Al Ghubar / Qarn Alam license (“Block 64 EPSA”) in Oman for the drilling of two wells over a three-year period which expires in May 2012. We began funding this commitment in the second quarter of 2011. We also have minimum work commitments during the various phases of the exploration periods in the Budong PSC and Dussafu PSC.
     In October 2007, we entered into a JEDA with a private third party with respect to the Antelope Project. In connection with the sale of each party’s interests in the Antelope Project (see Note 3 — Dispositions), on January 11, 2011, we entered into a letter agreement with the private third party wherein the private third party agreed to reimburse us for certain expenses related to the sale of the two parties’ interests in the Antelope Project. The private third party disputes our calculation of the amount owed to us pursuant to the January 11, 2011 letter agreement. On March 11, 2011, we entered into a letter agreement with the private third party regarding certain obligations between the parties related to the JEDA. The private third party disputes our calculation of the amount due pursuant to one of the items in the March 11, 2011 letter agreement. At June 30, 2011, we have a note receivable outstanding from the private third party of $3.3 million (see Note 2 — Summary of Significant Accounting Policies, Accounts and Notes Receivable) and an account payable outstanding to the private third party of $3.6 million related to the purchase in July 2010 of an incremental 10 percent interest in the Antelope Project. At this time, we cannot predict the outcome of this dispute with the private third party.
     On May 31, 2011, the United Kingdom branch of our subsidiary, Harvest Natural Resources, Inc. (UK), initiated a wire transfer of approximately $1.1 million ($0.7 million net to our 66.667 percent interest) intending to pay Libya Oil Gabon S.A. (“LOGSA”) for fuel that LOGSA supplied to our subsidiary in the Netherlands, Harvest Dussafu, B.V., for the company’s drilling operations in Gabon. On June 1, 2011, our bank notified us that it had been required to block the payment in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s OFAC, because the payee, LOGSA, may be a blocked party under the sanctions. The bank further advised us that it could not release the funds to the payee or return the funds to us unless we obtain authorization from OFAC.

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     On June 30, 2011, we filed a voluntary self-disclosure with OFAC to report that we had possibly violated the U.S. sanctions by attempting to remit funds to LOGSA. We concurrently applied for a license with OFAC that would authorize us to pay LOGSA for the fuel provided. We are unable, at this time, to predict when a license may be granted, if at all. We also intend to file an application with OFAC for return of the blocked funds to us. Unless that application is approved, the funds will remain in the blocked account, and we can give no assurance when, or if, OFAC will permit the funds to be released. In addition, we owe this supplier approximately $0.7 million ($0.5 million net to our 66.667 percent interest) in additional payments that we are unable to remit unless we are authorized to do so. We are also investigating to what extent payments to LOGSA can be made under European Union sanctions.
     If it is found that we violated the U.S. sanctions, such violations may be punishable by civil penalties, including fines, denial of export privileges, injunctions, asset seizures, debarment from government contracts and revocations or restrictions of licenses, as well as criminal fines and imprisonment. Although we are unable to estimate the amount or range of any possible losses resulting from this matter, we do not believe that this matter will have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
     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 Petroleos de Venezuela S.A. (“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 a 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 a 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.

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    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 that will have a material adverse impact on our consolidated 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:
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
    (in thousands)  
Franchise Taxes
  $ 45     $ 45     $ 91     $ 106  
Payroll and Other Taxes
    262       153       565       392  
 
                       
 
  $ 307     $ 198     $ 656     $ 498  
 
                       
Taxes on Income
     As further disclosed in Note 3 — Dispositions, we completed the sale of our Antelope Project during the second quarter 2011, recognizing a capital gain. As a result, we expect to fully utilize all of our available net operating losses to offset most of the gain, and to also utilize our remaining alternative minimum tax credits against the resulting tax liability. Utilization of these tax benefits essentially eliminates the previously accrued deferred tax asset (“DTA”), and, therefore, also eliminates the valuation allowance associated with the DTA that we did not previously expect to utilize.
Note 7 — 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 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:

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    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
    (in thousands)  
Segment Income (Loss)
                               
Venezuela
  $ 17,300     $ 7,786     $ 33,662     $ 44,276  
Indonesia
    (1,464 )     (1,514 )     (2,877 )     (2,793 )
Gabon
    (417 )     (101 )     (550 )     (423 )
United States and other
    (24,582 )     (7,270 )     (35,362 )     (19,584 )
Discontinued operations (Antelope Project)
    99,213       803       95,947       2,818  
 
                       
Net income (loss) attributable to Harvest
  $ 90,050     $ (296 )   $ 90,820     $ 24,294  
 
                       
                 
    June 30,     December 31,  
    2011     2010  
    (in thousands)  
Operating Segment Assets
               
Venezuela
  $ 313,855     $ 292,023  
Indonesia
    58,051       16,254  
Gabon
    48,515       25,335  
United States and other
    214,976       130,626  
Net assets held for sale (Antelope Project)
          88,774  
 
           
 
    635,397       553,012  
Intersegment eliminations
    (91,626 )     (64,768 )
 
           
 
  $ 543,771     $ 488,244  
 
           
Note 8 — Investment in Equity Affiliates
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. Petrodelta has undertaken its operations in accordance with Petrodelta’s business plan as set forth in its conversion contract. Under its 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. Petrodelta’s 2011 capital expenditures are expected to be approximately $200 million. Petrodelta’s shareholders are still reviewing the 2011 final capital budget for updated drilling requirements.
     As previously disclosed, 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 is continuing 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 2008, the Venezuelan government published in the Official Gazette the Law of Special Contribution to Extraordinary Prices at the Hydrocarbons International Market (“original Windfall Profits Tax”). The original Windfall Profits Tax is calculated on the Venezuelan Export Basket (“VEB”) of prices as published by the Ministry of the People’s Power for Energy and Petroleum (“MENPET”). The original Windfall Profits Tax is applied to gross oil production delivered to PDVSA. The original Windfall Profits Tax established a special contribution to the Venezuelan government of (1) a 50 percent tax when the average price of the VEB exceeded $70 per barrel but is less than $100 per barrel, and (2) a 60 percent tax when the average price of the VEB exceeds $100 per barrel. The

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original Windfall Profits Tax was repealed with the issuance on April 18, 2011 of the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (the “amended Windfall Profits Tax”).
     The amended Windfall Profits Tax establishes a special contribution for extraordinary prices to the Venezuelan government of 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $40 per barrel for 2011) and $70 per barrel. The amended Windfall Profits Tax also establishes a special contribution for exorbitant prices to the Venezuelan government of (1) 80 percent when the average price of the VEB exceeds $70 per barrel but is less than $90 per barrel; (2) of 90 percent when the average price of the VEB exceeds $90 per barrel but is less that $100 per barrel; and (3) of 95 percent when the average price of the VEB exceeds $100 per barrel. The amended Windfall Profits Tax caps the royalty paid on production at $70 per barrel. It is not clear from the drafting of the amended Windfall Profits Tax how the $70 cap on royalty barrels will be applied to royalties paid in-kind. By placing a cap on the royalty barrels, the amended Windfall Profits Tax reduces the royalties paid to the government and increases payments to the National Development Fund (“FONDEN”). Petrodelta pays royalties in-kind and has not applied the $70 cap to its royalty barrels as doing so may overstate earnings. Until further guidance is issued, Petrodelta will continue applying the current sales price to its royalty barrels.

     Also, the amended Windfall Profits Tax considers that an exemption of this tax could be granted by MENPET for the incremental production of projects and grass root developments until the specific investments are recovered. This exemption has to be considered and approved in a case by case basis by MENPET. We believe several of the fields operated by Petrodelta may qualify for the exemption from the amended Windfall Profits Tax. We are waiting for clarification from MENPET on the definitions of incremental production and grass roots development, as well as guidance on the process for applying for the exemption. There are many sections of the amended Windfall Profits Tax which have yet to be clarified.
     Both the original and amended Windfall Profits Taxes are deductible for Venezuelan income tax purposes. Petrodelta recorded $65.3 million and $92.5 million for the combined original and amended Windfall Profits Taxes during the three and six months ended June 30, 2011, respectively. We estimate that the amended Windfall Profits Tax increased the expense for windfall profits tax by $15.4 million for the six months ended June 30, 2011. Petrodelta recorded $1.7 million and $2.9 million of expense for the original Windfall Profits Tax during the three and six months ended June 30, 2010, respectively.
     The Science and Technology Law (referred to as “LOCTI” in Venezuela) 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 on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. 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 fourth quarter of 2010. However, in April 2011, Petrodelta received a copy of the waiver acceptance letter issued by LOCTI to PDVSA for the 2010 filing year. Petrodelta reversed the 2010 LOCTI accrual of $4.6 million, $2.3 million net of tax ($0.7 million net to our 32 percent interest) in the three months ended March 31, 2011. Petrodelta is accruing the 2011 liability to LOCTI on a current basis.
     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. LOCTI was also modified to require all contributions to be paid in cash directly to the National Fund for Science, Technology and Innovation (“FONDACIT”), the entity responsible for the administration of LOCTI contributions. Self-funded programs and direct contributions to projects performed by other institutions are no longer allowed.
     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). Petrodelta shareholder approval of the dividend was received on March 14, 2011. As of July 29, 2011, this dividend has not been received, and the timing of the receipt of this dividend is uncertain.
     Petrodelta does not have currency exchange risk other than the official prevailing exchange rate that applies to its operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). 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 rate. 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

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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. At June 30, 2011, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 97.3 million Bolivars and 2,542.6 million Bolivars, respectively.
     Petrodelta’s reporting and functional currency is the U.S. Dollar. Petrodelta’s financial information is prepared in accordance with International Financial Reporting Standards (“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 June 30, 2011 and December 31, 2010 and for the three and six months ended June 30, 2011 and 2010:
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
    (in thousands)  
Revenues:
                               
Oil sales
  $ 282,975     $ 135,964     $ 509,588     $ 277,466  
Gas sales
    679       1,022       1,405       2,040  
Royalty
    (96,214 )     (46,391 )     (173,529 )     (94,377 )
 
                       
 
    187,440       90,595       337,464       185,129  
Expenses:
                               
Operating expenses
    18,684       10,632       32,966       20,675  
Workovers
    7,021             13,496        
Depletion, depreciation and amortization
    13,231       9,770       25,718       18,377  
General and administrative
    3,782       2,641       2,852       6,058  
Windfall profits tax
    65,345       1,664       92,471       2,915  
 
                       
 
    108,063       24,707       167,503       48,025  
 
                       
Income from operations
    79,377       65,888       169,961       137,104  
 
                               
Gain on exchange rate
          1,938             120,654  
Investment earnings and other
    185       (13 )     352       2,881  
Interest expense
    (3,146 )     (1,328 )     (4,418 )     (2,223 )
 
                       
 
                               
Income before income tax
    76,416       66,485       165,895       258,416  
 
                               
Current income tax expense
    31,618       52,656       84,961       138,076  
Deferred income tax (benefit) expense
    (2,513 )     5,118       (28,275 )     47,582  
 
                       
Net income
    47,311       8,711       109,209       72,758  
Adjustment to reconcile to reported net income from unconsolidated equity affiliate:
                               
Deferred income tax (benefit) expense
    1,176       (14,499 )     19,739       (47,488 )
 
                       
Net income equity affiliate
    46,135       23,210       89,470       120,246  
Equity interest in unconsolidated equity affiliate
    40 %     40 %     40 %     40 %
 
                       
Income before amortization of excess basis in equity affiliate
    18,454       9,284       35,788       48,098  
Amortization of excess basis in equity affiliate
    (452 )     (322 )     (873 )     (656 )
Conform depletion expense to GAAP
    (216 )     (47 )     (297 )     (160 )
 
                       
Net income from unconsolidated equity affiliate
  $ 17,786     $ 8,915     $ 34,618     $ 47,282  
 
                       
                 
    June 30,   December 31,
    2011   2010
    (in thousands)
Current assets
  $ 905,004     $ 535,225  
Property and equipment
    365,998       321,816  
Other assets
    87,013       67,755  
Current liabilities
    756,916       406,339  
Other liabilities
    43,207       39,224  
Net equity
    557,892       479,233  

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Fusion Geophysical, LLC (“Fusion”)
     On January 28, 2011, Fusion Geophysical, LLC’s (“Fusion”) 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. We received $1.4 million for our equity investment 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.
     At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion. Accordingly, we did not record net losses incurred by Fusion in the six months ended June 30, 2011 and 2010 as doing so would have caused our equity investment to go into a negative position. However, we have recognized a $1.4 million gain on the sale of Fusion in the six months ended June 30, 2011.
Note 9 — United States Operations
     In 2008, we initiated a domestic exploration program in two different basins. We are the operator of both exploration programs.
Gulf Coast
West Bay Project
     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 parties. During the six months ended June 30, 2011, we and our partners in the West Bay project agreed to relinquish the exploration acreage we held to the farmor. The relinquishment is expected to be completed by August 2011. Neither we nor our partners intend to continue any

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activity in West Bay. Based on the decision in the second quarter 2011 to relinquish the exploration acreage, we impaired the carrying value of West Bay of $3.3 million as of June 30, 2011. The West Bay project represented $3.3 million of unproved oil and gas properties on our December 31, 2010 balance sheet.
Western United States — Antelope
     On May 17, 2011, we closed the transaction to sell all of our interest in the oil and gas assets located in our Antelope Project area in the Uinta Basin of Utah which consisted of approximately 69,000 gross acres (47,600 net acres), and the related contracts, reserves, production, wells, pipelines production facilities and other rights, title and interests located in the Uintah Basin in Duchesne and Uintah Counties, Utah. The transaction included the Mesaverde Gas Exploration and Appraisal Project (“Mesaverde”), the Lower Green River/Upper Wasatch and the Monument Butte Extension. We owned an approximate working interest of 70 percent in the Mesaverde and Lower Green River/Upper Wasatch, an approximate 60 percent working interest in one well in the Monument Butte Extension, an approximate 43 percent working interest in the initial eight well program in the Monument Butte Extension, and 37 percent working interest in the follow-up six well program in the Monument Butte Extension. The initial eight well program and follow-up six well program in the Monument Butte Extension were non-operated. The sale has an effective date of March 1, 2011 (see Note 3 — Dispositions). We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. All activities associated with the Antelope Project have been reflected as discontinued operations on the statement of operations.
Note 10 — Indonesia
     On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator to a third party, which allowed us to acquire an additional 10 percent equity interest in the Budong PSC at a cost of $3.7 million. Closing of this acquisition, which is subject to the approval of the Government of Indonesia and BPMIGAS, increased our interest in the Budong PSC to 64.4 percent. The $3.7 million was paid on April 18, 2011.
     During the initial exploration period, the Budong PSC covered 1.35 million acres. The Budong PSC includes a ten-year exploration period and a 20-year development phase. Pursuant to the terms of the Budong PSC, at the end of the first three-year exploration phase, 45 percent of the original area was to be relinquished to BPMIGAS. In January 2010, 35 percent of the original area was relinquished and ten percent of the required relinquishment was deferred until 2011. On January 20, 2011, the deferred ten percent of the original total contract area was relinquished to BPMIGAS. The Budong PSC now covers 0.75 million acres.
     See Note 2 — Summary of Significant Accounting Policies — Suspended Exploratory Drilling Costs, Budong PSC for a status of the LG-1 exploratory drilling costs. The Budong PSC represents $26.5 million and $10.9 million of unproved oil and gas properties on our June 30, 2011 and December 31, 2010 balance sheets, respectively.
Note 11 — Gabon
     We are the operator of the Dussafu PSC offshore Gabon in West Africa with a 66.667 percent ownership interest. 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 three-year exploration phase of the Dussafu PSC with an effective date of May 28, 2007. In order to complete drilling activities of the first exploratory well, in March 2011, the Direction Generale Des Hydrocarbures (“DGH”) approved a second one-year extension to May 27, 2012 of the second exploration phase.
     A Standby Letter of Credit was issued on April 8, 2011 for the Transocean Sedneth 701 semi-submersible drilling unit. We took possession of the drilling unit mid-April 2011 on a one well contract. A second Standby Letter of Credit was issued April 7, 2011 for the Subsea 7 Remote Operated Vehicle.
     See Note 5 — Commitments and Contingencies for a discussion of legal matters related to our Gabon operations.
     The Dussafu PSC represents $24.5 million and $9.2 million of unproved oil and gas properties on our June 30, 2011 and December 31, 2010 balance sheets, respectively.
Note 12 — Oman
     In April 2009, we signed an Exploration and Production Sharing Agreement (“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. 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 began funding this commitment in the second quarter of 2011.
     The Block 64 EPSA represents $5.0 million and $4.2 million of unproved oil and gas properties on our June 30, 2011 and December 31, 2010 balance sheets, respectively.

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Note 13 — 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 one dividend, totaling $12.2 million, which has not yet been received by HNR Finance. HNR Finance has not distributed these dividends to the partners. At June 30, 2011, Vinccler’s share of the undistributed dividends is $9.0 million.
Note 14 — Subsequent Event
     We conducted our subsequent events review up through the date of the issuance of this Quarterly Report on Form 10-Q.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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. A discussion of these factors is included in our Annual Report on Form 10-K for the year ended December 31, 2010, which includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q.
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 Port Gentil, Republic of Gabon (“Gabon”) 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, and Vinccler indirectly owns eight percent. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. 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 mainly onshore West Sulawesi in Indonesia; offshore of Gabon; onshore in Oman; and offshore of the People’s Republic of China (“China”). Until March 1, 2011, we had developed and undeveloped 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 had established production (see Notes to Consolidated Financial Statements — Note 3 — Dispositions).

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     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 producing and exploration assets, and we are currently evaluating these potential opportunities. There can be no assurances that our discussions will continue or that any transaction may ultimately result from our discussions.
     On May 17, 2011, we closed the transaction to sell all of our interest in the oil and gas assets in Utah’s Uinta Basin (“Antelope Project”). The transaction included the Mesaverde Gas Exploration and Appraisal Project (“Mesaverde”), the Lower Green River/Upper Wasatch and the Monument Butte Extension. The sale has an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. Bank of America Merrill Lynch served as our financial advisor in connection with this transaction. This transaction is part of our ongoing process of exploring strategic alternatives announced in September 2010.
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 Venezuela Bolivars (“Bolivars”) (4.30 Bolivars per U.S. Dollar). However, during the three and six months ended June 30, 2011, Harvest Vinccler exchanged approximately $0.1 million and $0.4 million, respectively, through Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) and received an average exchange rate of 5.21 Bolivars and 5.19 Bolivars, respectively, per U.S. Dollar. During the three and six months ended June 30, 2010, no such exchanges took place. Petrodelta does not have, and has not had, any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate. Harvest Vinccler currently does not have any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate.
     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. At June 30, 2011, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 3.1 million Bolivars and 4.3 million Bolivars, respectively. At June 30, 2011, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 97.3 million Bolivars and 2,542.6 million Bolivars, respectively.
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.
     Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Petrodelta’s 2011 capital expenditures are expected to be approximately $200 million. Petrodelta’s shareholders are still reviewing the 2011 final capital budget for updated drilling requirements. 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 further drilling in the Isleño field. It also includes engineering work for production facilities required for the full development of the El Salto and Temblador fields. 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. During the six months ended June 30, 2011, Petrodelta has incurred $66.5 million in capital expenditures.
     As previously disclosed, 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

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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 is continuing 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 continuing to have an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.
     In 2008, the Venezuelan government published in the Official Gazette the Law of Special Contribution to Extraordinary Prices at the Hydrocarbons International Market (“original Windfall Profits Tax”). The original Windfall Profits Tax is calculated on the Venezuelan Export Basket (“VEB”) of prices as published by the Ministry of the People’s Power for Energy and Petroleum (“MENPET”). The original Windfall Profits Tax is applied to gross oil production delivered to PDVSA. The original Windfall Profits Tax established a special contribution to the Venezuelan government of (1) a 50 percent tax when the average price of the VEB exceeded $70 per barrel but is less than $100 per barrel, and (2) a 60 percent tax when the average price of the VEB exceeds $100 per barrel. The original Windfall Profits Tax was repealed with the issuance on April 18, 2011 of the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (the “amended Windfall Profits Tax”).
     The amended Windfall Profits Tax establishes a special contribution for extraordinary prices to the Venezuelan government of 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $40 per barrel for 2011) and $70 per barrel. The amended Windfall Profits Tax also establishes a special contribution for exorbitant prices to the Venezuelan government of (1) 80 percent when the average price of the VEB exceeds $70 per barrel but is less than $90 per barrel; (2) of 90 percent when the average price of the VEB exceeds $90 per barrel but is less that $100 per barrel; and (3) of 95 percent when the average price of the VEB exceeds $100 per barrel. The amended Windfall Profits Tax caps the royalty paid on production at $70 per barrel. It is not clear from the drafting of the amended Windfall Profits Tax how the $70 cap on royalty barrels will be applied to royalties paid in-kind. By placing a cap on the royalty barrels, the amended Windfall Profits Tax reduces the royalties paid to the government and increases payments to the National Development Fund (“FONDEN”). Petrodelta pays royalties in-kind and has not applied the $70 cap to its royalty barrels as doing so may overstate earnings. Until further guidance is issued, Petrodelta will continue applying the current sales price to its royalty barrels.

     Also, the amended Windfall Profits Tax considers that an exemption of this tax could be granted by MENPET for the incremental production of projects and grass root developments until the specific investments are recovered. This exemption has to be considered and approved in a case by case basis by MENPET. We believe several of the fields operated by Petrodelta may qualify for the exemption from the amended Windfall Profits Tax. We are waiting for clarification from MENPET on the definitions of incremental production and grass roots development, as well as guidance on the process for applying for the exemption. There are many sections of the amended Windfall Profits Tax which have yet to be clarified.
     Both the original and amended Windfall Profits Taxes are deductible for Venezuelan income tax purposes. Petrodelta recorded $65.3 million and $92.5 million for the combined original and amended Windfall Profits Taxes during the three and six months ended June 30, 2011, respectively. We estimate that the amended Windfall Profits Tax increased the expense for windfall profits tax by $15.4 million for the three and six months ended June 30, 2011. Petrodelta recorded $1.7 million and $2.9 million of expense for the original Windfall Profits Tax during the three and six months ended June 30, 2010, respectively.
     The Science and Technology Law (referred to as “LOCTI” in Venezuela) 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 on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. 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 fourth quarter of 2010. However, in April 2011, Petrodelta received a copy of the waiver acceptance letter issued by LOCTI to PDVSA for the 2010 filing year. Petrodelta reversed the 2010 LOCTI accrual of $4.6 million, $2.3

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million net of tax ($0.7 million net to our 32 percent interest) in the three months ended March 31, 2011. Petrodelta is accruing the 2011 liability to LOCTI on a current basis.
     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. LOCTI was also modified to require all contributions to be paid in cash directly to the National Fund for Science, Technology and Innovation (“FONDACIT”), the entity responsible for the administration of LOCTI contributions. Self-funded programs and direct contributions to projects performed by other institutions are no longer allowed.
     The recently announced reinstatement of emergency electricity conservation measures in Venezuela are not expected to have a material impact on Petrodelta. There is no particular language in the emergency measure that limits or imposes any restrictions to operations related to the oil and gas industry related sectors. The regulations explicitly states that the oil and gas sector is excluded from consumption limits and reduction directly linked to the operations. Petrodelta’s operations currently generate most of its own power either through Uracoa’s generator systems, PDVSA’s electrical grid, or rented portable generators. Tucupita if the only field which has a connection to the public grid. Current regulations and shortages are focused on the industrial, commercial and domestic sectors.
     During the six months ended June 30, 2011, Petrodelta drilled and completed eight development wells, one successful appraisal well and one water injector well compared to nine development wells in the six months ended June 30, 2010. Petrodelta delivered approximately 5.4 million barrels (“MBls”) of oil and 0.9 billion cubic feet (“Bcf”) of natural gas, averaging 30,481 barrels of oil equivalent (“BOE”) per day during the six months ended June 30, 2011 compared to deliveries of 3.9 MBls of oil and 1.3 Bcf of gas, averaging 22,895 BOE per day during the six months ended June 30, 2010.
     During the six months ended June 30, 2011, Petrodelta completed facilities at EPM transfer point for El Salto field. Completion of the facilities has enabled Petrodelta to increase production from the El Salto field. Petrodelta is continuing additional infrastructure enhancement projects in El Salto and Temblador. Currently, Petrodelta is operating drilling rigs in the El Salto and Uracoa fields, and workover rigs in the Uracoa and Tucupita fields. Petrodelta expects to take possession of a third drilling rig in August 2011.
     Certain operating statistics for the three and six months ended June 30, 2011 and 2010 for the Petrodelta fields operated by Petrodelta are set forth below. This information is provided at 100 percent. This information may not be representative of future results.
                                 
    Three Months Ended   Six Months Ended
    June 30,   June 30,
    2011   2010   2011   2010
Thousand barrels of oil sold
    2,782       1,955       5,365       3,923  
Million cubic feet of gas sold
    440       663       910       1,323  
Total thousand barrels of oil equivalent
    2,855       2,066       5,517       4,144  
Average price per barrel
  $ 101.72     $ 69.55     $ 94.98     $ 70.73  
Average price per thousand cubic feet
  $ 1.54     $ 1.54     $ 1.54     $ 1.54  
Cash operating costs ($millions)
  $ 18.7     $ 11.6     $ 33.0     $ 22.8  
Capital expenditures ($millions)
  $ 32.1     $ 19.4     $ 66.5     $ 25.5  
     Crude oil delivered from the Petrodelta fields to PDVSA Petroleo S.A. (“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.

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United States
Gulf Coast — West Bay
     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 parties. During the six months ended June 30, 2011, we and our partners in the West Bay project agreed to relinquish the exploration acreage we held to the farmor. The relinquishment is expected to be completed by August 2011. Neither we nor our partners intend to continue any activity in West Bay. Based on the decision in the second quarter 2011 to relinquish the exploration acreage, we impaired the carrying value of West Bay of $3.3 million as of June 30, 2011.
Western United States — Antelope
     On May 17, 2011, we closed the transaction to sell all of our interest in the oil and gas assets located in our Antelope Project area in the Uinta Basin of Utah which consisted of approximately 69,000 gross acres (47,600 net acres), and the related contracts, reserves, production, wells, pipelines production facilities and other rights, title and interests located in the Uintah Basin in Duchesne and Uintah Counties, Utah. The transaction included the Mesaverde, the Lower Green River/Upper Wasatch and the Monument Butte Extension. We owned an approximate working interest of 70 percent in the Mesaverde and Lower Green River/Upper Wasatch, an approximate 60 percent working interest in one well in the Monument Butte Extension, an approximate 43 percent working interest in the initial eight well program in the Monument Butte Extension, and 37 percent working interest in the follow-up six well program in the Monument Butte Extension. The initial eight well program and follow-up six well program in the Monument Butte Extension are non-operated. The sale has an effective date of March 1, 2011 (see Notes to Consolidated Financial Statements, Note 3 — Dispositions). We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project.
Budong-Budong Project, Indonesia (“Budong PSC”)
     In January 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. On April 18, 2011, we paid the $3.7 million consideration. Closing of this acquisition, which is subject to the approval of the Government of Indonesia and BPMIGAS, increased our interest in the Budong PSC to 64.4 percent.
     During the initial exploration period, the Budong PSC covered 1.35 million acres. The Budong PSC includes a ten-year exploration period and a 20-year development phase. Pursuant to the terms of the Budong PSC, at the end of the first three-year exploration phase, 45 percent of the original area was to be relinquished to BPMIGAS. In January 2010, 35 percent of the original area was relinquished and ten percent of the required relinquishment was deferred until 2011. On January 20, 2011, the deferred ten percent of the original total contract area was relinquished to BPMIGAS. The Budong PSC now covers 0.75 million acres.
     The Lariang-1 (“LG-1”), the first of two planned exploration wells, was spud on January 6, 2011 in the Budong-Budong Block, West Sulawesi. On April 8, 2011, the LG-1 was plugged and abandon for safety

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reasons. The primary Eocene targets had not yet been reached, as the well was planned for a total measured depth of approximately 7,200 feet. The costs for drilling the LG-1, $13.9 million, have been suspended pending further evaluation and appraisal (see Notes to Consolidated Financial Statements, Note 2 — Summary of Significant Accounting Policies — Suspended Exploratory Drilling Costs, Budong PSC).
     During the second quarter 2011, the drilling rig was mobilized from the LG-1 location to the Karama-1 (“KD-1”) location to drill the second exploratory well on the Budong PSC. The KD-1, which is located approximately 50 miles south of the LG-1, spud on June 20, 2011. The KD-1 will be drilled to test a thrusted surface anticline with stacked Miocene and Eocene targets to a planned total measured depth of approximately 10,800 feet. Drilling is anticipated to require approximately 43 days. In the event of success, additional time may be required to test and evaluate the well.
     During the six months ended June 30, 2011, we had cash capital expenditures of $9.4 million for drilling and construction costs and $3.7 million for the purchase of the additional 10 percent equity interest.
Dussafu Project — Gabon
     The Dussafu Marin Permit (“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 three-year exploration phase of the Dussafu PSC with an effective date of May 28, 2007. In order to complete drilling activities of the first exploratory well, in March 2011, the Direction Generale Des Hydrocarbures (“DGH”) approved a second one year extension to May 27, 2012 of the second exploration phase.
     Operational activities during the three months ended June 30, 2011 included negotiation and contracting of a drilling unit in preparation to spud the exploration well, the Dussafu Ruche Marin-1 (“DRM-1”), and drilling and testing of the DRM-1, which spud on April 28, 2011. A Standby Letter of Credit was issued on April 8, 2011 for the Transocean Sedneth 701 semi-submersible drilling unit. We took possession of the drilling unit mid-April 2011 on a one well contract. A second Standby Letter of Credit was issued April 7, 2011 for the Subsea 7 Remote Operated Vehicle. The DRM-1 was initially drilled in 380 feet of water.
     On June 10, 2011, we announced the DRM-1 had reached a vertical depth of 9,953 feet within the upper Dentale Formation. Log evaluation, pressure data and samples indicated an oil discovery of approximately 55 feet of pay in a 90 foot oil column within the Gamba Formation. We also announced plans to deepen the well to test Middle and Lower Dentale exploration potential and sidetrack to appraise the extent of the Gamba oil discovery.
     Subsequently the DRM-1 was deepened to reach a true vertical depth subsea (“TVDSS”) of 11,355 feet to test the prospectivity of the Middle and Lower Dentale Formations. Log evaluation, pressure data and a fluid sample indicate that Harvest has discovered a second oil accumulation with approximately 35 feet of oil pay within the secondary objective of the Middle Dentale Formation.
      The Gamba discovery has been appraised by drilling a sidetrack (“DRM-1ST1”) 0.75 miles to the southwest to test the lateral extent and structural elevation of the Gamba reservoir. The sidetrack was drilled to a total depth (“TD”) in the Upper Dentale of 11,562 feet, (9,428 feet TVDSS) and found 19 feet of oil pay in the Gamba reservoir. A second sidetrack (“DRM-1ST2”) was drilled 0.5 miles to the northwest of the original DRM-1 wellbore to a TD in the Upper Dentale of 11,562 feet, (9,428 feet TVDSS)and found 40 feet of oil pay in the Gamba reservoir. Following completion of the drilling operations in the second sidetrack, the well will be suspended for possible future use and the rig demobilized.
     During the six months ended June 30, 2011, we had cash capital expenditures of $13.9 million for well planning and drilling.
     See Notes to Consolidated Financial Statements, Note 5 — Commitments and Contingencies for a discussion of legal matters related to our Gabon operations.
Block 64 EPSA Project — Oman
     We have a work commitment of $22.0 million which is a minimum amount to be spent on the Al Ghubar / Qarn Alam license (“Block 64 EPSA”) for the drilling of two wells over a three-year period which expires in May 2012. Operational activities during the three months ended June 30, 2011 included completion of the prospect definition phase of the project and submission of two potential well locations to the Oman government. Well planning and procurement of long lead items began in April 2011 in anticipation of spudding the first of the two exploratory wells in late 2011. We plan to drill the two exploration wells back-to-back. During the six months ended June 30, 2011, we incurred $0.7 million for seismic interpretation.

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Management Changes
     Effective July 5, 2011, Mr. G. Michael Morgan, Vice President of Business Development, resigned. Mr. Morgan will remain with Harvest on a retained consulting arrangement through the end of 2011 in order to serve on the board of Petrodelta and assist in ongoing business development opportunities.
     Effective July 5, 2011, Mr. Patrick R. Oenbring, Vice President Western Operations, resigned due to the sale of the Antelope Project.
Capital Resources and Liquidity
     The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. In Item 1A — Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2010, 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.
     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. We are concentrating a substantial portion of our 2011 budget on the development of 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 in Oman for the drilling of two wells over a three-year period which expires in May 2012. We began funding this commitment in the second quarter of 2011. We also have minimum work commitments during the various phases of the exploration periods in the Budong PSC and Dussafu PSC.
     Our primary ongoing source of cash is still dividends from Petrodelta. 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). As of July 29, 2011, this dividend has not been received, and the timing of receipt of this dividend is uncertain. 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. As of March 31, 2011, Vinccler’s share of the undistributed dividends is $9.0 million inclusive of the unpaid November 2010 dividend. See Notes to Consolidated Financial Statements, Note 13 — Related Party Transactions.
     Working Capital. The net funds raised and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:

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    Six Months Ended June 30,  
    2011     2010  
    (in thousands)  
Net cash used in operating activities
  $ (14,922 )   $ (5,156 )
Net cash provided by (used in) investing activities
    152,024       (24,949 )
Net cash provided by (used in) financing activities
    (59,773 )     29,297  
 
           
Net increase (decrease) in cash
  $ 77,329     $ (808 )
 
           
     At June 30, 2011, we had current assets of $169.8 million and current liabilities of $36.1 million, resulting in working capital of $133.7 million and a current ratio of 4.7:1. This compares with a working capital of $133.3 million and a current ratio of 5.7:1 at December 31, 2010. The increase in working capital of $0.4 million was primarily due to dividends declared by an equity affiliate offset by increase in capital expenditures and administrative expenses and completion of the sale of the Antelope Project.
     Cash Flow used in Operating Activities. During the six months ended June 30, 2011 and 2010, net cash used in operating activities was approximately $14.9 million and $5.2 million, respectively. The $9.7 million decrease was primarily due to increases in accounts payable and income taxes payable and the sale of our Antelope Project.
     Cash Flow from Investing Activities. During the six months ended June 30, 2011, we had cash capital expenditures for property and equipment of approximately $28.1 million. Of the 2011 expenditures, $13.1 million was attributable to activity on the Budong PSC, $13.9 million was attributable to activity on the Dussafu PSC and $1.1 million was attributable to activity on other projects. During the six months ended June 30, 2010, we had cash capital expenditures of approximately $23.9 million. Of the 2010 expenditures, $15.4 million was attributable to activity on the Antelope projects, $5.6 million was attributable to activity on the Budong PSC, $1.6 million was attributable to activity on the Dussafu PSC and $1.3 million was attributable to other projects.
     During the six months ended June 30, 2011, we received sales proceeds of $217.8 million for the sale of our Antelope Project (see Notes to Consolidated Financial Statements, Note 3 — Dispositions), and we incurred $31.7 million of capital expenditures on the Antelope Project.
     During the six months ended June 30, 2011, we received $1.4 million from the sale of our equity investment in Fusion, and we deposited $7.3 million as collateral for two standby letters of credit issued in support of the drilling activities on the Gabon PSC. During the six months ended June 30, 2010, we deposited with a U.S. bank $1.0 million as collateral for a standby letter of credit issued in support of a bank guarantee required as a performance guarantee for a joint study. During the six months ended June 30, 2011 and 2010, we incurred $0.1 million and $0.03 million, respectively, of investigatory costs related to various international and domestic exploration studies.
     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 for 2011 will be funded through sales proceeds, our existing cash balances, accessing equity and debt markets, and cost reductions, as warranted.
     Cash Flow from Financing Activities. During the six months ended June 30, 2011, we repaid $60.0 million of our term loan facility. During the six months ended June 30, 2011 and 2010, we incurred $0.2 million and $0.3 million, respectively, in legal fees associated with financings. During the six months ended June 30, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes, incurred $2.5 million in deferred financings costs related to the $32.0 million convertible debt offering that are being amortized over the life of the financial instrument.
Results of Operations
     You should read the following discussion of the results of operations for the three and six months ended June 30, 2011 and 2010 and the financial condition as of June 30, 2011 and December 31, 2010 in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2010.

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Three Months Ended June 30, 2011 Compared with Three Months Ended June 30, 2010
     We reported net income attributable to Harvest of $90.1 million, or $2.24 diluted earnings per share, for the three months ended June 30, 2011, compared with a net loss attributable to Harvest of $0.3 million, or $(0.01) diluted earnings per share, for the three months ended June 30, 2010.
     Total expenses and other non-operating (income) expense from continuing operations (in millions):
                         
    Three Months Ended    
    June 30,   Increase
    2011   2010   (Decrease)
Depreciation and amortization
  $ 0.1     $ 0.1     $  
Exploration expense
    4.7       1.5       3.2  
General and administrative
    6.7       5.8       0.9  
Taxes other than on income
    0.3       0.2       0.1  
Investment earnings and other
    (0.2 )     (0.1 )     (0.1 )
Interest expense
    1.7       0.7       1.0  
Loss on extinguishment of debt
    9.7             9.7  
Other non-operating expense
    0.2             0.2  
Income tax expense
    0.3       0.2       0.1  
     During the three months ended June 30, 2011, we incurred $1.3 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, $0.1 million related to other general business development activities, and $3.3 million of impairment for the carrying value of West Bay (see Notes to Consolidated Financial Statements, Note 10 — United States Operations, Gulf Coast). During the three months ended June 30, 2010, we incurred $1.3 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations and $0.2 million related to other general business development activities.
     General and administrative costs were higher in the three months ended June 30, 2011 compared to the three months ended June 30, 2010, primarily due to higher employee related costs ($0.6 million), legal and other professional fees ($0.4 million), travel ($0.1 million) and other miscellaneous expenses ($0.1 million) offset by lower employee related costs ($0.1 million), public relations ($0.1 million), and general office and corporate overhead costs ($0.2 million). Taxes other than on income were higher in the three months ended June 30, 2011 compared to the three months ended June 30, 2010 primarily due to payroll related taxes.
     Investment earnings and other were higher in the three months ended June 30, 2011 compared to the three months ended June 30, 2011 due to the receipt of payment for transition services provided on the Antelope Project after closing of the sale. Interest expense was higher for the three months ended June 30, 2011 compared to the three months ended June 30, 2010 due to the interest associated with our $32 million convertible debt offering in February 2010, our $60 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 capitalized interest to oil and gas properties of $0.2 million. During the three months ended June 30, 2011, we incurred a loss on extinguishment of debt related to the early payment of our $60 million term loan facility. The loss on extinguishment of debt includes the write-off of the discount on debt ($7.2 million), a prepayment premium of 3.5 percent of the amount outstanding ($2.1 million), expensing of financing costs related to the term loan facility ($0.3 million), and the cost to repurchase 4.4 million unvested warrants issued in connection with the term loan facility (see Notes to Consolidated Financial Statements, Note 4 — Long-Term Debt).
     Other non-operating expense was higher in the three months ended June 30, 2011 compared to the three months ended June 30, 2010 due to costs incurred related to our on-going strategic alternative process and evaluation. For the three months ended June 30, 2011, income tax expense was higher compared with that of the three months ended June 30, 2010, due to income tax assessed in the Netherlands on an increase in interest income.
     For the three months ended June 30, 2011, net income from unconsolidated equity affiliates reflects an increase in Petrodelta’s revenue from oil sales due to higher sales volumes and prices which was partially offset by the amended Windfall Profits Tax. Operating expense and workovers increased in the three months ended June 30, 2011 compared to the three months ended June 30, 2010 due to increased oil production and having a workover rig on location. Petrodelta did not have a workover rig during the three months ended June 30, 2010. Gain on exchange rates decreased in the three months ended June 30, 2011 compared to the three months ended June 30, 2010 due to there not being any Bolivar/U.S. Dollar currency exchange rate devaluations during the current period. There was a Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. Petrodelta’s effective tax rate for the three months ended June 30, 2011 decreased compared to effective tax rate for the three months ended June 30, 2010 due to the tax effects of the currency devaluation in the three months ended June 30, 2010.

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Discontinued Operations
     On May 17, 2011, we closed the transaction to sell our Antelope Project. (See Notes to Consolidated Financial Statements, Note 3 — Dispositions and Note 9 — United States Operations, Western United States — Antelope.) The sale has an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale of $103.9 million is reported in the second quarter of 2011.
     Revenue and net income on discontinued operations for the three months ended June 30, 2011 and 2010 are shown in the table below:
                 
    Three Months Ended
    June 30,
    2011   2010
    (in thousands)
Revenue applicable to discontinued operations
  $ 2,368     $ 2,914  
Net income from discontinued operations
  $ 99,213     $ 803  
     Net income from discontinued operations for the three months ended June 30, 2011 includes $103.9 million gain in the sale of our Antelope Project, $0.2 million for employee severance and special bonuses, and $5.2 million U.S. income tax related to the sale of our Antelope Project.
Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010
     We reported net income attributable to Harvest of $90.8 million, or $2.28 diluted earnings per share, for the six months ended June 30, 2011, compared with net income attributable to Harvest of $24.3 million, or $0.65 diluted earnings per share, for the six months ended June 30, 2010.
     Total expenses and other non-operating (income) expense from continuing operations (in millions):
                         
    Six Months Ended    
    June 30,   Increase
    2011   2010   (Decrease)
Depreciation and amortization
  $ 0.2     $ 0.2     $  
Exploration expense
    5.8       2.7       3.1  
General and administrative
    13.1       10.8       2.3  
Taxes other than on income
    0.7       0.5       0.2  
Investment earnings and other
    (0.4 )     (0.3 )     (0.1 )
Interest expense
    3.9       1.1       2.8  
Loss on extinguishment of debt
    9.7             9.7  
Other non-operating expense
    0.7             0.7  
Loss on exchange rates
          1.6       (1.6 )
Income tax expense
    0.5       0.1       0.4  
     During the six months ended June 30, 2011, we incurred $2.3  million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, $0.2 million related to other general business development activities, and $3.3 million of impairment for the carrying value of West Bay (see Notes to Consolidated Financial Statements, Note 10 — United States Operations, Gulf Coast). During the six months ended June 30, 2010, we incurred $2.2 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations and $0.5 million related to other general business development activities.
     General and administrative costs were higher in the six months ended June 30, 2011 compared to the six months ended June 30, 2010 primarily due to higher employee related costs ($1.9 million), general corporate overhead costs ($0.3 million) and travel expenses ($0.2 million) offset by lower public relations costs ($0.1 million). The employee related cost increase includes $0.4 million of special consideration bonuses related to the sale of our Antelope Project. Taxes other than on income for the six months ended June 30, 2011 were higher compared to the six months ended June 30, 2010, primarily due to higher payroll and other taxes.

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     Investment earnings and other were higher in the six months ended June 30, 2011 compared to the six months ended June 30, 2011 due to receipt of payment for transition services provided on the Antelope Project after closing of the sale. Interest expense was higher for the six months ended June 30, 2011 compared to the six months ended June 30, 2010 due to the interest associated with our $32 million convertible debt offering in February 2010, our $60 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 $1.0 million. During the six months ended June 30, 2011, we incurred a loss on extinguishment of debt related to early payment of our $60 million term loan facility. The loss on extinguishment of debt includes the write off of the discount on debt ($7.2 million), a prepayment premium of 3.5 percent of the amount outstanding ($2.1 million), expensing of financing costs related to the term loan facility ($0.3 million), and the cost to repurchase 4.4 million unvested warrants issued in connection with the term loan facility (see Notes to Consolidated Financial Statements, Note 4 — Long-Term Debt).
     Loss on exchange rates is lower for the six months ended June 30, 2011 compared to the six months ended June 30, 2010 due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. There was no Bolivar/U.S. Dollar exchange rate devaluations in the six months ended June 30, 2011. Other non-operating expense was higher in the six months ended June 30, 2011 compared to the six months ended June 30, 2010 due to costs incurred related to our on-going strategic alternative process and evaluation. For the six months ended June 30, 2011, income tax expense was higher compared with that of the six months ended June 30, 2010, due to income tax assessed in the Netherlands on an increase in interest income offset by a U.S. tax refund received in the six months ended June 30, 2010.
     For the six months ended June 30, 2011, net income from unconsolidated equity affiliates reflects an increase in Petrodelta’s revenue from oil sales due to higher sales volumes and prices which was partially offset by the amended Windfall Profits Tax. Operating expense and workovers increased in the six months ended June 30, 2011 compared to the six months ended June 30, 2010 due to increased oil production and having a workover rig on location. Petrodelta did not have a workover rig during the six months ended June 30, 2010. Gain on exchange rates decreased in the six months ended June 30, 2011 compared to the six months ended June 30, 2010 due to there not being any Bolivar/U.S. Dollar currency exchange rate devaluations during the current period. There was a Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. Petrodelta’s effective tax rate for the six months ended June 30, 2011 decreased compared to effective tax rate for the six months ended June 30, 2010 due to the tax effects of the currency devaluation in the six months ended June 30, 2010.
     We recorded a $1.4 million gain on the sale of our equity affiliate, Fusion, during the six months ended June 30, 2011.
Discontinued Operations
     On May 17, 2011, we closed the transaction to sell our Antelope Project. (See Notes to Consolidated Financial Statements, Note 3 - Dispositions and Note 9 — United States Operations, Western United States — Antelope.) The sale has an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale of $103.9 million is reported in the second quarter of 2011.
     Revenue and net income on discontinued operations for the six months ended June 30, 2011 and 2010 are shown in the table below:
                 
    Six Months Ended
    June 30,
    2011   2010
    (in thousands)
Revenue applicable to discontinued operations
  $ 6,488     $ 6,038  
Net income from discontinued operations
  $ 95,947     $ 2,818  
     Net income from discontinued operations for the six months ended June 30, 2011 includes $1.4 million for impairment of inventory from cost to market, $3.6 million for employee severance and special accomplishment bonuses, and $5.2 million of U.S. income tax related to the sale of our Antelope Project. Severance costs for key employees include $0.5 million of restricted stock units which was paid in July 2011. Severance costs for key employees also include 58,000 stock appreciation rights (“SAR”) granted at an exercise price of $4.595 per right. These SARs are exercisable by the key employee for up to one year after termination.
     Net income from discontinued operations for

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the six months ended June 30, 2011 and 2010 also includes a revision of approximately $0.4 million and $0.3 million, respectively, of general and administrative expense related to the sale of our Antelope Project. These revisions did not impact consolidated net income for the three months ended March 31, 2011 and 2010, and we concluded the adjustments were not material to our Quarterly Report on Form 10-Q for the three months ended March 31, 2011.
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 minimal for the six months ended June 30, 2011 and $1.6 million for the six months ended June 30, 2010. 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 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, during the six months ended June 30, 2011, Harvest Vinccler exchanged approximately $0.4 million through SITME and received an average 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 lia bilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Petrodelta does not have, and has not had, any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate. Harvest Vinccler currently does not have any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate.
     Within the United States and other countries in which we conduct business, inflation has had a minimal effect on us, but it is potentially an important factor with respect to results of operations in Venezuela.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk
     We are exposed to market risk from adverse changes of the situation in Venezuela, our recently initiated exploration program and adverse changes in oil prices, interest rates, foreign exchange and political risk, as discussed in our Annual Report on Form 10-K for the year ended December 31, 2010. The information about market risk for the six months ended June 30, 2011 does not differ materially from that discussed in the Annual Report on Form 10-K for the year ended December 31, 2010.
Item 4. Controls and Procedures
     Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures that are designed to ensure the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
     Based on their evaluation as of June 30, 2011, 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.
     Changes in Internal Control over Financial Reporting. There have been no changes in our internal control over financial reporting during our most recent quarter ended June 30, 2011, that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION
Item 1. Legal Proceedings
     On May 31, 2011, the United Kingdom branch of our subsidiary, Harvest Natural Resources, Inc. (UK), initiated a wire transfer of approximately $1.1 million ($0.7 million net to our 66.667 percent interest) intending to pay Libya Oil Gabon S.A. (“LOGSA”) for fuel that LOGSA supplied to our subsidiary in the Netherlands, Harvest Dussafu, B.V., for the company’s drilling operations in Gabon. On June 1, 2011, our bank notified us that it had been required to block the payment in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”), because the payee, LOGSA, may be a blocked party under the sanctions. The bank further advised us that it could not release the funds to the payee or return the funds to us unless we obtain authorization from OFAC.
     On June 30, 2011, we filed a voluntary self-disclosure with OFAC to report that we had possibly violated the U.S. sanctions by attempting to remit funds to LOGSA. We concurrently applied for a license with OFAC that would authorize us to pay LOGSA for the fuel provided. We are unable, at this time, to predict when a license may be granted, if at all. We also intend to file an application with OFAC for return of the blocked funds to us. Unless that application is approved, the funds will remain in the blocked account, and we can give no assurance when, or if, OFAC will permit the funds to be released. In addition, we owe this supplier approximately $0.7 million ($0.5 million net to our 66.667 percent interest) in additional payments that we are unable to remit unless we are authorized to do so. We are also investigating to what extent payments to LOGSA can be made under European Union sanctions.
     If it is found that we violated the U.S. sanctions, such sanctions may be punishable by civil penalties, including fines, denial of export privileges, injunctions, asset seizures, debarment from government contracts and revocations or restrictions of licenses, as well as criminal fines and imprisonment. Although we are unable to estimate the amount or range of any possible losses resulting from this matter, we do not believe that this matter will have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
     See our Annual Report on Form 10-K for the year ended December 31, 2010 for a description of certain other legal proceedings. There have been no material developments in such legal proceedings since the filing of such Annual Report.
Item 1A. Risk Factors
     See our Annual Report on Form 10-K for the year ended December 31, 2010 under Item 1A Risk Factors for a description of risk factors. There have been no material developments in such risk factors since the filing of such Annual Report.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
     None.
Item 3. Defaults Upon Senior Securities
     None.
Item 6. Exhibits
(a)   Exhibits
  3.1   Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1(i) to our Form 10-Q filed on August 13, 2002, File No. 1-10762.)

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  3.2   Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on April 23, 2007,
File No. 1-10762.)
 
  4.1   Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.1 to our Form 10-K filed on March 17, 2008, File No. 1-10762.)
 
  4.2   Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.)
 
  4.3   Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A filed on October 23, 2007, File No. 1-10762.)
 
  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.)
 
  10.1   Separation agreement dated July 5, 2011 between Harvest Natural Resources, Inc. and G. Michael Morgan.
 
  10.2   Separation agreement dated July 5, 2011 between Harvest Natural Resources, Inc. and Patrick R. Oenbring.
 
  10.3   Consulting agreement dated July 9, 2011 between Harvest Natural Resources, Inc. and G. Michael Morgan.
 
  31.1   Certification of the principal executive officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
  31.2   Certification of the principal financial officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
  32.1   Certification accompanying Quarterly Report on Form 10-Q 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 Quarterly Report on Form 10-Q 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.
 
      101.INS XBRL Instance Document
 
      101.SCH XBRL Schema Document
 
      101.CAL XBRL Calculation Linkbase Document
 
      101.LAB XBRL Label Linkbase Document
 
      101.PRE XBRL Presentation Linkbase Document

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SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  HARVEST NATURAL RESOURCES, INC.
 
 
Dated: August 9, 2011  By:   /s/James A. Edmiston    
    James A. Edmiston   
    President and Chief Executive Officer   
 
Dated: August 9, 2011  By:   /s/ Stephen C. Haynes    
    Stephen C. Haynes   
    Vice President — Finance, Chief Financial
Officer and Treasurer 
 

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Exhibit Index
     
Exhibit    
Number   Description
3.1
  Amended and Restated Certificate of Incorporation (Incorporated by reference to Exhibit 3.1(i) to our Form 10-Q filed on August 13, 2002, File No. 1-10762).
 
   
3.2
  Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on April 23, 2007, File No. 1-10762.)
 
   
4.1
  Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.1 to our Form 10-K filed on March 17, 2008. File No. 1-10762.)
 
   
4.2
  Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.)
 
   
4.3
  Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A filed on October 23, 2007,
File No. 1-10762.)
 
   
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.)
 
   
10.1
  Separation agreement dated July 5, 2011 between Harvest Natural Resources, Inc. and G. Michael Morgan.
 
   
10.2
  Separation agreement dated July 5, 2011 between Harvest Natural Resources, Inc. and Patrick R. Oenbring.
 
   
10.3
  Consulting agreement dated July 9, 2011 between Harvest Natural Resources, Inc. and G. Michael Morgan.
 
   
31.1
  Certification of the principal executive officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2
  Certification of the principal financial officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1
  Certification accompanying Quarterly Report on Form 10-Q 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 Quarterly Report on Form 10-Q 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.
 
   
101.INS
  XBRL Instance Document
 
   
101.SCH
  XBRL Schema Document
 
   
101.CAL
  XBRL Calculation Linkbase Document
 
   
101.LAB
  XBRL Label Linkbase Document
 
   
101.PRE
  XBRL Presentation Linkbase Document
 
   

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