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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 March 31, 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
(State or Other Jurisdiction of Incorporation or Organization)
  77-0196707
(IRS Employer Identification No.)
     
1177 Enclave Parkway, Suite 300    
Houston, Texas
(Address of Principal Executive Offices)
  77077
(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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a smaller reporting company. See the definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large Accelerated Filer o   Accelerated Filer þ   Non-Accelerated Filer o   Smaller Reporting Company o
        (Do not check if a smaller reporting company)    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ
At April 29, 2011, 33,974,691 shares of the Registrant’s Common Stock were outstanding.
 
 

 


 

HARVEST NATURAL RESOURCES, INC.
FORM 10-Q
TABLE OF CONTENTS
         
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 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2

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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                 
    March 31,     December 31,  
    2011     2010  
    (in thousands)  
ASSETS
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 24,664     $ 58,703  
Restricted cash
    4,490        
Accounts and notes receivable, net:
               
Oil and gas revenue receivable
    3,724       1,907  
Dividend receivable — equity affiliate
    12,200        
Joint interest and other
    4,369       2,325  
Note receivable
    3,255       3,420  
Advances to equity affiliate
    1,852       1,706  
Assets held for sale (See Note 3)
    102,544       88,774  
Prepaid expenses and other
    2,193       4,793  
 
           
TOTAL CURRENT ASSETS
    159,291       161,628  
OTHER ASSETS
    2,293       2,477  
INVESTMENT IN EQUITY AFFILIATES
    292,564       287,933  
PROPERTY AND EQUIPMENT:
               
Oil and gas properties (successful efforts method)
    46,589       34,679  
Other administrative property
    3,250       3,209  
 
           
 
    49,839       37,888  
Accumulated depletion, depreciation and amortization
    (1,805 )     (1,682 )
 
           
 
    48,034       36,206  
 
           
 
  $ 502,182     $ 488,244  
 
           
 
               
LIABILITIES AND EQUITY
               
CURRENT LIABILITIES:
               
Joint interest and royalty payable
  $ 1,771     $ 675  
Accounts payable, trade and other
    3,553       2,530  
Accounts payable — carry obligation
    4,910       8,395  
Accrued expenses
    24,284       15,087  
Liabilities held for sale (See Note 3)
    599       663  
Accrued interest
    237       896  
Income taxes payable
    283       72  
 
           
TOTAL CURRENT LIABILITIES
    35,637       28,318  
OTHER LONG-TERM LIABILITIES
    2,268       1,834  
LONG-TERM DEBT
    81,775       81,237  
COMMITMENTS AND CONTINGENCIES (See Note 6)
           
 
               
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 March 31, 2011 and December 31, 2010, respectively; issued 40,195 shares and 40,103 shares at March 31, 2011 and December 31, 2010, respectively
    401       401  
Additional paid-in capital
    231,890       230,362  
Retained earnings
    142,354       141,584  
Treasury stock, at cost, 6,475 shares at March 31, 2011 and December 31, 2010, respectively
    (65,543 )     (65,543 )
 
           
TOTAL HARVEST STOCKHOLDERS’ EQUITY
    309,102       306,804  
NONCONTROLLING INTEREST
    73,400       70,051  
 
           
TOTAL EQUITY
    382,502       376,855  
 
           
 
  $ 502,182     $ 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  
    March 31,  
    2011     2010  
    (in thousands, except per share data)  
EXPENSES
               
Depreciation and amortization
  $ 124     $ 101  
Exploration expense
    1,189       1,246  
General and administrative
    6,707       5,317  
Taxes other than on income
    349       300  
 
           
 
    8,369       6,964  
 
           
 
               
LOSS FROM OPERATIONS
    (8,369 )     (6,964 )
 
               
OTHER NON-OPERATING INCOME (EXPENSE)
               
Investment earnings and other
    145       131  
Interest expense
    (2,212 )     (416 )
Other non-operating expenses
    (431 )      
Loss on exchange rates
    (11 )     (1,527 )
 
           
 
    (2,509 )     (1,812 )
 
           
LOSS FROM CONSOLIDATED COMPANIES CONTINUING OPERATIONS BEFORE INCOME TAXES
    (10,878 )     (8,776 )
 
               
INCOME TAX EXPENSE (BENEFIT)
    222       (19 )
 
           
LOSS FROM CONSOLIDATED COMPANIES CONTINUING OPERATIONS
    (11,100 )     (8,757 )
 
               
NET INCOME FROM UNCONSOLIDATED EQUITY AFFILIATES
    18,104       38,367  
 
           
 
               
NET INCOME (LOSS) FROM CONTINUING OPERATIONS
    7,004       29,610  
 
       
DISCONTINUED OPERATIONS
    (2,885 )     2,315  
 
           
 
               
NET INCOME (LOSS)
    4,119       31,925  
 
       
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
    3,349       7,335  
 
           
 
       
NET INCOME ATTRIBUTABLE TO HARVEST
  $ 770     $ 24,590  
 
           
 
               
NET INCOME ATTRIBUTABLE TO HARVEST PER COMMON SHARE
(See Note 2 – Summary of Significant Accounting Policies, Earnings Per Share):
               
Basic
  $ 0.02     $ 0.74  
 
           
Diluted
  $ 0.02     $ 0.64  
 
           
See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                 
    Three Months Ended March 31,  
    2011     2010  
    (in thousands)  
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net Income
  $ 4,119     $ 31,925  
Adjustments to reconcile net income to net cash used in operating activities:
               
Depletion, depreciation and amortization
    934       566  
Impairment of long-lived assets
    1,440        
Amortization of debt financing costs
    270       108  
Amortization of discount on debt
    538        
Net income from unconsolidated equity affiliates
    (18,104 )     (38,367 )
Non-cash compensation related charges
    1,114       853  
Changes in Operating Assets and Liabilities:
               
Accounts and notes receivable
    (3,696 )     4,616  
Advances to equity affiliate
    (146 )     1,066  
Prepaid expenses and other
    2,600       350  
Revenue and royalty payable
    1,096       134  
Accounts payable
    1,023       1,405  
Accrued expenses
    2,071       423  
Accrued interest
    (925 )     (4,383 )
Other long-term liabilities
    434       370  
Income taxes payable
    211       (490 )
 
           
NET CASH USED IN OPERATING ACTIVITIES
    (7,021 )     (1,424 )
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Additions of property and equipment
    (8,361 )     (13,495 )
Additions to assets held for sale
    (15,633 )      
Proceeds from sale of equity affiliates
    1,273        
Increase in restricted cash
    (4,490 )     (1,000 )
Investment costs
    (34 )     (1,656 )
 
           
NET CASH USED IN INVESTING ACTIVITIES
    (27,245 )     (16,151 )
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Net proceeds from issuances of common stock
    416        
Proceeds from issuance of long-term debt
          32,000  
Financing costs
    (189 )     (2,627 )
 
           
NET CASH PROVIDED BY FINANCING ACTIVITIES
    227       29,373  
 
           
 
               
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    (34,039 )     11,798  
 
               
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    58,703       32,317  
 
           
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 24,664     $ 44,115  
 
           
Supplemental Schedule of Noncash Investing and Financing Activities:
     During the three months ended March 31, 2010, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 20,831 shares being added to treasury stock at cost.
See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2011 and 2010 (unaudited)
Note 1 — Organization
Interim Reporting
     In our opinion, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position as of March 31, 2011, and the results of operations and cash flows for the three months ended March 31, 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. Petrodelta is governed by its own charter and bylaws and operates a portfolio of properties in eastern Venezuela including large proven oil fields as well as properties with substantial opportunities for both development and exploration. HNR Finance has a direct controlling interest in Harvest Vinccler S.C.A. (“Harvest Vinccler”). Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with Petroleos de Venezuela S.A. (“PDVSA”). We do not have a business relationship with Vinccler outside of Venezuela.
     In addition to our interests in Venezuela, we have exploration acreage in the Gulf Coast Region of the United States, mainly onshore in West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in the Sultanate of Oman (“Oman”), and offshore of the People’s Republic of China (“China”). Until March 1, 2011, pending closing of the sale for our Utah Operations (see Note 3 – Dispositions), we had developed acreage in the Antelope project in the Western United States in the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”) and Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) where we had established production. See Note 10 – United States, Note 11 – Indonesia, Note 12 – Gabon and Note 13 – Oman and Note 14 – China.
Note 2 — Summary of Significant Accounting Policies
Principles of Consolidation
     The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. All intercompany profits, transactions and balances have been eliminated.

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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 into U.S. Dollars, and all currency gains or losses are recorded in the consolidated statement of operations. We attempt to manage our operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence.
     On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Venezuelan Bolivars (“Bolivars”) per U.S. Dollar exchange rate for purchases, the 2.5935 Bolivars per U.S. Dollar exchange rates for the sale of foreign currency, and the Central Bank’s entitlement to require the sale of foreign currency at specific rates with an effective date of January 1, 2011. The elimination of the 2.60 Bolivars per U.S. Dollar exchange rate for purchases is not expected to have an impact on our business in Venezuela. Since all sales of foreign currency will be at the 4.2893 Bolivars per U.S. Dollar exchange rate, we will not be required to pay a financing fee resulting from blended exchange rates for the purchase of foreign currency.
     In May 2010, the government of Venezuela established the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) for exchanging Bolivars. SITME’s purpose is to assist companies and individuals requiring foreign currency (U.S. Dollars) for the import of goods and services into Venezuela. SITME may also be used for buying or selling of Venezuela’s bonds. The establishment of SITME has not had, nor is it expected to have, an impact on our business in Venezuela.
     Harvest Vinccler does 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 three months ended March 31, 2011, Harvest Vinccler exchanged approximately $0.3 million through SITME and received an average exchange rate of 5.18 Bolivars per U.S. Dollar. During the three months ended March 31, 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 March 31, 2011, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 3.0 million and BsF 3.5 million, respectively.
     See Note 9 – Investment in Equity Affiliates – Petrodelta, S.A. for a discussion on the effects of the exchange agreements on Petrodelta’s business.
Revenue Recognition
     We record revenue for our U.S. oil and natural gas operations when we deliver our production to the customer and collectability is reasonably assured. Revenues from the production of oil and natural gas on properties in which we have joint ownership are recorded under the sales method. Differences between these sales and our entitled share of production are not significant.
Cash and Cash Equivalents
     Cash equivalents include money market funds and short term certificates of deposit with original maturity dates of less than three months.
Restricted Cash
     Restricted cash is classified as current or non-current based on the terms of the agreement. Restricted cash at March 31, 2011 represents cash held in a U.S. bank used as collateral for a standby letter of credit issued in support of the contract for the drilling unit to be used to drill the Ruche Marin-A exploratory well on the Dussafu Marin Permit (“Dussafu PSC”) (see Note 12 – Gabon).

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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 March 31, 2011 and December 31, 2010 consisted of $32 million of fixed-rate unsecured senior convertible notes maturing in 2013 unless earlier redeemed, purchased or converted and $60 million of fixed-rate unsecured term loan facility maturing in 2012.
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 March 31, 2011 and December 31, 2010, note receivable plus accrued interest was approximately $3.3 million and $3.4 million, respectively, and considered to be fully recoverable. With the recent announcement of the sale of our Antelope project, it is expected that the note receivable plus accrued interest will be settled upon closing of the announced sale transaction.
Other Assets
     At March 31, 2011, other assets consist of investigative costs of $0.3 million associated with new business development projects and deferred financing costs of $2.0 million. The investigative costs are reclassified to oil and natural gas properties or expensed depending on management’s assessment of the likely outcome of the project. During the three months ended March 31, 2011, no investigative costs related to new business development were reclassified to exploration expense. 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.
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 March 31, 2011 and December 31, 2010, there were no events that caused us to evaluate our investment in Petrodelta for impairment.
Property and Equipment
     We use the successful efforts method of accounting for oil and gas properties.

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Suspended Exploratory Drilling Costs
Mesaverde
     At March 31, 2011 and December 31, 2010, assets held for sale included capitalized suspended exploratory drilling costs of $16.5 million. The $16.5 million of suspended exploratory drilling costs relates to drilling in the Mesaverde formation in the Bar F #1-20-3-2 (“Bar F”). The Mesaverde Gas Exploration and Appraisal Project (“Mesaverde”) targeted the Mesaverde formation in the Uintah Basin of Utah. Testing focused on the evaluation of the natural gas potential of the Mesaverde tight gas reservoir over a prospective interval from 14,000 to 17,400 feet. While the results to date have not definitively determined the commerciality of stand-alone development of the Mesaverde in the current gas price environment, we believe that the test results confirm that the Mesaverde formation exhibits sufficient quantities of hydrocarbons and reservoir over-pressure to justify potential development. See Note 10 – United States Operations, Western United States – Antelope.
Budong PSC
     At March 31, 2011, oil and gas properties included capitalized suspended exploratory drilling costs of $13.2 million related to drilling in the Budong-Budong Production Sharing Contract (“Budong PSC”) of the Lariang-1 (“LG-1”) well. 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 operations 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 11 – 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 months ended March 31, 2011, we capitalized interest costs of $0.8 million for qualifying oil and gas property additions. During the three months ended March 31, 2010, we did not capitalize any interest cost.
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 March 31, 2011 and December 31, 2010, cash and cash equivalents include $14.9 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 March 31, 2011 and December 31, 2010 was $62.3 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 March 31, 2011 and December 31, 2010 was $49.8 million and $49.2 million, respectively.
     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 notes 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 March 31,

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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.
                 
    March 31,     December 31,  
    2011     2010  
    (in thousands)  
Financial assets:
               
Beginning balance
  $ 3,420     $ 3,265  
Issuances
          200  
Accrued interest
    157       398  
Payments
    (322 )     (443 )
 
           
Ending balance
  $ 3,255     $ 3,420  
 
           
 
               
Financial liabilities:
               
Beginning balance
  $ 49,237     $  
Debt issuance
          60,000  
Discount on debt
          (11,122 )
Amortization of discount on debt
    538       359  
 
           
Ending balance
  $ 49,775     $ 49,237  
 
           
Asset Retirement Liability
     The accounting for asset retirement obligations standard requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. No wells were abandoned during the three months ended March 31, 2011 or the year ended December 31, 2010. Changes in asset retirement obligations during the three months ended March 31, 2011 and the year ended December 31, 2010 were as follows:
                 
    March 31,     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 liabilities held for sale
    (599 )      
 
           
Asset retirement obligations end of period
  $     $ 663  
 
           
Noncontrolling Interests
     Changes in noncontrolling interest during the three months ended March 31, 2011 and 2010 were as follows:
                 
    March 31,     March 31,  
    2011     2010  
    (in thousands)  
Balance at beginning of period
  $ 70,051     $ 57,406  
Net income attributable to noncontrolling interest
    3,349       7,335  
 
           
Balance at end of period
  $ 73,400     $ 64,741  
 
           

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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.
                                 
    Three Months Ended March 31,  
    2011     2010  
    Basic     Diluted     Basic     Diluted  
    (in thousands, except per share data)  
Income (loss) from continuing operations(a)
  $ 3,655     $ 3,655     $ 22,275     $ 22,275  
Discontinued operations
    (2,885 )     (2,885 )     2,315       2,315  
 
                       
Net income (loss) attributable to Harvest
  $ 770     $ 770     $ 24,590     $ 24,590  
 
                       
Weighted average common shares outstanding
    33,945       33,945       33,274       33,274  
Effect of dilutive securities
          4,555             5,148  
 
                       
Weighted average common shares, Including dilutive effect
    33,945       38,500       33,274       38,422  
 
                       
Per share:
                               
Income (loss) from continuing operations(a)
  $ 0.11     $ 0.09     $ 0.67     $ 0.58  
Discontinued operations
  $ (0.09 )   $ (0.07 )   $ 0.07     $ 0.06  
Net income (loss) attributable to Harvest
  $ 0.02     $ 0.02     $ 0.74     $ 0.64  
 
(a)   Excludes net income attributable to noncontrolling interest.
     The per share calculations above exclude 0.2 million and 3.2 million options because their exercise price exceeded the average stock price for the three months ended March 31, 2011 and 2010, respectively. The per share calculations above also exclude 5.6 million warrants because their exercise price exceeded the average price for the three months ended March 31, 2011. We did not have any warrants outstanding during the three months ended March 31, 2010.
     Stock options of 41,666 were exercised in the three months ended March 31, 2011 resulting in cash proceeds of $0.4 million. No stock options were exercised in the three months ended March 31, 2010.
Reclassifications
     Certain items in 2010 have been reclassified to conform to the 2011 financial statement presentation.
Note 3 — Dispositions
Assets Held for Sale
     On March 22, 2011, we announced that we had entered into a definitive agreement to sell all of our oil and gas assets in Utah’s Uinta Basin (“Utah Operations”) for $215 million in cash. The sale has an effective date of March 1, 2011. The net proceeds from the sale are estimated to be $205 million after deduction for transaction related costs. Closing is expected to occur in May 2011 and the final sales price is subject to customary adjustments at closing at that time. We will provide transition services for a period of 60 days. The purchaser can cancel the transition services arrangement at any time by delivering to us five days written notice of the intent to cancel. We will not have any continuing involvement with the Utah operations except in the capacity of the transition services arrangement; therefore, the related estimated gain on the sale of approximately $100 million is expected to be reported in the second quarter of 2011. Accordingly, these operations have been classified as discontinued operations. The Utah assets and liabilities held for sale are reported in the consolidated balance sheet as follows:

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    March 31,     December 31,  
    2011     2010  
    (in thousands)  
Proved oil and gas properties
  $ 39,872     $ 31,037  
Unproved oil and gas properties
    62,672       57,737  
 
           
Total assets held for sale
  $ 102,544     $ 88,774  
 
           
 
               
Asset retirement liabilities
  $ 599     $ 663  
 
           
Total liabilities held for sale
  $ 599     $ 663  
 
           
     Revenue and pretax income on these dispositions are shown in the table below:
                 
    Three Months Ended March 31,
    2011   2010
    (in thousands)
Revenues applicable to discontinued operations
  $ 4,120     $ 3,124  
Pretax income (loss) from discontinued operations
  $ (2,885 )   $ 2,315  
     Pretax loss from discontinued operations for the three months ended March 31, 2011 includes $1.4 million for impairment of long-lived assets and $3.5 million for employee severance and special accomplishment bonuses related to the sale of our Utah Operations. Special accomplishment bonuses of $1.2 million directly relate to the sale of the Utah properties and will be paid at the closing of the sale. Employee severance costs of $0.8 million will be paid at closing, $0.7 million is expected to be paid by June 30, 2011, and $1.2 million is expected to be paid in January 2012.
Note 4 — Long-Term Debt
Long-Term Debt
     Long-term debt consists of the following:
                 
    March 31,     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       60,000  
 
           
 
    92,000       92,000  
 
               
Discount on term loan facility
               
See description below
    (10,225 )     (10,763 )
Less current portion
           
 
           
 
  $ 81,775     $ 81,237  
 
           
     On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. Under the terms of the notes, interest is payable semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2010. The senior convertible notes will mature on March 1, 2013, unless earlier redeemed, repurchased or converted. The notes are convertible into shares of our common stock at a conversion rate of 175.2234 shares of common stock per $1,000 principal amount of senior convertible notes, equivalent to a conversion price of approximately $5.71 per share of common stock. The notes are general unsecured obligations, ranking equally with all of our other unsecured senior indebtedness, if any, and senior in right of payment to any of our subordinated indebtedness, if any. The notes are also redeemable in certain circumstances at our option and may be repurchased by us at the purchaser’s option in connection with occurrence of certain events. Financing costs 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 was $1.7 million and $1.9 million at March 31, 2011 and December 31, 2010, respectively.

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     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 is paid on a monthly basis at the initial rate of 10 percent and will mature on October 28, 2012. The initial rate of interest increases to 15 percent on July 28, 2011, the Bridge Date. The Bridge Date may be extended at our option for three months by paying a fee to MSD Energy in the amount of five percent of the initial principal amount of the term loan facility. If the loan is repaid in whole or in part at any time before the Bridge Date, a prepayment premium of 3.5 percent of the amount prepaid plus accrued interest on the prepayment amount is required in addition to the prepayment. Financing costs associated with the term loan facility offering are being amortized over the remaining life of the loan and are recorded in other assets. The balance was $0.3 million at March 31, 2011 and December 31, 2010, respectively.
     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.
     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 is recorded as discount on debt with a corresponding credit to additional paid in capital. The discount on debt is being amortized over the life of the warrants.
Note 5 — 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-Budong Production Sharing Contract (“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 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 currently plan to fund this commitment in 2012, and we may be required to raise capital to do so. We also have minimum work commitments during the various phases of the exploration periods in the Budong PSC and Dussafu PSC.
     As a petroleum exploration and production company, our revenue, profitability, cash flows, and future rate of growth are substantially dependent on the condition of the oil and gas industry generally, our success with our exploration program, and the belief that Petrodelta will fund its own operations and continue to pay dividends. Because our revenues are generated from customers with the same economic interests, our operations are also susceptible to market volatility resulting from economic, cyclical, weather or other factors related to the energy industry. Changes in the level of operating and capital spending in the industry, decreases in oil or gas prices, or industry perceptions about future oil and gas prices could adversely affect our financial position, results of

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operations and cash flows. Based on our current level of cash flow from operations, we will be required to raise capital to meet our general and administrative costs and fund our oil and gas programs.
     Our primary source of cash is still dividends from Petrodelta and funding from debt financing. In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under International Financial Reporting Standards (“IFRS”) for the year ended December 31, 2009. We expect to receive future dividends from Petrodelta; however, we expect that in the near term Petrodelta will reinvest most of its earnings into the company in support of its drilling and appraisal activities. Therefore, there is uncertainty that Petrodelta will pay additional dividends in 2011 or 2012.
     Additionally, any dividend received from Petrodelta carries a liability to our non-controlling interest holder, Vinccler, for its 20 percent share. Dividends declared and paid by Petrodelta are paid to HNR Finance, our consolidated subsidiary. HNR Finance must declare a dividend in order for us and our non-controlling interest holder, Vinccler, to receive our respective shares of Petrodelta’s dividends. A dividend from HNR Finance is due upon demand. Currently, Vinccler has not demanded its respective share of the three most recent Petrodelta dividends and has waived such a demand until at least April 2012. As of March 31, 2011, Vinccler’s share of the undistributed dividends is $9.0 million inclusive of the unpaid November 2010 dividend. See Note 15 – Related Party Transactions.
     We incurred significant debt during 2010 which has imposed restrictions on us and increased our vulnerability to adverse economic and industry conditions. Our monthly and semi-annual interest expense has increased significantly, and our senior convertible notes and term loan facility impose new restrictions on us. Our senior convertible notes and term loan facility impose covenant restrictions on us that limit our ability to obtain additional financing. Our ability to meet these covenants is primarily dependent on meeting customary affirmative covenant clauses, including providing consolidated statements to be audited and accompanied by a report and opinion of an independent certified public accountant, which report and opinion shall not be subject to any “going concern” or like qualification. Our inability to satisfy the covenants contained in our long term debt arrangements would constitute an event of default, if not waived. An uncured default could result in our outstanding debt becoming immediately due and payable. If this were to occur, we may not be able to obtain waivers or secure alternative financing to satisfy our obligations, either of which would have a material adverse impact on our business. As of March 31, 2011 and December 31, 2010, we were in compliance with all of our long term debt covenants.
     At March 31, 2011, we had cash on hand of $24.7 million. On March 22, 2011, we announced that we had entered into a definitive agreement to sell all of our oil and gas assets in Utah’s Uinta Basin for $215 million in cash. Closing is expected to occur in May 2011, and the net proceeds from the sale are estimated to be $205 million after deduction for transaction related costs. We believe that this cash plus cash generated from Petrodelta dividends and funding from our prior debt financings combined with our ability to vary the timing of our capital expenditures is sufficient to fund our operations and capital commitments through at least March 31, 2012. However, if the sale of the Utah Operations is unsuccessful, we will be required to increase our liquidity to levels sufficient to fund our exploration program.
     In order to increase our liquidity to levels sufficient to meet our commitments, we are currently pursuing a number of actions including our ability to delay discretionary capital spending to future periods, possible farm-out or sale of assets, or other monetization of assets as necessary to maintain the liquidity required to run our operations. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, and cost reductions. However, there is no assurance that our plans will be successful. Although we believe that we will have adequate liquidity to meet our near term operating requirements and to remain compliant with the covenants under our long term debt arrangements, the factors described above create uncertainty. Our lack of cash flow and the unpredictability of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance adequate financing can be raised. Accordingly, there can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.

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Note 6 — Commitments and Contingencies
     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 the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims.
    Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim.
    Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims.
Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s, the Venezuelan income tax authority, interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.
     Libertador Municipality Tax Assessments. Harvest Vinccler has received five assessments from a tax inspector for the Libertador municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:
    One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Mayor’s Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. On April 10, 2008, the Tax Court suspended the case pending a response from the Mayor’s Office to the protest. If the municipality’s response is to confirm the assessment, Harvest Vinccler will defer to the competent Tax Court to enjoin and dismiss the claim.
    Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.
    Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.

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Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the refund of all municipal taxes paid since 2002.
     We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such litigation which will have a material adverse impact on our financial condition, results of operations and cash flows.
Note 7 — Taxes Other Than on Income
     The components of taxes other than on income were:
                 
    Three Months Ended  
    March 31,  
    2011     2010  
    (in thousands)  
Franchise Taxes
  $ 46     $ 61  
Payroll and Other Taxes
    303       239  
 
           
 
  $ 349     $ 300  
 
           
Note 8 — Operating Segments
     We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Operations included under the heading “United States and Other” include U.S. operations, corporate management, cash management, business development and financing activities performed in the United States and other countries which do not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the United States and Other segment and are not allocated to other operating segments:
                 
    Three Months Ended  
    March 31,  
    2011     2010  
    (in thousands)  
Operating Segment Income (Loss)
               
Venezuela
  $ 16,362     $ 36,490  
Indonesia
    (1,413 )     (1,279 )
United States and other
    (11,294 )     (12,936 )
Discontinued operations (Utah Operations)
    (2,885 )     2,315  
 
           
Net income (loss)
  $ 770     $ 24,590  
 
           
                 
    March 31,     December 31,  
    2011     2010  
    (in thousands)  
Operating Segment Assets
               
Venezuela
  $ 296,314     $ 292,023  
Indonesia
    45,157       16,254  
United States and other
    115,849       140,744  
Net assets held for sale (Utah Operations)
    102,544       88,774  
 
           
 
    559,864       537,795  
Intersegment eliminations
    (57,682 )     (49,551 )
 
           
 
  $ 502,182     $ 488,244  
 
           

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Note 9 — Investment in Equity Affiliates
Petrodelta, S.A.
     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 budget is expected to be approximately $220 million for Petrodelta’s 2011 business plan. The 2011 budget is still pending shareholder approval.
     As discussed in previous filings, 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 (“Windfall Profits Tax”). The 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 Windfall Profits Tax is being applied to gross oil production delivered to PDVSA. The Windfall Profits Tax established a special 50 percent tax to the Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar manner, the percentage is increased from 50 percent to 60 percent when the average price of the VEB exceeds $100 per barrel. The Windfall Profits Tax is reported as taxes other than on income on the income statement of Petrodelta and is deductible for Venezuelan tax purposes. Petrodelta recorded $27.1 million and $1.3 million of expense for the Windfall Profits Tax during the three months ended March 31, 2011 and 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

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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. The dividend represents the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under IFRS for the year ended December 31, 2009.
     On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement with an effective date of January 1, 2011. See Note 2 — Summary of Significant Accounting Policies, Reporting and Functional Currency. 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 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 March 31, 2011, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 106.2 million and BsF 1,902.1 million, respectively.
     Petrodelta’s reporting and functional currency is the U.S. Dollar. HNR Finance owns a 40 percent interest in Petrodelta. Petrodelta’s financial information is prepared in accordance with IFRS which we have adjusted to conform to GAAP. All amounts through Net Income Equity Affiliate represent 100 percent of Petrodelta. Summary financial information has been presented below at March 31, 2011 and December 31, 2010 and for the three months ended March 31, 2011 and 2010:

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    Three Months     Three Months  
    Ended     Ended  
    March 31,     March 31,  
    2011     2010  
    (in thousands)  
Revenues:
               
Oil sales
  $ 226,613     $ 141,502  
Gas sales
    726       1,018  
Royalty
    (77,315 )     (47,986 )
 
           
 
    150,024       94,534  
 
               
Expenses:
               
Operating expenses
    14,282       10,043  
Workovers
    6,475        
Depletion, depreciation and amortization
    12,487       8,607  
General and administrative
    (930 )     3,417  
Windfall profits tax
    27,126       1,251  
 
           
 
    59,440       23,318  
 
           
 
               
Income from operations
    90,584       71,216  
 
               
Gain on exchange rate
          118,716  
Investment Earnings and Other
    167       2,894  
Interest expense
    (1,272 )     (895 )
 
           
 
               
Income before Income Tax
    89,479       191,931  
 
               
Current income tax expense
    53,343       85,420  
Deferred income tax expense (benefit)
    (25,762 )     42,464  
 
           
Net Income
    61,898       64,047  
Adjustment to reconcile to reported Net Income from Unconsolidated Equity Affiliate:
               
Deferred income tax expense (benefit)
    18,563       (32,989 )
 
           
Net Income Equity Affiliate
    43,335       97,036  
Equity interest in unconsolidated equity affiliate
    40 %     40 %
 
           
Income before amortization of excess basis in equity affiliate
    17,334       38,814  
Amortization of excess basis in equity affiliate
    (421 )     (334 )
Conform depletion expense to GAAP
    (81 )     (113 )
 
           
Net income from unconsolidated equity affiliate
  $ 16,832     $ 38,367  
 
           
                 
    March 31,     December 31,  
    2011     2010  
    (in thousands)  
Current assets
  $ 704,681     $ 535,225  
Property and equipment
    345,191       321,816  
Other assets
    84,501       67,755  
Current liabilities
    583,225       406,339  
Other liabilities
    40,568       39,224  
Net equity
    510,580       479,233  
Fusion Geophysical, LLC
     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 $1.3 million for our equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full of the outstanding balance of the prepaid service agreement, short term loan and accrued interest. The Agreement and Plan of Merger includes an Earn Out provision wherein we would receive an additional payment of up to a maximum of $2.7 million if FusionGeo, Inc.’s 2011 gross profit exceeds $5.6 million. The Earn Out payment will not be determined until early in 2012. We can give no assurance that we will receive any Earn Out payment.

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     Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering. Our minority equity investment in Fusion was accounted for using the equity method of accounting. Operating revenue and total assets represent 100 percent of Fusion. No dividends were declared or paid during the three months ended March 31, 2011 and 2010, respectively. Summarized financial information for Fusion follows. Due to the sale of Fusion on January 28, 2011, the operating results shown for the three months ended March 31, 2011 reflect only January 2011 results, corresponding to date of sale.
                 
    Three Months     Three Months  
    Ended     Ended  
    March 31,     March 31,  
    2011     2010  
    (in thousands)  
Operating Revenues
  $ 678     $ 2,836  
 
           
 
               
Net Loss
  $ (197 )   $ (839 )
Equity interest in unconsolidated equity affiliate
    49 %     49 %
 
           
Net loss from unconsolidated equity affiliate
  $ (97 )   $ (411 )
 
           
         
    December 31,  
    2010  
    (in thousands)  
Current assets
  $ 1,925  
Total assets
    23,780  
Current liabilities
    7,447  
Total liabilities
    7,479  
     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 three months ended March 31, 2011 and 2010 as doing so would have caused our equity investment to go into a negative position. However, we have recognized a $1.3 million gain on the sale of Fusion in the three months ended March 31, 2011.
     Approximately 25.0 percent of Fusion’s revenue for the three months ended March 31, 2010 was earned from Harvest or equity affiliates.
Note 10 — United States Operations
     In 2008, we initiated a domestic exploration program in two different basins. We are the operator of both exploration programs and complemented our existing personnel with the addition of highly experienced management and technical personnel.
Gulf Coast
     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.
West Bay Project
     In February 2011, the previously existing Alligator Point Unit (as approved by the Texas General Land Office [“GLO”]) expired. We have obtained from the GLO an extension until September 1, 2011 of a smaller version of the Alligator Point Unit defined more specifically by the drilling prospects currently existing on the project. As a result of the GLO approval of the smaller Alligator Point Unit and the anticipated expiry of five leases previously held by the larger unit, we expect our lease position on the West Bay project to be reduced from approximately 13,000 acres in February 2011 to approximately 10,050 acres in August 2011.
     The West Bay project represents $3.3 million of unproved oil and gas properties on our March 31, 2011 and December 31, 2010 balance sheets, respectively.

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Western United States — Antelope
     On March 22, 2011, we announced that we had entered into a definitive agreement to sell all of our oil and gas assets in Utah’s Uinta Basin (see Note 3 — Dispositions). The oil and gas assets are located in our Antelope project area in the Uinta Basin of Utah and consist of approximately 69,000 gross acres (47,600 net acres). The transaction includes the Mesaverde project, the Lower Green River/Upper Wasatch project and the Monument Butte Extension project. We owned an approximate working interest of 70 percent in the Mesaverde and Lower Green River/Upper Wasatch projects, 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.
     In July 2010, we executed a farm-out agreement with the private third party in the Joint Exploration and Development Agreement (“JEDA”) for the acquisition of an incremental 10 percent interest in the Antelope Project with an effective date of July 1, 2010. This acquisition increased our ownership in the Antelope project to 70 percent. Total consideration for the incremental 10 percent interest was $20.0 million, of which (1) $3.0 million was paid on August 2, 2010 (the closing date of the acquisition); (2) $3.0 million to be used as a credit against future joint interest billings, the balance of which was paid on October 15, 2010; and (3) a capped $14.0 million carry of a portion of our partner’s exploration and development cost obligations in the Lower Green River/Upper Wasatch and Monument Butte Extension drilling programs in the Antelope project. At March 31, 2011, the outstanding balance on the $14.0 million exploration and development cost obligation carry is $4.9 million. Due to the recent announcement of the sale of our Antelope project, the balance of the carry obligation will be settled in cash from the sales proceeds upon closing of the announced sale transaction.
     The Antelope project represents $39.9 million and $62.7 million of proved and unproved oil and gas properties held for sale on our March 31, 2011 balance sheet and $31.0 million and $57.7 million of proved and unproved oil and gas properties held for sale on our December 31, 2010 balance sheet.
     The Antelope project was targeted to explore for and develop oil and natural gas from three prospective reservoir horizons in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties.
Mesaverde
     The Mesaverde is the first prospective horizon in the Antelope project. Exploratory drilling costs for the Mesaverde have been suspended pending further evaluation (see Note 2 — Summary of Significant Accounting Policies, Suspended Exploratory Drilling Costs, Mesaverde).
Lower Green River/Upper Wasatch
     The Lower Green River/Upper Wasatch is the second prospective horizon that was being pursued in the Antelope project. After the initial oil discovery in this project in the Bar F announced in first quarter 2010, a five well Lower Green River/Upper Wasatch delineation and development drilling program was initiated in the third quarter of 2010. The delineation and development program was later expanded to include a sixth well. As of March 31, 2011, six wells were producing from this project. The seventh well, the Evans #1-4-3-3, commenced production on April 22, 2011.
Monument Butte
     The Monument Butte Extension is the third prospective horizon in the Antelope project. It was initiated in the fourth quarter of 2009 with an eight well appraisal and development drilling program to produce oil and natural gas from the Green River formation. As a follow up to the successful completion of the eight well program, a six well appraisal and development drilling program was approved in 2010. The six well expansion was on acreage immediately adjacent to the eight well program. These 14 wells in the Monument Butte Extension (as defined above) are non-operated, and we held a 43 percent working interest in the initial eight wells and an approximate 37 percent working interest in the follow-up six wells. All 14 of these wells were producing as of March 31, 2011.
     During 2010, an additional Harvest operated well, the K Moon #2-13-4-3, was added to the project. We had an approximate 60 percent working interest in the well. The K Moon #2-13-4-3 was producing on natural flow as of March 31, 2011.

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     Operational activities during 2011 for the Monument Butte Extension consisted of completion of the K Moon #2-13-4-3 and drilling and completion of the sixth and final well in the six-well follow-up program.
Note 11 — Indonesia
     In December 2007, we entered into a Farmout Agreement to acquire a 47 percent interest in the Budong PSC located mostly onshore West Sulawesi, Indonesia. In April 2008, the Government of Indonesia approved the assignment to us of the 47 percent interest in the Budong PSC. Our partner is the operator through the exploration phase as required by the terms of the Budong PSC, and we have an option to become operator, if approved by the Government of Indonesia and BPMIGAS, Indonesia’s oil and gas regulatory authority, in any subsequent development and production phase.
     We acquired our original 47 percent interest in the Budong PSC by committing to fund the first phase of the exploration program up to a cap of $17.2 million, including the acquisition of 2-D seismic and drilling of the first two exploration wells under a Farmout Agreement with our partner in the Budong PSC. Prior to drilling the first exploration well, our partner had a one-time option to increase the level of the carried interest to a maximum of $20.0 million. On September 15, 2010, our partner exercised their option to increase the carry obligation by $2.7 million to a total of $19.9 million. The additional carry increased our ownership by 7.4 percent to 54.4 percent. On March 3, 2011, the Government of Indonesia and BPMIGAS approved this change in ownership interest.
     On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator to a third party, which has allowed us to acquire an additional 10 percent equity in the Budong PSC at a cost of $3.7 million payable ten business days after completion of the first exploration well. Closing of this acquisition, which is subject to the approval of the Government of Indonesia and BPMIGAS, will increase our interest in the Budong PSC to 64.4 percent. The $3.7 million was paid on April 18, 2011.
     Operational activities during the three months ended March 31, 2011 focused on drilling of the first exploratory well, the Lariang-1 (“LG-1”), which spud on January 6, 2011, and well planning and construction of the second exploratory well site. The LG-1 was drilled to a total depth of 5,311 feet and encountered multiple hydrocarbon shows and overpressure in Miocene formations requiring up to 16.5 pound per gallon mud. 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 to the decision to discontinue operations 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. At March 31, 2011, exploratory drilling costs of $13.2 million had been expended for the drilling of the LG-1. These costs have been suspended pending further evaluation and appraisal (see Note 2 — Summary of Significant Accounting Policies — Suspended Exploratory Drilling Costs, Budong PSC). The Budong PSC represents $22.8 million and $10.9 million of unproved oil and gas properties on our March 31, 2011 and December 31, 2010 balance sheets, respectively.
Note 12 — 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 exploration phase of the Dussafu PSC with an effective date of May 28, 2007. It was agreed that the second three-year exploration phase be extended until May 27, 2011, at which time the partners can elect to enter a third exploration phase. In order to complete drilling activities of the first exploratory well, in March 2011, the Direction Generale Des Hydrocarbures (“DGH”) approved another one year extension to May 27, 2012 of the second exploration phase.
     Operational activities during the three months ended March 31, 2011 included well preparation, importation of drilling material and equipment into Gabon, contracting of well services for drilling, the negotiation and contracting of a drilling unit in preparation to spud the exploration well in the second quarter of 2011. A Standby Letter of Credit was issued on April 7, 2011 for a semi-submersible rig to drill the Ruche Marin prospect. The exploratory well was spud on April 28, 2011 to test stacked reservoir potential in the pre-salt section. The Dussafu PSC represents $11.6 million and $9.2 million of unproved oil and gas properties on our March 31, 2011 and December 31, 2010 balance sheets, respectively.
     In January 2011, we established an operational and logistics base in Port Gentil, Gabon to support the drilling program.

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Note 13 — 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.
     Operational activities during the three months ended March 31, 2011 included the completion of the reprocessing and integrating multiple existing 3-D seismic databases. Detail geological and geophysical interpretation is underway to refine the prospects and define drilling locations. 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. The Block 64 EPSA represents $4.3 million and $4.2 million of unproved oil and gas properties on our March 31, 2011 and December 31, 2010 balance sheets, respectively.
Note 14 — China
     In March 2011, China National Offshore Oil Corporation (“CNOOC”) granted us an extension of Phase One of the Exploration Period for the WAB-21 contract area to May 2013. WAB-21 represents $3.1 million of unproved oil and gas properties on our March 31, 2011 and December 31, 2010 balance sheets, respectively.
Note 15 — 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 March 31, 2011, Vinccler’s share of the undistributed dividends is $9.0 million.
Note 16 — 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”); Port Gentil, Republic of Gabon (“Gabon”); and Roosevelt, Utah to support field operations in those areas. We expect to cease operations in the Roosevelt, Utah field office in May 2011 upon closing of the announced sale transaction.
     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. Petrodelta is governed by its own charter and bylaws and operates a portfolio of properties in eastern Venezuela including large proven oil fields as well as properties with very substantial opportunities for both development and exploration. We have seconded key technical and managerial personnel into Petrodelta and participate on Petrodelta’s board of directors. HNR Finance has a direct controlling interest in Harvest Vinccler S.C.A. (“Harvest Vinccler”). Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with Petroleos de Venezuela S.A. (“PDVSA”). We do not have a business relationship with Vinccler outside of Venezuela.
     Through the pursuit of technically-based strategies guided by conservative investment philosophies, we are building a portfolio of exploration prospects to complement the low-risk production, development and exploration prospects we hold in Venezuela. In addition to our interests in Venezuela, we hold exploration acreage in the Gulf Coast Region of the United States through an Area of Mutual Interest (“AMI”) agreement with two private third

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parties; mainly onshore West Sulawesi in Indonesia; offshore of Gabon; onshore in Oman; and offshore of the People’s Republic of China (“China”). Until March 1, 2011, pending closing of the sale for our Utah Operations (see Notes to Consolidated Financial Statements — Note 3 — Dispositions), we had developed acreage in the Antelope project in the Western United States through a Joint Exploration and Development Agreement (“JEDA”) in the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”) and Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) where we had established production.
     From time to time we learn of possible third party interests in acquiring ownership in certain assets within our property portfolio. We evaluate these potential opportunities taking into consideration our overall property mix, our operational and liquidity requirements, our strategic focus and our commitment to long-term shareholder value. For example, we have received such expressions of interest in acquiring some of our international and domestic producing and exploration assets, and we are currently evaluating these potential opportunities. There can be no assurances that our discussions will continue or that any transaction may ultimately result from our discussions.
     On March 22, 2011, we announced that we had entered into a definitive agreement to sell all of our oil and gas assets in Utah’s Uinta Basin for $215 million in cash. The sale has an effective date of March 1, 2011. The net proceeds from the sale are estimated to be $205 million after deduction for transaction related costs. Closing is expected to occur in May 2011 and the final sales price is subject to customary adjustments at closing at that time. The oil and gas assets are located in our Antelope project area in the Uinta Basin of Utah and consist of approximately 69,000 gross acres (47,600 net acres). The transaction includes both operated and non-operated wells. Bank of America Merrill Lynch served as our financial advisor in connection with the transaction. This transaction is part of our ongoing process of exploring strategic alternatives announced in September of 2010.
Venezuela
     On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Venezuela Bolivars (“Bolivars”) per U.S. Dollar exchange rate for purchases, the 2.5935 Bolivars per U.S. Dollar exchange rates for the sale of foreign currency, and the Central Bank’s entitlement to require the sale of foreign currency at specific rates with an effective date of January 1, 2011. The elimination of the 2.60 Bolivars per U.S. Dollar exchange rate for purchases is not expected to have an impact on our business in Venezuela. Since all sales of foreign currency will be at the 4.2893 Bolivars per U.S. Dollar exchange rate, we will not be required to pay a financing fee resulting from blended exchange rates for the purchase of foreign currency.
     In May 2010, the government of Venezuela established the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) for exchanging Bolivars. SITME’s purpose is to assist companies and individuals requiring foreign currency (U.S. Dollars) for the import of goods and services into Venezuela. SITME may also be used for buying or selling of Venezuela’s bonds. The establishment of SITME has not had, nor is it expected to have, an impact on our business in Venezuela.
     Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). However, during the three months ended March 31, 2011, Harvest Vinccler exchanged approximately $0.3 million through SITME and received an average exchange rate of 5.18 Bolivars per U.S. Dollar. During the three months ended March 31, 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 March 31, 2011, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 3.0 million and BsF 3.5 million, respectively. At March 31, 2011, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 106.2 million and BsF 1,902.1 million, respectively.

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Petrodelta
     Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Petrodelta’s 2011 capital budget is expected to be approximately $220 million for Petrodelta’s 2011 business plan. The 2011 budget is still pending shareholder approval. Since Petrodelta only executed approximately 50 percent its 2010 budget primarily due to lack of funding by PDVSA, we do not believe that PDVSA will be able to provide the support required to execute Petrodelta’s proposed 2011 budget. However, Petrodelta’s 2011 proposed business plan includes a planned drilling program to utilize two rigs to drill both development and appraisal wells for maintaining production capacity, the continued appraisal of the substantial resource base in the El Salto field and further drilling in the Isleño field. It also includes engineering work for production facilities required for the full development of the El Salto field.
     As discussed in previous filings, 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 being applied to gross oil production delivered to PDVSA. The original Windfall Profits Tax established a special 50 percent tax to the Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar manner, the percentage is increased from 50 percent to 60 percent when the average price of the VEB exceeds $100 per barrel.
     On April 18, 2011, the Venezuelan government published in the Official Gazette 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 repeals the original 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. It is not clear from the drafting of the amended Windfall Profits Tax if the special contribution for extraordinary prices and the special contribution for exorbitant prices are exclusive of each other; whether these layers are additive or if the 95 percent rate would apply from $70 to the price above $100; and whether the new rates apply to 100 percent of production. The amended Windfall Profits Tax caps the royalty paid on production at $70 per barrel. 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”). 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. There is still a lack of clarity on several issues. We are currently evaluating the impact of the amended Windfall Profits Tax on Petrodelta’s operations.
     During the three months ended March 31, 2011, Petrodelta drilled and completed four development wells and one successful appraisal well compared to four development wells in the three months ended March 31, 2010. Petrodelta delivered approximately 2.6 million barrels (“MBls”) of oil and 0.5 billion cubic feet (“Bcf”) of natural gas, averaging 28,700 barrels of oil equivalent (“BOE”) per day during the three months ended March 31, 2011 compared to deliveries of 2.0 MBls of oil and 0.7 Bcf of gas, averaging 21,867 BOE per day during the three months ended March 31, 2010.

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     During the three months ended March 31, 2011, Petrodelta began appraisal of the Isleño field. The first appraisal well, the ILM-8, began production on March 16 through temporary facilities. Currently, Petrodelta is operating drilling rigs in the El Salto and the Uracoa fields. A workover rig is operating in the Tucupita field. Petrodelta is also continuing infrastructure enhancement projects in El Salto and Temblador.
     Certain operating statistics for the three months ended March 31, 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     Three Months  
    Ended     Ended  
    March 31,     March 31,  
    2011     2010  
Thousand barrels of oil sold
    2,583       1,968  
Million cubic feet of gas sold
    470       660  
Total thousand barrels of oil equivalent
    2,661       2,078  
Average price per barrel
  $ 87.73     $ 71.90  
Average price per thousand cubic feet
  $ 1.54     $ 1.54  
Cash operating costs ($millions)
  $ 14.3     $ 11.2  
Capital expenditures ($millions)
  $ 34.4     $ 6.1  
     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.
United States
Gulf Coast AMI — West Bay
     In February 2011, the previously existing Alligator Point Unit (as approved by the Texas General Land Office [“GLO”]) expired. We have obtained from the GLO an extension until September 1, 2011 of a smaller version of the Alligator Point Unit defined more specifically by the drilling prospects currently existing on the project. As a result of the GLO approval of the smaller Alligator Point Unit and the anticipated expiry of five leases previously held by the larger unit, we expect our lease position on the West Bay project to be reduced from approximately 13,000 acres in February 2011 to approximately 10,050 acres in August 2011.
Western United States — Antelope
     On March 22, 2011, we announced that we had entered into a definitive agreement to sell all of our oil and gas assets in Utah’s Uinta Basin for $215 million in cash. The sale has an effective date of March 1, 2011. The net proceeds from the sale are estimated to be $205 million after deduction for transaction related costs. Closing is expected to occur in May 2011 and the final sales price is subject to customary adjustments at closing at that time.
     The oil and gas assets are located in our Antelope project area in the Uinta Basin of Utah and consist of approximately 69,000 gross acres (47,600 net acres). The transaction includes the Mesaverde project, the Lower Green River/Upper Wasatch project and the Monument Butte Extension project. We owned an approximate working interest of 70 percent in the Mesaverde and Lower Green River/Upper Wasatch projects, an approximate 60 percent working interest in one well in the Monument Butte Extension, and an approximate 43 percent working interest in the initial eight well program 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.

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Lower Green River/Upper Wasatch Oil Delineation and Development Project
     Operational activities during the three months ended March 31, 2011 included completion of the five-well delineation and development drilling program, that was later expanded to include a sixth well, which was initiated in the third quarter of 2010. As of March 31, 2011, we had six Lower Green River/Upper Wasatch wells on production and one well, the Evans #1-4-3-3 in the process of being completed and having production facilities installed. The Evans #1-4-3-3 commenced production on April 22, 2011.
Monument Butte
     Operational activities during 2011 for the Monument Butte Extension consisted of drilling and completion of the sixth and final well in the non-operated six-well follow-up program started in the fourth quarter of 2010. At March 31, 2011, all non-operated wells had been drilled and completed, and all were on production.
     During 2010, an additional Harvest operated well, the K Moon #2-13-4-3, was added to the project. We had an approximate 60 percent working interest in the well. During the first quarter of 2011, the K Moon #2-13-4-3 was drilled to total depth, completed, and production facilities installed. The K Moon #2-13-4-3 is producing on natural flow as of March 31, 2011.
     Certain operating statistics for the three months ended March 31, 2011 and 2010 for the U.S. operations are set forth below. This information is provided at our net ownership.
                 
    Three Months     Three Months  
    Ended     Ended  
    March 31,     March 31,  
    2011     2010  
Barrels of oil sold
    40,323       42,269  
Thousand cubic feet of gas sold
    246,019       86,336  
Total barrels of oil equivalent
    81,326       56,658  
Average price per barrel
  $ 81.25     $ 65.86  
Average price per thousand cubic feet
  $ 3.43     $ 3.94  
Lease operating costs and production taxes ($millions)
  $ 2.4     $ 0.2  
Cash capital expenditures ($millions)
  $ 15.6     $ 10.7  
Depletion expense per barrel of oil equivalent
  $ 9.91     $ 8.27  
     Crude oil delivered from the Monument Butte Extension is priced with reference to NYMEX CL1 — Light Sweet Crude Contract published prices. Natural gas delivered from the Monument Butte Extension is priced with reference to NYMEX Henry Hub published prices. Crude oil delivered from the Lower Green River/Upper Wasatch is priced with reference to Chevron Altamont Yellow Wax monthly average posting.
Budong-Budong Project, Indonesia
     On September 15, 2010, our partner in the Budong-Budong Production Sharing Contract (“Budong PSC”) exercised their option to increase the carry obligation. The additional carry obligation increased our ownership by 7.4 percent from 47 percent to 54.4 percent. On March 3, 2011, the Government of Indonesia and BPMIGAS, Indonesia’s oil and gas regulatory authority, approved this change in ownership interest.
     On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator to a third party, which has allowed us to acquire an additional 10 percent equity in the Budong PSC at a cost of $3.7 million payable ten business days after completion of the first exploration well. Closing of this acquisition, which is subject to the approval of the Government of Indonesia and BPMIGAS, will increase our interest in the Budong PSC to 64.4 percent. The $3.7 million was paid on April 18, 2011.
     The Lariang-1 (“LG-1”) well, the first of two planned exploration wells, was spud on January 6, 2011 in the Budong-Budong Block, West Sulawesi. 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. Wireline logs and samples of reservoir fluids confirmed the presence of hydrocarbons, trap and seal thus greatly de-risking the exploration potential of the license as well as proving the LG structure to be hydrocarbon bearing. The high formation pressures, well control difficulties, and a poor cementing job on the 9-5/8ths casing required the use of more casing strings at shallower depths than were originally planned. 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 operations and plug and abandon the well for safety reasons on April 8, 2011. 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, $13.2 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).

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     The drilling rig is currently mobilizing to drill the second exploratory well on the block, the Karama-1 (“KD-1”), which is located approximately 50 miles south of the LG-1 well. The KD-1 well will be drilled to a total depth of about 10,500 feet.
     During the three months ended March 31, 2011, we had cash capital expenditures of $5.5 million for drilling and construction costs.
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 exploration phase of the Dussafu PSC with an effective date of May 28, 2007. It was agreed that the second three-year exploration phase be extended until May 27, 2011, at which time the partners can elect to enter a third exploration phase. In order to complete drilling activities of the first exploratory well, in March 2011, the Direction Generale Des Hydrocarbures (“DGH”) approved another one year extension to May 27, 2012 of the second exploration phase.
     Operational activities during the three months ended March 31, 2011 included well preparation, importation of drilling material and equipment into Gabon, contracting of well services for drilling, the negotiation and contracting of a drilling unit in preparation to spud the exploration well in the second quarter of 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. All critical materials required for drilling the well have been purchased and received. The Ruche Marin-A exploration well spud April 28, 2011. The Ruche Marin-A well is in a water depth of 380 feet and will drill to test multiple stacked pre-salt targets to a planned total measured depth of approximately 10,100 feet with an option to deepen to 12,500 feet. We have also established an operational and logistics base in Port Gentil, Gabon to support the drilling program. During the three months ended March 31, 2011, we had cash capital expenditures of $2.1 million for well planning.
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 March 31, 2011 included the completion of the reprocessing and integrating multiple existing 3-D seismic databases. Detail geological and geophysical interpretation is underway to refine the prospects and define drilling locations. 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. During the three months ended March 31, 2011, we incurred $0.3 million for seismic interpretation.
WAB-21 Project — China
     In March 2011, China National Offshore Oil Corporation (“CNOOC”) granted us an extension of Phase One of the Exploration Period for the WAB-21 contract area to May 2013.
Other Exploration Projects
     Any of the exploratory wells to be drilled in 2011 on the Budong PSC and the Dussafu PSC could have a significant impact on our ability to obtain financing, record reserves and generate cash flow in 2011 and beyond.

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Fusion Geophysical, LLC (“Fusion”)
     On January 28, 2011, Fusion’s 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. We received $1.3 million for our equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full of the outstanding balance of the prepaid service agreement, short term loan and accrued interest. The Agreement and Plan of Merger includes an Earn Out provision wherein we would receive an additional payment of up to a maximum of $2.7 million if FusionGeo, Inc.’s 2011 gross profit exceeds $5.6 million. The Earn Out payment will not be determined until early in 2012. We can give no assurance that we will receive any Earn Out payment. See Notes to Consolidated Financial Statements, Note 9 — Investment in Equity Affiliates — Fusion Geophysical LLC.
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 currently plan to fund this commitment in 2012, and we may be required to raise capital to do so. We also have minimum work commitments during the various phases of the exploration periods in the Budong PSC and Dussafu PSC.
     As a petroleum exploration and production company, our revenue, profitability, cash flows, and future rate of growth are substantially dependent on the condition of the oil and gas industry generally, our success with our exploration program, and the belief that Petrodelta will fund its own operations and continue to pay dividends. Because our revenues are generated from customers with the same economic interests, our operations are also susceptible to market volatility resulting from economic, cyclical, weather or other factors related to the energy industry. Changes in the level of operating and capital spending in the industry, decreases in oil or gas prices, or industry perceptions about future oil and gas prices could adversely affect our financial position, results of operations and cash flows. Based on our current level of cash flow from operations, we will be required to raise capital to meet our general and administrative costs and fund our oil and gas programs.
     Our primary source of cash is still dividends from Petrodelta and funding from debt financing. In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodelta’s net income as reported under International Financial Reporting Standards (“IFRS”) for the year ended December 31, 2009. 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

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upon demand. Currently, Vinccler has not demanded its respective share of the three most recent Petrodelta dividends and has waived such a demand until at least April 2012. 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 15 — Related Party Transactions.
     We incurred significant debt during 2010 which has imposed restrictions on us and increased our vulnerability to adverse economic and industry conditions. Our monthly and semi-annual interest expense has increased significantly, and our senior convertible notes and term loan facility impose new restrictions on us. Our senior convertible notes and term loan facility impose covenant restrictions on us that limit our ability to obtain additional financing. Our ability to meet these covenants is primarily dependent on meeting customary affirmative covenant clauses, including providing consolidated statements to be audited and accompanied by a report and opinion of an independent certified public accountant, which report and opinion shall not be subject to any “going concern” or like qualification. Our inability to satisfy the covenants contained in our long term debt arrangements would constitute an event of default, if not waived. An uncured default could result in our outstanding debt becoming immediately due and payable. If this were to occur, we may not be able to obtain waivers or secure alternative financing to satisfy our obligations, either of which would have a material adverse impact on our business. As of March 31, 2011 and December 31, 2010, we were in compliance with all of our long term debt covenants.
     At March 31, 2011, we had cash on hand of $24.7 million. On March 22, 2011, we announced that we had entered into a definitive agreement to sell all of our oil and gas assets in Utah’s Uinta Basin for $215 million in cash. Closing is expected to occur in May 2011, and the net proceeds from the sale are estimated to be $205 million after deduction for transaction related costs. We believe that this cash plus cash generated from Petrodelta dividends and funding from our prior debt financings combined with our ability to vary the timing of our capital expenditures is sufficient to fund our operations and capital commitments through at least March 31, 2012. However, if the sale of the Utah Operations is unsuccessful, we will be required to increase our liquidity to levels sufficient to fund our exploration program.
     In order to increase our liquidity to levels sufficient to meet our commitments, we are currently pursuing a number of actions including our ability to delay discretionary capital spending to future periods, possible farm-out or sale of assets, or other monetization of assets as necessary to maintain the liquidity required to run our operations. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, and cost reductions. However, there is no assurance that our plans will be successful. Although we believe that we will have adequate liquidity to meet our near term operating requirements and to remain compliant with the covenants under our long term debt arrangements, the factors described above create uncertainty. Our lack of cash flow and the unpredictability of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance adequate financing can be raised. Accordingly, there can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.
     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:
                 
    Three Months Ended March 31,  
    2011     2010  
    (in thousands)  
Net cash used in operating activities
  $ (7,021 )   $ (1,424 )
Net cash used in investing activities
    (27,245 )     (16,151 )
Net cash provided by financing activities
    227       29,373  
 
           
Net increase (decrease) in cash
  $ (34,039 )   $ 11,798  
 
           
     At March 31, 2011, we had current assets of $159.3 million and current liabilities of $35.6 million, resulting in working capital of $123.7 million and a current ratio of 4.5:1. This compares with a working capital of $133.3 million and a current ratio of 5.7:1 at December 31, 2010. The decrease in working capital of $9.6 million was primarily due to dividends declared by an equity affiliate and the reclassification of Antelope assets to Asset Held for Sale offset by increases in capital expenditures and administrative expenses.

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     Cash Flow used in Operating Activities. During the three months ended March 31, 2011 and 2010, net cash used in operating activities was approximately $7.0 million and $1.4 million, respectively. The $5.6 million decrease was primarily due to increases in accounts payable and accrued expenses offset by payments of income tax payable and increases in accounts receivable and dividend receivable from equity affiliate.
     Cash Flow from Investing Activities. During the three months ended March 31, 2011, we had cash capital expenditures for property and equipment of approximately $8.4 million. Of the 2011 expenditures, $5.5 million was attributable to activity on the Budong PSC, $2.1 million was attributable to activity on the Dussafu PSC and $0.8 million was attributable to activity on other projects. During the three months ended March 31, 2010, we had cash capital expenditures of approximately $13.5 million. Of the 2010 expenditures, $10.7 million was attributable to activity on the Antelope projects, $2.3 million was attributable to activity on the Budong PSC, $0.4 million was attributable to activity on the Dussafu PSC and $0.1 million was attributable to other projects.
     During the three months ended March 31, 2011, we received $1.3 million from the sale of our equity investment in Fusion, and we deposited $4.5 million as collateral for a standby letter of credit issued in support of the drilling unit to be used on the Gabon PSC. During the three months ended March 31, 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 three months ended March 31, 2011 and 2010, we incurred $0.03 million and $1.7 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 our existing cash balances, accessing equity and debt markets, and cost reductions. In addition, we could delay the discretionary portion of our capital spending to future periods or sell, farm-out or otherwise monetize assets as necessary to maintain the liquidity required to run our operations, as warranted.
     Cash Flow from Financing Activities. During the three months ended March 31, 2011 and 2010, we incurred $0.2 million and $0.1 million, respectively, in legal fees associated with financings. During the three months ended March 31, 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 months ended March 31, 2011 and 2010 and the financial condition as of March 31, 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.
Three Months Ended March 31, 2011 Compared with Three Months Ended March 31, 2010
     We reported net income attributable to Harvest of $0.8 million, or $0.02 diluted earnings per share, for the three months ended March 31, 2011, compared with net income attributable to Harvest of $24.6 million, or $0.64 diluted earnings per share, for the three months ended March 31, 2010.

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     Total expenses and other non-operating (income) expense (in millions):
                         
    Three Months Ended        
    March 31,     Increase  
    2011     2010     (Decrease)  
Depreciation and amortization
  $ 0.1     $ 0.1     $  
Exploration expense
    1.2       1.2        
General and administrative
    6.7       5.3       1.4  
Taxes other than on income
    0.3       0.3        
Investment earnings and other
    (0.1 )     (0.1 )      
Interest expense
    2.2       0.4       1.8  
Other non-operating expense
    0.4             0.4  
Loss on exchange rates
          1.5       (1.5 )
Income tax expense
    0.2             0.2  
     During the three months ended March 31, 2011, we incurred $1.1 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations and $0.1 million related to other general business development activities. During the three months ended March 31, 2010, we incurred $0.9 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, and $0.3 million related to other general business development activities.
     General and administrative costs were higher in the three months ended March 31, 2011 compared to the three months ended March 31, 2010 primarily due to higher employee related costs ($1.3 million) and general corporate overhead costs ($0.5 million) offset by lower legal and other professional fees ($0.4 million). The employee related cost increase includes $0.4 million of special consideration bonuses related to the sale of our Utah operations. Taxes other than on income for the three months ended March 31, 2011 were consistent with the three months ended March 31, 2010.
     Investment earnings and other for the three months ended March 31, 2011 were consistent with the three months ended March 31, 2010. Interest expense was higher for the three months ended March 31, 2011 compared to the three months ended March 31, 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 $0.8 million. Other non-operating expense was higher in the three months ended March 31, 2011 compared to the three months ended March 31, 2010 due to $0.4 million of costs incurred related to on-going strategic alternatives.
     Loss on exchange rates was lower for the three months ended March 31, 2011 compared to the three months ended March 31, 2010 due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. In January 2010, Harvest Vinccler revalued the appropriate monetary accounts that were Bolivar-denominated to U.S. Dollars, Harvest Vinccler’s functional and reporting currency, at the published exchange rate of 4.30 Bolivars per U.S. Dollar. The primary factor in Harvest Vinccler’s loss on currency exchange rates is that Harvest Vinccler had substantially higher Bolivar denominated assets than Bolivar denominated liabilities. During the three months ended March 31, 2010, Harvest Vinccler recorded a $1.5 million remeasurement loss on revaluation of assets and liabilities.
     For the three months ended March 31, 2011, income tax expense was higher compared with that of the three months ended March 31, 2010, due to income tax assessed in the Netherlands recorded in the first quarter of 2011.
     For the three months ended March 31, 2010, net income from unconsolidated equity affiliates includes a $118.7 million, before tax, ($38.0 million, before tax, net to our 32 percent interest) remeasurement gain on revaluation of assets and liabilities recorded by Petrodelta due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. Petrodelta’s reporting and functional currency is the U.S. Dollar. The adjustment to reconcile to reported net income from unconsolidated affiliate for deferred income taxes increased due to the effect of the currency devaluation on the deferred tax asset associated with the non-monetary assets impacted by inflationary adjustments.
     We recorded a $1.3 million gain on the sale of our equity affiliate, Fusion, during the three months ended March 31, 2011.

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Discontinued Operations
     On March 22, 2011, we announced that we had entered into a definitive agreement to sell all of our oil and gas assets in Utah’s Uinta Basin for $215 million in cash. The sale has an effective date of March 1, 2011. The net proceeds from the sale are estimated to be $205 million after deduction for transaction related costs. Closing is expected to occur in May 2011 and the final sales price is subject to customary adjustments at closing at that time.
     Revenues were higher in the three months ended March 31, 2011 compared with the three months ended March 31, 2010 due to more wells being on production and higher average prices received for the sale of oil and natural gas. Production for the two areas for the three months ended March 31, 2011 and 2010 was:
                                 
    March 31, 2011     March 31, 2010  
    Lower Green     Monument     Lower Green     Monument  
    River/Upper     Butte     River/Upper     Butte  
    Wasatch     Extension     Wasatch     Extension  
Barrels of oil sold
    23,542       16,780       2,541       39,728  
Thousand cubic feet of gas sold
    5,939       240,080             86,336  
Total barrels of oil equivalent
    24,532       56,794       2,541       54,117  
Average price per barrel
  $ 84.31     $ 76.95     $ 71.89     $ 65.46  
Average price per thousand cubic feet
  $ 4.79     $ 3.40     $     $ 3.94  
     Lease operating costs and production taxes were higher in the three months ended March 31, 2011 compared to the three months ended March 31, 2010 due to the increase in the number oil and natural gas wells on production in the U.S. Costs incurred were for supervision and pipeline and transportation costs. Depletion expense was $0.8 million and $0.5 million ($9.91 and $8.27 per BOE) for the three months ended March 31, 2011 and 2010, respectively.
     Pretax loss from discontinued operations includes $1.4 million for impairment of long-lived assets and $3.5 million for employee severance and special bonuses related to the sale of our Utah Operations.
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 three months ended March 31, 2011 and $1.5 million for the three months ended March 31, 2010. The U.S. Dollar and Bolivar exchange rates had not been adjusted from March 2005 until January 2010. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our control. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.
     Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004, March 2005, January 2010 and again in January 2011. On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement, which established new exchange rates for the Bolivar/U.S. Dollar currencies that went into effect on January 11, 2010. On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate with an effective date of January 1, 2011.
     Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). However, during the three months ended March 31, 2011, Harvest Vinccler exchanged approximately $0.3 million through SITME and received an average exchange rate of 5.18 Bolivars per U.S. Dollar. The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Petrodelta does not have, and has not had, any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate. Harvest Vinccler

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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.
Item 3.   Quantitative and Qualitative Disclosures About Market Risk
     We are exposed to market risk from adverse changes of the situation in Venezuela, our 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 three months ended March 31, 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 Securities Exchange Act of 1934, as amended (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 March 31, 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 March 31, 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
     See our Annual Report on Form 10-K for the year ended December 31, 2010 for a description of 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
  2.1   Purchase and Sale Agreement, dated March 21, 2011, between Harvest (US) Holding, Inc. and Newfield Production Company. (Incorporated by reference to Exhibit 2.1 to our Form 8-K filed on March 25, 2011, File No. 1-10762.)
 
  3.1   Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.)
 
  3.2   Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on 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 4.2 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.)
 
  4.3   Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A filed on October 23, 2007, File No. 1-10762.)
 
  4.4   Amendment to Third Amended and Restated Rights Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
 
  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.

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  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.

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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: May 10, 2011  By:   /s/ James A. Edmiston    
    James A. Edmiston   
    President and Chief Executive Officer   
 
     
Dated: May 10, 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
2.1
  Purchase and Sale Agreement, dated March 21, 2011, between Harvest (US) Holding, Inc. and Newfield Production Company. (Incorporated by reference to Exhibit 2.1 to our Form 8-K filed on March 25, 2011, File No. 1-10762.)
 
   
3.1
  Amended and Restated Certificate of Incorporation (Incorporated by reference to Exhibit 3.1 to our Form 10-Q filed on November 9, 2010, File No. 1-10762).
 
   
3.2
  Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on 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 4.2 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.)
 
   
4.3
  Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A filed on October 23, 2007, File No. 1-10762.)
 
   
4.4
  Amendment to Third Amended and Restated Rights Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
 
   
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.

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