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Harvest Natural Resources (HNR)

Filed: 21 Nov 10, 7:00pm
(GRAPHIC) (HARVEST LOGO)
November 22, 2010
United States Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549
Attention: H. Roger Schwall
 Re: Harvest Natural Resources, Inc.
 
   Form 10-K for Fiscal Year Ended December 31, 2009
Filed March 16, 2010
 
   Schedule 14A
Filed April 9, 2010
 
   Form 10-Q for Fiscal Quarter Ended June 30, 2010
Filed August 9, 2010
 
   File No. 001-10762
Ladies and Gentleman:
     In its letter dated August 20, 2010, the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) provided to Harvest Natural Resources, Inc. (together with its subsidiaries, “us”, “we”, “our”, “Harvest” or the “Company”) comments with respect to the Company’s (a) Annual Report on Form 10-K for the year ended December 31, 2009, (b) Proxy Statement on Schedule 14A filed on April 9, 2010 and (c) Quarterly Report on Form 10-Q for the quarter ended June 30, 2010. By letter to the Commission dated September 14, 2010, the Company responded to those comments. In its letter dated November 1, 2010, the Staff responded to the Company’s September 14, 2010 letter and provided additional comments (the “Comment Letter”). This letter sets forth the Company’s response to the Comment Letter. For your convenience, we have repeated the Staff’s comments and used the section headings and numbering used by the Staff in the Comment Letter. We have also attached asExhibit A a revised draft of a Form 10-K/A for the fiscal year ended December 31, 2009 (the “Form 10-K/A”) responding to certain of the Staff’s comments that we will file after we receive clearance from the Staff. For purposes of the draft Form 10-K/A attached, we have included only the subsections of the various Items that are being revised. In accordance with Rule 12b-15, however, we will include the full text of each Item affected when we file the final Form 10-K/A.
HARVEST NATURAL RESOURCES, INC.
1177 ENCLAVE PARKWAY     SUITE 300 HOUSTON, TEXAS 77077 PH: 281-899-5700     FAX: 281-899-5702     HARVESTNR.COM

 


 

United States Securities and Exchange Commission
November 22, 2010
Page 2
Form 10-K for Fiscal Year Ended December 31, 2009
Executive Summary, page 1
1. We note your response to our previous comment number two and acknowledge your concerns regarding inclusion of dormant or non-substantive entities in an organizational chart. Please tell us whether you have considered including an organizational chart that excludes dormant or non-substantive entities in order to illustrate your significant operating and ownership entities. Given your operating and ownership structure (including unconsolidated affiliates), we are not in a position to agree that an organizational chart will not provide more clarity to your readers in addition to the narrative already provided. Please include an organizational chart, which may omit dormant or non-substantive entities, or tell us why you continue to believe such a chart is not necessary.
     Harvest’s Response:
     We continue to believe that an organizational chart is not necessary and may be more confusing to the reader than the narrative provided. In our Quarterly Report on Form 10-Q for the period ending September 30, 2010, however, we included the following revised disclosure inItem 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Executive Summarythat we believe clarifies our structure with respect to Venezuela:
     “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”). We indirectly own 80 percent of HNR Finance and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining 20 percent interest of HNR Finance. HNR Finance owns 40 percent of Petrodelta, S.A. (“Petrodelta”). As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta (80 percent of 40 percent), and Vinccler indirectly owns eight percent (20 percent of 40 percent). Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta.”
Results of Operations — Years Ended December 31, 2009 and 2008, page 30
2. Please expand your management’s discussion and analysis to include the nature of and causes for the increase in Petrodelta’s accounts receivable you noted in your response to our prior comment 11. Please also expand your disclosure to include the factors you considered in assessing the adequacy of your allowance for doubtful accounts. Please provide us a sample of your proposed expanded disclosure in your response to this comment.

 


 

United States Securities and Exchange Commission
November 22, 2010
Page 3
     Harvest’s Response:
     Costs incurred by Harvest on behalf of Petrodelta include consultants in engineering, drilling, operations and seismic interpretation, and employee salaries and related benefits for Harvest employees seconded into Petrodelta. Since 2006, Harvest has had as many as six employees seconded into Petrodelta. Currently, Harvest has five employees seconded into Petrodelta.
     From the period of April 1, 2006 (date of conversion) through October 25, 2007 (date of Venezuelan Presidential Decree), Harvest advanced $13.0 million to Petrodelta for continuing operations costs. These costs could not be paid by Petrodelta until Petrodelta became a legal entity. Petrodelta became a legal entity on October 25, 2007. From October 25, 2007 through December 31, 2007, Harvest advanced an additional $3.4 million to Petrodelta for operations costs pending the establishment Petrodelta bank accounts and completion of legal documents. Advances to Equity Affiliate (accounts receivable due to Harvest from Petrodelta) on Harvest’s balance sheet at December 31, 2007 was $16.4 million.
     During 2008, Harvest advanced $8.3 million to Petrodelta for operational costs, and Petrodelta repaid $20.9 million of the advances. Advances to Equity Affiliate on Harvest’s balance sheet at December 31, 2008 was $3.7 million.
     During 2009, Harvest advanced $4.4 million to Petrodelta for operational costs, and Petrodelta repaid $3.2 million of the advances. Advances to Equity Affiliate on Harvest’s balance sheet at December 31, 2008 was $4.9 million.
     In Harvest’s Quarterly Report on Form 10-Q for the period ending June 30, 2009, Harvest included a risk factor regarding PDVSA’s failure to timely pay contractors that it had contracted to do work for Petrodelta; PDVSA’s failure to pay amounts owed to Petrodelta with which Petrodelta would use to pay its contractors; and the effect this failure was having on Petrodelta’s business. Of the $3.2 million in payments received in 2009, $1.0 million was received during the last six months of 2009. These payments were only for Bolivar denominated invoices for payment of Bolivar denominated costs. No payments were received during the last six months of 2009 for U.S. Dollar invoices for major contractors.
     Beginning in February 2010, PDVSA started paying amounts owed to Petrodelta, which enabled Petrodelta to repay to Harvest a portion of the Advances to Equity Affiliate. During the nine months ended September 30, 2010, Harvest advanced $2.6 million to Petrodelta for operational costs, and Petrodelta has repaid $5.5 million. Advances to Equity Affiliate on Harvest’s balance sheet at September 30, 2010 was $2.0 million.
     The main factors that Harvest considered in determining whether or not an allowance for doubtful accounts was required for Advances to Equity Affiliate were:
 a. PDVSA’s slow payment to contractors. Even though payment has been slow, PDVSA has made and continues to make payments to Petrodelta enabling Petrodelta to pay its contractors. As mentioned above, Petrodelta repaid $3.2

 


 

United States Securities and Exchange Commission
November 22, 2010
Page 4
   million of the Advances to Equity Affiliate in 2009 when Harvest reported that PDVSA was not making timely payments. Petrodelta has repaid $5.5 million of the advances in 2010. Payments continue to be received.
 b. Disputed balance. No portion of the Advances to Equity Affiliate is in dispute.
 
 c. Additional Advances. Harvest has control over the timing and extent of consultant charges contracted by Harvest on behalf of Petrodelta. Consultants’ work can be suspended if reimbursements are not received.
     Based on these factors, Harvest determined that an allowance for doubtful accounts was not required. Harvest is monitoring this issue and will report progress and material changes in status in future filings.
     In Harvest’s Quarterly Report on Form 10-Q for the period ending September 30, 2010, Harvest included the following disclosure inItem 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Venezuela:
     “InItem 1A — Risk Factorsin our Annual Report on Form 10-K for the year ended December 31, 2009, we disclosed that PDVSA’s failure to timely pay contractors, including Petrodelta, was having an adverse effect on Petrodelta. During the nine months ended September 30, 2010, PDVSA began making regular payments to Petrodelta to enable Petrodelta to reduce the outstanding debt to contractors. Some of the payments received from PDVSA were designated to be used to repay Harvest Vinccler (Advances to Equity Affiliates). During the nine months ended September 30, 2010, Petrodelta has paid $5.5 million to Harvest Vinccler for costs related to contractors and seconded employees.”
Part III, page 40
3. We note your responses to prior comments 15, 16, 17, and 18 from our letter to you dated August 20, 2010. Insofar as you will be amending the Form 10-K, be sure to provide in the amended Form 10-K all the revised disclosure you provided to us in draft form. In that regard, please eliminate any gaps in the five year sketches that were the subject of prior comment 17, including those which remain in the revised draft of Mr. Head’s biographical sketch.
     Harvest’s Response:
     We confirm that we will provide in the Form 10-K/A all the revised disclosure provided to the Staff in draft form in response to prior comments 15, 16, 17, and 18, and will eliminate any gaps in the five year sketches that were the subject of prior comment 17. Attached hereto asExhibit B is a revised draft of our response to prior comment 17.
Form 10-Q for Quarterly Period Ended June 30, 2010
Management’s discussion and analysis — Venezuela, page 22

 


 

United States Securities and Exchange Commission
November 22, 2010
Page 5
4. In order to assist readers in understanding why the currency devaluation in Venezuela has not affected your financial position and results of operations, please confirm that you will expand the disclosure in your next interim and annual filing to include a summary of the information contained in your response to our prior comment 20. Please also confirm you will either quantify the amount of net monetary assets and liabilities that are exposed to exchange rate changes, or state that the amount is not material. For more information on our expectations regarding this disclosure, please refer to the section of the minutes of the CAQ SEC Regulations Committee meeting on April 6, 2010 titled “SEC Staff Observations Regarding Venezuela” under Item III.B. A copy of the minutes can be found here: http://thecaq.orglresources/secregslpdfs/highlights/2010 0406 Highlights.pdf.
     Harvest’s Response:
     Harvest confirms that it will expand the disclosure in Harvest’s next interim and annual filings to include a summary of the information contained Harvest’s response to the SEC’s prior comment 20. In Harvest’s Quarterly Report on Form 10-Q for the period ending September 30, 2010, Harvest included the following disclosure inItem 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Venezuela:
     “On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement, which established new exchange rates for the Venezuela Bolivar (“Bolivar”)/U.S. Dollar currencies that went into effect on January 11, 2010. Per the Exchange Agreement, each exchange rate is applied to foreign currency sales and purchases conducted through the Foreign Currency Administration Commission (“CADIVI”), in the cases expressly provided in the Exchange Agreement. In this regard, the exchange rates established in the Agreement are: 2.60 Bolivars per U.S. Dollar and 4.30 Bolivars per U.S. Dollar. The 2.60 Bolivar exchange rate applies to the food, health, medical and technology sectors. The 4.30 Bolivar exchange rate applies to all other sectors not expressly established by the 2.60 Bolivar exchange rate. The 4.30 Bolivar exchange rate applies to the oil and gas sector.
     As an alternative to the use of the official exchange rate, an exemption under the Venezuelan Criminal Exchange Law for transactions in certain securities resulted in an indirect securities transaction market of foreign currency exchange, through which companies could obtain foreign currency legally without requesting it from CADIVI. Publicly available quotes did not exist for the securities transaction exchange rate but such rates could be obtained from brokers. Securities transaction markets were used to move financial securities into and out of Venezuela. In May 2010, the government of Venezuela effectively eliminated this indirect market of foreign currency exchange and established the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) for exchanging Bolivars. SITME’s purpose is to assist companies and individuals requiring foreign currency (U.S. Dollars) for the import of goods and services into Venezuela. SITME may also be used for buying or selling of Venezuela’s bonds. The elimination of the indirect market for foreign currency exchange and the establishment of SITME has not had, is not expected to have, an impact on our business in Venezuela.

 


 

United States Securities and Exchange Commission
November 22, 2010
Page 6
     Harvest Vinccler, S.C.A. (“Harvest Vinccler”), a subsidiary of HNR Finance, 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). The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Harvest Vinccler and Petrodelta do not have, and have not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate.
     At December 31, 2009, Harvest Vinccler and Petrodelta remeasured the appropriate monetary assets and liabilities at the official exchange rate of 2.15 Bolivars per U.S. Dollar, Harvest Vinccler’s and Petrodelta’s functional and reporting currency. On January 31, 2010, Harvest Vinccler and Petrodelta remeasured the appropriate monetary assets and liabilities at the new official exchange rate of 4.30 Bolivars per U.S. Dollar. During the nine months ended September 30, 2010, Harvest Vinccler recorded a $1.5 million remeasurement loss and Petrodelta recorded a $120.5 million remeasurement gain on revaluation of monetary assets and liabilities. The revaluation of Bolivars to U.S. Dollars was calculated as the difference between the old official exchange rate of 2.15 Bolivars per U.S. Dollar and the new official exchange rate of 4.30 Bolivars per U.S. dollar. The primary factor in Harvest Vinccler’s loss on currency exchange rates is that Harvest Vinccler had substantially higher Bolivar denominated monetary assets than Bolivar denominated monetary liabilities. The primary factor in Petrodelta’s gain on currency exchange rates is that Petrodelta had substantially higher Bolivar denominated monetary liabilities than Bolivar denominated monetary assets. At September 30, 2010, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 2.9 million and BsF 3.4 million, respectively. At September 30, 2010, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 78.0 million and BsF 2,032.3 million, respectively.”
     In connection with responding to the Staff’s comments, we acknowledge that (i) the Company is responsible for the adequacy and accuracy of the disclosure in the filings, (ii) Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filings and (iii) the Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

 


 

United States Securities and Exchange Commission
November 22, 2010
Page 7
     If you have any questions or comments regarding this letter, please contact Harva R. Dockery or Roger K. Harris of Fulbright & Jaworski L.L.P. at (214) 855-8369 or (713) 651-5517, respectively.
     
 Sincerely,

Harvest Natural Resources, Inc.
 
 
 By:  /s/ Stephen C. Haynes   
  Name:  Stephen C. Haynes  
  Title:  Vice President & Chief Financial Officer  
 
cc: Harva R. Dockery
Roger K. Harris

 


 

EXHIBIT A
 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K/A
Amendment No. 1
(Mark One)
   
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
  For the fiscal year ended December 31, 2009
or
   
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File No.: 1-10762
HARVEST NATURAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
   
Delaware 77-0196707
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number)
   
1177 Enclave Parkway, Suite 300
Houston, Texas
 77077
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code:(281) 899-5700
Securities registered pursuant to Section 12(b) of the Act:
   
Title of each class Name of each exchange on which registered
   
Common Stock, $.01 Par Value NYSE
Securities registered pursuant to Section 12(g) of the Act:Preferred Share Purchase Rights
Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yeso Noþ
Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ
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. Yesþ Noo
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yeso Noo
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a smaller reporting company. See the definition of “large accelerated filer,” ���accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
       
Large Accelerated filero Accelerated filerþ Non-Accelerated filero(Do not check if a smaller reporting company) Smaller Reporting Companyo
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ
The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 2009 was: $144,812,960.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practical date. Class: Common Stock, par value $0.01 per share, on March 9, 2010, shares outstanding: 33,260,554.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s Proxy Statement for the 2010 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission, not later than 120 days after the close of the registrant’s fiscal year, pursuant to Regulation 14A, are incorporated by reference into Items 10, 11, 12, 13 and 14 of Part III of this annual report.
 
 

 


 

Explanatory Note — Amendment
          Harvest Natural Resources, Inc. and Subsidiaries (collectively, “we”, “us”, “our”, “Harvest” or “the Company”) is filing this Amendment No. 1 (“Amendment”) to our Annual Report on Form 10-K for the year ended December 31, 2009 (the “Original Form 10-K”) to reflect changes made in response to comments received by us from the Staff of the Securities and Exchange Commission (the “Staff”), in connection with the Staff’s review of our report. We are only filing the sections of our Original Form 10-K that have been revised in response to the Staff’s comment letter and all other information in our Original Form 10-K remains unchanged and does not otherwise reflect events occurring after March 16, 2010, the original filing date of the Original Form 10-K. Accordingly, this Amendment should be read in conjunction with our Original Form 10-K and any Harvest filings with the SEC subsequent to the filing of the Original Form 10-K.
          Pursuant to the Rules of the SEC, currently dated certifications from our Chief Executive Officer and Chief Financial Officer as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 are filed or furnished herewith, as applicable.
Item 1. Business — Reserves
Reserves
          In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. The primary impacts of the SEC’s final rule on our reserve estimates include:
  In Venezuela, the use of the unweighted 12-month average of the first-day-of-the-month contracted reference price of $56.83 per barrel for oil compared to the year-end contracted reference price of $69.87 per barrel, and
 
  In the United States, the use of the unweighted 12-month average of the first-day-of-the-month reference prices of $48.21 per barrel for oil and $3.31 per Mcf for gas compared to year-end reference prices of $61.73 per barrel of oil and $4.25 per Mcf for gas.
 
  The disclosure of probable and possible reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves which are less certain to be recovered than probable reserves and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.
              Under the SEC’s final rule, prior period reserves were not restated.
          The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data

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provided for, management reviews and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Arts in Engineering Science, a Master of Science in Petroleum Engineering, has more than 25 years of experience in reservoir engineering and is a member of the Society of Petroleum Engineers.
          All reserve information in this report is based on estimates prepared by Ryder Scott Company L.P. (“Ryder Scott”), independent petroleum engineers. The technical personnel responsible for preparing the reserve estimates at Ryder Scott meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.
          The following table shows, by country and in the aggregate, a summary of our proved, probable and possible oil and gas reserves as of December 31, 2009. Probable and possible reserves are not reported for Domestic — Utah due to the ongoing evaluation of assets within these categories.

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  Oil and  Natural    
  Condensate  Gas  Total 
  (MBls)  (MMcf)  (MBOE)(1) 
Proved Developed Reserves:            
Domestic — Utah  131   653   240 
International — Venezuela(2)
  11,394   19,212   14,596 
          
             
Total Proved Developed  11,525   19,865   14,836 
          
             
Proved Undeveloped Reserves:            
Domestic — Utah  95   473   174 
International — Venezuela(2)
  26,542   30,956   31,701 
          
Total Proved Undeveloped  26,637   31,429   31,875 
          
             
Total Proved Reserves
  38,162   51,294   46,711 
          
             
Probable Developed Reserves:            
International — Venezuela(2)
  94   74   106 
             
Probable Undeveloped Reserves:            
International — Venezuela(2)
  34,951   11,674   36,897 
          
             
Total Probable Reserves
  35,045   11,748   37,003 
          
             
Possible Developed Reserves:            
International — Venezuela(2)
  9      9 
             
Possible Undeveloped Reserves:            
International — Venezuela(2)
  134,805   37,147   140,996 
          
             
Total Possible Reserves
  134,814   37,147   141,005 
          
 
(1) MBOE (thousand barrels of oil equivalent) is determined using the approximate heat content ratio of one barrel of crude oil or condensate to six Mcf of natural gas, which ratio does not necessarily reflect price equivalency.
 
(2) Information represents our indirect 80 percent ownership interest in HNR Finance.
     Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2009, 2008 and 2007 and changes in proved reserves during the last three years are contained inPart IV, Item 15 — Supplemental Information on Oil and Natural Gas Producing Activities (unaudited). See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policiesfor additional information on our reserves.

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Item 1. Business — Production, Prices and Lifting Cost Summary
Production, Prices and Lifting Cost Summary
     In the following table we have set forth, by country, our net production, average sales prices and average operating expenses for the years ended December 31, 2009, 2008 and 2007. Venezuela is presented at our net 32 percent ownership interest in Petrodelta. The United States is presented at our ownership interest. In thousands, except per unit information:
             
  Year Ended December 31, 
  2009  2008  2007 
Venezuela
            
Crude Oil Production (Bbls)(b)  2,507   1,762   1,720 
Natural Gas Production (Mcf)(a)(c)  1,407   3,424   4,306 
Average Crude Oil Sales Price ($ per Bbl) $57.62  $83.22  $58.61 
Average Natural Gas Sales Price ($ per Mcf) $1.54  $1.54  $1.54 
Average Operating Expenses ($ per Boe)(d) $5.64  $10.65  $3.12 
             
United States
            
Monument Butte
            
Net Crude Oil Production (Bbls)  3       
Natural Gas Production (Mcf)  6       
Average Crude Oil Sales price ($ per Bbl) $61.61  $  $ 
Average Natural Gas Sales Price ($ per Mcf) $2.77  $  $ 
Average Operating Expenses ($ per Boe) $  $  $ 
 
(a) Royalty-in-kind paid on gas used as fuel was 1,063 Mcf, 1,226 Mcf and 1,242 Mcf for 2009, 2008 and 2007, respectively, net to our 32 percent ownership interest in Petrodelta.
 
(b) Crude oil production for Petrodelta at 100 percent was 7,835 Bbls, 5,505 Bbls and 5,374 Bbls for 2009, 2008 and 2007, respectively.
 
(c) Natural gas production for Petrodelta at 100 percent was 4,397 Mcf, 10,700 Mcf and 13,456 Mcf for 2009, 2008 and 2007, respectively.
 
(d) Before royalties and including workovers. Average operating expenses per Boe net of royalties and workovers was $8.46, $10.90 and $4.20 for 2009, 2008 and 2007, respectively.
Item 1A. Risk Factors
     We may incur significant indebtedness in the near future.We continually assess our need for additional sources of financing based on our operational, working capital and other needs from time to time. In addition, we are currently contemplating one particular additional source of financing through an Islamic (sukuk) financing. Sukuk financing is an Islamic financial certificate, similar to a bond in Western finance, that complies with Sharia, Islamic religious law. Trading debt is prohibited under Sharia. As such, financing under Sharia must only be raised for identifiable assets. The issuer of a sukuk buys an asset from an investor group, who then rents the asset from the issuer for a predetermined fee. Under the sukuk, one of our

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subsidiaries would form and contribute certain assets to a partnership and subsequently sell a minority interest in the partnership to the sukuk issuers for approximately $250 million. Although the terms of this transaction have not been finalized, we anticipate that the terms would include our agreement to pay all or a substantial portion of the future dividends paid by Petrodelta over the next five or six years to reacquire all of the sukuk issuers partnership interests, including premiums thereon. While we may be able to consummate this financing transaction in the near future, there can be no assurances that this transaction will be consummated at all, and we may consider alternative forms of additional financing if we deem necessary or advisable with respect to our operations from time to time.

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PART IV
Item 15.Exhibits and Financial Statement Schedules
Item 15 of the Annual Report on Form 10-K for the fiscal year ended December 31, 2009, filed on March 16, 2010, is amended by the addition of the following exhibits:
Exhibits
   
Exhibit No. Description of Exhibit
23.1(1)
 Consent of Ryder Scott Company, L.P.
   
31.1(1)
 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
   
31.2(1)
 Certification of Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
   
32.1(1)
 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
   
32.2(1)
 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
   
99.1(1)
 Revised reserve report dated February 26, 2010, of Ryder Scott Company to Harvest (US) Holdings, Inc.
   
99.2(1)
 Revised reserve report dated February 26, 2010, of Ryder Scott Company to HNR Finance B.V.
 
(1) Filed herewith

- 6 -


 

SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
     
 Harvest Natural Resources, Inc.
 
 
Date: November __, 2010 /s/   
 Name:    
 Title:    

- 7 -


 

     
EXHIBIT INDEX
   
Exhibit No. Description of Exhibit
23.1(1)
 Consent of Ryder Scott Company, L.P.
   
31.1(1)
 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
   
31.2(1)
 Certification of Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
   
32.1(1)
 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
   
32.2(1)
 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
   
99.1(1)
 Revised reserve report dated February 26, 2010, of Ryder Scott Company to Harvest (US) Holdings, Inc.
   
99.2(1)
 Revised reserve report dated February 26, 2010, of Ryder Scott Company to HNR Finance B.V.
 
(1) Filed herewith

- 8 -


 

EXHIBIT 23.1
HARVEST NATURAL RESOURCES, INC.
INDEPENDENT PETROLEUM ENGINEERS’ CONSENT
     We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-167887, 333-134630, 333-115841, 333-94823, 333-49114 and 333-85900) and Form S-3 (No. 333-162858) of Harvest Natural Resources, Inc. (formerly Benton Oil and Gas Company) of our revised reports dated February 26, 2010 attached as Exhibits 99.1 and 99.2 to Amendment No. 1 on Form 10-K/A to Harvest Natural Resources, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009.
     
   
   
 Ryder Scott Company, L.P.  
Denver, Colorado
November __, 2010

 


 

EXHIBIT 31.1
I, James A. Edmiston, certify that:
 1. I have reviewed this report on Form 10-K/A of Harvest Natural Resources, Inc.;
 
 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
 4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
 a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
 b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
 c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
 d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 


 

 b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: November __, 2010
     
   
 James A. Edmiston  
 President and Chief Executive Officer  

 


 

     
EXHIBIT 31.2
I, Stephen C. Haynes, certify that:
 1. I have reviewed this report on Form 10-K/A of Harvest Natural Resources, Inc.;
 
 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
 4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
 a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
 b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
 c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
 d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 


 

 b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: November __, 2010
     
   
 Stephen C. Haynes  
 Vice President - Finance, Chief Financial
Officer and Treasurer 
 

 


 

     
EXHIBIT 32.1
Accompanying Certificate
Pursuant to Rule 13a-14(b) or Rule 15d-14(b)
and 18 U.S.C. Section 1350
Not Filed Pursuant to the Securities Exchange Act of 1934
     The undersigned Chief Executive Officer of Harvest Natural Resources, Inc. (the “Company”) does hereby certify as follows:
     This report on Form 10-K/A of Harvest Natural Resources, Inc. for the period ended December 31, 2009 and filed with the Securities and Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
     
   
Date: November __, 2010 By:    
  James A. Edmiston  
  President and Chief Executive Officer  

 


 

     
EXHIBIT 32.2
Accompanying Certificate
Pursuant to Rule 13a-14(b) or Rule 15d-14(b)
and 18 U.S.C. Section 1350
Not Filed Pursuant to the Securities Exchange Act of 1934
     The undersigned Chief Financial Officer of Harvest Natural Resources, Inc. (the “Company”) does hereby certify as follows:
     This report on Form 10-K/A of Harvest Natural Resources, Inc. for the period ended December 31, 2009 and filed with the Securities and Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
     
   
Date: November __, 2010   
 Stephen C. Haynes  
 Vice President - Finance, Chief Financial
Officer and Treasurer 
 
 

 


 

EXHIBIT 99.1
       
(RS LOGO)   FAX (303) 623-4258

     621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO
80293 TELEPHONE (303) 623-9147    
February 26, 2010
Harvest (US) Holdings, Inc.
1177 Enclave Parkway, Suite 300
Houston, Texas, 77077
Attention: Steven Haynes
                 Phil Harries
Gentlemen:
At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of Harvest (US) Holdings, Inc. (Harvest) as of December 31, 2009. The subject properties are located in the state of Utah. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on February 26, 2010 and presented herein, was prepared for public disclosure by Harvest in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.
     The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of Harvest as of December 31, 2009.
     The estimated reserves and future net income amounts presented in this report, as of December 31, 2009, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

 


 

SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
Harvest (US) Holdings, Inc.
As of December 31, 2009
                 
  Proved 
  Developed      Total 
  Producing  Non-Producing  Undeveloped  Proved 
Net Remaining Reserves
                
Oil/Condensate — Barrels  32,117   98,482   95,400   225,999 
Gas — MMCF  161   492   473   1,126 
                 
Income Data M$
                
Future Gross Revenue $1,990  $6,102  $5,899  $13,990 
Deductions  524   925   2,761   4,210 
             
Future Net Income (FNI) $1,466  $5,176  $3,138  $9,780 
                 
Discounted FNI @ 10% $1,053  $3,987  $1,772  $6,812 
     Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).
     The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C. The program was used at the request of Harvest. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.
     The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 75 percent and gas reserves account for the remaining 25 percent of total future gross revenue from proved reserves.
     The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.
       
    Discounted Future Net Income
    As of December 31, 2009
Discount Rate Total
Percent Proved
5  $7,940 
8  $7,206 
12  $6,476 
15  $6,054 

 


 

     The results shown above are presented for your information and should not be construed as our estimate of fair market value.
Reserves Included in This Report
     The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
     The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in category.
     No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.
     Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Harvest’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.
     Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”
     Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.
     Harvest’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and

 


 

are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
     The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Harvest owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Estimates of Reserves
     The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.
     In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
     Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
     The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, and analogies.All (100%) of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods.These performance methods

 


 

include, but may not be limited to, decline curve analysis which utilized extrapolations of historical production and pressure data available through November, 2009 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by Harvest or obtained from public data sources and were considered sufficient for the purpose thereof. All (100%) of the proved non-producing and undeveloped reserves included herein were estimated by the analogy method.
     To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
     Harvest has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Harvest with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Harvest. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
     In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
Future Production Rates
     For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
     Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production,

 


 

sales were estimated to commence at an anticipated date furnished by Harvest. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
     The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
Hydrocarbon Prices
     The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.
     Harvest furnished us with the above mentioned average prices in effect on December 31, 2009. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area(s) included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.
     The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Harvest. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Harvest to determine these differentials.
     In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.
         
      Average Average
    Price Benchmark Realized
Geographic Area Product Reference Prices Prices
United States Oil/Condensate WTI Cushing $61.18 /Bbl $48.21 /Bbl
  Gas Henry Hub $3.87 /MMBTU $3.31 /MCF

 


 

     The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.
Costs
     Operating costs for the leases and wells in this report are based on the operating expense reports of Harvest and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Harvest.
     Development costs were furnished to us by Harvest and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Harvest were accepted without independent verification.
     The proved non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Harvest’s plans to develop these reserves as of December 31, 2009. The implementation of Harvest’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Harvest’s management. As the result of our inquires during the course of preparing this report, Harvest has informed us that the development activities included herein have been subjected to and received the internal approvals required by Harvest’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Harvest. Additionally, Harvest has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.
     Current costs used by Harvest were held constant throughout the life of the properties.
Standards of Independence and Professional Qualification
     Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
     Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We

 


 

encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
     Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
     We are independent petroleum engineers with respect to Harvest. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
     The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person(s) primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
     The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Harvest.
     Harvest makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Harvest has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-8 (Nos. 333-115841, 333-94823, 333-49114 and 333-85900) and Forms S-3 (No. 333-162858) of Harvest of the references to our name as well as to the references to our third party report for Harvest, which appears in the December 31, 2009 annual report on Form 10-K of Harvest. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Harvest.
     We have provided Harvest with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Harvest and the original signed report letter, the original signed report letter shall control and supersede the digital version.
     The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
   
  Very truly yours,
   
  RYDER SCOTT COMPANY, L.P.
  TBPE Firm Registration No. F-1580
   
  Scott James Wilson, P.E., M.B.A.
  Senior Vice President
/sm

 


 

EXHIBIT 99.2
     
(RS LOGO)
   FAX (303) 623-4258

621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO
80293      TELEPHONE (303) 623-9147    
 
  February 26, 2010  
HNR Finance B.V.
Prins Bernhardplein 200
P.O. Box 990
1000 AZ Amsterdam, Netherlands
Attention: Harvest (US) Holdings, Inc. — Director A
                 Fortis Intertrust (Netherlands) B.V. — Director B
Gentlemen:
     At your request, we have prepared an estimate of the proved, probable and possible reserves, future production, and income attributable to HNR Finance B.V.’s (“HNR Finance”) interest in certain properties located in the Greater Oficina Trend of Eastern Venezuela as of December 31, 2009. These properties have been included in a company called Petrodelta S.A., in which HNR Finance has a 40 percent interest, and Corporación Venezolana del Petroleo S.A. (CVP) has 60 percent interest. The properties include six fields, Uracoa, Tucupita, Bombal, Temblador, Isleño, and El Salto (“Petrodelta fields”).
     The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on February 26, 2010 and presented herein, was prepared for public disclosure by HNR Finance in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.
     The properties evaluated by Ryder Scott represent 100 percent of the total net proved, probable and possible liquid hydrocarbon reserves and 100 percent of the total net proved, probable and possible gas reserves of HNR Finance as of December 31, 2009.
     The estimated reserves and future net income amounts presented in this report, as of December 31, 2009, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

 


 

HNR Finance B.V.
February 26, 2010
Page 2
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
HNR Finance in Petrodelta S.A.
As of December 31, 2009
                 
  Proved 
  Developed      Total 
  Producing  Non-Producing  Undeveloped  Proved 
Net Remaining Reserves
                
Oil/Condensate — Barrels  11,404,822   2,836,885   33,177,013   47,418,720 
Gas — MMCF  23,217   798   38,695   62,710 
                 
Income Data $M
                
Future Gross Revenue $665,351  $162,448  $1,945,040  $2,772,839 
Deductions  143,274   39,202   730,074   912,550 
             
Future Net Income (FNI) $522,077  $123,246  $1,214,966  $1,860,289 
 
Discounted FNI @ 10% $322,904  $66,901  $624,855  $1,014,660 
         
  Total  Total 
  Probable  Possible 
  Non-producing  Non-producing 
  and  and 
  Undeveloped  Undeveloped 
Net Remaining Reserves
        
Oil/Condensate — Barrels  43,806,586   168,516,762 
Gas — MMCF  14,686   46,434 
         
Income Data M$
        
Future Gross Revenue $2,512,145  $9,648,315 
Deductions  919,142   3,102,372 
       
Future Net Income (FNI) $1,593,003  $6,545,943 
 
Discounted FNI @ 10% $698,265  $2,388,673 
     Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. Where applicable, one barrel of oil is considered equivalent to 6,000 cubic feet of natural gas. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

 


 

HNR Finance B.V.
February 26, 2010
Page 3
     The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software (version 2.8 Build 3), a copyrighted program of TRC Consultants L.C. The program was used at the request of HNR Finance. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material
     The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal or foreign income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.
     Liquid hydrocarbon reserves account for approximately 97 percent of the total future gross revenue from proved reserves and gas reserves account for the remaining 3 percent of total future gross revenue from proved reserves. Liquid hydrocarbon reserves account for approximately 99 percent of the total future gross revenue from probable reserves and gas reserves account for the remaining one percent of total future gross revenue from probable reserves. Liquid hydrocarbon reserves account for approximately 99 percent of the total future gross revenue from possible reserves and gas reserves account for the remaining one percent of total future gross revenue from possible reserves.
     The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded annually. Future net income was discounted at four other discount rates which were also compounded annually. These results are shown in summary form as follows.
               
    Discounted Future Net Income
    As of December 31, 2009
Discount Rate Total Total Total
Percent Proved Probable Possible
 5  $1,340,542  $1,032,335  $3,851,928 
 8  $1,128,363  $812,682  $2,874,765 
 12  $918,104  $603,382  $1,999,587 
 15  $798,559  $489,450  $1,551,800 
     The results shown above are presented for your information and should not be construed as our estimate of fair market value.
Reserves Included in This Report
     The proved, probable and possible reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

 


 

HNR Finance B.V.
February 26, 2010
Page 4
     The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved, probable and possible developed non-producing reserves included herein consist of the shut-in and behind pipe categories.
     No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved, probable and possible gas volumes included herein do not attribute gas consumed in operations as reserves.
     Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At HNR Finance’s request, this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein.
     Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low. The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.
     Reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

 


 

HNR Finance B.V.
February 26, 2010
Page 5
     The reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production, unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to HNR Finance for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with HNR Finance the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of HNR Finance’s representations regarding such contractual information should be construed as a legal opinion on this matter.
     Ryder Scott did not evaluate the country and geopolitical risks in the countries where HNR Finance operates or has interests. HNR Finance’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved, probable and possible reserves actually recovered and amounts of proved, probable and possible income actually received to differ significantly from the estimated quantities.
     The estimates of reserves presented herein were based upon a detailed study of the properties in which HNR Finance owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Estimates of Reserves
     The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

 


 

HNR Finance B.V.
February 26, 2010
Page 6
     In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
     Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
     The proved, probable and possible reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods.All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods.These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through November, 2009 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by HNR Finance or obtained from public data sources and were considered sufficient for the purpose thereof.
     All (100 percent) of the proved, probable and possible non-producing and undeveloped reserves included herein were estimated by a combination of the volumetric and analogy methods. The volumetric analysis utilized pertinent well and seismic data supplied to Ryder Scott by HNR Finance or which we have obtained from public data sources that were available through November, 2009. The data utilized from the analogues as well as well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.
     To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices

 


 

HNR Finance B.V.
February 26, 2010
Page 7
received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
     HNR Finance has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved, probable and possible production and income, we have relied upon data furnished by HNR Finance with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by HNR Finance. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
     In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
Future Production Rates
     For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
     Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by HNR Finance. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
     The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

 


 

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Hydrocarbon Prices
     The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.
     HNR Finance furnished us with the above mentioned average prices in effect on December 31, 2009. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.
     The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by HNR Finance.
     In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.
                 
          Average  Average Realized 
      Price  Benchmark  Prices 
Geographic Area Product Reference Prices (All Categories)
Venezuela Oil WTI Cushing $61.18 / BBL $56.83 / BBL
  Gas Defined Contract NA $1.24 / MCF
     The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.
Costs
     Operating costs for the leases and wells in this report are based on the operating expense reports of HNR Finance and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For

 


 

HNR Finance B.V.
February 26, 2010
Page 9
operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by HNR Finance. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
     Development costs were furnished to us by HNR Finance and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by HNR Finance were accepted without independent verification.
     The proved, probable and possible non-producing and undeveloped reserves in this report have been incorporated herein in accordance with HNR Finance’s plans to develop these reserves as of December 31, 2009. The implementation of HNR Finance’s development plans as presented to us and incorporated herein is subject to the approval process adopted by HNR Finance’s management. As the result of our inquires during the course of preparing this report, HNR Finance has informed us that the development activities included herein have been subjected to and received the internal approvals required by HNR Finance’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to HNR Finance. Additionally, HNR Finance has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.
     Although some development capital is projected for blow-down, recompletions, operations, and maintenance beyond 2014, these amounts are in accordance with long-term project plans and are insignificant compared to activities pursued within 5 years of December 31, 2009 (approximately 2%). Accounting for past bookings, this small portion of Harvest’s 164-well proved undeveloped portfolio may not be drilled until the sixth year after the initial booking, but still within 5 years of December 31, 2009. Under the new SEC regulations, undeveloped reserves should be developed within 5 years of the initial booking unless special circumstances exist. Ryder Scott has discussed these reserves with Harvest and Harvest believes that, in accordance with guidance provided by the SEC, special circumstances do exist with respect to these reserves and warrant classification of these reserves as proved undeveloped reserves. Ryder Scott has included these reserves in this report based on our understanding of these exceptional circumstances.
     Current costs used by HNR Finance were held constant throughout the life of the properties.
Standards of Independence and Professional Qualification
     Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We

 


 

HNR Finance B.V.
February 26, 2010
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have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
     Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
     Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
     We are independent petroleum engineers with respect to HNR Finance Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
     The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
     The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by HNR Finance
     HNR Finance makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, HNR Finance has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-8 (Nos. 333-115841, 333-94823, 333-49114 and 333-85900) and Forms S-3 (No. 333-162858) of HNR Finance of the references to our name as well as to the references to our third party report for HNR Finance, which appears in the December 31, 2009 annual report on Form 10-K of HNR Finance. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by HNR Finance.
     We have provided HNR Finance with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by HNR Finance and the original signed report letter, the original signed report letter shall control and supersede the digital version.

 


 

HNR Finance B.V.
February 26, 2010
Page 11
     The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
Scott J. Wilson, P.E., MBA
Senior Vice President
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and income presented herein.
Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2000, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company. For more information regarding Mr. Wilson’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.php.
Mr. Wilson earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance from the University of Colorado in 1985, graduating from both with High Honors. He is a registered Professional Engineer by exam in the States of Alaska, Colorado, and Wyoming. He is also an active member of the Society of Petroleum Engineers; serving as co-Chairman of the SPE Reserves and Economics Technology Interest Group, and Gas Technology Editor for SPE’s Journal of Petroleum Technology. He is a member and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers. Mr. Wilson has published several technical papers and holds two US patents.
In addition to gaining experience and competency through prior work experience, the Wyoming Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson fulfills. As part of his 2009 continuing education hours, Mr. Wilson attended an internally presented sixteen hours of formalized training as well as a public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released

 


 

January 14, 2009 in the Federal Register. Mr. Wilson attended an additional seven hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, procedures and software and ethics for consultants.
Based on his educational background, professional training and more than 25 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

 


 

EXHIBIT B
EXECUTIVE OFFICERS
     The following table provides information regarding each of our executive officers.
       
Name Age Position
James A. Edmiston *  50  President and Chief Executive Officer
       
Stephen C. Haynes  53  Vice President, Finance, Chief Financial Officer and Treasurer
       
Keith L. Head  52  Vice President, General Counsel and Corporate Secretary
       
G. Michael Morgan  56  Vice President, Business Development
       
Karl L. Nesselrode  52  Vice President
       
Patrick R. Oenbring  58  Vice President, Western Operations
       
Robert Speirs  54  Vice President, Eastern Operations
 
* See Mr. Edmiston’s biography on page _.
     Stephen C. Hayneshas served as our Vice President, Chief Financial Officer and Treasurer since May 19, 2008. Mr. Haynes performed various financial consulting engagements from January 1, 2008, until his appointment with Harvest. Previously, he served as Chief Financial Officer for Cygnus Oil and Gas Corporation for the period February 1, 2006 through December 31, 2007. Before joining Cygnus, Mr. Haynes was the Corporate Controller with Carrizo Oil and Gas for the period January 1, 2005 through January 31, 2006. Mr. Haynes served as an independent consultant from March 2001 through end of 2004. From March 1990 through December 2000, Mr. Haynes served in a series of increasing responsibilities in international managerial and executive positions with British Gas, culminating in his appointments as Vice President-Finance of Atlantic LNG, a joint venture of British Gas and several industry partners in Trinidad and Tobago. Mr. Haynes is a Certified Public Accountant, holds a Master of Business Administration degree with a concentration in Finance from the University of Houston and a Bachelor of Business Administration degree in Accounting from Sam Houston State University. He also attended the Executive Development Program at Harvard University.
     Keith L. Headhas served as our Vice President, General Counsel and Corporate Secretary since May 7, 2007. He joined Texas Eastern upon graduation from law school and remained with the same organization through mergers with Panhandle Eastern, Duke Energy Corporation and Cinergy Corp. Mr. Head held various business development positions with Duke Energy Corporation from 1995 to 2001. His corporate development work included the identification, evaluation and negotiation of acquisitions in Latin America, North America and the United Kingdom. Mr. Head was Senior Vice President and General Counsel at Duke Energy North America from 2001 to 2004 and Associate General Counsel of Duke Energy Corporation from 2004 through December 2006. After leaving Duke Energy, Mr. Head joined Harvest in

 


 

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

 


 

engineering and construction from June 2001. During both these periods, Mr. Speirs spent considerable time in West Siberia where he oversaw substantial increases in production at both companies. From November 1997 until March 2001, Mr. Speirs resided in Jakarta where he served as President of Premier Oil Indonesia. During this period, Premier was active in all phases of the Upstream business, culminating in the commissioning of the West Natuna Gas Project. Prior to 1997, Mr. Speirs was with Conoco for 21 years in various leadership positions in the US, UK, Russia, Indonesia, Singapore and Dubai, UAE. Mr. Speirs earned a Bachelor of Science degree with Honors in Engineering Science from the University of Edinburgh. He also attended the Executive Management Program at INSEAD.