UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-K

(Mark One)
   
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
or
   
For the fiscal year ended December 31, 2004
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)
   
Delaware77-0196707

(State or other jurisdiction of incorporation or organization)		 77-0196707
(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

15835 Park Ten Place Drive, Suite 115
Houston, Texas 77084
(Former name, former address and former fiscal year, if changed since last report)

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:
   
Title of each class Name of each exchange on which registered
None None

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 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.o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a smaller reporting company. See the definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated FileroAccelerated FilerþNon-Accelerated Filer  oSmaller Reporting Companyo
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act Rule 12b-2)Act). Yesþo Nooþ

State the

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 the last business day of the registrant’s most recently completed second fiscal quarter, June 30, 2004: $535,652,892.

29, 2007 was: $444,689,722.

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 February 11, 2005,March 12, 2008, shares outstanding: 37,596,464.

35,050,833.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for the 20052008 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission, not later than 120 days after the close of the registrant’s fiscal year, pursuant to Regulation 14A, are incorporated by reference into Items 10, 11, 12, 13 and 14 of Part III of this annual report.
 
 

 

HARVEST NATURAL RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS
     
Part I Page
Part I
Item 1. Business
  21
Item 1A. Risk Factors
10
Item 1B. Unresolved Staff Comments
14 
Item 2. Properties
  1314 
Item 3. Legal Proceedings
  14 
Item 4. Submission of Matters to a Vote of SecuritySecurities Holders
  1415
 
Part II
    
Item 5. Market for Registrant’s Common Equity, and Related Stockholder Matters and Issuer Purchases of Equity Securities
  1516 
Item 6. Selected Financial Data
  1518 
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
  1619 
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
  29 
Item 8. Financial Statements and Supplementary Data
  2930 
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
  2930 
Item 9A. Controls and Procedures
  2930 
Item 9B. Other Information
  3031
 
Part III
    
Item 10. Directors, and Executive Officers of the Registrantand Corporate Governance
  3132 
Item 11. Executive Compensation
  3132 
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
  3132 
Item 13. Certain Relationships and Related Transactions, and Director Independence
  3132 
Item 14. Principal Accountant Fees and Services
  3132
 
Part IV
    
Item 15. Exhibits and Financial Statement Schedules and Reports on Form 8-K
  3233
 
Financial Statements
  S-1S-2
 
Signatures
  S-31S-35 
Indemnification Agreement
 Form of 2004 Long TermCommon Stock Incentive Plan Stock Option AgreementCertificate
 Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement
Form of 2004 Long Term Stock Incentive Plan Employee Restricted StockSeparation Agreement
 List of Subsidiaries
 Consent of PricewaterhouseCoopers LLP - Houston
 Consent of ZAO PricewaterhouseCoopers Audit-Moscow
Consent of Ryder Scott Company LP
 Certification of James A. Edmiston, President & CEO, pursuantPursuant to Section 302
 Certification of Steven W. Tholen, SVP, CFO, pursuant& Treasurer, Pursuant to Section 302
 Certification of James A. Edmiston, President & CEO, pursuantPursuant to Section 9061350
 Certification of Steven W. Tholen, SVP, CFO, pursuant& Treasurer, Pursuant to Section 9061350

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PART I

Harvest Natural Resources, Inc. (“Harvest” or the “Company”) cautions that any forward-looking statements (as such term is defined in the Private Securities Litigation Reform Act of 1995) contained in this report or made by management of the Company involve risks and uncertainties and are subject to change based on various important factors. When used in this report, the words “budget”, “guidance”, forecast”, “anticipate”, “expect”, “believes”, “goals”, “projects”, “plans”, “anticipates”, “estimates”, “should”, “could”, “assume” and similar expressions are intended to identify forward-looking statements. In accordance with the provisions of the Private Securities Litigation Reform Act of 1995, we caution you that important factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include our concentration of operations in Venezuela, the political and economic risks associated with international operations (particularly those in Venezuela), the anticipated future development costs for our undeveloped proved reserves, drilling risks, the risk that actual results may vary considerably from reserve estimates, the dependence upon the abilities and continued participation of certain of our key employees, the risks normally incident to the exploration, operation and development of oil and natural gas properties, risks incumbent to being a minority shareholder in a corporation, the permitting and the drilling of oil and natural gas wells, the availability of materials and supplies necessary to projects and operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, basis risk and counterparty credit risk in executing commodity price risk management activities, the Company’s ability to acquire oil and natural gas properties that meet its objectives, changes in operating costs,availability and cost of drilling rigs, seismic crews, overall economic conditions, political instability,stability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in governmental policy, availability of sufficient financing, changes in weather conditions, and ability to hire, retain and train management and personnel. See Item 1A - Risk Factors included inand Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 1. Business

Executive Summary

          Harvest Natural Resources, Inc. is an independent energy company engaged in the acquisition, exploration, development, production and disposition of oil and natural gas properties since 1989, when it was incorporated under Delaware law. Over our history, weWe have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”) through our subsidiary Harvest Vinccler, S.C.A. (“Harvest Vinccler”) and the Russian Federationour equity affiliate, Petrodelta S.A. (“Russia”Petrodelta”) and have undeveloped acreage offshore China.of the People’s Republic of China (“China”). In 2007, we executed a sale and purchase agreement for a partial interest in the production sharing contract related to the Dussafu Marin field offshore Gabon in West Africa (“Dussafu PSC”); and a farm-in agreement for a partial interest in the production sharing contract related to the Budong-Budong field onshore Indonesia (“Budong PSC”). All conditions precedent in the agreements are complete except for governmental approvals.
          Currently, our only producing operations are conducted throughasset is in Venezuela. Since 1992, our 80 percent-owned Venezuelan subsidiary, Harvest Vinccler, C.A.has been providing operating services to Petroleos de Venezuela, S.A. (“Harvest Vinccler”, formerly Benton Vinccler, C.A.PDVSA”), which operates for the South Monagas Unit under an Operating Service Agreement (“OSA”). On March 31, 2006, Harvest Vinccler signed a Memorandum of Understanding (the “MOU”) with two affiliates of PDVSA, Corporación Venezolana del Petroleo S.A. (“CVP”) and PDVSA Petroleo S.A. (“PPSA”), to convert the OSA into a minority interest in Venezuela.Petrodelta. On August 16, 2006, the MOU was amended to provide for the addition of the Isleño, El Salto and Temblador fields (“New Fields”) to Petrodelta as additional consideration for the conversion of the OSA to Petrodelta. On December 18, 2006, at our special meeting of the stockholders, the transactions contemplated by the MOU were approved. On September 11, 2007, we signed the Contract of Conversion (“Conversion Contract”), and on October 3, 2007, together with CVP, we formed and funded Petrodelta. On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Uracoa, Tucupita and Bombal fields (“SMU fields”) and the New Fields, subject to the conditions of the Conversion Contract, was published in the Official Gazette. Harvest Vinccler has transferred all of its tangible assets and contracts, permits and rights related to the SMU fields in Venezuela to Petrodelta. In January 2008, a majority of Harvest Vinccler’s employees accepted positions with Petrodelta. Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the SMU Fields and New Fields (collectively “Petrodelta Fields”). HNR Finance B.V. (“HNR Finance”) has a 40 percent ownership interest in Petrodelta. As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta, and our partner, Oil & Gas Technology Consultants

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(Netherlands) Coöperatie U.A. (“OGTC”), a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining eight percent interest. CVP owns the remaining 60 percent. At our request, CVP has added HNR Finance as a party to the Conversion Contract. Petrodelta is governed by its own board of directors, charter and bylaws.
          In April 2006, the Venezuelan National Assembly passed legislation terminating all operating service agreements and directed the government to take over the operations carried out by the private companies without prejudice to the incorporation of mixed companies for that purpose. This action, coupled with the unfinished conversion to Petrodelta, left Harvest Vinccler without a contractual means recognized by the government of Venezuela to address revenues or costs and expenses from April 1, 2006 until October 25, 2007. As a result of this situation, our consolidated financial statements prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) from April 1, 2006 until September 2004, we announced30, 2007, did not reflect the redemption on November 1, 2004 of all $85 millionnet results of our 9.375 percent senior unsecured notes due Novemberproducing operations in Venezuela. Since the Conversion Contract terms have been fulfilled, we have recorded the results of operations and economic benefits of our ownership in Petrodelta from April 1, 2006 through December 31, 2007 (the “2007 Notes”). In Augustin the fourth quarter of 2007 as Net Income from Unconsolidated Equity Affiliates.
          Since signing the MOU in March 2006, CVP has designated its board members and September 2004, we purchased West Texas Intermediate (“WTI”) crude oil puts covering 10,000 barrelsa General Manager and President for Petrodelta. While Petrodelta has been formed, funded and is the legal owner of oil per daythe Petrodelta Fields, Harvest Vinccler continued in the day-to-day operations of the Petrodelta Fields until the end of January 2008. During 2007, Harvest Vinccler advanced cash to Petrodelta of $47.7 million to fund its operations of which $8.0 million remains to be repaid as of February 29, 2008.
          At December 31, 2007, Harvest Vinccler had one loan outstanding with a Venezuelan bank for calendar year 2005 to protect our 2005 cash flow. These puts cost a total of $14.920 billion Venezuela Bolivars (“Bolivars”) (approximately $9.3 million). This loan is cash collateralized by $6.8 million havedeposited in a U. S. bank. The loan represents the remaining balance originally borrowed in 2006 to pay income tax assessments and related interest to the SENIAT, the Venezuelan income tax authority.
          In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method. Although the full cost method of accounting for oil and gas exploration and development continues to be an average strike priceaccepted method of $42.20 per barrelaccounting for oil and gas properties, the successful efforts method of accounting as prescribed by SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies is the preferred method. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 154, Accounting Changes and Error Corrections, financial information for prior periods has been restated to reflect retrospective application of the successful efforts method. We believe the successful efforts method provides a more transparent representation of our results of operations and the ability to assess our future investments in oil and gas properties for impairment based on their estimated fair values rather than being required to base valuation on prices and costs as of the balance sheet date.  The significant differences between successful efforts and full cost accounting for oil and gas properties relate to the expensing of exploration activities and related unsuccessful exploratory drilling activities. The expensing of these costs can create volatility in the statement of operations. The change in accounting principle resulted in a cumulative, non-cash increase to retained earnings of $52.4 million, net of income tax, as of December 31, 2004. Retained earnings increased due to our pricing structure for our Venezuelan oil, have the economicreversal of ceiling test write downs in prior years required under the full cost accounting rules of the Securities and Exchange Commission (“SEC”). There were no such impairments under the successful efforts accounting rules. The effect of hedging approximately 20,800 barrels of oil per day. During 2004, we drilled ten new wells and re-entered and completed an additional six wells in the South Monagas Unit. Our daily crude oil and natural gas salesaccounting change on income from continuing operations for the years ended December 31, 2004, were 29,000 barrels2006 and 2005 was a decrease of oil$4.9 million and 77$15.0 million, cubic feetnet of gas.income tax, or $0.13 and $0.39 per diluted share, respectively. The decrease in income from continuing operations was due to an increase in depletion expense. There was no effect on cash and cash equivalents. For additional information on the impact of the change to the successful efforts method of accounting seePart IV, Item 15, Notes to the Consolidated Financial Statements, Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle.
          SeeItem 1 – Business, Operations, Item 1A – Risk Factors,andItem 7 – Management’s Discussion and Analysis of Financial ConditionsCondition and Results of Operationsfor a completemore detailed description of these and other events during 2004.

2007.

          As of December 31, 2004, we had total estimated Proved Reserves in the South Monagas Unit, net of minority interest, of 84.4 million barrels of oil equivalent (“MMBoe”), and a standardized measure of discounted future net cash flow, before income taxes, for total Proved Reserves of $802 million.

     As of December 31, 2004,2007, we had total assets of $367.5 million. We had$413.4 million, unrestricted cash in the amount of $84.6$120.8 million and no long-term debt. WeFor the year ended December 31, 2007, we had total revenues of $186.1$11.2 million and

2

net cash provided byused in operating activities of $74.1$20.5 million. As of December 31, 2006, we had total assets of $468.4 million, unrestricted cash in the amount of $148.1 million and long-term debt of $67.0 million. For the year ended December 31, 2003,2006, we had cash in the amount of $138.7 million and $96.8 million in long-term debt. We had total revenues of $106.1$59.5 million and net cash provided byused in operating activities of $38.5$24.4 million.

2

Our strategy has broadened from our primary focus on Venezuela to identify, access and integrate hydrocarbon assets to include organic growth through exploration in basins globally with proven hydrocarbon systems. We seek to leverage our Venezuelan experience as well as our recently expanded business strategydevelopment and technical platform to create a diversified resource base. With the addition of technical resources, opening of our London office, the planned 2008 opening of a Singapore office, the redeployment of resources from our Moscow office, as well as our earlier purchase of a 45 percent equity interest in Fusion Geophysical, L.L.C. (“Fusion”), we have made significant investments to provide the necessary foundation and global reach required for an organic growth focus. While exploration will become a larger part of our overall portfolio, we will generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles.

          Our goal, with the conversion process in Venezuela completed, is to identify, acquire, developinfluence the management and produce large discovered oiloperations of Petrodelta while developing and gas fieldsproducing the Petrodelta Fields in Venezuelathe most efficient manner. We expect that amounts available for dividends will be distributed to us on a regular basis after a catch up dividend for the period of April 1, 2006 to December 31, 2007. Then Petrodelta is expected to reinvest a substantial portion of its earnings in its development and Russia.producing activities and, accordingly, we expect subsequent dividends to be minimal in the near-term.
          We have more than twelve years of experience in Venezuela and Russia, and have established organizations in both countries. We seekintend to use our available cash to pursue additional growth opportunities in these two countriesGabon, Indonesia, China and would consider investments in other countries that meet our criteria. In executing our businessstrategy. However, the execution of this strategy we will strivemay be limited by factors including access to sustainadditional capital and the current balance sheet strength through:

•  maintaining financial prudence and rigorous investment criteria;
•  maximizing cash flows from existing operations in order to invest in new opportunities;
•  using our experience, skills and cash on hand to acquire new projects; and
•  keeping our organizational capabilities in line with our rate of growth.

     In Venezuela, we seekreceipt of a dividend from Petrodelta as well as the need to deliver maximum operating cash flow throughpreserve adequate development capital in the efficient management of our capital expenditure programs and cost structure.interim.

          The year 2004 represented our first full year of natural gas production, which allowed us to diversify our revenues and cash flow. Our Venezuelan producing properties generate net cash from operating activities in excess of projected capital expenditures.

     We have significant financial flexibility and substantial cash flow supported by current oil prices and current production levels for both oil and gas. We believe this provides us with the ability to pursue growth opportunities while at the same time maintaining a strong balance sheet. However, we have recently experienced difficulties in Venezuela with getting our budgets approved and obtaining permits from the Ministry of Energy and Petroleum (“MEP”, formerly Ministry of Energy and Mines) and Ministry of Environment, as required, which are critical to our ability to fully execute our drilling program. A continuation of these difficulties or a curtailment of production in Venezuela could adversely affect our production and our ability to pursue growth opportunities.

     While we cannot predict the degree to which we will be successful, we continue to evaluate properties in both Venezuela and Russia to find opportunities which meet our focused acquisition criteria. We expect our cash generating capacity to be supported by our new gas production, lower operating expenses and our expected future Uracoa and Bombal drilling programs.

     Our ability to successfully execute our strategy is subject to significant risks including, among other things, payment of Petrodelta dividends, exploration, operating, risks, political, risks, legal risks and financial risks. SeeItem 1A – Risk Factors,Item 7 – Management’s Discussion and Analysis of Financial ConditionsCondition and Results of Operationsand other information set forth elsewhere in this Annual Report on Form 10-K for a description of these and other risk factors.

Available Information

          We file annual, quarterly and current reports, proxy statements and other documents with the Securities and Exchange Commission (“SEC”)SEC under the Securities Exchange Act of 1934.1934 (“Exchange Act”). The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 450 Fifth100 F Street NW,NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC athttp://www.sec.gov.

          We also make available, free of charge on or through our Internet website (http://www.harvestnr.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the SecuritiesExchange Act of 1934 are also available on the website. In addition, we have adopted a Code of Business Conduct and Ethics that applies to all of our employees, including our chief executive officer, principal financial officer and principal accounting officer. The text of the Code of Business Conduct and Ethics has been posted on the Corporate Governance section of our website. We intend to post on our website any amendments to, or waivers from, our Code of Business Conduct and Ethics applicable to our senior officers. Additionally, the Code of Business Conduct and Ethics is available in print to any person who requests the information. Individuals wishing to obtain this printed material should submit a request to Harvest Natural Resources, Inc., attention1177 Enclave Parkway, Suite 300, Houston, Texas 77077, Attention: Investor Relations.

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Operations

     The following table summarizes

          Since April 1, 2006, all of our Proved Reserves, drillingcurrent operations are conducted through our equity affiliate Petrodelta in Venezuela. Harvest Vinccler, HNR Finance and production activity, and financial operating data by principal geographic area atCVP entered into the end of eachConversion Contract in September 2007. HNR Finance is a Netherlands private company with limited liability. All of the years ending December 31, 2004, 2003equity interest in HNR Finance and 2002. All Venezuelan reserves are attributable to an operating service agreement between Harvest Vinccler and Petroleos de Venezuela S.A. (“PDVSA”) under which all mineral rights areis owned by the Government of Venezuela.Harvest-Vinccler Dutch Holding B.V., a Netherlands private company with limited liability. We own an 80 percent equity interest in Harvest-Vinccler Dutch Holding B.V. The remaining 20 percent equity interest is owned by OGTC. In addition, we own 100 percent of the WAB-21 petroleum contract in the South China Sea for which we are the operator. During the fourth quarter of 2007, we entered into a sale and purchase agreement for a 50 percent ownership interest in the Dussafu PSC, which we expect to operate as soon as final approvals are received; and a farm-in agreement for an initial 47 percent ownership interest, which may increase to a 54.65 percent ownership interest, in the Budong PSC, which we may operate during the production phase. SeeItem I – Business, Dussafu Marin, Offshore GabonandBudong-Budong, Onshore Indonesiafor a more detailed description.
Petrodelta
General
          On October 25, 2007, the Venezuelan Presidential Decree which formally transfers to Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract was published in the Official Gazette. Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from October 25, 2007. Petrodelta will undertake its operations in accordance with the Business Plan as set forth in Annex I to the Conversion Contract (“Business Plan”). Under the Conversion Contract, work programs and annual budgets adopted by Petrodelta must be consistent with the Business Plan. The Business Plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. The 2008 budget of Petrodelta’s Business Plan was approved by its shareholders on January 23, 2008.
          Petrodelta has adopted policies and procedures governing its operations, including, among others, policies and procedures for safety, health and environment, contracting, maintenance of insurance, accounting, banking and treasury and human resources, following the guidelines established by CVP. To the extent possible, such policies and procedures will be consistent with the policies and procedures of PDVSA and the ultimate parent company of HNR Finance. Petrodelta has hired personnel, largely from Harvest Vinccler; and the Board of Directors of Petrodelta has appointed the management of Petrodelta. Certain of these appointments are made by the shareholders. Effective August 9, 2007, Mr. Karl L. Nesselrode, Vice President, Engineering and Business Development of Harvest Vinccler.Natural Resources, Inc. (“Harvest”), accepted a long-term secondment to Petrodelta as its Operations and Technical Manager. Per Petrodelta’s bylaws, the Operations and Technical Manager’s position is designated as our appointment. Mr. Nesselrode will remain an officer of Harvest. The General Manager of Petrodelta (CVP appointment) has been appointed by the Board of Directors of Petrodelta. This position is in charge of the daily management of the business of Petrodelta and has the power and duties customary to manage, direct and supervise the accounting of Petrodelta.
          Petrodelta is governed by a board of directors in accordance with the Charter and Bylaws of Petrodelta as set forth in Annex E to the Conversion Contract (“Charter and Bylaws”). Under the Charter and Bylaws, matters requiring shareholder approval may be approved by a simple majority with the exception of certain specified matters which require the approval by the holders of at least 75 percent of the capital stock. These matters include: most changes to the Charter and Bylaws; changes in the capital stock of Petrodelta that would alter the percentage participation of HNR Finance or CVP; any liquidation or dissolution of Petrodelta; any merger, consolidation or business combination of Petrodelta; disposition of all or any substantial part of the assets of Petrodelta, except in the ordinary course of business; any financing agreement for an amount greater than $10 million; approval or modification of Petrodelta’s financial statements; creation of certain reserve information presented below is netfunds; any distribution of dividends or return of paid-in surplus; changes to the policy regarding dividends and other distributions established by the Charter and Bylaws; changes to the Business Plan; changes to the Contract for Sale and Purchase of Hydrocarbons with PPSA; contracts with shareholders or affiliates that are not at market price; any social investment in excess of the amount required by the Venezuelan government; any waiver of material rights or actions with respect to litigation involving more than $1 million; selection of external auditors; appointment of any judicial representative or general agent of Petrodelta; and designation of a 20 percent deduction forliquidator in the minority interest in Harvest Vinccler. Drilling and production activity and financial data are reflected without deduction for minority interest. Reserves include production projected through the endevent of the operating service agreement in 2012. The Venezuelan national civil work stoppage required Harvest Vinccler to shut-in production for approximately two months. We believe the two months representing this delay will be added to the original termliquidation of the operating service agreement pursuant to the force majeure provisions of the agreement.
             
  Harvest Vinccler 
  Year Ended December 31, 
  2004  2003  2002 
  (Dollars in 000’s)
RESERVE INFORMATION:
            
Proved Reserves (MBoe)  84,418   96,364   102,534 
Discounted future net cash flow attributable to proved reserves, before income taxes $802,022  $545,308  $481,284 
Standardized measure of discounted future net cash flows $544,980  $366,770  $317,799 
DRILLING AND PRODUCTION ACTIVITY:
            
Gross wells drilled  16   3   13 
Average daily production (Boe)  36,418   20,130   26,598 
FINANCIAL DATA:
            
Oil and natural gas revenues $186,066  $106,095  $126,731 
Expenses:            
Operating expenses and taxes other than on income  33,297   31,445   31,608 
Depletion  34,108   19,599   22,685 
Income tax expense  38,968   12,158   4,866 
          
Total expenses  106,373   63,202   59,159 
          
Results of operations from oil and natural gas producing activities $79,693  $42,893  $67,572 
          
Petrodelta.

     We disposed of our Russian investments partly in 2002 and partly in 2003. LLC Geoilbent (“Geoilbent”) and Arctic Gas Company (“Arctic Gas”) were accounted for under the equity method and were included at their respective ownership interests in our consolidated financial statements for the periods in which we owned such investments. Our year-end financial information contains results from our Russian operations based on a twelve-month period ending September 30. Accordingly, our results of operations for the years ended December 31, 2003 and 2002 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002, and from Arctic Gas, until it was sold on April 12, 2002.

     We owned 34 percent of Geoilbent, which we accounted for under the equity method. The following table presents our proportionate share of Geoilbent’s Proved Reserves (at September 30 for each respective year), drilling and production activity, and financial operating data for the period until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002.

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  Geoilbent 
  Year Ended September 30, 
  2003  2002 
  (Dollars in 000’s) 
RESERVE INFORMATION:
        
Proved Reserves (MBbls)  (a)  25,356 
Discounted future net cash flow attributable to proved reserves, before income taxes  (a) $117,229 
Standardized measure of discounted future net cash flows  (a) $92,939 
DRILLING AND PRODUCTION ACTIVITY:
        
Gross development wells drilled  (a)  6 
Net development wells drilled  (a)  2 
Average daily production (Bbls)  5,242   6,438 
FINANCIAL DATA:
        
Oil and natural gas revenues $27,876  $31,039 
Expenses:        
Operating, selling and distribution expenses and taxes other than on income  16,088   16,902 
Depletion  6,215   9,237 
Write-down of oil and gas properties  32,300   — 
Income tax expense  2,073   1,955 
       
Total expenses  56,676   28,094 
       
Results of operations from oil and natural gas producing activities $(28,800) $2,945 
       

(a) Geoilbent was sold on September 25, 2003.

     We owned, free          The Board of Directors of Petrodelta consists of five directors, three of whom are appointed by CVP, including the President of the Board, and two of whom are appointed by HNR Finance. Decisions of the Board of Directors are taken by the favorable vote of at least three of its members, except in the case of any sale and transfer restrictions, until it was sold on April 12, 2002, 39 percentdecision implementing a decision of the equity interestsShareholders’ Meeting relating to any of the matters where a qualified majority is required, in Arctic Gas, which we accountedcase, a favorable vote of four members will be required. The Board of Directors has broad powers of administration and disposition expressly granted in the Charter and Bylaws. The powers include: proposing budget and work programs; presenting the annual report to the shareholders; appointing and dismissing personnel; making recommendations regarding financial reserves and utilization of surplus; making proposals on dividends consistent with the Charter and Bylaws; agreeing on contracts consistent with the work programs and budgets; opening and closing bank accounts; making, accepting, endorsing and guaranteeing bank drafts and other commercial instruments consistent with work programs and budgets; and implementing policies and procedures.

          The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for underSale and Purchase of Hydrocarbons with PPSA signed on January 17, 2008. The form of the equity method. The following table presents our proportionate share, freeagreement is set forth in Annex K to the Conversion Contract. Crude oil delivered from the Petrodelta Fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets, and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make payment to Petrodelta of sale andeach invoice within 60 days of the end of the invoiced production month by wire transfer, restrictions,in United States Dollars (“U.S. Dollars”) in the case of Arctic Gas’s financial operating datapayment for the period.
     
  Arctic Gas Company 
  Year Ended 
  September 30, 2002 
  (Dollars in 000’s) 
RESERVE INFORMATION:
    
Proved Reserves (MBoe)  (a)
Discounted future net cash flow attributable to proved reserves, before income taxes  (a)
Standardized measure of discounted future net cash flows  (a)
DRILLING AND PRODUCTION ACTIVITY:
    
Gross wells reactivated  (a)
Average daily production (Bbls)  189 
FINANCIAL DATA:
    
Oil and natural gas revenues $3,554 
Expenses:    
Selling and distribution expenses  1,429 
Operating expenses and taxes other than on income  1,673 
Depletion  139 
Income tax expense  19 
    
Total expenses  3,260 
    
Results of operations from oil and natural gas producing activities $294 
    

(a) Arctic Gas was sold on April 12, 2002.

5

South Monagas Unit, Venezuela (Harvest Vinccler)

General

     In July 1992, we and Venezolana de Inversiones y Construcciones Clerico, C.A., a Venezuelan construction and engineering company (“Vinccler”), signed a 20-year operating service agreement with Lagoven, S.A., an affiliate of PDVSA, to reactivate and further develop the Uracoa, Tucupita and Bombal fields. These fields comprise the South Monagas Unit. We were the first U.S. company since 1976 to be granted such an oil field development contract in Venezuela.

     Thecrude oil and natural gas operationsliquids delivered, and in Bolivars in the South Monagas Unit are conducted by Harvest Vinccler, our 80 percent-owned subsidiary. The remaining 20 percentcase of the outstanding capital stock of Harvest Vinccler is owned by Vinccler. Through our majority ownership of stock in Harvest Vinccler, we make all operational and corporate decisions related to Harvest Vinccler, subject to certain super-majority provisions of Harvest Vinccler’s charter documents related to:

Ÿ mergers;
Ÿ consolidations;
Ÿ sales of substantially all of its corporate assets;
Ÿ change of business; and
Ÿ similar major corporate events.

     Vinccler has an extensive operating history in Venezuela. It provided Harvest Vinccler with initial financial assistance and significant construction services. Vinccler provided assistance with construction projects, governmental relations and labor relations during 2004 and 2003.

     Under the terms of the operating service agreement, Harvest Vinccler is a contractor for PDVSA. Harvest Vinccler is responsible for overall operations of the South Monagas Unit, including all necessary investments to reactivate and develop the fields comprising the South Monagas Unit. The Venezuelan government maintains full ownership of all hydrocarbons in the fields. In addition, PDVSA maintains full ownership of equipment and capital infrastructure following its installation.

     The operating service agreement provides for Harvest Vinccler to receive an operating fee for each barrel of crude oil delivered. It also provides Harvest Vinccler with the right to receive a capital recovery fee for certain of its capital expenditures, provided that such operating fee and capital recovery fee cannot exceed the maximum total fee per barrel set forth in the agreement. The operating fee is subject to quarterly adjustments to reflect changes in the special energy index of the U.S. Consumer Price Index. The maximum total fee is subject to quarterly adjustments to reflect changes in the average of certain world crude oil prices. Since 1992, the maximum total fee received by Harvest Vinccler has approximated 48 percent of West Texas Intermediate crude oil (“WTI”) price.

     In September 2002, Harvest Vinccler and PDVSA signed an amendment to the operating service agreement, providing for the delivery of up to 198 Bcf of natural gas through July 2012 at a price of $1.03 per Mcf. For 2004, natural gas sales averaged 85 million cubic feet (“MMcf”) per day. In addition, Harvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the gas production (“Incremental Crude Oil”). Incremental Crude Oil is sold at a price of $7.00 per barrel with the quarterly volume of such sales based on quarterly natural gas sales multiplied by the ratio of 4.5 MMBbls to 198 Bcf.

     At the end of each quarter, Harvest Vinccler prepares an invoice to PDVSA based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted contract service fees per barrel. At the end of each quarter, Harvest Vinccler also prepares invoicespayment for natural gas sales and Incremental Crude Oil. Payment is due underdelivered, in immediately available funds to the invoicesbank accounts designated by the endPetrodelta. Any dividend paid by Petrodelta will be made in U.S. Dollars.

          An unofficial English translation of the second month after the end of the quarter. Invoice amounts and payments are denominated in U.S. Dollars. Payments are wire transferred into Harvest Vinccler’s account in a commercial bank in the United States.

6

     Harvest Vinccler has constructed a 25-mile oil pipeline from its oil processing facilities at UracoaConversion Contract is attached to PDVSA’s storage facility, the custody transfer point. The operating service agreement specifies that the oil stream may contain no more than one percent base sediment and one percent water. Quality measurements are conducted both at Harvest Vinccler’s facilities and at PDVSA’s storage facility.

     In 2003, we built and completed a 64-mile pipeline with a normal capacity of 70 MMcf of natural gas per day and a design capacity of 90 MMcf of natural gas per day, a gas gathering system, upgrades to the UM-2 plant facilities and new gas treatment and compression facilities. Harvest Vinccler borrowed $15.5 million under a project loanour Quarterly Report on Form 10-Q for the gas pipeline and related facilities and the remainder of the project costs were funded from existing cash balances and internally generated cash flow. The operating service agreement contains requirements for the measurement and quality of the natural gas delivered to PDVSA.

     In August 1999, Harvest Vinccler sold its power generation facility located in the Uracoa and Tucupita Fields. Concurrentlyquarter ended September 30, 2007 filed with the sale, Harvest Vinccler entered into a long-term power purchase agreement with the purchaser of the facility to provide for the electrical needs of the field throughout the remaining term of the operating service agreement. Harvest Vinccler has entered into long-term agreements for the leasing of compression and the operation and maintenance of the gas treatment and compression facilities.

Risk Factors

     Currently, the production from the South Monagas Unit represents all of our production. This production may be reduced by actions of the Venezuelan government. In addition, political uncertainty in Venezuela increases our exposure to production disruptions and project execution risk. These risk factors and other risk factors are discussed in Item 7,Risk Factors.

SEC on November 1, 2007.

Location and Geology

     The

South Monagas Unit extends across the southeastern part of the state of Monagas and the southwestern part of the state of Delta Amacuro in eastern Venezuela. The South Monagas Unit is approximately 51 miles long and eight miles wide and consists of 157,843 acres, of which the fields comprise approximately one-half of the acreage. At December 31, 2004, Proved Reserves attributable to our Venezuelan operations were 105.5 MBoe (84.4 MBoe net to Harvest). This represented 100 percent of our Proved Reserves at year end. Harvest Vinccler has been primarily developing the Oficina sands in the Uracoa Field. The Fields (“SMU Fields”)
Uracoa Field contains 66 percent of the South Monagas Unit’s Proved Reserves.

Drilling and Development Activity

     Harvest Vinccler drilled ten oil wells and re-entered an additional six wells in 2004 and had 124 wells on production in all fields at year end 2004 in the Uracoa Field.

Uracoa Field

     Harvest Vinccler has been developing the South Monagas Unit since 1992, beginning with the Uracoa Field.

          There are currently 9080 oil and natural gas producing wells and five water injection wells in the field.

     Harvest Vinccler processes the oil, water and natural gas in the Uracoa central processing unit and ships the processed oil via pipeline to the PDVSA custody transfer point. Harvest Vinccler treats and filters produced water, then reinjects it into the aquifer to assist the natural water drive. Harvest Vinccler had reinjected produced natural gas into the natural gas cap primarily for storage conservation until November 2003, at which time it began selling the natural gas. The major components of the state-of-the-art process facility were designed in the United States and installed by Harvest Vinccler. This process design is commonly used in heavy oil production in the United States, but was not previously used extensively in Venezuela to process crude oil of similar gravity or quality. The current production facility has capacity to handle 60 thousand barrels (“MBbls”) of oil per day, 130 MBbls of water per day, and injection capacity of 46 MMcf of natural gas per day and storage of up to 75 MBbls of crude oil. All natural gas presently being solddelivered by Harvest VincclerPetrodelta is produced from the Uracoa Field.

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field.

Tucupita Field

          There are currently 3017 oil producing wells and five water injection wells at Tucupita.in the field. The currentTucupita production facility has capacity to handleprocess 30 MBbls of oil per day, 125 MBbls of water per day and storage for up to 60 MBbls of crude oil. The oil is transported through a 31-mile, 20 MBblMBbls of oil per day capacity oil pipeline constructed in 2001 from the Tucupita field to the Uracoa plant facilities.

     Harvest Vinccler reinjects produced water from Tucupita into the aquifer to aid the natural water drive, and we utilize a portion of the associated natural gas to operate a power generation facility to supply our power needs.

Bombal Field

          The East Bombal Fieldfield was drilled in 1992, and the wells were suspended until gas sales could take place.currently has two producing wells. There are currently fourtwo oil producing wells in the West Bombal Field. Portable separation, pumping and storage for 7.5 MBbl of crude oil are maintained at the field. The crude oil is pumped viafluid produced from West Bombal field flows through a six-mile pipeline and is tied into the 31-mile Tucupita oil pipeline to the Uracoa plant facilities. Development of the East Bombal field has been incorporated into Petrodelta’s long term development plan.
Infrastructure and Facilities
          Petrodelta has a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA’s storage facility, the custody transfer point. The marketing contract specifies that the oil stream may contain no more than one

5

percent base sediment and one percent water. Quality measurements are conducted both at Petrodelta’s facilities and at PDVSA’s storage facility.
          Petrodelta has a 64-mile pipeline with a normal capacity of 70 million cubic feet (“MMcf”) of natural gas per day and a design capacity of 90 MMcf of natural gas per day.
          Petrodelta has assumed from Harvest Vinccler began engineeringas part of the conversion the long-term power purchase agreements for the electrical needs, the long-term agreements for the leasing of compression and design studiesthe operation and maintenance of the gas treatment and compression facilities at the Uracoa and Tucupita fields through 2012.
Isleño, Temblador and El Salto Fields (“New Fields”)
          The New Fields transferred to Petrodelta after conversion are located in late 2004the same geographic area and have the same geology and productive formations as the SMU Fields. As with firstthe SMU Fields before Harvest Vinccler’s entry in 1992, there has been minimal development activity in the three fields during the last 20 years.
Isleño Field
          The Isleño field was discovered in 1953. 2-D seismic data is available over a portion of the field. Seven oil appraisal wells have been drilled in Isleño which have confirmed the presence of commercial oil deposits. The field is located near existing infrastructure in the SMU Fields. Petrodelta’s Business Plan projects full development of the Isleño field over the next three years.
Temblador Field
          The Temblador field was discovered in 1936 and developed in the 1940s and 1950s. Temblador has produced approximately 118 million barrels of oil and 34 billion cubic feet of natural gas sales expectedfrom 155 wells since 1936. 3-D seismic is available over the entire Temblador field.
El Salto Field
          The El Salto field was discovered in 2005. Gas1936. A total of 31 appraisal wells have been drilled identifying nine productive structures and six productive formations. The field has produced less than 1 million Boe and is currently dormant. 3-D seismic data is available over one-third of the field. We believe the El Salto field has substantial exploration upside from this fieldseveral fault blocks, which have been identified using 2-D seismic data but have not yet been confirmed through drilling.
Business Plan of Petrodelta
          Petrodelta’s Business Plan was approved as part of the conversion process.
          Petrodelta’s immediate focus will be usedthe resumption of drilling in the Uracoa field which is expected to supplement gasresult in a rapid increase in production. Concurrently, Petrodelta will acquire and process or reprocess existing 3-D seismic over the New Fields. Isleño field production can be integrated into the existing Uracoa field infrastructure providing for early production from Uracoa asthe field. Temblador field production there declines.would be processed at existing field facilities. The El Salto field is believed to contain substantial undeveloped reserves. Accordingly, we expect to acquire additional 3-D seismic and undergo significant appraisal and development in a timely manner to provide for larger scale development implementation. Overall, production is expected to peak four to six years from commencement of drilling by Petrodelta.

6

Customers

Production, Prices and Market Information

     UnderLifting Cost Summary

          In the operating service agreement, all oil and natural gas produced is delivered to PDVSA for a fee. Whilefollowing table we have substantial cash reserves, a prolonged loss ofset forth the net production, average sales could have a material adverse effect on our financial condition.

Employeesprices and Community Relations

     Harvest Vinccler has a highly skilled staff of 219 local employees and two expatriates. Harvest Vinccler has invested in a Social Community Program that includes medical programs in ophthalmologic and dental care, as well as additional social investments includingaverage operating expenses for the purchase of medicines and medical equipment for local communities within the South Monagas Unit.

Health, Safety and Environment

     Harvest Vinccler’s health, safety and environmental policy is an integral part of its business. Harvest Vinccler continually improves its policy and practices related to personnel safety, property protection and environmental management. These improvements can be directly attributed to its efforts in accident prevention programsyear ended December 31, 2007 and the trainingperiod April 1, 2006 through December 31, 2006 for Petrodelta. The presentation for Petrodelta includes 100 percent of the production (in thousands, except per unit information).

         
  Year Ended Nine Months Ended
  December 31, 2007 December 31, 2006
Venezuela
        
Crude Oil Sales (Bbls)  5,374   5,211 
Natural Gas Sales (Mcf)  13,456   11,519 
Average Crude Oil Sales Price ($per Bbl) $58.61  $50.98 
Average Natural Gas Sales Price ($per Mcf) $1.54  $1.54 
Average Operating Expenses ($per Boe) $3.12  $3.19 
          Royalty-in-kind paid on gas used as fuel was 3,882 Mcf and implementation3,285 Mcf for 2007 and 2006, respectively.
Acreage
          The following table summarizes the developed and undeveloped acreage that we hold under concession as of a comprehensive Process Safety Management System.

North GubkinskoyeDecember 31, 2007:

                 
  Developed Undeveloped
  Gross Net Gross Net
Petrodelta  16,432   6,573   230,672   92,269 
                 
          We have recorded the results of operations and South Tarasovskoye, Russia (Geoilbent)

     In September 2003, we soldeconomic benefits of our 34 percent minority equity investmentownership in GeoilbentPetrodelta from April 1, 2006 through December 31, 2007 in the fourth quarter of 2007 as Net Income from Unconsolidated Equity Affiliates. Petrodelta’s results and operating information is more fully described inPart IV, Item 15, Notes to Yukos Operational Holding Limited for $69.5 million plus $5.5 million for the repaymentConsolidated Financial Statements, Note 7 – Venezuela Operations – Petrodelta, S.A.

Risk Factors
          We face significant risks in our Petrodelta investment. These risks and other risk factors are discussed inItem 1A – Risk FactorsandItem 7 – Management’s Discussion and Analysis of intercompany loansFinancial Condition and accounts receivable. SeeNote 8 – RussianResults of Operations.

East Urengoy, Russia (Arctic Gas Company)

     Arctic Gas Company was sold in April 2002. SeeNote 8 – Russian Operations.

WAB-21, South China Sea (Benton Offshore China Company)

General

          In December 1996, we acquired Crestone Energy Corporation, subsequently renamed Benton Offshore China Company. Its principal asset is a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under certain circumstances, and lies within an area which is

8

the subject of a territorialborder dispute between the People’s Republic of China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The territorialborder dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area underdue to the dispute. As part of a review of our assets, a third-party conducted an evaluation of the WAB-21 area. Through that evaluation and our own assessment, we recorded a $13.4 million impairment charge in the second quarter of 2002. No further impairment of the property is currently required.

Location and Geology

          The WAB-21 contract area is located in the West Wan’an Basin (Nam Con Son) on the South China Sea. Its western edge lies approximately 5020 miles southeastto the east of the Dai Hung (Big Bear) Oil Field. The block is adjacent to British Petroleum’s giantsignificant natural gas discoveryfields at Lan Tay (Red Orchid) and 100 miles northLan Do, which are reported to contain two trillion cubic feet of Exxon’s Natuna Discovery.natural gas and commenced production in November 2002. WAB-21 is also adjacent to the 2005 Thien Ung discovery which tested oil and natural gas and lies east of the Dua and Chim Sao (formerly Blackbird) discoveries which successfully tested oil and gas in 2006. The WAB-21

7

contract area covers several similar structural trends and geological formations, each with potential for hydrocarbon reserves in possible multiple pay zones.

zones similar to the known fields and discoveries.

Drilling and Development Activity

          Due to the sovereignty issuesborder dispute between China and Vietnam, we have been unable to pursue an exploration program during phase one of the contract. As a result, we have obtained license extensions, with the current extension in effect until May 31, 2005.2009. While no assurance can be given, we believe we will continue to receive licensecontract extensions so long as the sovereignty issuesborder disputes persist.

Domestic Operations

     We acquired a 100 percent interest in three California State offshore oil and gas leases (“the California Leases”) and a parcel of onshore property from Molino Energy Company, LLC. In June 2004, we sold our California onshore property, which had a zero carrying value, for net proceeds of $0.6 million. We and other parties may be responsible to the State of California for any remediation costs associated with the onshore property and the related offshore oil and gas leases.

Activities by Area

Undeveloped Acreage
Acreage
          The following table summarizes our consolidated activities by area. Total Assets represents all assets, including long-lived assets accounted forthe undeveloped acreage that we hold under the equity method:
                     
      Other  Total       
(in thousands) Venezuela  Foreign  Foreign  United States  Total 
 
Year ended December 31, 2004
                    
Oil and gas sales $186,066   —  $186,066   —  $186,066 
Total Assets $309,794  $385  $310,179  $57,307  $367,486 
 
Year ended December 31, 2003
                    
Oil and gas sales $106,095   —  $106,095   —  $106,095 
Total Assets $241,855  $237  $242,092  $132,256  $374,348 
 
Year ended December 31, 2002
                    
Oil sales $126,731   —  $126,731   —  $126,731 
Total Assets $209,733  $52,302  $262,035  $73,157  $335,192 

Reserves

     Estimates of our Proved Reservesconcession as of December 31, 2004 and 2003 were prepared by Ryder Scott Company, L.P., independent2007:

         
  Undeveloped
  Gross Net
China  7,470,080   7,470,080 
         
Title to Undeveloped Acreage
          The WAB-21 petroleum engineers. The following table sets forth information regarding estimates of Proved Reserves at December 31, 2004,contract lies within an area which are all Venezuelan. The information includes reserve information netis the subject of a 20 percent deductionborder dispute between China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with a third party. The border dispute has existed for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the dispute. It is uncertain when or how this dispute will be resolved, and under what terms the various countries and parties to the agreements may participate in the resolution.
Dussafu Marin, Offshore Gabon
General
          In November 2007, we executed a sale and purchase agreement for the minoritypurchase of a 50 percent interest in Harvest Vinccler.the Dussafu PSC. All reservesconditions precedent to the sale and purchase agreement are attributablecomplete except for final government and partner approvals. We anticipate receiving final approvals during the first half of 2008. On receipt of final partner approval, we will become the operator of the Dussafu PSC. The purchase will be recorded in the quarter in which approvals are received.
Location and Geology
          The Dussafu PSC contract area is located offshore Gabon, adjacent to the border with the Republic of Congo. It contains 680,000 acres with water depths to 1,000 feet. The Dussafu PSC has two small oil discoveries in the Gamba and Dentale reservoirs and a small natural gas discovery. Production and infrastructure exists in the blocks contiguous to the Dussafu PSC.
Drilling and Development Activity
          The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources (“Republic of Gabon”), recently agreed to enter into the second exploration phase of the Dussafu PSC with an operating service

effective date of May 28, 2007. The second exploration phase is a three-year work commitment which includes the acquisition and processing of 500 kilometers of 2-D seismic, geology and geophysical interpretation, engineering studies and the drilling of a conditional well. Leads in the underexplored syn-rift potential in the M’Baya and Lucina reservoirs that are commercial in immediately adjacent fields have been identified and are expected to be the focus of the 2008 work program, which includes the acquisition and processing of 500 kilometers of 2-D seismic data. The Dussafu PSC partners anticipate prospects can be generated to test these play concepts in 2009.

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agreement between Harvest Vinccler and PDVSA under which all mineral rights are owned by the Government of Venezuela.

             
  Net Crude Oil and Condensate (MBbls) 
  Proved  Proved    
  Developed  Undeveloped  Total 
Venezuela  36,390   26,124   62,514 
          
Budong-Budong, Onshore Indonesia
             
  Net Natural Gas (MMcf) 
  Proved  Proved    
  Developed  Undeveloped  Total 
Venezuela  64,718   66,708   131,426 
          
General

          Estimates of commercially recoverable oil and natural gas reserves and of the future net cash flows derived therefrom are based upon a number of variable factors and assumptions, such as:

•historical production from the subject properties;
•comparison with other producing properties;
•the assumed effects of regulation by governmental agencies; and
•assumptions concerning future operating costs, municipal taxes, abandonment costs, development costs, and workover and remedial costs, all of which may vary considerably from actual results.

          All such estimates are to some degree speculative and various classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of the commercially recoverable reserves of oil and natural gas attributable to any particular property or group of properties, the classification, cost and risk of recovering such reserves and estimates of the future net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times may vary substantially. The difficulty of making precise estimates is accentuated by the fact that 44 percent of our total Proved Reserves were undeveloped as of December 31, 2004. The cost to develop the Proved Undeveloped Reserves is expected to be $102.8 million over the next three years.

          Reserve estimates are not constrained by the availability of the capital resources required to finance the estimated development and operating expenditures.

          In addition, actual future net cash flows will be affected by factors such as:

•actual production;
•  oil and natural gas sales;
•  supply and demand for oil and natural gas;
•  availability and capacity of gathering systems and pipelines;
•  changes in governmental regulations, policies or taxation; and
•  the impact of inflation on costs.

          The timing of actual future net oil and natural gas sales from Proved Reserves as well as the year-end price, and thus their actual present value, can be affected by the timing of the incurrence of expenditures in connection with development ofFebruary 2008, Indonesia’s oil and gas properties.regulatory authority, BP Migas, approved the assignment to us of a 47 percent interest in the Budong PSC located onshore West Sulawesi, Indonesia. Final government approval from Migas is pending. The 10 percent discount factorBudong PSC includes a ten-year exploration period and a 20-year development phase. In the initial three-year exploration phase, which began January 2007, we expect to acquire, process and interpret approximately 500 kilometers of 2-D seismic and drill two exploration wells. Our partner, Tately Budong-Budong N.V. (“Tately”), will be the operator through the exploration phase as required by the SECterms of the Budong PSC. We will have control of major decisions and financing for the project with an option to be usedoperate in the development and production phase if approved by BP Migas.

Location and Geology
          The Budong PSC covers 1.35 million acres and includes the Lariang and Karama sub-basins which are the eastern onshore extension of the West Sulawesi foldbelt (“WSFB”). Exploration to calculate present value for reporting purposesdate in the basin is not necessarily the most appropriate discount factor based on interest rates in effect from timeimmature due to time, risks associatedpreviously difficult jungle terrain, which is now accessible with the development of palm oil plantations and natural gas industry andtheir related infrastructure. Field work performed over the political risks associated with operations in Venezuela. Discounted present value, regardless of what discount rate is used, is materially affected by assumptionslast 10 years, as outcrops have been more accessible, has given a new understanding to the amountpresence of Eocene source and timing of future production, which assumptions may, and often do, prove to be inaccurate. Forreservoir potential that had not previously been recognized. Recent seismic surveys have greatly improved the period ending December 31, 2004, we reported $1,003 million ($802 million net to us) of discounted future net cash flows before income taxes from Proved Reserves based on the SEC’s required calculations.

10

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, 2004, 2003 and 2002. The presentation for Venezuela includes 100 percentunderstanding of the production, without deduction for minority interest. Geoilbent (34 percent ownership)geology and Arctic Gas (39 percent ownership not subject to any sale or transfer restrictions at December 2001), which are accounted for underenhanced the equity method,prospectivity of the offshore WSFB and, by analogy, the sparsely explored onshore area.

          To date, a total of eight leads have been included at their respective ownershiprecognized. It will be necessary to acquire a grid of seismic data to confirm the structures and give an indication of Eocene target(s) within the section and to mature these leads into drillable prospects. The two identified sub-basins (Lariang and Karama) provide an opportunity to test prospects in two sub-basins.
Farm-In Agreement Terms
          We acquired the 47 percent interest in the consolidated financial statements based onBudong PSC by committing to fund the first phase of the exploration program including the acquisition of 2-D seismic and drilling of the first two exploration wells. This commitment is capped at $17.2 million. Prior to drilling the first exploration well, subject to the estimated cost of that well, Tately will have a fiscal period ending September 30one-time option to increase the level of the carried interest to $20.0 million, and accordingly, our results of operationsas compensation for the years ended December 31, 2004, 2003 and 2002 reflect results from Geoilbent until it was sold on September 25, 2003, andincrease, we will increase our participation to a maximum of 54.65 percent. This equates to a total carried cost for the twelve months ended September 30, 2002farm-in of $9.1 million.
Regulation
General
          Our operations and from Arctic Gas until it was sold on April 12, 2002.
             
  Year Ended December 31, 
  2004  2003  2002 
Venezuela(a)
            
Crude Oil Production (Bbls)  8,152,261   7,347,399   9,708,295 
Natural Gas Production (Mcf)  31,059,416   2,660,241   — 
Average Crude Oil Sales Price ($per Bbl)(b) $18.90  $14.88  $13.08 
Average Natural Gas Sales Price ($per Mcf) $1.03  $1.03   — 
Average Operating Expenses ($per Boe) $2.50  $4.00  $3.26 
Russia
            
Geoilbent(c)(d)
            
Net Crude Oil production (Bbls)  (d)  1,913,187   2,349,916 
Average Crude Oil Sales price ($per Bbl)  (d) $14.52  $13.21 
Average Operating Expenses ($per Bbl)  (d) $2.83  $2.09 
Arctic Gas(c)(e)
            
Net Crude Oil Production (Bbls)  (e)  (e)  (e)
Average Crude Oil Sales price ($per Bbl)  (e)  (e)  (e)
Average Operating Expenses ($per Bbl)  (e)  (e)  (e)

(a)  Information represents 100 percent of production.
(b)  Average crude oil sales price before hedging activity.
(c)  Information represents our ownership interest.
(d)  Geoilbent was sold on September 25, 2003.
(e)  Arctic Gas was sold on April 12, 2002.

Regulation

General

          Our operationsour ability to finance and fund our growth strategy are affected by political developments and laws and regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are affected by:

 • change in governments;
 
 • civil unrest;
 
 • price and currency controls;
 
 • limitations on oil and natural gas production;
 
 •world demand for crude oil;
• tax, environmental, safety and other laws relating to the petroleum industry;
��
 • changes in such laws;laws relating to the petroleum industry;
 
 • changes in administrative regulations and the interpretation and application of such rules and regulations; and
 
 • changes in contract interpretation and policies of contract adherence.

9

          In any country in which we may do business, the oil and natural gas industry legislation and agency regulation are periodically changed, sometimes retroactively, for a variety of political, economic, environmental and other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some

11

of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business.

Venezuela

          On February 5, 2003, Venezuela imposed currency controlsbusiness and created the Commissionour potential for Administration of Foreign Currency with the task of establishing the detailed rules and regulations and generally administering the exchange control regime. These controls fix the exchange rate between the Venezuelan Bolivar and the U.S. Dollar and restrict the ability to exchange Venezuelan Bolivars for U.S. Dollars and vice versa. Initially the exchange rate was set at 1,600 Venezuelan Bolivars for each U.S. Dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. Dollar. Oil companies such as Harvest Vinccler are allowed to receive payments for oil sales in U.S. Dollars and pay U.S. Dollar-denominated expenses from those payments. We have substantial cash reserves and do not expect the Venezuelan currency conversion restriction to adversely affect our ability to meet short-term loan obligations and operating requirements for the next twelve months.

          Venezuela requires environmental and other permits for certain operations conducted in oil field development, such as site construction, drilling and seismic activities. As a contractor to PDVSA, Harvest Vinccler submits capital budgets to PDVSA for review, including capital expenditures to comply with Venezuelan environmental regulations. No capital expenditures to comply with environmental regulations were required in 2003 or 2004. Harvest Vinccler also submits requests for permits for drilling, seismic and operating activities to PDVSA, which then obtains such permits from the MEP and Ministry of Environment, as required. Harvest Vinccler is also subject to income, municipal and value-added taxes, and must file certain monthly and annual compliance reports with the national tax administration and with various municipalities.

Drilling and Undeveloped Acreage

          For acquisitions of leases and producing properties, development and exploratory drilling, production facilities and additional development activities such as workovers and recompletions, we spent approximately (excluding our share of capital expenditures incurred by equity affiliates) $39.2 million, $58.3 million and $50.6 million in 2004, 2003 and 2002, respectively. Included in these numbers is $33.5 million, $43.6 million and $44.3 million for the development of Proved Undeveloped Reserves in 2004, 2003 and 2002, respectively.

          We have drilled or participated through our equity affiliate in the drilling of wells as follows:economic loss.

                         
  Year Ended December 31, 
  2004  2003  2002 
  Gross  Net  Gross  Net  Gross  Net 
Wells Drilled:
                        
Exploration:                        
Dry hole  —   —   —   —   1   0.4 
Development:                        
Crude oil  16   12.8   3   2.4   18   12.0 
                   
Total  16   12.8   3   2.4   19   12.4 
                   
Average Depth of Wells (Feet)
      5,443       6,095       7,341 
Producing Wells(1):
                        
Crude Oil  124   99.2   111   88.8   258   158.2 
Competition

(1)The information related to producing wells reflects wells we drilled, wells we participated in drilling and producing wells we acquired.

          All of our drilling activities are conducted on a contract basis with independent drilling contractors. We do not directly operate any drilling equipment.

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Acreage

          The following table summarizes the developed and undeveloped acreage that we owned, leased or held under operating service agreement or concession as of December 31, 2004:

                 
  Developed  Undeveloped 
  Gross  Net  Gross  Net 
Venezuela  11,726   9,381   146,117   116,894 
China  —   —   7,470,080   7,470,080 
             
Total  11,726   9,381   7,616,197   7,586,974 
             

Competition

          We encounter substantial competition from major, national and independent oil and natural gas companies and independent operators in acquiring properties and leases for the exploration and development of crude oil and natural gas. The principal competitive factors in the acquisition of such oil and natural gas properties include staff and data necessary to identify, investigate and purchase such properties, the financial resources necessary to acquire and develop such properties, and access to local partners and governmental entities. Many of our competitors have influence, financial resources, staffs, data resources and facilities substantially greater than ours.

Environmental Regulation

          Various federal, state, local and international laws and regulations relating to the discharge of materials into the environment, the disposal of oil and natural gas wastes, or otherwise relating to the protection of the environment may affect our operations and costs. We are committed to the protection of the environment and believe we are in substantial compliance with the applicable laws and regulations. However, regulatory requirements may, and often do, change and become more stringent, and there can be no assurance that future regulations will not have a material adverse effect on our financial position, results of operations and cash flows.

Employees

          At December 31, 2004, we2007, our Houston office had 1918 full-time employees. Harvest VincclerOur Caracas, Moscow and London offices had 21914, 11 and 5 employees, and our Moscow office had 16 employees.respectively. We augment our staffsemployees from time to time with independent consultants, as required. On February 26, 2008, we reduced the staff of our Moscow office to three employees and will be redeploying two of these employees to London. Mr. Robert Speirs will relocate and head our new Singapore office which is planned to open in 2008. The Singapore office will coordinate our eastern operations and business development.
Item 1A. Risk Factors
In addition to other information set forth elsewhere in this Form 10-K, the following factors should be carefully considered when evaluating us.
We may not be able to meet the requirements of the global expansion of our business strategy. We have added a global exploration component to diversify our overall portfolio. In many locations, we may be required to post performance bonds in support of a work program. We also intend to acquire underdeveloped, undeveloped and exploration properties from time to time for which the primary risks may be technical, operational or both.
Our strategy to identify, access and integrate hydrocarbon assets in known hydrocarbon basins globally carries greater deal execution, operating, financial, legal and political risks.The environments in which we operate are often difficult and the ability to operate successfully will depend on a number of factors, including our ability to control the pace of development, our ability to apply “best practices” in drilling and development, and the fostering of productive and transparent relationships with local partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, often the legal systems of these countries are not mature and their reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and natural gas projects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy depends on our ability to have significant influence over operations and financial control.

10

Title

Operations in areas outside the United States are subject to Developedvarious risks inherent in foreign operations.Our operations are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and Undeveloped Acreage

          All Venezuelanequipment as a result of hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and governmental royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts or tribunals, renegotiation of contracts with governmental entities, changes in laws and policies, including taxes, governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign policy, foreign trade, taxation and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States.

Estimates of oil and natural gas reserves are attributableuncertain and inherently imprecise. This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves based on our equity investment in Petrodelta. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
          The process of estimating oil and natural gas reserves is complex requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth. Actual production, revenue, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used, and these variances may be material.
          You should not assume that the present value of future net revenues referred to inPart IV, Item 15, Notes to the Consolidated Financial Statements, TABLE V – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve QuantitiesandAdditional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuelan Equity Affiliate as of December 31, 2007 and 2006, TABLE V – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantitiesis the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in demand, changes in our ability to produce or changes in governmental regulations, policies or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from estimated proved reserves and their present value. In addition, the 10 percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with the oil and natural gas industry in general will affect the accuracy of the 10 percent discount factor.
Our future operations and our investments in equity affiliates are subject to numerous risks of oil and natural gas drilling and production activities.Oil and natural gas exploration and development drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is often uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
•unexpected drilling conditions;
•pressure or irregularities in formations;
•equipment failures or accidents;
•weather conditions;
•shortages in experienced labor;
•delays in receiving necessary governmental permits;
•shortages or delays in the delivery of equipment;

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•delays in receipt of permits or access to lands; and
•government actions or changes in regulations.
          The prevailing price of oil also affects the cost of and availability for drilling rigs, production equipment and related services. We cannot assure you the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs.
Our oil and natural gas operations are subject to various governmental regulations that materially affect our operations. Our oil and natural gas operations are subject to various governmental regulations. These regulations may be changed in response to economic or political conditions. Matters regulated may include permits for discharges of wastewaters and other substances generated in connection with drilling operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on oil and natural gas production. In order to conserve or limit supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.
Our cash position and limited ability to access additional capital may limit our growth opportunities.At December 31, 2007, we had $120.8 million of available cash and, until Petrodelta pays a dividend, there will be no additional cash available from operations. Having a Petrodelta dividend as our sole source of cash flow limits our access to additional capital and our concentration of political risk in Venezuela may limit our ability to leverage our assets. In addition, our future cash position depends upon the payment of dividends by Petrodelta, in particular for the period from April 1, 2006 through December 31, 2007. While we believe such dividends, if available, will be paid, there is no assurance this will be the case. These factors may limit our ability to grow through the acquisition of additional oil and gas properties and projects.
Competition within the industry may adversely affect our operations. We operate in a highly competitive environment. We compete with major, national and independent oil and natural gas companies for the acquisition of desirable oil and natural gas properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours.
The loss of key personnel could adversely affect our ability to successfully execute our strategy.We are a small organization and depend on the skills and experience of a few individuals in key management and operating positions to execute our business strategy. Loss of one or more key individuals in the organization could hamper or delay achieving our strategy.
We may not receive the required government approvals for the Dussafu PSC and/or the Budong PSC.Although all conditions precedent to the Dussafu PSC sale and purchase agreement and the Budong PSC farm-in agreement have been met, there is no certainty that the Republic of Gabon or Indonesia’s Migas will approve the respective agreements. Without the governmental approvals, we will not have an operating service agreementinterest in either asset.
We no longer directly manage operations of Petrodelta.PDVSA, through CVP, exercises substantial control over operations, making Petrodelta subject to some internal policies and procedures of PDVSA as well as being subject to constraints in skilled personnel available to Petrodelta. These issues may have an adverse effect on the efficiency and effectiveness of Petrodelta operations.
Now that the conversion to Petrodelta is completed, we are a minority interest owner in Petrodelta.Even though we have substantial negative control provisions as a minority owner in Petrodelta, our control of Petrodelta is limited to our rights under the Conversion Contract and its annexes and the Charter and Bylaws. As a result, our ability to implement or influence Petrodelta’s Business Plan, assure quality control, and set the timing and pace of development may be adversely affected.

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Now that the conversion to Petrodelta is completed, Petrodelta has a new sales contract with PPSA, and we have no experience with PPSA as to the timeliness of their payment of invoices.  Under the OSA between Harvest Vinccler and PDVSA, PDVSA had a history of making timely payment of invoices for oil and natural gas deliveries.  Even though there is no reason not to believe that PPSA won’t make timely payment of invoices for oil and natural gas deliveries, there is no guarantee that this will be the case.
Petrodelta’s Business Plan will be sensitive to market prices for oil.Petrodelta will be operating under a business plan, the success of which all mineral rights are owned bywill rely heavily on the Governmentmarket price of Venezuela.

          The WAB-21 petroleum contract lies within an areaoil. To the extent that market values of oil decline, the business plan of Petrodelta may be adversely affected.

A decline in the market price of crude oil could uniquely affect the financial condition of Petrodelta.Under the terms of the Conversion Contract and other governmental documents, Petrodelta is subject to a special advantage tax (“ventajas especiales”) which requires that if in any year the aggregate amount of royalties, taxes and certain other contributions is less than 50 percent of the subjectvalue of the hydrocarbons produced, Petrodelta must pay the government the difference. In the event of a territorial dispute betweensignificant decline in crude prices, the People’s Republicventajas especiales could force Petrodelta to operate at a loss. Moreover, our ability to control those losses by modifying the Business Plan or restricting the budget is limited under the Conversion Contract.
Oil price declines and volatility could adversely affect Petrodelta’s future, our dividends and profitability.Prices for oil fluctuate widely. Prices also affect the amount of Chinacash flow available for capital expenditures and Vietnam. Vietnamdividends from Petrodelta. Lower prices may also reduce the amount of oil that we can produce economically and lower oil production could affect the amount of natural gas we can produce. We cannot predict future oil prices. Factors that can cause fluctuations in oil prices include:
•relatively minor changes in the global supply and demand for oil;
•export quotas;
•market uncertainty;
•the level of consumer product demand;
•weather conditions;
•domestic and foreign governmental regulations and policies;
•the price and availability of alternative fuels;
•political and economic conditions in oil-producing and oil consuming countries; and
•overall economic conditions.
Petrodelta may not be able to pay dividends on its operations.While we continue to maintain cash reserves, our investment in Petrodelta currently represents all of our near-term cash generating capability, and the funds available to pursue our growth strategy may be adversely affected by Petrodelta’s inability to pay a dividend.
The total capital required for development of the New Fields in Venezuela may exceed the ability of Petrodelta to finance.Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Petrodelta’s future capital requirements for the development of the New Fields may exceed the cash available from existing cash flow. Petrodelta’s ability to secure financing is currently limited and uncertain, and has executed an agreement onbeen, and may be, affected by numerous factors beyond its control, including the risks associated with operating in Venezuela. Because of this financial risk, Petrodelta may not be able to secure either the equity or debt financing necessary to meet its future cash needs for investment, which may limit its ability to fully develop the properties, cause delays with their development or require early divestment of all or a portion of those projects. This could negatively impact our investment. If we are called upon to fund Petrodelta’s operations, our failure to do so could be considered a default under the same offshore acreageConversion Contract and cause the forfeiture of some or all our shares in Petrodelta. In addition, CVP may be unable or unwilling to fund its share of capital requirements and our ability to require them to do so is limited.
We may not be able to replace production from Petrodelta with a third party.new reserves. In general, production rates and remaining reserves from oil and natural gas properties decline as reserves are depleted. The territorial dispute has existeddecline rates depend on reservoir characteristics. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves. The business of exploring for, many years,developing or acquiring reserves is capital intensive and there has beenuncertain. We may be unable to make the necessary capital investment to maintain or

13

expand our oil and natural gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot assure you that our future exploration, development and no development activityacquisition activities will result in the area under dispute. It is uncertain whenadditional proved reserves or how this disputethat we will be resolved,able to drill productive wells at acceptable costs.
The legal or fiscal regime for Petrodelta may change and under what terms the various countriesVenezuelan government may not honor its commitments.While we believe that the Conversion Contract and partiesPetrodelta provide a basis for a more durable arrangement in Venezuela, the value of the investment necessarily depends upon Venezuela’s maintenance of legal, tax, royalty and contractual stability. Our recent experiences in Venezuela demonstrate that such stability cannot be assured. While we have and will continue to take measures to mitigate our risks, no assurance can be provided that we will be successful in doing so or that events beyond our control will not adversely affect the agreementsvalue of our investment in Venezuela.
Tax claims by municipalities in Venezuela may participate inadversely affect Harvest Vinccler’s financial condition.The municipalities of Uracoa and Libertador have asserted numerous tax claims against Harvest Vinccler which we believe are without merit. However, the resolution.reliability of Venezuela’s judicial system is a source of concern and it can be subject to local and political influences.

Item 1B. Unresolved Staff Comments
          None.
Item 2. Properties

          In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month. We moved into the new space in August 2004. In addition,Also during 2004, Harvest Vinccler leased new office space in Maturin and Caracas, Venezuela for $13,200 andapproximately $4,000 per month, respectively. We leased 17,500 square feet of space in a California building that we no longer occupy under a lease agreement that expired in December 2004. We subleased all of the office space in California for rents that approximated our lease costs.month. See also “ItemItem 1 – Business” Businessfor a description of our oil and natural gas properties and reserves.

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properties.

Item 3. Legal Proceedings

          Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Harvest Vinccler,Benton-Vinccler, C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, Texas. This suit was brought in May 2003 by Excel alleging, among other things, breach of a consulting agreement between Excel and us, misappropriation of proprietary information and trade secrets, and fraud. Excel seeks actual and exemplary damages, injunctive relief and attorneys’ fees. TheIn October 2003, the Court has abated the suit pending final judgment of a case pending in Louisiana to which we are not a party. In April 2007, the Court lifted the abatement and set the case for trial. The trial date has been set for the second quarter of 2008. We dispute Excel’s claims and plan to vigorously defend against them.

We are unable to estimate the amount or range of any possible loss.

          Uracoa Municipality Tax Assessments.Assessments In July 2004,. Harvest Vinccler has received three taxnine assessments from a tax inspector for the Uracoa municipality in which part of the South Monagas UnitSMU Fields are located as follows:
•Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the capital fee reimbursement and related interest paid by PDVSA under the OSA. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims.
•Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the Municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims.
•Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest

14

Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim.
•Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims.
Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is located. A protestunable to estimate the assessments was filed withamount or range of any possible loss. As a result of the municipality, and in September 2004SENIAT’s interpretation of the tax inspector responded in part by affirming one of the assessments and issuing a payment order.code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.
Libertador Municipality Tax Assessments. Harvest Vinccler has received five assessments from a motion withtax inspector for the tax courtLibertador municipality in Barcelona, Venezuela, seeking to enjoin the payment order and dismiss the assessment. We dispute allwhich part of the SMU Fields are located as follows:
•One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the Municipality. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim.
•Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claims.
•Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claims.
Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believe we havebelieves it has a substantial basis for our positions.its position. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the refund of all municipal taxes paid since 2002.
          In June 2007, the SENIAT issued an assessment in the amount of $0.4 million for Harvest Vinccler’s failure to withhold value added tax (“VAT”) from vendors during 2005.  The SENIAT has recognized a payment made by Harvest Vinccler in 2006 for the underwithheld VAT and has partially confirmed that some of the affected vendors have remitted the underwithheld VAT.  Harvest Vinccler has received credit, less penalties and interest, from the SENIAT for the VAT remitted by the vendors.  Harvest Vinccler has filed claims against the SENIAT for the portion of VAT not recognized by the SENIAT and believes it has a substantial basis for its position.

Item 4. Submission of Matters to a Vote of SecuritySecurities Holders

None

     None.

1415

PART II

Item 5.Market for Registrant’s Common Equity, and Related Stockholder Matters

and Issuer Purchases of Equity Securities

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

          Our Common Stockcommon stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HNR”. As of December 31, 2004,2007, there were 36,779,40934,793,735 shares of common stock outstanding, with approximately 698559 stockholders of record. The following table sets forth the high and low sales prices for our Common Stock reported by the NYSE.
           
Year Quarter High  Low 
2003
 First quarter $6.58  $4.40 
  Second quarter  6.90   4.20 
  Third quarter  7.17   5.58 
  Fourth quarter  10.02   6.35 
           
2004
 First quarter  14.25   9.48 
  Second quarter  17.00   12.13 
  Third quarter  16.60   11.54 
  Fourth quarter  18.25   14.67 
           
Year        Quarter High Low
2006 First quarter $10.68  $8.00 
  Second quarter  14.35   9.89 
  Third quarter  14.40   9.71 
  Fourth quarter  11.74   9.81 
           
2007 First quarter $10.46  $9.11 
  Second quarter  13.50   9.37 
  Third quarter  12.89   10.00 
  Fourth quarter  14.00   12.13 

          On February 11, 2005,March 12, 2008, the last sales price for the common stock as reported by the NYSE was $12.26$11.78 per share.

          Our policy is to retain earnings to support the growth of our business. Accordingly, our board of directors has never declared a cash dividend on our common stock.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
EQUITY COMPENSATION PLAN INFORMATION
DECEMBER 31, 2007
             
          Number of Securities
          Remaining
  Number of     Available for
  Securities to be Weighted Future Issuance
  Issued upon Average Under Equity
  Exercise of Exercise Price Compensation
  Outstanding Of Outstanding Plans (Excluding
  Options, Warrants Options, Warrants Securities Reflected
  And Rights And Rights in Column (a))
PLAN CATEGORY (a) (b) (c)
 
Equity compensation plans approved by security holders  3,702,160  $8.55   620,940 
Equity compensation plans not approved by security holders (1)  519,650  $2.69   — 
       
Total  4,221,810  $7.83   620,940 
       

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(1)SeePart IV, Item 15, Notes to the Consolidated Financial Statements, Note 5 – Stock Option and Stock Purchase Plansfor a description of options issued to individuals other than our officers, directors or employees. The 1999 Stock Option Plan permits the granting of stock options to purchase up to 2,500,000 shares of our common stock in the form of ISOs, NQSOs or a combination of each, with exercise prices not less than the fair market value of the common stock on the date of the grant, subject to the dollar limitations imposed by the Internal Revenue Code. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. Options granted to employees under the 1999 Stock Option Plan vest 50 percent after the first year and 25 percent after each of the following two years, or they vest ratably over a three-year period, from their dates of grant and expire ten years from grant date or three months after retirement, if earlier. All options granted to outside directors and consultants under the 1999 Stock Option Plan vest ratably over a three-year period from their dates of grant and expire ten years from grant date. These were the only compensation plans in effect that were adopted without the approval of our stockholders.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
          None.
STOCK PERFORMANCE GRAPH
          The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2007, assuming an investment of $100 on December 31, 2002 in each of Harvest’s common stock, the Dow Jones U.S. Exploration & Production Index and the S&P Composite 500 Stock Index.
          This graph assumes that the value of the investment in Harvest stock and each index was $100 at December 31, 2002 and that all dividends were reinvested.
PLOT POINTS
(December 31 of each year)
                                 
 
    2002  2003  2004  2005  2006  2007 
 Harvest Natural Resources, Inc.  $100   $154   $268   $138   $165   $190  
 Dow Jones US E&P Index  $100   $129   $182   $298   $312   $403  
 S&P 500 Index  $100   $126   $138   $142   $161   $167  
 

17

          Total Return Data provided by S&P’s Institutional Market Services, Dow Jones & Company, Inc. is composed of companies that are classified as domestic oil companies under Standard Industrial Classification codes (1300-1399, 2900-2949, 5170-5179 and 5980-5989). The Dow Jones US Exploration & Production Index is accessible athttp://www.djindexes.com/mdsidx/index.cfm?event=showTotalMarket.

Item 6. Selected Financial Data

SELECTED CONSOLIDATED FINANCIAL DATA

          The following table sets forth our selected consolidated financial data for each of the years in the five-year period ended December 31, 2004.2007. Financial information for 2003 through 2006 has been restated to reflect the retrospective application of the successful efforts method of accounting. SeePart IV, Item 15, Notes to the Consolidated Financial Statements, Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle. The selected consolidated financial data have been derived from and should be read in conjunction with our annual audited consolidated financial statements, including the notes thereto. Our year-end financial information contains results from our Russian operations through our equity affiliates based on a twelve-month period ending September 30. Accordingly, our results of operations for the years ended December 31, 2003 2002, 2001 and 20002002 reflect results from Geoilbent (until sold on September 25, 2003) for the twelve months ended September 30, 2002, 20012003 and 2000, and from Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2001 and 2000.

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  Year Ended December 31, 
  2004  2003  2002  2001  2000 
  (in thousands, except per share data) 
Statement of Operations:
                    
Total revenues $186,066  $106,095  $126,731  $122,386  $140,284 
Operating income  90,480   33,627   34,585   28,201   53,204 
Net income  34,360   27,303   100,362   43,237   20,488 
Net income per common share:                    
Basic $0.95  $0.77  $2.90  $1.27  $0.67 
                
Diluted $0.90  $0.74  $2.78  $1.27  $0.66 
                
 
Weighted average common shares outstanding                    
Basic  36,128   35,332   34,637   33,937   30,724 
Diluted  38,122   36,840   36,130   34,008   30,890 
                     
  Year Ended December 31, 
  2004  2003  2002  2001  2000 
  (in thousands) 
Balance Sheet Data:
                    
Total assets $367,486  $374,348  $335,192  $348,151  $286,447 
Long-term debt, net of current maturities  —   96,833   104,700   221,583   213,000 
Stockholders’ equity(1)
  243,189   199,713   171,317   67,623   12,904 

(1)2002. No cash dividends were declared or paid during the periods presented.
                     
  Year Ended December 31, 
  2007(1)  2006(1)  2005  2004  2003 
  (in thousands, except per share data) 
Statement of Operations:
                    
Total revenues $11,217  $59,506  $236,941  $186,066  $106,095 
Operating income (loss)  (19,536)  574   104,571   70,547   13,930 
Net income from Unconsolidated Equity Affiliates  51,695   —   —   —   — 
Net income (loss)  57,237   (62,502)  38,876   18,414   11,545 
Net income (loss) per common share:                    
Basic $1.57  $(1.68) $1.05  $0.51  $0.33 
                
Diluted $1.51  $(1.68) $1.01  $0.48  $0.31 
                
                     
Weighted average common shares outstanding                    
Basic  36,550   37,225   36,949   36,128   35,332 
Diluted  37,950   37,225   38,444   38,122   36,840 
                     
  Year Ended December 31,
  2007(1) 2006(1) 2005 2004 2003
  (in thousands)
Balance Sheet Data:
                    
Total assets $413,469  $468,365  $451,377  $433,019  $459,814 
Long-term debt, net of current maturities  —   66,977   —   —   96,833 
Stockholders’ equity  313,766   281,409   337,975   295,615   268,086 
(1)Activities under our OSA are reflected under the equity method of accounting effective April 1, 2006. The results of Petrodelta’s operations from April 1, 2006 until December 31, 2007 are reflected in 2007 when Petrodelta was formed.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
          We had earnings of $57.2 million, or $1.51 per diluted share, for the twelve months ended December 31, 2007 compared with a loss of $62.5 million, or $1.68 per diluted share, for 2006. Net income for the year ended December 31, 2007 includes the net results of Petrodelta’s operations from April 1, 2006 through December 31, 2007 of $52.1 million, the reversal of deferred revenue and deferred income tax recorded by Harvest Vinccler for 2005 and first quarter of 2006 deliveries pending clarification on the calculation of crude prices under a Transitory Agreement (“Transitory Agreement”) which provided that the maximum total fee per barrel paid under the OSA could not exceed 66.67 percent of the total value of the crude oil as determined under an Annex to the Transitory Agreement of $5.6 million, net, and gains from the exchange of financial securities of $49.6 million. The loss for 2006 was due to the inability to recognize equity earnings for the producing operations in Venezuela since the second quarter of 2006 and charges of $73.8 million for additional taxes and related interest in Venezuela for 2001 through 2006. We completed the formation of Petrodelta and moved forward with our plans to create a diversified portfolio using our existing cash and enhanced technical capabilities which are more fully described in the following sections.
Formation of Petrodelta
          On October 25, 2007, the Venezuelan Presidential Decree, which formally transfers to Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract, was published in the Official Gazette. Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from October 25, 2007. Petrodelta will undertake its operations in accordance with the Business Plan. Under the Conversion Contract, work programs and annual budgets adopted by Petrodelta must be consistent with the Business Plan. The Business Plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. The 2008 budget of Petrodelta’s Business Plan was approved by its shareholders on January 23, 2008.
          Petrodelta has hired personnel, largely from Harvest Vinccler as well as seconding its technical and financial managers; and the Board of Directors of Petrodelta has appointed the management of Petrodelta. Certain of these appointments are made by the shareholders. Effective August 9, 2007, Mr. Karl L. Nesselrode, Vice President, Engineering and Business Development of Harvest, accepted a long-term secondment to Petrodelta as its Operations and Technical Manager. Per Petrodelta’s bylaws, the Operations and Technical Manager’s position is designated as our appointment. Mr. Nesselrode will remain an officer of Harvest. The General Manager of Petrodelta (CVP appointment) has been appointed by the Board of Directors of Petrodelta and is in charge of the daily management of the business of Petrodelta and has the power and duties customary to manage, direct and supervise the accounting of Petrodelta.
          Petrodelta is governed by a board of directors in accordance with the Charter and Bylaws. Under the Charter and Bylaws, matters requiring shareholder approval may be approved by a simple majority with the exception of certain specified matters which require the approval by the holders of at least 75 percent of the capital stock. These matters include: most changes to the Charter and Bylaws; changes in the capital stock of Petrodelta that would alter the percentage participation of HNR Finance or CVP; any liquidation or dissolution of Petrodelta; any merger, consolidation or business combination of Petrodelta; disposition of all or any substantial part of the assets of Petrodelta, except in the ordinary course of business; any financing agreement for an amount greater than $10 million; approval or modification of Petrodelta’s financial statements; creation of certain reserve funds; any distribution of dividends or return of paid-in surplus; changes to the policy regarding dividends and other distributions established by the Charter and Bylaws; changes to the Business Plan; changes to the Contract for Sale and Purchase of Hydrocarbons with PPSA; contracts with shareholders or affiliates that are not at market price; any social investment in excess of the amount required by the Venezuelan government; any waiver of material rights or actions with respect to litigation involving more than $1 million; selection of external auditors; appointment of any judicial representative or general agent of Petrodelta; and designation of a liquidator in the event of the liquidation of Petrodelta.

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Business Strategy

     We intend

          The Board of Directors of Petrodelta consists of five directors, three of whom are appointed by CVP, including the President of the Board, and two of whom are appointed by HNR Finance. Decisions of the Board of Directors are taken by the favorable vote of at least three of its members, except in the case of any decision implementing a decision of the Shareholders’ Meeting relating to continueany of the matters where a qualified majority is required, in which case, a favorable vote of four members will be required. The Board of Directors has broad powers of administration and disposition expressly granted in the Charter and Bylaws. The powers include: proposing budget and work programs; presenting the annual report to identify, acquirethe shareholders; appointing and exploit knowndismissing personnel; making recommendations regarding financial reserves and utilization of surplus; making proposals on dividends consistent with the Charter and Bylaws; agreeing on contracts consistent with the work programs and budgets; opening and closing bank accounts; making, accepting, endorsing and guaranteeing bank drafts and other commercial instruments consistent with work programs and budgets; and implementing policies and procedures.
          The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PPSA signed on January 17, 2008. The form of the agreement is set forth in Annex K to the Conversion Contract. Crude oil delivered from the Petrodelta Fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets, and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make payment to Petrodelta of each invoice within 60 days of the end of the invoiced production month by wire transfer, in U.S. Dollars in the case of payment for crude oil and natural gas fieldsliquids delivered, and in Bolivars in the case of payment for natural gas delivered, in immediately available funds to the bank accounts designated by Petrodelta. Any dividend paid by Petrodelta will be made in U.S. Dollars.
          An unofficial English translation of the Conversion Contract is attached to our current areasQuarterly Report on Form 10-Q for the quarter ended September 30, 2007, filed with the SEC on November 1, 2007.
          Petrodelta currently has a workover rig performing well maintenance. A drilling rig has been contracted and is expected to begin operations during the first quarter of interest2008. Petrodelta is in the bidding and possibly other areas while maintainingselection process to contract a second drilling rig. The second drilling rig is projected to begin operations during the second or third quarter of 2008. Petrodelta’s plan of development is focused on 1) increasing production, 2) conversion of probable and possible reserves to proved reserves in the New Fields, 3) adding reserves through exploration in El Salto by acquiring and processing 3-D seismic over the remaining two-thirds of the field and drilling identified prospects, and 4) capturing the synergies and scale at all levels of Petrodelta’s operations.
          We have recorded the results of operations and economic benefits of our financial strengthownership in Petrodelta from April 1, 2006 through December 31, 2007 in the fourth quarter of 2007 as Net Income from Unconsolidated Equity Affiliates. Petrodelta’s results and flexibility. To accomplish this, operating information is more fully described inPart IV, Item 15, Notes to the Consolidated Financial Statements, Note 7 – Venezuela Operations – Petrodelta, S.A.
          InItem 1 – BusinessandItem 1A – Risk Factors,we intenddiscuss the situation in Venezuela and how the actions of the Venezuelan government have and continue to adversely affect our operations. The situation in Venezuela has also restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere. Until there is clarity and certainty over receipt of payment for prior crude oil and natural gas deliveries and the payment of dividends by Petrodelta, uncertainty over the future of our investment in Venezuela will continue to affect our performance and limit our growth opportunities.
          We will use our available cash and future access to capital markets to expand our diversified strategy in a number of countries that fit our strategic investment criteria. In executing our business strategy, we will strive to:

 •Seek to Deliver More Operating Cash Flow:In Venezuela, we seek to deliver more operating cash flow through the efficient management of our capital expenditure programsmaintain financial prudence and cost structure.rigorous investment criteria;
 
 •Focus Our Efforts in Areas of Low Geologic Risk:We intend to focus our activities principally in areas of large known but undeveloped or under-developed oil and gas resources.access capital markets;
 
 •create a diversified portfolio of assets;
•preserve our financial flexibility;
•use our experience and skills to acquire new projects; and
•keep our organizational capabilities in line with our rate of growth.

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To accomplish our strategy, we intend to:
•Diversify our political risk:Acquire oil and natural gas fields in a number of countries to diversify and reduce the overall political risk of our investment portfolio.
• Seek Operational Andand Financial Control: We desire control of major decisions for development, production, staffing and financing for each project for a period of time sufficient for us to ensure maximum returns on investments.
 
 • Establish a Local Presence Through Joint Venture Partners and the Use of Local Personnel:We seek to establish a local presence in ourthe countries and areas of operationwe operate through joint venture partners to facilitate stronger relationships with local governmentgovernmental and labor.business relationships. In addition, usingwe use local personnel helpsto help us to take advantage of local knowledge and experience and to minimize costs. In pursuing new opportunities, we will seek to enter at an early stage and find local partners in an effort to reduce our risk in any one venture.
 
 • Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time:We are willing to agree to minimum capital expenditureexpenditures or development commitments at the outset of new projects, but we endeavor to structure such commitments so that we canto fulfill them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our

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maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure.

•  Limit Exploration Activities:We do not engage in exploration except in connection with the expansion of an existing reservoir and in that case only where the risks are deemed to be manageable in the context of total cash exposure and probability of success.
 
 •Provide Technical Expertise:We believe there is an advantage in being able to provide geological, geophysical and engineering expertise beyond what many companies or countries possess internally. In addition to our in-house technical capabilities, in January 2007 we acquired a minority interest in Fusion, a technical firm with significant experience in providing leading edge geophysical, geosciences and reservoir engineering services in many places in the world. Through this acquisition we have strategic access to these services.
• Maintain A Prudent FinancialFinancing Plan: We intend to maintain our financial flexibility by closely monitoring spending, holding significantsufficient cash reserves, minimizing the use of restricted cash, actively seeking opportunities to reduce our weighted average cost of capital and increasingincrease our liquidity.

Risk Factors

In addition to the other information set forth elsewhere in thisForm 10-K, the following factors should be carefully considered when evaluating us.

Our only source of production may be reduced by actions of the Venezuelan Government. Currently, the production from the South Monagas Unit in Venezuela represents all of our production. Our revenueaccess to debt and cash flow will be adversely affected if we are not allowed to produce under our contract crude oil and natural gas at our projected levels. Recent events have increased the likelihood of this event occurring.

          Under the operating service agreement Harvest Vinccler submits an annual budget to PDVSA for review and comment. Harvest Vinccler submitted to PDVSA its 2005 budget which provided for a $68 million drilling and facilities program. Under the terms of the operating service agreement this budget was deemed approved by PDVSA in November 2004. However, on December 17, 2004, Harvest Vinccler received letters from PDVSA seeking to reduce the 2005 drilling and facilities budget by over 60 percent and appearing to restrict average crude oil production for 2005 to about 20,400 barrels a day. At about the same time, Harvest Vinccler began to experience delays in the receipt of permits to drill new wells pursuant to its budget. In accordance with established procedures, Harvest Vinccler submitted requests to PDVSA to obtain permits from MEP for the drilling of eight wells. Only one of those requests was forwarded to the MEP. As a consequence of these delayed drilling permits, Harvest Vinccler began to run out of approved locations to continue its two-rig drilling program. On January 11, 2005, Harvest Vinccler formally notified one of its rig contractors that it would not be renewing its drilling contract and placed the rig on standby until January 29, 2005. Also, on January 11, 2005, Harvest Vinccler gave a thirty-day termination notice to the other rig company. On January 18, 2005, we announced that Harvest Vinccler was suspending its drilling program. In recent months, Harvest Vinccler has also experienced some operational interruptions in deliveries to PDVSA, although not of such a magnitude or duration as to affect production.

          It has been reported that PDVSA has also sought to cut the budgets between 30 percent and 90 percent of the other 31 active operating service agreements in Venezuela. In addition, Rafael Ramirez, the President of PDVSA and Minister of MEP, has stated that PDVSA wants to renegotiate the terms of the operating service agreements as they are too costly, and that five or six of the operating service agreements have serious problems. It has been reported that one of these agreements is the South Monagas Unit operating service agreement held by Harvest Vinccler. Mr. Ramirez has also said that PDVSA will honor its contracts.

          Collectively, these actions by the Venezuelan Government and PDVSA create a risk that our production will be reduced. Currently, Harvest Vinccler’s production has not been reduced, but if it is not allowed to conduct its drilling and facilities program, or if that program is restricted, then we will not meet our production forecasts and, over time, existing levels of production and available reserves will decline. While we believe such actions are not in accord with the operating service agreement, we and Harvest Vinccler are in discussions with Venezuelan officials and PDVSA to determine if these issues can be resolved through a mutually acceptable agreement. While we are hopeful of achieving a business solution, no assurance can be given that we will succeed or that the situation will not continue for an extended period of time. While we have substantial cash reserves, a prolonged curtailment of production or a failure or delay by PDVSA to pay our invoices could have a material adverse effect on our financial condition, results of operations and cash flows.

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Political uncertainty in Venezuela increases our exposure to production disruptions and project execution risk.Political and economic uncertainty is very high in Venezuela. From December 14, 2002 through February 6, 2003, PDVSA was unable to accept our oil due to the national civil work stoppage in Venezuela protesting the government of President Chavez. As a result, Harvest Vinccler’s 2002 oil deliveries were reduced by an estimated 0.6 million barrels and 2003 deliveries were reduced by an estimated 1.2 million barrels. In response to the national civil work stoppage, the Venezuelan government terminated several thousand PDVSA employees. As a result of the situation in PDVSA, its payment to Harvest Vinccler for crude oil delivered in the fourth quarter of 2002 was late by seven days. However, since then all other payments have been on time.

          Following the national work stoppage, President Chavez prevailed in a recall referendum. In addition, PDVSA has been reorganized a number of times, most recently in January 2005. The current President of PDVSA is also the Minister of MEP. The political situation in Venezuela adds to the risk that we will be able to enforce the operating service agreement in Venezuela and could lead to further civil unrest and work stoppages that could affect our ability to produce crude oil and natural gas. In addition, the increasing integration of PDVSA into the governmental structure adds legal and economic uncertainty to our continued operations. These same risk factors could also affect our ability to acquire new projects in Venezuela and the timing of those acquisitions.

Acquiring new oil projects in Venezuela depends upon our ability to meet the requirements of the Organic Hydrocarbon Law.New oil projects in Venezuela are governed by the Organic Hydrocarbon Law, which requires that such projects be carried out through incorporated joint ventures with majority ownership by governmental entities. It is our understanding that the MEP is still defining the methodology for the application of this law. While we believe it is possible to comply with this law and at the same time meet our criteria for new projects, no precedents exist and there is a risk we will be unable to achieve the desired result.

Our strategy to focus on Russia carries deal execution, operating, financial, legal and political risks.While we believe our established presence in Russia and our experience and skills from prior operations position us well for future projects, doing business in Russia also carries unique risks. The operating environment is often difficult and the ability to operate successfully will depend on a number of factors, including our ability to control the pace of development, our ability to apply “best practices” in drilling and development, and the fostering of relationships with Russian partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for Russian projects. In addition, the Russian legal system is not mature and its reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and gas projects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy in Russia depends on our ability to have operational and financial control. Recently, the Russian government has restricted certain “strategic” projects in Russia to majority-owned Russia companies. Such a policy, if widely applied, could adversely affect our ability to acquire projects in Russia consistent with our strategy.

Operations in areas outside the U.S. are subject to various risks inherent in foreign operations, and our strategy to primarily focus on Venezuela and Russia limits our country risk diversification.Our operations in areas outside the U.S. are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and governmental royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts or tribunals, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign policy, foreign trade, taxation and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States. Our strategy to focus on Venezuela and Russia concentrates our foreign operations risk and increases the potential impact to us of the operating, financial and political risks in those countries.

The loss of key personnel could adversely affect our ability to successfully execute our strategy.We are a small organization and depend on the skills and experience of a few individuals in key management and operating positions to execute our business strategy. Loss of one or more key individuals in the organization could hamper or delay achieving our strategy.

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The total capital required for development of new fields may exceed our ability to finance. Our future capital requirements for new projects may exceed the cash available from existing free cash flow and cash on hand. Our ability to acquire financing is uncertain and may be affected by numerous factors beyond our control, including the risks associated with our sole operations in Venezuela. Because of the financial risk factors in the countries in which we operate, we may not be able to secure either the equity or debt financing necessary to meet any future cash needs for investment, which may limit our ability to fully develop new projects, cause delays with their development or require early divestment of all or a portion of those projects.

Our current and future revenue is subject to concentrated counter-party risk.Our current operations in Venezuela rely on production fee payments from PDVSA for all revenue receipts. We do not own the hydrocarbons and do not sell oil and gas in open markets. Future projects in Venezuela, Russia and other countries may involve similar production fee payments from a limited number of companies or governments.

Our foreign operations expose us to foreign currency risk.Presently, our only operations are located in Venezuela. Venezuela continues to be considered a highly inflationary economy. Results of operations in that country are measured in U.S. Dollars with all currency gains or losses recorded in the consolidated statement of operations. There are many factors which affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan Bolivar to the U.S. Dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates. Our Venezuelan receipts are denominated in U.S. Dollars, and most expenditures are in U.S. Dollars as well. For a discussion of currency controls in Venezuela, seeCapital Resources and Liquiditybelow. Successful acquisition of projects in Russia may also expose us to foreign currency risk in that country.

Oil price declines and volatility could adversely affect our revenue, cash flows and profitability. Prices for oil fluctuate widely. The average price we received for oil in Venezuela increased to $18.90 per Bbl for the year ended December 31, 2004, compared with $14.07 per Bbl for the year ended December 31, 2003. In November 2003, we began selling natural gas in Venezuela under an addendum to our operating service contract at $1.03 per Mcf and Incremental Crude Oil at $7.00 per Bbl. While this diversifies our revenue stream, revenues, profitability and future rate of growth depend substantially upon the prevailing prices of oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to service our debt. In addition, we may have ceiling test write-downs when prices decline. Lower prices may also reduce the amount of oil that we can produce economically and lower oil production could affect the amount of natural gas we can produce. We cannot predict future oil prices. Factors that can cause this fluctuation include:

•  relatively minor changes in the global supply and demand for oil;
 
 •market uncertainty;Manage Exploration Risks. We seek to manage the higher risk of exploration by diversifying our prospect portfolio, applying state-of-the-art technology for analyzing targets and focusing on opportunities in proven active hydrocarbon systems with infrastructure.
 
 •the level of consumer product demand;
 •  weather conditions;
•  domesticEstablish Various Sources of Production. We seek to establish new production from our exploration and foreign governmental regulationsdevelopment efforts in a number of diverse markets and policies;
•  expect to monetize production through operations or the price and availabilitysale of alternative fuels;
•  political and economic conditions in oil-producing countries; and
•  overall economic conditions.assets.

Lower oilDiversification
          In 2005 and natural gas prices2006, we recognized the need to diversify our asset base as part of our strategy. Our strategy has broadened from our primary focus on Venezuela to identify, access and integrate hydrocarbon assets to include organic growth through exploration in basins globally with proven hydrocarbon systems. We seek to leverage our Venezuelan experience as well as our recently expanded business development and technical platform to create a diversified resource base. With the addition of technical resources, opening of our London office, the planned 2008 opening of a Singapore office, the redeployment of resources from our Moscow office as well as our earlier purchase of a 45 percent equity interest in Fusion, we have made significant investments to provide the necessary foundation and global reach required for an organic growth focus. Our organic growth is focused on undeveloped or downward adjustments tounderdeveloped fields, field redevelopments and exploration. While exploration will become a larger part of our reserves may cause us to record ceiling limitation write-downs. We use the full cost method of accounting to report our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties. The estimated future net cash flows include the impact of effective hedging activity as applicable. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down”. This charge does not impact cash flow from operating activities, but does reduce stockholders’ equity. The risk thatoverall portfolio, we will generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles. Exploration will be requiredtechnically driven with a low entry cost and high resource potential that provides sustainable growth. We will continue to write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downsseek opportunities where perceived geopolitical risk may occur if we experience substantial downward adjustments to our estimated proved reserves. We did not incur ceiling test write-downs in 2004provide high reward opportunities in the consolidated financial statementslong term. We will limit producing property acquisitions as market pricing of the wholly-owned and majority owned subsidiaries. Equity in Net Losses of Affiliated Companies

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proved producing reserves generally translates into low returns. Our WAB-21, South China Sea asset has been in our portfolio since 1996. Gabon and Indonesia are expected to be additions to our new strategy after receipt of government approvals.
WAB-21, South China Sea
          In December 1996, we acquired Crestone Energy Corporation, subsequently renamed Benton Offshore China Company. Its principal asset is a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under certain circumstances, and lies within an area which is the subject of a border dispute between the People’s Republic of China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The border dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the dispute. We continue to have meetings with CNOOC to monitor this situation and explore new business opportunities.
Dussafu Marin, Offshore Gabon
          In November 2007, we executed a sale and purchase agreement for the purchase of a 50 percent interest in the Dussafu PSC. All conditions precedent to the sale and purchase agreement are complete except for final government and partner approvals. We anticipate receiving final approvals during the first half of 2008. On receipt of final partner approval, we will become the operator of the Dussafu PSC. The purchase will be recorded in the quarter in which approvals are received. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC contains 680,000 acres with water depths to 1,000 feet. The Dussafu PSC has two small oil discoveries in the Gamba and Dentale reservoirs and a small natural gas discovery. Production and infrastructure exists in the blocks contiguous to the Dussafu PSC. The Dussafu PSC partners and the Republic of Gabon recently agreed to enter into the second exploration phase of the PSC with an effective date of May 28, 2007. The second exploration phase is a three-year work commitment which includes the acquisition and processing of 500 kilometers of 2-D seismic, geology and geophysical interpretation, engineering studies and the drilling of a conditional well. Leads in the underexplored syn-rift potential in the M’Baya and Lucina reservoirs that are commercial in immediately adjacent fields have been identified and are expected to be the focus of the planned 2008 work program which includes the acquisition and processing of 500 kilometers of 2-D seismic data. The Dussafu PSC partners anticipate prospects can be generated to test these play concepts in 2009.
Budong-Budong, Onshore Indonesia
          In February 2008, Indonesia’s oil and gas regulatory authority, BP Migas, approved the assignment to us of a 47 percent interest in the Budong PSC located onshore West Sulawesi, Indonesia. Final government approval from Migas is pending. The Budong PSC includes a $32.3 million (our share) ceiling test write-down recorded by Geoilbent during their fiscal year ended September 30, 2003.

Estimatesten-year exploration period and a 20-year development phase. In the initial three-year exploration phase, which began January 2007, we expect to acquire, process and interpret approximately 500 kilometers of oil2-D seismic and natural gas reserves are uncertain and inherently imprecise. This Form 10-K contains estimates of our proved oil and natural gas reserves anddrill two exploration wells. Tately will be the estimated future net revenues from such reserves. These estimates are based upon various assumptions, including assumptionsoperator through the exploration phase as required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. SeeOur only source of production may be reduced by actionsterms of the Venezuelan Government.

          The processBudong PSC. We will have control of estimating oil and natural gas reserves is complex. Such process requires significantmajor decisions and assumptionsfinancing for the project with an option to operate in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices, ability to deliver under the terms of our operating service agreement, approval of capital budgets and permits from PDVSA and other factors, many of which are beyond our control. Actual production, revenue, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used. Such variances may be material.

          At December 31, 2004, approximately 44 percent of our estimated Proved Reserves were undeveloped. Undeveloped reserves, by their nature, are less certain than developed reserves. The estimated future development cost increased by over $39 million to develop the Undeveloped Reserves. The estimates of our future reserves include the assumption that we will make significant capital expenditures to develop these reserves. Although we have prepared estimates of our oil and natural gas reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the results will be as estimated. SeeSupplemental Information on Oil and Natural Gas Producing Activities.

          You should not assume that the present value of future net revenues referred to is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in demand, our ability to produce or in governmental regulations, policies or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production phase if approved by BP Migas. The Budong PSC covers 1.35 million acres and includes the Lariang and Karama sub-basins which are the eastern onshore extension of the WSFB. Exploration to date in the basin is immature due to previously difficult jungle terrain, which is now accessible with the development of palm oil and gas properties will affect the timing of actual future net cash flows from estimated proved reservesplantations and their present value. In addition,related infrastructure. Field work performed over the last 10 percent discount factor, which is required byyears, as outcrops have been more accessible, has given a new understanding to the SEC to be used in calculating discounted future net cash flows for reporting purposes, ispresence of Eocene source and reservoir potential that had not necessarilypreviously been recognized. Recent seismic surveys have greatly improved the most accurate discount factor. The effective interest rate at various times and our risks or the risks associated with the oil and natural gas industry in general will affect the accuracyunderstanding of the 10 percent discount factor.

We may not be able to replace production with new reserves. In general, production ratesgeology and remaining reserves from oilenhanced the prospectivity of the offshore WSFB and, gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. Our reserves inby analogy, the South Monagas Unit in Venezuela will decline as they are produced unless we acquire additional properties in Venezuela, Russia or elsewhere with proved reserves or conduct successful exploration and development activities. Our future oil and natural gas production is highly dependent upon our levelsparsely explored onshore area. To date, a total of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive and uncertain. We may be unable to make the necessary capital investment to maintain or expand our oil and natural gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot assure you that our future exploration, development and acquisition activities will result in additional proved reserves or that weeight leads have been recognized. It will be ablenecessary to drill productive wells at acceptable costs.

Our operations are subjectacquire a grid of seismic data to numerous risksconfirm the structures and give an indication of oilEocene target(s) within the section and natural gas drillingto mature these leads into drillable prospects. The two identified sub-basins (Lariang and production activities.Oil and natural gas drilling and production activities are subjectKarama) provide an opportunity to numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is

test prospects in two sub-basins.

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often uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

•  unexpected drilling conditions;
•  pressure or irregularities in formations;
•  equipment failures or accidents;
•  weather conditions;
•  shortages in experienced labor;
•  delays in receiving necessary governmental permits;
•  shortages or delays in the delivery of equipment; and
•  delays in receipt of permits or access to lands.

          The prevailing price of oil also affects the cost of and the demand for drilling rigs, production equipment and related services. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs.

The oil and natural gas industry experiences numerous operating risks. These operating risks include the risk of fire, explosions, blow-outs, pump and pipe failures, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, natural gas leaks, pipeline ruptures and discharges of toxic gases. If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. We cannot predict the continued availability of insurance at premium levels that justify its purchase.

Competition within the industry may adversely affect our operations. We operate in a highly competitive environment. We compete with major and independent oil and natural gas companies for the acquisition of desirable oil and gas properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours.

Our oil and natural gas operations are subject to various governmental regulations that materially affect our operations. Our oil and natural gas operations are subject to various foreign governmental regulations. These regulations may be changed in response to economic or political conditions. Matters regulated may include permits for discharges of wastewaters and other substances generated in connection with drilling operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve or limit supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

Results of Operations

          We includeincluded the results of operations of Harvest Vinccler in our consolidated financial statements and reflectreflected the 20 percent ownership interest of Vinccler as a minority interest. We accounted for our investmentsinterest in Geoilbent2005 and Arctic Gas usingthe first quarter of 2006. Since April 1, 2006, equity investment in Petrodelta has been reflected under the equity method. We included Geoilbent and Arctic Gas in our consolidated financial statements based on a fiscal year ending September 30. Ourmethod of accounting. In the fourth quarter of 2007, we recorded the cumulative effect from April 1, 2006 to December 31, 2007. SeePart IV, Item 15, Notes to the Consolidated Financial Statements, Note 7 – Venezuela Operations – Petrodelta, S.A.for Petrodelta’s results of operations for the years ended December 31, 2003 and 2002which reflect the results of Geoilbent (until sold on September 25, 2003) and Arctic Gas (until sold on April 12, 2002) for the nine month period ending December 31, 2006 and the twelve months ended September 30, 2002.

          You should read themonth period ending December 31, 2007, comparatively.

          The following discussion ofshould be read with the results of operations for each of the years in the three-year period ended December 31, 20042007 and the financial condition as of December 31, 20042007 and 20032006 in conjunction with our Consolidated Financial Statements and related Notes thereto.

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Years Ended December 31, 2007 and 2006

          We have presented selected expense items from our consolidatedreported net income statement asof $57.2 million, or $1.51 diluted earnings per share, for 2007 compared with a percentagenet loss of revenue in$62.5 million, or $1.68 diluted earnings per share, for 2006.
          Revenue recorded for the following table:
             
  Years Ended December 31, 
  2004  2003  2002 
Operating Expenses  18%  29%  27%
Depletion, Depreciation and Amortization  19   20   21 
General and Administrative  12   15   13 
Taxes Other Than on Income  3   3   3 
Interest  4   10   13 

Yearsyear ended December 31, 20042007 reflects the reversal of deferred revenue recorded by Harvest Vinccler for 2005 and 2003

          Net income for 2004 was $34.4 million, or $0.90 per diluted share, compared with $27.3 million, or $0.74 per diluted share for 2003.

          Our resultsfirst quarter of operations for 2004 primarily reflected2006 deliveries pending clarification on the results for Harvest-Vinccler in Venezuela, which accounted for allcalculation of our productioncrude prices under the Transitory Agreement. SeePart IV, Item 15, Notes to the Consolidated Financial Statements, Note 1 – Organization and Summary of Significant Account Policies – Revenue Recognition. There were no sales of oil and natural gas sales revenue. Oil revenue per barrel increased 34 percent (from $14.07 in 2003 to $18.90 in 2004) and oil sales quantities increased 11 percent (from 7.3 MBbls of oil in 2003 to 8.2 MBbls of oil in 2004) during 2004 compared with 2003. Natural gas sales quantities for 2004 from Venezuela were 31.1 Bcf. Revenue for 2004 includes 0.7 MBbls of oil at a $7.00 fixed price associated with the gas sales contract.

          Our revenues increased $80.0 million, or 75 percent, during 2004 compared with 2003. This was2007 due to the additionconversion of a full year of natural gas sales ($29.3 million), higher oil volumes ($7.7 million) and higher crude oil prices ($43.0 million). Our sales quantities for 2004 from Venezuela were 13.3 MBoe compared with 7.8 MBoe in 2003. The increase in sales quantities of 5.5 MBoe, or 71 percent, was duethe OSA to a full year of natural gas production. Crude oil volumes for 2004 were also higher as 2003 was affected by the shut-in of the productionminority equity interest in Venezuela from December 2002 to February 2003 due to the national work stoppage.

          Our operatingPetrodelta.

Total expenses increased $2.4 million, or 8 percent, for 2004 compared with 2003. This was primarily due to higher production volumes, higher workover and maintenance programs and increased insurance costs. Depletion, depreciation and amortization increased $14.8 million, or 70 percent, during 2004 compared with 2003 due to increased oil and gas production from Venezuela. Depletionother non-operating (income) expense per barrel of oil produced from Venezuela during 2004 was $2.56 compared with $2.52 during 2003. The increase was primarily due to increased future development costs. We recognized write-downs of $0.2 million for additional capitalized costs associated with former exploration projects during 2003.(in millions):
             
  Year Ended  
  December 31, Increase
  2007 2006 (Decrease)
General and administrative $29.7  $26.4  $3.3 
Contribution to Science and Technology Fund  —   3.9   (3.9)
Taxes other than on income  0.4   3.9   (3.5)
Gain on financing transactions  (49.6)  —   (49.6)
Investment income and other  (9.1)  (9.4)  0.3 
Interest expense  8.2   23.2   (15.0)
Net (gain) loss on exchange rates  —   0.1   (0.1)
          General and administrative expenses increased $6.1 million, or 39 percent, for 2004 compared with 2003. This was, in part, due to severance payments for a number of employees paid in the second quarter of 2004, the write-off of project evaluation costs associated with projects in Russia, restricted stock bonuses recorded in the third quarter 2004, additional costs associated with Sarbanes-Oxley compliance and an increase in liability under our deferred compensation plan for directors. An arbitration settlement of $1.5 million was recorded in 2003, and bad debt recoveries of $0.6 million and $0.4 million were recorded in 2004 and 2003, respectively,employee related to an allowance for uncollectible accounts in prior years.

          Taxes other than on income increased $2.2 million, or 65 percent, during 2004 compared with 2003. This was primarily due to increased Venezuelan municipal taxes which result from higher oil and gas revenues.

          Investment income and other increased $0.7 million, or 47 percent, during 2004 compared with 2003. This was due to higher interest rates earned on average cash balances. Interest expense decreased $2.7 million, or 26 percent, during 2004 compared with 2003 due to lower average outstanding debt balances for 2004 compared to 2003. In 2004, we redeemed all $85 million of our 2007 Notes, and we repaid all Bolivar denominated debt in March 2003.

          Net gain (loss) on exchange rates decreased $1.2 million, or 218 percent, for 2004 compared with 2003. This was due to the significant devaluation of the Bolivar and Bolivar currency controls imposed in February 2003 which fixed the exchange rate between the Bolivar and the U.S. Dollar and restricts the ability to exchange Venezuelan Bolivars for dollars and vice versa.

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          We realized income before income taxes and minority interest of $81.3 million during 2004 compared with income of $71.8 million in 2003. The increase was primarily attributable to higher crude oil and natural gas volumes and an increase in crude oil price in 2004expenses offset by lower contract services. During the sale of our minority equity investment in Geoilbent in 2003. Income tax expense increased $23.6 million due to higher Venezuela pre-tax income. The effective tax rate increased from 13 to 41 percent for 2004 compared with 2003. The rate increase was due to foreign income taxes incurred on profitable foreign operations in 2004. The sale of our minority equity investment in Geoilbent in 2003 was offset by U.S. loss carryforwards. The income before minority interest decreased $14.2 million for 2004 compared with 2003. This decrease was due to the sale of our minority equity investment in Geoilbent partially offset by increased production of Harvest Vinccler.

          Equity in net losses of affiliated companies decreased $28.9 million during 2004 compared to 2003. This was due to the elimination of Geoilbent equity losses on September 25, 2003, the date of its sale.

Yearsyear ended December 31, 20032007, we recorded a gain of $49.6 million as a result of the purchase and 2002

          Net income for 2003 was $27.3 million, or $0.74 per diluted share, compared with $100.4 million, or $2.78 per diluted share, for 2002. The $27.3 million net income included the gain from the sale of our minority equity investment in Geoilbent of $46.6 million, $0.4 million partial recovery of a bad debt and $1.5 million arbitration settlement related to an allowance for uncollectible accounts in prior years. Operating and general and administrative expenses were reduced by $3.8 million, or almost 8 percent, compared with 2002.

          Our results of operations for 2003 primarily reflected the results for Harvest Vinccler in Venezuela, which accounted for all of our production and oil and gas sales revenue. Oil revenue per barrel increased 8 percent (from $13.05 in 2002 to $14.07 in 2003) and oil sales quantities decreased 24 percent (from 9.7 MBbl of oil in 2002 to 7.3 MBbl of oil in 2003) during 2003 compared with 2002. Gas sales began on November 25, 2003, at the contract rate of $1.03 per Mcf. Incremental Crude Oil sales began on the same date at a fixed price of $7.00 per barrel. Total gas sales were 2.7 Bcf for the period. Revenue for 2003 includes 0.1 MMBbls of oil at the $7.00 fixed price associated with the gas sales contract.

          Our revenues decreased $20.6 million, or 16 percent, during 2003 compared with 2002. This was primarily due to lower production offset by higher world crude oil prices. Our sales quantities for 2003 from Venezuela were 7.8 MBoe compared with 9.7 MBoe in 2002. The decrease in sales quantities of 1.9 MBoe, or 20 percent, was dueU.S. Dollar indexed Venezuelan government bonds (seePart IV, Item 15, Notes to the Venezuelan national civil work stoppage which led to the shut-in of our production from December 2002 to February 2003, natural reservoir decline rates and the fact that some wells did not immediately return to previous production levels following the national work stoppage.

          Our operating expenses decreased $3.1 million, or 9 percent, for 2003 compared with 2002. This was primarily due to lower production volumes partially offset by higher workover and maintenance programs that continuedConsolidated Financial Statements, Note 12 – Gain on Financing Transaction). There were no such financing transactions entered into during the Venezuelan national civil work stoppage. Depletion, depreciation and amortization decreased $5.2 million, or 20 percent, during 2003 compared with 2002 primarily due to decreased production from Venezuela and the addition of natural gas reserves in 2002. Depletion expense per barrel of oil produced from Venezuela during 2003 was $2.52 compared with $2.56 during 2002. The decrease was primarily due to reduced future development costs. We recognized write-downs of $0.2 million for additional capitalized costs associated with former exploration projects during 2003 compared with $13.4 million for the impairment of the China WAB-21 block and $1.1 million for the Lakeside Prospect exploration activities during 2002. General and administrative expenses decreased $0.8 million from 2002 to 2003. An arbitration settlement of $1.5 million and a bad debt recovery of $0.4 million were recorded in the third quarter of 2003, and a bad debt recovery of $3.3 million was recorded in the third quarter of 2002 related to an allowance for uncollectible accounts in prior years.

year ended December 31, 2006. Taxes other than on income decreased $0.7 million, or 17 percent, during 2003 compared with 2002. This was primarily due to decreased Venezuelanthe elimination of municipal taxes which result from lowerwere based on oil revenues partially offset by a one-time adjustment of U.S. employment taxes of $0.7 million in 2002.

deliveries under the OSA.

          Investment incomeearnings and other decreased $0.7 million, or 32 percent, during 2003 compared with 2002. This was due to lower interest rates earned on averagelower cash and marketable securities balances. Interest expense decreased $5.9 million, or 36 percent, during 2003 compared with 2002 due to lower average outstandingthe payment of Harvest Vinccler’s Bolivar denominated debt

in the year ended December 31, 2007.
          Income tax expense decreased due to the recording of Harvest Vinccler’s prior period tax assessments in the year ended December 31, 2006 and the reversal of deferred income taxes provided on Harvest Vinccler’s deferred revenue. We have utilized our current United States general and administrative expenses plus our net operating loss carryovers to offset the gains on financing transactions generated during the year ended December 31, 2007. There was no effect on our effective tax rate.

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balances

Years Ended December 31, 2006 and 2005
          We reported a net loss of $62.5 million, or $1.68 diluted earnings per share, for 20032006 compared with 2002. In 2002, we redeemed all $108 millionnet income of our 11.625 percent Senior Notes due in May 2003 and purchased $20 million face of the 9.375 percent Senior Notes due in November 2007. In October 2002, we borrowed $15.5 million to finance the construction of the gas pipeline in Venezuela from the Uracoa field to the PDVSA sales line, and we repaid all Bolivar denominated debt in March 2003.

          Net gain on exchange rates decreased $4.0$38.9 million, or 88 percent,$1.05 diluted earnings per share, for 20032005.

          Revenues were lower for the year ended December 31, 2006 compared with 2002. This wasthe year ended December 31, 2005 due to the significant devaluationconversion of the BolivarOSA to a minority equity interest in Petrodelta.
Total expenses and Bolivar currency controls imposed in February 2003other non-operating (income) expense (in millions):
             
  Year Ended  
  December 31, Increase
  2006 2005 (Decrease)
General and administrative $26.4  $22.8   3.6 
Contribution to Science and Technology Fund  3.9   —   3.9 
Account receivable write-off on retroactive oil price adjustment  —   4.5   (4.5)
Taxes other than on income  3.9   6.4   (2.5)
Investment income and other  (9.4)  (4.2)  (5.2)
Interest expense  23.2   3.4   19.8 
Net (gain) loss on exchange rates  0.1   (2.8)  2.9 
          General and administrative expenses increased due to higher business development costs and employee related expenses. Taxes other than on income decreased due to the elimination of municipal taxes as a result of the conversion of the OSA to Petrodelta. Interest expense increased due to Harvest Vinccler’s estimated liability for interest of $52.9 million on the tax assessments as well as increased borrowings to pay the tax assessments.
          In October 2006, the Executive Branch of the Venezuelan government issued the Regulations for the Science and Technology Law which fixedestablished the exchange rate betweenmethodology for determining the Bolivarrequired investment, contribution or expenditure for the 2005 calendar year financial results. After release of the regulations, Harvest Vinccler accrued $3.9 million for the estimated liability for 2005 and the U.S. Dollarfirst quarter of 2006 based on its current understanding of the regulations.
Capital Resources and restrictsLiquidity
          While we can give no assurance, we currently believe that Petrodelta will fund its own operations and pay a dividend prior to December 31, 2008, and that our cash on hand will provide sufficient capital resources and liquidity to fund our exploration and business development expenditures for the next 12 months. InItem 1A – Risk Factors, we discuss a number of variables and risks related to our investment in Petrodelta and exploration projects that could significantly affect our capital resources and liquidity. These risk factors include, but are not limited to, delays or inability of PPSA to pay for past and future crude oil and natural gas deliveries, the ability to exchange Venezuelan Bolivarsimplement Petrodelta’s Business Plan, changes in oil prices, fiscal and contractual stability, payment of a Petrodelta dividend and the ability to obtain financing for dollarsother projects. We also point out that the total capital required to develop the fields in Venezuela may exceed Petrodelta’s available cash and vice versa.

          We realized income before income taxesfinancing capabilities, and minority interestthat there may be operational or contractual consequences to this inability. In addition, our ability to explore and develop growth opportunities outside of $71.8 million during 2003 compared with income of $169.8 million in 2002. The decrease was primarily attributableVenezuela is dependent upon the ability to the Arctic Gas Sale in 2002 offset by the sale of our minorityreceive dividends from Petrodelta and access debt and equity investment in Geoilbent in 2003. Income tax expense decreased $50.6 million due to lower pre-tax income. The effective tax rate decreased from 36 to 13 percent for 2003 compared with 2002. The rate decrease was due to an increase in U.S. income with no corresponding U.S. taxes because they were offset by U.S. operating loss carryforwards for which the benefit was fully reserved in historical periods. The income before minority interest decreased $47.4 million for 2003 compared with 2002. This decrease was due to the sale of our minority equity investment in Geoilbent partially offset by decreased production of Harvest Vinccler.

          Equity in net losses of affiliated companies decreased $29.0 million during 2003 from income of $0.2 million in 2002 to a loss of $28.9 million in 2003. This was primarily due to full cost ceiling test writedowns of $32.3 million (our share) and decreased income from Geoilbent. SeeNote 9 – Russian Operations. The year ended 2002 included a loss of $1.5 million on Arctic Gas.

Capital Resources and Liquidity

markets.

          The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks (seeItem 1A — Risk Factors)Factors). We require capital principally to service debt and to fund the following costs:exploration and development of new oil and gas properties.
          On February 5, 2003, Venezuela imposed currency controls and created the Commission for Administration of Foreign Currency with the task of establishing the detailed rules and regulations and generally administering the exchange control regime. These controls fix the exchange rate between the Bolivar and the U.S. Dollar and restrict the ability to exchange Bolivars for U.S. Dollars and vice versa. The Bolivar is not readily convertible into the U.S. Dollar. We do not expect the Venezuelan currency conversion restriction to adversely affect our ability to meet short-term loan obligations and operating requirements for the foreseeable future.

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•  drilling and completion costs of wells and the cost of production, treating and transportation facilities;
•  geological, geophysical and seismic costs; and
•  acquisition of interests in oil and gas properties.

          In March 2007, Venezuela announced that effective January 1, 2008, the currency unit of the monetary system of Venezuela will be redenominated to the equivalent of 1,000 current Bolivars. This means that the Bolivar dropped three zeros effective January 1, 2008. From January 1, 2008, all amounts of money became denominated in a new and smaller scale of Bolivars under the temporary name of Bolívares Fuertes, which after a period of time will bear again the name of Bolivars.
          The amount of available capital will affect the scope of our operations and the rate of our growth. Our future rate of capital resource and liquidity growth also depends substantially upon the prevailing prices of oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to service our debt.

          On February 5, 2003, the Government of Venezuela fixed the exchange rate between the Bolivar and the U.S. Dollar, and restricted the ability to exchange Venezuelan Bolivars for U.S. Dollars and vice versa. Initially the exchange rate was fixed at 1,600 Venezuelan Bolivars for each U.S. Dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. Dollar. Oil companies, such as Harvest Vinccler are allowed to receive payments for oil sales in U.S. Dollars and pay U.S. Dollar-denominated expenses from those payments. We have substantial cash reserves and do not expect the Venezuelan currency conversion restriction to adversely affect our ability to meet our short-term loan obligations and operating requirements for the next twelve months.

expenditures. Our ability to replace production with new reservesacquire and develop growth opportunities outside of Venezuela is dependent upon the ability ofto receive dividends from Petrodelta and access debt and equity markets.

Debt.At December 31, 2007, Harvest Vinccler to make loan repayments, dividends and other cash payments to us. However, there have been, and may again be, interruptions in oil and gas sales or there may be contractual obligations or legal impediments to receiving dividends or distributions from Harvest Vinccler, which could affect the ability of Harvest Vinccler to remit funds to us.

Debt Reduction.In September 2004, we announced that the remaining 2007 Notes would be redeemed on November 1, 2004, and we irrevocably deposited with the Trustee for the 2007 Notes as trust funds $85.0 million plus accrued interest through November 1, 2004 and a prepayment call premium of $1.3 million to redeem the 2007 Notes on the redemption date. We were released from all obligations related to the 2007 Notes upon deposit of the trust funds with the Trustee. We recorded a loss on early extinguishment ofhas debt of $2.920 billion Bolivars (approximately $9.3 million) which is secured by $6.8 million which includes the $1.3 million prepayment call premium, $0.7 million for interest related to the period October 1, 2004 to

24

November 1, 2004 and $0.9 million write-off of unamortizedin restricted cash deposited in a U.S. bank. We have no other debt financing costs. Our repayment of the 2007 Notes triggered an obligation under the terms of Harvest Vinccler’s loans from a Venezuelan commercial bank to renegotiate the terms of those loans or, if agreement on renegotiated terms cannot be reached within 30 days after November 1, 2004, the loans can be declared due and payable. Harvest Vinccler is in discussions with the Venezuelan bank on possible renegotiated terms. While we believe the loans will be renegotiated, it is possible that agreement will not be reached and Harvest Vinccler will be required to repay the remaining balance of $11.8 million. As of February 11, 2005, no agreement had been reached.

obligations.

          Working Capital.Our capital resources and liquidity are affected by the receiptability of the quarterly payments from PDVSA at the end of the months of February, May, August and November pursuantPetrodelta to the terms of the operating service agreement for the South Monagas Unit. As a consequence of the timing of the PDVSA payment inflows, our cash balances can increase and decrease dramatically on a few dates during the year.

          Harvest Vinccler’s oil and gas pipeline project loans of $11.8 million allow the lender to accelerate repayment if production ceases for a period greater than thirty days. A future disruption of production could trigger the debt acceleration provision.

pay dividends.

          The net funds raised and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:
                        
 Year Ended December 31,  Year Ended December 31, 
 (in thousands)    (in thousands except as indicated) 
 2004 2003 2002  2007 2006 2005 
Net cash provided by operating activities $74,140 $38,538 $42,627 
Net cash provided by (used in) operating activities $(20,451) $(24,448) $114,665 
Net cash provided by (used in) investing activities  (39,684) 38,191 126,143  69,756  (90,556)  (15,647)
Net cash used in financing activities  (88,516)  (2,570)  (113,293)
Net cash provided by (used in) financing activities  (76,543) 100,064  (20,599)
              
Net increase (decrease) in cash $(54,060) $74,159 $55,477  $(27,238) $(14,940) $78,419 
              
 
Working Capital 111,534 117,564 178,074 
Current Ratio 3.6 2.4 3.9 
Total Cash, including restricted cash 127,610 236,968 163,019 
Total Debt 9,302 104,651 5,467 
Percent of total debt to capitalization  3%  27%  2%

          At December 31, 2004, we had current assets of $172.2 million and current liabilities of $83.2 million, resulting in working capital of $89.0 million and a current ratio of 2:1. This compares with a working capital of $137.2 million and a current ration of 4:1 at December 31, 2003.

          The decrease in working capital of $48.2$6.0 million was primarily due to the prepaymentinability to reflect a dividend from Petrodelta or collect the advances made by Harvest Vinccler to PDVSA in our consolidated financial statements for the year ended December 31, 2007 and the charge in the second and third quarters of 2006 of $73.8 million for additional taxes and related interest for the 2007 Notes offsetimpact of income tax assessments by higher crude oil prices and an increase in crude oil and natural gas sales in Venezuela.

the SENIAT for 2001 through first quarter of 2006.

Cash Flow from Operating Activities. During the years ended December 31, 20042007 and 2003,2006, net cash provided byused in operating activities was approximately $74.1$20.5 million and $38.5$24.4 million, respectively. The $35.6$3.9 million increasedecrease was primarily due to naturalthe collection of accrued oil and gas sales higher crude oil prices andreceivable in the salefirst quarter of our California onshore property,2006 which was offset by the charge in the second and third quarters of 2006 for the estimated tax assessments and related interest, as well as our inability to reflect a dividend from Petrodelta or collect the advances made by Harvest Vinccler’s purchaseVinccler to PDVSA beginning with the second quarter of two WTI crude oil puts and the loss of $2.9 million on the early repayment of the 2007 Notes. As of September 30, 2004, we no longer have an obligation to make annual interest payments of approximately $8.0 million on the 2007 Notes.

2006.

          Cash Flow from Investing Activities.During the years ended December 31, 20042007 and 2003,2006, we had drilling andlimited production-related capital expenditures of approximately $39.1 million and $60.9 million, respectively.expenditures. The decreasereduction in capital expenditures iswas due to the completioncontinued suspension of our gas project in 2003drilling program and the timingfact that our producing properties are now recognized under the equity method of our 2004 Uracoa drilling program. The year ended 2003 includedaccounting. We continued to advance funds during the receiptperiod prior to the formation of $69.5 million fromPetrodelta for maintenance of the saleexisting wells. After the formation of our minority equity investment in Geoilbent.

          The timing and size of capital expenditures for the South Monagas Unit are largely at our discretion, although PDVSA has recently attempted to limit Harvest Vinccler’s capital spending (seeRisk Factors). Our remainingPetrodelta, capital commitments worldwidefor Petrodelta will be determined by the Business Plan provided for in the Conversion Contract and the annual budget approved by the Petrodelta Board of Directors to implement the Business Plan. Outside of Venezuela, our capital commitments to date support our search for new acquisitions, are relatively minimal

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business development efforts and are substantially at our discretion. We continueDuring the year ended December 31, 2007, we invested $4.1 million of investigatory costs in support of our business development.
          In January 2007, we purchased a 45 percent interest in Fusion for $4.6 million and HNR Finance funded its 40 percent share of Petrodelta for $2.8 million. During the year ended December 31, 2006, we deposited cash of $94.5 million as collateral for four loans with Venezuelan banks, of which $5.6 million had been returned to assess production levelsus. By December 31, 2006, the restricted cash balance was $88.9 million. During the year ended December 31, 2007, $82.1 million of the restricted cash was released and commodity prices in conjunction with our capital resources and liquidity requirements.

returned to us.

          Cash Flow from Financing Activities.During the year ended 2004, we irrevocably deposited with the Trustee for ourDecember 31, 2007, Notes as trust funds $85.0 million plus accrued interest through November 1, 2004 and a prepayment call premium of $1.3 million to redeem the 2007 Notes on the redemption date. During the same period, Harvest Vinccler repaid $6.4 million205 billion Bolivars (approximately $95.3 million) of its U.S. DollarBolivar denominated debt. Harvest Vinccler repaid the debt using a series of exchange transactions more fully described inPart IV, Item 15, Notes to the Consolidated Financial Statements, Note 12 – Gain on Financing Transactions. During the year ended 2003,December 31, 2006, Harvest Vinccler

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repaid all of its borrowed 11 billion Bolivars (approximately $5.0 million) for short term Bolivar denominated debt ($2.2obligations, 105 billion Bolivars (approximately $48.8 million) and $1.220 billion Bolivars (approximately $9.3 million) for the SENIAT income tax assessments and related interest and 120 billion Bolivars (approximately $55.8 million) for the SENIAT income tax assessments and related interest, to refinance previous borrowings and for operational needs. Also during the year ended December 31, 2006, Harvest Vinccler repaid $5.5 million of its U.S. Dollar debt which was(one payment of $0.3 million and four payments of $1.3 million each on the variable rate loans) and 31 billion Bolivars (approximately $14.3 million) of its Bolivar debt.

          In June 2007, we announced that our Board of Directors had authorized the purchase of up to $50 million of our common stock from time to time through open market transactions. As of December 31, 2007, 3.0 million shares had been purchased under the program for $32.8 million, or an accelerationaverage cost of the next two principal payments.

$11.09 per share, including commissions. At December 31, 2007, we had approximately 34.8 million shares outstanding.

Contractual Obligations.Obligations
We have a lease obligation of approximately $17,000 per month for our Houston office space. This lease runs through April 2014. In addition, Harvest Vinccler leased newhas lease obligations for office space in Maturin and Caracas, Venezuela for $13,200 andapproximately $4,000 per month, respectively. The Board of Directors Deferred Compensation Plan atmonth. This lease runs through December 31, 2004 represents 106,000 phantom stock shares with an aggregate liability of $1.8 million, or $17.27 per share, based on the December 31, 2004 stock price.2009.
                                        
 Payments (in thousands) Due by Period  Payments (in thousands) Due by Period 
 Less than After 4  Less than After 4 
Contractual Obligation Total 1 Year 1-2 Years 3-4Years Years  Total 1 Year 1-2 Years 3-4 Years Years 
Long-Term Debt $11,833 $11,833 $— $— $—  $9,302 $9,302 $— $— $— 
Building Lease 3,117 415 421 388 1,893  1,795 342 333 216 904 
                      
Total $14,950 $12,248 $421 $388 $1,893  $11,097 $9,644 $333 $216 $904 
                      

          While we can give no assurance, we currently believe that our cash flow from operations coupled with our cash on hand will provide sufficient capital resources and liquidity to fund our planned capital expenditures, investments in and advances to affiliates, and quarterly interest payment obligations for the next 12 months. Our expectation is based upon our current estimate of projected prices, production levels, and our assumptions that we will be allowed to carry out our capital program on acceptable terms, that there will be no disruptions or limitations on our production and that PDVSA will pay our invoices timely. Actual results could be materially affected if there is a significant change in our expectations or assumptions (seeRisk Factors). Future cash flows are subject to a number of variables including, but not limited to, the level of production and prices, as well as various economic and political conditions that have historically affected the oil and natural gas business. Additionally, prices for oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond our control.

Effects of Changing Prices, Foreign Exchange Rates and Inflation

          Our results of operations and cash flow are affected by changing oil prices. Fluctuations in oil prices may affect our total planned development activities and capital expenditure program. In August and September 2004, Harvest Vinccler hedged a portion of its oil sales for calendar year 2005 by purchasing two WTI crude oil puts. SeeNote 1 – Derivatives and Hedging.

          As noted above underCapital Resources and Liquidity, Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004.2004 and again in March 2005. We do not expect the currency conversion restrictions or the adjustment in the exchange rate to have a material impact on us at this time.

Dividends from Petrodelta will be denominated in U.S. Dollars when paid. Within the United States, inflation has had a minimal effect on us, but it is potentially an important factor inwith respect to results of operations in Venezuela. With respect to Harvest Vinccler, a significant majority

          In March 2007, Venezuela announced that effective January 1, 2008, the currency unit of the sourcesmonetary system of funds, includingVenezuela will be redenominated to the proceeds from oil sales, our contributions and credit financings, areequivalent of 1,000 current Bolivars. This means that the Bolivar will drop three zeros effective January 1, 2008. From January 1, 2008, all amounts of money will become denominated in U.S. Dollars, while a minor amountnew and smaller scale of local transactions in Venezuela are conducted in local currency. IfBolivars under the ratetemporary name of increase inBolívares Fuertes, which after a period of time will bear again the valuename of the U.S. Dollar compared with the Bolivar continues to be less than the rate of inflation in Venezuela, then inflation could be expected to have an adverse effect on Harvest Vinccler.Bolivars.

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          During the yearyears ended December 31, 2004,2007 and 2006, our net foreign exchange lossgains attributable to our international operations was $0.6 million.were minimal. The U.S. Dollar and Bolivar exchange rates were fixed in February 2003 andhave not been adjusted in February 2004. No gains or losses were recognized from February 2003 to February 2004.since March 2005. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, manymost of which are beyond our control. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan currency to the U.S. Dollar. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.

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          An exemption under the Venezuelan Criminal Exchange Law for transactions in certain securities results in an indirect securities transaction market of foreign currency exchange, through which companies may obtain foreign currency legally without requesting it from the Venezuelan government. Publicly available quotes do not exist for the securities transaction exchange rate but such rates may be obtained from brokers. Securities transaction markets are used to move financial securities in and out of Venezuela.

          In October 2007, the government of Venezuela announced the application of a new tax on financial transactions (the “TFT”) to private companies. The TFT does not apply to individuals. The tax was set at 1.5 percent of the value of the transaction. The TFT applies to all debits to bank accounts as well as payments of debt outside the banking system and is not tax deductible. The levy will be applied from November 1, 2007 through December 31, 2008. The TFT will not have a material effect on Harvest Vinccler’s financial position, results of operations or cash flows.
Critical Accounting Policies

Principles of Consolidation

          The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. The equity method of accounting is used for companies and other investments in which we have significant influence. All intercompany profits, transactions and balances have been eliminated. We accounted
Investment in Equity Affiliates
          The equity method of accounting is used for our investmentcompanies and other investments in Geoilbentwhich we have significant influence. In January 2007, we purchased a 45 percent equity interest in Fusion. In October 2007, Petrodelta was formed, and Arctic Gas based on a fiscal year ending September 30 priorthe equity in earnings from April 1, 2006 to their respective sales.

          OilDecember 31, 2007 is reflected in the fourth quarter of 2007 consolidated statement of operations. These investments are increased or decreased by earnings/losses and natural gas revenue is accrued monthly based on sales. Each quarter, Harvest Vinccler invoices PDVSA based on barrels of oil accepteddecreased by PDVSA during the quarter, using quarterly adjusted U.S. Dollar contract service fees per barrel.

dividends paid. No dividends were declared or paid by Fusion or Petrodelta in 2007.

Property and Equipment

          We follow

          In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method. Although the full cost method of accounting for oil and gas properties with costs accumulated in cost centers on a country-by-country basis. All costs associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized as incurred, including exploration overhead. Only overhead that is directly identified with acquisition, exploration or development activities is capitalized. All costs relatedcontinues to production, general corporate overhead and similar activities are expensed as incurred. The costs for China unproved properties are excluded from amortization until the properties are evaluated. At least annually, we evaluate our unproved property for possible impairment. If we abandon all exploration efforts in China where no proved reserves are assigned, all exploration and acquisition costs associated with the country will be expensed. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty.

          The full costan accepted method of accounting uses proved reserves in the calculation of depletion, depreciation and amortization. Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data, economic changes and other relevant developments. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place. Changes in previous estimates of proved reserves result from new information obtained from production history, changes in economic factors and other relevant developments. A large portion of our proved reserves base from consolidated operations is comprised of oil and gas properties, that are sensitivethe successful efforts method of accounting as prescribed by SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies is the preferred method. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 154 Accounting Changes and Error Corrections, financial information for prior periods has been restated to oil price volatility.reflect retrospective application of the successful efforts method. We are susceptiblebelieve the successful efforts method provides a more transparent representation of our results of operations and the ability to significant upward and downward revisions toassess our Proved Reserve volumes and values as a result of changesfuture investments in year end oil and gas properties for impairment based on their estimated fair values rather than being required to base valuation on prices and costs as of the corresponding adjustment to the projected economic life of such properties. Pricesbalance sheet date.  The significant differences between successful efforts and full cost accounting for oil and gas are likelyproperties relate to continuethe expensing of exploration activities and related unsuccessful exploratory drilling activities. The expensing of these costs can create volatility in the statement of operations. The change in accounting principle resulted in a cumulative, non-cash increase to be volatile, resulting in future revisionretained earnings of $52.4 million, net of income tax, as of December 31, 2004. Retained earnings increased due to our Proved Reserve base. We perform a quarterly cost centerthe reversal of ceiling test of our oil and gas propertieswrite downs in prior years required under the full cost accounting rules of the SEC. These rules generally require that we price our future oilThere were no such impairments under the successful efforts accounting rules. The effect of the accounting change on income from continuing operations for the years ended December 31, 2006 and gas production at the oil2005 was a decrease of $4.9 million and gas prices$15.0 million, net of income tax, or $0.13 and $0.39 per diluted share, respectively. The decrease in effect at the end of each fiscal quarter and require a write–down if our capitalized costs exceed this “ceiling,” even if prices declined for only a short period of time. We have had no write-downs due to these ceiling test limitations since 1998 other than the write-downs recorded by our equity affiliates. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved reserves will change in the near term. If oil and gas prices decline significantly in the future, even if only for a short period of time, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities.

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income from continuing operations was due to an increase in depletion expense. There was no effect on cash and cash equivalents.
          Oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
          Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. Exploratory drilling costs are capitalized when drilling is complete if it is determined that there is economic producibility supported by either actual production, conclusive formation test or by certain technical data. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the projects is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in production of natural gas and crude oil, are capitalized.
          Depreciation, depletion, and amortization of the cost of proved oil and natural gas properties are calculated using the unit of production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. With respect to lease and well equipment costs, which include costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.
          Assets are grouped in accordance with paragraph 30 of SFAS No. 19 Financial Accounting and Reporting by Oil and Gas Producing Companies. The basis for grouping is reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
          Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.
          We account for impairments under the provisions of SFAS No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.
          Inventory held for use in the exploration for and development and production of natural gas and crude oil reserves are carried at cost with adjustments made from time to time to recognize any reductions in value.
Income Taxes

          Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

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Foreign Currency

          Our current operations are in Venezuela.

          The U.S. Dollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in U.SU.S. Dollars, and all currency gains or losses are recorded in the statement of operations. We attempt to manage our operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We have recognized significant exchange gains and losses in the past resulting from fluctuations in the relationship of the Venezuelan Bolivar to the U.S. Dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates.

New Accounting Pronouncements

          In December 2004,February 2008, the FinancialFASB issued FASB Staff Position (“FSP”) 157-1 – Application of FASB Statement No. 157 to FASB Statement No. 13 and Its Related Interpretive Accounting Standards BoardPronouncements That Address Leasing Transactions (“FASB”) issued Statement of Financial Accounting Standard 123 (revised 2004) Share-Based Payment (“SFAS 123R”FSP 157-1”), an amendment to Statement ofwhich excludes SFAS 13 Accounting Standards 123for Leases, and 95. SFAS 123R focuses primarily onits related interpretive accounting for transactions in which an entity obtains employee services in share-based payment transactions. Public companies with a calendar year end will be required to adoptpronouncements from the provisions of SFAS 157. FSP 157-1 is effective with the standard effective for periods beginning after June 15, 2005. We doinitial adoption of SFAS 157. FSP 157-1 will not expect SFAS 123R to have a material effect on our consolidated financial position, results of operationoperations or cash flows.

          In December 2004,February 2008, the FASB issued FASB Staff Position (“FSP”) 157-2 – Effective Date of FASB Statement of Financial Accounting Standard 153 Exchanges on Nonmonetary AssetsNo. 157 (“SFAS 153”FSP 157-2”), an amendmentwhich delays the effective date of Accounting Principles Board (“APB”) Opinion No. 29 (“Opinion 29”). SFAS 153 amends Opinion 29 to eliminate the exception157 for nonmonetary exchanges of similar productiveall nonfinancial assets and replaces it withnonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a general exception for exchanges of nonmonetary assets that dorecurring basis (at least annually), until January 1, 2009. FSP 157-2 will not have commercial substance. We do not expect SFAS 153 to have a material effect on our consolidated financial position, results of operationoperations or cash flows.

          In September 2004,February 2007, the SECFinancial Accounting Standards Board (“FASB”) issued Staff Accounting Bulletin 106SFAS 159 – The Fair Value Option for Financial Assets and Financial Liabilities (“SAB 106”SFAS 159”), which provides guidance regardingpermits entities to choose to measure many financial instruments and certain other items at fair value. SFAS 159 is effective as of the interactionbeginning of an entity’s first fiscal year that begins after November 15, 2007. SFAS 159 will not have a material effect on our consolidated financial position, results of operations or cash flows.
          In December 2007, the FASB issued SFAS 141 (revised 2007) – Business Combinations (“SFAS 141R”). The objective of SFAS 143 with141R is to improve the calculation of depletionrelevance, representational faithfulness, and the full cost ceiling test of oil and gas properties under the full cost accounting rulescomparability of the SEC. The guidance providedinformation that a reporting entity provides in SAB 106its financial reports about a business combination and its effects. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. When adopted, SFAS 141R is not expected to have a material effect on our consolidated financial position, results of operationoperations or cash flows.

          In January 2003,December 2007, the FASB issued InterpretationSFAS 160 – Noncontrolling Interest in Consolidated Financial Statements – an amendment of ARB No. 4651 (“FIN 46”SFAS 160”) Consolidation. The objective of Variable Interest Entities, which addressesSFAS 160 is to improve the consolidation of variable interest entities (“VIEs”) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the majorityrelevance, comparability and transparency of the risksfinancial information that a reporting entity provides in its consolidated financial statements. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or rewards associated with the VIE. In December 2003, the FASB issued a revision to FIN 46, Interpretation No. 46R (“FIN 46R”), to clarify some of the provisions of FIN 46, and to defer certain entities from adopting until the end of the first interim or annual reporting period ending after March 15, 2004. Application of FIN 46R is required in financial statements of public entities that have interests in structures that are commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application for all other types2008. Early adoption is prohibited. When adopted, SFAS 160 is not expected to have a material effect on our consolidated results of VIEs is required in financial statements for periods ending after March 15, 2004.operations or cash flows.
Off-Balance Sheet Arrangements
          We believe wedo not have no arrangements that would require the application of FIN 46R. We have noany off-balance sheet arrangements.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

          We are exposed to market risk from adverse changes in oil and natural gas prices, interest rates and foreign exchange risk, as discussed below.

Oil Prices

          As an independent oil producer, our revenue, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas.

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Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control. Historically, prices received for oil production have been volatile and unpredictable, and such volatility is expected to continue. Harvest Vinccler hedged a portion of its 2003 oil production by purchasing a WTI crude oil “put” to protect its 2003 cash flow. In August and September 2004, Harvest Vinccler hedged a portion of its oil sales for calendar year 2005 by purchasing two WTIWest Texas Intermediate (“WTI”) crude oil puts. Because gains or losses associated with hedging transactions are included in oil sales when the hedged production is delivered, such gains and losses are generally offset by similar changes in the realized prices of the commodities. SeePart IV, Item 15, Notes to the Consolidated Financial Statements, Note 1 – Organization and Summary of Significant Accounting Policies – Derivatives and Hedgingfor a complete discussion of our derivative activity. We had no hedging transactions in place for our 2004 or 2006 production.

Interest Rates

          Total short-term debt at December 31, 20042007 of $11.8$9.3 million consisted of Harvest Vinccler’s Bolivar denominated debt, which had a fixed rate for its initial twelve months. Total short-term debt at December 31, 2006 of $37.7 million consisted of Harvest Vinccler U.S. Dollar denominated variablefixed rate loans. A hypothetical 10 percent adverse change in the interest rate would not have a material affecteffect on our results of operations.

Foreign Exchange

          For

          The Bolivar is not readily convertible into the Venezuelan operations, oil and gas sales are received under a contract in effect through 2012 in U.S. Dollars; expenditures are both in U.S. Dollars and local currency.Dollar. We have utilized no currency hedging programs to mitigate any risks associated with operations in these countries,Venezuela, and therefore our financial results are subject to favorable or unfavorable fluctuations in exchange rates and inflation in these countries.that country. Venezuela has recently imposed currency exchange controls (seeCapital Resources and Liquidityabove).

Item 8. Financial Statements and Supplementary Data

          The information required by this item is included herein on pages S-1 through S-33.S-34.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

          None.

Item 9A. Controls and Procedures

          The Securities and Exchange Commission, among other things,SEC adopted rules requiring reporting companies to maintain disclosure controls and procedures to provide reasonable assurance that a registrant is able to record, process, summarize and report the information required in the registrant’s quarterly and annual reports under the Securities Exchange Act of 1934 (the “Exchange Act”).Act. While we believe that our existing disclosure controls and procedures have been effective to accomplish these objectives, we intend to continue to examine, refine and formalize our disclosure controls and procedures and to monitor ongoing developments in this area.

There have not been any changes in our internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter of 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Changes in Internal Control over Financial Reporting.The only changes to our internal controls since December 31, 2004, pertain to the change in accounting policy for our oil and natural gas exploration and development activities to the successful efforts method from the full cost method of accounting and equity accounting of our Unconsolidated Equity Affiliates. The internal controls have been modified as necessary in connection with our adoption of the successful efforts method of accounting and retrospectively revising financial information for prior periods.

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          Evaluation of Disclosure Controls and Procedures.We have established disclosure controls and procedures to ensure that material information relating to us, including our consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the Board of Directors.

          Based on their evaluation as of December 31, 2004,2007, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in RulesRule 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is 1) recorded, processed, summarized and reported within the time periods as specified in the Securities and Exchange CommissionSEC’s rules and forms.

forms and 2) accumulated and communicated to our management, including our principal executive and principal financial officers, to allow timely decisions regarding required disclosure.

          Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act RulesRule 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the Internal Control Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited our management’s assessment of the2007. The effectiveness of our internal control over financial reporting as of December 31, 2004, and issued2007, has been audited by PricewaterhouseCoopers LLP, an attestationindependent registered public accounting firm, as stated in their report which is includedappears herein.

Item 9B. Other Information

          None.

     None.

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PART III

Item 10. Directors, and Executive Officers of the Registrant

and Corporate Governance

          Please refer to the information under the captions “Election of Directors” and “Executive Officers” in our Proxy Statement for the 20052008 Annual Meeting of Shareholders.Stockholders.

Item 11. Executive Compensation

          Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the 20052008 Annual Meeting of Shareholders.Stockholders.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
          Please refer to the information under the caption “Stock Ownership” in our Proxy Statement for the 20052008 Annual Meeting of Shareholders.Stockholders.

Item 13. Certain Relationships and Related Transactions,

and Director Independence

          Please refer to the information under the caption “Certain Relationships and Related Transactions” in our Proxy Statement for the 20052008 Annual Meeting of Shareholders.Stockholders.

Item 14. Principal Accounting Fees and Services

          Please refer to the information under the caption “Independent Registered Public Accounting Firm” in our Proxy Statement for the 20052008 Annual Meeting of Shareholders.

Stockholders.

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PART IV

Item 15. Exhibits and Financial Statement Schedules and Reports on Form 8-K
(a) 1. Index to Financial Statements:
(a)1.Index to Financial Statements:Page
     
 
 Page
Report of Independent Registered Public Accounting Firm
 S-1
     
Consolidated Balance Sheets at December 31, 20042007 and 2003
S-2
2006  S-2 Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2004, 2003 and 2002S-3
     
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005
S-3
    
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2004, 20032007, 2006 and 20022005
 S-4
     
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 20032007, 2006 and 20022005
 S-5
     
Notes to Consolidated Financial Statements
S-7
    
Notes to Consolidated Financial StatementsS-7
2.Consolidated Financial Statement Schedules and Other:  
Schedule II - Valuation and Qualifying Accounts  
     
     
Financial Statements
Schedule II — Valuation and Notes for LLC Geoilbent, a significant equity investment
Qualifying Accounts  S-36 
     All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto.
3.Exhibits:
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto.
(b) 3. Exhibits:
     
 3.1  Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1(i) to our Form 10-Q filed on August 13, 2002, File No. 1-10762.)
     
 3.2  Amended and Restated Bylaws as of December 11, 2003.May 17, 2007. (Incorporated by reference to Exhibit 3.73.1 to our Form 10-K8-K filed on March 10, 2004,April 23, 2007, File No. 1-10762.)
     
 4.1  Form of Common Stock Certificate. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-26333).)
     
 4.2  Certificate of Designation, Rights and Preferences of the Series B.B Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.)
     
 4.3  Third Amended and Restated Rights Agreement, dated as of September 16, 2003,August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, Minnesota, N.A. (incorporated by reference to Exhibit 5 to Amendment No. 1 to our Registration Statement on Form 8-A filed October 29, 2003 (Registration No. 000-17534)).
10.1Operating Service Agreement between Benton Oil and Gas Company and Lagoven, S.A., which has been subsequently combined into PDVSA Petroleo y Gas, S.A., dated July 31, 1992, (portions have been omitted pursuant to Rule 406 promulgated under the Securities Act of 1933 and filed separately with the Securities and Exchange Commission. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-52436).)

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10.2Note payable agreement dated March 8, 2001 between Harvest Vinccler, C.A. and Banco Mercantil, C.A. related to a note in the principal amount of $6,000,000 with interest at LIBOR plus five percent, for financing of Tucupita Pipeline. (Incorporated by reference to Exhibit 10.2499.3 to our Form 10-Q,8-A filed on May 15, 2001,October 23, 2007, File No. 1-10762.)
     
10.3†Change of Control Severance Agreement effective May 4, 2001. (Incorporated by reference to Exhibit 10.26 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.)
 
10.4Alexander E. Benton Settlement and Release Agreement effective May 11, 2001 (Incorporated by reference to Exhibit 10.27 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.).
10.5First Amendment to Change of Control Severance Plan effective June 5, 2001. (Incorporated by reference to Exhibit 10.31 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.)
10.6Sale and Purchase Agreement dated February 27, 2002 between Benton Oil and Gas Company and Sequential Holdings Russian Investors Limited regarding the sale of Benton Oil and Gas Company’s 68 percent interest in Arctic Gas Company. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on March 28, 2002, File No. 1-10762.)
10.710.1  2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-8 filed on April 9, 2002 (Registration Statement No. 333-85900).)
     
10.8Addendum No. 2 to Operating service agreement Monagas SUR dated 19th September, 2002. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
 10.2 
10.9Bank Loan Agreement between Banco Mercantil, C.A. and Harvest Vinccler C.A. dated October 1, 2002. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
10.10Guaranty issued by Harvest Natural Resources, Inc. dated September 26, 2002. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
10.11†Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Peter J. Hill. (Incorporated by reference to Exhibit 10.10 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
10.12†Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.11 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
10.13†Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.12 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
10.14†Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.13 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
10.15Sale and Purchase Agreement dated September 26, 2003, between Harvest Natural Resources, Inc. and Yukos Operational Holding Limited regarding the sale of our 34 percent minority equity investment in LLC Geoilbent. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 10, 2003, File No. 1-10762.)
10.16†Employment Agreement dated November 17, 2003 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.18 to our Form 10-Q filed on March 10, 2004, File No. 1-10762.)

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10.17†Employment Agreement dated September 1, 2004 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10-1 to our Form 10-Q filed on November 5, 2004, File No. 1-10762.)
10.18† Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).)

33

     
10.1910.3† Form of Indemnification Agreement between Harvest Natural Resources, Inc. and the Directorseach Director and Executive OfficersOfficer of the Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
 
 10.20†
10.4 Form of 2004 Long Term Stock Incentive Plan Stock Option AgreementAgreement. (Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
     
 
10.5 10.21† Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock AgreementAgreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
     
 
10.6 10.22† Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock AgreementAgreement. (Incorporated by reference to Exhibit 10.22 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
     
10.7†Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
  
10.8† Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
10.9†Employment Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
10.10†Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.24 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)
10.11†Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)
10.12†Stock Option Agreement dated September 26, 2005, between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.26 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)
10.13†Employment Agreement dated February 10, 2006 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on April 20, 2006, File No. 1-10762.)
10.14Harvest Natural Resources 2006 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on June 1, 2006 [Registration Statement No. 333-134630].)
10.15Form of 2006 Long Term Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
10.16Form of 2006 Long Term Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
10.17Form of 2006 Long Term Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)

34

10.18†Stock Unit Award Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
10.19†Stock Unit Award Agreement dated March 2, 2006 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
10.20Note Payable agreement dated November 20, 2006 between Harvest Vinccler, C.A. and Banesco Banco Universal C.A. related to a principal amount of 120 billion Bolivars with interest at 10.0 percent, for refinancing of the SENIAT assessments and operating requirements. (Incorporated by reference to Exhibit 10.32 to our Form 10-K filed on March 13, 2007, File No. 1-10762.)
10.21Form of 2006 Long Term Incentive Plan Stock Option Agreement – Five Year Vesting, Seven Year Term. (Incorporated by reference to Exhibit 10.33 to our Form 10-K filed on March 13, 2007, File No. 1-10762.)
10.22Amendment to Harvest Natural Resources 2006 Long Term Incentive Plan adopted July 19, 2006. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on May 3, 2007, File No. 1-10762.)
10.23†Employment Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)
10.24†Stock Option Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)
10.25†Employee Restricted Stock Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)
10.26†Consulting Agreement dated July 16, 2007 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)
10.27Contract for Conversion to a Mixed Company between Corporación Venezolana del Petróleo, S.A., Harvest-Vinccler, S.C.A. and HNR Finance B.V. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on November 1, 2007, File No. 1-10762.)
10.28†Separation Agreement dated November 16, 2007 between Harvest Natural Resources, Inc. and Byron A. Dunn.
 21.1  List of subsidiaries.
     
 23.1  Consent of PricewaterhouseCoopers LLP — Houston– Houston.
     
 23.2  Consent of ZAO PricewaterhouseCoopers Audit — MoscowRyder Scott Company, LP.
     
 
31.1  23.3ConsentCertification pursuant to Section 302 of Ryder Scott Company, LPthe Sarbanes-Oxley Act of 2002 executed by James A. Edmiston, President and Chief Executive Officer.
     
 
31.131.2  Certification of the Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer.

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32.1Certification accompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by James A. Edmiston, President and Chief Executive Officer.
     
31.2Certification of the Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1Certification of the Chief Executive Officer accompanying the annual report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 32.2  Certification of theaccompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer accompanying the annual report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.and Treasurer.
† Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c)15(a) and (b) of Form 10-K.

(b) Reports on Form 8-K

On November 4, 2004, we filed a Report on Form 8-K with the Securities and Exchange Commission in which we furnished a press release announcing our results for the third quarter ended September 30, 2004 and furnishing the following financial statements: (i) Consolidated Balance Sheets for the Period Ended September 30, 2004 and December 31, 2003; (ii) Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2004 and 2003; and (iii) Consolidated Statement of Cash Flows for the Three and Nine Months Ended September 30, 2004 and 2003.

On December 14, 2004, we filed a Report on Form 8-K with the Securities and Exchange Commission in which we furnished a press release providing financial and operating guidance assumptions for 2005.

3436

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMReport of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Harvest Natural Resources, Inc.:

     We have completed an integrated audit of Harvest Natural Resources, Inc.’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004, and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedule

In our opinion, the consolidated financial statements listed in the index appearing under Item 15 (a)(1)15(a)1 present fairly, in all material respects, the financial position of Harvest Natural Resources,Resource, Inc. and its subsidiaries at December 31, 20042007 and 2003,December 31, 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20042007 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the indexappearing under Item 15(a)(2)2 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. TheseAlso in our opinion, the Company maintained, in all material respects, effective internal control over financial statements and financial statement schedule arereporting as of December 31, 2007, based on criteria established inInternal Control — Integrated Framework issued by the responsibilityCommittee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management. Our responsibilitymanagement is to express an opinion onresponsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the auditaudits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An auditmisstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements includesincluded examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinion.

opinions.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for employee stock-based compensation to the fair value based method effective January 1, 2003.

Internal control over financial reporting

     Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reportingoil and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

gas producing activities.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP
Houston, Texas
February 22, 2005

March 17, 2008

S-1

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
        
 December 31,         
 2004 2003  December 31, 
 (in thousands, except per  2007 2006* 
 share data)  (in thousands, except per share data) 
ASSETS  
Current Assets:  
Cash and cash equivalents $84,600 $138,660  $120,841 $148,079 
Restricted cash 12 12  6,769 15,888 
Accounts and notes receivable: 
Accrued oil sales 58,937 32,766 
Joint interest and other, net 12,780 11,197 
Put options 14,209 — 
Accounts receivable, net 9,418 9,811 
Advances to equity affiliate 16,352 19,146 
Deferred income tax 251 —  — 5,608 
Prepaid expenses and other 1,426 805  1,032 1,246 
          
Total Current Assets 172,215 183,440  154,412 199,778 
Restricted Cash 16 16  — 73,001 
Other Assets 2,072 2,080  4,301 176 
Deferred Income Taxes 6,034 4,749 
Investment in equity affiliates 251,173 192,090 
Property and Equipment:  
Oil and gas properties (full cost method-costs of $2,900 excluded from amortization in 2004 and 2003, respectively) 631,082 593,622 
Oil and gas properties (successful efforts method) 3,163 2,900 
Other administrative property 10,008 8,948  1,481 1,375 
          
 641,090 602,570  4,644 4,275 
Accumulated depletion, depreciation, and amortization  (453,941)  (418,507)
Accumulated depletion, depreciation and amortization  (1,061)  (955)
          
Net Property and Equipment 187,149 184,063  3,583 3,320 
          
 $367,486 $374,348  $413,469 $468,365 
          
  
LIABILITIES AND STOCKHOLDERS’ EQUITY  
Current Liabilities:  
Accounts payable, trade and other $8,428 $4,163  $5,949 $3,827 
Accounts payable, related party 11,063 10,557  10,093 9,637 
Accrued expenses 29,355 15,069  11,895 12,975 
Accrued interest payable 71 1,427 
Accrued interest 5,136 6,850 
Deferred revenue — 11,217 
Income taxes payable 22,475 8,647  503 34 
Current portion of long-term debt 11,833 6,367  9,302 37,674 
          
Total Current Liabilities 83,225 46,230  42,878 82,214 
Long-Term Debt — 96,833  — 66,977 
Asset Retirement Liability 1,941 1,459 
Commitments and Contingencies — —  — — 
Minority Interest 39,131 30,113  56,825 37,765 
Stockholders’ Equity:  
Preferred stock, par value $0.01 a share; Authorized 5,000 shares; outstanding, none Common stock, par value $0.01 a share; Authorized 80,000 shares at December 31, 2004 and 2003; issued 37,544 shares and 36,405 shares at December 31, 2004 and 2003, respectively 375 364 
Preferred stock, par value $0.01 a share; Authorized 5,000 shares; outstanding, none 
Common stock, par value $0.01 a share; Authorized 80,000 shares at December 31, 2007 and 2006; issued 38,513 shares and 37,974 shares at December 31, 2007 and 2006, respectively 385 380 
Additional paid-in capital 185,183 175,051  201,938 194,176 
Retained earnings 61,897 27,537  147,934 90,697 
Accumulated other comprehensive loss  (487) — 
Treasury stock, at cost, 764 shares and 730 shares at December 31, 2004 and 2003, respectively  (3,779)  (3,239)
Treasury stock, at cost, 3,719 shares at December 31, 2007 and 770 shares at December 31, 2006, respectively  (36,491)  (3,844)
          
Total Stockholders’ Equity 243,189 199,713  313,766 281,409 
          
 $367,486 $374,348  $413,469 $468,365 
          

*Financial information for 2006 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle.
See accompanying notes to consolidated financial statements.

S-2

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
             
  Years Ended December 31, 
  2004  2003  2002 
  (in thousands, except per share data) 
Revenues
            
Oil sales $154,075  $103,920  $127,015 
Gas sales  31,991   2,740   — 
Ineffective hedge activity  —   (565)  (284)
          
   186,066   106,095   126,731 
          
             
Expenses
            
Operating expenses  33,324   30,893   33,950 
Depletion, depreciation and amortization  36,020   21,188   26,363 
Write-downs of oil and gas properties and impairments  —   165   14,537 
General and administrative  21,857   15,746   16,504 
Arbitration settlement  —   1,477   — 
Bad debt recovery  (598)  (374)  (3,276)
Gain on sale of long-lived asset  (578)  —   — 
Taxes other than on income  5,561   3,373   4,068 
          
   95,586   72,468   92,146 
          
             
Income from Operations  90,480   33,627   34,585 
Other Non-Operating Income (Expense)            
Gain on disposition of investment  —   46,619   144,029 
Gain (loss) on early extinguishment of debt  (2,928)  —   874 
Investment earnings and other  2,085   1,418   2,080 
Interest expense  (7,749)  (10,405)  (16,310)
Net gain (loss) on exchange rates  (622)  529   4,553 
          
   (9,214)  38,161   135,226 
          
             
Income from Consolidated Companies Before Income Taxes and Minority Interest  81,266   71,788   169,811 
Income Tax Expense  33,288   9,657   60,295 
          
Income Before Minority Interest  47,978   62,131   109,516 
Minority Interest in Consolidated Subsidiary Companies  13,618   5,968   9,319 
          
Income from Consolidated Companies  34,360   56,163   100,197 
Equity in Net Income (Losses) of Affiliated Companies  —   (28,860)  165 
          
Net Income $34,360  $27,303  $100,362 
          
             
Net Income Per Common Share:            
Basic $0.95  $0.77  $2.90 
          
Diluted $0.90  $0.74  $2.78 
          
             
Other comprehensive loss:            
Unrealized mark to market loss from cash flow hedging activities, net of tax  (487)  —   — 
          
Comprehensive income $33,873  $27,303  $100,362 
          
             
  Years Ended December 31, 
  2007  2006*  2005* 
  (in thousands, except per share data) 
Revenues
            
Oil sales (a) $11,217  $54,858  $210,493 
Gas sales  —   4,648   26,448 
          
   11,217   59,506   236,941 
          
             
Expenses
            
Operating expenses  —   9,241   39,723 
Depletion, depreciation and amortization  384   15,435   58,922 
Exploration expense  204   —   — 
General and administrative  29,742   26,421   22,819 
Contribution to Science and Technology Fund  —   3,887   — 
Account receivable write-off on retroactive oil price adjustments  —   —   4,548 
Taxes other than on income  423   3,948   6,358 
          
   30,753   58,932   132,370 
          
             
Income (Loss) from Operations  (19,536)  574   104,571 
Other Non-Operating Income (Expense)            
Gain on Financing Transactions  49,623   —   — 
Investment earnings and other  9,065   9,406   4,205 
Interest expense  (8,224)  (23,156)  (3,388)
Net gain (loss) on exchange rates  (14)  (121)  2,752 
          
   50,450   (13,871)  3,569 
          
             
Income (Loss) from Consolidated Companies Before Income Taxes and Minority Interest  30,914   (13,297)  108,140 
Income Tax Expense  6,312   60,917   57,025 
          
Income (Loss) Before Minority Interest  24,602   (74,214)  51,115 
Minority Interest in Consolidated Subsidiary Companies  19,060   (11,712)  12,239 
          
Income (loss) from Consolidated Companies  5,542   (62,502)  38,876 
Net Income from Unconsolidated Equity Affiliates  51,695   —   — 
          
Net Income (Loss) $57,237  $(62,502) $38,876 
          
             
Net Income (Loss) Per Common Share:            
Basic $1.57  $(1.68) $1.05 
          
Diluted $1.51  $(1.68) $1.01 
          

(a)Recognition of deferred revenue – See Note 1 – Organization and Summary of Significant Accounting Policies – Revenue Recognition.
*Financial information for 2006 and 2005 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle.
See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)
                             
              Retained  Accumulated       
  Common      Additional  Earnings  Other       
  Shares  Common  Paid-in  (Accumulated  Comprehensive  Treasury    
  Issued  Stock  Capital  Deficit)  Loss  Stock  Total 
                             
Balance at January 1, 2002
  34,164  $342  $168,108  $(100,128) $—  $(699) $67,623 
                             
Issuance of common shares:                            
Non-employee director compensation  46   —   543   —   —   —   543 
Employee compensation  175   2   663   —   —   —   665 
Exercise of stock options  1,515   15   4,245   —   —   —   4,260 
Treasury stock (600 shares)  —   —   —   —   —   (2,136)  (2,136)
Net Income  —   —   —   100,362   —   —   100,362 
                      
Balance at December 31, 2002
  35,900   359   173,559   234   —   (2,835)  171,317 
                             
Issuance of common shares:                            
Exercise of stock options  505   5   1,196   —   —   —   1,201 
Employee stock based compensation  —   —   296   —   —   —   296 
Treasury stock (80 shares)  —   —   —   —   —   (404)  (404)
Net Income  —   —   —   27,303   —   —   27,303 
                      
Balance at December 31, 2003
  36,405   364   175,051   27,537   —   (3,239)  199,713 
                             
Issuance of common shares:                            
Exercise of warrants  53   —   600   —   —   —   600 
Exercise of stock options  1,001   10   7,381   —   —   —   7,391 
Employee stock-based compensation  85   1   2,151   —   —   —   2,152 
Treasury stock (34 shares)  —   —   —   —   —   (540)  (540)
Accumulated other comprehensive loss  —   —   —   —   (487)  —   (487)
Net Income  —   —   —   34,360   —   —   34,360 
                      
                             
Balance at December 31, 2004
  37,544  $375  $185,183  $61,897  $(487) $(3,779) $243,189 
                      
                             
                  Accumulated       
  Common      Additional      Other       
  Shares  Common  Paid-in  Retained  Comprehensive  Treasury    
  Issued  Stock  Capital  Earnings  Gain(Loss)  Stock  Total 
Balance at January 1, 2005
  37,544  $375  $185,183  $114,323  $(487) $(3,779) $295,615 
                             
Issuance of common shares:                            
Exercise of stock options  139   3   829   —   —   —   832 
Employee stock-based compensation  74   —   2,230   —   —   —   2,230 
Purchase of Treasury Shares  —   —   —   —   —   (65)  (65)
Accumulated other comprehensive gain  —   —   —   —   487   —   487 
Net Income*  —   —   —   38,876   —   —   38,876 
                      
                             
Balance at December 31, 2005
  37,757   378   188,242   153,199   —   (3,844)  337,975 
                             
Issuance of common shares:                            
Exercise of stock options  137   1   879   —   —   —   880 
Employee stock-based compensation  80   1   5,055   —   —   —   5,056 
Net Loss *  —   —   —   (62,502)  —   —   (62,502)
                      
                             
Balance at December 31, 2006
  37,974   380   194,176   90,697   —   (3,844)  281,409 
                             
Issuance of common shares:                            
Exercise of stock options  402   4   1,934   —   —   —   1,938 
Employee stock-based compensation  137   1   5,828   —   —   —   5,829 
Purchase of Treasury Shares  —   —   —   —   —   (32,647)  (32,647)
Net Income  —   —   —   57,237   —   —   57,237 
                      
                             
Balance at December 31, 2007
  38,513  $385  $201,938  $147,934  $—  $(36,491) $313,766 
                      

*Financial information for 2006 and 2005 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle.
See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
                        
 Years Ended December 31,  Years Ended December 31, 
 2004 2003 2002  2007 2006* 2005* 
 (in thousands)  (in thousands) 
Cash Flows From Operating Activities:  
Net income $34,360 $27,303 $100,362 
Adjustments to reconcile net income to net cash provided by operating activities: 
Net income (loss) $57,237 $(62,502) $38,876 
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: 
Depletion, depreciation and amortization 36,020 21,188 26,363  384 15,435 58,922 
Write-down of oil and gas properties and impairment — 165 14,537 
Amortization of financing costs 228 497 1,745 
Gain on disposition of assets and investments  (578)  (46,619)  (144,029)
Write off of unamortized financing costs 936 — — 
Equity in net earnings (losses) of affiliated companies — 28,860  (165)
Allowance for employee notes and accounts receivable  (598)  (169)  (2,987)
Exploration expense 204 — — 
Gain on financing transactions  (49,623) — — 
Net income from unconsolidated equity affiliates  (51,695) — — 
Account receivable write-off on retroactive oil price adjustments — — 4,548 
Deferred compensation expense 1,521 306 —  — —  (745)
Non-cash compensation related charges 2,152 296 1,458  6,108 5,056 2,230 
Minority interest in consolidated subsidiary companies 13,618 5,968 9,319  19,060  (11,712) 12,239 
Gain from early extinguishment of debt — —  (874)
Deferred income taxes  (1,285)  (667) 53,618  5,608  (2,556) 2,982 
Changes in operating assets and liabilities:  
Accounts and notes receivable  (27,156)  (7,935)  (1,972) 393 61,839  (4,481)
Advances to equity affiliate 2,794  (19,146) — 
Prepaid expenses and other  (621) 2,164  (1,130) 214 903  (723)
Commodity hedging contract  (14,947)  (430) 430  — — 14,947 
Accounts payable 4,265 359  (4,328) 2,122 3,419  (8,020)
Accounts payable, related party 506 4,386  (604) 456 434  (1,860)
Accrued interest payable  (1,356) 22  (2,489)
Accrued expenses 12,765  (382)  (9,686)  (1,251)  (5,469)  (10,165)
Accrued interest  (1,714) 4,213 2,565 
Deferred revenue  (11,217) 4,489 6,728 
Asset retirement liability 482 1,459 —  — 24 188 
Income taxes payable 13,828 1,767 3,059  469  (18,875)  (3,566)
              
Net Cash Provided by Operating Activities 74,140 38,538 42,627 
Net Cash Provided By (Used In) Operating Activities  (20,451)  (24,448) 114,665 
              
Cash Flows from Investing Activities:  
Proceeds from sale of investment — 69,500 189,841 
Proceeds from sale of long-lived assets 578 — — 
Additions of property and equipment  (39,106)  (60,925)  (43,346)  (851)  (1,657)  (16,147)
Investment in and advances to affiliated companies — 2,328 9,185 
Increase in restricted cash — —  (2,800)
Decrease in restricted cash — 1,800 1,000 
Purchases of marketable securities —  (256,058)  (353,478)
Maturities of marketable securities — 283,446 326,090 
Investments in equity affiliates  (7,388)  (513) — 
(Increase) decrease in restricted cash 82,120  (88,889) 28 
Investment costs  (1,156)  (1,900)  (349)  (4,125) 503 472 
              
Net Cash Provided by (Used In) Investing Activities  (39,684) 38,191 126,143 
Net Cash Provided By (Used In) Investing Activities 69,756  (90,556)  (15,647)
              
Cash Flows from Financing Activities:  
Net proceeds from issuances of common stock 7,451 1,201 3,345  1,938 880 767 
Purchase of treasury stock —  (404) —   (32,755) — — 
Proceeds from issuance of long-term debt — — 15,500 
Payments on long-term debt  (91,367)  (3,367)  (132,138)
Dividends paid to minority interest  (4,600) — — 
Proceeds from issuance of notes payable — 118,953 — 
Payments of note payable  (45,726)  (19,769)  (6,366)
Dividend paid to minority interest — —  (15,000)
              
Net Cash Used In Financing Activities  (88,516)  (2,570)  (113,293)
Net Cash Provided By (Used In) Financing Activities  (76,543) 100,064  (20,599)
              
Net Increase (Decrease) in Cash and Cash Equivalents  (54,060) 74,159 55,477   (27,238)  (14,940) 78,419 
Cash and Cash Equivalents at Beginning of Year 138,660 64,501 9,024  148,079 163,019 84,600 
              
Cash and Cash Equivalents at End of Year $84,600 $138,660 $64,501  $120,841 $148,079 $163,019 
              
Supplemental Disclosures of Cash Flow Information:  
Cash paid during the year for interest expense $12,541 $13,241 $19,201  $7,972 $23,171 $795 
              
Cash paid during the year for income taxes $11,705 $4,254 $3,935  $201 $62,505 $20,991 
              

*Financial information for 2006 and 2005 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle.
See accompanying notes to consolidated financial statements.

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Supplemental Schedule of Noncash Investing and Financing Activities:

          During the year ended December 31, 2004,2007, we issued 0.3 million shares of restricted stock valued at $2.6 million; most of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 16,042 shares being added to treasury stock at cost; and 20,000 shares held in treasury were reissued as restricted stock.
          During the year ended 2006, we issued 0.1 million shares of restricted stock valued at $1.2 million and we wrote-off $0.9 million of unamortized debt financing costs in connection with the redemption and discharge of the 9.375 percent senior unsecured notes due November 1, 2007. For the years ended December 31, 2003 and 2002, we recorded an allowance for doubtful accounts related to interest accrued on the remaining amount owed to us by our former chief executive officer, A. E. Benton. During the years ended December 31, 2004, 2003 and 2002, we reversed a portion of such allowance as a result of our collection of certain amounts owed to us including the portions of the note secured by our stock and other properties (seeNote 12 – Related Party Transactions).

$1.0 million.

          During the year ended December 2004, the holders2005, we issued 0.1 million shares of restricted stock valued at $0.8 million and Dr. Peter J. Hill, our warrantsformer Chief Executive Officer, elected to exercise 45,000 warrantspay withholding tax on a 2002 restricted stock grant on a cashless basis. This resulted in the issuance of 34,0545,497 shares which arebeing held as treasury stock at cost.

See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements

Note 1 — Organization and Summary of Significant Accounting Policies

Organization

     Harvest Natural Resources, Inc. is an independent energy company engaged in the acquisition, exploration, development, production and managementdisposition of oil and natural gas properties.properties since 1989, when it was incorporated under Delaware law. We conducthave acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”) through our business principallysubsidiary Harvest Vinccler, S.C.A. (“Harvest Vinccler”) and our equity affiliate, Petrodelta S.A. (“Petrodelta”) and have offshore undeveloped acreage in the People’s Republic of China (“China”).
     On March 31, 2006, Harvest Vinccler signed a Memorandum of Understanding (the “MOU”) with two affiliates of PDVSA, Corporación Venezolana del Petroleo S.A. (“CVP”) and PDVSA Petroleo S.A. (“PPSA”), to convert its Operating Service Agreement (“OSA”) into a minority interest in Petrodelta. On August 16, 2006, the MOU was amended to provide for the addition of the Isleño, El Salto and Temblador fields (“New Fields”) to Petrodelta as additional consideration for the conversion of the OSA to Petrodelta. On December 18, 2006, at our special meeting of the stockholders, the transactions contemplated by the MOU were approved. On September 11, 2007, we signed the Contract of Conversion (“Conversion Contract”), and on October 3, 2007, together with CVP, we formed and funded Petrodelta. On October 25, 2007, the Presidential Decree which formally transferred to Petrodelta the rights to the Uracoa, Tucupita and Bombal fields (“SMU Fields”) and the New Fields, subject to the conditions of the Conversion Contract, was published in the Official Gazette. Harvest Vinccler has transferred all of its tangible assets and contracts, permits and rights related to the SMU Fields in Venezuela (Harvest Vincclerto Petrodelta. In January 2008, a majority of Harvest Vinccler’s employees accepted positions with Petrodelta. Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the SMU Fields and New Fields (collectively “Petrodelta Fields”). HNR Finance B.V. (“HNR Finance”) has a 40 percent ownership interest in Petrodelta. As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta, and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. or “Harvest (“Vinccler” formerly Benton Vinccler, C.A.), indirectly owns the remaining eight percent interest. CVP will own the remaining 60 percent. At our request, CVP has added HNR Finance as a party to the Conversion Contract. Petrodelta is governed by its own charter and until September 25, 2003, through our minority equity investment in LLC Geoilbent, a Russian entity.

bylaws.

Principles of Consolidation

     The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. The equity method of accounting is used for companies and other investments in which we have significant influence. All intercompany profits, transactions and balances have been eliminated. We accounted
Investment in Equity Affiliates
     The equity method of accounting is used for our investmentcompanies and other investments in LLC Geoilbentwhich we have significant influence. In January 2007, we purchased a 45 percent equity interest in Fusion Geophysical, L.L.C. (“Geoilbent”Fusion”). In October 2007, Petrodelta was formed, and Arctic Gas Company (“Arctic Gas”), priorthe equity in earnings from April 1, 2006 to December 31, 2007 is reflected in the salefourth quarter of our interests, based on a fiscal year ending September 30 (seeNote 2 – Investments In2007 consolidated statement of operations. These investments are increased or decreased by earnings/losses and Advances to Affiliated Companies).

decreased by dividends paid and amortization of basis differential. No dividends were declared or paid by Fusion or Petrodelta in 2007.

Reporting and Functional Currency

     The U.S. Dollar is our functional and reporting currency.

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Revenue Recognition

     Oil and natural gas revenue is accrued monthly based on production and delivery. EachUntil March 31, 2006, each quarter, Harvest Vinccler invoicesinvoiced Petroleos de Venezuela S.A. (“PDVSA”) or affiliates, based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. Dollar contract service fees per barrel. The operating service agreement providesrelated OSA with PDVSA provided for Harvest Vinccler to receive an operating fee for each barrel of crude oil delivered and the right to receive a capital recovery fee for certain of its capital expenditures, provided that such operating fee and capital recovery fee cannotcould not exceed the maximum total fee per barrel set forth in the agreement. In August 2005, Harvest Vinccler and PDVSA executed a Transitory Agreement (the “Transitory Agreement”) which provided that the maximum total fee per barrel paid under the OSA could not exceed 66.67 percent of the total value of the crude oil as determined under an Annex to the Transitory Agreement. This limitation was applied retroactively to January 1, 2005 and approximated 47 percent of West Texas Intermediate (“WTI”). The operating fee iswas subject to quarterly adjustments to reflect changes in the special energy index of the U.S. Consumer Price Index. The maximum total fee is subject to quarterly adjustments to reflect changes in the average of certain world crude oil prices. EachUntil March 31, 2006, each quarter Harvest Vinccler also invoicesinvoiced PDVSA for natural gas sales based on a fixed price of $1.03 per Mcf. In addition, Harvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the natural gas production (“Incremental Crude Oil”). A portion of the Incremental Crude Oil iswas invoiced to PDVSA quarterly at a fixed price of $7.00 per Bbl.

The invoices were prepared and submitted to PDVSA by the end of the first month following the end of each calendar quarter, and payment was due from PDVSA by the end of the second month following the end of each calendar quarter. Harvest Vinccler invoiced PDVSA for the first quarter 2006 delivery of its crude oil and natural gas in accordance with the Transitory Agreement. With the formation of Petrodelta, Harvest Vinccler recognized deferred revenue of $11.2 million for 2005 and first quarter 2006 deliveries that had been deferred pending clarification on the calculation of crude prices under the Transitory Agreement.

Cash and Cash Equivalents

     Cash equivalents include money market funds and short term certificates of deposit with original maturity dates of less than three months.

At December 31, 2007, Harvest Vinccler had 4.7 billion Venezuela Bolivars (“Bolivars”) which are shown in the December 31, 2007 financial statements as $2.4 million in cash and cash equivalents.

Restricted Cash

     Restricted cash represents cash and cash equivalents held in a U.S. bank used as collateral for financing, letter of credit andHarvest Vinccler’s loan agreements,agreement, and is classified as current or non-current based on the terms of the agreements.

Marketable Securities

     Marketable securities are carried at cost. Cash Equivalents may be comprised of high-grade debt instruments, demand or time deposits, certificates of depositagreement. SeeNote 2 — Long-Term Debt and commercial paper of highly rated U.S. corporations, all having maturities of no more than 180 days.

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Liquidity.

Credit Risk and Operations

     All of our total consolidated revenues relate to operations in Venezuela. During the yearyears ended December 31, 2004,2006 and 2005, our Venezuelan crude oil and natural gas production represented all of our total production from consolidated companies, and ourcompanies. Petrodelta’s sole source of revenues related to such Venezuelanfor its production is PDVSA,PPSA, which maintains full ownership of all hydrocarbons in its fields. OnThe sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PPSA which was signed on January 17, 2008. As of December 2, 2002, employers’31, 2007, Petrodelta has not been paid by PPSA for its oil and workers’ organizations, together with political and civic organizations began a national civic work stoppage, which seriously affected many ofnatural gas deliveries from April 1, 2006 through December 31, 2007. Until payment is received for the country’s economic activities, in particular, the oil industry. As a result of the strike, we were unable to deliverdeliveries or PPSA advances funds on crude oil and hence generate revenues from PDVSA between December 14, 2002 and February 6, 2003. Further, on February 5, 2003, the Venezuelan Government implemented currency exchange controls aimed at restricting the convertibility of the Venezuelan Bolivar and the transfer of funds out of Venezuela. The Venezuelan Government set the exchange rate at 1,600 Bolivars for each U.S. Dollar and creatednatural gas deliveries, Petrodelta will be unable to pay a new Currency Exchange Agency which is responsible for the administration of exchange controls. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. Dollar. Management believes that we have sufficient cash and does not expect the currency conversion restrictions to adversely affect our ability to meet our short-term obligations and operating requirements for the next twelve months.

dividend.

Derivatives and Hedging

     Statement of Financial Accounting Standards (“SFAS”) No. 133, (“SFAS 133”), as amended, establishes accounting and reporting standards for derivative instruments and hedging activities. All derivatives are recorded on the balance sheet at fair value. To the extent that the hedge is determined to be effective, changes in the fair value of derivatives for qualifying cash flow hedges are recorded each period in other comprehensive income. Our derivatives have been designated as cash flow hedge transactions in which we hedge the variability of cash flows related to future oil prices for some or all of our forecasted oil production. The changes in the fair value of these derivative instruments

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have been reported in other comprehensive income because the highly effective test was met, and have been reclassified to earnings in the period in which earnings were impacted by the variability of the cash flows of the hedged item.

     Harvest Vinccler hedged a portion of its 2003 oil sales by purchasing a West Texas Intermediate (“WTI”) crude oil put option to protect its 2003 cash flow. The put was for 10,000 barrels of oil per day for the period of March 1, 2003 through December 31, 2003. Due to the pricing structure for our Venezuela oil, the put had the economic effect of hedging approximately 20,800 barrels of oil per day. The put cost was $2.50 per barrel, or $7.7 million, and had a strike price of $30.00 per barrel. The notional amount of the financial instrument was based on expected sales of crude oil production from existing and future development wells.

     We had no hedging instruments in place for our 2004 or 2006 production. In August 2004, Harvest Vinccler hedged a portion of its oil sales for calendar year 2005 by purchasing a WTI crude oil put for 5,000 barrels of oil per day. The put cost was $4.24 per barrel, or $7.7 million, and hashad a strike price of $40.00 per barrel. In September 2004, Harvest Vinccler hedged an additional portion of its calendar year 2005 oil sales by purchasing a second WTI crude oil put for 5,000 barrels of oil per day. The put cost was $3.95 per barrel, or $7.2 million, and hashad a strike price of $44.40 per barrel. Due to the amended pricing structure as revised by the Transitory Agreement for our Venezuelan oil, these two puts havehad the economic effect of hedging approximately 20,80021,500 barrels of oil per day for an average of $18.29$17.72 per barrel. These puts qualifyqualified under the highly effective test and thetest. There was no mark-to-market gain/loss at December 31, 2004 is included in other comprehensive loss.

     At December 31, 2004, Accumulated Other Comprehensive Loss consisted of $0.7 million ($0.5 million net of tax) of unrealized losses on our crude oil puts. Oil sales for the year ended 2004 included no losses in settlement of the puts. Oil sales for the year ended 2003 included settlements of $1.7 million as well as the amortization of the put option cost of $7.7 million.2005.

     Deferred net losses recorded in Accumulated Other Comprehensive Loss at December 31, 2004 are expected to bewere reclassified to earnings during 2005.

     We continue to assess production levels There was no difference between net income and commodity prices in conjunction with our capital resources and liquidity requirements.

Asset Retirement Liability

     Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accountingcomprehensive net income for Asset Retirement Obligations” (“SFAS 143”). In January 2003, Harvest Vinccler recorded, under the full cost method of accounting for oil and gas properties, an increase in oil and gas properties and a corresponding liability in the amount of $4.3 million. This asset retirement obligation is associated with the plugging and abandonment of

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certain wells in Venezuela. SFAS 143 requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. Nine wells were abandoned in the year ended December 31, 2004 and 11 wells were abandoned in year ended2005. All hedging instruments expired under their own terms on December 31, 2003. Changes in asset retirement obligations during the years ended December 31, 2004 and 2003 were as follows:2005.

         
  December 31,  December, 31 
  2004  2003 
         
Asset retirement obligations beginning of period $1,459  $— 
Liabilities recorded during the period  1,454   4,237 
Liabilities settled during the period  (540)  (733)
Revisions in estimated cash flows  (470)  (2,125)
Accretion expense  38   80 
       
Asset retirement obligations end of period $1,941  $1,459 
       

Accounts and Notes Receivable

     Allowance for doubtful accounts related to former employee notes at December 31, 20042007 and 20032006 was $2.8 million and $3.4 million, respectively. We received $0.5 million through the exercise of stock options and $0.1 million through the excess income provision of the settlement and release agreement. (seeNote 12 – Related Party Transactions).

million.

Other Assets

     Other assets consist of investigative costs associated with new business development projects. New projectThese costs are reclassified to oil and natural gas properties or expensed depending on management’s assessment of the likely outcome of the project.

Property and Equipment

     We follow

     In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method. Although the full cost method of accounting for oil and gas exploration and development continues to be an accepted method of accounting for oil and gas properties, the successful efforts method of accounting as prescribed by SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies is the preferred method. In accordance with SFAS No. 154 Accounting Changes and Error Corrections, financial information for prior periods has been restated to reflect retrospective application of the successful efforts method. We believe the successful efforts method provides a more transparent representation of our results of operations and the ability to assess our future investments in oil and gas properties for impairment based on their estimated fair values rather than being required to base valuation on prices and costs accumulatedas of the balance sheet date. The significant differences between successful efforts and full cost accounting for oil and gas properties relate to the expensing of exploration activities and related unsuccessful exploratory drilling activities. The expensing of these costs can create volatility in the statement of operations. The change in accounting principle resulted in a cumulative, non-cash increase to retained earnings of $52.4 million, net of income tax, as of December 31, 2004. Retained earnings increased due to the reversal of ceiling test write downs in prior years required under the full cost centers on a country-by-country basis, subject to a cost center ceiling (as defined byaccounting rules of the Securities and Exchange Commission [“(“SEC”]). All costs associated withThere were no such impairments under the acquisition, exploration and development of oil and natural gas reserves are capitalized as incurred. Only overhead that is directly identified with acquisition, exploration or development activities are capitalized. All costs related to production, general corporate overhead and similar activities are expensed as incurred.

successful efforts accounting rules. The costs of unproved properties are excluded from amortization until the properties are evaluated. At least quarterly we evaluate our unproved properties on a country by country basis for possible impairment. If we abandon all exploration efforts in a country where no proved reserves are assigned, all exploration and acquisition costs associated with the country are expensed. During 2003 and 2002, we recognized $0.2 million and $14.5 million, respectively, in impairments associated with former exploration prospects and the China WAB-21 block. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty.

     Excluded costs at December 31, 2004 consisted of property acquisition costs in the amount of $2.9 million which were all incurred prior to 2001. Alleffect of the excluded costs at December 31, 2004 relate to the acquisition of Benton Offshore China Company and exploration related to its WAB-21 property. The ultimate timing of when the costs related to the acquisition of Benton Offshore China Company will be included in amortizable costs is uncertain.

     All capitalized costs (including oilfield inventory and future abandonment costs under SFAS 143) and estimated future development costs of proved reserves are depleted using the units of production method basedaccounting change on the total proved reserves of the country cost center. Depletion expense, which was substantially all attributable to the Venezuelan cost centerincome from continuing operations for the years ended December 31, 2004, 20032006 and 20022005 was $34.1 million, $19.6a decrease of $4.9 million and $24.9$15.0 million, ($2.56, $2.52net of income tax, or $0.13 and $2.56$0.39 per equivalent barrel),diluted share, respectively.

     A gain The decrease in income from continuing operations was due to an increase in depletion expense. There was no effect on cash and cash equivalents.

     Properties and equipment are stated at cost less accumulated depreciation, depletion and amortization (“DD&A”). Costs of improvements that appreciably improve the efficiency or loss is recognized on the saleproductive capacity of oilexisting properties or extend their lives are capitalized. Maintenance and gas properties only when the sale involves a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved property.

repairs are expensed as incurred. Upon retirement

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or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if appropriate, gains or losses are recognized in Investment Earnings and Other.
     Exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense. Costs of drilling successful exploratory wells, all development wells, and related production equipment and facilities are capitalized and depleted or depreciated using the unit-of-production method as oil and gas is produced.
     Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent associated with successful exploration activities. Costs of maintaining and retaining undeveloped leaseholds, as well as amortization and impairment of unsuccessful leases, are included in exploration expense. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties.
     Proved oil and gas properties are reviewed for impairment for which identifiable cash flows are independent of cash flows of other assets when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are determined based on estimated future oil and gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these undiscounted estimated future net cash flows is less than the carrying amount of the property, an impairment loss is recognized for the excess, if any, of the property’s carrying amount over its estimated fair value, which is generally based on discounted future net cash flows.
     Costs of drilling and equipping successful exploratory wells, development wells, asset retirement costs and costs to construct or acquire offshore platforms and other facilities, are depreciated using the unit-of-production method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved leaseholds, are depleted using the unit-of-production method based on total estimated proved developed and undeveloped reserves. All other properties are stated at historical acquisition cost, net of allowance for impairment, and depreciated using the straight-line method over the useful lives of the assets.
     Undeveloped property costs consist of $2.9 million for WAB-21, $0.1 million for the Dussafu Marin exploration production sharing contract (“Dussafu PSC”) and $0.2 million for the Budong-Budong production sharing contract (“Budong PSC”). None of these costs are being amortized and have not been impaired.
     Depreciation of furniture and fixtures is computed using the straight-line method with depreciation rates based upon the estimated useful life of the property, generally 5 years. Leasehold improvements are depreciated over the life of the applicable lease. Depreciation expense was $1.9$0.4 million, $1.6$0.6 million and $1.4$2.8 million for the years ended December 31, 2004, 20032007, 2006 and 2002,2005, respectively.

     The major components of property and equipment at December 31 are as follows (in thousands):

         
  2004  2003 
         
Proved property costs $621,679  $582,456 
Costs excluded from amortization  2,900   2,900 
Oilfield inventories  6,503   8,266 
Other administrative property  10,008   8,948 
       
   641,090   602,570 
Accumulated depletion, impairment and depreciation  (453,941)  (418,507)
       
  $187,149  $184,063 
       

     We perform a quarterly cost center ceiling test of our oil and gas properties under the full cost accounting rules of the SEC. The consolidated financial statements of the wholly-owned and majority owned subsidiaries do not include ceiling test write-downs in 2004 or 2003. Equity in Net Losses of Affiliated Companies includes a $32.3 million (our share) ceiling test write-down recorded by Geoilbent during their fiscal year ending September 30, 2003.

Stock-Based Compensation

     At December 31, 20042007 and 2003,2006, we had several stock-based employee compensation plans, which are more fully described inNote 5 –— Stock Option and Stock Purchase Plans. Prior to 2003, we accounted for those plans under the recognition and measurement provisions of APBAccounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Effective January 1, 2003, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards StatementSFAS No. 123 (“FAS 123”), Accounting for Stock-Based Compensation as amended by SFAS No. 148 (“SFAS 148”), prospectively to all employee awards granted, modified, or settled after January 1, 2003. Effective January 1, 2005, we adopted SFAS 123 (revised 2004) Share-Based Payment (“SFAS 123R”) to all employee awards granted, modified, or settled after October 1, 2005. The effect of the adoption of SFAS 123R was not material. Awards under our plans vest in periodic installments after one year of their grant and expire ten years from grant date. Therefore, the costs related to stock-based employee compensation included in the determination of net income in the yearsyear ended December 31, 2004 and 2003 are2005 is less than that which would have been

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recognized if the fair value based method had been applied to all awards since the original effective date of FAS 123. The following table illustrates the effect on net income and earnings per share if the fair value based method had been applied to all outstanding and unvested awards in each period.
             
  2004  2003  2002 
             
Net income, as reported $34,360  $27,303  $100,362 
             
Add: Stock-based employee compensation cost, net of tax  999   296   915 
             
Less: Total stock-based employee compensation cost determined under fair value based method, net of tax  (1,382)  (1,056)  (2,905)
          
             
Net income – proforma $33,977  $26,543  $98,372 
          
Net income per common share:            
Basic – as reported $0.95  $0.77  $2.90 
          
Basic – proforma $0.94  $0.75  $2.87 
          
             
Diluted – as reported $0.90  $0.74  $2.78 
          
Diluted – proforma $0.89  $0.72  $2.75 
          
     
  2005 
  (in thousands, except per share data) 
Net income, as reported $38,876 
     
Add: Stock-based employee compensation cost, net of tax  2,635 
     
Less: Total stock-based employee compensation cost determined under fair value based method, net of tax  (2,711)
    
     
Net income — proforma $38,800 
    
Net income per common share:    
Basic — as reported $1.05 
    
Basic — proforma $1.05 
    
     
Diluted — as reported $1.01 
    
Diluted — proforma $1.01 
    

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     Stock options of 0.4 million, 0.1 million and 0.2 million were exercised in the years ended December 31, 2007, 2006 and 2005, respectively, with cash proceeds of $1.9 million, $0.9 million and $0.8 million, respectively.

Income Taxes

     Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carryforwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

With the formation of Petrodelta, Harvest Vinccler recognized the deferred tax related to the deferred revenue discussed above.

Foreign Currency

     We have significant

     Most of our operations are outside of the United States, principally in Venezuela and, until September 25, 2003, a minority equity investment in Russia.States. The U.S. Dollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in U.S. Dollars, and all currency gains or losses are recorded in the statement of operations. We attempt to manage our operations in a manner to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan currency to the U.S. Dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates.

Financial Instruments

     Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents marketable securities and accounts receivable. Cash and cash equivalents are placed with commercial banks with high credit ratings. This diversified investment policy limits our exposure both to credit risk and to concentrations of credit risk. Accounts receivable result from oil and natural gas exploration and production activities and our customers and partners are engaged in the oil and natural gas business. PDVSA purchases 100 percent of our Venezuelan oil and gas production. Although we do not currently foresee a credit risk associated with these receivables, collection is dependent upon the financial stability of PDVSA.

     The book values of all financial instruments are representative of their fair values due to their short-term maturities. The aggregate fair value of our senior unsecured notes, based on the last trading prices at December 31, 2003, was approximately $85.0 million. Our senior unsecured notes were repaid in the quarter ended September 30, 2004.

Comprehensive Income

     Statement of Financial Accounting Standards No. 130 (“SFAS 130”) requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. We reflected unrealized mark-to-market losses from cash flow hedging activities as other comprehensive loss during the year ended December 31, 2004 and in accordance with SFAS 130, have provided a separate line in the audited consolidated statement of operations and comprehensive income.

Minority Interests

     We record a minority interest attributable to the minority shareholder of our Netherlands, Venezuela and Barbados subsidiaries. The minority interests in net income and losses are generally subtracted from or added to arrive at consolidated net income.

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Change in Accounting Principle
     In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method. Although the full cost method of accounting for oil and gas exploration and development continues to be an accepted method of accounting for oil and gas properties, the successful efforts method of accounting as prescribed by SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies is the preferred method. In accordance with SFAS No. 154 Accounting Changes and Error Corrections, financial information for prior periods has been restated to reflect retrospective application of the successful efforts method. We believe the successful efforts method provides a more transparent representation of our results of operations and the ability to assess our future investments in oil and gas properties for impairment based on their estimated fair values rather than being required to base valuation on prices and costs as of the balance sheet date. The significant differences between successful efforts and full cost accounting for oil and gas properties relate to the expensing of exploration activities and related unsuccessful exploratory drilling activities. The expensing of these costs can create volatility in the statement of operations. The change in accounting principle resulted in a cumulative, non-cash increase to retained earnings of $52.4 million, net of income tax, as of December 31, 2004. Retained earnings increased due to the reversal of ceiling test write downs in prior years required under the full cost accounting rules of the SEC. There were no such impairments under the successful efforts accounting rules. The effect of the accounting change on income from continuing operations for the years ended December 31, 2006 and 2005 was a decrease of $4.9 million and $15.0 million, net of income tax, or $0.13 and $0.39 per diluted share, respectively. The decrease in income from continuing operations was due to an increase in depletion expense. There was no effect on cash and cash equivalents.
New Accounting Pronouncements

     In December 2004,February 2008, the FinancialFASB issued FASB Staff Position (“FSP”) 157-1 — Application of FASB Statement No. 157 to FASB Statement No. 13 and Its Related Interpretive Accounting Standards BoardPronouncements That Address Leasing Transactions (“FASB’) issued Statement of Financial Accounting Standard 123 (revised 2004) Share-Based Payment (“SFAS 123R”FSP 157-1”), an amendment to Statement ofwhich excludes SFAS 13 Accounting Standards 123for Leases, and 95. SFAS 123R focuses primarily onits related interpretive accounting for transactions in which an entity obtains employee services in share-based payment transactions. Public companies with a calendar year-end will be required to adoptpronouncements from the provisions of SFAS 157. FSP 157-1 is effective with the standard effective for periods beginning after June 15, 2005. We doinitial adoption of SFAS 157. FSP 157-1 will not expect SFAS 123R to have a material effect on our consolidated financial position, results of operationoperations or cash flows.

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     In December 2004,February 2008, the FASB issued FASB Staff Position (“FSP”) 157-2 — Effective Date of FASB Statement of Financial Accounting Standard 153 Exchanges of Nonmonetary AssetsNo. 157 (“SFAS 153”FSP 157-2”), an amendmentwhich delays the effective date of Accounting Principles Board (“APB”) Opinion No. 29 (“Opinion 29”). SFAS 153 amends Opinion 29 to eliminate the exception157 for nonmonetary exchanges of similar productiveall nonfinancial assets and replaces it withnonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a general exception for exchanges of nonmonetary assets that dorecurring basis (at least annually), until January 1, 2009. FSP 157-2 will not have commercial substance. We do not expect SFAS 153 to have a material effect on our consolidated financial position, results of operationoperations or cash flows.

     In September 2004,February 2007, the SECFinancial Accounting Standards Board (“FASB”) issued Staff Accounting Bulletin 106SFAS 159 — The Fair Value Option for Financial Assets and Financial Liabilities (“SAB 106”SFAS 159”), which provides guidance regardingpermits entities to choose to measure many financial instruments and certain other items at fair value. SFAS 159 is effective as of the interactionbeginning of an entity’s first fiscal year that begins after November 15, 2007. SFAS 159 will not have a material effect on our consolidated financial position, results of operations or cash flows.
     In December 2007, the FASB issued SFAS 141 (revised 2007) — Business Combinations (“SFAS 141R”). The objective of SFAS 143 with141R is to improve the calculation of depletionrelevance, representational faithfulness, and the full cost ceiling test of oil and gas properties under the full cost accounting rulescomparability of the SEC. The guidance providedinformation that a reporting entity provides in SAB 106its financial reports about a business combination and its effects. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. When adopted, SFAS 141R is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.

     In January 2003,December 2007, the FASB issued InterpretationSFAS 160 — Noncontrolling Interest in Consolidated Financial Statements — an amendment of ARB No. 4651 (“FIN 46”SFAS 160”) Consolidation. The objective of Variable Interest Entities, which addressesSFAS 160 is to improve the consolidation of variable interest entities (“VIEs”) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the majorityrelevance, comparability and transparency of the risksfinancial information that a reporting entity provides in its consolidated financial statements. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning

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on or rewards associated with the VIE. In December 2003, the FASB issued a revision to FIN 46, Interpretation No. 46R (“FIN 46R”), to clarify some of the provisions of FIN 46, and to defer certain entities from adopting until the end of the first interim or annual reporting period ending after March 15, 2004. Application of FIN 46R is required in financial statements of public entities that have interests in structures that are commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application for all other types2008. Early adoption is prohibited. When adopted, SFAS 160 is not expected to have a material effect on our consolidated results of VIEs is required in financial statements for periods ending after March 15, 2004. We believe we have no arrangements that would require the application of FIN 46R. We have no off-balance sheet arrangements.

operations or cash flows.

Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of AmericaGAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil plant products and natural gas reserve volumes and the future development costs. Actual results could differ from those estimates.

Reclassifications

     Certain items in 2002 and 2003 have been reclassified to conform to the 2004 financial statement presentation.

Note 2 -— Long-Term Debt and Liquidity

Long-Term Debt

Long-term debt consists of the following (in thousands):
         
  December 31,  December 31, 
  2004  2003 
Senior unsecured notes with interest at 9.375% See description below $—  $85,000 
Note payable with interest at 6.1% See description below  1,500   2,700 
Note payable with interest at 7.1%  10,333   15,500 
       
   11,833   103,200 
Less current portion  11,833   6,367 
       
  $—  $96,833 
       
         
  December 31,  December 31, 
  2007  2006 
Note payable with interest at 10.0% $—  $55,814 
Note payable with interest at 10.0%  —   39,535 
Note payable with interest at 12.5%  9,302   9,302 
       
   9,302   104,651 
         
Less current portion  9,302   37,674 
       
  $—  $66,977 
       

     In

     On September 27, 2006, Harvest Vinccler entered into a three-year term loan with a Venezuelan bank for 105 billion Bolivars (approximately $48.8 million). The first principal payment was due 360 days after the funding date in the amount of 21 billion Bolivars (approximately $9.8 million), and 21 billion Bolivars (approximately $9.8 million) every 180 days thereafter. The interest rate for the first year was fixed at 10.0 percent and was renegotiated for the second year subject to a maximum of 95 percent of the average interest rate charged by six major Venezuelan banks. The interest rate was adjusted to 12.5 percent on October 1, 2007. The loan was used to meet income tax assessments and related interest of the SENIAT, the Venezuelan income tax authority. The loan was repaid on October 18, 2007.
     On October 3, 2006, Harvest Vinccler entered into a term loan with a Venezuelan bank for 20 billion Bolivars (approximately $9.3 million). The original loan matured on April 2, 2007. At maturity, Harvest Vinccler and the Venezuelan bank agreed to extend the loan for an additional 180 days subject to the same terms and conditions. The extended loan matured September 28, 2007 at a fixed interest rate of 10.0 percent. The loan was repaid on September 28, 2007.
     On November 1997, we issued $115.0 million20, 2006, Harvest Vinccler entered into a three-year term loan with a Venezuelan bank for 120 billion Bolivars (approximately $55.8 million). The first principal payment was due 180 days after the funding date in 9.375the amount of 20 billion Bolivars (approximately $9.3 million), and 20 billion Bolivars (approximately $9.3 million) every 180 days thereafter. The interest rate for the first 180 days was fixed at 10.0 percent senior unsecured notes due November 1, 2007 (“2007 Notes”),and may be adjusted from time to time thereafter within the limits set forth by the Central Bank of which we repurchased $30.0 million. In September 2004, we announced that the remaining 2007 Notes would be redeemed on November 1, 2004, and we irrevocably depositedVenezuela or in accordance with the Trusteeconditions in the financial market. The interest rate was adjusted to 12.5 percent on October 1, 2007. The loan is collateralized by a $6.8 million deposit plus interest in a U.S. bank. The loan was used to meet the SENIAT income tax assessments and related interest, refinance a portion of the 105 billion Bolivar loan and to fund operating requirements.
     During the ten months ended October 31, 2007, we exchanged through an intermediary, U.S. government securities for the 2007 Notes as trust funds $85.0 million plus accrued interest through November 1, 2004 and a prepayment call premium

U.S. Dollar indexed Venezuelan government securities that can only be converted into Bolivars. The additional Bolivars were used to pay down Harvest Vinccler’s Bolivar denominated debt. Harvest Vinccler reduced

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of $1.3 million

its Bolivar denominated debt to redeem the20.0 billion Bolivars (approximately $9.3 million) by October 30, 2007 Notesusing exchange transactions as more fully described inNote 12 — Gain on the redemption date. We were released from all obligations related to the 2007 Notes upon depositFinancing Transactionand in advance of the trust funds witheffective date for the Trustee. We recorded a lossTax on early extinguishment of debt of $2.9 million which includes the $1.3 million prepayment call premium, $0.7 million for interest related to the period October 1, 2004 to November 1, 2004 and $0.9 million write-off of unamortized debt financing costs. Our repayment of the 2007 Notes triggered an obligation under the terms of Harvest Vinccler’s loans from a Venezuelan commercial bank to renegotiate the terms of those loans or, if agreement on renegotiated terms cannot be reached within 30 days after November 1, 2004, the loans can be declared due and payable. Harvest Vinccler isFinancial Transactions described in discussions with the Venezuelan bank on possible renegotiated terms. The entire amount has been reclassified from long term to current in the interim. While we believe the loans will be renegotiated, it is possible that agreement will not be reached and Harvest Vinccler will be required to repay the remaining balance of $11.8 million. As of February 11, 2005, no agreement had been reached.

     In March 2001, Harvest Vinccler borrowed $12.3 million from a Venezuelan commercial bank, for construction of an oil pipeline. The loan is in two parts, with the first part in an original principal amount of $6.0 million that bears interest payable monthly based on 90-day London Interbank Borrowing Rate (“LIBOR”) plus 5 percent with principal payable quarterly for five years. The second part, in the original principal amount of 4.4 billion Venezuelan Bolivars (“Bolivars”) (approximately $6.3 million)Note 4 — Taxes. The Bolivar loan was repaid as of March 31, 2003. The loans provide for certain limitations on mergers and sale of assets. We have guaranteed the repayment of the remaining loan.

     In October 2002, Harvest Vinccler, C.A. executed a note and borrowed $15.5 million to fund construction of a gas pipeline and related facilities to deliver natural gas from the Uracoa field to a PDVSA pipeline. The interest rate for this loan is 90-day LIBOR plus 6 percentage points. The term is four years with a quarterly amortization of $1.3 million beginning with the first quarter 2004 to coincide with the first payment from our gas sales.

     We have classified all of our outstanding debt as current at December 31, 2004.

Note 3 -— Commitments and Contingencies

     We have employment contracts with six executive officers which provide for annual base salaries, eligibility for bonus compensation and various benefits. The contracts provide for a lump sum payment as a multiple of base salary in the event of termination of employment without cause. In addition, these contracts provide for payments as a multiple of base salary and bonus, excise tax reimbursement and a continuation of benefits in the event of termination without cause following a change in control. By providing one year notice, these agreements may be terminated by either party on May 31, 2006 for five of the executives and on May 7, 2007 for the sixth executive.

2008.

     In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month. We moved into the new space in August 2004. In addition,Also during 2004, Harvest Vinccler leased newsigned a five-year lease for office space in Maturin and Caracas, Venezuela for $13,200 and $4,000 per month, respectively. We leased 17,500 square feet of space in a California building that we no longer occupy under a lease agreement that expired in December 2004, all of which was subleased for rents that approximated our lease costs.

month.

     Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Harvest Vinccler,Benton-Vinccler, C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, Texas. This suit was brought in May 2003 by Excel alleging, among other things, breach of a consulting agreement between Excel and us, misappropriation of proprietary information and trade secrets, and fraud. Excel seeks actual and exemplary damages, injunctive relief and attorneys’ fees. TheIn October 2003, the Court has abated the suit pending final judgment of a case pending in Louisiana to which we are not a party. In April 2007, the Court lifted the abatement and set the case for trial. The trial date has been set in the second quarter 2008. We dispute Excel’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.

     Uracoa Municipality Tax Assessments. In July 2004, Harvest Vinccler has received three taxnine assessments from a tax inspector for the Uracoa municipality in which part of the South Monagas Unit is located. A protest to the assessments was filed with the municipality, and in September 2004 the tax inspector responded in part by affirming one of the assessments and issuing a payment order. SMU Fields are located as follows:
•Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the capital fee reimbursement and related interest paid by PDVSA under the OSA. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims.
•Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the Municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims.
•Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim.
•Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims.
Harvest Vinccler has filed a motion withdisputes the tax court in Barcelona, Venezuela, seeking to enjoin the payment order and dismiss the assessment. We dispute all of theUracoa tax assessments and believe we havebelieves it has a substantial basis for ourits positions. We areHarvest Vinccler is unable to estimate the amount or range of any possible loss.

As a result of the SENIAT’s interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.
Libertador Municipality Tax Assessments. Harvest Vinccler has received five assessments from a tax inspector for the Libertador municipality in which part of the SMU Fields are located as follows:

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•One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the Municipality. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim.
•Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claims.
•Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claims.
Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the refund of all municipal taxes paid since 2002.
     In June 2007, the SENIAT issued an assessment in the amount of $0.4 million for Harvest Vinccler’s failure to withhold value added tax (“VAT”) from vendors during 2005. The SENIAT has recognized a payment made by Harvest Vinccler in 2006 for the underwithheld VAT and has partially confirmed that some of the affected vendors have remitted the underwithheld VAT. Harvest Vinccler has received credit, less penalties and interest, from the SENIAT for the VAT remitted by the vendors. Harvest Vinccler has filed claims against the SENIAT for the portion of VAT not recognized by the SENIAT and believes it has a substantial basis for its position.
     We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such litigation which will have a material adverse impact on our financial condition, results of operations and cash flows.

Note 4 — Taxes

Taxes Other Than on Income

     Harvest Vinccler payspaid municipal taxes through the first quarter 2006 on operating fee revenues it receivesreceived under the OSA for productiondeliveries from the South Monagas Unit. The year ended December 31, 2002 included a non-recurring foreign payrollSMU Fields. In September 2006, PDVSA remitted to the Uracoa municipality an additional $1.0 million in municipal taxes based on the new tax adjustment of $0.7 million.rates from amounts that had been withheld by PDVSA from Harvest Vinccler’s first quarter 2006 oil and natural gas sales for other purposes. The components of taxes other than on income were (in thousands):
                        
 2004 2003 2002  2007 2006 2005 
Venezuelan municipal taxes $4,485 $2,741 $3,805  $— $3,191 $5,788 
Franchise taxes 464 341 139  166 175  (70)
Payroll and other taxes 612 291 124  257 582 640 
              
 $5,561 $3,373 $4,068  $423 $3,948 $6,358 
              
Contribution to Science and Technology Fund
     In 2005, Venezuela modified the Science and Technology Law to require companies doing business in Venezuela to invest, contribute, or spend a percentage of their gross revenue on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. In October 2006, the Executive Branch issued the Regulations for the Science and Technology Law which established the methodology for determining the required investment, contribution or expenditure for the 2005 calendar year financial results. Harvest Vinccler was unable to estimate the corresponding percentage of the gross revenue for 2005 or the first quarter of 2006 until the regulations were released as many aspects of the law were unclear. After release of the regulations, Harvest Vinccler accrued $3.9 million for the estimated liability for 2005 and the first quarter of 2006 based on its current understanding of

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the regulations. Harvest Vinccler did not have any gross revenue subject to this law after March 31, 2006. The regulation provides that the amount that is not invested, contributed or spent must be deposited with an official agency created to administrate the law which has yet to be formed. This liability will be paid in the first quarter of 2008.
Tax on Financial Transactions
     In October 2007, the government of Venezuela announced the application of a new tax on financial transactions (the “TFT”) to private companies. The TFT does not apply to individuals. The tax was set at 1.5 percent of the value of the transaction. The TFT applies to all debits to bank accounts as well as payments of debt outside the banking system and is not tax deductible. The levy will be applied from November 1, 2007 through December 31, 2008. The TFT will not have a material effect on Harvest Vinccler’s financial position, results of operations or cash flows.
Taxes on Income

     The tax effects of significant items comprising our net deferred income taxes as of December 31, 2004 and 20032006 are as follows (in thousands):
         
  2004  2003 
Deferred tax assets – non-current:        
Operating loss carryforwards $14,748  $20,442 
Difference in basis of property  28,753   29,602 
Other  3,025   3,070 
Valuation allowance  (40,492)  (48,365)
       
Net deferred tax asset – non-current $6,034  $4,749 
       
     
  2006 
Deferred tax assets:    
Operating loss carryforwards $7,466 
Difference in basis of assets  25,343 
Deferred revenue  5,608 
Valuation allowance  (32,809)
    
Net deferred tax asset  5,608 
Less current portion  5,608 
    
  $— 
    

     The valuation allowance decreased by $7.9$32.8 million as a result of the change inelimination of the U.S. deferred tax assets related to the net operating loss carryforward as well as aand the basis difference on our Venezuelan deferred tax asset impairment.assets prior to converting to Petrodelta. Realization of deferred tax assets associated with net operating loss carryforwards is dependent upon generating sufficient taxable income prior to their expiration. Management believesanticipates that additional losses will be generated and that it is more likely than not that they will not be realized through future taxable income.

     The components of income before income taxes and minority interest are as follows (in thousands):
                        
 2004 2003 2002  2007 2006 2005 
Income (loss) before income taxes  
United States $(16,593) $34,236 $92,394  $(17,786) $(15,688) $8,178 
Foreign 97,859 37,552 77,417  48,700 2,391 99,962 
              
Total $81,266 $71,788 $169,811  $30,914 $(13,297) $108,140 
              

     The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):
                        
 2004 2003 2002  2007 2006 2005 
Current:  
United States $(8) $1,187 $351  $400 $— $739 
Foreign 34,581 9,137 6,326  5,912 63,473 53,304 
              
 $34,573 $10,324 $6,677  6,312 63,473 54,043 
        
 
Deferred:  
United States $— $— $53,413 
Foreign  (1,285)  (667) 205  —  (2,556) 2,982 
              
  (1,285)  (667) 53,618  $6,312 $60,917 $57,025 
              
 $33,288 $9,657 $60,295 
       

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     A comparison of the income tax expense (benefit) at the federal statutory rate to our provision for income taxes is as follows (in thousands):
             
  2004  2003  2002 
Computed tax expense at the statutory rate $28,443  $15,025  $59,348 
State income taxes  25   1,188   353 
Effect of foreign source income and rate differentials on foreign income  (2,169)  (15,849)  (19,373)
Change in valuation allowance  7,020   9,219   19,446 
All other  (31)  74   80 
          
Sub-total income tax expense  33,288   9,657   59,854 
Effects of recording equity income of certain affiliated Companies on an after-tax basis  —   —   441 
          
Total income tax expense $33,288  $9,657  $60,295 
          
             
  2007  2006  2005 
Computed tax expense (benefit) at the statutory rate $10,820  $(2,930) $43,083 
Effect of foreign source income and rate differentials on foreign income  (11,140)  8,563   16,065 
Change in valuation allowance  1,085   5,446   13,129 
Alternative minimum tax  —   —   739 
Deemed income inclusion  12,942   —   — 
Venezuela tax settlement  —   49,793   — 
Net operating loss utilization  (7,306)  —   (15,567)
Other  (89)  45   (424)
          
Total income tax expense $6,312  $60,917  $57,025 
          

     Rate differentials for foreign income result from tax rates different from the U.S. tax rate being applied in foreign jurisdictions andjurisdictions.
     The net operating loss carryforwards from the effect of foreign currency devaluation in foreign subsidiaries which use the2006 for U.S. Dollar as their functional currency.

     At December 31, 2004, we had, for federal income tax purposes operating loss carryforwards of approximately $42.1 million, expiring in the years 2014 through 2025.

were fully utilized at December 31, 2007.

     We do not provide deferred income taxes on undistributed earnings of international consolidated subsidiaries for possible future remittances as all such earnings are reinvested as part of our ongoing business. The amount of deferred taxes on the undistributed earnings cannot be determined at this time.

FIN 48 Disclosure
     In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of SFAS 109, Accounting for Income Taxes (“FIN 48”), to create a single model to address accounting for uncertainty in tax positions. FIN 48 clarifies the accounting for income taxes, by prescribing a minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We have adopted FIN 48 as of January 1, 2007, as required.
     We or one of our subsidiaries files income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2004. To date, the Internal Revenue Service (“IRS”) has not performed an examination of our U.S. income tax returns for 2004 through 2006.
     The adoption of FIN 48 has not had a significant impact on our consolidated financial position, results of operations or cash flows. We do not have any unrecognized tax benefits.
Note 5 — Stock Option and Stock Purchase Plans
     In May 2006, our shareholders approved the 2006 Long Term Incentive Plan (the “2006 Plan”). The 2006 Plan provides for the issuance of up to 1,825,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to eligible participants including employees, non-employee directors and consultants of our company or subsidiaries. Under the 2006 Plan, no more than 325,000 shares may be granted as restricted stock. No individual may be granted more than 900,000 options or SARs and no more than 175,000 shares of restricted stock during any period of three consecutive calendar years. The exercise price of stock options granted under the 2006 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted through December 31, 2006 vest ratably over a three to five year period from their dates of grant and expire seven to ten years from grant date. Restricted

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stock granted to employees or consultants to date is subject to a restriction period of not less than 36 months during which the stock will be deposited with Harvest Natural Resources, Inc. (“Harvest”) and is subject to forfeiture under certain circumstances. Restricted stock granted to non-employee directors vests as to one-third of the shares on each anniversary of the date of grant of the award provided that he is still a director on that date. The 2006 Plan also permits the granting of performance awards to eligible employees and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time of at least one year. No employee or consultant shall be granted a performance award during a calendar year that could result in a cash payment of more than $5.0 million. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become exercisable.
     In May 2004, our shareholders approved the 2004 Long Term Incentive Plan (the “Plan”“2004 Plan”). The 2004 Plan provides for the issuance of up to 1,750,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to eligible participants including employees, non-employee directors and consultants of our company or subsidiaries. Under the 2004 Plan, no more than 438,000 shares may be granted as restricted stock, and no individual may be granted more than 110,000 shares of restricted stock or 438,000 in options over the life of the Plan. The exercise price of stock options granted under the plan2004 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted to date will vest ratably over a three-year period from their dates of grant and expire ten years from grant date. All restricted stock granted to date is subject to a restriction period of 36 months during which the stock will be deposited with the CompanyHarvest and is subject to forfeiture under certain circumstances. The 2004 Plan also permits the granting of performance awards to eligible employees and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time of at least one year. Performance awards granted under the Plan may not exceed $5.0 million in a calendar year and may not exceed $2.5 million to any one individual in a calendar year. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become exercisable.

     In January 2001, we adopted the Non-Employee Director Stock Purchase Plan (the “Stock Purchase Plan”) to encourage our directors to acquire a greater proprietary interest in us through the ownership of our common stock. Under the Stock Purchase Plan, each non-employee director could elect to receive shares of our common stock for all or a portion of their fee for serving as a director. The number of shares issuable is equal to 1.5 times the amount of cash compensation due the director divided by the fair market value of the common stock on the scheduled date of payment of the applicable director’s fee. The shares have a restriction upon their sale for one year from the date of issuance. As of December 31, 2002, 337,850 shares had been issued from the plan. The Stock Purchase Plan was terminated by the Board of Directors in September 2002.

     In July 2001, our shareholders approved the adoption of the 2001 Long Term Stock Incentive Plan.Plan (the “2001 Plan”). The 2001 Long Term Stock Incentive Plan provides for grants of options to purchase up to 1,697,000 shares of our common stock in the form of Incentive Stock Options and Non-Qualified Stock Options to eligible participants including employees of our company or subsidiaries, directors, consultants and other key persons. The exercise price of stock options granted under the plan2001 Plan must be no less than the fair market value of our common stock on the date of grant. No officer may be granted more than 500,000 options during any one fiscal year, as adjusted for any

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changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date.

     Since 1989 we have adopted several other stock option plans under which options to purchase shares of our common stock have been granted to employees, officers, directors, independent contractors and consultants. Options granted under these plans have been at prices equal to the fair market value of the stock on the grant dates. Options granted under the plans are generally exercisable in varying cumulative periodic installments after one year and cannot be exercised more than ten years after the grant dates. Following the adoption of the 2001 Long Term Stock Incentive Plan, no options may be granted under any of these plans.

     A summary of the status of our stock option plans as of December 31, 2004, 20032007, 2006 and 20022005 and changes during the years ending on those dates is presented below (shares in thousands):
                                                
 2004 2003 2002  2007 2006 2005
 Weighted Weighted Weighted  Weighted Weighted Weighted
 Average Average Average  Average Average Average
 Exercise Exercise Exercise  Exercise Exercise Exercise
 Price Shares Price Shares Price Shares  Price Shares Price Shares Price Shares
Outstanding at beginning of the year: $7.52 4,523 $7.42 5,223 $6.36 6,865  $7.70 4,123 $8.61 4,070 $8.18 3,793 
Options granted 13.36 378 6.26 246 4.84 165  9.63 866 10.62 558 11.51 922 
Options exercised  (7.41)  (955) 2.32  (494) 2.21  (1,515)  (4.73)  (397)  (5.69)  (65)  (3.45)  (241)
Options cancelled  (6.31)  (153) 11.37  (452) 8.03  (292)  (13.49)  (420)  (19.96)  (440)  (14.24)  (404)
              
Outstanding at end of the year 8.18 3,793 7.52 4,523 7.42 5,223  7.80 4,172 7.70 4,123 8.61 4,070 
              
Exercisable at end of the year 7.71 3,236 8.18 3,857 8.49 4,360  5.87 2,372 5.91 2,719 7.40 2,886 
              

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     Significant option groups outstanding at December 31, 20042007 and related weighted average price and life information follow:follow (shares in thousands):
                     
  Outstanding  Exercisable 
Range of Number  Weighted-Average      Number    
Exercise Outstanding At  Remaining  Weighted-Average  Exercisable at  Weighted-Average 
Prices December 31, 2004  Contractual Life  Exercise Price  December 31, 2004  Exercise Price 
$1.55 - $2.75  1,701,149   4.93  $1.96   1,701,149  $1.96 
$4.80 - $7.10  410,834   7.28   5.74   226,832   5.57 
$8.72 - $10.88  153,900   0.73   8.86   153,900   8.86 
$11.50 - $16.90  1,091,907   3.29   13.48   719,332   13.54 
$17.88 - $24.13  434,833   0.33   21.23   434,833   21.23 
                   
   3,792,623           3,236,046     
                   
                             
  Outstanding  Exercisable 
      Weighted-                  
      Average  Weighted          Weighted-    
Range of
 Number  Remaining  Average  Aggregate  Number  Average  Aggregate 
Exercise
 Outstanding  Contractual  Exercise  Intrinsic  Exercisable  Exercise  Intrinsic 
Prices
 at 12/31/07  Life  Price  Value  at 12/31/07  Price  Value 
$  1.55 -  $   2.75  1,295   2.29  $2.02  $13,576   1,295  $2.02  $13,576 
$  4.86 -  $   7.10  226   4.78   5.82   1,509   226   5.82   1,509 
$  8.72 -  $ 10.91  1,906   7.40   9.90   4,958   300   9.32   954 
$12.50 -  $ 13.90  745   6.89   13.09   —   551   13.06   — 
                         
   4,172          $20,043   2,372      $16,039 
                         

     The aggregate intrinsic value in the preceding table represents the total pretax intrinsic value based on our closing stock price of $12.50 as of December 31, 2007, which would have been received by the option holders had all option holders exercised their options as of that date. Of the number outstanding, 858,750408,750 options are pledged to us to secure a repayment of debt. SeeNote 12 – Related Party Transactions.

     The value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions:
     For options granted during:
             
  2007 2006 2005
Weighted average fair value $4.67  $5.98  $6.35 
Weighted averaged expected life  7   7   7 
Valuation assumptions:            
Expected volatility  47.7-48.7%  49.9%-53.3%  50.0%-53.4%
Risk-free interest rate  4.5%-4.6%  4.6%-5.2%  3.9%-4.6%
Expected dividend yield  0%  0%  0%
Expected annual forfeitures  3%  3%  3%
     The Black-Scholes option pricing model was developed for use in estimating the value of traded options that have no vesting restrictions and are fully transferable. In connection with our acquisitionaddition, option pricing models require the input of Benton Offshore China Company in December 1996, we adoptedhighly subjective assumptions, including the Benton Offshore China Company 1996 Stock Option Plan. Under the plan, Benton Offshore China Companyexpected stock price volatility and expected life. The expected volatility is authorized to issue up to 107,571 options to purchase our common stock for $7.00 per share. The plan was adopted in substitution of Benton Offshore China Company’s stock option plan, and all options to purchase shares of Benton Offshore China Company common stock were replaced under the plan by options to purchase sharesbased on historical volatilities of our common stock. AllHistorical data is used to estimate option exercise and employee termination within the valuation model. The expected term of options were issued upongranted is derived from the acquisitionoutput of Benton Offshore China Companythe option valuation model and vested upon issuance. Atrepresents the period of time that options are expected to be outstanding. The risk-free rate for the periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant.
     A summary of our nonvested shares as of December 31, 2004, options2007, and changes during the year ended December 31, 2007, is presented below (shares in thousands):
         
      Weighted-Average
      Grant-Date
Nonvested Shares Shares Fair Value
Nonvested at January 1, 2007  1,404  $6.75 
Granted  916   4.67 
Vested  (420)  (7.48)
Forfeited  (50)  (9.63)
         
Nonvested at December 31, 2007  1,850  $5.83 
         
     As of December 31, 2007, there was $5.5 million of total unrecognized compensation cost related to purchase 74,427nonvested share-based compensation arrangements granted under our plans. That cost is expected to be recognized

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over the next three to five years. The total fair value of shares of common stock were both outstandingvested during the years ended December 31, 2007, 2006 and exercisable.

2005 was $4.5 million, $4.1 million and $2.7 million, respectively.

     In addition to options issued pursuant to the plans, options have been issued to individuals other than our officers, directors or employees at prices ranging from $10.88 to $11.88$10.07 which vest over three to four years. At December 31, 2004,2007, a total of 15,00050,000 options issued outside of the plans were both outstanding andwith none exercisable.

Note 6 — Stock Warrants

          The date the warrants were issued, the expiration date, the exercise price and the number of warrants issued and outstanding at December 31, 2004 were (warrants in thousands):

               
        Warrants
Date Issued Expiration Date Exercise Price Issued Outstanding
June 1995 June 2007 $17.09   125   125 

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Note 7 — Operating Segments

     We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. With the formation of Petrodelta, we have recorded the results of operations and economic benefits of our ownership in Petrodelta from April 1, 2006 through December 31, 2007 in the fourth quarter of 2007 as Net Income from Unconsolidated Equity Affiliates. Oil and gas sales for 2007 is the recognition of the deferred revenue recorded by Harvest Vinccler for 2005 and first quarter 2006 deliveries pending clarification on the calculation of crude prices under the Transitory Agreement (seeNote 1 — Organization and Summary of Significant Accounting Policies — Revenue from Venezuela is derived primarily from the production and sale of oil and gas. Other income from USA and Other is derived primarily from interest earnings on various investments and consulting revenues.Recognition). Operations included under the heading “Russia” include project evaluation costs and other costs to maintain an office in Russia. Operations included under the heading “USA“United States and Other” include corporate management, cash management, business development and financing activities performed in the United States and other countries which do not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the USAUnited States and Other segment and are not allocated to other operating segments.
             
  2004  2003  2002 
Segment Revenues
            
Oil and gas sales:            
Venezuela $186,066  $106,095  $126,731 
          
Total oil and gas sales  186,066   106,095   126,731 
          
             
Segment Income (Loss)
            
Venezuela  54,469   23,874   64,509 
Russia  (3,524)  (29,620)  (2,777)
United States and other  (16,585)  33,049   38,630 
          
Net income $34,360  $27,303  $100,362 
          
         
  December 31,  December 31, 
  2004  2003 
Operating Segment Assets
        
Venezuela $309,794  $241,855 
Russia  385   237 
United States and other  108,408   180,768 
       
   418,587   422,860 
Intersegment eliminations  (51,101)  (48,512)
       
  $367,486  $374,348 
       
             
  2007 2006 2005
  (in thousands)
Segment Revenues
            
Oil and gas sales:            
Venezuela $11,217  $59,506  $236,941 
          
Total oil and gas sales  11,217   59,506   236,941 
          
             
Segment Income (Loss)
            
Venezuela  76,276   (46,835)  52,133 
United States and other  (19,039)  (15,667)  (13,257)
          
Net income (loss) $57,237  $(62,502) $38,876 
          

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  December 31,  December 31, 
  2007  2006 
  (in thousands) 
Operating Segment Assets
        
Venezuela $303,042  $351,943 
United States and other  126,766   155,973 
       
   429,808   507,916 
Intersegment eliminations  (16,339)  (39,551)
       
  $413,469  $468,365 
       

Note 87 — RussianVenezuela Operations

Geoilbent

— Petrodelta S.A.

     On SeptemberOctober 25, 2003, we sold our minority equity investment in Geoilbent2007, the Venezuelan Presidential Decree which formally transfers to Yukos Operational Holding Limited for $69.5 million plusPetrodelta the repaymentrights to the Petrodelta Fields subject to the conditions of the subordinated loan and certain payables owed to us by GeoilbentConversion Contract was published in the amountOfficial Gazette. Petrodelta will engage in the exploration, production, gathering, transportation and storage of $5.5 million. Priorhydrocarbons from the Petrodelta Fields for a maximum of 20 years from October 25, 2007. Petrodelta will undertake its operations in accordance with the Business Plan as set forth in Annex I to the sale, we owned 34Conversion Contract (“Business Plan”). Under the Conversion Contract, work programs and annual budgets adopted by Petrodelta must be consistent with the Business Plan. The Business Plan may be modified by a favorable decision of the shareholders owning at least 75 percent of Geoilbent, a Russian limited liability company, formed in 1991 to develop, produce and market crude oil from the North Gubkinskoye and South Tarasovskoye Fields in the Western Siberia regionshares of Russia. Our minority equity investment in GeoilbentPetrodelta. The 2008 budget of Petrodelta’s Business Plan was accounted for using the equity method and was basedapproved by its shareholders on a fiscal year ending September 30. Sales quantities attributable to Geoilbent for the period until it was sold on September 25, 2003 and for the year ended September 30, 2002 were 5.6 million barrels (3.3 million domestic and 2.3 million export) and 6.9 million barrels (4.6 million domestic and 2.3 million export), respectively. Prices for crude oil for the period until it was sold on September 25, 2003 and for the year ended September 30, 2002 averaged $14.52 ($8.61 domestic and $23.05 export) and $13.25 ($8.89 domestic and $21.73 export) per barrel, respectively. Depletion expense attributable to Geoilbent for the period until it was sold on September 25, 2003 and for the year ended September 30, 2002 was $3.23 and $3.93 per barrel, respectively. All amounts represent 100 percent of Geoilbent. Summarized financial information for Geoilbent follows (in thousands):
         
Year ended September 30: 2003  2002 
Revenues        
Oil sales $81,724  $91,598 
       
         
Expenses        
Selling and distribution expenses  5,893   6,696 
Operating expenses  15,897   15,360 
Depletion, depreciation and amortization  18,182   27,168 
Write-downs of oil and gas properties  95,000   — 
General and administrative  9,456   8,335 
Taxes other than on income  25,626   27,657 
       
   170,054   85,216 
       
         
Income (loss) from operations  (88,330)  6,382 
 
Other non-operating income (expense)        
Investment earnings and other  1,064   381 
Interest expense  (1,992)  (4,629)
Net gain on exchange rates  1,566   2,053 
       
   638   (2,195)
       
         
Income (loss) before income taxes  (87,692)  4,187 
Income tax (benefit) expense  (3,117)  302 
       
   (84,575)  3,885 
Effects of change in accounting policy  310   — 
       
Net income (loss) $(84,885) $3,885 
       
January 23, 2008.

Arctic Gas Company

     On April 12, 2002, we sold our 68 percent equity interest in Arctic Gas. The equity earnings of Arctic Gas have historically been based on a fiscal year ended September 30. The fourth quarter of 2001, the first quarter of 2002 and the first twelve days of April have been included in the results for 2002.

     We accounted for our interest in Arctic Gas using the equity method due to the significant influence we exercised over the operating and financial policies of Arctic Gas. Our weighted-average equity interest, for the year ended December 31, 2001 was 39 percent. We recorded as our share in the losses of Arctic Gas $1.5 million for the period ended April 12, 2002. Summarized financial information for Arctic Gas follows (in thousands). All amounts represent 100 percent of Arctic Gas.

S-18S-20

     
Year ended September 30: 2002 
 
Revenues    
Oil sales $7,880 
     
Expenses    
Selling and distribution expenses  3,170 
Operating expense  2,473 
Depletion, depreciation and amortization  333 
General and administrative  2,112 
Taxes other than on income  1,261 
    
   9,349 
    
     
Loss from operations  (1,469)
     
Other non-operating expense    
Other expense  (4)
Interest and foreign exchange expense  (1,722)
    
   (1,726)
    
     
Loss before income taxes  (3,195)
Income tax expense  — 
    
Net loss $(3,195)
    

Note     Petrodelta has adopted policies and procedures governing its operations, including, among others, policies and procedures for safety, health and environment, contracting, maintenance of insurance, accounting, banking and treasury and human resources, following the guidelines established by CVP. To the extent possible, such policies and procedures will be consistent with the policies and procedures of PDVSA and the ultimate parent company of HNR Finance. Petrodelta has hired personnel, largely from Harvest Vinccler; and the Board of Directors of Petrodelta has appointed the management of Petrodelta. Certain of these appointments are made by the shareholders. Effective August 9, — Venezuela2007, Mr. Karl L. Nesselrode, Vice President, Engineering and Business Development of Harvest, accepted a long-term secondment to Petrodelta as its Operations

     On July 31, 1992, we and Technical Manager. Per Petrodelta’s bylaws, the Operations and Technical Manager’s position is designated as our partner, Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), signedappointment. Mr. Nesselrode will remain an operating service agreement to reactivate and further develop three Venezuelan oil fields with Lagoven, S.A., then oneofficer of three exploration and production affiliatesHarvest. The General Manager of Petrodelta (CVP appointment) has been appointed by the Board of Directors of Petrodelta. This position is in charge of the national oil company, PDVSA. The operating service agreement coversdaily management of the Uracoa, Bombalbusiness of Petrodelta and Tucupita Fields that comprisehas the South Monagas Unit.power and duties customary to manage, direct and supervise the accounting of Petrodelta.

     Petrodelta is governed by a board of directors in accordance with the Charter and Bylaws of Petrodelta as set forth in Annex E to the Conversion Contract (“Charter and Bylaws”). Under the termsCharter and Bylaws, matters requiring shareholder approval may be approved by a simple majority with the exception of certain specified matters which require the approval by the holders of at least 75 percent of the operating service agreement, Harvest Vinccler, a Venezuelan corporation owned 80 percent by uscapital stock. These matters include: most changes to the Charter and 20 percent by Vinccler, is a contractor for PDVSA and is responsible for overall operationsBylaws; changes in the capital stock of Petrodelta that would alter the percentage participation of HNR Finance or CVP; any liquidation or dissolution of Petrodelta; any merger, consolidation or business combination of Petrodelta; disposition of all or any substantial part of the South Monagas Unit,assets of Petrodelta, except in the ordinary course of business; any financing agreement for an amount greater than $10 million; approval or modification of Petrodelta’s financial statements; creation of certain reserve funds; any distribution of dividends or return of paid-in surplus; changes to the policy regarding dividends and other distributions established by the Charter and Bylaws; changes to the Business Plan; changes to the Contract for Sale and Purchase of Hydrocarbons with PPSA; contracts with shareholders or affiliates that are not at market price; any social investment in excess of the amount required by the Venezuelan government; any waiver of material rights or actions with respect to litigation involving more than $1 million; selection of external auditors; appointment of any judicial representative or general agent of Petrodelta; and designation of a liquidator in the event of the liquidation of Petrodelta.
     The Board of Directors of Petrodelta consists of five directors, three of whom are appointed by CVP, including all necessary investmentsthe President of the Board, and two of whom are appointed by HNR Finance. Decisions of the Board of Directors are taken by the favorable vote of at least three of its members, except in the case of any decision implementing a decision of the Shareholders’ Meeting relating to reactivateany of the matters where a qualified majority is required, in which case, a favorable vote of four members will be required. The Board of Directors has broad powers of administration and developdisposition expressly granted in the fields comprisingCharter and Bylaws. The powers include: proposing budget and work programs; presenting the South Monagas Unit. Harvest Vinccler receives an operating feeannual report to the shareholders; appointing and dismissing personnel; making recommendations regarding financial reserves and utilization of surplus; making proposals on dividends consistent with the Charter and Bylaws; agreeing on contracts consistent with the work programs and budgets; opening and closing bank accounts; making, accepting, endorsing and guaranteeing bank drafts and other commercial instruments consistent with work programs and budgets; and implementing policies and procedures.
     The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PPSA signed on January 17, 2008. The form of the agreement is set forth in Annex K to the Conversion Contract. Crude oil delivered from the Petrodelta Fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets, and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference priced and prevailing market conditions. Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make payment to Petrodelta of each invoice within 60 days of the end of the invoiced production month by wire transfer, in U.S. Dollars deposited into a U.S. commercial bank accountin the case of payment for each barrel of crude oil produced (subjectand natural gas liquids delivered, and in Bolivars in the case of payment for natural gas delivered, in immediately available funds to periodic adjustments to reflect changes in a special energy index of the U.S. Consumer Price Index) and is reimbursed according to a prescribed formulabank accounts designated by Petrodelta. Any dividend paid by Petrodelta will be made in U.S. Dollars for its capital costs, provided that such operating fee and cost recovery fee cannot exceed the maximum dollar amount per barrel set forth in the agreement.

     In September 2002, Harvest Vinccler and PDVSA signed an amendment to the operating service agreement, providing for the delivery of up to 198 Bcf of natural gas through July 2012 atDollars.

HNR Finance owns a price of $1.03 per Mcf. In addition, Harvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the gas production at $7.00 per barrel beginning with our first gas sale.

     The Venezuelan government maintains full ownership of all hydrocarbons in the fields.

     We drilled ten oil wells and re-entered an additional six wells in 2004.

Note 10 — United States Operations

     We acquired a 10040 percent interest in three California State offshore oilPetrodelta and gas leases (“California Leases”) and a parcelhas recorded its share of onshore propertythe earnings of Petrodelta from Molino Energy Company, LLC. In June 2004, we sold our California onshore property, which had a zero carrying value, for net proceeds of $0.6 million. We and other parties may be responsibleApril 1, 2006 to December 31, 2007 in the State of California for any remediation costs associatedcurrent year in accordance with the onshore propertyConversion Contact. Summary historical financial information has been presented below at December 31, 2006 and 2007 and for the nine months ended December 31, 2006 and the related offshore oil and gas leases.

year ended December 31, 2007 for comparative purposes (in thousands, except per unit information):

S-19S-21

         
  Year Ended  Nine Months Ended 
  December 31, 2007  December 31, 2006 
Barrels of oil sold  5,374   5,211 
MCF of gas sold  13,456   11,519 
Total BOE  7,616   7,131 
         
Average price per barrel $58.61  $50.98 
Average price per mcf $1.54  $1.54 
         
Revenues:        
Oil sales $314,928  $265,625 
Gas sales  20,789   17,796 
Royalty  (114,847)  (96,790)
       
   220,870   186,631 
         
Expenses :        
Operating expenses  23,752   22,729 
Depletion, depreciation and amortization  18,549   17,076 
General and administrative  19,880   11,093 
Taxes other than on income  2,747   2,029 
       
   64,928   52,927 
       
         
Income from operations and before income taxes  155,942   133,704 
         
Current income tax expense  85,849   67,188 
Deferred income tax benefit  (21,348)  (23,415)
       
Net Income  91,441   89,931 
Adjustment to reconcile to reported Net Income from Unconsolidated Equity Affiliate:        
Deferred income tax benefit  21,348   23,415 
       
Net Income Equity Affiliate  70,093   66,516 
Equity interest in unconsolidated equity affiliate  40%  40%
       
Income before amortization of excess basis in equity affiliate  28,037   26,606 
Amortization of excess basis in equity affiliate  (2,530)  — 
       
Net income from unconsolidated equity affiliate $25,507  $26,606 
       
         
  December 31, December 31,
  2007 2006
Current assets $464,904  $206,907 
Property and equipment  190,613   200,376 
Other assets  38,738   23,415 
Current liabilities  287,491   122,896 
Other liabilities  5,964   5,420 
Net equity  400,800   302,382 
Note 118 — China Operations

     In December 1996, we acquired Crestone Energy Corporation, subsequently renamed Benton Offshore China Company. Its principal asset is a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under certain circumstances, and lies within an area which is the subject of a territorialborder dispute between the People’s Republic of China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The territorialborder dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area underdue to the dispute. As part of a review of our assets, a third-party conducted

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Due to the border dispute between China and Vietnam, we have been unable to pursue an evaluationexploration program during Phase One of the WAB-21 area. Through that evaluation and our own assessment,contract. As a result, we recorded a $13.4 million impairment chargehave obtained license extensions, with the current extension in effect until May 31, 2009. While no assurance can be given, we believe we will continue to receive contract extensions so long as the second quarter of 2002. No further impairment of the property is currently required.border disputes persist. WAB-21 represents the $2.9 million excluded from the full cost pool as reflectedof oil and gas properties on our December 31, 20042007 balance sheet.

Note 129 — Domestic Operations
     In January 2007, we purchased a 45 percent interest in Fusion for $4.6 million. Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering. The purchase of Fusion extends our technical ability and global reach to support a more organic growth strategy. Our minority equity investment in Fusion is accounted for using the equity method of accounting. Operating revenue and total assets represent 100 percent of Fusion. Fusion acquired Renegade Geophysical L.L.C. on August 30, 2007 for 9.1 percent of one of Fusion’s subsidiaries’ stock plus $0.5 million. No dividends were declared or paid during the period. Summarized financial information for Fusion follows:
     
  Year Ended 
  December 31, 
  2007 
  (in thousands) 
Operating Revenues $7,392 
    
     
Net Income $527 
Equity interest in unconsolidated equity affiliate  45%
    
Net income from unconsolidated equity affiliate  237 
Amortization of fair value of intangibles  (656)
    
Net loss from unconsolidated equity affiliate $(419)
    
December 31,
2007
Current assets$3,995
Total assets14,846
Current liabilities2,100
Total liabilities2,100
Note 10 — Related Party Transactions

     In March 2002, we entered into construction service agreements with Venezolana International, S.A. (“Vinsa”). Vinsa is an affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A., which owns 20 percent of Harvest Vinccler. Vinsa provided $0.3 million, $1.7 million and $0.5 million in construction services for our Venezuelan field operations for the years ended December 31, 2004, 2003 and 2002, respectively. This agreement was terminated on September 19, 2004.

     In August 1997, we entered into a consulting agreement with Oil & Gas Technology Consultants Inc. (“OGTC”) to provide operational and technical assistance in Venezuela. OGTC is an affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A., which indirectly owns 20 percent of Harvest Vinccler. Payment for services is due when earnings are not reinvested in Harvest Vinccler operations.Petrodelta. The consulting agreement was cancelled January 1, 2004. Expenses related to this consulting agreement were $1.5At December 31, 2007 and 2006, we owed $10.1 million and $2.6$9.6 million, at December 31, 2003 and 2002, respectively.

     From 1996 through 1998, we made unsecured loans to our then Chief Executive Officer, A. E. Benton, bearing interest at the rate of 6 percent per annum. As of December 31, 2004, Mr. Benton’s debt balance was $2.8 million. This amount is after the payment to us in 2004 of $0.5 million from the proceeds, net of tax, of the exercise of stock options issued to Mr. Benton, but pledged to us to secure repayment of the debt, and a $0.1 million paymentrespectively, under the excess income provision of an agreement with Mr. Benton. We continue to accrue interest and provide a bad debt allowance on the remaining amount due.

consulting agreement.

Note 1311 — Earnings Per Share

     Basic earnings per common share (“EPS”) are computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. The weighted average number of common shares outstanding for computing basic EPS was 36.136.5 million, 35.337.2 million and 34.636.9 million for the years ended December 31, 2004, 20032007, 2006 and 2002,2005, respectively. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The weighted average number of common shares outstanding for computing diluted EPS, including dilutive stock options, was 38.137.9 million, 36.837.2 million 36.1and 38.4 million for the years ended December 31, 2004, 20032007, 2006 and 2002,2005, respectively.

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     An aggregate of 0.91.1 million options and warrants were excluded from the earnings per share calculations because their exercise price exceeded the average price for the year ended December 31, 2004.2007. For the years ended December 31, 20032006 and 2002, 2.52005, 1.5 million and 3.51.9 million options and warrants, respectively, were excluded from the earnings per share calculations because their exercise price exceeded the average price.

Note 12 — Gain on Financing Transaction
     In 2006, Harvest Vinccler entered into two Bolivar denominated three-year loans and one Bolivar denominated term loan with Venezuelan banks. The interest and debt service obligations for these loans are denominated in Bolivars. The Bolivar debt was collateralized with U.S. Dollar deposits in banks outside of Venezuela. SeeNote 2 — Long-Term Debt and Liquidity. Since Harvest Vinccler has no source for Bolivars due to the situation in Venezuela (seeNote 7— Venezuela Operations-Petrodelta, S.A.), the consolidated Harvest group of companies evaluated its current options to convert U.S. Dollars to Bolivars and entered into a series of security exchange transactions to effectively convert U.S. Dollars to Bolivars. In these exchange transactions, one Harvest affiliate purchased U.S. government securities and exchanged them for U.S. Dollar indexed debt issued by the Venezuelan government. The U.S. Dollar indexed Venezuelan government securities can only be traded in Venezuela for Bolivars (“Southern Bonds” or “TICC’s”). The exchange was transacted through an intermediary at the securities transaction rate of Bolivars to U.S. Dollars. Harvest Vinccler at the same time purchased a like amount of U.S. government securities and exchanged those securities with the intermediary for the TICCs. Harvest Vinccler converted the TICCs to Bolivars at a local bank at the official exchange rate of 2,150 Bolivars to one U.S. Dollar and used the Bolivars to settle 205 billion Bolivars (approximately $95.4 million) of its Bolivar denominated debt. These security exchange transactions resulted in a $49.6 million gain on financing transactions for the year ended December 31, 2007. There were no such financing transactions entered into during the year ended December 31, 2006.
Note 13 — Subsequent Events
     In November 2007, we executed a sale and purchase agreement for the purchase of a 50 percent interest in the Dussafu PSC. All conditions precedent to the sale and purchase agreement are complete except for final government and partner approvals. We anticipate receiving final approvals during the first half of 2008. On receipt of final partner approval, we will become the operator of the Dussafu PSC. The purchase will be recorded in the quarter in which approvals are received. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC contains 680,000 acres with water depths to 1,000 feet. The Dussafu PSC represents $0.1 million of oil and gas properties on our December 31, 2007 balance sheet.
     In February 2008, Indonesia’s oil and gas regulatory authority, BP Migas, approved the assignment to us of a 47 percent interest in the Budong PSC located onshore West Sulawesi, Indonesia. Final government approval from Migas is pending. The Budong PSC includes a ten-year exploration period and a 20-year development phase. In the initial three-year exploration phase, which began January 2007, we expect to acquire, process and interpret approximately 500 kilometers of 2-D seismic and drill two exploration wells. Our partner, Tately Budong-Budong N.V. (“Tately”), will be the operator through the exploration phase as required by the terms of the Budong PSC. We will have control of major decisions and financing for the project with an option to operate in the development and production phase if approved by BP Migas. The Budong PSC represents $0.2 million of oil and gas properties on our December 31, 2007 balance sheet.
     In February 2008, Messrs. R.E. Irelan and Igor Effimoff were elected to our Board of Directors, increasing the number of Board members to eight. Our Board is now composed of seven external and one internal members.

S-20S-24

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

Quarterly Financial Data (unaudited)

     Summarized quarterly financial data is as follows:
                 
  Quarter Ended 
  March 31  June 30  September 30  December 31 
  (amounts in thousands, except per share data) 
Year ended December 31, 2004
                
Revenues $38,797  $41,397  $46,053  $59,819 
Expenses  (20,329)  (20,478)  (24,697)  (30,082)
Non-operating income (expense)  (2,795)  (2,031)  (4,779)  391 
             
Income from consolidated companies before income taxes and minority interests  15,673   18,888   16,577   30,128 
Income tax expense  5,600   9,902   7,617   10,169 
             
Income before minority interests  10,073   8,986   8,960   19,959 
Minority interests  2,566   2,738   3,654   4,660 
             
Net income $7,507  $6,248  $5,306  $15,299 
             
                 
Net income per common share:                
Basic $0.21  $0.17  $0.15  $0.42 
             
Diluted $0.20  $0.16  $0.14  $0.39 
             
                 
Other comprehensive income (loss)  —   —   (2,357)  1,870 
             
Total comprehensive income $7,507  $6,248  $2,949  $17,169 
             
                                
 Quarter Ended  Quarter Ended 
 March 31 June 30 September 30 December 31  March 31 June 30 September 30 December 31 
 (amounts in thousands, except per share data)  (amounts in thousands, except per share data) 
Year ended December 31, 2003
 
Year ended December 31, 2007
 
Revenues $18,825 $28,576 $27,834 $30,860  $— $— $— $11,217 
Expenses  (13,901)  (19,911)  (20,037)  (18,619)  (6,951)  (7,798)  (6,069)  (9,935)
Non-operating income (expense)  (1,864)  (2,288) 44,056  (1,743)  (38) 353 15,076 35,059 
                  
Income from consolidated companies before income taxes and minority interests 3,060 6,377 51,853 10,498 
Income (loss) before income taxes and minority interests  (6,989)  (7,445) 9,007 36,341 
Income tax expense 1,056 3,104 3,603 1,894  114 52 863 5,283 
                  
Income before minority interests 2,004 3,273 48,250 8,604 
Income (loss) before minority interests  (7,103)  (7,497) 8,144 31,058 
Minority interests 887 1,216 1,367 2,498   (637)  (736) 2,524 17,909 
                  
Income from consolidated companies 1,117 2,057 46,883 6,106 
Equity in net income (losses) of affiliated companies  (16,575)  (13,470)  (473) 1,658 
Income (loss) from consolidated companies  (6,466)  (6,761) 5,620 13,149 
Net income (loss) from unconsolidated equity affiliates  (39)  (137)  (235) 52,106 
                  
Net income (loss) $(15,458) $(11,413) $46,410 $7,764  $(6,505) $(6,898) $5,385 $65,255 
                  
  
Net income (loss) per common share:  
Basic $(0.44) $(0.32) $1.31 $0.22  $(0.17) $(0.18) $0.15 $1.87 
                  
Diluted $(0.44) $(0.32) $1.25 $0.21  $(0.17) $(0.18) $0.14 $1.78 
                  
 
Other comprehensive income (loss) 2,614  (3,001) 21 366 
         
Total comprehensive income (loss) $(12,844) $(14,414) $46,431 $8,130 
         

                 
  Quarter Ended 
  March 31  June 30  September 30  December 31 
  (amounts in thousands, except per share data) 
Year ended December 31, 2006*
                
Revenues $59,172  $334  $—  $— 
Expenses  (33,068)  (7,796)  (7,654)  (10,414)
Non-operating income (expense)  1,940   (13,419)  (2,650)  258 
             
Income (loss) before income taxes and minority interests  28,044   (20,881)  (10,304)  (10,156)
Income tax expense  14,762   40,810   5,338   7 
             
Income (loss) before minority interests  13,282   (61,691)  (15,642)  (10,163)
Minority interests  3,354   (11,409)  (2,044)  (1,613)
             
Net income (loss) $9,928  $(50,282) $(13,598) $(8,550)
             
                 
Net income (loss) per common share:                
Basic $0.27  $(1.35) $(0.36) $(0.23)
             
Diluted $0.26  $(1.35) $(0.36) $(0.23)
             
*Financial information for 2006 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 — Organization and Summary of Significant Accounting Policies — Property and Equipment and Change in Accounting Principle. The effect of the accounting change on net income for the three months ended March 31, 2006 was a decrease of $3.9 million, net of income tax, or $0.10 per diluted share.
Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)

     The following tables summarize our proved reserves, drilling and production activity, and financial operating data at the end of each year. The Venezuelan reserves are attributable to our consolidated activities prior to the conversion to an equity investment in Petrodelta. Historical costs in Tables I through III provide information prior to the effective date of the conversion to Petrodelta on April 1, 2006.
     In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS 69”), this section provides supplemental information on our oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs

S-25

incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

S-21

TABLE I —TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):

                                
 United States    United States   
 Venezuela China and Other Total  Venezuela China and Other Total 
Year Ended December 31, 2004
 
Development costs $39,161 $— $— $39,161 
Year Ended December 31, 2007
 
Acquisition costs $— $160 $304 $464 
Exploration costs 10 53 — 63  — 204 — 204 
                  
 $39,171 $53 $— $39,224  $— $364 $304 $668 
                  
  
Year Ended December 31, 2003
 
Year Ended December 31, 2006
 
Acquisition costs $— $35 $— $35 
Development costs $58,079 $— $2 $58,081  501 — — 501 
Exploration costs 11 39 133 183 
                  
 $58,090 $39 $135 $58,264  $501 $35 $— $536 
                  
  
Year Ended December 31, 2002
 
Year Ended December 31, 2005
 
Acquisition costs $— $42 $— $42 
Development costs��$49,163 $120 $577 $49,860  8,912 — — 8,912 
Exploration costs 794  (149) 88 733 
                  
 $49,957 $(29) $665 $50,593  $8,912 $42 $— $8,954 
                  

TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):
                                
 United States    United States   
 Venezuela China and Other Total  Venezuela(a) China(b) and Other Total 
Year Ended December 31, 2004
 
Year Ended December 31, 2007
 
Costs excluded from amortization $— $2,859 $304 $3,163 
         
 
Year Ended December 31, 2006
 
Proved property costs $608,225 $13,454 $— $621,679  $— $13,532 $— $13,532 
Costs excluded from amortization — 2,900 — 2,900  — 2,900 — 2,900 
Oilfield inventories 6,503 — — 6,503  — — — — 
Less accumulated depletion and impairment  (432,302)  (13,454) —  (445,756) —  (13,532) —  (13,532)
                  
 $182,426 $2,900 $— $185,326  $— $2,900 $— $2,900 
                  
  
December 31, 2003
 
Year Ended December 31, 2005
 
Proved property costs $569,055 $13,401 $— $582,456  $617,137 $13,497 $— $630,634 
Costs excluded from amortization — 2,900 — 2,900  — 2,900 — 2,900 
Oilfield inventories 8,266 — — 8,266  8,150 — — 8,150 
Less accumulated depletion and impairment  (398,206)  (13,401) —  (411,607)  (473,496)  (13,497) —  (486,993)
                  
 $179,115 $2,900 $— $182,015  $151,791 $2,900 $— $154,691 
                  
 
December 31, 2002
 
Proved property costs $519,175 $26,210 $21,030 $566,415 
Costs excluded from amortization — 2,900 — 2,900 
Oilfield inventories 7,286 — — 7,286 
Less accumulated depletion and impairment  (386,824)  (26,210)  (20,764)  (433,798)
         
 $139,637 $2,900 $266 $142,803 
         

(a)Reclassified to investment in equity affiliates effective April 1, 2006.
(b)SeeNote 8 — China Operations.

S-22S-26

TABLE III — Results of operations for oil and natural gas producing activities (in thousands):
                    
 United States    Venezuela 
Year ended December 31, 2006(a)
 
Oil and natural gas revenues $59,506 
Expenses: 
Operating, selling and distribution expenses and taxes other than on income 9,451 
Depletion 9,904 
Income tax expense 20,076 
 Venezuela China and Other Total    
Year ended December 31, 2004
 
Total expenses(b)
 39,431 
   
Results of operations from oil and natural gas producing activities $20,075 
   
 
Year ended December 31, 2005
 
Oil and natural gas revenues $186,066 $— $— $186,066  $236,941 
Expenses:  
Operating, selling and distribution expenses and taxes other than on income 33,297 — 214 33,511  39,969 
Depletion 34,108 — — 34,108  41,175 
Income tax expense 38,968 — — 38,968  65,943 
            
Total expenses 106,373 — 214 106,587  147,087 
            
Results of operations from oil and natural gas producing activities $79,693 $— $(214) $79,479  $89,854 
            
 
Year ended December 31, 2003
 
Oil and natural gas revenues $106,095 $— $— $106,095 
Expenses: 
Operating, selling and distribution expenses and taxes other than on income 31,445 — 76 31,521 
Write-down of oil and gas properties and impairments — 23 142 165 
Depletion 19,599 — — 19,599 
Income tax expense 12,158 — 1,187 13,345 
         
Total expenses 63,202 23 1,405 64,630 
         
Results of operations from oil and natural gas producing activities $42,893 $(23) $(1,405) $41,465 
         
 
Year ended December 31, 2002
 
Oil revenue $126,731 $— $— $126,731 
Expenses: 
Operating, selling and distribution expenses and taxes other than on income 31,608 2,493 — 34,101 
Write-down of oil and gas properties and impairments — 13,371 1,166 14,537 
Depletion 24,941 — — 24,941 
Income tax expense 4,715 3 — 4,718 
         
Total expenses 61,264 15,867 1,166 78,297 
         
Results of operations from oil and natural gas producing activities $65,467 $(15,867)  (1,166) 48,434 
         

(a)Reflects oil and natural gas deliveries through March 31, 2006.
(b)Excludes taxes of $50.3 million recorded in 2006 due to the settlement of the SENIAT tax assessments.
TABLE IV — Quantities of Oil and Natural Gas Reserves

     Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. All Venezuelan reserves are attributable to an operating service agreementthe OSA between Harvest Vinccler and PDVSA, under which all mineral rights are owned by the government of Venezuela. The Venezuelan reserves include production projected throughgovernment unilaterally terminated the endOSA in April 2006. SeeNote 1 — Organization and Summary of the operating service agreement in July 2012. We believe the two months representing the delay due to the time sales were halted by the civil work stoppage will be added to the original term of the operating service agreement pursuant to the force majeure provisions of the agreement.

Significant Accounting Policies — Organization.

     The SEC requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data, economic changes and other relevant developments. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.

     Proved Developed Reservesdeveloped reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well.

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     Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reservesproved developed reserves only after

S-27

testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

     Proved Undeveloped Reservesundeveloped reserves are Proved Reservesproved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates.

     Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reservesproved undeveloped reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir.

     Changes in previous estimates of Proved Reservesproved reserves result from new information obtained from production history and changes in economic factors.

     The evaluation of the oil and natural gas reserves were prepared by Ryder Scott Company L.P., independent petroleum engineers.
     The evaluations of the oil and natural gas reserves as of December 31, 2004, 20032006 and 20022005 were prepared by Ryder Scott Company L.P., independent petroleum engineers.

The 2006 reserve information shown below has been reduced to exclude reserves formerly classified as proved undeveloped. Under SEC standards for the reporting of oil and natural gas reserves, proved reserves are estimated quantities of crude oil and natural gas “which geological data and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirsunder existing economic and operating conditions.” (Emphasis added). Our quantities of proved reserves were reduced to remove undeveloped reserves because the actions taken by the Venezuelan government beginning in 2005 under our OSA have created uncertainty as to whether those reserves will be recovered under the economic and operating conditions which currently exist in Venezuela. For ease of reference, the reclassified reserves are hereafter referred to as “Contractually Restricted Reserves”. In April 2006, the OSA was unilaterally terminated by the Venezuelan government. SeeNote 1 — Organization and Summary of Significant Accounting Policies - Organization. Reserves for Petrodelta are reflected in the following sectionAdditional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela Equity Affiliate as of December 31, 2007 and 2006, TABLE IV — Quantities of Oil and Natural Gas Reserves.

     The tables shown below represent our interests in Venezuela and Russia in each of the years.
             
      Minority    
      Interest in    
  Venezuela  Venezuela  Net Total 
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls)
            
Year ended December 31, 2004
            
Proved Reserves at beginning of the year  87,872   (17,574)  70,298 
Revisions of previous estimates  (1,578)  316   (1,262)
Purchases of reserves in place  —   —   — 
Extensions, discoveries and improved recovery  —   —   — 
Production  (8,152)  1,630   (6,522)
Sales of reserves in place  —   —   — 
          
Proved Reserves at end of the year  78,142   (15,628)  62,514 
          
             
Year ended December 31, 2003
            
Proved Reserves beginning of the year  95,168   (19,033)  76,135 
Revisions of previous estimates  (521)  104   (417)
Extensions, discoveries and improved recovery  572   (114)  458 
Production  (7,347)  1,469   (5,878)
Sales of reserves in place  —   —   — 
          
Proved Reserves at end of the year  87,872   (17,574)  70,298 
          
             
Year ended December 31, 2002
            
Proved Reserves beginning of the year  104,514   (20,903)  83,611 
Revisions of previous estimates  362   (72)  290 
Extensions, discoveries and improved recovery  —   —   — 
Production  (9,708)  1,942   (7,766)
Sales of reserves in place  —   —   — 
          
Proved Reserves at end of the year  95,168   (19,033)  76,135 
          
Russia – Geoilbent (34%) Proved Reserves at end of the year          24,781 
            
             
      Minority    
Proved Reserves-Crude oil, condensate,     Interest in    
and natural gas liquids (MBbls) Venezuela  Venezuela  Net Total 
     (in thousands)     
Year ended December 31, 2006
            
Proved Reserves at beginning of the year  35,311   (7,062)  28,249 
Revisions of previous estimates(a)
  (33,417)  6,683   (26,734)
Production  (1,894)  379   (1,515)
          
Proved Reserves at end of the year  —   —   — 
          

(a)All reserves have been removed pending conversion to Petrodelta.

S-24S-28

             
      Minority    
      Interest in    
  Venezuela  Venezuela  Net Total 
Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at:
            
December 31, 2004  45,488   (9,098)  36,390 
December 31, 2003  45,860   (9,172)  36,688 
December 31, 2002  53,833   (10,767)  43,066 
January 1, 2002  51,465   (10,293)  41,172 
             
Russia – Geoilbent (34%) Proved Reserves at end of the year 2002          11,840 
             
Proved Reserves-Natural gas (MMcf)
            
             
Year ended December 31, 2004
            
Proved Reserves beginning of the year  195,500   (39,100)  156,400 
Revisions of previous estimates  (159)  32   (127)
Extensions, discoveries and improved recovery  —   —   — 
Production  (31,059)  6,212   (24,847)
          
Proved Reserves end of the year  164,282   (32,856)  131,426 
          
             
Year ended December 31, 2003
            
Proved Reserves beginning of the year  198,000   (39,600)  158,400 
Revisions of previous estimates  160   (32)  128 
Extensions, discoveries and improved recovery  —   —   — 
Production  (2,660)  532   (2,128)
          
Proved Reserves end of the year  195,500   (39,100)  156,400 
          
             
Year ended December 31, 2002
            
Proved Reserves beginning of the year  —   —   — 
Revisions of previous estimates  —   —   — 
Extensions, discoveries and improved recovery  198,000   (39,600)  158,400 
Sales of reserves in place  —   —   — 
          
Proved Reserves end of the year  198,000   (39,600)  158,400 
          
             
Proved Developed Reserves-Natural gas (MMcf) at:
            
December 31, 2004  80,897   (16,179)  64,718 
December 31, 2003  106,147   (21,229)  84,918 
December 31, 2002  105,000   (21,000)  84,000 
             
      Minority    
Proved Reserves-Crude oil, condensate,     Interest in    
and natural gas liquids (MBbls) Venezuela  Venezuela  Net Total 
     (in thousands)     
Year ended December 31, 2005
            
Proved Reserves at beginning of the year  78,142   (15,628)  62,514 
Revisions of previous estimates(a)
  (34,068)  6,813   (27,255)
Production  (8,763)  1,753   (7,010)
          
Proved Developed Reserves at end of the year  35,311   (7,062)  28,249 
          

TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities

(a)Includes primarily Contractually Restricted Reserves as well as other minor revisions.
             
Proved Developed Reserves-Crude oil, condensate,
and natural gas liquids (MBbls) at:
            
December 31, 2005  35,311   (7,062)  28,249 
January 1, 2005  45,488   (9,098)  36,390 
             
Proved Reserves-Natural gas (MMcf)
            
             
Year ended December 31, 2006
            
Proved Reserves beginning of the year  58,918   (11,784)  47,134 
Revisions of previous estimates(a)
  (54,412)  10,883   (43,529)
Production  (4,506)  901   (3,605)
          
Proved Reserves end of the year  —   —   — 
          
(a)All reserves have been removed pending conversion to Petrodelta.
             
Year ended December 31, 2005
            
Proved Reserves beginning of the year  164,282   (32,856)  131,426 
Revisions of previous estimates(a)
  (79,687)  15,937   (63,750)
Production  (25,677)  5,135   (20,542)
          
Proved Developed Reserves end of the year  58,918   (11,784)  47,134 
          
(a)Includes primarily Contractually Restricted Reserves as well as other minor revisions.
             
Proved Developed Reserves-Natural gas (MMcf) at:
            
December 31, 2005  58,918   (11,784)  47,134 
January 1, 2005  80,897   (16,179)  64,718 
TABLE V —Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities
     The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.

     Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.

     The tables shown below represent our net interest in Venezuela in each of the years. In addition to these reserves is our 34 percent interest in Geoilbent at December 31, 2002.Petrodelta. We report the results of Ryder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan reserves.

S-25S-29

             
      Minority    
      Interest in    
  Venezuela  Venezuela  Net Total 
  (amounts in thousands) 
December 31, 2004
            
Future cash inflow $1,852,045  $(370,409) $1,481,636 
Future production costs  (342,373)  68,475   (273,898)
Future development costs  (141,565)  28,313   (113,252)
          
Future net revenue before income taxes  1,368,107   (273,621)  1,094,486 
10% annual discount for estimated timing of cash flows  (365,580)  73,116   (292,464)
          
Discounted future net cash flows before income taxes  1,002,527   (200,505)  802,022 
Future income taxes, discounted at 10% per annum  (321,302)  64,260   (257,042)
          
Standardized measure of discounted future net cash flows $681,225  $(136,245) $544,980 
          
             
December 31, 2003
            
Future cash inflow $1,513,525  $(302,705) $1,210,820 
Future production costs  (382,577)  76,515   (306,062)
Future development costs  (130,160)  26,032   (104,128)
          
Future net revenue before income taxes  1,000,788   (200,158)  800,630 
10% annual discount for estimated timing of cash flows  (319,152)  63,830   (255,322)
          
Discounted future net cash flows before income taxes  681,636   (136,328)  545,308 
Future income taxes, discounted at 10% per annum  (223,172)  44,634   (178,538)
          
Standardized measure of discounted future net cash flows $458,464  $(91,694) $366,770 
          
             
December 31, 2002
            
Future cash flows $1,510,346  $(302,069) $1,208,277 
Future production costs  (400,694)  80,139   (320,555)
Future development costs  (192,671)  38,534   (154,137)
          
Future net revenue before income taxes  916,981   (183,396)  733,585 
10% annual discount for estimated timing of cash flows  (315,376)  63,075   (252,301)
          
Discounted future net cash flows before income taxes  601,605   (120,321)  481,284 
Future income taxes, discounted at 10% per annum  (204,356)  40,871   (163,485)
          
Standardized measure of discounted future net cash flows $397,249  $(79,450) $317,799 
          
Russia — Geoilbent (34%)         $45,395 
            
             
      Minority    
      Interest in    
  Venezuela  Venezuela  Net Total 
      (in thousands)     
December 31, 2005(a)
            
Future cash inflows from sales of oil and gas $1,029,630  $(205,926) $823,704 
Future production costs  (227,079)  45,416   (181,663)
Future development costs  (27,917)  5,583   (22,334)
Future income tax expenses  (239,386)  47,877   (191,509)
          
Future net cash flows  535,248   (107,050)  428,198 
Effect of discounting net cash flows at 10%  (123,451)  24,691   (98,760)
          
Standardized measure of discounted future net cash flows $411,797  $(82,359) $329,438 
          
(a)Proved reserves do not include Contractually Restricted Reserves.
TABLE VI —Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
         
  Net Venezuela
  2006(a)  2005 
  (in thousands)
Standardized Measure at January 1 $329,438  $544,980 
Sales of oil and natural gas, net of related costs  (40,361)  (124,638)
Revisions to estimates of proved reserves        
Net changes in prices, development and production costs  —   262,852 
Quantities  —   (365,565)
Extensions, discoveries and improved recovery, net of future costs  —   — 
Accretion of discount  —   80,202 
Net change in income taxes  —   109,030 
Development costs incurred  501   7,130 
Changes in timing and other  (289,578)  (184,553)
       
Standardized Measure at December 31 $—  $329,438 
       
(a)All reserves have been removed pending conversion to Petrodelta.

TABLE VI — Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

             
  Net Venezuela 
  2004  2003  2002 
  (amounts in thousands) 
Present Value at January 1 $366,770  $317,799  $163,328 
Sales of oil and natural gas, net of related costs  (122,215)  (59,720)  (76,098)
Revisions to estimates of Proved Reserves            
Net changes in prices, development and production costs  333,237   76,037   310,043 
Quantities  (7,597)  (1,584)  611 
Extensions, discoveries and improved recovery, net of future costs  —   4,971   89,670 
Accretion of discount  54,531   48,128   17,621 
Net change in income taxes  (78,504)  (15,053)  (150,603)
Development costs incurred  31,329   46,463   40,532 
Changes in timing and other  (32,571)  (50,271)  (77,305)
          
Present Value at December 31 $544,980  $366,770  $317,799 
          

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Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)
for RussiaVenezuela Equity AffiliatesAffiliate as of September 30, their fiscal year end.December 31, 2007 and 2006

     In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS 69”), this section provides supplemental information on our oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

     Geoilbent (34

     Petrodelta (32 percent ownership until sold September 25, 2003) and Arctic Gas (39 percent ownership not subject to certain sale and transfer restrictions at December 31, 2001, until Arctic Gas was sold on April 12, 2002, respectively), which areownership) is accounted for under the equity method, haveand has been included at their respectiveits ownership interestsinterest in the consolidated financial statements and the following Tables based on a fiscal periodyear ending September 30December 31 and, accordingly, results of operations for oil and natural gas producing activities in RussiaVenezuela reflect the year ended September 30, 2002.

December 31, 2007 and 2006.

TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
    
 Petrodelta 
Year Ended December 31, 2007
 
Development costs $976 
Exploration costs — 
               
 Total Equity  $976 
 Arctic Gas Geoilbent Affiliates    
Year Ended September 25, 2003
 
  
Year Ended December 31, 2006
 
Development costs $— $3,474 $3,474  $217 
Exploration costs — 1,034 1,034  — 
          
 $— $4,508 $4,508  $217 
          
 
Year Ended September 30, 2002
 
Development costs $— $8,599 $8,599 
Exploration costs 16,156 498 16,654 
       
 $16,156 $9,097 $25,253 
       

TABLE II —Capitalized costs related to oil and natural gas producing activities (in thousands):
                
 Total Equity  Petrodelta 
 Arctic Gas Geoilbent Affiliates 
September 25, 2003
 
December 31, 2007
 
Proved property costs $— $102,753 $102,753  $59,820 
Unproved property costs 7,247 
Costs excluded from amortization  (976)
Oilfield inventories — 2,530 2,530  4,426 
Less accumulated depletion and impairment —  (72,333)  (72,333)  (11,063)
          
 $— $32,950 $32,950  $59,454 
          
  
September 30, 2002
 
December 31, 2006
 
Proved property costs $— $94,404 $94,404  $58,849 
Unproved property costs 7,247 
Costs excluded from amortization — 272 272   (217)
Oilfield inventories — 2,348 2,348  2,650 
Less accumulated depletion and impairment —  (31,440)  (31,440)  (5,317)
          
 $— $65,584 $65,584  $63,212 
          

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TABLE III — Results of operations for oil and natural gas producing activities (in thousands):
    
 Petrodelta 
Year ended December 31, 2007
 
Oil and natural gas revenues $107,429 
Royalty  (36,751)
               
 Total Equity  70,678 
 Arctic Gas Geoilbent Affiliates  
Year ended September 25, 2003
 
Oil sales $— $27,876 $27,876 
Expenses:  
Operating, selling and distribution expenses and taxes other than on income — 16,088 16,088  7,601 
Depletion — 6,215 6,215  5,746 
Write-down of oil and gas properties — 32,300 32,300 
Income tax expense — 2,073 2,073  23,714 
          
Total expenses — 56,676 56,676  37,061 
          
Results of operations from oil and natural gas producing activities $— $(28,800) $(28,800) $33,617 
          
 
Year ended December 31, 2006
 
Oil and natural gas revenues $90,695 
Royalty  (30,973)
   
 59,722 
 
Expenses: 
Operating, selling and distribution expenses and taxes other than on income 7,273 
Depletion 5,317 
Income tax expense 15,430 
   
Total expenses 28,020 
   
Results of operations from oil and natural gas producing activities $31,702 
   

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          Total Equity 
  Arctic Gas  Geoilbent  Affiliates 
Year ended September 30, 2002
            
Oil sales $3,554  $31,039  $34,593 
Expenses:            
Operating, selling and distribution expenses and taxes other than on income  3,102   16,902   20,004 
Depletion  139   9,237   9,376 
Income tax expense  19   1,955   1,974 
          
Total expenses  3,260   28,094   31,354 
          
Results of operations from oil and natural gas producing activities $294  $2,945  $3,239 
          

TABLE IV — Quantities of Oil and Natural Gas Reserves

     Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Geoilbent and Arctic Gas oil and gas fieldsAll Venezuelan reserves are situated on land belongingattributable to the Government of the Russian Federation. Each obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Geoilbent had licenses to develop the North Gubkinskoye and South Tarasovskoye fieldsour net equity interest in western Siberia. Our 34 percent equity investment in Geoilbent was sold September 25, 2003. Arctic Gas had licenses to develop the Samburg and Yevo-Yakhinskiy fields in western Siberia. Arctic Gas was sold on April 12, 2002.

Petrodelta.

     The SEC requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data, economic changes and economic changes.other relevant developments. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.

     Proved Developed Reservesdeveloped reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well.

     Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reservesproved developed reserves only after

S-32

testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

     Proved Undeveloped Reservesundeveloped reserves are Proved Reservesproved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates.

     Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reservesproved undeveloped reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir.

     Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.

     The evaluation of the oil and natural gas reserves as of December 31, 2007 was prepared by Ryder Scott Company L.P., independent petroleum engineers.
     The tables shown below represents HNR Finance’s interest, net of a 33.33 percent royalty, in Venezuela in each of the years.
             
      Minority    
Proved Reserves-Crude oil, condensate,     Interest in  32% 
and natural gas liquids (MBbls) HNR Finance  Venezuela  Net Total 
      (in thousands)     
Year ended December 31, 2007
            
Proved Reserves at January 1, 2007  —   —   — 
Additions(a)
  50,085   (10,017)  40,068 
Production  (2,824)  565   (2,259)
          
Proved Reserves at end of the year  47,261   (9,452)  37,809 
          
(a)Petrodelta was formed in 2007
             
Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at:
            
December 31, 2007  14,779   (2,956)  11,823 
             
Proved Reserves-Natural gas (MMcf)
            
             
Year ended December 31, 2007
            
Year ended December 31, 2007
            
Proved Reserves at January 1, 2007  —   —   — 
Additions(a)
  50,019   (10,004)  40,015 
Production  (6,935)  1,387   (5,548)
          
Proved Reserves at end of the year  43,084   (8,617)  34,467 
          
(a)Petrodelta was formed in 2007
         
Proved Developed Reserves-Natural gas (MMcf) at:
        
December 31, 20077,755  (1,551) 6,204

S-28S-33

             
          Total Equity 
  Arctic Gas  Geoilbent  Affiliates 
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls)
            
             
Year ended September 30, 2003
            
Proved reserves beginning of the year  —   25,356   25,356 
Revisions of previous estimates  —   537   537 
Extensions, discoveries and improved recovery  —   962   962 
Production  —   (1,942)  (1,942)
Sales of reserves in place  —   (24,913)  (24,913)
          
Proved reserves at end of the year  —   —   — 
          
             
Year ended September 30, 2002
            
Proved Reserves beginning of the year  20,965   29,668   50,633 
Revisions of previous estimates  —   (3,455)  (3,455)
Extensions, discoveries and improved recovery  —   1,493   1,493 
Production  (89)  (2,350)  (2,439)
Sales of reserves in place  (20,876)  —   (20,876)
          
Proved Reserves at end of the year  —   25,356   25,356 
          
             
Proved Developed Reserves at:
            
September 30, 2003  —   —   — 
September 30, 2002  —   13,200   13,200 
October 1, 2001  2,483   15,658   18,141 
             
Proved Reserves-natural gas (MMcf)
            
Year ended September 30, 2002
            
Proved Reserves beginning of the year  208,010   —   208,010 
Revisions of previous estimates  —   —   — 
Extensions, discoveries and improved recovery  —   —   — 
Production  —   —   — 
Sales of reserves in place  (208,010)  —   (208,010)
          
Proved Reserves end of the year  —   —   — 
          
             
Proved Developed Reserves at:
            
September 30, 2002  —   —   — 
October 1, 2001  21,292   —   21,292 
TABLE V —Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities

S-29

TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities

     The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.

     Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.
         
      Total Equity 
  Geoilbent  Affiliates 
  (amounts in thousands) 
September 30, 2003
        
Future cash inflow $481,557  $481,557 
Future production costs  (229,982)  (229,982)
Future development costs  (36,666)  (36,666)
       
Future net revenue before income taxes  214,909   214,909 
10% annual discount for estimated timing of cash flows  (99,948)  (99,948)
       
Discounted future net cash flows before income taxes  114,961   114,961 
Future income taxes, discounted at 10% per annum  (23,163)  (23,163)
       
Standardized measure of discounted future net cash flows $91,798  $91,798 
       
         
September 30, 2002
        
Future cash inflow $469,837  $469,837 
Future production costs  (203,754)  (203,754)
Future development costs  (40,707)  (40,707)
       
Future net revenue before income taxes  225,376   225,376 
10% annual discount for estimated timing of cash flows  (108,147)  (108,147)
       
Discounted future net cash flows before income taxes  117,229   117,229 
Future income taxes, discounted at 10% per annum  (24,290)  (24,290)
       
Standardized measure of discounted future net cash flows $92,939  $92,939 
       

TABLE VI — Changes     The table shown below represents HNR Finance’s net interest in Petrodelta. We report the Standardized Measureresults of Discounted Future Net Cash Flows from Proved ReservesRyder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan reserves.

         
  Equity Affiliates 
  2003  2002 
  (amounts in thousands) 
Present Value at October 1 $92,939  $152,853 
Sales of oil and natural gas, net of related costs  (20,410)  (23,644)
Revisions to estimates of Proved Reserves        
Net changes in prices, development and production costs  (5,522)  76,545 
Quantities  3,178   (10,007)
Sales of reserves in place  (91,798)  (82,205)
Extensions, discoveries and improved recovery, net of future costs  1,246   2,031 
Accretion of discount  11,723   7,065 
Net change in income taxes  1,127   1,145 
Development costs incurred  4,507   8,999 
Changes in timing and other  3,010   (39,843)
       
Present Value at September 30 $—  $92,939 
       
             
      Minority  
      Interest in  
  HNR Finance Venezuela Net Total
  (in thousands)
December 31, 2007
            
Future cash inflows from sales of oil and gas $3,650,110  $(730,022) $2,920,088 
Future production costs  (685,368)  137,074   (548,294)
Future development costs  (358,759)  71,752   (287,007)
Future income tax expenses  (1,274,005)  254,801   (1,019,204)
         
Future net cash flows  1,331,978  (266,395)  1,065,583
Effect of discounting net cash flows at 10%  (677,756)  135,551  (542,205)
         
Standardized measure of discounted future net cash flows $654,222  $(130,844) $523,378 
         

TABLE VI — Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
     Not applicable.

S-30S-34

SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
     
 HARVEST NATURAL RESOURCES, INC.
(Registrant)
 		 
Date: February 22, 2005March 17, 2008 By:  /s/ Peter J. HillJames A. Edmiston   
  Peter J. HillJames A. Edmiston  
  Chief Executive Officer  
 

     Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the 22nd17th day of February, 2005,March, 2008, on behalf of the registrant and in the capacities indicated:
   
Signature Title
 
/s/ Peter J. HillJames A. Edmiston
James A. Edmiston
 Director, President and Chief Executive Officer
   
Peter J. Hill
/s/ Steven W. Tholen
Steven W. Tholen
(Principal Financial Officer)
 Senior Vice President - Finance, Chief Financial Officer and Treasurer
   
/s/ Steven W. TholenSenior Vice President — Finance, Chief Financial
Steven W. TholenOfficer and Treasurer
(Principal Financial Officer)
/s/ Kurt A. Nelson
Kurt A. Nelson
(Principal Accounting Officer)
 Vice President-Controller, Chief Accounting Officer
   
Kurt A. Nelson
(Principal Accounting Officer)
/s/ Stephen D. Chesebro’
Stephen D. Chesebro’
 Chairman of the Board and Director
Stephen D. Chesebro’
/s/
  /s/ John U. Clarke
John U. Clarke
 Director
   
John U. Clarke
/s/ Byron A. DunnIgor Effimoff
Igor Effimoff
 Director
   
Byron A. Dunn
/s/ H. H. Hardee
H. H. Hardee
 Director
   
H.H. Hardee
/s/ Patrick M. MurrayR. E. Irelan
R. E. Irelan
 Director
   
/s/ Patrick M. Murray
Patrick M. Murray
Director
  
/s/ J. Michael Stinson
J. Michael Stinson
Director

S-31S-35

SCHEDULE II

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
(in thousands)
                                        
 Additions      Additions    
 Balance at Charged to Deductions Balance at  Balance at Charged to Other Deductions From Balance at End of
 Beginning Charged to Other From End of  Beginning of Year Charged to Income Accounts Reserves Year
 of Year Income Accounts Reserves Year 
At December 31, 2004
 
At December 31, 2007
 
Amounts deducted from applicable assets  
Accounts receivable $3,355 $— $— $598 $2,757  $2,757 $— $— $— $2,757 
Deferred tax valuation allowance 48,365  (3,284) — — 45,081  32,809 32,809 — — 
Investment at cost 1,350 — — — 1,350  1,350 — — — 1,350 
At December 31, 2003
 
At December 31, 2006
 
Amounts deducted from applicable assets  
Accounts receivable $3,525 $205 $— $375 $3,355  $2,757 $— $— $— $2,757 
Deferred tax valuation allowance 39,146 9,219 — — 48,365  27,363 5,446 — — 32,809 
Investment at cost 1,350 — — — 1,350  1,350 — — — 1,350 
At December 31, 2002
 
At December 31, 2005
 
Amounts deducted from applicable assets  
Accounts receivable $6,512 $289 $— $3,276 $3,525  $2,757 $— $— $— $2,757 
Deferred tax valuation allowance 19,700 20,577 — 1,131 39,146  40,492  (13,129) — — 27,363 
Investment at cost 1,350 — — — 1,350  1,350 — — — 1,350 

S-32S-36

Financial Statements and Notes
for LLC GeoilbentExhibit Index

LLC Geoilbent
Financial Statements
30 September 2003

(b) 3. Exhibits:

REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and
Owners of Limited Liability Company Geoilbent

In our opinion, the accompanying balance sheets and the related statements of income, cash flows and changes in stockholders’ equity, present fairly, in all material respects, the financial position of LLC Geoilbent (the “Company”) at 30 September 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended 30 September 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Notes 4 and 10 to the financial statements, the Company has a long-term debt facility for which it is in violation of certain loan covenants and therefore the lender may declare the loan to be in default and can accelerate the maturity. Accordingly, this long-term debt has been classified in the accompanying financial statements as a current liability resulting in a working capital deficit of approximately US$35,772,000 as at 30 September 2003 which raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regards to this matter are also described in Note 4. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

ZAO PricewaterhouseCoopers Audit

Moscow, Russian Federation
2 March 2004

LLC GEOILBENT
BALANCE SHEETS
(expressed in thousand of US Dollars)

             
      As at As at
  Notes
 30 September 2003
 30 September 2002
Assets
            
Cash and cash equivalents      680   2,001 
Restricted cash  10   1,217   1,469 
Accounts receivable and advances to suppliers  7   7,161   6,308 
Inventories  8   8,018   7,201 
Deferred income tax, current  14   966   1,806 
   
 		   
 		   
 		 
Total current assets
      18,042   18,785 
Oil and gas producing properties, full cost method  9   89,469   185,989 
Deferred income tax, non-current  14   —   696 
Other long term assets      —   130 
   
 		   
 		   
 		 
Total assets
      107,511   205,600 
   
 		   
 		   
 		 
Liabilities and Stockholders’ Equity
            
Current portion of long-term debt  10   37,500   22,550 
Accounts payable      6,559   15,244 
Trade advances      993   3,000 
Taxes payable  11   7,858   12,354 
Other payables and accrued liabilities      904   903 
   
 		   
 		   
 		 
Total current liabilities
      53,814   54,051 
   
 		   
 		   
 		 
Long-term debt  10   —   7,500 
Asset retirement obligation  3   734   — 
   
 		   
 		   
 		 
Total liabilities
      54,548   61,551 
   
 		   
 		   
 		 
Commitments and contingent liabilities
  16   —   — 
Contributed capital  12   82,518   82,518 
Retained earnings (accumulated deficit)      (23,353)  61,531 
Accumulated other comprehensive loss      (6,202)  — 
   
 		   
 		   
 		 
Total stockholders’ equity
      52,963   144,049 
   
 		   
 		   
 		 
Total liabilities and stockholders’ equity
      107,511   205,600 
   
 		   
 		   
 		 

The accompanying notes are an integral part of these financial statements.

LLC GEOILBENT
STATEMENTS OF INCOME
(expressed in thousand of US Dollars)

                 
      Year ended Year ended Year ended
  Notes
 30 September 2003
 30 September 2002
 30 September 2001
Total sales and other operating revenues
  13   82,307   91,598   101,159 
   
 		   
 		   
 		   
 		 
Costs and other deductions
                
Operating expenses      15,801   15,360   11,415 
Selling and distribution expenses      5,893   6,696   9,876 
General and administrative expenses      9,456   8,335   5,650 
Depletion and amortization expense      18,278   27,168   14,918 
Impairment of property, plant and equipment  9   95,000   —   — 
Taxes other than income tax  14   25,625   27,657   26,011 
   
 		   
 		   
 		   
 		 
Total costs and other deductions
      170,053   85,216   67,870 
   
 		   
 		   
 		   
 		 
Other income and expense
                
Exchange gain, net      (1,566)  (2,053)  (781)
Interest expense, net      1,992   4,629   7,547 
Other non-operating income, net      (481)  (381)  (648)
   
 		   
 		   
 		   
 		 
Total other expense (income)
      (55)  2,195   6,118 
   
 		   
 		   
 		   
 		 
Income (loss) before income tax
      (87,691)  4,187   27,171 
   
 		   
 		   
 		   
 		 
Income tax expense
  14             
Current income tax expense      3,542   2,804   6,751 
Deferred income tax benefit      (6,659)  (2,502)  — 
   
 		   
 		   
 		   
 		 
Total income tax expense (benefit)
      (3,117)  302   6,751 
   
 		   
 		   
 		   
 		 
Income (loss) before cumulative effect of change in accounting principle, net of tax
      (84,574)  3,885   20,420 
Cumulative effect of change in accounting principle, net of tax  3   (310)  —   — 
   
 		   
 		   
 		   
 		 
Net income (loss)
      (84,884)  3,885   20,420 
   
 		   
 		   
 		   
 		 

The accompanying notes are an integral part of these financial statements.

LLC GEOILBENT
STATEMENTS OF CASHFLOWS
(expressed in thousand of US Dollars)

             
  Year ended Year ended Year ended
  30 September 2003
 30 September 2002
 30 September 2001
Cash flows from operating activities
            
Net income (loss)  (84,884)  3,885   20,420 
Adjustments to reconcile net income to net cash provided by operating activities:            
Depletion and amortization expense  18,278   27,168   14,918 
Impairment of oil and gas properties  95,000   —   — 
Amortization of financing costs  130   520   520 
Exchange gain  (1,566)  (2,053)  (781)
Deferred tax benefit  (6,659)  (2,502)  — 
Decrease/(increase) in accounts receivable and advances to suppliers  (631)  403   85 
Decrease/(increase) in inventories  (544)  6,362   (4,700)
Increase/(decrease) in accounts payable  (9,030)  (3,407)  11,902 
Increase/(decrease) in trade advances  (2,070)  (5,747)  3,785 
Increase/(decrease) in taxes payable  (4,822)  5,436   4,780 
Decrease in other payables and accrued liabilities  (28)  (1,378)  (2,386)
   
 		   
 		   
 		 
Cash provided by operating activities
  3,174   28,687   48,543 
   
 		   
 		   
 		 
Cash flow from investing activities
            
Capital expenditures  (13,257)  (26,755)  (39,874)
Proceeds on disposal of oil and gas producing properties  1,023   286   191 
Disposal/(purchase) of investments  —   367   (129)
   
 		   
 		   
 		 
Net cash used in investing activities
  (12,234)  (26,102)  (39,812)
   
 		   
 		   
 		 
Cash flows from financing activities
            
Payment of short-term borrowings from founders  —   —   (717)
Payment of short-terms borrowings  —   (3,000)  (3,845)
Proceeds from short-term borrowings  —   —   6,446 
Proceeds from long-term borrowings from founders  —   7,500   — 
Payments of long-term borrowings  (550)  (18,200)  (10,455)
Proceeds from long-term borrowings  8,000   —   — 
Decrease in restricted cash  252   8,738   2,153 
   
 		   
 		   
 		 
Net cash provided by (used in) financing activities
  7,702   (4,962)  (6,418)
   
 		   
 		   
 		 
Effect of foreign exchange on cash balances  37   (31)  (37)
   
 		   
 		   
 		 
Net decrease in cash and cash equivalents
  (1,321)  (2,408)  2,276 
Cash and cash equivalents, beginning of year  2,001   4,409   2,133 
   
 		   
 		   
 		 
Cash and cash equivalents, end of year  680   2,001   4,409 
   
 		   
 		   
 		 
Supplemental cash flow information
            
Interest paid  1,977   4,862   7,609 
Income taxes paid  2,388   2,747   6,906 

The accompanying notes are an integral part of these financial statements.

LLC GEOILBENT
STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(expressed in thousands of US Dollars except as indicated)

                 
              Total
  Contributed Retained earnings Accumulated other stockholders'
  Capital
 (accumulated deficit)
 comprehensive loss
 equity
Balance at 30 September 2000
  82,518   37,226   —   119,744 
   
 		   
 		   
 		   
 		 
Net income and total comprehensive income  —   20,420   —   20,420 
   
 		   
 		   
 		   
 		 
Balance at 30 September 2001
  82,518   57,646   —   140,164 
   
 		   
 		   
 		   
 		 
Net income and total comprehensive income  —   3,885   —   3,885 
   
 		   
 		   
 		   
 		 
Balance at 30 September 2002
  82,518   61,531   —   144,049 
   
 		   
 		   
 		   
 		 
Net loss  —   (84,884)  —   (84,884)
Cumulative translation adjustment  —   —   (6,202)  (6,202)
               
 		 
Total comprehensive loss              (91,086)
   
 		   
 		   
 		   
 		 
Balance at 30 September 2003
  82,518   (23,353)  (6,202)  52,963 
   
 		   
 		   
 		   
 		 

The accompanying notes are an integral part of these financial statements.

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 1: Organization

LLC Geoilbent (the “Company”) is engaged in the development and production of oil and gas in the North Gubkinskoye and South Tarasovskoye fields. These fields are located in the West Siberian region of the Russian Federation, approximately 2,000 miles northeast of Moscow. The Company was established in December 1991 by two Russian oil companies, OAO Purneftegas (“PNG”) and OAO Purneftegasgeologia (“PNGG”), and by Harvest Natural Resources, Inc. (“Harvest”, formerly, Benton Oil and Gas Company) of the United States, which contributed 33%, 33% and 34%, respectively, of the Company’s charter capital, in accordance with the Company’s Foundation Document. In January 2002, PNG and PNGG transferred their stakes in the Company to OAO Minley. In September 2003, Harvest sold its interests in the Company to a company affiliated with OAO YUKOS (“YUKOS”).

Note 2: Basis of Presentation

The Company maintains its accounting records and prepares its statutory financial statements in accordance with the Regulations on Accounting and Reporting of the Russian Federation (“RAR”). The accompanying financial statements have been prepared from these accounting records and adjusted as necessary to comply with accounting principles generally accepted in the United States of America (“US GAAP”). The Company has a year ending 30 September for US GAAP reporting purposes.

In preparing the financial statements in conformity with US GAAP, management makes estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from such estimates.

Certain previously presented amounts have been reclassified to conform to the presentation adopted during the current period. These reclassifications had no impact on previously reported net income or stockholders’ equity.

Reporting and functional currency.The Russian Rouble is the functional currency (primary currency in which business is conducted) for the Company’s operations in the Russian Federation. The Company considers the US dollar as its reporting currency.

In November 2002, the International Practices Task Force concluded that Russia ceased being a highly inflationary economy as of 1 January 2003. As a result of the Task Force conclusion, the Company applied the guidance contained in Emerging Issues Task Force (“EITF”) No. 92-4 and EITF No. 92-8 as of 1 January 2003, which address changes in accounting when an economy ceases to be considered highly inflationary. As a result of the application of the guidance in EITF No. 92-4 and No. 92-8, as of 1 January 2003, the Company recognised a deferred tax liability of USD 8.1 million for temporary differences related to its property, plant and equipment and a corresponding amount as a cumulative translation adjustment as a separate component in stockholders’ equity.

Effective 1 January 2003, the measurement currency of the Company is the Russian Rouble. The transactions and balances in the accompanying financial statements have been translated into US dollars in accordance with the relevant provisions of Statement of Financial Accounting Standards (“SFAS”) No. 52,Foreign Currency Translation(“SFAS No. 52”). Consequently, assets and liabilities are translated at closing exchange rates. The statements of income and cash flows have been translated using monthly average exchange rates. Translation differences resulting from the use of these exchange rates have been included as a component of stockholders equity. The amount of such differences for the period beginning 1 January 2003 through 30 September 2003 was approximately USD 1.9 million. The exchange rates at 30 September 2003, and 30 September 2002, were 30.61 and 31.64, respectively, Russian Roubles to the US dollar.

Prior to 1 January 2003, transactions not already measured in US dollars were remeasured into US dollars in accordance with the relevant provisions of SFAS No. 52 as applied to hyperinflationary economies. Consequently, monetary assets and liabilities were translated at closing exchange rates and non-monetary items were translated at historic exchange rates and adjusted for any impairments. The statements of income and cash flows were translated using monthly average exchange rates. Translation differences resulting from the use of these exchange rates were included in the determination of net income and were included in exchange gains/losses in the accompanying statements of income through 31 December 2002.

1

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 2: Basis of Presentation (continued)

Inflation, exchange restriction and controls.Exchange restrictions and controls exist relating to converting Russian Roubles to other currencies. At present, the Russian Rouble is not a convertible currency outside the Russian Federation. Future movements in the exchange rates between the Russian Rouble and the US dollar will affect the carrying value of the Company’s Russian Rouble denominated assets and liabilities. Such movements may also affect the Company’s ability to realise non-monetary assets represented in US dollars in the accompanying financial statements. Accordingly, any translation of Russian Rouble amounts to US dollars should not be construed as a representation that such Russian Rouble amounts have been, could be, or will in the future be converted into US dollars at the exchange rate shown or at any other exchange rate. At 30 September 2003, the Company was required to sell 25% of its foreign currency receipts within the Russian Federation to the Central Bank for Russian Roubles. Such amounts are subject to certain deductions depending on debt payments on certain hard currency denominated borrowing agreements.

Note 3: Summary of Significant Accounting Policies

Cash and cash equivalents.Cash and cash equivalents include all highly liquid securities with original maturities of three months or less when acquired.

Accounts receivable.Accounts receivable are presented at net realisable value and include value-added and excise taxes which are payable to tax authorities upon collection of such receivables.

Inventories.Crude oil and petroleum products inventories are valued at the lower of cost, using the first-in-first out method, or net realisable value. Materials and supplies inventories are recorded at the lower of average cost or net realisable value.

Property, plant and equipment.The Company follows the full cost method of accounting for oil and gas properties. Under this method, all oil and gas property acquisition, exploration, and development costs including internal costs directly attributable to such activities are capitalized as incurred in the Company’s cost center (full cost pool), which is the Russian Federation. Payroll and other internal costs capitalized include salaries and related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties as well as all other directly identifiable internal costs associated with these activities. Payroll and other internal costs associated with production operations and general corporate activities are expensed in the period incurred.

The full cost pool, including future development costs, estimated asset retirement obligations, net of prior accumulated depletion, is depleted using the unit-of-production method based upon actual production and estimates of proved reserve quantities. Proceeds from sales of oil and gas properties are credited to the full cost pool with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.

Pursuant to full cost accounting rules, capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves discounted at 10 percent; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. During 2003, the Company’s capitalized costs exceeded the ceiling limit resulting in an impairment of oil and gas properties. See Note 9 for additional information.

Pension and post-employment benefits.The Company’s mandatory contributions to the governmental pension scheme are expensed when incurred.

Revenue recognition.Revenue from the sale of crude oil and gas condensate are recognized when dispatched to customers and title has transferred.

2

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 3: Summary of Significant Accounting Policies (continued)

Income taxes.Deferred income tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, in accordance with SFAS No. 109,Accounting for Income Taxes. Deferred income tax assets and liabilities are measured using enacted tax rates in the years in which these temporary differences are expected to reverse. Valuation allowances are provided for deferred income tax assets when management believes it is more likely than not that the assets will not be realized.

Change in accounting principle. Effective 1 October 2002, the Company adopted Statement of Financial Accounting Standards No. 143,Accounting for Assets Retirement Obligations(“SFAS No. 143”). SFAS No. 143 requires entities to record the fair value of its asset retirement obligation as a liability in the period in which they are incurred and a corresponding increase in the carrying amount of the related long-lived asset.

SFAS No. 143 differs in several respects from the previous accounting method employed by the Company. Prior to the adoption of SFAS No. 143, the Company included estimated undiscounted asset retirement costs in its calculation for determining depletion expense. Under SFAS 143, the Company recognizes a liability for the fair value of an asset retirement obligation (“ARO”) in the period in which it is incurred, and capitalizes the associated asset retirement cost. In periods subsequent to initial measurement, the Company recognizes period-to-period changes in the liability for an ARO resulting from a) the passage of time and b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows. The Company’s asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities.

The cumulative effect of this change in accounting principle was a reduction in net income of USD 310 thousand, net of tax, which was recorded in the statement of income for the year ended 30 September 2003. The effect of adoption resulted in increases in property, plant and equipment and long-term liabilities of USD 303 thousand and USD 613 thousand as of 1 October 2002, respectively.

The following table provides pro forma information as if SFAS No. 143 has been applied in previous periods:

             
  Year ended Year ended Year ended
Thousands of US dollars
 30 September 2003
 30 September 2002
 30 September 2001
Asset retirement obligations as of the beginning of the period  613   483   358 
Liabilities incurred for the period  25   56   79 
Accretion expense  96   75   45 
Asset retirement obligations as of the end of the period  734   613   483 
Net income for the period as reported      3,885   20,420 
Pro-forma net income      3,777   20,358 
   
 		   
 		   
 		 

Recent accounting standards.FASB Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities(“FIN 46R”), identifies certain off-balance sheet arrangements that meet the definition of a variable interest entity (“VIE”). FIN 46R requires consolidation of VIEs by primary beneficiaries and requires more extensive disclosures. FIN 46R is applicable to any VIE created after 1 February 2003. The Company does not expect the adoption of this interpretation will have any material effect on its financial position or results of operations.

3

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 4: Going Concern

During the years ended 30 September 2003 and 2002 the Company took steps to reduce its working capital deficit. These included the repayment of debt, the receipt of subordinated long-term loans from the Company’s stockholders and the repayment of accounts payable, primarily from additional borrowings from the European Bank for Reconstruction and Development (“EBRD”). However, as at 30 September 2003, and 30 September 2002, the current liabilities of the Company exceeded its current assets by USD 35,772 thousand and USD 35,266 thousand, respectively. Included in current liabilities, as at 30 September 2003 and 30 September 2002, are loans repayable to the EBRD of USD 30,000 thousand and USD 22,000 thousand, respectively. This debt has been reclassified as current because the Company is not in compliance with a loan facility covenant related to the required implementation of a new management information system, required by 1 May 2003. The loan facility also requires the Company to maintain a minimum working capital ratio. The Company was not in compliance with the required working capital ratio as of the interim reporting dates during the year ended 30 September 2003, however, it met the minimum required working capital ratio as of 30 September 2003 (see also Note 10). Under the terms of the loan facility the EBRD may declare the loan to be in default and can accelerate the maturity. There can be no assurance that the EBRD will not demand repayment of the loan.

During the year ended 30 September 2003, a substantial portion of the Company’s cash flow was utilised to pay accounts and taxes payable resulting in a reduction in capital expenditures for the year. In order to maintain or increase proved oil and gas reserves, the Company must make substantial capital expenditures in 2004 and subsequently. The Company’s cash flow from operations is dependent on the level of oil prices, which are historically volatile and are significantly impacted by the proportion of production that the Company can sell on the export market. Historically, the Company has supplemented its cash flow from operations with additional borrowings or equity capital and may continue to do so. Should oil prices decline for a prolonged period and should the Company not have access to additional capital, the Company would need to reduce its capital expenditures, which could limit its ability to maintain or increase production and, in turn, meet its debt service requirements. Asset sales and financing are restricted under the terms of debt agreements.

Management plans to further address the Company’s working capital deficit by resolving issues with the EBRD relating to its non compliance with the loan covenants and by reducing certain capital expenditures and funding its 2004 cash requirements with cash flows from existing producing properties and its development drilling program. Management is in the process of implementing the required management information system and expects to have implemented this system during the 2004 reporting year. The accompanying financial statements do not include any adjustments that might result if the Company were unable to continue as a going concern.

Note 5: Cash and Cash Equivalents

Included in cash and cash equivalents as at 30 September 2003, and 2002, respectively, are Russian Rouble denominated amounts totaling RR 19.7 million (USD 643 thousand) and RR 18.3 million (USD 578 thousand).

Restricted cash consists of deposits with lending institutions to pay interest and principal as discussed in Note 10. As at 30 September 2003, the amount of restricted cash was USD 1,217 thousand (2002: USD 1,469 thousand). These accounts are maintained in US Dollar denominated accounts located outside Russia.

Note 6: Financial Instruments

Fair values.The estimated fair values of financial instruments are determined with reference to various market information and other valuation methodologies as considered appropriate, however considerable judgment is required in interpreting market data to develop these estimates. Accordingly, the estimates are not necessarily indicative of the amounts that the Company could realize in a current market transaction. The methods and assumptions used to estimate fair value of each class of financial instrument are presented below.

Cash and cash equivalents, accounts receivable and accounts payable.The carrying amount of these items are a reasonable approximation of their fair value.

Short-term and long-term debt. Loan arrangements have both fixed and variable interest rates that reflect the currently available terms and conditions for similar debt. The carrying value of this debt is a reasonable approximation of its fair value.

4

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 6: Financial Instruments (continued)

Credit risk. A significant portion of the Company’s accounts receivable are from domestic and foreign customers, and advances are made to domestic suppliers. Although collection of these amounts could be influenced by economic factors affecting these entities, management believes there is no significant risk of loss to the Company beyond the provisions already recorded, provided that the economic situation in the Russian Federation does not deteriorate (Note 16).

Note 7: Accounts Receivable and Advances to Suppliers

         
Thousands of US dollars
 30 September 2003
 30 September 2002
Trade accounts receivable  1,531   1,387 
Recoverable value-added tax  4,227   3,515 
Advances to suppliers  1,286   1,193 
Advances to customs  117   137 
Other receivables  —   76 
   
 		   
 		 
Total accounts receivable and advances to suppliers
  7,161   6,308 
   
 		   
 		 

Accounts receivables are presented net of an allowance for doubtful accounts of USD 147 thousand and USD 70 thousand at 30 September 2003 and 2002, respectively.

Note 8: Inventories

         
Thousands of US Dollars
 30 September 2003
 30 September 2002
Materials and supplies  7,442   6,905 
Crude oil  576   296 
   
 		   
 		 
Total inventories
  8,018   7,201 
   
 		   
 		 

Note 9: Oil and Gas Producing Properties

         
Thousands of US dollars
 30 September 2003
 30 September 2002
Oil and gas producing properties, cost  302,214   278,459 
Accumulated depletion and impairment  (212,745)  (92,470)
   
 		   
 		 
Oil and gas producing properties, net book value
  89,469   185,989 
   
 		   
 		 

The Company’s oil and gas fields are situated on land belonging to the Government of the Russian Federation. The Company obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Licenses will expire in September 2018 for the North Gubkinskoye field, and in March 2023 for the South Tarasovskoye field. However, under Paragraph 4 of the Russian Federal Law 20-FZ, dated 2 January 2000, the licenses may be extended over the economic life of the lease at the Company’s option. Management intends to extend such licenses for properties that are expected to produce subsequent to their expiry dates. Estimates of proved reserves extending past 2018 represent approximately 9 percent of total proved reserves.

At 31 December 2002 and at 31 March 2003, the Company’s capitalized costs for oil and gas producing properties exceeded its full cost accounting ceiling limitation. The Company’s ceiling limitation decreased primarily because of a decline in the Company’s average realized price it received for its oil at those dates. As a result the Company recorded impairments of its oil and gas producing properties in the aggregate amount of USD 95 million (excluding a deferred income tax benefit of USD 7.6 million); this impairment was recorded as an impairment expense in the statement of income for the year ended 30 September 2003.

5

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 10: Long-term Debt

         
Thousands of US dollars
 30 September 2003
 30 September 2002
EBRD  30,000   22,000 
IMB  —   550 
OAO Minley  5,000   5,000 
YUKOS  2,500   — 
Harvest Natural Resources  —   2,500 
Less: current portion  (37,500)  (22,550)
   
 		   
 		 
Total long-term debt
  —   7,500 
   
 		   
 		 

EBRD loan.At 30 September 2003, the outstanding balance of loans with the EBRD totaled USD 30 million. On 23 September 2002, the Company signed an amended loan agreement with the EBRD that increased the maximum amount that could be drawn down under the facility with the EBRD to USD 50 million. Under the loan agreement, the use of loan proceeds is restricted to the repayment of accounts payable and development of oil and gas reserves. This loan facility is to be repaid such that the loan balance may not exceed set amounts at certain dates in the future. The interest rate under the loan agreement is linked to the London interbank offer rate (“LIBOR”) and an agreed upon margin. The Company must hold as restricted cash a) principal and interest to be paid at the next repayment date and b) 30 percent of the total of principal and interest to be paid at the following repayment date.

LIBOR interest rates ranged from 1.12 percent to 1.84 percent in 2003 (2002: 1.84 percent to 3.5 percent, 2001: 3.5 percent to 6.94 percent). The annual weighted average interest rates on these loans varied between 5.09 percent and 5.43 percent for the year ended 30 September 2003 (2002: 8.59 percent and 11.71 percent, 2001: 14.93 percent to 15.17 percent). The loan is collaterized by the Company’s immovable assets and crude oil export contracts.

The EBRD loan agreement includes certain covenants which include, among other things, the maintenance of financial ratios. If the Company fails to meet these requirements for two consecutive quarters it will result in an event of default whereby the EBRD may, at its option, demand payment of the outstanding principal and interest. As discussed in Note 4, as of 31 December 2002, 31 March 2003 and 30 June 2003 the Company was in violation of the minimum working capital ratio covenant. As of 30 September 2003, the minimum working capital ratio as defined in the loan facility exceeds the covenant requirements. Additionally, the Company has not completed its implementation of a management information system as required under the terms of the loan. Due to these loan convenant violations, the Company has classified the EBRD debt as a current liability.

In addition, while in default of EBRD covenants, the Company may not declare or pay any dividend, make any distribution on its charter capital, purchase, or redeem any shares of the charter capital of the Company, nor make any payment of principal or interest on subordinated shareholder loans or make any other payment or distribution to any stockholder or any affiliate of any stockholder.

As part of the sale of Harvest’s interest in the Company to YUKOS, as described in Note 1, YUKOS assumed Harvest’s stockholder loan.

Loans from OAO Minley and YUKOS are subordinated, unsecured and repayable commencing from January 2004. Interest rates are 2 percent for the Minley loan, and LIBOR for the YUKOS loan, to January 2004. Repayment of the subordinated loans are subject to approval from the EBRD. If approval is not received, the terms of the loan agreements are not considered to be violated. After January 2004, the interest rates on the YUKOS loan increases to 8 percent for the remainder of 2004, and 12 percent from 2005 onwards.

6

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 10: Long-term Debt (continued)

While the Company remains in violation of its EBRD loan convenants, further borrowings under the facility are at the sole discretion of the EBRD. The maximum loan facility available under the terms of the EBRD loan and the related aggregate maturities are as follows:

     
 Maximum loan facility
Thousands of US dollars
3.1		 outstanding
30 September 2003 to 27 January 200450,000
27 January 2004 to 27 July 200441,667
27 July 2004 to 27 January 200533,333
27 January 2005 to 27 July 200525,000
27 July 2005 to 27 January 200616,667
27 January 2006 to 27 January 20078,333
Thereafter—

The aggregate maturities of long-term debt outstanding at 30 September 2003 are as follows:

Thousands of US dollars
Year ended 30 September 20047,500
Year ended 30 September 20055,000
Year ended 30 September 20068,333
Year ended 30 September 20078,333
Year ended 30 September 20088,333

Note 11: Taxes Payable

         
Thousands of US dollars
 30 September 2003
 30 September 2002
Value added tax  —   1,445 
Income tax  3,777   1,176 
Royalty  —   896 
Mineral restoration tax  —   152 
Road users tax  —   642 
Unified production tax  1,552   6,703 
Property taxes  586   1,121 
Penalties and interest  1,784   219 
Other taxes  159   — 
   
 		   
 		 
Total taxes payable
  7,858   12,354 
   
 		   
 		 

7

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 12: Contributed Capital

Capital contributions are as follows:

         
Thousands of US dollars
 30 September 2003
 30 September 2002
OAO Minley  54,733   54,733 
YUKOS  27,785   — 
Harvest Natural Resources  —   27,785 
   
 		   
 		 
Total contributed capital
  82,518   82,518 
   
 		   
 		 

All capital contributions have been made since inception in accordance with the Company’s Foundation Document.

Reserves available for distribution to shareholders are based on the statutory accounting reports of the Company, which are prepared in accordance with Regulations on Accounting and Reporting of the Russian Federation and differ from US GAAP. Russian legislation identifies the basis of distribution as net income. For 2002, the current year statutory net income for the Company as reported in the annual statutory accounting reports was RR 772 million (2001: RR 551 million). However, current legislation and other statutory laws and regulations dealing with distribution rights are open to legal interpretation and, consequently, actual distributable reserves may differ from the amount disclosed. The Company cannot distribute capital while in default of its EBRD loan facility obligations (Note 10).

Note 13: Revenues

Revenues for the years ended 30 September 2003, 2002 and 2001, consisted of the following:

             
Thousand of US dollars
 30 September 2003
 30 September 2002
 30 September 2001
Crude oil — export (Europe and CIS)  51,949   47,751   83,889 
Crude oil — domestic  28,599   40,778   10,900 
Gas condensate — domestic  1,176   —   — 
Refined products — domestic  —   2,764   6,231 
Other operating revenues  583   305   139 
   
 		   
 		   
 		 
Total sales and other operating revenues
  82,307   91,598   101,159 
   
 		   
 		   
 		 

Note 14: Taxes

Presented below is a reconciliation between the provision for income taxes and taxes determined by applying the statutory tax rate as applied in the Russian Federation to income before income taxes.

             
Thousand of US dollars
 30 September 2003
 30 September 2002
 30 September 2001
Income (loss) before income taxes  (87,691)  4,187   27,171 
   
 		   
 		   
 		 
Theoretical income tax expense (benefit) at statutory rate (24% in 2002 and 2003; 35% in 2001)  (21,046)  1,005   9,509 
Increase (reduction) due to:            
Change in valuation allowance  17,192   80   1,810 
Non-deductible expenses  1,860   2,894   2,693 
Investment tax credits  (593)  (5,348)  (6,821)
Change in statutory tax rate  —   595   (750)
Tax penalties and interest  442   1,135   517 
Other  (972)  (59)  (207)
   
 		   
 		   
 		 
Total income tax expense (benefit)
  (3,117)  302   6,751 
   
 		   
 		   
 		 

8

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 14: Taxes (continued)

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for statutory tax purposes. Net deferred tax assets are comprised of the following, at 30 September 2003 and 2002:

         
Thousand of US dollars
 30 September 2003
 30 September 2002
Inventories  (313)  93 
Accounts receivable  121   258 
Accounts payable and accrued liabilities  1,205   430 
Losses carried forward  966   2,502 
Property, plant and equipment  4,989   4,810 
   
 		   
 		 
Total deferred tax assets  6,968   8,093 
Less: Valuation allowance  (6,002)  (5,591)
   
 		   
 		 
Net deferred tax asset
  966   2,502 
   
 		   
 		 

Losses carried forward represent those losses for tax purposes which, according to legislation, the Company is permitted to offset against future taxable earnings in the periods up to 2008, and is subject to limitations of no more than 30% of the Company’s tax liabilities for the tax reporting period.

As at 30 September 2003, management of the Company have assessed the recoverability of the Company’s deferred tax assets and believe that it will be able to realise the tax losses carried forward. Accordingly, the Company has provided a valuation allowance as at 30 September 2003 and 2002, of USD 6,002 thousand and USD 5,591 thousand, respectively, against the remaining deferred tax assets.

Principal movements in the valuation allowance for deferred income tax assets (“DTA”) during the year ended 30 September 2003 are as follows:

Millions of US dollars
Valuation allowance, beginning of period5.6
Increase related to DTA resulting from the December ceiling test writedown12.0
Net other increase in DTA movements during the December quarter1.0
Decrease due to application of EITF No. 92-4 and No. 92-8 effective 1 January 2003(16.8)
Increase relating to DTA resulting from the March ceiling test writedown3.2
Net other increase in DTA movements1.0
Valuation allowance, end of period
6.0

As a result of the application of EITF No. 92-4 and No. 92-8, the valuation allowance related to property, plant and equipment was reduced to zero and a deferred tax liability of USD 8.1 million recorded on 1 January 2003 (Note 2), with no effect on income as the adjustment was recorded as part of the currency translation adjustment as of 1 January 2003. A subsequent ceiling test writedown in March resulted in the recognition of an additional deferred tax asset of USD 10.8 million of which USD 7.6 million and USD 3.2 million were credited as a deferred tax benefit and an increase to the DTA valuation allowance, respectively.

Deferred income tax assets are classified as follows:

         
Thousands of US dollars
 30 September 2003
 30 September 2002
Deferred income tax, current  966   1,806 
Deferred income tax, non-current  —   696 
   
 		   
 		 
Total net deferred tax asset
  966   2,502 
   
 		   
 		 

9

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 14: Taxes (continued)

Taxes other than income tax.The Company is subject to a number of taxes other than on income which are detailed below.

             
Thousands of US dollars
 30 September 2003
 30 September 2002
 30 September 2001
Export duties  8,464   5,376   10,922 
Excise tax  —   535   1,548 
Royalty  —   2,254   4,867 
Mineral restoration tax  377   885   4,596 
Road users tax  203   860   1,427 
Unified production tax  19,056   14,221   — 
Property taxes  2,263   1,994   1,424 
Taxes recovery  (7,017)  —   — 
Other taxes  2,279   1,532   1,227 
   
 		   
 		   
 		 
Total taxes other than income tax
  25,625   27,657   26,011 
   
 		   
 		   
 		 

Beginning 1 January 2002, mineral restoration tax, royalty tax and excise tax on crude oil production were abolished and replaced by the unified natural resources production tax. From 1 January 2004 through 31 December 2006, the base rate for the unified natural resources production tax is set at RR 347 per metric ton of crude oil produced, and is to be adjusted depending on the market price of Urals blend and the RR/USD exchange rate. The tax becomes nil if the Urals blend price falls to or below USD 8.00 per barrel. From 1 January 2007, the unified natural resources production tax rate is set by law at 16.5 percent of crude oil revenues recognized by the Company based on Tax Regulations of the Russian Federation.

During the year ended 30 September 2003, the Company pursued its claim of overpayment of mineral restoration taxes (MRT) paid during the period from 1999 to 2001 of approximately RR 211 million (USD 7.0 million), plus approximately RR 4 million (USD 0.1 million) in related penalties paid. During the year, the regional courts ruled in favour of the Company and, accordingly, the Company and the tax authorities agreed to offset the amounts awarded against the Company’s unified production taxes payable.

Note 15: Related Party Transactions

As of 30 September 2003 and 2002, the Company had the following balances with its stockholders. These balances are included in the balance sheet within accounts receivable, accounts payable and long-term debt as appropriate.

         
Thousand of US Dollars
 30 September 2003
 30 September 2002
Accounts receivable
        
Purneftegasgeologia and affiliated entities  19   63 
Accounts payable
        
Purneftegasgeologia and affiliated entities  183   574 
YUKOS  2,111   — 
Harvest Natural Resources  —   3,354 
Purneftegas and affiliated entities  —   22 
Long-term debt
        
Harvest Natural Resources  —   2,500 
YUKOS  2,500   — 
Minley  5,000   5,000 

10

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 15: Related Party Transactions (continued)

Harvest Natural Resources/YUKOS.During 2003 and 2002, Harvest provided insurance on behalf of the Company and personnel services to the Company for a total value of approximately USD 1,087 thousand (2002: USD 1,752 thousand). The remaining portion of the accounts payable balance outstanding relates to services provided in prior reporting periods. As part of the sale of Harvest’s interest in the Company to YUKOS, all balances owing by the Company to Harvest were transferred to YUKOS.

Purneftegasgeologia.During 2003, 2002 and 2001, Purneftegasgeologia and affiliated entities provided services to the Company for a total value of approximately nil, USD 2,414 thousand and USD 4,193 thousand, respectively. Services consisted of drilling, well maintenance and other related work. The Company sold crude oil for a total value of USD 19 thousand and USD 24 thousand during 2003 and 2002, respectively, and materials during 2003 and 2002 for a total value of approximately USD 726 thousand and USD 613 thousand, respectively.

Purneftegas.During 2002 and 2001, Purneftegas and affiliated companies provided well maintenance services and supplies to the Company for a total of approximately USD 312 thousand and USD 248 thousand, respectively. The Company sold materials to Purneftegas and affiliated entities during 2002 for a total value of approximately USD 260 thousand.

Minley.During 2002, the Company paid USD 4.9 million to Minley in settlement at face value of promissory notes originally issued to the Company’s suppliers and contractors.

During 2003, interest expense on shareholder loans of USD 99 thousand was incurred with respect to Minley and USD 49 thousand was incurred with respect to Harvest. At 30 September 2003 interest payable to Minley totalled USD 21 thousand (2002: USD 21 thousand) and interest payable to Harvest was USD 65 thousand (2002: USD 14 thousand).

Note 16: Commitments and Contingent Liabilities

Economic and operating environment in the Russian Federation.Whilst there have been improvements in the economic situation in the Russian Federation in recent years, the country continues to display some characteristics of an emerging market. These characteristics include, but are not limited to, the existence of a currency that is not freely convertible in most countries outside of the Russian Federation, restrictive currency controls, and relatively high inflation.

The prospects for future economic stability in the Russian Federation are largely dependent upon the effectiveness of economic measures undertaken by the government, together with legal, regulatory, and political developments.

Taxation.Russian tax legislation is subject to varying interpretations and changes occurring frequently, which may be retroactive. Further, the interpretation of tax legislation by tax authorities as applied to the transactions and activity of the Company may not coincide with that of management. As a result, the tax authorities may challenge transactions and the Company may be assessed additional taxes, penalties and interest, which may be significant. The tax periods remain open to review by the tax and customs authorities for three years. The Company cannot predict the ultimate amount of additional assessments, if any, and the timing of their related settlements with certainty, but expects that additional liabilities, if any, arising will not have a significant effect on the accompanying financial statements.

Environmental matters.Environmental regulations and their enforcement are continually being considered by government authorities and the Company periodically evaluates its obligations related thereto. As obligations are determined, they are provided for over the estimated remaining lives of the related oil and gas reserves, or recognized immediately, depending on their nature. The existence of environmental liabilities under proposed or any future legislation, or as a result of stricter enforcement of existing legislation, cannot reasonably be estimated. Under existing legislation, management believes, there are no liabilities that would have a material adverse effect on the financial position, operating results or liquidity of the Company, and that have not been accrued in the financial statements.

11

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)

Note 16: Commitments and Contingent Liabilities (continued)

Oilfield licenses.The Company is subject to periodic reviews of its activities by governmental authorities with respect to the requirements of its oilfield licenses. Management of the Company correspond with governmental authorities to agree on remedial actions necessary to resolve any findings resulting from these reviews. Failure to comply with the terms of a license could result in fines, penalties or license limitation, suspension or revocation. The Company’s management believes any issues of non-compliance will be resolved through negotiations or corrective actions without any materially adverse effect on the Company’s financial position or results of operations.

Legal contingencies.The Company is claiming additional deductions relating to the fiscal periods from 1999 to 2001 amounting to approximately RR 330 million (USD 10.8 million). Management believe these deductions are permitted for companies operating in the northern regions of the Russian Federation and also deductions for certain interest paid during that period. Although the Company was successful in the initial hearing before the courts, the tax authorities have continued to challenge the Company’s position. As at 30 September 2003, the Company has not recorded any benefit relating to the above claims.

The Company is the named defendant in a number of lawsuits as well as the named party in numerous other proceedings arising in the ordinary course of business. While the outcomes of such contingencies, lawsuits or other proceedings cannot be determined at present, management believes that any resulting liabilities will not have a materially adverse effect on the operating results or the financial position of the Company.

Insurance.At 30 September 2003 and 2002, the Company held limited insurance policies in relation to its assets and operations, or in respect of public liability or other insurable risks. Since the absence of insurance alone does not indicate that an asset has been impaired or a liability incurred, no provision has been made in the financial statements for unspecified losses.

12

LLC GEOILBENT
Supplemental Information on Oil and Natural Gas Producing Activities(unaudited)
(expressed in thousands US Dollars except as indicated)

Supplemental Information on Oil and Natural Gas Producing Activities(unaudited)

In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS No. 69”), this section provides supplemental information on the Company’s oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities:

             
  Year ended Year ended Year ended
Thousand of US Dollars
 30 September 2003
 30 September 2002
 30 September 2001
Development costs  10,217   25,290   33,774 
Exploration costs  3,040   1,465   6,100 
   
 		   
 		   
 		 
Total costs incurred in oil and natural gas acquisition, exploration, and development activities
  13,257   26,755   39,874 
   
 		   
 		   
 		 

TABLE II — Capitalized costs related to oil and natural gas producing activities:

         
  As at As at
Thousand of US Dollars
 30 September 2003
 30 September 2002
Proved property costs  302,214   277,659 
Costs excluded from amortisation  —   800 
Oilfield inventories  7,442   6,905 
Less accumulated depletion and impairment  (212,745)  (92,470)
   
 		   
 		 
Total capitalised costs related to oil and natural gas producing activities
  96,911   192,894 
   
 		   
 		 

TABLE III — Results of operations for oil and natural gas producing activities:

In accordance with SFAS 69, results of operations for oil and natural gas producing activities do not include general corporate overhead and monetary effects, nor their associated tax effects. Income tax is based on statutory rates for the year, adjusted for tax deductions, tax credits and allowances.

             
  Year ended Year ended Year ended
Thousand of US Dollars
 30 September 2003
 30 September 2002
 30 September 2001
Oil and natural gas sales  81,987   91,291   100,768 
Expenses:            
Operating, selling and distribution expenses and taxes other than on income  47,319   49,713   47,302 
Depletion and amortization  18,278   27,168   14,918 
Impairment of oil and gas properties  95,000   —   — 
Income tax expense  6,098   5,750   11,006 
Total expenses  166,695   82,631   73,226 
   
 		   
 		   
 		 
Results of operations from oil and natural gas producing activities
  (84,708)  8,660   27,542 
   
 		   
 		   
 		 

13

LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in thousands US Dollars except as indicated)

TABLE IV — Quantities of oil and natural gas reserves

Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions.

The Company’s oil and gas fields are situated on land belonging to the Government of the Russian Federation. The Company obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Licenses will expire in September 2018 for the North Gubkinskoye field, and in March 2023 for the South Tarasovskoye field. However, under Paragraph 4 of the Russian Federal Law 20-FZ, dated 2 January 2000, the licenses may be extended over the economic life of the lease at the Company’s option. Management intends to extend such licenses for properties that are expected to produce subsequent to their expiry dates. Estimates of proved reserves extending past 2018 represent approximately 9 percent of total proved reserves.

The Securities and Exchange Commission requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and the Company considers such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.

Proved developed reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed non producing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well.

Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves are proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates.

Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for proved undeveloped reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir.

Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.

The evaluations of the oil and natural gas reserves were prepared by Ryder-Scott Company, independent petroleum engineers.

14

LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in thousands US Dollars except as indicated)

             
Proved reserves-crude oil,      
condensate and natural gas Year ended Year ended Year ended
liquids (MBbls)
 30 September 2003
 30 September 2002
 30 September 2001
Proved reserves beginning of year
  74,575   87,259   95,924 
Revisions of previous estimates  1,580   (10,163)  (16,454)
Extensions, discoveries and improved recovery  2,829   4,391   12,974 
Production  (5,712)  (6,912)  (5,185)
   
 		   
 		   
 		 
Proved reserves, end of year
  73,272   74,575   87,259 
   
 		   
 		   
 		 
Proved developed reserves
  35,344   38,824   46,052 
   
 		   
 		   
 		 

TABLE V — Standardized measure of discounted future net cash flows related to proved oil and natural gas reserve quantities

The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.

Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.

             
  Year ended Year ended Year ended
Thousand of US Dollars
 30 September 2003
 30 September 2002
 30 September 20
Future cash inflow  1,416,343   1,381,874   1,277,494 
Future production costs  (676,419)  (599,277)  (739,221)
Future development costs  (107,841)  (119,725)  (108,882)
   
 		   
 		   
 		 
Future net revenue before income taxes  632,083   662,872   429,391 
10% annual discount for estimated timing of cash flows  (293,965)  (318,079)  (190,788)
   
 		   
 		   
 		 
Discounted future net cash flows before income taxes  338,118   344,793   238,603 
Future income taxes, discounted at 10% per annum  (68,126)  (71,442)  (30,815)
   
 		   
 		   
 		 
Standardized measure of discounted future net cash flows
  269,992   273,351   207,788 
   
 		   
 		   
 		 

15

LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in thousands US Dollars except as indicated)

TABLE VI — Changes in the standardized measure of discounted future net cash flows from proved reserves

             
  Year ended Year ended Year ended
Thousand of US Dollars
 30 September 2003
 30 September 2002
 30 September 2001
Present value at beginning of period
  273,351   207,788   337,426 
Sales of oil and natural gas, net of related costs  (60,030)  (69,541)  (54,015)
Revisions to estimates of proved reserves:            
Net changes in prices, development and production costs  (16,242)  225,132   (107,356)
Quantities  9,346   (29,432)  (71,709)
Extensions, discoveries and improved recovery, net of future costs  3,663   5,974   55,197 
Accretion of discount  34,479   23,862   41,224 
Net change of income taxes  3,316   3,367   43,994 
Development costs incurred  13,257   26,468   37,953 
Changes in timing and other  8,852   (120,267)  (74,926)
   
 		   
 		   
 		 
Present value at end of period
  269,992   273,351   207,788 
   
 		   
 		   
 		 

16

Index to Exhibits

3.1 Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1(i) to our Form 10-Q filed on August 13, 2002, File No. 1-10762.)
   
3.2 Amended and Restated Bylaws as of December 11, 2003.May 17, 2007. (Incorporated by reference to Exhibit 3.73.1 to our Form 10-K8-K filed on March 10, 2004,April 23, 2007, File No. 1-10762.)
   
4.1 Form of Common Stock Certificate. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-26333).)
   
4.2 Certificate of Designation, Rights and Preferences of the Series B.B Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.)
   
4.3 Third Amended and Restated Rights Agreement, dated as of September 16, 2003,August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, Minnesota, N.A. (incorporated by reference to Exhibit 5 to Amendment No. 1 to our Registration Statement on Form 8-A filed October 29, 2003 (Registration No. 000-17534)).
10.1Operating Service Agreement between Benton Oil and Gas Company and Lagoven, S.A., which has been subsequently combined into PDVSA Petroleo y Gas, S.A., dated July 31, 1992, (portions have been omitted pursuant to Rule 406 promulgated under the Securities Act of 1933 and filed separately with the Securities and Exchange Commission. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-52436).)
10.2Note payable agreement dated March 8, 2001 between Harvest Vinccler, C.A. and Banco Mercantil, C.A. related to a note in the principal amount of $6,000,000 with interest at LIBOR plus five percent, for financing of Tucupita Pipeline. (Incorporated by reference to Exhibit 10.2499.3 to our Form 10-Q,8-A filed on May 15, 2001,October 23, 2007, File No. 1-10762.)
   
10.3†
Change of Control Severance Agreement effective May 4, 2001. (Incorporated by reference to Exhibit 10.26 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.)
  
10.410.1 Alexander E. Benton Settlement and Release Agreement effective May 11, 2001 (Incorporated by reference to Exhibit 10.27 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.).
10.5First Amendment to Change of Control Severance Plan effective June 5, 2001. (Incorporated by reference to Exhibit 10.31 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.)
10.6Sale and Purchase Agreement dated February 27, 2002 between Benton Oil and Gas Company and Sequential Holdings Russian Investors Limited regarding the sale of Benton Oil and Gas Company’s 68 percent interest in Arctic Gas Company. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on March 28, 2002, File No. 1-10762.)
10.7 2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-8 filed on April 9, 2002 (Registration Statement No. 333-85900).)
   
10.8Addendum No. 2 to Operating service agreement Monagas SUR dated 19th September, 2002. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
  
10.910.2 Bank Loan Agreement between Banco Mercantil, C.A. and Harvest Vinccler C.A. dated October 1, 2002. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
10.10Guaranty issued by Harvest Natural Resources, Inc. dated September 26, 2002. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
10.11†
Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Peter J. Hill. (Incorporated by reference to Exhibit 10.10 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
10.12†
Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.11 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
10.13†
Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.12 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
10.14†
Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.13 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
10.15Sale and Purchase Agreement dated September 26, 2003, between Harvest Natural Resources, Inc. and Yukos Operational Holding Limited regarding the sale of our 34 percent minority equity investment in LLC Geoilbent. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 10, 2003, File No. 1-10762.)
10.16†
Employment Agreement dated November 17, 2003 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.18 to our Form 10-Q filed on March 10, 2004, File No. 1-10762.)

10.17†
Employment Agreement dated September 1, 2004 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10-1 to our Form 10-Q filed on November 5, 2004, File No. 1-10762.)
10.18†
 Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).)

   
10.1910.3†
 Form of Indemnification Agreement between Harvest Natural Resources, Inc. and the Directorseach Director and Executive OfficersOfficer of the Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
   
10.20†
10.4 Form of 2004 Long Term Stock Incentive Plan Stock Option AgreementAgreement. (Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
   
10.21†
10.5 Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock AgreementAgreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
   
10.22†
10.6 Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock AgreementAgreement. (Incorporated by reference to Exhibit 10.22 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
   
10.7†
Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
10.8†
Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
10.9†
Employment Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
10.10†
Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.24 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)
10.11†
Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)
10.12†
Stock Option Agreement dated September 26, 2005, between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.26 to our Form 10-K filed on February 27, 2006, File No. 1-10762.)
10.13†
Employment Agreement dated February 10, 2006 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on April 20, 2006, File No. 1-10762.)
10.14Harvest Natural Resources 2006 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on June 1, 2006 [Registration Statement No. 333-134630].)
10.15Form of 2006 Long Term Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
10.16Form of 2006 Long Term Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
10.17Form of 2006 Long Term Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)

10.18†
Stock Unit Award Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
10.19†
Stock Unit Award Agreement dated March 2, 2006 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.)
10.20Note Payable agreement dated November 20, 2006 between Harvest Vinccler, C.A. and Banesco Banco Universal C.A. related to a principal amount of 120 billion Bolivars with interest at 10.0 percent, for refinancing of the SENIAT assessments and operating requirements. (Incorporated by reference to Exhibit 10.32 to our Form 10-K filed on March 13, 2007, File No. 1-10762.)
10.21Form of 2006 Long Term Incentive Plan Stock Option Agreement — Five Year Vesting, Seven Year Term. (Incorporated by reference to Exhibit 10.33 to our Form 10-K filed on March 13, 2007, File No. 1-10762.)
10.22Amendment to Harvest Natural Resources 2006 Long Term Incentive Plan adopted July 19, 2006. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on May 3, 2007, File No. 1-10762.)
10.23†
Employment Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)
10.24†
Stock Option Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)
10.25†
Employee Restricted Stock Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)
10.26†
Consulting Agreement dated July 16, 2007 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.)
10.27Contract for Conversion to a Mixed Company between Corporación Venezolana del Petróleo, S.A., Harvest-Vinccler, S.C.A. and HNR Finance B.V. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on November 1, 2007, File No. 1-10762.)
10.28†
Separation Agreement dated November 16, 2007 between Harvest Natural Resources, Inc. and Byron A. Dunn.
21.1 List of subsidiaries.
   
23.1 Consent of PricewaterhouseCoopers LLP — HoustonHouston.
   
23.2 Consent of ZAO PricewaterhouseCoopers Audit — MoscowEspiñeira, Sheldon y Asociados.
   
23.3 Consent of Ryder Scott Company, LPLP.
   
31.1 Certification of the Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.2002 executed by James A. Edmiston, President and Chief Executive Officer.
   
31.2 Certification of the Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer.

32.1Certification accompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by James A. Edmiston, President and Chief Executive Officer.
   
32.1Certification of the Chief Executive Officer accompanying the annual report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
  
32.2 Certification of theaccompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer accompanying the annual report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.and Treasurer.

†
Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c)15(a) and (b) of Form 10-K.10-K