UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-K

(Mark One)
   
[ X ]þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005
or
   
For the fiscal year ended December 31, 2003
or
[]o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No.: 1-10762

HARVEST NATURAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
   
Delaware 77-0196707
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number)
15835 Park Ten Place Drive,1177 Enclave Parkway, Suite 115300  
Houston, Texas 7708477077
(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code:(281) 579-6700899-5700

Securities registered pursuant to Section 12(b) of the Act:
   
Title of each class Name of each exchange on which registered
 		 
 
Common Stock, $.01 Par Value NYSE

Securities registered pursuant to Section 12(g) of the Act:
   
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. Yes [X]þ No [   ]

o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [  ]

o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. Large Accelerated Filero Accelerated Filerþ Non-Accelerated Filero
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). Yes [X]o No [   ]

þ

State the aggregate market value of the 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 27, 2003: $225,487,430.

30, 2005: $415,711,721.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practical date. Class: Common Stock, par value $0.01 per share, on March 1, 2004,February 10, 2006, shares outstanding: 35,778,161.

37,093,595.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for the 20042006 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
Item 1. Business
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
PART II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
Item 6. Selected Financial Data
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
PART III
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions
Item 14. Principal Accounting Fees and Services
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
SIGNATURES
EXHIBIT INDEX
Amended Bylaws
Employment Agreement - Karl L. Nesselrode
List of Subsidiaries
Consent of PricewaterhouseCoopers LLP
Consent of ZAO PricewaterhouseCoopers Audit-Moscow
Consent of Ryder Scott Company, LP
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO & CFO Pursuant to Section 906

HARVEST NATURAL RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS

       
    Page
Part I
      
Item 1.Business2
Item 2.Properties14
Item 3.Legal Proceedings14
Item 4.Submission of Matters to a Vote of Security Holders14
Part II      
Item 5.1.
 Market for Registrant’s Common Equity and Related Stockholder MattersBusiness  151 
Item 6.1A.
 Selected Financial DataRisk Factors  1513 
Item 7.1B.
 Management's Discussion and Analysis of Financial Condition and Results of OperationsUnresolved Staff Comments  1618 
Item 7A.2.
 Quantitative and Qualitative Disclosures About Market RiskProperties  2818 
Item 8.3.
 Financial Statements and Supplementary DataLegal Proceedings  2919 
Item 9.4.
 Changes in and Disagreements with Accountants on Accounting and Financial DisclosureSubmission of Matters to a Vote of Security Holders  2919 
Item 9A.Controls and Procedures29
Part III      
Item 10.Directors and Executive Officers of the Registrant30
Item 11.Executive Compensation30
Item 12.Security Ownership of Certain Beneficial Owners and Management30
Item 13.Certain Relationships and Related Transactions30
Item 14.Principal Accounting Fees and Services30
Part IVII
      
Item 15. Exhibits,
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities20
Item 6.
Selected Financial Statement SchedulesData20
Item 7.
Management's Discussion and Reports on Form 8-KAnalysis of Financial Condition and Results of Operations22
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk30
Item 8.
Financial Statements and Supplementary Data  31
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure31
Item 9A.
Controls and Procedures31
Item 9B.
Other Information31
Part III
Item 10.
Directors and Executive Officers of the Registrant32
Item 11.
Executive Compensation32
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters32
Item 13.
Certain Relationships and Related Transactions32
Item 14.
Principal Accountant Fees and Services32
Part IV
Item 15.
Exhibits and Financial Statement Schedules33
 
Financial Statements  S-1S-2 
Signatures  S-35 
Signatures
S-31
Stock Option Agreement dated September 15, 2005 - James A. Edmiston
Stock Option Agreement dated September 15, 2005 - James A. Edmiston
Stock Option Agreement dated September 26, 2005 - Byron A. Dunn
List of Subsidiaries
Consent of PricewaterhouseCoopers LLP - Houston
Consent of ZAO PricewaterhouseCoopers Audit - Moscow
Consent of Ryder Scott Company, LP
Certification pursuant to Section 302, President and CEO
Certification pursuant to Section 302, SVP, CFO and Treasurer
Certification pursuant to Section 906, President and CEO
Certification pursuant to Section 906, SVP, CFO and Treasurer

1

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 theour concentration of our 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, successful conversion of Venezuelan assets to a mixed company, 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 operation and development of oil and natural gas properties, 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, overall economic conditions, political stability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in governmental policy, availability of sufficient financing, changes in weather conditions, and ability to hire, retain and train management and personnel. See Item 1A — Risk Factors included inand Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.

At the end of Item 1 is a glossary of terms.

Item 1. Business

General

Executive Summary
     Harvest Natural Resources, Inc. is an independent energy company engaged in the acquisition, development, production and disposition of oil and natural gas properties since 1989, when it was incorporated under Delaware law. Over our history, we have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”) and the Russian Federation (“Russia”) and have undeveloped acreage offshore China. Ourof the People’s Republic of China (“China”). Currently, all of our producing operations are conducted principally through our 80 percent-owned Venezuelan subsidiary, Benton-Vinccler,Harvest Vinccler, C.A. (“Benton-Vinccler”Harvest Vinccler”), which operates the South Monagas Unit in Venezuela. From December 14, 2002 through February 6, 2003, no sales of our Venezuelan oil production were made because ofVenezuela under an operating service agreement with Petroleos de Venezuela S.A.’s (“PDVSA”) inability. During 2005, the government of Venezuela initiated a series of actions to acceptcompel companies with operating service agreements to convert those agreements into new companies in which PDVSA has a majority interest. These actions adversely affected our oil due to the national civil work stoppageoperations in Venezuela. While restoring production led to increased workover activity and higher operating costs, the return performanceVenezuela in a number of the field was within our expectations. On November 25, 2003, we diversified our revenue stream by beginning the sale of natural gas in Venezuela. On September 25, 2003, we closed the Sale ways. SeeItem 1 – Business, Operations, Item 1A — Risk Factors,and Purchase Agreement to sell our entire 34 percent minority equity investment in LLC Geoilbent (“Geoilbent”), to Yukos Operational Holding Limited, a Russian oil and gas company, for $69.5 million plus $5.5 million as repayment of intercompany loans and outstanding accounts payable owed to us by Geoilbent. SeeItem 7 –— Management’s Discussion and Analysis of Financial ConditionsCondition and Results of Operationsfor a complete description of these and other events.

events during 2005.

     Due to the actions taken by the government of Venezuela, we were unable to carry out our planned development program for 2005. Moreover, our ability to carry out future programs is uncertain. As a consequence, we have reduced our proved reserves by approximately 50 percent and we estimate that the discounted future net cash flows from our proved reserves has been reduced by approximately 60 percent. As a result of this reduction, as of December 31, 2003,2005, we had total estimated Proved Reservesproved reserves in the South Monagas Unit, net of minority interest, of 96.4 MMBoe,36 million barrels of oil equivalent (“MMBoe”), and a standardized measure of discounted future net cash flow, before income taxes,flows of $329 million. See the discussion inItem 1 – Business, Operationsbelow, for total Proved Reservesa more detailed discussion of $545.3 million.

our proved reserves and the reserve reduction.

     As of December 31, 2003,2005, we had total assets of $374.3$400.8 million. We had cash in excess of long term debt in the amount of $41.9$163.0 million, no long-term debt, total revenues of $236.9 million and net cash provided by operating activities of $114.7 million. For the year ended December 31, 2003,2004, we had total assets of $367.5 million. We had cash in the amount of $84.6 million, no long-term debt, total revenues of $106.1$186.1 million and net cash provided by operating activities of $38.5 million, and long-term debt of $96.8$74.1 million. For the year ended December 31, 2002, we had total revenues of $126.7 million, net cash provided by operating activities of $42.6 million, and long-term debt of $104.7 million.

21

     Our business strategy is to be a growing international company that seeks and develops large known resources in countries perceived as politically challenged. Our strategy is to segregate and diversify risk by adding fields in other countries. In executing our business strategy, we strive to:
•maintain financial prudence and rigorous investment criteria;
•enhance access to capital markets;
•create a diversified portfolio of large assets;
•maximize cash flows from existing operations;
•use our experience, skills to acquire new projects; and
•keep our organizational capabilities in line with our rate of growth.
While our strategy does not focus on unexplored areas, we will consider appropriate exploration opportunities that have large potential scale and the cost of failure is low.
     In Venezuela, we seek to deliver maximum operating cash flow through the efficient management of our capital expenditure programs and cost structure. Our Venezuelan producing properties generate net cash from operating activities in excess of projected capital expenditures.
     We have substantial cash flow due to current oil prices, current production levels for both oil and natural gas and the current capital reinvestment restrictions in Venezuela. We believe this provides us with the ability to pursue growth opportunities in Russia and other countries while at the same time maintaining a strong balance sheet. However, in 2005 and to date in 2006, we have been unable to obtain permits from the Ministry of Energy and Petroleum (“MEP”) to drill wells, which are critical to our ability to fully execute our drilling and facilities program. These difficulties have adversely affected our production and may affect our ability to pursue growth opportunities in Russia and other countries.
     Our ability to successfully execute our strategy is subject to significant risks including, among other things, operating risks, political risks, legal risks and financial risks. SeeItem 1A – Risk Factors,Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operationsand other information set forth elsewhere in this Form 10-K for a description of these and other risk factors.
     Effective October 1, 2005, James A. Edmiston was elected President and Chief Executive Officer. The election follows the retirement of Dr. Peter J. Hill, who remains on our Board of Directors. Mr. Edmiston joined us in September 2004 when he was named Executive Vice President and Chief Operating Officer. Mr. Edmiston was elected to the Board of Directors at the May 2005 Annual Meeting of Stockholders.
     In September 2005, Byron A. Dunn was elected Senior Vice President, Corporate Development. Mr. Dunn resigned his position on the Board of Directors where he served from October 2000 until March 2002 and again from December 2003 until September 2005.
     In November 2005, J. Michael Stinson was elected to our Board of Directors.
Available Information

     We file annual, quarterly and current reports, proxy statements and other documents with the Securities and Exchange Commission (“SEC”) under the Securities Act of 1934. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, 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.

www.sec.gov.

     We also make available, free of charge on or through our Internet website (http:(http://www.harvestnr.com)www.harvestnr.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Current Reports on Form 3, 4 and 5, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably

2

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 Securities 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 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., attentionAttention Investor Relations.

Business Strategy

          Our business strategy is

Operations
     During 2005, Harvest Vinccler was not able to identify, acquire, developexecute its budgeted facilities and produce large discovereddrilling program due to the refusal of PDVSA and MEP to process and grant necessary permits. As a result, Harvest Vinccler suspended its drilling program for the year, and completed only one new well. Due to the lack of drilling in 2005, daily production of oil and natural gas fields in areas that are being largely avoidedvolumes declined. Crude oil sales volumes were also affected by many other oil and gas companies due to challenging political and economic circumstances. We have more than ten years of experience in Venezuela and Russia, and have established operating organizations in both countries. We seek additional opportunities in these two countries and in other countries that meet our investment criteria. In executing our business strategy, we will strive to sustain the current balance sheet strength through financial prudence and rigorous investment profitability criteria; maximize cash flows from existing operations to invest in new opportunities; use our experience, skills and cash on hand to acquire new projects in Russia and Venezuela; and keep our organizational capabilities in line with our rate of growth.

          In Venezuela, we intend to deliver more operating cash flow through the efficient managementa curtailment of our capital expenditure programs and cost structure. We completedoil deliveries during the first phasepart of 2005. In August 2005, we submitted a proposed 2006 work program and budget to PDVSA which, under circumstances where we have reasonable assurances that PDVSA will adhere to the provisions of our gas project at the South Monagas Unit in November 2003 on time and within budget and commenced gas sales on November 25, 2003. This isoperating service agreement, would enable Harvest Vinccler to increase deliveries through an important milestone of our strategy because it diversifies our revenues and cash flow, and develops vital market outlets to support further development of untapped reserves of natural gas in Eastern Venezuela. Our Venezuelan producing properties generate net cash from operating activities in excess of projected capital expenditures. We expect to reinvest this cash in new growth opportunities in Venezuela. In November 2003, we executed a Memorandum of Understanding with PDVSA to submit a plan of development for the previously developed Temblador Field and the discovered, yet undeveloped, El Salto Field.accelerated drilling program. Under the terms of the Memorandum of Understanding, we can submitexisting operating service agreement, Harvest Vinccler’s 2006 work program and budget was deemed approved in October 2005. There are ongoing discussions between Harvest Vinccler and PDVSA on the terms for commencing the 2006 work program. In 2005, Harvest Vinccler was also notified by the MEP that it considered all operating service agreements in Venezuela to be illegal and that the agreements must be converted into incorporated companies in which PDVSA will have a plan of developmentcontrolling interest (a “mixed company”). MEP has stated that the deadline for developmentconversion of the fields under Venezuela’s Organic Hydrocarbon Law. We are alsoagreements into mixed companies is March 31, 2006. While Harvest Vinccler is engaged in discussionsgood faith negotiations with MEP and PDVSA foron converting to a mixed company, significant issues remain open, and the developmenttiming or outcome is uncertain. The resumption of the nearby Isleno Field.

          We are seeking to diversify our cash flow outside of Venezuela as events there demonstrated the risks of our concentrationany significant drilling operations in Venezuela when we lost six weeks of production in the first part of 2003. We seek operational and financial control, good minority interest partners, access to competitive oil and gas markets, and where possible, reliable export facilities and infrastructure. We seek low entry cost projects that need additional funding, execution skills and well reasoned development.

          In Russia, we continue to evaluate a number of options to invest in known discoveries which remain undeveloped or under-developed. In September 2003, we sold our 34 percent minority equity investment in our Russian company Geoilbent. As a minority interest owner, our continuing investment in Geoilbent was determined to be inconsistent with our objective of investing in properties in which we have operating and financial control.

          We intend to continue to identify, acquire and exploit known oil and natural gas fields in our current areas of activity while maintaining our financial strength and flexibility. To accomplish this, we intend to:

3

•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.
•Seek operational and financial control. We desire to control all major decisions for development, production, staffing and financing of each project for a period of time sufficient for us to reap attractive 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 our areas of operation to facilitate stronger relationships with local government and labor. In addition, using local personnel helps 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 expenditure or development commitments at the outset of new projects, but we endeavor to structure such commitments so that we can fulfill them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our maximum cash outlay. 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.
•Maintain a prudent financial plan: We intend to maintain our financial flexibility by maintaining our total debt within average industry debt to capitalization levels, closely monitoring spending, holding significant cash reserves, actively seeking opportunities to reduce our weighted average cost of capital and increasing our liquidity.

          Our ability to successfully execute our strategy is subject to significant risks including, among other things, operating risks, political risks, legal risks and financial risks. SeeItem 7 – Management’s Discussion and Analysis of Financial Conditions and Results of Operationsand other information set forth elsewhere in this Form 10-K for a description ofunlikely until these and other risk factors.

Operations

uncertainties are resolved.

     The following table summarizes our Proved Reserves,proved reserves, drilling and production activity, and financial operating data by principal geographic area at the end of each of the years ending December 31, 2003, 20022005, 2004 and 2001.2003. All Venezuelan reserves are attributable to an operating service agreement between Benton-VincclerHarvest Vinccler and PDVSAPetroleos de Venezuela S.A. under which all mineral rights are owned by the Government of Venezuela. We disposed of our Russian investments partly in 2002 and partly in 2003. Geoilbent and 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, 2002 and 2001 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002 and 2001, and from Arctic Gas, until it was sold on April 12, 2002 and for the twelve months ended September 30, 2001.

     We own 80 percent of Benton-Vinccler.Harvest Vinccler. The reserve information presented below is net of a 20 percent deduction for the minority interest in Benton-Vinccler.Harvest Vinccler. Drilling and production activity and financial data are reflected without deduction for minority interest. Reserves include production projected through the end of the operating service agreement in 2012. We have submitted a request for extension under the force majeure provisions of our contract. The Venezuelan national civil work stoppage required Benton-Vinccler to shut-in production for approximately two months. We believe the two months representing this delay will be added to the original term of our agreement.

43

                     
 Benton-Vinccler
 Harvest Vinccler 
 Year Ended December 31,
 Year Ended December 31, 
 2003
 2002
 2001
 2005 2004 2003 
 (Dollars in 000’s) (Dollars in 000’s) 
RESERVE INFORMATION
 
RESERVE INFORMATION:
 
Proved Reserves (MBoe) 96,364 102,534 83,611  36,105 84,418 96,364 
Discounted future net cash flow attributable to proved reserves, before income taxes $545,308 $481,284 $176,210 
Standardized measure of future net cash flows $366,770 $317,799 $163,328 
Standardized measure of discounted future net cash flows $329,438 $544,980 $366,770 
DRILLING AND PRODUCTION ACTIVITY:
  
Gross wells drilled 3 13 8  1 16 3 
Average daily production (Boe) 20,130 26,598 26,788  35,732 36,418 20,130 
FINANCIAL DATA:
  
Oil and natural gas revenues $106,095 $126,731 $122,386  $236,941 $186,066 $106,095 
Expenses:  
Operating expenses and taxes other than on income 31,445 31,608 42,175  39,969 33,297 31,445 
Depletion 19,599 22,685 21,175  41,175 34,108 19,599 
Income tax expense 12,158 4,866 9,083  65,943 38,968 12,158 
 
 		 
 		 
 		        
Total expenses 63,202 59,159 72,433  147,087 106,373 63,202 
 
 		 
 		 
 		        
Results of operations from oil and natural gas producing activities $42,893 $67,572 $49,953  $89,854 $79,693 $42,893 
 
 		 
 		 
 		        

     Due to the actions of the Venezuelan government, the 2005 reserve information shown above 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 have been reduced to remove undeveloped reserves because the actions taken by the Venezuelan government in 2005 under our operating service agreement 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 reduced reserves are hereafter referred to as “Contractually Restricted Reserves”. The following table is a reconciliation of the impact of the reduction of our year-end proved reserves.
             
  Proved Reserves 
  Total  Developed  Undeveloped 
  (amounts in thousands) 
Total MBoe (net of minority interest)
            
Proved Reserves beginning of the year  84,418   47,176   37,242 
Revisions of previous estimates(a)
  (37,880)  (638)  (37,242)
Production  (10,433)  (10,433)  — 
          
Proved Reserves end of the year  36,105   36,105   — 
          
(a)Includes primarily Contractually Restricted Reserves as well as other minor revisions.
     We owneddisposed of our 34 percent ofinterest in LLC Geoilbent which we(“Geoilbent”), a Russian company, in 2003. We accounted for Geoilbent under the equity method.method and included its ownership interest in our consolidated financial statements for the periods in which we owned the investment. Our year-end financial information contains results from our Russian operation based on a twelve-month period ending September 30. Accordingly, our results of operations for the year ended December 31, 2003 reflect results from Geoilbent until it was sold on September 25, 2003. The following table presents our proportionate share of Geoilbent’s Proved Reserves (atproved reserves at September 30, for each respective year),2003, 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 and 2001.
             
  Geoilbent
  Year Ended September 30,
  2003
 2002
 2001
  (Dollars in 000’s)
RESERVE INFORMATION
            
Proved Reserves (MBbls)  (a)  25,356   29,668 
Discounted future net cash flow attributable to proved reserves, before income taxes  (a) $117,229  $81,125 
Standardized measure of future net cash flows  (a) $92,939  $70,648 
DRILLING AND PRODUCTION ACTIVITY:
            
Gross development wells drilled  (a)  6   39 
Net development wells drilled  (a)  2   13 
Average daily production (Bbls)  5,242   6,438   4,830 
FINANCIAL DATA:
            
Oil and natural gas revenues $27,876  $31,039  $34,261 
Expenses:            
Operating, selling and distribution expenses and taxes other than on income  16,088   16,902   16,083 
Depletion  6,215   9,237   5,072 
Write-down of oil and gas properties  32,300   —   — 
Income tax expense  2,073   1,955   3,742 
   
 		   
 		   
 		 
Total expenses  56,676   28,094   24,897 
   
 		   
 		   
 		 
Results of operations from oil and natural gas producing activities $(28,800) $2,945  $9,364 
   
 		   
 		   
 		 
that date.

4

     
  Geoilbent 
  Year Ended 
  September 30, 2003 
  (Dollars in 000’s) 
RESERVE INFORMATION:
    
Proved Reserves  (a)
Standardized measure of discounted future net cash flows  (a)
DRILLING AND PRODUCTION ACTIVITY:
    
Gross development wells drilled  (a)
Net development wells drilled  (a)
Average daily production  5,242 
FINANCIAL DATA:
    
Oil and natural gas revenues $27,876 
Expenses:    
Operating, selling and distribution expenses and taxes other than on income  16,088 
Depletion  6,215 
Write-down of oil and gas properties  32,300 
Income tax expense  2,073 
    
Total expenses  56,676 
    
Results of operations from oil and natural gas producing activities $(28,800)
    
(a) Geoilbent was sold on September 25, 2003.

          As of December 31, 2001, we owned, free of any sale and transfer restrictions, 39 percent of the equity interests in Arctic Gas, which we accounted for under the equity method. The following table presents our proportionate share, free of sale and transfer restrictions, of Arctic Gas’s Proved Reserves (at September 30, 2001),

5

drilling and production activity, and financial operating data for the period until it was sold on April 12, 2002 and for the twelve months ended September 30, 2001.

         
  Arctic Gas Company
  Year Ended September 30,
  2002
 2001
  (Dollars in 000’s)
RESERVE INFORMATION
        
Proved Reserves (MBoe)  (a)  55,631 
Discounted future net cash flow attributable to proved reserves, before income taxes  (a) $108,400 
Standardized measure of future net cash flows  (a) $82,205 
DRILLING AND PRODUCTION ACTIVITY:
        
Gross wells reactivated  (a)  2 
Average daily production (Bbls)  189   502 
FINANCIAL DATA:
        
Oil and natural gas revenues $3,554  $889 
Expenses:        
Selling and distribution expenses  1,429   1,166 
Operating expenses and taxes other than on income  1,673   2,215 
Depletion  139   311 
Income tax expense  19   80 
   
 		   
 		 
Total expenses  3,260   3,772 
   
 		   
 		 
Results of operations from oil and natural gas producing activities $294  $(2,883)
   
 		   
 		 

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

South Monagas Unit, Venezuela (Benton-Vinccler)

(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.fields (the “operating service agreement” or “OSA”). 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.

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

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

     Vinccler has an extensive operating history in Venezuela. It provided Benton-VincclerHarvest 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, Benton-VincclerHarvest Vinccler is a contractor for PDVSA. Benton-VincclerHarvest 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

6

ownership of all hydrocarbons in the fields. In addition, PDVSA maintains full ownership of equipment and capital infrastructure following its installation.

5

     The operating service agreement provides for Benton-VincclerHarvest Vinccler to receive an operating fee for each barrel of crude oil delivered. It also provides Benton-VincclerHarvest 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. In August 2005, Harvest Vinccler entered into a Transitory Agreement with PDVSA (the “Transitory Agreement”). The Transitory Agreement provides that effective January 1, 2005, the total amounts paid under the OSA will not exceed 66.67 percent of the total value of the crude oil as determined under an Annex to the Transitory Agreement. Historically, our maximum total fee is subject to quarterly adjustments to reflect changes inunder the averageOSA averaged approximately 48 percent of certain world crude oil prices. Since 1992, the maximum total fee received by Benton-Vinccler has approximated 48 percentprice of West Texas Intermediate crude oil (“WTI”) price.

. Under the fee limit in the Transitory Agreement, the new fee has historically averaged approximately 47 percent of the price of WTI.

     In September 2002, Benton-VincclerHarvest 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. Naturalthousand standard cubic feet (“Mcf”). For 2005, natural gas sales began in November 2003 and were averaging 70-80 MMcfaveraged 70 million cubic feet (“MMcf”) per day by the end of the year.day. In addition, Benton-VincclerHarvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil (“MMBbls”) stipulated as additional volumes resulting from the natural 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 MMBlsMMBbls to 198 Bcf.

     At the end of each quarter, Benton-VincclerHarvest 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, Benton-VincclerHarvest Vinccler also prepares invoices for natural gas sales and Incremental Crude Oil. Payment is due under the invoices by the end of the second month after the end of the quarter. InvoiceThe operating service agreement stipulates invoice amounts and payments are to be denominated in U.S. dollars. PaymentsDollars. Notwithstanding these contractual requirements, PDVSA paid the fee for first quarter 2005 deliveries 50 percent in U.S. Dollars and 50 percent in Venezuelan Bolivars (“Bolivars”). Subsequent quarterly payments for 2005 have been received 75 percent in U.S. Dollars and 25 percent in Bolivars. U.S. Dollar payments are wire transferred into Benton-Vinccler’sHarvest Vinccler’s account in a commercial bank in the United States.

          Benton-VincclerStates and the Bolivar payments are deposited in a bank in Venezuela. PDVSA’s payment for the first quarter of 2005 was late by 28 days and was short $9.8 million. Upon signing the Transitory Agreement, the underpayment, to the extent of the new limit on service fees, was paid.

     Harvest Vinccler has constructed a 25-mile oil pipeline from its oil processing facilities at Uracoa 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 Benton-Vinccler’sHarvest Vinccler’s facilities and at PDVSA’s storage facility.

          With respect to gas sales, an initial capital investment of approximately $27 million was required to build

     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. We completed the fabrication and construction process for the gas pipeline in late 2003. Benton-Vinccler borrowed $15.5 million under a project loan for the gas pipeline and related facilities and the remainder was funded from existing cash balances and internally generated cash flow. In addition, Benton-Vinccler has entered into long-term agreements for the leasing of compression, and the operation and maintenance of the gas treatment and compression facilities. The operating servicesservice agreement contains requirements for the measurement and quality of the natural gas delivered to PDVSA.

     In August 1999, Benton-VincclerHarvest Vinccler sold its power generation facility located in the Uracoa and Tucupita Fields. Concurrently with the sale, Benton-VincclerHarvest 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 in the future 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 inItem 1A – Risk Factors andItem 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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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, 2003, Proved Reserves2005, proved reserves attributable to our Venezuelan operations were 120,455 MBoe (96,364 MBoe45 MMBoe (36 MMBoe net to Harvest). This represented 100 percent of our Proved Reservesproved reserves at year end. Benton-VincclerThe 2005 reserve information does not include Contractually Restricted Reserves. SeeItem 1 – Business, Operations.Harvest Vinccler has been primarily developing the Oficina sands in the Uracoa Field. The Uracoa Field contains 6673 percent of the South Monagas Unit’s Proved Reserves.

7

proved reserves.

Drilling and Development Activity

          Benton-Vinccler

     Harvest Vinccler drilled three oil wells and converted two gas injection wells to producing wells in 2003one well and had an average of 111108 wells on production in all fields at year end 2005 in 2003.

the South Monagas Unit.

Uracoa Field

          Benton-Vinccler

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

          Benton-Vinccler There are currently 80 oil and natural gas producing wells in the field.

     Harvest Vinccler processes the oil, water and natural gas in the Uracoa central processing unit and shipstransports the processed oil via pipeline to the PDVSA custody transfer point. Benton-VincclerHarvest Vinccler treats and filters produced water, then reinjects it into the aquifer to assist the natural water drive. Benton-Vinccler hadHarvest Vinccler 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.gas to PDVSA pursuant to an amendment to the operating service agreement. The major components of the state-of-the-art process facility were designed in the United States and installed by Benton-Vinccler.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 MBblsthousand barrels (“MBbls”) of oil per day, 130 MBbls of water per day, and injection capacitystorage of 46 MMcfup to 75 MBbls of crude oil. All natural gas per day. Presently all gaspresently being sold by Harvest Vinccler is produced from the Uracoa Field.

Tucupita Field

     There are currently 3124 oil producing wells and sixfive water injection wells at Tucupita. 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 per day capacity oil pipeline constructed in 2001 from Tucupita to the Uracoa central processing unit.

          Benton-Vincclerplant 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

          In 2003, Benton-Vinccler

     The East Bombal Field was drilled threein 1992, and production from the wells was halted until the produced natural gas could be sold. There are currently four oil producing wells in the West Bombal Field. Portable separation, pumpingThe fluid produced from West Bombal Field flows through a six mile pipeline and storage for 7.5 MBbl of crude oil are maintained at the field. The crude oil is pumped via a pipeline and tied into the 31-mile Tucupita oil pipeline to the Uracoa central processing unit. The East Bombal Field was drilled in 1992,plant facilities. Development of this field has been postponed due to the refusal of PDVSA and the wells were suspended untilMEP to process and grant necessary permits. SeeItem 1 — BusinessandItem 1A – Risk Factors. Natural gas sales could take place. Benton-Vinccler expects to begin engineering and design studies in late 2004 with first gas sales expected in 2005. Gas from this field willwas intended to be used to supplement natural gas productionsales from Uracoa as production there declines.

Customers and Market Information

     Under the operating service agreement, all oil and natural gas produced is delivered to PDVSA for a fee. From December 14, 2002 through February 6, 2003, no sales were made because of PDVSA’s inability to accept our oil due to the national civil work stoppage in Venezuela. While we have substantial cash reserves, a prolonged loss of sales could have a material adverse effect on our financial condition.

7

Employees and Community Relations

          Benton-Vinccler

     Harvest Vinccler has a highly skilled staff of 189252 local employees and four expatriates and has also formed successful and supportive relationships with local government agencies and communities.

          Benton-Vincclerone expatriate. Harvest Vinccler has invested in a Social Community Program that includes medical programs in ophthalmologic and dental care, as well as additional social investments including the purchase of medicines and medical equipment for local communities within the South Monagas Unit.

Health, Safety and Environment

          Benton-Vinccler’s

     Harvest Vinccler’s health, safety and environmental policy is an integral part of its business. Benton-VincclerHarvest Vinccler continually improves its policy and practices related to personnel safety, property protection and

8

environmental management. These improvements can be directly attributed to its efforts in accident prevention programs and the training and implementation of a comprehensive Process Safety Management System.

North Gubkinskoye and South Tarasovskoye, Russia (Geoilbent)

          On

     In September 25, 2003, we sold our 34 percent minority equity investment in Geoilbent to Yukos Operational Holding Limited for $69.5 million plus $5.5 million for the repayment of intercompany loans and accounts receivable. SeeNote 97 – Russian Operations.

East Urengoy, Russia (Arctic Gas Company)

          Arctic Gas Company was sold in April 2002. SeeNote 9 – 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 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 area under 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. An evaluation was performed again at December 31, 2003, and such evaluation indicated that no further impairment of the property had been incurred in 2003.

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 50 miles southeast of the Dai Hung (Big Bear) Oil Field.Field, which recently discovered additional oil reserves in deeper Miocene zones. The block is adjacent to the east of British Petroleum’s giant natural gas discoverydiscoveries at Lan Tay (Red Orchid) and 100 miles northLan Do, which are estimated to contain two trillion cubic feet of Exxon’s Natuna Discovery.natural gas. It is also adjacent to the 2005 Thien Ung discovery which tested oil and natural gas. The contract area covers several similar structural trends involving similar geological formations, each with potential for hydrocarbon reserves in possible multiple pay zones.

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, 2005.2007. While no assurance can be given, we believe we will continue to receive license extensions so long as the border disputes persist.

8

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. All capitalized costs associated with the California Leases have been fully impaired. The California Leases have expired and we have listed the onshore property for sale.

Activities by Area

     The following table summarizes our consolidated activities by area. Total Assets represents all assets, including long-lived assets accounted for under the equity method:

9

                     
      Other  Total       
(in thousands) Venezuela  Foreign  Foreign  United States  Total 
Year ended December 31, 2005
                    
Oil and natural gas sales $236,941   —  $236,941   —  $236,941 
Total Assets $258,268  $317  $258,585  $142,213  $400,798 
                     
Year ended December 31, 2004
                    
Oil and natural 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 natural gas sales $106,095   —  $106,095   —  $106,095 
Total Assets $241,855  $237  $242,092  $132,256  $374,348 
                     
      Other Total    
(in thousands)
 Venezuela
 Foreign
 Foreign
 United States
 Total
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 
Year ended December 31, 2001
                    
Oil sales $122,386      $122,386      $122,386 
Total Assets $167,671  $100,801  $268,472  $79,679  $348,151 
Reserves

Reserves

     Estimates of our Proved Reservesproved reserves as of December 31, 20032005 and 20022004 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. The following table sets forth information regarding estimates of Proved Reservesproved reserves at December 31, 2003.2005, which are all in Venezuela. The Venezuelan information includes reserve information net of a 20 percent deduction for the minority interest in Benton-Vinccler.Harvest Vinccler. All Venezuelan reserves are attributable to an operating service agreement between Benton-VincclerHarvest 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  36,688   33,610   70,298 
   
 		   
 		   
 		 
 The Ryder Scott report states: “The reserve report is prepared following SEC’s definitions and guidelines. One specific guideline is the estimation of proved reserves requires a demonstration with reasonable certainty that the proved reserves are recoverable in future years under existing economic and operating conditions. This year’s report does not include reserves in the proved undeveloped category due solely to the uncertainty in future capital spending by Harvest Vinccler C.A. to drill and develop this category of reserves is a result of the actions and statements of the Venezuelan authorities during the year 2005.” (For management’s discussion of the reserve reduction, seeItem 1 – Business, Operationsabove.) A detailed reconciliation of proved reserves and values can be found on Table IV and Table V of the Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) under Item 15.
             
  Net Natural Gas (MMcf)
  Proved Proved  
  Developed
 Undeveloped
 Total
Venezuela  84,918   71,482   156,400 
   
 		   
 		   
 		 
Venezuela
Net Crude Oil and Condensate (MBbls) – Proved28,249
Net Natural Gas (MMcf) – Proved47,134

     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.results; and
•assumptions concerning contractual rights to develop reserves and whether those rights will be honored.

     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 47 percent of our total Proved Reserves were undeveloped as of December 31, 2003. The cost to develop the Proved Undeveloped Reserves is expected to be $65.6 million over the next three years.

9

     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:

10

• 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, contracting policies, taxation or taxation;other policies;
•contract sanctity; and
 
• the impact of inflation on costs.

     The timing of actual future net oil and natural gas sales from Proved Reservesproved 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 of oil and natural gas properties. The 10 percent discount factor required by the SEC to be used to calculate present value for reporting purposes is not necessarily the most appropriate discount factor based on interest rates in effect from time to time, risks associated with the oil and natural gas industry and the political risks associated with operations in Venezuela. Discounted present value, regardless of what discount rate is used, is materially affected by assumptions as to the amount and timing of future production, which assumptions may, and often do, prove to be inaccurate. For the period ending December 31, 2003,2005, we reported $545.3$412 million ($329 million net to us) of discounted future net cash flows before income taxes from Proved Reservesproved reserves based on the SEC’s required calculations.

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, 2003, 20022005, 2004 and 2001.2003. The presentation for Venezuela includes 100 percent of the production, without deduction for minority interest. Geoilbent (34 percent ownership) and Arctic Gas (39 percent ownership not subject to any sale or transfer restrictions at December 2001), which areis accounted for under the equity method, havehas been included at their respectiveits ownership interest in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, our results of operations for the years ended December 31, 2003, 20022005, 2004 and 20012003 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002 and 2001 and from Arctic Gas until it was sold on April 12, 2002 and for the twelve months ended September 30, 2001.2003.
                        
 Year Ended December 31,
 Year Ended December 31, 
 2003
 2002
 2001
 2005 2004 2003 
Venezuela(a)
  
Crude Oil Production (Bbls) 7,347,399 9,708,295 9,777,516  8,762,687 8,152,261 7,347,399 
Natural Gas Production (MMcf) 2,660,241 — — 
Natural Gas Production (Mcf) 25,677,460 31,059,416 2,660,241 
Average Crude Oil Sales Price ($per Bbl)(b) $14.07 $13.08 $12.52  $24.02 $18.90 $14.07 
Average Natural Gas Sales Price ($per MMcf) $1.03 — — 
Average Operating Expenses ($per Boe) $4.00 $3.26 $4.30 
Average Natural Gas Sales Price ($ per Mcf) $1.03 $1.03 $1.03 
Average Operating Expenses ($ per Boe) $3.05 $2.50 $4.00 
Russia
  
Geoilbent (b)(d)
  
Net Crude Oil Production (Bbls) 1,913,187 2,349,916 1,762,814   (d)  (d) 1,913,187 
Average Crude Oil Sales price ($per Bbl) $14.52 $13.21 $19.51   (d)  (d) $14.52 
Average Operating Expenses ($per Bbl) $2.83 $2.09 $2.17   (d)  (d) $2.83 
Arctic Gas (a)(c)
 
Net Crude Oil Production (Bbls)  (c)  (c) 183,087 
Average Crude Oil Sales price ($per Bbl)  (c)  (c) $21.93 
Average Operating Expenses ($per Bbl)  (c)  (c) $7.42 

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

1110

Regulation

General

     Our operations 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; andlaws relating to the petroleum industry;
 
• changes in administrative regulations and the interpretation and application of such rules and regulations.regulations; and
•changes in contract interpretation and policies of contract adherence.

     In any country in which we may do business, the oil and natural gas industry legislation and agency regulation are periodically changed for a variety of political, economic, environmental and other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business.

Venezuela

     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 Venezuelan Bolivar and the U.S. dollarDollar and restrict the ability to exchange Venezuelan Bolivars for U.S. dollarsDollars 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 Benton-VincclerHarvest Vinccler are allowed to receive payments for oil and natural gas sales in U.S. dollarsDollars and pay U.S. dollar-denominated debt, dividends andDollar-denominated expenses from those payments. Notwithstanding the contractual provisions of our operating service agreement which requires all payments to be in U.S. Dollars, PDVSA paid 50 percent of 2005 first quarter oil and natural gas sales in Bolivars. Subsequent quarterly payments for 2005 were paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar, but Harvest Vinccler projects that it will be able to utilize its Bolivars to meet local obligations. We have substantial cash reserves and do not expect the Venezuelan currency conversion restrictions orrestriction to adversely affect our ability to meet short-term loan obligations and operating requirements for the adjustment in the exchange rate to have a material impact on us at this time.

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, Benton-VincclerHarvest Vinccler submits capital budgets to PDVSA for approvalreview, including capital expenditures to comply with Venezuelan environmental regulations. No capital expenditures to comply with environmental regulations were required in 20022004 or 2003. Benton-Vinccler2005. Harvest Vinccler also submits requests for permits for drilling, seismic and operating activities to PDVSA, which then obtains such permits from the Ministry of Energy and MinesMEP and Ministry of Environment, as required. Benton-VincclerDuring 2005 and continuing into 2006, PDVSA and MEP have refused to approve or issue permits and, as a result, Harvest Vinccler suspended its drilling and facilities program in 2005. 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) $9.0 million, $39.2 million and $58.3 million $50.6 millionin 2005, 2004 and $43.9 million in 2003, 2002 and 2001, respectively. Included in these numbers is $43.6$8.9 million, $44.3$33.5 million and $28.0$43.6 million for the development of Proved Undeveloped Reservesproved undeveloped reserves in 2005, 2004 and 2003, 2002 and 2001, respectively.

11

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

12

                         
  Year Ended December 31,
  2005 2004 2003
  Gross Net Gross Net Gross Net
Wells Drilled:
                        
Development:                        
Crude oil  1   0.8   16   12.8   3   2.4 
                         
Average Depth of Wells (Feet)
  —   4,349   —   5,443   —   6,095 
                         
Producing Wells(1):
                        
Crude Oil  108   86.4   124   99.2   111   88.8 
                         
  Year Ended December 31,
  2003
 2002
 2001
  Gross
 Net
 Gross
 Net
 Gross
 Net
Wells Drilled:
                        
Exploration:                        
Dry hole  —   —   1   0.4   —   — 
Development:                        
Crude oil  3   2.4   17   10.8   20   10.5 
   
 		   
 		   
 		   
 		   
 		   
 		 
Total  3   2.4   18   11.2   20   10.5 
   
 		   
 		   
 		   
 		   
 		   
 		 
Average Depth of Wells (Feet)
      6,095       7,341       6,043 
Producing Wells(1):
                        
Crude Oil  111   88.8   258   158.2   274   169.9 

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

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

Acreage

     The following table summarizes the developed and undeveloped acreage that we owned, leased or held under operating service agreement or concession as of December 31, 2003:2005:
                              
 Developed
 Undeveloped
 Developed Undeveloped
 Gross
 Net
 Gross
 Net
 Gross Net Gross Net
Venezuela 11,166 8,933 146,677 117,342  11,726 9,381 146,117 116,894 
China — — 7,470,080 7,470,080  — — 7,470,080 7,470,080 
 
 		 
 		 
 		 
 		          
Total 11,166 8,933 7,616,757 7,587,422  11,726 9,381 7,616,197 7,586,974 
 
 		 
 		 
 		 
 		          

Competition

     We encounter strongsubstantial 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, and the financial resources necessary to acquire and develop such properties.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.

position, results of operations and cash flows.

Employees

     At December 31, 2003, we2005, our Houston office had 1815 full-time employees. Harvest Vinccler had 252 employees augmentedand our Moscow office had 10 employees. We augment our staffs from time to time with independent consultants, as required. Benton-Vinccler had 189 employees and our Moscow office had 14 employees.

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Title to Developed and Undeveloped Acreage

     All Venezuelan reserves are attributable to an operating service agreement between Benton-VincclerHarvest Vinccler and PDVSA, under which all mineral rights are owned by the Government of Venezuela.

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     The WAB-21 petroleum contract 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 a third party. The territorialborder dispute has existed for many years, and there has been limited exploration and no development activity in the area under 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.

Item 1A. 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 interests in Venezuela may be unlawfully expropriated by the Venezuelan government.All of our production and operating revenues are derived from Harvest Vinccler through its operations of the South Monagas Unit under the operating service agreement with PDVSA. The government of Venezuela has announced that all operating service agreements will cease to exist in 2006 and that operations under those agreements will be converted to mixed companies in which PDVSA has a controlling interest. The government has stated that it will reclaim the interests of operators who do not convert to a mixed company. While we are engaged in good faith negotiations with MEP and PDVSA for the conversion of Harvest Vinccler’s operating service agreement to a mixed company, there is no assurance that a conversion will be possible under acceptable terms. Based upon the government’s statements and actions, there is a risk that if Harvest Vinccler is unable to agree with Venezuela on the terms of a mixed company, its interests may be unlawfully expropriated or actions may be taken to prevent or render impossible continued operations. Expropriatory acts by Venezuela would likely cause us to seek international arbitration for the loss of our investment.
Our only source of production may be reduced further by actions of the Venezuelan government. Harvest Vinccler began the year with average oil deliveries of 29,000 barrels of oil per day (“Bopd”) and is currently averaging about 22,000 Bopd. Natural gas deliveries at the beginning of the year were averaging 79 million cubic feet a day (MMCFpd), and are currently averaging about 56 MMCFpd. The decline is due to PDVSA’s refusal to allow us to carry out our drilling and facilities program for 2005 and the natural decline of the field. In August 2005, we submitted a proposed 2006 work program and budget to PDVSA which, under circumstances where we have reasonable assurances that PDVSA will adhere to the provisions of our operating service agreement, would enable Harvest Vinccler to increase deliveries through an accelerated drilling program. Under the terms of our existing operating service agreement, Harvest Vinccler’s 2006 work program and budget were deemed approved in October 2005. There are discussions on going between Harvest Vinccler and PDVSA on the terms for commencing the 2006 program. Without the ability to drill new wells, crude oil and natural gas volumes will continue to decline.
     Crude oil volumes for 2005 were also affected by PDVSA’s curtailment of our crude oil deliveries during the first part of the year. PDVSA may curtail us again in the future.
Future Payments to Harvest Vinccler may be adversely affected by actions of the Venezuelan government.Harvest Vinccler was paid 28 days late for deliveries in the first quarter of 2005. In addition, the payment was paid 50 percent in Bolivars, notwithstanding the provisions of the operating service agreement which requires all payments to be in U.S. Dollars. Subsequent 2005 quarterly payments for oil and natural gas sales were paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar; however, at 25 percent Bolivar payment levels, Harvest Vinccler projects that it will be able to utilize its Bolivars to meet local obligations.
     At the direction of MEP, PDVSA imposed a limit on our maximum total fee equal to two-thirds of the total value of the crude oil delivered to PDVSA beginning January 1, 2005. This caused an underpayment to Harvest Vinccler for deliveries in the first quarter of 2005. In August 2005, Harvest Vinccler signed the Transitory Agreement with PDVSA which included a two-thirds limit on fees, and PDVSA paid the underpaid amount to the extent of that limit.

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     Harvest Vinccler has been paid for oil and natural gas deliveries made through December 31, 2005 and expects to be paid for first quarter 2006 deliveries. Venezuela has not indicated how it intends to pay for deliveries after March 31, 2006, as it has stated that all operating service agreements must be converted to mixed companies by that date.
     Failure or refusal of PDVSA to pay Harvest Vinccler’s services fees, significant underpayment or withholding of fees, substantial payments by PDVSA in Bolivars, or the inability to convert the Bolivars into U.S. Dollars could, individually or in the aggregate, have a further material adverse effect on our financial position, results of operations and cash flows.
Actions by SENIAT to collect claimed back taxes could threaten the viability of our Venezuelan operations.In 2005, the Venezuelan income tax authority (the “SENIAT”) announced that the income tax rate paid by companies with operating service agreements would be retroactively increased from 34 percent to 67 percent for 2001 and from 34 percent to 50 percent for all years thereafter. The SENIAT completed a tax audit of Harvest Vinccler for the tax years 2001 through 2004, and in July 2005, the SENIAT issued a preliminary tax assessment of 184 billion Bolivars or approximately $85 million at the current exchange rate. In addition, the SENIAT imposed penalties equal to 10 percent of the preliminary tax assessment. A significant part of the preliminary tax assessment received relates to the retroactive increase in taxes above the existing rate of 34 percent. The assessment also relates to the disallowance of some deductions and attribution of additional income. Upon review of the preliminary tax assessment, and after discussions with officials in the SENIAT, Harvest Vinccler determined not to contest two elements of the preliminary tax assessment and made payments totaling $5.3 million. In September and October 2005, Harvest Vinccler filed an answer and evidentiary support with the SENIAT contesting all other elements of the preliminary tax assessment. The SENIAT and Harvest Vinccler have formed a working group to review the tax assessment for possible resolution of these claims.
     The SENIAT has up to one year to consider Harvest Vinccler’s answer and to determine whether, or to what extent, to issue a final tax assessment. A final tax assessment by the SENIAT may also include additional penalties between 25 percent and 200 percent of the unpaid tax. We are advised that the average penalty imposed by the SENIAT historically has been 112.5 percent of the unpaid tax unless extenuating or aggravating circumstances apply. If a final tax assessment is issued, Harvest Vinccler may file a further administrative appeal with the SENIAT. During the period of review by the SENIAT, any payment obligation is suspended. However, during this period the SENIAT may seek a court order allowing it to take precautionary measures such as attaching assets. After exhausting administrative appeals, Harvest Vinccler may either pay the tax or file a judicial appeal. If a judicial appeal is filed, the payment obligation may be suspended at the discretion of the court. While there are no established rules regarding payment suspension, we understand it is often granted only if the taxpayer posts a bond or other security equal to 210 percent of the final tax assessment. In the event we initiate an international arbitration, we may also seek to include the tax assessment as part of that proceeding.
     The SENIAT may also be considering additional tax audits of operating companies such as Harvest Vinccler. Despite a four year statute of limitations on tax claims, in January 2006, the head of the SENIAT stated consideration was being given to extending the audits back to 1993.
     At the current level of the tax assessment and considering possible interest and penalties, attachment of assets by the SENIAT, a determination of the need to take a charge against Harvest Vinccler’s earnings for the tax liability or a requirement to pay the taxes or post security will have a material adverse effect on Harvest Vinccler’s financial condition. A requirement to pay taxes, interest and penalties may exceed Harvest Vinccler’s cash balance. To the extent such events would cause the liabilities of Harvest Vinccler to exceed its assets, Harvest Vinccler would be insolvent. In addition, the implementation of a 50 percent tax rate or other changes in the interpretation or application of the tax laws, without compensating values, will have a material adverse effect on Harvest Vinccler’s financial position, results of operations or cash flows. We believe that these actions would not impact the cash or cash equivalent position of Harvest Natural Resources, Inc. or its other subsidiaries, which totaled $140.0 million at December 31, 2005.

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     We believe Harvest Vinccler has met its tax obligations in all material respects. We intend to take all measures necessary to protect Harvest Vinccler’s rights, and will vigorously challenge all elements of any tax assessment that are not supported by Venezuelan law.
The actions of the Venezuelan government may cause us to file for international arbitration. As a result of the actions taken by PDVSA, MEP and the SENIAT, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank. An arbitration proceeding may take a number of years to conclude and we can provide no assurances as to outcome. It is uncertain how the Venezuelan government might react to an arbitration filing, but it is possible it could lead to a shut down of Harvest Vinccler’s operations.
Harvest Vinccler may not be able to reach agreement on the terms of a mixed company and there is a risk any agreement will not receive the necessary approvals.We remain hopeful of reaching a mutually acceptable agreement with the government of Venezuela on converting the operating service agreement to a mixed company while preserving the value of our investment in Harvest Vinccler. We are actively engaged in discussions with government representatives and believe progress has been made. However, significant issues remain and it is not possible to give any assurances as to outcome. In addition, any agreement with PDVSA will require the approval of the Venezuelan National Assembly and of our shareholders. While no assurance can be provided, we believe these approvals would be obtained for any agreement supported by PDVSA, MEP, the SENIAT and us.
Our strategy to focus on Russia and other countries perceived to be politically challenging carries deal execution, operating, financial, legal and political risks.While we believe our established presence in countries perceived to be politically challenging and our experience and skills from prior operations position us well for future projects, doing business in Russia and other countries perceived to be politically challenging 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 local partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, 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 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 focus on countries perceived to be politically challenging limits our 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 countries perceived to be politically challenging 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 has been 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 service fee payments from PDVSA for all revenue receipts. We do not own the hydrocarbons and do not sell oil and natural 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 has been considered a highly inflationary economy. Results of operations in highly inflationary countries 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 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 Bolivars. Most of our operating and capital expenditures are in U.S. Dollars. For a discussion of currency controls in Venezuela, seeCapital Resources and LiquidityunderItem 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.Successful acquisition of projects in any international country 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 $24.02 per Bbl for the year ended December 31, 2005, compared with $18.90 per Bbl for the year ended December 31, 2004. 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;
•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.
Lower oil and natural gas prices or downward adjustments to 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 natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural 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 natural 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 that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we

16

experience substantial downward adjustments to our estimated proved reserves. We did not incur ceiling test write-downs in 2005 in the consolidated financial statements of the wholly-owned and majority owned subsidiaries. While our proved reserves were reduced by our Contractually Restricted Reserves as well as other revisions, this did not cause a ceiling limitation write down. 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 ended September 30, 2003.
Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. As a result of the actions of the Venezuelan Government, our Contractually Restricted Reserves have been excluded from our proved reserves. SeeItem 1 – Business, Operations.
     The process of estimating oil and natural gas reserves is complex. Such process requires 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. 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, the conversion of Harvest Vinccler’s interests to a mixed company in which it is a minority interest owner, 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.
     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 of oil and natural gas properties will affect the timing of actual future net cash flows from estimated proved reserves and their present value. In addition, the 10 percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with the oil and natural gas industry in general will affect the accuracy of the 10 percent discount factor.
We may not be able to replace production with new reserves. In general, production rates and remaining reserves from oil and natural gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. Our reserves in the South Monagas Unit in Venezuela will decline as they are produced unless we are able to include Contractually Restricted Reserves, 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 level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive and uncertain. We may be unable to make the necessary capital investment to maintain or expand our oil and natural gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot assure you that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.
Our operations are subject to numerous risks of oil and natural gas drilling and production activities.Oil and natural gas 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:

17

•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;
•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 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, 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.
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 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.
Item 1B. Unresolved Staff Comments
     None
Item 2. Properties

     In July 2001,April 2004, we leasedsigned a ten-year lease for office space in Houston, Texas, for three years for approximately $11,000$17,000 per month. We lease 17,500 square feet of space in a California building that we no longer occupy under a lease agreement that expires in December 2004. We have subleased all of theAlso during 2004, Harvest Vinccler leased office space in CaliforniaMaturin and Caracas, Venezuela for rents that approximate$13,200 and $4,000 per month, respectively. See alsoItem 1 – Business for a description of our lease costs.oil and natural gas properties and reserves.

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Item 3. Legal Proceedings

Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-Vinccler,Harvest 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. We dispute Excel’s claims and plan to vigorously defend against them.
Uracoa Municipality Tax Assessments. In July 2004, Harvest Vinccler received three tax 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. Harvest Vinccler has filed a motion with the tax court in Barcelona, Venezuela, seeking to enjoin the payment order and dismiss the assessment. We dispute all of the tax assessments and believe we have a substantial basis for our positions.
The SENIAT Tax Assessment. On July 22, 2005, the SENIAT, the Venezuelan income tax authority, issued a preliminary tax assessment to Harvest Vinccler of 184 billion Venezuelan Bolivars related to fiscal years 2001 through 2004. At the official exchange rate of 2,150 Bolivars per U.S. Dollar, the dollar equivalent of the preliminary tax assessment is approximately $85 million. In addition, the SENIAT imposed penalties equal to 10 percent of the preliminary tax assessment claim for a total claim of 202 billion Bolivars, or approximately $94 million. Upon review of the preliminary tax assessment, we determined not to contest two elements of the claim and made payments totaling 11.3 billion Bolivars or $5.3 million in August and September, 2005. In September and October 2005, we filed a response and evidentiary support with the SENIAT contesting all other claims. We believe Harvest Vinccler has met its tax obligations in all material respects. We intend to take all measures necessary to protect our rights, and will vigorously challenge all elements of the tax assessment that are not supported by Venezuelan law.
International Arbitration. As a result of the actions taken by PDVSA, MEP and the SENIAT, in July 2005, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank.

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

     None.

          None.

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PART IIRisk Factors
     Currently, the production from the South Monagas Unit represents all of our production. This production may be reduced in the future 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 inItem 1A – Risk Factors andItem 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

6

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, 2005, proved reserves attributable to our Venezuelan operations were 45 MMBoe (36 MMBoe net to Harvest). This represented 100 percent of our proved reserves at year end. The 2005 reserve information does not include Contractually Restricted Reserves. SeeItem 5.1 – Business, Operations.Harvest Vinccler has been primarily developing the Oficina sands in the Uracoa Field. The Uracoa Field contains 73 percent of the South Monagas Unit’s proved reserves.
Drilling and Development Activity
     Harvest Vinccler drilled one well and had 108 wells on production in all fields at year end 2005 in the South Monagas Unit.
Uracoa Field
     Harvest Vinccler has been developing the South Monagas Unit since 1992, beginning with the Uracoa Field. There are currently 80 oil and natural gas producing wells in the field.
     Harvest Vinccler processes the oil, water and natural gas in the Uracoa central processing unit and transports 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 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 to PDVSA pursuant to an amendment to the operating service agreement. 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 storage of up to 75 MBbls of crude oil. All natural gas presently being sold by Harvest Vinccler is produced from the Uracoa Field.
Tucupita Field
     There are currently 24 oil producing wells and five water injection wells at Tucupita. The Tucupita production facility has capacity to process 30 MBbls of oil per day, 125 MBbls of water per day and storage for up to 60 MBbls of crude oil. The oil is transported through a 31-mile, 20 MBbls per day capacity oil pipeline from Tucupita 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 Field was drilled in 1992, and production from the wells was halted until the produced natural gas could be sold. There are currently four oil producing wells in the West Bombal Field. The fluid 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 this field has been postponed due to the refusal of PDVSA and MEP to process and grant necessary permits. SeeItem 1 — BusinessandItem 1A – Risk Factors. Natural gas from this field was intended to be used to supplement natural gas sales from Uracoa as production there declines.
Customers and Market Information
     Under the operating service agreement, all oil and natural gas produced is delivered to PDVSA for Registrant’s Common Equitya fee. While we have substantial cash reserves, a prolonged loss of sales could have a material adverse effect on our financial condition.

7

Employees and Related Stockholder Matters

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

          Our Common StockCommunity Relations

     Harvest Vinccler has a highly skilled staff of 252 local employees and one expatriate. Harvest Vinccler has invested in a Social Community Program that includes medical programs in ophthalmologic and dental care, as well as additional social investments including 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 tradedan 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 programs and the training and implementation of a comprehensive Process Safety Management System.
North Gubkinskoye and South Tarasovskoye, Russia (Geoilbent)
     In September 2003, we sold our 34 percent minority equity investment in Geoilbent to Yukos Operational Holding Limited for $69.5 million plus $5.5 million for the repayment of intercompany loans and accounts receivable. SeeNote 7 – 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 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 area under dispute.
Location and Geology
     The WAB-21 contract area is located in the West Wan’an Basin (Nam Con Son) on the New York Stock Exchange (“NYSE”) underSouth China Sea. Its western edge lies approximately 50 miles southeast of the symbol “HNR”.Dai Hung (Big Bear) Oil Field, which recently discovered additional oil reserves in deeper Miocene zones. The block is adjacent to the east of British Petroleum’s giant natural gas discoveries at Lan Tay and Lan Do, which are estimated to contain two trillion cubic feet of natural gas. It is also adjacent to the 2005 Thien Ung discovery which tested oil and natural gas. The contract area covers several similar structural trends involving similar geological formations, each with potential for hydrocarbon reserves in possible multiple pay zones.
Drilling and Development Activity
     Due to the border dispute between China and Vietnam, we have been unable to pursue an exploration program during phase one of the contract. As a result, we have obtained license extensions, with the current extension in effect until May 31, 2007. While no assurance can be given, we believe we will continue to receive license extensions so long as the border disputes persist.

8

Activities by Area
     The following table summarizes our consolidated activities by area.
                     
      Other  Total       
(in thousands) Venezuela  Foreign  Foreign  United States  Total 
Year ended December 31, 2005
                    
Oil and natural gas sales $236,941   —  $236,941   —  $236,941 
Total Assets $258,268  $317  $258,585  $142,213  $400,798 
                     
Year ended December 31, 2004
                    
Oil and natural 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 natural gas sales $106,095   —  $106,095   —  $106,095 
Total Assets $241,855  $237  $242,092  $132,256  $374,348 
Reserves
     Estimates of our proved reserves as of December 31, 2003, there2005 and 2004 were 35,674,660 shares of common stock outstanding, with approximately 808 stockholders of record.prepared by Ryder Scott Company, L.P., independent petroleum engineers. The following table sets forth information regarding estimates of proved reserves at December 31, 2005, which are all in Venezuela. The information includes reserve information net of a 20 percent deduction for the highminority interest in Harvest Vinccler. All reserves are attributable to an operating service agreement between Harvest Vinccler and lowPDVSA under which all mineral rights are owned by the Government of Venezuela. The Ryder Scott report states: “The reserve report is prepared following SEC’s definitions and guidelines. One specific guideline is the estimation of proved reserves requires a demonstration with reasonable certainty that the proved reserves are recoverable in future years under existing economic and operating conditions. This year’s report does not include reserves in the proved undeveloped category due solely to the uncertainty in future capital spending by Harvest Vinccler C.A. to drill and develop this category of reserves is a result of the actions and statements of the Venezuelan authorities during the year 2005.” (For management’s discussion of the reserve reduction, seeItem 1 – Business, Operationsabove.) A detailed reconciliation of proved reserves and values can be found on Table IV and Table V of the Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) under Item 15.
Venezuela
Net Crude Oil and Condensate (MBbls) – Proved28,249
Net Natural Gas (MMcf) – Proved47,134
     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;
•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; and
•assumptions concerning contractual rights to develop reserves and whether those rights will be honored.
     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.

9

     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, contracting policies, taxation or other policies;
•contract sanctity; 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 of oil and natural gas properties. The 10 percent discount factor required by the SEC to be used to calculate present value for reporting purposes is not necessarily the most appropriate discount factor based on interest rates in effect from time to time, risks associated with the oil and natural gas industry and the political risks associated with operations in Venezuela. Discounted present value, regardless of what discount rate is used, is materially affected by assumptions as to the amount and timing of future production, which assumptions may, and often do, prove to be inaccurate. For the period ending December 31, 2005, we reported $412 million ($329 million net to us) of discounted future net cash flows from proved reserves based on the SEC’s required calculations.
Production, Prices and Lifting Cost Summary
     In the following table we have set forth, by country, our net production, average sales prices for our Common Stock reported by the NYSE.
           
Year
 Quarter
 High
 Low
2002
          
  First quarter  4.03   1.43 
  Second quarter  5.00   3.77 
  Third quarter  5.43   3.21 
  Fourth quarter  7.54   5.50 
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 

          On March 1, 2004, the last sales priceand average operating expenses for the common stock as reported by the NYSE was $11.68 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 and our indenture currently restricts the declaration and payment of any cash dividends.

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, 2005, 2004 and 2003. The selected consolidated financial data havepresentation for Venezuela includes 100 percent of the production, without deduction for minority interest. Geoilbent (34 percent ownership), which is accounted for under the equity method, has been derived from and should be readincluded at its ownership interest in conjunction with our annual auditedthe 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-monthfiscal period ending September 30. Accordingly,30 and, accordingly, our results of operations for the years ended December 31, 2003, 2002, 2001, 20002005, 2004 and 19992003 reflect results from Geoilbent (untiluntil it was sold on September 25, 2003) for the twelve months ended September 30, 2002, 2001, 2000 and 1999, and from Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2001, 2000 and 1999.

2003.
             
  Year Ended December 31, 
  2005  2004  2003 
Venezuela(a)
            
Crude Oil Production (Bbls)  8,762,687   8,152,261   7,347,399 
Natural Gas Production (Mcf)  25,677,460   31,059,416   2,660,241 
Average Crude Oil Sales Price ($per Bbl)(b) $24.02  $18.90  $14.07 
Average Natural Gas Sales Price ($  per Mcf) $1.03  $1.03  $1.03 
Average Operating Expenses ($  per Boe) $3.05  $2.50  $4.00 
Russia
            
Geoilbent(c)(d)
            
Net Crude Oil Production (Bbls)  (d)  (d)  1,913,187 
Average Crude Oil Sales price ($per Bbl)  (d)  (d) $14.52 
Average Operating Expenses ($per Bbl)  (d)  (d) $2.83 
(a)Information represents 100 percent of production.
(b)Average crude oil sales price after hedging activity.
(c)Information represents our ownership interest.
(d)Geoilbent was sold on September 25, 2003.

1510

                     
  Year Ended December 31,
  2003
 2002
 2001
 2000
 1999
  (in thousands, except per share data)
Statement of Operations:
                    
Total revenues $106,095  $126,731  $122,386  $140,284  $89,060 
Operating income (loss)  33,627   34,585   28,201   53,204   (22,525)
Net income (loss)  27,303   100,362   43,237   20,488   (32,284)
Net income (loss) per common share:                    
Basic $0.77  $2.90  $1.27  $0.67  $(1.09)
   
 		   
 		   
 		   
 		   
 		 
Diluted $0.74  $2.78  $1.27  $0.66  $(1.09)
   
 		   
 		   
 		   
 		   
 		 
Weighted average common shares outstanding Basic  35,332   34,637   33,937   30,724   29,577 
Diluted  36,840   36,130   34,008   30,890   29,577 
Regulation
                     
  Year Ended December 31,
  2003
 2002
 2001
 2000
 1999
          (in thousands)        
Balance Sheet Data:
                    
Working capital (deficit) $137,210  $97,001  $(586) $12,370  $32,093 
Total assets  374,348   335,192   348,151   286,447   276,311 
Long-term debt, net of current maturities  96,833   104,700   221,583   213,000   264,575 
Stockholders’ equity (deficit)(1)
  199,713   171,317   67,623   12,904   (17,178)
General
     Our operations are affected by political developments and laws and regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are affected by:
•change in governments;
•civil unrest;
•price and currency controls;
•limitations on oil and natural gas production;
•tax, environmental, safety and other laws relating to the petroleum industry;
•changes in laws relating to the petroleum industry;
•changes in administrative regulations and the interpretation and application of such rules and regulations; and
•changes in contract interpretation and policies of contract adherence.
     In any country in which we may do business, the oil and natural gas industry legislation and agency regulation are periodically changed for a variety of political, economic, environmental and other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business.
Venezuela
     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. Oil companies such as Harvest Vinccler are allowed to receive payments for oil and natural gas sales in U.S. Dollars and pay U.S. Dollar-denominated expenses from those payments. Notwithstanding the contractual provisions of our operating service agreement which requires all payments to be in U.S. Dollars, PDVSA paid 50 percent of 2005 first quarter oil and natural gas sales in Bolivars. Subsequent quarterly payments for 2005 were paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar, but Harvest Vinccler projects that it will be able to utilize its Bolivars to meet local obligations. 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 2004 or 2005. 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. During 2005 and continuing into 2006, PDVSA and MEP have refused to approve or issue permits and, as a result, Harvest Vinccler suspended its drilling and facilities program in 2005. 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) $9.0 million, $39.2 million and $58.3 million in 2005, 2004 and 2003, respectively. Included in these numbers is $8.9 million, $33.5 million and $43.6 million for the development of proved undeveloped reserves in 2005, 2004 and 2003, respectively.

11

     We have participated in the drilling of wells as follows:
                         
  Year Ended December 31,
  2005 2004 2003
  Gross Net Gross Net Gross Net
Wells Drilled:
                        
Development:                        
Crude oil  1   0.8   16   12.8   3   2.4 
                         
Average Depth of Wells (Feet)
  —   4,349   —   5,443   —   6,095 
                         
Producing Wells(1):
                        
Crude Oil  108   86.4   124   99.2   111   88.8 
(1) No cash dividends were declared or paid during the periods presented.The information related to producing wells reflects wells we drilled, wells we participated in drilling and producing wells we acquired.
     All of our drilling activities are conducted on a contract basis with independent drilling contractors. We do not directly operate any drilling equipment.
Acreage
     The following table summarizes the developed and undeveloped acreage that we owned, leased or held under operating service agreement or concession as of December 31, 2005:
                 
  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 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, 2005, our Houston office had 15 full-time employees. Harvest Vinccler had 252 employees and our Moscow office had 10 employees. We augment our staffs from time to time with independent consultants, as required.

12

Title to Developed and Undeveloped Acreage
     All Venezuelan reserves are attributable to an operating service agreement between Harvest Vinccler and PDVSA, under which all mineral rights are owned by the Government of Venezuela.
     The WAB-21 petroleum contract lies within an area which is the subject of a border 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 area under 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.

Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 1A. 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 concentration of assetsinterests in Venezuela increasesmay be unlawfully expropriated by the Venezuelan government.All of our exposure to production disruptions and project execution risk.Political and economic uncertainty is very high in Venezuela. Currently, the productionoperating revenues are derived from Harvest Vinccler through its operations of the South Monagas Unit under the operating service agreement with PDVSA. The government of Venezuela has announced that all operating service agreements will cease to exist in 2006 and that operations under those agreements will be converted to mixed companies in which PDVSA has a controlling interest. The government has stated that it will reclaim the interests of operators who do not convert to a mixed company. While we are engaged in good faith negotiations with MEP and PDVSA for the conversion of Harvest Vinccler’s operating service agreement to a mixed company, there is no assurance that a conversion will be possible under acceptable terms. Based upon the government’s statements and actions, there is a risk that if Harvest Vinccler is unable to agree with Venezuela represents allon the terms of a mixed company, its interests may be unlawfully expropriated or actions may be taken to prevent or render impossible continued operations. Expropriatory acts by Venezuela would likely cause us to seek international arbitration for the loss of our investment.
Our only source of production may be reduced further by actions of the Venezuelan government. Harvest Vinccler began the year with average oil deliveries of 29,000 barrels of oil per day (“Bopd”) and revenueis currently averaging about 22,000 Bopd. Natural gas deliveries at the beginning of the year were averaging 79 million cubic feet a day (MMCFpd), and cash floware currently averaging about 56 MMCFpd. The decline is due to PDVSA’s refusal to allow us to carry out our drilling and facilities program for 2005 and the natural decline of the field. In August 2005, we submitted a proposed 2006 work program and budget to PDVSA which, under circumstances where we have reasonable assurances that PDVSA will adhere to the provisions of our operating service agreement, would enable Harvest Vinccler to increase deliveries through an accelerated drilling program. Under the terms of our existing operating service agreement, Harvest Vinccler’s 2006 work program and budget were deemed approved in October 2005. There are discussions on going between Harvest Vinccler and PDVSA on the terms for commencing the 2006 program. Without the ability to drill new wells, crude oil and natural gas volumes will continue to decline.
     Crude oil volumes for 2005 were also affected by PDVSA’s curtailment of our crude oil deliveries during the first part of the year. PDVSA may curtail us again in the future.
Future Payments to Harvest Vinccler may be adversely affected if production from the South Monagas Unit decreases significantly for any reason. From December 14, 2002 through February 6, 2003, no sales were made because of PDVSA’s inability to accept our oil due to the national civil work stoppage in Venezuela. As a result, 2002 sales were reduced by approximately 0.6 million barrels and 2003 sales were reduced by an estimated 1.2 million barrels. As a resultactions of the Venezuelan national civil work stoppage,government.Harvest Vinccler was paid 28 days late for deliveries in the Venezuelan government terminated several thousand PDVSA employees and announced a restructuringfirst quarter of PDVSA’s operations. Throughout 2003, there have been numerous organizational changes2005. In addition, the payment was paid 50 percent in PDVSA. As a resultBolivars, notwithstanding the provisions of the situationoperating service agreement which requires all payments to be in U.S. Dollars. Subsequent 2005 quarterly payments for oil and natural gas sales were paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar; however, at 25 percent Bolivar payment levels, Harvest Vinccler projects that it will be able to utilize its Bolivars to meet local obligations.
     At the direction of MEP, PDVSA its paymentimposed a limit on our maximum total fee equal to Benton-Vinccler fortwo-thirds of the total value of the crude oil delivered to PDVSA beginning January 1, 2005. This caused an underpayment to Harvest Vinccler for deliveries in the fourthfirst quarter of 2002 was late by seven days. However, all other payments have been2005. In August 2005, Harvest Vinccler signed the Transitory Agreement with PDVSA which included a two-thirds limit on time,fees, and we believe PDVSA is committedpaid the underpaid amount to building its production levels and returning to more normalized business relations with its customers and suppliers.

          There are ongoing efforts by opponentsthe extent of President Chavez for a constitutional recall referendum. A successful recall referendum could lead to new presidential elections. These events create civil unrest and the possibility of work stoppages or disruptions. The political uncertainty and economic instability in Venezuela could adversely affect our operations and business prospects in that country. In addition, while the effect of the changes and the possible politicalization of PDVSA cannot be predicted, it could adversely affect PDVSA’s ability to manage its contracts and meet its obligations with its suppliers and vendors, such as Benton-Vinccler. Organizational instability and uncertainty at PDVSA could also adversely affect our ability to acquire new projects in Venezuela and the timing of those acquisitions. While we have substantial cash reserves to withstand a future

limit.

1613

disruption

     Harvest Vinccler has been paid for oil and natural gas deliveries made through December 31, 2005 and expects to be paid for first quarter 2006 deliveries. Venezuela has not indicated how it intends to pay for deliveries after March 31, 2006, as it has stated that all operating service agreements must be converted to mixed companies by that date.
     Failure or refusal of sales, a prolonged loss of sales or a failure or delay by PDVSA to pay Harvest Vinccler’s services fees, significant underpayment or withholding of fees, substantial payments by PDVSA in Bolivars, or the inability to convert the Bolivars into U.S. Dollars could, individually or in the aggregate, have a further material adverse effect on our invoicesfinancial position, results of operations and cash flows.
Actions by SENIAT to collect claimed back taxes could threaten the viability of our Venezuelan operations.In 2005, the Venezuelan income tax authority (the “SENIAT”) announced that the income tax rate paid by companies with operating service agreements would be retroactively increased from 34 percent to 67 percent for 2001 and from 34 percent to 50 percent for all years thereafter. The SENIAT completed a tax audit of Harvest Vinccler for the tax years 2001 through 2004, and in July 2005, the SENIAT issued a preliminary tax assessment of 184 billion Bolivars or approximately $85 million at the current exchange rate. In addition, the SENIAT imposed penalties equal to 10 percent of the preliminary tax assessment. A significant part of the preliminary tax assessment received relates to the retroactive increase in taxes above the existing rate of 34 percent. The assessment also relates to the disallowance of some deductions and attribution of additional income. Upon review of the preliminary tax assessment, and after discussions with officials in the SENIAT, Harvest Vinccler determined not to contest two elements of the preliminary tax assessment and made payments totaling $5.3 million. In September and October 2005, Harvest Vinccler filed an answer and evidentiary support with the SENIAT contesting all other elements of the preliminary tax assessment. The SENIAT and Harvest Vinccler have formed a working group to review the tax assessment for possible resolution of these claims.
     The SENIAT has up to one year to consider Harvest Vinccler’s answer and to determine whether, or to what extent, to issue a final tax assessment. A final tax assessment by the SENIAT may also include additional penalties between 25 percent and 200 percent of the unpaid tax. We are advised that the average penalty imposed by the SENIAT historically has been 112.5 percent of the unpaid tax unless extenuating or aggravating circumstances apply. If a final tax assessment is issued, Harvest Vinccler may file a further administrative appeal with the SENIAT. During the period of review by the SENIAT, any payment obligation is suspended. However, during this period the SENIAT may seek a court order allowing it to take precautionary measures such as attaching assets. After exhausting administrative appeals, Harvest Vinccler may either pay the tax or file a judicial appeal. If a judicial appeal is filed, the payment obligation may be suspended at the discretion of the court. While there are no established rules regarding payment suspension, we understand it is often granted only if the taxpayer posts a bond or other security equal to 210 percent of the final tax assessment. In the event we initiate an international arbitration, we may also seek to include the tax assessment as part of that proceeding.
     The SENIAT may also be considering additional tax audits of operating companies such as Harvest Vinccler. Despite a four year statute of limitations on tax claims, in January 2006, the head of the SENIAT stated consideration was being given to extending the audits back to 1993.
     At the current level of the tax assessment and considering possible interest and penalties, attachment of assets by the SENIAT, a determination of the need to take a charge against Harvest Vinccler’s earnings for the tax liability or a requirement to pay the taxes or post security will have a material adverse effect on ourHarvest Vinccler’s financial condition. A requirement to pay taxes, interest and penalties may exceed Harvest Vinccler’s cash balance. To the extent such events would cause the liabilities of Harvest Vinccler to exceed its assets, Harvest Vinccler would be insolvent. In addition, the implementation of a 50 percent tax rate or other changes in the interpretation or application of the tax laws, without compensating values, will have a material adverse effect on Harvest Vinccler’s financial position, results of operations or cash flows. We believe that these actions would not impact the cash or cash equivalent position of Harvest Natural Resources, Inc. or its other subsidiaries, which totaled $140.0 million at December 31, 2005.

14

     We havebelieve Harvest Vinccler has met its tax obligations in all material respects. We intend to take all measures necessary to protect Harvest Vinccler’s rights, and will vigorously challenge all elements of any tax assessment that are not supported by Venezuelan law.
The actions of the Venezuelan government may cause us to file for international arbitration. As a result of the actions taken by PDVSA, MEP and the SENIAT, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank. An arbitration proceeding may take a number of years to conclude and we can provide no assurances as to outcome. It is uncertain how the Venezuelan government might react to an arbitration filing, but it is possible it could lead to a shut down of Harvest Vinccler’s operations.
Harvest Vinccler may not be able to reach agreement on the terms of a mixed company and there is a risk any agreement will not receive the necessary approvals.We remain hopeful of reaching a mutually acceptable agreement with the government of Venezuela on converting the operating service agreement to a mixed company while preserving the value of our investment in Harvest Vinccler. We are actively engaged in discussions with government representatives and believe progress has been requiredmade. However, significant issues remain and it is not possible to curtail salesgive any assurances as to PDVSA in April and December 2002 due to insufficient crude oil storage capacity. While these appear to be isolated incidents, we cannot be assured that our sales tooutcome. In addition, any agreement with PDVSA will notrequire the approval of the Venezuelan National Assembly and of our shareholders. While no assurance can be curtailed inprovided, we believe these approvals would be obtained for any agreement supported by PDVSA, MEP, the future in the same manner.

SENIAT and us.

     Our strategy to focus on Russia and other countries perceived to be politically challenging carries deal execution, operating, financial, legal and political risk.risks.While we believe our established presence in Russiacountries perceived to be politically challenging and our experience and skills from prior operations positionsposition us well for future projects, doing business in Russia and other countries perceived to be politically challenging 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 Russianlocal partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for Russian projects, while remaining within our existing debt covenants.projects. In addition, the Russian legal system issystems of these countries are not mature and itstheir 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.

Acquiring new projects in Venezuela Our strategy depends uponon our ability to meethave operational and financial control. Recently, the requirements of the Organic Hydrocarbon Law.New oilRussian government has restricted certain “strategic” projects in Venezuela are governed by the Organic Hydrocarbon Law which requires that suchRussia to majority-owned Russia companies. Such a policy, if widely applied, could adversely affect our ability to acquire projects be carried out through incorporated joint venturesin Russia consistent with majority ownership by governmental entities. While we believe it is possible to comply with the Organic Hydrocarbons 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.

strategy.

     Operations in areas outside the U.S. are subject to various risks inherent in foreign operations, and our strategy to focus on Venezuela and Russiacountries perceived to be politically challenging 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 possibility of having to be subject to exclusive jurisdiction of courts in connection with legal disputes 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 andcountries perceived to be politically challenging increases the potential impact to us of the operating, financial and political risks in those countries.

Our foreign operations expose us to foreign currency risk.Presently, our only operations are located in Venezuela. Venezuela has historically been considered a highly inflationary economy. Results of operations in that country are measured in U.S. dollars, and 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 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. 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.

     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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Leverage materially affects our operations. As of December 31, 2003, our long-term debt was $96.8 million. Our long-term debt represented 33 percent of our total capitalization at December 31, 2003. Our current

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cash balances are in excess of these obligations and lessen the impact of our debt but our long-term debt can effect our operations in several important ways, including the following:

•a significant portion of our cash flow from operations is used to pay interest on borrowings;
•our single largest indebtedness of $85 million is due in November 2007;
•the covenants contained in the indentures governing such debt limits our ability to borrow additional funds or to dispose of assets;
•the covenants contained in the indentures governing our debt affect our flexibility in planning for, and reacting to, changes in business conditions;
•the level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and
•the terms of the indentures governing our debt permit our creditors to accelerate payments upon an event of default or a change of control.

     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 has been and may be affected by numerous factors beyond our control.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 productionservice fee payments from PDVSA for all revenue receipts. We do not own the hydrocarbons and do not sell oil and natural 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 has been considered a highly inflationary economy. Results of operations in highly inflationary countries 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 may not be able to investhave recognized significant exchange gains and losses in the net cash proceedspast, resulting from fluctuations in the sale of Geoilbent in new oil and gas projects. The termsrelationship of the 2007 Notes requireBolivar 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 Bolivars. Most of our operating and capital expenditures are in U.S. Dollars. For a discussion of currency controls in Venezuela, seeCapital Resources and LiquidityunderItem 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.Successful acquisition of projects in any international country may also expose us to foreign currency risk in that net cash proceeds in excess of $25 million from the sale of Geoilbent must be invested in the oil and gas business within one year of the sale, or any amount not so invested must be used to repay or prepay the 2007 Notes or certain debts of subsidiaries.

country.

     Oil price declines and volatility could adversely affect our revenue, cash flows and profitabilityprofitability.. Prices for oil fluctuate widely. The average price we received for oil in Venezuela increased to $14.07$24.02 per Bbl for the year ended December 31, 2003,2005, compared to $13.08with $18.90 per Bbl for the year ended December 31, 2002.2004. 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 of and demand for oil;
 
 • market uncertainty;
 
 • the level of consumer product demand;
 
 • weather conditions;
 
 • domestic and foreign governmental regulations;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.

     Lower oil and natural gas prices or downward adjustments to 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 natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural 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,

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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 natural 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 that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we

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experience substantial downward adjustments to our estimated proved reserves. TheWe did not incur ceiling test write-downs in 2005 in the consolidated financial statements of the wholly-owned and majority owned subsidiaries dosubsidiaries. While our proved reserves were reduced by our Contractually Restricted Reserves as well as other revisions, this did not includecause a ceiling test write-downs in 2003.limitation write down. 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 endingended September 30, 2003.

     Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

As a result of the actions of the Venezuelan Government, our Contractually Restricted Reserves have been excluded from our proved reserves. SeeItem 1 – Business, Operations.

     The process of estimating oil and natural gas reserves is complex. Such process requires 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 most 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, the conversion of Harvest Vinccler’s interests to a mixed company in which it is a minority interest owner, 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, 2003, approximately 47 percent of our estimated Proved Reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. 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 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 our risks or the risks associated with the oil and natural gas industry in general will affect the accuracy of the 10 percent discount factor.

     We may not be able to replace production with new reserves. In general, production rates and remaining reserves from oil and natural gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. Our reserves in the South Monagas Unit in Venezuela will decline as they are produced unless we are able to include Contractually Restricted Reserves, 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 level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive and uncertain. We may be unable to make the necessary capital investment to maintain or expand our oil and natural gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot assure you that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.

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     Our operations are subject to numerous risks of oil and natural gas drilling and production activities.Oil and natural gas 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:

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 • 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.lands; and
•government actions or changes in regulations.

     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, 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.

     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 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.

2003 Financial

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. Also during 2004, Harvest Vinccler leased office space in Maturin and Operational Performance

          In 2003, we strengthened our management teamCaracas, Venezuela for $13,200 and board of directors, added to our financial flexibility by completing the sale of Geoilbent$4,000 per month, respectively. See alsoItem 1 – Business for $69.5 million in cash plus $5.5 million for repaymenta description of our intercompany debt and accounts receivable, added a gas revenue stream and advanced our growth plan by announcing an agreement with PDVSA to study two oil and natural gas fields close to our facilities in Venezuela.

          At December 31, 2003, we had $138.7 million of cashproperties and a debt to total capitalization ratio of 33 percent compared with 38 percent at the end of 2002.reserves.

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          Our board of directors has authorized the repurchase of up to one million shares of our common stock. In March 2003 we repurchased approximately 80,000 shares for an aggregate price of $0.4 million.

2004 Capital Program

          Benton-Vinccler’s capital expenditures for 2004 are projected to be $30-35 million, compared with 2003 capital expenditures of $58.1 million. The 2004 capital program includes plans for ten wells in Proved Undeveloped Reserves

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, C.A., Gale Campbell and related facilities at Uracoa for approximately $18 million as well as the start of the engineering and design studies at East Bombal in anticipation of gas sales in 2005.

          In 2003, we completed our three well Bombal Field development program in Venezuela and constructed a pipeline from Bombal to the Tucupita delivery line. The Bombal drilling program delivered disappointing results. Instead of initial flush production with little or no water, the wells experienced early water breakthrough and consequently lower oil production. Benton-Vinccler converted two gas injection wells in Uracoa to gas production and completed the gas project and facilities improvements on time at a cost of $27 million.

Results of Operations

          We include the results of operations of Benton-Vinccler in our consolidated financial statements and reflect the 20 percent ownership interest of Vinccler as a minority interest. We accounted for our investments in Geoilbent and Arctic Gas using the equity method. We include Geoilbent and Arctic Gas in our consolidated financial statements based on a fiscal year ending September 30. Our results of operations for the years ended December 31, 2003, 2002 and 2001 reflect the results of Geoilbent (until sold on September 25, 2003) and Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2003, 2002 and 2001.

          You should read the following discussion of the results of operations for each of the yearsSheila Campbell in the three-year period ended December 31, 2003 and the financial condition as of December 31, 2003 and 2002 in conjunction with our Consolidated Financial Statements and related Notes thereto.

          We have presented selected expense items from our consolidated income statement as a percentage of revenue in the following table:

             
  Years Ended December 31,
  
  2003 2002 2001
  
 
 
Operating Expenses  29%  27%  35%
Depletion, Depreciation and Amortization  20   21   21 
General and Administrative  15   13   16 
Taxes Other Than on Income  3   3   4 
Interest  10   13   20 

Years ended December 31, 2003 and 2002

          Net incomeDistrict Court for the year ended 2003Harris County, Texas. This suit was $27.3 million, or $0.74 per diluted share, compared with $100.4 million for the year ended 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 A. E. Benton (SeeNote 13 – Related Party Transactions). Operating and general and administrative expenses were reduced by $3.8 million, or almost 8 percent, compared with 2002.

          Our results of operations for the year 2003 primarily reflected the results for Benton-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 the year ended 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.

          Our revenues decreased $20.6 million, or 16 percent, during the year ended 2003 compared with 2002. This was primarily due to lower production offset by higher world crude oil prices. Our sales quantities for the year ended

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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 due 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 the year ended 2003 compared with 2002. This was primarily due to lower production volumes partially offset by higher workover and maintenance programs that continued during the Venezuelan national civil work stoppage. Depletion, depreciation and amortization decreased $5.2 million, or 20 percent, during the year 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 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 the year ended 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 the year ended 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 A. E. Benton.

          Taxes other than on income decreased $0.7 million, or 17 percent, during the year ended 2003 compared with 2002. This was primarily due to decreased Venezuelan municipal taxes which are a function of oil revenues partially offset by a one-time adjustment of U.S. employment taxes of $0.7 million in 2002.

          Investment income and other decreased $0.7 million, or 32 percent, during the year ended 2003 compared with 2002. This was due to lower interest rates earned on average cash and marketable securities balances. Interest expense decreased $5.9 million, or 36 percent, during the year ended 2003 compared with 2002 due to lower average outstanding debt balances for the year ended 2003 compared to 2002. In 2002, we redeemed all $108 million of our 11.625 percent Senior Notes duebrought in May 2003 by Excel alleging, among other things, breach of a consulting agreement between Excel and purchased $20 million faceus, misappropriation of proprietary information and trade secrets, and fraud. Excel seeks actual and exemplary damages, injunctive relief and attorneys’ fees. In October 2003, the Court abated the suit pending final judgment of a case pending in Louisiana to which we are not a party. We dispute Excel’s claims and plan to vigorously defend against them.

Uracoa Municipality Tax Assessments. In July 2004, Harvest Vinccler received three tax assessments from a tax inspector for the Uracoa municipality in which part 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 fieldSouth Monagas Unit is located. A protest to the PDVSA sales line,assessments was filed with the municipality, and we repaid all Bolivar denominated debt in March 2003.

          Net gain on exchange rates decreased $4.0 million, or 88 percent, forSeptember 2004 the year ended 2003 compared with 2002. 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. We realized income before income taxes and minority interest of $71.8 million during the year 2003 compared with income of $169.8 million in the year ended 2002. The decrease was primarily attributable to the Arctic Gas Sale in 2002 offset by the sale of our minority 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 the year ended 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 interests decreased $47.4 million for the year ended 2003 compared with 2002. This decrease was due to the sale of our minority equity investment in Geoilbent partially offset by decreased production of Benton-Vinccler.

          Equity in net losses of affiliated companies decreased $29.0 million during the year 2003 from $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.

Years ended December 31, 2002 and 2001

          Net income for the year ended 2002 was $100.4 million, or $2.78 per diluted share, compared with $43.2 million for 2001. The $100.4 million net income included the after-tax gain from the Arctic Gas Sale of $93.6 million, and the pre-tax $3.3 million, partial recovery of a bad debt related to A. E. Benton (SeeNote 13 – Related Party Transactions); offset,inspector responded in part by a pre-tax $13.4 million impairmentaffirming one of the WAB-21 petroleum property locatedassessments and issuing a payment order. Harvest Vinccler has filed a motion with the tax court in Barcelona, Venezuela, seeking to enjoin the South China Sea. Operatingpayment order and general and administrative expenses were reduced by $12 million, or almost 20 percent, compared with 2001.

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          Our results of operations fordismiss the year ended 2002 primarily reflected the results for Benton-Vinccler in Venezuela, which accounted forassessment. We dispute all of the tax assessments and believe we have a substantial basis for our productionpositions.

The SENIAT Tax Assessment. On July 22, 2005, the SENIAT, the Venezuelan income tax authority, issued a preliminary tax assessment to Harvest Vinccler of 184 billion Venezuelan Bolivars related to fiscal years 2001 through 2004. At the official exchange rate of 2,150 Bolivars per U.S. Dollar, the dollar equivalent of the preliminary tax assessment is approximately $85 million. In addition, the SENIAT imposed penalties equal to 10 percent of the preliminary tax assessment claim for a total claim of 202 billion Bolivars, or approximately $94 million. Upon review of the preliminary tax assessment, we determined not to contest two elements of the claim and oil sales revenue.made payments totaling 11.3 billion Bolivars or $5.3 million in August and September, 2005. In September and October 2005, we filed a response and evidentiary support with the SENIAT contesting all other claims. We believe Harvest Vinccler has met its tax obligations in all material respects. We intend to take all measures necessary to protect our rights, and will vigorously challenge all elements of the tax assessment that are not supported by Venezuelan law.
International Arbitration. As a result of increases in world crude oil prices, partially offsetthe actions taken by lower production from the South Monagas Unit, oil sales in Venezuela were 3.8 percent higher in 2002 compared with 2001. Realized fees per barrel increased 4.5 percent (from $12.52 in 2001 to $13.08 in 2002).

          Our revenues increased $4.6 million, or 3.6 percent, during the year ended 2002 compared with 2001. This was due to increased oil sales revenue in Venezuela as a result of increases in world crude oil prices, partially offset by lower sales quantities. Our sales quantities for the year ended 2002 from Venezuela were 9.7 MMBbls compared to 9.8 MMBbls for the year ended 2001. The decrease in sales quantities of 100,000 Bbls, or less than 1 percent, was due primarily to logistics and equipment delays in early 2002 at the Tucupita fieldPDVSA, MEP and the SENIAT, in July 2005, we delivered formal notices to Venezuelan national civil work stoppage which led togovernment officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the shut-ingovernment of our production in late December 2002Venezuela. The bilateral investment treaties and Venezuelan law provide for nine days. Average productioninternational arbitration of investment disputes conducted through the International Centre for the year decreased by less than 775 Bbls per day for the aforementioned reasons.

          Our operating expenses decreased $8.8 million, or 21 percent, for the year ended 2002 compared with the year ended 2001. Lower fuel gas, water and oil treatments accounted for $3.4 millionSettlement of Investment Disputes of the reduction. Reduced workover expense ($2.6 million) and lower expenses associated with the transportationWorld Bank.

Item 4. Submission of Tucupita oil ($5.0 million) with the completionMatters to a Vote of the Tucupita oil pipeline in late 2001 were offset by $1.1 million of increases in various other categories. Depletion, depreciation and amortization increased $0.8 million, or 4 percent, during the year ended 2002 compared with 2001 primarily due to the first three quarters of 2002 having been calculated on the lower beginning of the year reserves. Depletion expense per barrel of oil produced from Venezuela during 2002 was $2.56 compared with $2.26 during 2001 primarily due to future development costs. We recognized write-downs of capitalized costs of $13.4 million associated with WAB-21 offshore China and $1.1 million for the Lakeside Prospect exploration activities during the year ended 2002 compared with $0.5 million associated with final costs associated with prior exploration activities. General and administrative expenses decreased $3.6 million from 2001 to 2002. The move to Houston was completed in 2001 and overall staff levels were reduced to the current level of ten in Houston. We recognized $3.3 million of income for the partial recovery of prior year bad debt allowance for the funds received from the A.E. Benton bankruptcy. The consideration includes 600,000 shares of stock taken into treasury at a price of $3.56 per share and approximately $1.1 million in cash.Security Holders
     None.

19

          Taxes other than on income decreased $1.3 million, or 24 percent, during the year ended 2002 compared with 2001. This was primarily due to decreased Venezuelan municipal taxes and a one-time adjustment of U.S. employment taxes of $0.7 million.

          Investment income and other decreased $1.0 million, or 33 percent, during the year ended 2002 compared with 2001. This was due to lower interest rates earned on average cash and marketable securities balances. Interest expense decreased $8.6 million, or 34 percent, during the year ended 2002 compared with 2001. We redeemed all $108 million 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.

          Net gain on exchange rates increased $3.8 million, or 493 percent for the year ended 2002 compared with 2001. This was due to the significant devaluation of the Bolivar. We realized income before income taxes and minority interest of $169.8 million during the year ended 2002 compared with $7.2 million in 2001. The increase was dominated by the Arctic Gas Sale. The 2001 income tax benefit related to the potential utilization by the Arctic Gas Sale of net operating loss carry forwards in 2002. Income tax expense decreased $105.0 million due to the reversal of a substantial portion of the valuation allowance on U.S. net operation loss carryforwards in 2001. The effective tax rate in 2002 of 36 percent reflects foreign income taxes incurred on profitable foreign operations and 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 interests increased $3.8 million for the year ended 2002 compared with 2001. This was primarily due to the increased profitability (oil prices) and reduced expenses of Benton-Vinccler.

          Equity in net earnings of affiliated companies decreased $5.7 million, during the year ended 2002 compared with 2001. This was primarily due to the decreased income from Geoilbent and the elimination of Arctic Gas equity income on April 12, 2002, the date of its sale.

23

Capital Resources and Liquidity

          The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks (see Risk Factors). We require capital principally to service our debt and to fund the following costs:

•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.

          The amount of available capital will affect the scope of our operations and the rate of our growth. We began selling Venezuelan natural gas in November 2003, but our future rate of 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 Benton-Vinccler are allowed to receive payments for oil sales in U.S. dollars and pay U.S. dollar-denominated expenses from those payments. The full amount of the Bolivar denominated debt was repaid as of March 31, 2003. As of March 1, 2004, we have cash reserves of approximately $156.0 million and do not expect the currency conversion restriction to adversely affect our ability to meet our short-term loan obligations.

          Our ability to pay interest on our debt and general corporate overhead is dependent upon the ability of Benton-Vinccler to make loan repayments, dividends and other cash payments to us. However, there have been, and may again be, unforeseeable interruptions in oil and gas sales or there may be contractual obligations or legal impediments such as the recently instituted currency controls to receiving dividends or distributions from Benton-Vinccler, which could prohibit Benton-Vinccler from remitting funds to us. Management does not believe that the currency controls will prohibit our ability to receive funds from Benton-Vinccler, although were it to do so, our ability to meet our cash requirements would be adversely affected.

Debt Reduction.We currently have a significant debt principal obligation payable in 2007 ($85 million). By September 24, 2004, we may be obligated to repay or prepay some portion of this debt with some of the net cash proceeds from the sale of Geoilbent (see

Risk Factors
     Currently, the production from the South Monagas Unit represents all of our production. This production may be reduced in the future 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 inItem 1A – Risk Factors andItem 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

6

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, 2005, proved reserves attributable to our Venezuelan operations were 45 MMBoe (36 MMBoe net to Harvest). This represented 100 percent of our proved reserves at year end. The 2005 reserve information does not include Contractually Restricted Reserves. SeeItem 1 – Business, Operations.Harvest Vinccler has been primarily developing the Oficina sands in the Uracoa Field. The Uracoa Field contains 73 percent of the South Monagas Unit’s proved reserves.
Drilling and Development Activity
     Harvest Vinccler drilled one well and had 108 wells on production in all fields at year end 2005 in the South Monagas Unit.
Uracoa Field
     Harvest Vinccler has been developing the South Monagas Unit since 1992, beginning with the Uracoa Field. There are currently 80 oil and natural gas producing wells in the field.
     Harvest Vinccler processes the oil, water and natural gas in the Uracoa central processing unit and transports 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 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 to PDVSA pursuant to an amendment to the operating service agreement. 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 storage of up to 75 MBbls of crude oil. All natural gas presently being sold by Harvest Vinccler is produced from the Uracoa Field.
Tucupita Field
     There are currently 24 oil producing wells and five water injection wells at Tucupita. The Tucupita production facility has capacity to process 30 MBbls of oil per day, 125 MBbls of water per day and storage for up to 60 MBbls of crude oil. The oil is transported through a 31-mile, 20 MBbls per day capacity oil pipeline from Tucupita 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 Field was drilled in 1992, and production from the wells was halted until the produced natural gas could be sold. There are currently four oil producing wells in the West Bombal Field. The fluid 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 this field has been postponed due to the refusal of PDVSA and MEP to process and grant necessary permits. SeeItem 1 — BusinessandItem 1A – Risk Factors. Natural gas from this field was intended to be used to supplement natural gas sales from Uracoa as production there declines.
Customers and Market Information
     Under the operating service agreement, all oil and natural gas produced is delivered to PDVSA for a fee. While we have substantial cash reserves, a prolonged loss of sales could have a material adverse effect on our financial condition.

7

Employees and Community Relations
     Harvest Vinccler has a highly skilled staff of 252 local employees and one expatriate. Harvest Vinccler has invested in a Social Community Program that includes medical programs in ophthalmologic and dental care, as well as additional social investments including 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 programs and the training and implementation of a comprehensive Process Safety Management System.
North Gubkinskoye and South Tarasovskoye, Russia (Geoilbent)
     In September 2003, we sold our 34 percent minority equity investment in Geoilbent to Yukos Operational Holding Limited for $69.5 million plus $5.5 million for the repayment of intercompany loans and accounts receivable. SeeNote 7 – 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 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 area under dispute.
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 50 miles southeast of the Dai Hung (Big Bear) Oil Field, which recently discovered additional oil reserves in deeper Miocene zones. The block is adjacent to the east of British Petroleum’s giant natural gas discoveries at Lan Tay and Lan Do, which are estimated to contain two trillion cubic feet of natural gas. It is also adjacent to the 2005 Thien Ung discovery which tested oil and natural gas. The contract area covers several similar structural trends involving similar geological formations, each with potential for hydrocarbon reserves in possible multiple pay zones.
Drilling and Development Activity
     Due to the border dispute between China and Vietnam, we have been unable to pursue an exploration program during phase one of the contract. As a result, we have obtained license extensions, with the current extension in effect until May 31, 2007. While no assurance can be given, we believe we will continue to receive license extensions so long as the border disputes persist.

8

Activities by Area
     The following table summarizes our consolidated activities by area.
                     
      Other  Total       
(in thousands) Venezuela  Foreign  Foreign  United States  Total 
Year ended December 31, 2005
                    
Oil and natural gas sales $236,941   —  $236,941   —  $236,941 
Total Assets $258,268  $317  $258,585  $142,213  $400,798 
                     
Year ended December 31, 2004
                    
Oil and natural 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 natural gas sales $106,095   —  $106,095   —  $106,095 
Total Assets $241,855  $237  $242,092  $132,256  $374,348 
Reserves
     Estimates of our proved reserves as of December 31, 2005 and 2004 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. The following table sets forth information regarding estimates of proved reserves at December 31, 2005, which are all in Venezuela. The information includes reserve information net of a 20 percent deduction for the minority interest in Harvest Vinccler. All reserves are attributable to an operating service agreement between Harvest Vinccler and PDVSA under which all mineral rights are owned by the Government of Venezuela. The Ryder Scott report states: “The reserve report is prepared following SEC’s definitions and guidelines. One specific guideline is the estimation of proved reserves requires a demonstration with reasonable certainty that the proved reserves are recoverable in future years under existing economic and operating conditions. This year’s report does not include reserves in the proved undeveloped category due solely to the uncertainty in future capital spending by Harvest Vinccler C.A. to drill and develop this category of reserves is a result of the actions and statements of the Venezuelan authorities during the year 2005.” (For management’s discussion of the reserve reduction, seeItem 1 – Business, Operationsabove.) A detailed reconciliation of proved reserves and values can be found on Table IV and Table V of the Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) under Item 15.
Venezuela
Net Crude Oil and Condensate (MBbls) – Proved28,249
Net Natural Gas (MMcf) – Proved47,134
     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;
•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; and
•assumptions concerning contractual rights to develop reserves and whether those rights will be honored.
     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.

9

     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, contracting policies, taxation or other policies;
•contract sanctity; 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 of oil and natural gas properties. The 10 percent discount factor required by the SEC to be used to calculate present value for reporting purposes is not necessarily the most appropriate discount factor based on interest rates in effect from time to time, risks associated with the oil and natural gas industry and the political risks associated with operations in Venezuela. Discounted present value, regardless of what discount rate is used, is materially affected by assumptions as to the amount and timing of future production, which assumptions may, and often do, prove to be inaccurate. For the period ending December 31, 2005, we reported $412 million ($329 million net to us) of discounted future net cash flows from proved reserves based on the SEC’s required calculations.
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, 2005, 2004 and 2003. The presentation for Venezuela includes 100 percent of the production, without deduction for minority interest. Geoilbent (34 percent ownership), which is accounted for under the equity method, has been included at its ownership interest in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, our results of operations for the years ended December 31, 2005, 2004 and 2003 reflect results from Geoilbent until it was sold on September 25, 2003.
             
  Year Ended December 31, 
  2005  2004  2003 
Venezuela(a)
            
Crude Oil Production (Bbls)  8,762,687   8,152,261   7,347,399 
Natural Gas Production (Mcf)  25,677,460   31,059,416   2,660,241 
Average Crude Oil Sales Price ($per Bbl)(b) $24.02  $18.90  $14.07 
Average Natural Gas Sales Price ($  per Mcf) $1.03  $1.03  $1.03 
Average Operating Expenses ($  per Boe) $3.05  $2.50  $4.00 
Russia
            
Geoilbent(c)(d)
            
Net Crude Oil Production (Bbls)  (d)  (d)  1,913,187 
Average Crude Oil Sales price ($per Bbl)  (d)  (d) $14.52 
Average Operating Expenses ($per Bbl)  (d)  (d) $2.83 
(a)Information represents 100 percent of production.
(b)Average crude oil sales price after hedging activity.
(c)Information represents our ownership interest.
(d)Geoilbent was sold on September 25, 2003.

10

Regulation
General
     Our operations are affected by political developments and laws and regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are affected by:
•change in governments;
•civil unrest;
•price and currency controls;
•limitations on oil and natural gas production;
•tax, environmental, safety and other laws relating to the petroleum industry;
•changes in laws relating to the petroleum industry;
•changes in administrative regulations and the interpretation and application of such rules and regulations; and
•changes in contract interpretation and policies of contract adherence.
     In any country in which we may do business, the oil and natural gas industry legislation and agency regulation are periodically changed for a variety of political, economic, environmental and other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business.
Venezuela
     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. Oil companies such as Harvest Vinccler are allowed to receive payments for oil and natural gas sales in U.S. Dollars and pay U.S. Dollar-denominated expenses from those payments. Notwithstanding the contractual provisions of our operating service agreement which requires all payments to be in U.S. Dollars, PDVSA paid 50 percent of 2005 first quarter oil and natural gas sales in Bolivars. Subsequent quarterly payments for 2005 were paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar, but Harvest Vinccler projects that it will be able to utilize its Bolivars to meet local obligations. 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 2004 or 2005. 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. During 2005 and continuing into 2006, PDVSA and MEP have refused to approve or issue permits and, as a result, Harvest Vinccler suspended its drilling and facilities program in 2005. 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) $9.0 million, $39.2 million and $58.3 million in 2005, 2004 and 2003, respectively. Included in these numbers is $8.9 million, $33.5 million and $43.6 million for the development of proved undeveloped reserves in 2005, 2004 and 2003, respectively.

11

     We have participated in the drilling of wells as follows:
                         
  Year Ended December 31,
  2005 2004 2003
  Gross Net Gross Net Gross Net
Wells Drilled:
                        
Development:                        
Crude oil  1   0.8   16   12.8   3   2.4 
                         
Average Depth of Wells (Feet)
  —   4,349   —   5,443   —   6,095 
                         
Producing Wells(1):
                        
Crude Oil  108   86.4   124   99.2   111   88.8 
(1)The information related to producing wells reflects wells we drilled, wells we participated in drilling and producing wells we acquired.
     All of our drilling activities are conducted on a contract basis with independent drilling contractors. We do not directly operate any drilling equipment.
Acreage
     The following table summarizes the developed and undeveloped acreage that we owned, leased or held under operating service agreement or concession as of December 31, 2005:
                 
  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 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, 2005, our Houston office had 15 full-time employees. Harvest Vinccler had 252 employees and our Moscow office had 10 employees. We augment our staffs from time to time with independent consultants, as required.

12

Title to Developed and Undeveloped Acreage
     All Venezuelan reserves are attributable to an operating service agreement between Harvest Vinccler and PDVSA, under which all mineral rights are owned by the Government of Venezuela.
     The WAB-21 petroleum contract lies within an area which is the subject of a border 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 area under 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.
Item 1A. 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 interests in Venezuela may be unlawfully expropriated by the Venezuelan government.All of our production and operating revenues are derived from Harvest Vinccler through its operations of the South Monagas Unit under the operating service agreement with PDVSA. The government of Venezuela has announced that all operating service agreements will cease to exist in 2006 and that operations under those agreements will be converted to mixed companies in which PDVSA has a controlling interest. The government has stated that it will reclaim the interests of operators who do not convert to a mixed company. While we are engaged in good faith negotiations with MEP and PDVSA for the conversion of Harvest Vinccler’s operating service agreement to a mixed company, there is no assurance that a conversion will be possible under acceptable terms. Based upon the government’s statements and actions, there is a risk that if Harvest Vinccler is unable to agree with Venezuela on the terms of a mixed company, its interests may be unlawfully expropriated or actions may be taken to prevent or render impossible continued operations. Expropriatory acts by Venezuela would likely cause us to seek international arbitration for the loss of our investment.
Our only source of production may be reduced further by actions of the Venezuelan government. Harvest Vinccler began the year with average oil deliveries of 29,000 barrels of oil per day (“Bopd”) and is currently averaging about 22,000 Bopd. Natural gas deliveries at the beginning of the year were averaging 79 million cubic feet a day (MMCFpd), and are currently averaging about 56 MMCFpd. The decline is due to PDVSA’s refusal to allow us to carry out our drilling and facilities program for 2005 and the natural decline of the field. In August 2005, we submitted a proposed 2006 work program and budget to PDVSA which, under circumstances where we have reasonable assurances that PDVSA will adhere to the provisions of our operating service agreement, would enable Harvest Vinccler to increase deliveries through an accelerated drilling program. Under the terms of our existing operating service agreement, Harvest Vinccler’s 2006 work program and budget were deemed approved in October 2005. There are discussions on going between Harvest Vinccler and PDVSA on the terms for commencing the 2006 program. Without the ability to drill new wells, crude oil and natural gas volumes will continue to decline.
     Crude oil volumes for 2005 were also affected by PDVSA’s curtailment of our crude oil deliveries during the first part of the year. PDVSA may curtail us again in the future.
Future Payments to Harvest Vinccler may be adversely affected by actions of the Venezuelan government.Harvest Vinccler was paid 28 days late for deliveries in the first quarter of 2005. In addition, the payment was paid 50 percent in Bolivars, notwithstanding the provisions of the operating service agreement which requires all payments to be in U.S. Dollars. Subsequent 2005 quarterly payments for oil and natural gas sales were paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar; however, at 25 percent Bolivar payment levels, Harvest Vinccler projects that it will be able to utilize its Bolivars to meet local obligations.
     At the direction of MEP, PDVSA imposed a limit on our maximum total fee equal to two-thirds of the total value of the crude oil delivered to PDVSA beginning January 1, 2005. This caused an underpayment to Harvest Vinccler for deliveries in the first quarter of 2005. In August 2005, Harvest Vinccler signed the Transitory Agreement with PDVSA which included a two-thirds limit on fees, and PDVSA paid the underpaid amount to the extent of that limit.

13

     Harvest Vinccler has been paid for oil and natural gas deliveries made through December 31, 2005 and expects to be paid for first quarter 2006 deliveries. Venezuela has not indicated how it intends to pay for deliveries after March 31, 2006, as it has stated that all operating service agreements must be converted to mixed companies by that date.
     Failure or refusal of PDVSA to pay Harvest Vinccler’s services fees, significant underpayment or withholding of fees, substantial payments by PDVSA in Bolivars, or the inability to convert the Bolivars into U.S. Dollars could, individually or in the aggregate, have a further material adverse effect on our financial position, results of operations and cash flows.
Actions by SENIAT to collect claimed back taxes could threaten the viability of our Venezuelan operations.In 2005, the Venezuelan income tax authority (the “SENIAT”) announced that the income tax rate paid by companies with operating service agreements would be retroactively increased from 34 percent to 67 percent for 2001 and from 34 percent to 50 percent for all years thereafter. The SENIAT completed a tax audit of Harvest Vinccler for the tax years 2001 through 2004, and in July 2005, the SENIAT issued a preliminary tax assessment of 184 billion Bolivars or approximately $85 million at the current exchange rate. In addition, the SENIAT imposed penalties equal to 10 percent of the preliminary tax assessment. A significant part of the preliminary tax assessment received relates to the retroactive increase in taxes above the existing rate of 34 percent. The assessment also relates to the disallowance of some deductions and attribution of additional income. Upon review of the preliminary tax assessment, and after discussions with officials in the SENIAT, Harvest Vinccler determined not to contest two elements of the preliminary tax assessment and made payments totaling $5.3 million. In September and October 2005, Harvest Vinccler filed an answer and evidentiary support with the SENIAT contesting all other elements of the preliminary tax assessment. The SENIAT and Harvest Vinccler have formed a working group to review the tax assessment for possible resolution of these claims.
     The SENIAT has up to one year to consider Harvest Vinccler’s answer and to determine whether, or to what extent, to issue a final tax assessment. A final tax assessment by the SENIAT may also include additional penalties between 25 percent and 200 percent of the unpaid tax. We are advised that the average penalty imposed by the SENIAT historically has been 112.5 percent of the unpaid tax unless extenuating or aggravating circumstances apply. If a final tax assessment is issued, Harvest Vinccler may file a further administrative appeal with the SENIAT. During the period of review by the SENIAT, any payment obligation is suspended. However, during this period the SENIAT may seek a court order allowing it to take precautionary measures such as attaching assets. After exhausting administrative appeals, Harvest Vinccler may either pay the tax or file a judicial appeal. If a judicial appeal is filed, the payment obligation may be suspended at the discretion of the court. While there are no established rules regarding payment suspension, we understand it is often granted only if the taxpayer posts a bond or other security equal to 210 percent of the final tax assessment. In the event we initiate an international arbitration, we may also seek to include the tax assessment as part of that proceeding.
     The SENIAT may also be considering additional tax audits of operating companies such as Harvest Vinccler. Despite a four year statute of limitations on tax claims, in January 2006, the head of the SENIAT stated consideration was being given to extending the audits back to 1993.
     At the current level of the tax assessment and considering possible interest and penalties, attachment of assets by the SENIAT, a determination of the need to take a charge against Harvest Vinccler’s earnings for the tax liability or a requirement to pay the taxes or post security will have a material adverse effect on Harvest Vinccler’s financial condition. A requirement to pay taxes, interest and penalties may exceed Harvest Vinccler’s cash balance. To the extent such events would cause the liabilities of Harvest Vinccler to exceed its assets, Harvest Vinccler would be insolvent. In addition, the implementation of a 50 percent tax rate or other changes in the interpretation or application of the tax laws, without compensating values, will have a material adverse effect on Harvest Vinccler’s financial position, results of operations or cash flows. We believe that these actions would not impact the cash or cash equivalent position of Harvest Natural Resources, Inc. or its other subsidiaries, which totaled $140.0 million at December 31, 2005.

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     We believe Harvest Vinccler has met its tax obligations in all material respects. We intend to take all measures necessary to protect Harvest Vinccler’s rights, and will vigorously challenge all elements of any tax assessment that are not supported by Venezuelan law.
The actions of the Venezuelan government may cause us to file for international arbitration. As a result of the actions taken by PDVSA, MEP and the SENIAT, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank. An arbitration proceeding may take a number of years to conclude and we can provide no assurances as to outcome. It is uncertain how the Venezuelan government might react to an arbitration filing, but it is possible it could lead to a shut down of Harvest Vinccler’s operations.
Harvest Vinccler may not be able to reach agreement on the terms of a mixed company and there is a risk any agreement will not receive the necessary approvals.We remain hopeful of reaching a mutually acceptable agreement with the government of Venezuela on converting the operating service agreement to a mixed company while preserving the value of our investment in Harvest Vinccler. We are actively engaged in discussions with government representatives and believe progress has been made. However, significant issues remain and it is not possible to give any assurances as to outcome. In addition, any agreement with PDVSA will require the approval of the Venezuelan National Assembly and of our shareholders. While no assurance can be provided, we believe these approvals would be obtained for any agreement supported by PDVSA, MEP, the SENIAT and us.
Our strategy to focus on Russia and other countries perceived to be politically challenging carries deal execution, operating, financial, legal and political risks.While we believe our established presence in countries perceived to be politically challenging and our experience and skills from prior operations position us well for future projects, doing business in Russia and other countries perceived to be politically challenging 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 local partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, 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 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 focus on countries perceived to be politically challenging limits our 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 countries perceived to be politically challenging 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 has been 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 service fee payments from PDVSA for all revenue receipts. We do not own the hydrocarbons and do not sell oil and natural 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 has been considered a highly inflationary economy. Results of operations in highly inflationary countries 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 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 Bolivars. Most of our operating and capital expenditures are in U.S. Dollars. For a discussion of currency controls in Venezuela, seeCapital Resources and LiquidityunderItem 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.Successful acquisition of projects in any international country 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 $24.02 per Bbl for the year ended December 31, 2005, compared with $18.90 per Bbl for the year ended December 31, 2004. 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;
•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.
Lower oil and natural gas prices or downward adjustments to 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 natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural 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 natural 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 that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we

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experience substantial downward adjustments to our estimated proved reserves. We did not incur ceiling test write-downs in 2005 in the consolidated financial statements of the wholly-owned and majority owned subsidiaries. While our proved reserves were reduced by our Contractually Restricted Reserves as well as other revisions, this did not cause a ceiling limitation write down. 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 ended September 30, 2003.
Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. As a result of the actions of the Venezuelan Government, our Contractually Restricted Reserves have been excluded from our proved reserves. SeeItem 1 – Business, Operations.
     The process of estimating oil and natural gas reserves is complex. Such process requires 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. 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, the conversion of Harvest Vinccler’s interests to a mixed company in which it is a minority interest owner, 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.
     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 of oil and natural gas properties will affect the timing of actual future net cash flows from estimated proved reserves and their present value. In addition, the 10 percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with the oil and natural gas industry in general will affect the accuracy of the 10 percent discount factor.
We may not be able to replace production with new reserves. In general, production rates and remaining reserves from oil and natural gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. Our reserves in the South Monagas Unit in Venezuela will decline as they are produced unless we are able to include Contractually Restricted Reserves, 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 level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive and uncertain. We may be unable to make the necessary capital investment to maintain or expand our oil and natural gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot assure you that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.
Our operations are subject to numerous risks of oil and natural gas drilling and production activities.Oil and natural gas 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:

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•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;
•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 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, 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.
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 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.
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. Also during 2004, Harvest Vinccler leased office space in Maturin and Caracas, Venezuela for $13,200 and $4,000 per month, respectively. See alsoItem 1 – Business for a description of our oil and natural gas properties and reserves.

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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, 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. In October 2003, the Court abated the suit pending final judgment of a case pending in Louisiana to which we are not a party. We dispute Excel’s claims and plan to vigorously defend against them.
Uracoa Municipality Tax Assessments. In July 2004, Harvest Vinccler received three tax 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. Harvest Vinccler has filed a motion with the tax court in Barcelona, Venezuela, seeking to enjoin the payment order and dismiss the assessment. We dispute all of the tax assessments and believe we have a substantial basis for our positions.
The SENIAT Tax Assessment. On July 22, 2005, the SENIAT, the Venezuelan income tax authority, issued a preliminary tax assessment to Harvest Vinccler of 184 billion Venezuelan Bolivars related to fiscal years 2001 through 2004. At the official exchange rate of 2,150 Bolivars per U.S. Dollar, the dollar equivalent of the preliminary tax assessment is approximately $85 million. In addition, the SENIAT imposed penalties equal to 10 percent of the preliminary tax assessment claim for a total claim of 202 billion Bolivars, or approximately $94 million. Upon review of the preliminary tax assessment, we determined not to contest two elements of the claim and made payments totaling 11.3 billion Bolivars or $5.3 million in August and September, 2005. In September and October 2005, we filed a response and evidentiary support with the SENIAT contesting all other claims. We believe Harvest Vinccler has met its tax obligations in all material respects. We intend to take all measures necessary to protect our rights, and will vigorously challenge all elements of the tax assessment that are not supported by Venezuelan law.
International Arbitration. As a result of the actions taken by PDVSA, MEP and the SENIAT, in July 2005, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank.
Item 4. Submission of Matters to a Vote of Security Holders
     None.

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PART II
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
     Our Common Stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HNR”. As of December 31, 2005, there were 36,986,643 shares of common stock outstanding, with approximately 683 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 
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 
           
2005
 First quarter  16.92   11.30 
  Second quarter  12.48   8.13 
  Third quarter  11.68   9.00 
  Fourth quarter  10.81   8.57 
     On February 10, 2006, the last sales price for the common stock as reported by the NYSE was $8.47 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.
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, 2005. 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 and 2001 reflect results from Geoilbent (until sold on September 25, 2003) for the twelve months ended September 30, 2003, 2002 and 2001, and from Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2001.

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  Year Ended December 31, 
  2005  2004  2003  2002  2001 
  (in thousands, except per share data) 
Statement of Operations:
                    
Total revenues $236,941  $186,066  $106,095  $126,731  $122,386 
Operating income  119,525   90,480   33,627   34,585   28,201 
Net income  50,839   34,360   27,303   100,362   43,237 
Net income per common share:                    
Basic $1.38  $0.95  $0.77  $2.90  $1.27 
                
Diluted $1.32  $0.90  $0.74  $2.78  $1.27 
                
                     
Weighted average common shares outstanding                    
Basic  36,949   36,128   35,332   34,637   33,937 
Diluted  38,444   38,122   36,840   36,130   34,008 
                     
  Year Ended December 31, 
  2005  2004  2003  2002  2001 
  (in thousands) 
Balance Sheet Data:
                    
Total assets $400,798  $367,486  $374,348  $335,192  $348,151 
Long-term debt, net of current maturities  —   —   96,833   104,700   221,583 
Stockholders’ equity(1)
  297,512   243,189   199,713   171,317   67,623 
(1)No cash dividends were declared or paid during the periods presented.

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Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
     We had record financial performance in 2005. Net income for 2005 was $50.8 million compared with 2004 net income of $34.4 million. Net cash provided by operating activities was $114.7 million for 2005 compared with $74.1 million for 2004. Despite these results, our share price suffered significantly in 2005. We believe this decline was primarily a result of the situation in Venezuela and our lack of country asset risk diversification.
     InItem 1 — BusinessandItem 1A — Risk Factors,we discuss the situation in Venezuela and how the actions of the Venezuelan government have and may continue to adversely affect our operations. We have also described how the uncertainty in Venezuela surrounding our ability to conduct future development programs has led to the reduction of our proved reserves by approximately 50 percent, and our estimated discounted future net cash flows from our proved reserves have been reduced by approximately 60 percent. Collectively, the events in Venezuela, both actual and threatened, are having a material adverse effect on our financial condition, results of operations and cash flows. The situation in Venezuela is also having an adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere.
     We remain hopeful of reaching a mutually acceptable agreement with the government of Venezuela on converting our operating service agreement to a mixed company while preserving the value of our investment in Harvest Vinccler. The Transitory Agreement we executed in August 2005 provides a platform for our discussions with PDVSA, MEP and the SENIAT, and we are actively engaged with their representatives at a number of levels. We feel we have made progress and continue to work cooperatively with Venezuelan officials. However, until there is clarity and resolution to the situation, uncertainty over the future of our investment in Venezuela will continue to affect our performance. We will also consider alternatives to unlocking the underlying value of our Venezuelan assets for our shareholders. This may include a sale or exchange of all or part of our Venezuelan interests.
     We recognize the need to diversify our asset base and that is the primary focus of our strategy. We have a strong balance sheet with $163 million of cash. We will use this cash to build a diversified portfolio of assets in a number of countries that fit our strategic investment criteria. We are pursuing opportunities in a number of areas including Russia, the Commonwealth of Independent States, the Middle East and Asia.
In executing our business strategy, we will strive to:
•maintain financial prudence and rigorous investment criteria;
•enhance access to capital markets;
•create a diversified portfolio of large assets;
•maximize cash flows from existing operations;
•use our experience, skills to acquire new projects; and
•keep our organizational capabilities in line with our rate of growth.
To accomplish our strategy, we intend to:
•Diversity our political risk:Acquire large oil and natural gas fields in a number of countries perceived to be politically challenging to diversify and reduce the overall political risk of our international investment portfolio.
•Seek Operational and Financial Control: We desire control of major decisions for development, production, staffing and financing for each project for a period of time sufficient for us to ensure maximum returns on investments.
•Establish a Local Presence Through Joint Venture Partners and the Use of Local Personnel:We seek to establish a local presence in our areas of operation to facilitate stronger relationships with local government and labor. In addition, using local personnel helps 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.

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•Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time:We are willing to agree to minimum capital expenditure or development commitments at the outset of new projects, but we endeavor to structure such commitments so that we can fulfill them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure.
•Limit Exploration Activities:While our strategy does not focus on unexplored areas, we will consider appropriate exploration opportunities that have large potential scale and the ability to manage risk without significant initial cost.
•Maintain A Prudent Financial Plan: We intend to maintain our financial flexibility by closely monitoring spending, holding sufficient cash reserves, actively seeking opportunities to reduce our weighted average cost of capital and increasing our debt capacity and liquidity.
Results of Operations
     We include the results of operations of Harvest Vinccler in our consolidated financial statements and reflect the 20 percent ownership interest of Vinccler as a minority interest. We accounted for our investment in Geoilbent using the equity method. We included Geoilbent in our consolidated financial statements based on a fiscal year ending September 30. Our results of operations for the year ended December 31, 2003 reflect the results of Geoilbent (until sold on September 25, 2003).
     You should read the following discussion of the results of operations for each of the years in the three-year period ended December 31, 2005 and the financial condition as of December 31, 2005 and 2004 in conjunction with our Consolidated Financial Statements and related Notes thereto.
     We have presented selected expense items from our consolidated income statement as a percentage of revenue in the following table:
             
  Years Ended December 31,
  2005 2004 2003
Operating Expenses  17%  18%  29%
Depletion, Depreciation and Amortization  19   19   20 
General and Administrative  10   12   15 
Taxes Other Than on Income  3   3   3 
Interest Expense  1   4   10 
Years Ended 2005 and 2004
     We reported net income of $50.8 million, or $1.32 diluted earnings per share, for 2005 compared with net income of $34.4 million, or $0.90 diluted earnings per share for 2004. Below is a discussion of revenues, price and volume variances.
                     
  Year Ended      %    
  December 31,  Increase  Increase    
(in millions) 2005  2004  (Decrease)  (Decrease)  Increase 
Revenues                    
Crude oil $210.5  $154.1  $56.4   37%    
Natural gas  26.4   32.0   (5.6)  (18)    
                
Total Revenues $236.9  $186.1  $50.8   27%    
                
                     

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The following table reconciles the net change in revenue:                    
                     
Price and Volume Variances                    
Crude oil price Variance (per Bbl) $24.02  $18.90  $5.12   27% $41.6 
Volume Variances                    
Crude oil volumes (MBbls)  8,763   8,152   611   7% $14.7 
Natural gas volumes (MMcf)  25,677   31,059   (5,382)  (17)  (5.5)
                    
Total volume variances                 $9.2 
                    
Revenue, Crude Oil Price Variance and Volume Variances
     Revenues were higher in 2005 compared with 2004 due to increases in world crude oil prices and oil volumes as a result of our second half 2004 drilling program. Price variance is net of the cost of hedges in place during 2005. Natural gas delivery volumes have declined due to the refusal of MEP and PDVSA to issue permits for the drilling of new oil wells and the natural decline of associated natural gas from existing oil wells. Currently, all natural gas deliveries are associated with the Uracoa oil wells.
     Total expenses and other non-operating (income) expense:
                 
  Year Ended      % 
  December 31,  Increase  Increase 
  2005  2004  (Decrease)  (Decrease) 
Operating expenses $39.7  $33.3  $6.4   19%
Depletion and amortization  41.2   34.2   7.0   20 
Depreciation  2.7   1.9   0.8   42 
General and administrative  22.8   21.9   0.9   4 
Account receivable write-off on retroactive oil price adjustment  4.5   —   4.5   — 
Gain on sale of long-lived assets  —   (0.6)  0.6   — 
Bad debt recovery  —   (0.6)  0.6   — 
Taxes other than on income  6.4   5.6   0.8   14 
Investment income and other  (4.2)  (2.1)  (2.1)  100 
Interest expense  3.4   7.7   (4.3)  (56)
Net (gain) loss on exchange rates  (2.8)  0.6   (3.4)  — 
             
  $113.7  $101.9  $11.8   12%
             
     Operating expenses increased as a result of higher oil volumes and maintenance work. Depletion and amortization expense per Boe produced during 2005 was $3.16 versus $2.56 in 2004. The increase was due to the exclusion of Contractually Restricted Reserves in our current proved reserves as well as other minor revisions. General and administrative expense increased primarily due to penalties accrued for the failure to withhold the prescribed amount of value added taxes from payments to vendors in Venezuela in 2005. Taxes other than on income increased due to increased Venezuelan municipal taxes which result from higher oil revenues.
     The effective tax rate increased in 2005 to 46 percent from 41 percent in 2004 primarily due to the payment of $5.6 million related to the 2001 through 2004 preliminary tax assessment. Our tax calculations do not include the tax increases recently announced by the SENIAT (seeItem 1A – Risk Factors).
Years Ended 2004 and 2003
     We reported net income of $34.4 million, or $0.90 diluted earnings per share, for 2004 compared with net income of $27.3 million, or $0.74 diluted earnings per share, for 2003. Below is a discussion of revenues, price and volume variances.

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  Year Ended      %    
  December 31,  Increase  Increase    
(in millions) 2004  2003  (Decrease)  (Decrease)  Increase 
Revenues                    
Crude oil $154.1  $103.4  $50.7   49%    
Natural gas  32.0   2.7   29.3   100     
                
Total Revenues $186.1  $106.1  $80.0   75%    
                
                     
The following table reconciles the net change in revenue:                    
                     
Price and Volume Variances                    
Crude oil price Variance (per Bbl) $18.90  $14.07  $4.83   34% $35.5 
Volume Variances                    
Crude oil volumes (MBbls)  8,152   7,347   805   11% $15.2 
Natural gas volumes (MMcf)  31,059   2,660   28,399   100   29.3 
                    
Total volume variances                 $44.5 
                    
Revenue, Crude Oil Price Variance and Volume Variances
     Revenues were higher in the for 2004 compared to 2003 due to the addition of a full year of natural gas sales, higher oil volumes and higher crude oil prices. All natural gas deliveries are associated with the Uracoa oil wells.
     Total expenses and other non-operating (income) expense:
                 
  Year Ended      % 
  December 31,  Increase  Increase 
  2004  2003  (Decrease)  (Decrease) 
Operating expenses $33.3  $30.9  $2.4   8%
Depletion and amortization  34.2   19.6   14.6   74 
Depreciation  1.9   1.6   0.3   19 
Write-downs of oil and gas properties  —   0.2   (0.2)  (100)
General and administrative  21.9   15.7   6.2   39 
Gain on sale of long-lived assets  (0.6)  —   (0.6)  — 
Arbitration settlement  —   1.5   (1.5)  (100)
Bad debt recovery  (0.6)  (0.4)  (0.2)  50 
Taxes other than on income  5.6   3.4   2.2   65 
Investment income and other  (2.1)  (1.4)  (0.7)  50 
Interest expense  7.7   10.4   (2.7)  (26)
Net (gain) loss on exchange rates  0.6   (0.5)  1.1   (220)
             
  $101.9  $81.0  $20.9   26%
             
     Operating expenses increased primarily due to higher production volumes, higher workover and maintenance programs and increased insurance costs. Depletion and amortization expense per Boe produced during 2004 was $2.56 versus $2.52 during 2003. The increase was primarily due to increased future development costs. We recognized write-downs for additional capitalized costs associated with former exploration projects during 2003. General and administrative expenses increased for 2004 compared with 2003, 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 was recorded in 2003, and bad debt recoveries were recorded in 2004 and 2003, respectively, related to an allowance for uncollectible accounts in prior years. Taxes other than on income increased due to increased Venezuelan municipal taxes which result from higher oil and natural gas revenues.
     Investment income and other increased due to higher interest rates earned on average cash balances. Interest expense decreased due to lower average outstanding debt balances from 2004 compared to 2003. In 2004, we redeemed all $85 million of our 9.375 percent senior unsecured notes due November 1, 2007 (“2007 Notes”), and we repaid all Bolivar denominated debt in March 2003.

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     Net gain (loss) on exchange rates decreased 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.
     The effective tax rate increased in 2004 to 41 percent from 13 percent in 2003 primarily 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.
     Equity in net losses of affiliated companies decreased during 2004 compared to 2003. This was due to the elimination of Geoilbent equity losses on September 25, 2003, the date of its sale.
Capital Resources and Liquidity
     The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks (seeItem 1A — Risk Factors). In 2001, Benton-Vinccler borrowed $12.3 millionWe require capital principally to fund the following costs:
•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.
     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.
     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. 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 athose payments. Notwithstanding the provisions in our operating service agreement which requires all payments to be in U.S. Dollars, PDVSA paid 50 percent of our 2005 first quarter oil and natural gas sales in Bolivars. Subsequent quarterly payments for 2005 oil and natural gas sales were paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar; however, based on current levels of payments in Bolivars, Harvest Vinccler projects that it will be able to utilize its Bolivars to meet local currency obligations. We have substantial cash reserves and do not expect the Venezuelan commercial bankcurrency conversion restriction to adversely affect our ability to meet short-term loan obligations and operating requirements for the constructionnext twelve months.
     Our ability to acquire and develop growth opportunities outside of anVenezuela is dependent upon the ability of Harvest Vinccler to make loan repayments and dividends to us. However, there have been, and may again be, interruptions in oil pipeline. A portionand natural gas sales, changes in the amount, timing or currency of payments by PDVSA, or there may be contractual obligations or legal impediments to receiving dividends from Harvest Vinccler, which could affect the loan was denominated in Bolivarsability of Harvest Vinccler to remit funds to us.
Debt Reduction.We have quarterly principal and was repaid asinterest obligations of March 31, 2003.

$1.3 and $0.3 million on the Harvest Vinccler variable rate loans. We have no other debt obligations.

     Working Capital.Our capital resources and liquidity are affected by the timing of our semiannual interest payments of approximately $4.0 million each May 1 and November 1 on the 9.375 percent Senior Notes due in November 2007 and by receipt of the quarterly payments from PDVSA at the end of the months of February, May, August and November pursuant to the terms of the operating service agreement for the South Monagas Unit. The first quarter 2005 payment was nearly a month late and 50 percent was paid in Bolivars. Each subsequent quarter was paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar. As a consequence of the timing of these interest payment outflows and the PDVSA payment inflows, our cash balances can increase and decrease dramatically on a few dates during the year. In each May and November in particular, interest payments at the beginning of the month and PDVSA payments at the end of the month create large swings in our cash balances.

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          Benton-Vinccler’s oil and gas pipeline project loans allow the lender to accelerate repayment if production ceases for a period greater than thirty days. During the production shut-in which started in December 2002, Benton-Vinccler was granted a waiver of this provision until February 18, 2003 in exchange for a prepayment of the next two principal obligations aggregating $0.9 million. This prepayment, while using cash reserves, reduced our net interest expense as the current interest expense was more than the current interest income earned on the invested funds. On February 8, 2003, Benton-Vinccler commenced production, thereby eliminating the need for an additional waiver. A future disruption of production could trigger the debt acceleration provision again. While no assurances can be given, we believe Benton-Vinccler would be able to obtain another waiver under acceptable terms and conditions.

     The net funds raised and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:

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  Year Ended December 31,
  
  (in thousands)
  2003 2002 2001
  
 
 
Net cash provided by operating activities $38,538  $42,627  $36,608 
Net cash provided by (used in) investing activities  38,191   126,143   (48,082)
Net cash provided by (used in) financing activities  (2,570)  (113,293)  5,366 
   
   
   
 
Net increase (decrease) in cash $74,159  $55,477  $(6,108)
   
   
   
 

             
  Year Ended December 31, 
  (in thousands) 
  2005  2004  2003 
Net cash provided by operating activities $114,665  $74,140  $38,538 
Net cash provided by (used in) investing activities  (15,647)  (39,684)  38,191 
Net cash used in financing activities  (20,599)  (88,516)  (2,570)
          
Net increase (decrease) in cash $78,419  $(54,060) $74,159 
          
     At December 31, 2003,2005, we had current assets of $183.4$239.9 million and current liabilities of $46.2$61.8 million, resulting in working capital of $137.2$178.1 million and a current ratio of 4.0:3.9:1. This compares with a working capital of $97.0$89.0 million and a current rationratio of 3.8:2.1:1 at December 31, 2002.2004. The increase in working capital of $40.2$89.1 million was primarily due to higher oil sales prices and oil volumes in Venezuela in 2005 offset by the saleprepayment of our minority equity investmentthe 2007 Notes in Geoilbent.

2004.

     Cash Flow from Operating Activities.Activities. During the years ended December 31, 20032005 and 2002,2004, net cash provided by operating activities was approximately $38.5$114.7 million and $42.6$74.1 million, respectively. The $4.1$40.6 million decreaseincrease was primarily due to lowerthe increase in oil revenues offset by the commencement of gas sales in the fourth quarter of 2003.

volumes and oil prices.

     Cash Flow from Investing Activities.During the years ended December 31, 20032005 and 2002,2004, we had drilling, production-related and production-relatedadministrative capital expenditures of approximately $60.9$16.1 million and $43.3$39.1 million, respectively. OfThe decrease in capital expenditures is due to completion of the 2003 expenditures, $33.6 million was attributable todrilling of an oil well and the development ofgathering system and facilities for the South Monagas Unit $27.0 millioncarried over from 2004. Due to the constructionactions of the gas pipelineMEP and PDVSA, no further drilling activity was carried out in 2005.
     On a year-to-year basis, the balance for other administrative property.

          The timing and size of capital expenditures for the South Monagas Unit are entirelylargely at our discretion.discretion, although recent actions by PDVSA have greatly limited our ability to make planned capital expenditures in 2005 and 2006, and could also limit us in the future. We suspended our drilling program in January 2005 because of the refusal of PDVSA and MEP to process and issue necessary permits to drill new wells. We continue to expend funds for workovers, maintenance, gathering systems and facility upgrades for the existing wells. Our remaining worldwide capital commitments worldwide support our search for new acquisitions, and are relatively minimal and are substantially at our discretion. We will also be required to make annual interest payments of approximately $8.0 million on the 2007 Notes.

We continue to assess production levels and commodity prices in conjunction with our capital resources and liquidity requirements.

requirements

     Cash Flow from Financing Activities.During 2003, Benton-Vincclerthe year ended 2005, Harvest Vinccler repaid the balance$6.4 million of their Bolivarits U.S. Dollar denominated debt (four payments of $2.2$0.3 million and other debtfour payments of $1.2 million.$1.3 million on the variable rate loans). During 2002,the year ended 2004, we paid $108irrevocably deposited with the Trustee as trust funds $85.0 million in 11.625 percent senior unsecured notes due May 1, 2003, $20 million in 9.375 percent senior unsecured notes dueplus accrued interest through November 1, 2004 and prepayment call premium of $1.3 million to redeem our 2007 and Benton-VincclerNotes on the redemption date. During the same period, Harvest Vinccler repaid other debt$6.4 million of $4.3 million. In November 1997, we issued $115 million in 9.375 percent senior unsecured notes due November 1, 2007, of which we repurchased $30 million. Interest on these notes is due May 1 and November 1 of each year. The indenture agreements provide for certain limitations on liens, additional indebtedness, certain investment and capital expenditures, dividends, mergers and sales of assets. At December 31, 2003, we were in compliance with all covenants of the indenture.

its U.S. Dollar debt.

Contractual Obligations.Obligations
We have a lease obligation of approximately $11,000$17,000 per month for our Houston office space. This lease is validruns through August 2004. The following table summarizes our contractualApril 2014. In addition, Harvest Vinccler has lease obligations at December 31, 2003.
                 
  Payments (in thousands) Due by Period
  
      Less than        
Contractual Obligation Total 1 Year 1-3 Years 3-5 Years
 
 
 
 
Long Term Debt $103,200  $6,367  $6,367  $90,466 
Office Lease  88   88   —   — 
   
   
   
   
 
Total $103,288  $6,455  $6,367  $90,466 
   
   
   
   
 
for office space in Maturin and Caracas, Venezuela for $13,200 and $4,000 per month, respectively.
                     
  Payments (in thousands) Due by Period 
      Less than          After 4 
Contractual Obligation Total  1 Year  1-2 Years  3-4Years  Years 
Long-Term Debt $5,467  $5,467  $—  $—  $— 
Building Lease  2,749   449   407   400   1,493 
                
Total $8,216  $5,916  $407  $400  $1,493 
                

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     While we can give no assurance, we currently believe that our cash flow from operations coupled with our cash and marketable securities on hand will provide sufficient capital resources and liquidity to fund our planned capital expenditures investments in and advances to affiliates, and semiannualquarterly 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 there will be no further disruptions toor limitations on our production and that PDVSA will timely pay our invoices.invoices timely and primarily in U.S. Dollars. Actual results could be materially affected if there is a significant change in our expectations or assumptions.assumptions (seeItem 1A — Risk Factors). Future cash flows are subject to a number of variables including, but not limited to, the level of production and prices, as well

25

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.

          We currently have a significant debt obligation of $85 million payable in November 2007. Our ability to meet our debt obligation and to reduce our level of debt depends on the successful implementation of our business strategy.

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 and natural gas prices may affect our total planned development activities and capital expenditure program.

     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.

     Within the United States, inflation has had a minimal effect on us, but it is potentially an important factor in results of operations in Venezuela. With respect to Benton-Vinccler,Harvest Vinccler, a significant majority of the sources of funds, including the proceeds from oil sales, our contributions and credit financings, are denominated in U.S. dollars,Dollars, while a minor amount of local transactions in Venezuela are conducted in local currency.Bolivars. If the rate of increase in the value of the U.S. dollarDollar 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 Benton-Vinccler.

Harvest Vinccler.

     During the year ended December 31, 2002,2005, our net foreign exchange gain attributable to our international operations was $4.6$2.8 million. The U.S. dollarDollar and Bolivar exchange rates were fixedadjusted in February 2003 and noMarch 2005. No gains or losses were recognized afterfrom February 2003.2004 to February 2005. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, many 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.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.

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 accountaccounted for our investment in Geoilbent, and Arctic Gasprior to its sale in September 2003, based on a fiscal year ending September 30 prior to their respective sales.

30.

     Oil and natural gas revenue is accrued monthly based on sales. Each quarter, Benton-VincclerHarvest Vinccler invoices PDVSA based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. dollarDollar contract service fees per barrel.

Property and Equipment

     We follow the full cost method of accounting for oil and natural 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 related to production, general corporate overhead and similar activities are expensed as incurred. The costs for China

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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 cost 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

26

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 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. Changes in previous estimates of proved reserves result from new information obtained from production history, and changes in economic factors.factors and other relevant developments. Our proved reserves at December 31, 2005 do not include Contractually Restricted Reserves. A large portion of our proved reserves base from consolidated operations is comprised of oil and natural gas properties that are sensitive to oil price volatility. We are susceptible to significant upward and downward revisions to our Proved Reserveproved reserve volumes and values as a result of changes in year end oil and natural gas prices, existing economic conditions, contractual uncertainty, contract term and the corresponding adjustment to the projected economic life of such properties. Prices for oil and natural gas are likely to continue to be volatile, resulting in future revision to our Proved Reserveproved reserve base. We perform a quarterly cost center ceiling test of our oil and natural gas properties under the full cost accounting rules of the SEC. These rules generally require that we price our future oil and natural gas production at the oil and natural gas prices 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 natural 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 natural gas prices decline significantly in the future, even if only for a short period of time, write-downs of our oil and natural gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities.

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.

Foreign Currency

     Our current operations are in Venezuela. The U.S. dollarDollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in U.S dollars,U.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.Dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates.

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New Accounting Pronouncements

     In May 2003,March 2005, the Financial Accounting Standards Board (“FASB”FASB’) issued Statement of Financial Accounting Standard No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (the “Statement”). The Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The Statement is generally effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this Statement had no effect on our consolidated financial statements.

          In January 2003, the FASB issuedStaff Interpretation No. 46 (“FIN 46”)46(R) — 5 Consolidation of Variable Interest Entities (“FSP FIN 46(R) — 5”), which addresses the consolidation of variable interest entities (“VIEs”) by business enterprises that are the primary beneficiaries. A VIEFSP FIN 46(R) — 5 is an entity that does not have sufficient equity investment at riskapplicable 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

27

majority of the risks 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,both nonpublic and to defer certain entities from adopting until the end of the first interim or annualpublic reporting period ending after March 15, 2004.enterprises. 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 types of VIEs is required in financial statements for periods endingthe first reporting period beginning after March 3, 2005 in accordance with the transition provisions of FSP FIN 46(R) — 5. The adoption of this interpretation will not impact our consolidated financial position, results of operations or cash flows.

     In April 2005, the FASB issued Staff Interpretation No. 19-1 (“FSP 19-1”) Accounting for Suspended Well Costs, which provides guidance on the accounting for exploratory well costs and proposes an amendment to FASB Statement No. 19 (“FASB 19”), Financial Accounting and Reporting by Oil and Gas Producing Companies. The guidance in FSP 19-1 applies to enterprises that use the successful efforts method of accounting as described in FASB 19. The guidance in FSP 19-1 will not impact our consolidated financial position, results of operations or cash flows.
     In June 2005, the Financial Accounting Standards Board (“FASB’) issued Statement of Financial Accounting Standard 154 – Accounting Changes and Error Corrections (“SFAS 154”), which changes the requirements for the accounting for and reporting of a change in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. Application is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2004. We believe we2005. Early adoption is permitted. The adoption of SFAS 154 is not expected to have no arrangements that would require the applicationa material effect on our consolidated financial position, results of FIN 46R. We have no material off-balance sheet arrangements.operations or cash flows.

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 and political risk, as discussed below.

Oil Prices

     As an independent oil producer, our revenue, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control. Historically, prices received for oil production have been volatile and unpredictable, and such volatility is expected to continue. Through February 14, 2003, we utilized a costless collar hedge transaction with respect to a portion of our oil production to achieve a more predictable cash flow,In August and establish an acceptable rate of return on our Tucupita drilling program, as well as to reduce our exposure to price fluctuations. Benton-VincclerSeptember 2004, Harvest Vinccler hedged a portion of its 2003 oil productionsales for calendar year 2005 by purchasing atwo WTI crude oil “put” to protect its 2003 cash flow.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. SeeNote 1 – Derivatives and Hedgingfor a complete discussion of our derivative activity. Currently, we haveWe had no hedging transactions in place for our 2004 production.

Currently, there are no hedging transactions in place for our 2006 production.

Interest Rates

     Total long-termshort-term debt at December 31, 20032005 of $96.8$5.5 million consisted of fixed-rate senior unsecured notes maturing in 2007 ($85.0 million). Benton-Vinccler has $11.8 million ofHarvest Vinccler U.S. dollarDollar denominated variable rate loans. A hypothetical 10 percent adverse change in the interest rate would not have a material affect on our results of operations.

Foreign Exchange

          For

     Under the Venezuelan operations,provisions of our operating service agreement, payments for oil and natural gas sales in Venezuela are to be received under a contract in effect through 2012 in U.S. dollars; expendituresDollars. Expenditures are both in U.S. dollarsDollars and local currency.Bolivars. For first quarter 2005 oil and natural gas deliveries, Harvest Vinccler was paid 50 percent in Bolivars, and each subsequent quarter

30

was paid 25 percent in Bolivars. The Bolivar is not readily convertible into the U.S. Dollar. We have utilized no currency hedging programs to mitigate any risks associated with operations in 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).

Political Risk

          Political and economic uncertainty remains very high in Venezuela. During 2003, the production from the South Monagas Unit in Venezuela represented all of our total production from consolidated companies. Our production, revenue and cash flow will be adversely affected if production from the South Monagas Unit decreases significantly for any reason. From December 14, 2002 through February 6, 2003, no sales were made because of PDVSA’s inability to accept our oil due to the national civil work stoppage in Venezuela. As a result, 2002 sales were reduced by approximately 0.6 million barrels and 2003 sales were reduced by an estimated 1.2 million barrels. As a result of the Venezuelan national civil work stoppage, the Venezuelan government terminated several thousand PDVSA employees and announced a restructuring of PDVSA’s operations. Throughout 2003, there have been numerous organizational changes in PDVSA. As a result of the situation in PDVSA, its payment to Benton-Vinccler for crude delivered in the fourth quarter of 2002 was late by seven days. However, all other payments have been on time, and we believe PDVSA is committed to building its production levels and returning to more normalized business relations with its customers and suppliers.

28

          There are ongoing efforts by opponents of President Chavez for a constitutional recall referendum. A successful recall referendum could lead to new presidential elections. These events create civil unrest and the possibility of work stoppages or disruptions. The political uncertainty and economic instability in Venezuela could adversely affect our operations and business prospects in that country. In addition, while the effect of the changes and the possible politicalization of PDVSA cannot be predicted, it could adversely affect PDVSA’s ability to manage its contracts and meet its obligations with its suppliers and vendors, such as Benton-Vinccler. Organizational instability and uncertainty at PDVSA could also adversely affect our ability to acquire new projects in Venezuela and the timing of those acquisitions. While we have substantial cash reserves to withstand a future disruption of sales, a prolonged loss of sales or a failure or delay by PDVSA to pay our invoices could have a material adverse effect on our financial condition.

Item 8. Financial Statements and Supplementary Data

     The information required by this item is included herein on pages S-1 through S-36.S-30.

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

Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
     None.

Item 9A.

Item 9A.Controls and Procedures
     The Securities and Procedures

          The SEC,Exchange Commission, among other things, 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”). 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.

          Our principal executive officer

Evaluation of Disclosure Controls and Procedures.We have established disclosure controls and procedures to ensure that material information relating to us, including our principalconsolidated subsidiaries, is made known to the officers who certify our financial officer have informed us that, based uponreports and to other members of senior management and the Board of Directors.
     Based on their evaluation as of December 31, 2003, of2005, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in RuleRules 13a-15(e) and Rule 15d-15(e) under the Exchange Act), they have 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 recorded, processed, summarized and reported within the time periods as specified in the Securities and Exchange Commission rules and forms.
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 Rules 13a-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 those disclosure controls and procedures are effective.

          There have been no changes in our internal controls or in other factors known to us that could significantly affect these controls subsequent to their evaluation, nor have we been required to take any corrective actions with regard to any significant deficienciescontrol over financial reporting was effective as of December 31, 2005. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, and material weaknesses.issued an attestation report which is included herein.

Item 9B. Other Information
     None.

31

29

PART III

PART III
Item 10. Directors and Executive Officers of the Registrant

     Please refer to the information under the captions “Election of Directors” and “Executive Officers” in our Proxy Statement for the 20042006 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 20042006 Annual Meeting of Shareholders.Stockholders.

Item 12. Security Ownership of Certain Beneficial Owners and Management

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 20042006 Annual Meeting of Shareholders.Stockholders.

Item 13. Certain Relationships and Related Transactions

     Please refer to the information under the caption “Certain Relationships and Related Transactions” in our Proxy Statement for the 20042006 Annual Meeting of Shareholders.Stockholders.

Item 14. Principal Accounting Fees and Services

     Please refer to the information under the caption “Independent Accountants”Registered Public Accounting Firm” in our Proxy Statement for the 20042006 Annual Meeting of Shareholders.Stockholders.

32

30

PART IV

PART IV
Item 15. Exhibits and Financial Statement Schedules and Reports on Form 8-K
     
  Page
(a) 1. Index to Financial Statements: Page
Report of Independent Registered Public Accounting Firm
S-1
    
(a) 1.
Consolidated Balance Sheets at December 31, 2005 and 2004
 Index to Financial Statements:S-2 
  Report of Independent AuditorsS-1
  Consolidated Balance Sheets at December 31, 2003 and 2002S-2
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2003, 20022005, 2004 and 20012003
 S-3
  
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2003, 20022005, 2004 and 20012003
 S-4
  
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 20022005, 2004 and 20012003
 S-5
  
Notes to Consolidated Financial Statements
 S-7

2.     Consolidated Financial Statement Schedules:

Schedule II       - - Valuation and Qualifying Accounts

Schedule III       - - Financial Statements and Notes for LLC Geoilbent

2.Consolidated Financial Statement Schedules and Other:
Schedule II — Valuation and Qualifying Accounts
Financial Statements and Notes for LLC Geoilbent, a significant equity investment
 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:

 
3. Exhibits:
 3.1 Amended and Restated Certificate of Incorporation filed September 9, 1988Incorporation. (Incorporated by reference to Exhibit 3.13.1(i) to our Registration Statement (RegistrationForm 10-Q filed on August 13, 2002, File No. 33-26333)1-10762.).
 
 3.2Amendment to Certificate of Incorporation filed June 7, 1991 (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-39214)).
3.3 Amended and Restated Bylaws as of December 11, 2003.May 19, 2005. (Incorporated by reference to Exhibit 3.2 to our Form 10-Q filed on April 29, 2005, File No. 1-10762.)
 
 4.1 Form of Common Stock Certificate (Previously filed as an exhibitCertificate. (Incorporated by reference to the exhibits to our S-1 Registration Statement Form S-1 (Registration No. 33-26333).).
 
 4.2 Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.)
 
 4.3 Second Amended and Restated Rights Agreement, dated as of April 15, 2005, between Benton OilHarvest Natural Resources, Inc. and Gas Company and First InterstateWells Fargo Bank, Rights Agent dated April 28, 1995.N.A. (Incorporated by reference to Exhibit 4.14.3 to our Form 10-Q filed on August 13, 2002,April 29, 2005, File No. 1-10762.)
 
 10.1Form of Employment Agreements (Exhibit 10.19)(Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-26333)).
10.2 Operating 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—Exhibit 10.25)(Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-52436)).

31

10.3Indenture dated November 1, 1997 between Benton Oil and Gas Company and First Trust of New York, National Association, Trustee related to an aggregate of $115,000,000 principal amount of 9 3/8 percent Senior Notes due 2007Commission. (Incorporated by reference to Exhibit 10.1the exhibits to our Registration Statement Form 10-Q for the quarter ended September 30, 1997, FileS-1 (Registration No. 1-10762)33-52436).)

33

 
10.410.2 Note payable agreementPayable Agreement dated March 8, 2001 between Benton-Vinccler,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 PipelinePipeline. (Incorporated by reference to Exhibit 10.24 to our Form 10-Q, filed on May 15, 2001, File No. 1-10762).1-10762.)
 
 10.5Change 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.).
10.610.3 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.).
 
 10.7First 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.).
10.810.4 Sale 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.)
 
 10.910.5 2001 Long Term Stock Incentive PlanPlan. (Incorporated by reference to Exhibit 4.1 to our S-8 (Registration Statement No. 333-85900).).
 
 10.1010.6 Addendum No. 2 to Operating ServicesService Agreement Monagas SUR dated 19th19th September, 2002. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
 
 10.1110.7 Bank Loan Agreement between Banco Mercantil, C.A. and Benton-VincclerHarvest 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.)
 
 10.1210.8 Guaranty 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.)
 
 10.13Employment 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.)
10.14Employment 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.)
10.15Employment 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.)
10.1610.9† 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.)
 
 10.1710.10 Sale 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.)
 
 10.11† 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).)
 
 10.12† 10.18Indemnification Agreement between Harvest Natural Resources, Inc. and the Directors and Executive Officers of the Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
10.13† Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
10.14†Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
10.15†Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.22 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
10.16The Transitory Agreement between Harvest Natural Resources, Inc. and PDVSA Petroleo S.A., dated August 4, 2005. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

34

10.17† Employment Agreement dated November 17, 2003September 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.)

32

 
 10.18† Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Karl L. Nesselrode.Kerry R. Brittain. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
 
 10.19† 21.1Employment 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.)
10.20† 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.)
10.21†Employment Agreement dated September 26, 2005 between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
10.22†Separation Agreement dated September 30, 2005, between Harvest Natural Resources, Inc. and Dr. Peter J. Hill. (Incorporated by reference to Exhibit 10.7 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
10.23†Consulting Agreement dated October 1, 2005, between Harvest Natural Resources, Inc. and Dr. Peter J. Hill. (Incorporated by reference to Exhibit 10.8 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
10.24†Stock Options Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston.
10.25†Stock Options Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston.
10.26†Stock Options Agreement dated September 26, 2005 between Harvest Natural Resources, Inc. and Byron A. Dunn.
21.1 List of subsidiaries.
 
 23.1 Consent of PricewaterhouseCoopers LLP -— Houston
 
 23.2 Consent of ZAO PricewaterhouseCoopers Audit -— Moscow
 
 23.3 Consent of Ryder Scott Company, LP
 
 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.
 
 32.1 CertificationsCertification accompanying the annual reportAnnual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.2002 executed by James A. Edmiston, President and Chief Executive Officer.
32.2Certification accompanying Annual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer.
†Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K.

35

(b) Reports on Form 8-K

     On October 10, 2003, we filed a Current Report on Form 8-K disclosing the Unaudited Pro Forma results from the sale of our minority equity investment in Geoilbent.

     On November 6, 2003, we filed a Current Report on Form 8-K announcing our third quarter and nine months net income and earnings.

33

REPORT OF INDEPENDENT AUDITORS

Report of Independent Registered Public Accounting Firm
To the Board of Directors
and Stockholders of Harvest Natural Resources, Inc.

:

We have completed integrated audits of Harvest Natural Resources, Inc.’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its December 31, 2003 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) present fairly, in all material respects, the financial position of Harvest Natural Resources, Inc. and its subsidiaries at December 31, 20032005 and 2002,December 31, 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20032005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement Schedule II – Valuation and Qualifying Accounts listedschedule in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; ourmanagement. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditingthe standards generally accepted inof the United States of America, whichPublic Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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.

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

Also as discussed in Note 1 to the consolidated financial statements, the Company’s total consolidated revenues relate to operations in Venezuela. As discussed in Note 3 SENIAT, the Venezuelan income tax authority has presented the Company’s Venezuelan subsidiary with preliminary tax assessments for the years 2001 through 2004 totaling approximately USD 94 million (Bolivars 202 billion), including penalties and interest. As discussed in Note 8 the Venezuelan subsidiary has also signed a Transitory Agreement with Petroleos de Venezuela S.A. (PDVSA) which obligates the parties to negotiate in good faith the conversion of the Subsidiary’s Operating Service Agreement to a Mixed Company under the Venezuelan Organic Hydrocarbon Law.

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, 2005 based on criteria established inInternal Control — Integrated Frameworkissued 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, 2005, based on criteria established inInternal Control — Integrated Frameworkissued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting 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.
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
March 4, 2004

February 27, 2006

S-1

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
             
      December 31,
      
      2003 2002
      
 
      (in thousands, except per
      share data)
    ASSETS        
Current Assets:        
 Cash and cash equivalents $138,660  $64,501 
 Restricted cash  12   1,812 
 Marketable securities  —   27,388 
 Accounts and notes receivable:        
  Accrued oil sales  32,766   27,359 
  Joint interest and other, net  11,197   8,002 
 Prepaid expenses and other  805   2,969 
    
   
 
   Total Current Assets  183,440   132,031 
Restricted Cash  16   16 
Other Assets  2,080   2,520 
Deferred Income Taxes  4,749   4,082 
Investments In and Advances To Affiliated Companies  —   51,783 
Property and Equipment:        
 Oil and gas properties (full cost method-costs of $2,900 excluded from amortization in 2003 and 2002, respectively)  593,622   576,601 
 Other administrative property  8,948   7,503 
    
   
 
   602,570   584,104 
 Accumulated depletion, depreciation, and amortization  (418,507)  (439,344)
    
   
 
   Net Property and Equipment  184,063   144,760 
    
   
 
  $374,348  $335,192 
    
   
 
    LIABILITIES AND STOCKHOLDERS’ EQUITY        
Current Liabilities:        
 Accounts payable, trade and other $4,163  $3,804 
 Accounts payable, related party  10,375   9,779 
 Accrued expenses  15,251   10,865 
 Accrued interest payable  1,427   1,405 
 Income taxes payable  8,647   6,880 
 Commodity hedging contract  —   430 
 Current portion of long-term debt  6,367   1,867 
    
   
 
   Total Current Liabilities  46,230   35,030 
Long-Term Debt  96,833   104,700 
Asset Retirement Liability  1,459   — 
Commitments and Contingencies  —   — 
Minority Interest  30,113   24,145 
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, 2003 and 2002; issued 36,405 shares and 35,900 shares at December 31, 2003 and 2002, respectively  364   359 
 Additional paid-in capital  175,051   173,559 
 Retained earnings  27,537   234 
 Treasury stock, at cost, 730 shares and 650 shares at December 31, 2003 and 2002, respectively  (3,239)  (2,835)
    
   
 
   Total Stockholders’ Equity  199,713   171,317 
    
   
 
  $374,348  $335,192 
    
   
 

         
  December 31, 
  2005  2004 
  (in thousands, except per 
  share data) 
ASSETS        
         
Current Assets:        
Cash and cash equivalents $163,019  $84,600 
Restricted cash  —   12 
Accounts and notes receivable:        
Accrued oil and gas sales  60,900   58,937 
Joint interest and other, net  10,750   12,780 
Put options  —   14,209 
Deferred income tax  3,052   251 
Prepaid expenses and other  2,149   1,426 
       
Total Current Assets  239,870   172,215 
Restricted Cash  —   16 
Other Assets  1,600   2,072 
Deferred Income Taxes  —   6,034 
Property and Equipment:        
Oil and gas properties (full cost method-costs of $2,900 excluded from amortization in 2005 and 2004, respectively)  641,684   631,082 
Other administrative property  9,568   10,008 
       
   651,252   641,090 
         
Accumulated depletion, depreciation, and amortization  (491,924)  (453,941)
       
Net Property and Equipment  159,328   187,149 
       
  $400,798  $367,486 
       
         
LIABILITIES AND STOCKHOLDERS’ EQUITY        
Current Liabilities:        
Accounts payable, trade and other $408  $8,428 
Accounts payable, related party  9,203   11,063 
Accrued expenses  21,081   29,426 
Deferred revenue  6,728   — 
Income taxes payable  18,909   22,475 
Current portion of long-term debt  5,467   11,833 
       
Total Current Liabilities  61,796   83,225 
Long-Term Debt  —   — 
Asset Retirement Liability  2,129   1,941 
Commitments and Contingencies  —   — 
Minority Interest  39,361   39,131 
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, 2005 and 2004; issued 37,757 shares and 37,544 shares at December 31, 2005 and 2004, respectively  378   375 
Additional paid-in capital  188,242   185,183 
Retained earnings  112,736   61,897 
Accumulated other comprehensive loss  —   (487)
Treasury stock, at cost, 770 shares and 764 shares at December 31, 2005 and 2004, respectively  (3,844)  (3,779)
       
Total Stockholders’ Equity  297,512   243,189 
       
  $400,798  $367,486 
       
See accompanying notes to consolidated financial statements.

S-2

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
              
   Years Ended December 31,
   
   2003 2002 2001
   
 
 
   (in thousands, except per share data)
Revenues
            
 Oil sales $103,920  $127,015  $122,386 
 Gas sales  2,740   —   — 
 Ineffective hedge activity  (565)  (284)  — 
   
   
   
 
   106,095   126,731   122,386 
   
   
   
 
Expenses
            
 Operating expenses  30,893   33,950   42,759 
 Depletion, depreciation and amortization  21,188   26,363   25,516 
 Write-downs of oil and gas properties and impairments  165   14,537   468 
 General and administrative  15,746   16,504   20,072 
 Arbitration settlement  1,477   —   — 
 Bad debt recovery  (374)  (3,276)  — 
 Taxes other than on income  3,373   4,068   5,370 
   
   
   
 
   72,468   92,146   94,185 
   
   
   
 
Income from Operations  33,627   34,585   28,201 
Other Non-Operating Income (Expense)            
 Gain on disposition of assets  46,619   144,029   — 
 Gain on early extinguishment of debt  —   874   — 
 Investment earnings and other  1,418   2,080   3,088 
 Interest expense  (10,405)  (16,310)  (24,875)
 Net gain on exchange rates  529   4,553   768 
   
   
   
 
   38,161   135,226   (21,019)
   
   
   
 
Income from Consolidated Companies Before Income            
 Taxes and Minority Interest  71,788   169,811   7,182 
Income Tax Expense (Benefit)  9,657   60,295   (35,698)
   
   
   
 
Income Before Minority Interest  62,131   109,516   42,880 
Minority Interest in Consolidated Subsidiary Companies  5,968   9,319   5,545 
   
   
   
 
Income from Consolidated Companies  56,163   100,197   37,335 
Equity in Net Income (Losses) of Affiliated Companies  (28,860)  165   5,902 
   
   
   
 
Net Income $27,303  $100,362  $43,237 
   
   
   
 
Net Income Per Common Share:            
 Basic $0.77  $2.90  $1.27 
   
   
   
 
 Diluted $0.74  $2.78  $1.27 
   
   
   
 

AND COMPREHENSIVE INCOME

             
  Years Ended December 31, 
  2005  2004  2003 
  (in thousands, except per share data) 
Revenues
            
Oil sales $210,493  $154,075  $103,920 
Gas sales  26,448   31,991   2,740 
Ineffective hedge activity  —   —   (565)
          
   236,941   186,066   106,095 
          
             
Expenses
            
Operating expenses  39,723   33,324   30,893 
Depletion, depreciation and amortization  43,968   36,020   21,188 
Write-downs of oil and gas properties and impairments  —   —   165 
General and administrative  22,819   21,857   15,746 
Account receivable write-off on retroactive oil price adjustments  4,548   —   — 
Arbitration settlement  —   —   1,477 
Bad debt recovery  —   (598)  (374)
Gain on sale of long-lived asset  —   (578)  — 
Taxes other than on income  6,358   5,561   3,373 
          
   117,416   95,586   72,468 
          
             
Income from Operations  119,525   90,480   33,627 
Other Non-Operating Income (Expense)            
Gain on disposition of investment  —   —   46,619 
Gain (loss) on early extinguishment of debt  —   (2,928)  — 
Investment earnings and other  4,205   2,085   1,418 
Interest expense  (3,388)  (7,749)  (10,405)
Net gain (loss) on exchange rates  2,752   (622)  529 
          
   3,569   (9,214)  38,161 
          
             
Income from Consolidated Companies Before Income Taxes and Minority Interest  123,094   81,266   71,788 
Income Tax Expense  57,025   33,288   9,657 
          
Income Before Minority Interest  66,069   47,978   62,131 
Minority Interest in Consolidated Subsidiary Companies  15,230   13,618   5,968 
          
Income from Consolidated Companies  50,839   34,360   56,163 
Equity in Net Losses of Affiliated Company  —   —   (28,860)
          
Net Income $50,839  $34,360  $27,303 
          
             
Net Income Per Common Share:            
Basic $1.38  $0.95  $0.77 
          
Diluted $1.32  $0.90  $0.74 
          
             
Other comprehensive loss:            
Unrealized mark to market loss from cash flow hedging activities, net of tax  —   (487)  — 
          
Comprehensive income $50,839  $33,873  $27,303 
          
See accompanying notes to consolidated financial statements.

S-3

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)
                          
               Retained        
   Common     Additional Earnings        
   Shares Common Paid-in (Accumulated Treasury    
   Issued Stock Capital Deficit) Stock Total
   
 
 
 
 
 
Balance at January 1, 2001
  33,872  $339  $156,629  $(143,365) $(699) $12,904 
Issuance of common shares:                        
 Non-employee director compensation  292   3   471   —   —   474 
Tax benefits related to stock option compensation  —   —   11,008   —   —   11,008 
Net Income  —   —   —   43,237   —   43,237 
   
   
   
   
   
   
 
Balance at December 31, 2001
  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 
   
   
   
   
   
   
 

                             
                  Accumulated       
  Common      Additional      Other       
  Shares  Common  Paid-in  Retained  Comprehensive  Treasury    
  Issued  Stock  Capital  Earnings  Gain(Loss)  Stock  Total 
Balance at January 1, 2003
  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 
                             
Issuance of common shares:                            
Exercise of stock options  240   3   829   —   —   —   832 
Employee stock-based compensation  74   —   2,230   —   —   —   2,230 
Treasury stock (5 shares)  —   —   —   —   —   (65)  (65)
Accumulated other comprehensive gain  —   —   —   —   487   —   487 
Net Income  —   —   —   50,839   —   —   50,839 
                      
                             
Balance at December 31, 2005
  37,858  $378  $188,242  $112,736  $—  $(3,844) $297,512 
                      
See accompanying notes to consolidated financial statements.

S-4

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
                
     Years Ended December 31,
     
     2003 2002 2001
     
 
 
     (in thousands)
Cash Flows From Operating Activities:            
 Net income $27,303  $100,362  $43,237 
 Adjustments to reconcile net income to net cash provided by operating activities:            
  Depletion, depreciation and amortization  21,188   26,363   25,516 
  Write-down and impairment of oil and gas properties  165   14,537   468 
  Amortization of financing costs  497   1,745   1,179 
  Gain on disposition of assets  (46,619)  (144,029)  (336)
  Equity in net earnings (losses) of affiliated companies  28,860   (165)  (5,902)
  Allowance for employee notes and accounts receivable  (169)  (2,987)  365 
  Non-cash compensation related charges  296   1,458   474 
  Minority interest in undistributed earnings of subsidiaries  5,968   9,319   5,545 
  Gain from early extinguishment of debt  —   (874)  — 
  Tax benefits related to stock option compensation  —   —   11,008 
  Deferred income taxes  (667)  53,618   (53,407)
 Changes in operating assets and liabilities:            
  Accounts and notes receivable  (7,935)  (1,972)  11,756 
  Prepaid expenses and other  2,164   (1,130)  565 
  Accounts payable  359   (4,328)  (4,671)
  Accounts payable, related party  4,386   (604)  (1,662)
  Accrued interest payable  22   (2,489)  161 
  Accrued expenses  (76)  (9,686)  1,705 
  Asset retirement liability  1,459   —   — 
  Commodity hedging contract  (430)  430   — 
  Income taxes payable  1,767   3,059   607 
   
   
   
 
   Net Cash Provided by Operating Activities  38,538   42,627   36,608 
   
   
   
 
Cash Flows from Investing Activities:            
 Proceeds from sale of investment  69,500   189,841   — 
 Additions of property and equipment  (60,925)  (43,346)  (43,364)
 Investment in and advances to affiliated companies  2,328   9,185   (16,855)
 Increase in restricted cash  —   (2,800)  (57)
 Decrease in restricted cash  1,800   1,000   10,961 
 Purchases of marketable securities  (256,058)  (353,478)  (15,067)
 Maturities of marketable securities  283,446   326,090   16,370 
 Investment selling costs  (1,900)  (349)  (70)
   
   
   
 
  Net Cash Provided by (Used In) Investing Activities  38,191   126,143   (48,082)
   
   
   
 
Cash Flows from Financing Activities:            
 Net proceeds from exercise of stock options  1,201   3,345   — 
 Purchase of treasury stock  (404)  —   — 
 Proceeds from issuance of notes payable  —   15,500   21,112 
 Payments on notes payable  (3,367)  (132,138)  (15,746)
   
   
   
 
  Net Cash Provided by (Used In) Financing Activities  (2,570)  (113,293)  5,366 
   
   
   
 
  Net Increase (Decrease) in Cash and Cash Equivalents  74,159   55,477   (6,108)
Cash and Cash Equivalents at Beginning of Year  64,501   9,024   15,132 
   
   
   
 
Cash and Cash Equivalents at End of Year $138,660  $64,501  $9,024 
   
   
   
 
Supplemental Disclosures of Cash Flow Information:            
 Cash paid during the year for interest expense $13,241  $19,201  $25,721 
   
   
   
 
 Cash paid during the year for income taxes $4,254  $3,935  $3,057 
   
   
   
 

             
  Years Ended December 31, 
  2005  2004  2003 
      (in thousands)     
Cash Flows From Operating Activities:            
Net income $50,839  $34,360  $27,303 
Adjustments to reconcile net income to net cash provided by operating activities:            
Depletion, depreciation and amortization  43,968   36,020   21,188 
Write-down of oil and gas properties and impairment  —   —   165 
Amortization of financing costs  —   228   497 
Gain on disposition of assets and investments  —   (578)  (46,619)
Write off of unamortized financing costs  —   936   — 
Account receivable write-off on retroactive oil price adjustments  4,548   —   — 
Equity in net losses of affiliated companies  —   —   28,860 
Allowance for employee notes and accounts receivable  —   (598)  (169)
Deferred compensation expense  (745)  1,521   306 
Non-cash compensation related charges  2,230   2,152   296 
Minority interest in consolidated subsidiary companies  15,230   13,618   5,968 
Deferred income taxes  2,982   (1,285)  (667)
Changes in operating assets and liabilities:            
Accounts and notes receivable  (4,481)  (27,156)  (7,935)
Prepaid expenses and other  (723)  (621)  2,164 
Commodity hedging contract  14,947   (14,947)  (430)
Accounts payable  (8,020)  4,265   359 
Accounts payable, related party  (1,860)  506   4,408 
Accrued expenses  (7,600)  11,409   (382)
Deferred revenue  6,728   —   — 
Asset retirement liability  188   482   1,459 
Income taxes payable  (3,566)  13,828   1,767 
          
Net Cash Provided by Operating Activities  114,665   74,140   38,538 
          
Cash Flows from Investing Activities:            
Proceeds from sale of investment  —   —   69,500 
Proceeds from sale of long-lived assets  —   578   — 
Additions of property and equipment  (16,147)  (39,106)  (60,925)
Investment in and advances to affiliated companies  —   —   2,328 
Decrease in restricted cash  28   —   1,800 
Purchases of marketable securities  —   —   (256,058)
Maturities of marketable securities  —   —   283,446 
Investment costs  472   (1,156)  (1,900)
          
Net Cash Provided by (Used In) Investing Activities  (15,647)  (39,684)  38,191 
          
Cash Flows from Financing Activities:            
Net proceeds from issuances of common stock  767   7,451   1,201 
Purchase of treasury stock  —   —   (404)
Payments of note payable  (6,366)  (91,367)  (3,367)
Dividend paid to minority interest  (15,000)  (4,600)  — 
          
Net Cash Used In Financing Activities  (20,599)  (88,516)  (2,570)
          
Net Increase (Decrease) in Cash and Cash Equivalents  78,419   (54,060)  74,159 
Cash and Cash Equivalents at Beginning of Year  84,600   138,660   64,501 
          
Cash and Cash Equivalents at End of Year $163,019  $84,600  $138,660 
          
Supplemental Disclosures of Cash Flow Information:            
Cash paid during the year for interest expense $795  $12,541  $13,241 
          
Cash paid during the year for income taxes $20,991  $11,705  $4,254 
          
See accompanying notes to consolidated financial statements.

S-5

Supplemental Schedule of Noncash Investing and Financing Activities:

     During the year ended 2005, we issued 0.1 million shares of restricted stock valued at $0.8 million and Dr. Peter J. Hill, our former Chief Executive Officer, elected to pay withholding tax on a 2002 restricted stock grant on a cashless basis. This resulted in 5,497 shares being held as treasury stock at cost.
     During the year ended 2004, 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 (“2007 Notes”). Also during the year ended 2004, the holders of our warrants elected to exercise 45,000 warrants on a cashless basis by delivering Company shares to us. This resulted in the issuance of 34,054 shares which are held as treasury stock at cost.
     For the three yearsyear ended December 31, 2003, we recorded an allowance for doubtful accounts related to interest accrued on the remaining amountan account receivable owed to us by oura former chief executive officer, A. E. Benton.employee. During the yearyears ended December 31,2004 and 2003, we reversed a portion of such allowance as a result of our collection of certain amounts owed to the Companyus including the portions of the note secured by our stock and other properties (seeNote 13 – Related Party Transactions).

properties.

See accompanying notes to consolidated financial statements.

S-6

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 engaged in the exploration, development, production and management of oil and natural gas properties. We conduct our business principally in Venezuela (Benton -Vinccler C.A. or “Benton-Vinccler”) and, until September 25, 2003, through our minority equity investment in LLC Geoilbent, a Russian entity.

80 percent-owned subsidiary Harvest Vinccler C.A. (“Harvest Vinccler”).

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 for our investment in LLC Geoilbent (“Geoilbent”) and Arctic Gas Company (“Arctic Gas”), prior to the sale of our interests,interest, based on a fiscal year ending September 30 (seeNote 2 – Investments In and Advances to Affiliated Companies).

30.

Reporting and Functional Currency

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

Revenue Recognition

     Oil and natural gas revenue is accrued monthly based on production and delivery. Each quarter, Benton-VincclerHarvest Vinccler invoices PDVSA Petroleo S.A., an affiliate of Petroleos de Venezuela S.A. (“PDVSA”) or affiliates, based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. dollarDollar contract service fees per barrel. The operating service agreementrelated Operating Service Agreement (“OSA”) with PDVSA provides for Benton-VincclerHarvest 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 cannot 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 provides 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 approximates 47 percent of West Texas Intermediate (“WTI”). 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. Each quarter, Benton-VincclerHarvest Vinccler also invoices PDVSA for natural gas sales based on a fixed price of $1.03 per Mcf. In addition, Benton-VincclerHarvest 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 is invoiced to PDVSA quarterly at a fixed price of $7.00 per Bbl.

The invoices are prepared and submitted to PDVSA by the end of the first month following the end of each calendar quarter, and payment is due from PDVSA by the end of the second month following the end of each calendar quarter. Harvest Vinccler invoiced PDVSA for the first and second quarters of 2005 for the delivery of its crude oil and natural gas in accordance with the original OSA terms and recognized its revenue in a manner consistent with prior periods. The retroactive application of the new maximum total fee limitation under the Transitory Agreement resulted in a write-off of $4.5 million of the PDVSA receivable in the third quarter 2005. All oil and natural gas revenues are now recorded based on the Transitory Agreement. However, Harvest Vinccler recorded deferred revenue of $6.7 million 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.

Restricted Cash

     Restricted cash represents At December 31, 2005, Harvest Vinccler had 45.5 billion Venezuela Bolivars (“Bolivars”) which are shown in the December 31, 2005 financial statements as $21.2 million in cash and cash equivalents used as collateral for financing, letterequivalents. Harvest Vinccler expects to be able to utilize the Bolivars received to date. However, to the extent that Harvest Vinccler receives additional Bolivars in excess of credit and loan agreements, and is classified as current or non-current based on the terms of the agreements.

Marketable Securities

     Marketable securities are carried at cost. The marketable securities we may purchase are limited to those defined as Cash Equivalents in the indentures for our senior unsecured note. Cash Equivalentsits internal needs, there may be comprisedlimited means to convert excess Bolivars into U.S. Dollars or other foreign currencies, and there would be a loss on any conversion where the exchange rate is above the official rate of high-grade debt instruments, demand or time deposits, certificates of deposit and commercial paper of highly rated2,150 Bolivars to the U.S. corporations, all having maturities of no more than 180 days. Our marketable securities at cost, which approximates fair value, consisted of $27.4 million in commercial paper at December 31, 2002.

Dollar.

S-7

Credit Risk and Operations

     All of our total consolidated revenues relate to operations in Venezuela. During the yearyears ended December 31, 2003,2005 and 2004, our Venezuelan crude oil and natural gas production represented all of our total production from consolidated companies, and our sole source of revenues related to such Venezuelan production is PDVSA, which maintains full ownership of all hydrocarbons in its fields. On December 2, 2002, employers’ and workers’ organizations, together with political and civic organizations began a national civic work stoppage, which has seriously affected many of the country’s economic activities, in particular, the oil industry. As a result of the strike, we were unable to deliver crude oil and hence generate revenues from PDVSA between December 14, 2002 andIn 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 thecurrent official exchange rate at 1,600is 2,150 Bolivars for each U.S. dollar and created 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 believesDollar. We believe that we have sufficient cash and doesdo not expect the currency conversion restrictions to adversely affect our ability to meet our short-term obligations.

obligations and operating requirements for the next twelve months.

Derivatives and Hedging

     Statement of Financial Accounting Standards No. 133 (“SFAS 133”), as amended, establishes accounting and reporting standards for derivative instruments and hedging activities. In order for a derivative instrument to qualify for hedge accounting, there must be a clear correlation between the derivative instrument and the forecasted transaction. For all derivatives designated as cash flow hedges, we formally document the relationship between the derivative contract and the hedged item, as well as the risk management objective for entering into the contract. To be designated as a cash flow hedge transaction, the relationship between the derivative and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis. 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 arehave 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 transactions. These derivative instruments have been designated as a cash flow hedge and theoil production. The changes in the fair value hasof these derivative instruments have been reported in other comprehensive income assumingbecause the highly effective test was met, and have been reclassified to earnings in the period in which earnings arewere impacted by the variability of the cash flows of the hedged item. We measure the hedge effectiveness on a quarterly basis and hedge accounting is discontinued prospectively if it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item.

     Benton-Vinccler

     Harvest Vinccler hedged a portion of its 2003 oil sales by purchasing a WTI crude oil “put”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. This put qualified under the highly effective test. 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 iswas $2.50 per barrel, or $7.7 million, and had a strike price of $30.00 per barrel. SettlementsThe 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 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 had 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 had 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 had the economic effect of hedging approximately 21,500 barrels of oil per day for an average of $17.72 per barrel. These puts qualify under the highly effective test and the mark-to-market 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 have been reflected as amillion. Deferred net reduction to oil revenue.

     Benton-Vinccler hedged a portion of its 2002 oil sales by purchasing a commodity contract (costless collar), which required payment to (or receipts from) counterparties based on a WTI floor price of $23.00 and a ceiling price of $30.15 for 6,000 barrels of oil per day. The collar qualified under the highly effective test. Atlosses recorded in Accumulated Other Comprehensive Loss at December 31, 2002, we determined that the underlying crude oil would not be delivered due2004 were reclassified to the cessation of production. Accordingly, hedge accounting was discontinuedearnings during 2005. All hedging instruments expired under their own terms on December 31, 2005.

     We continue to assess production levels and the value of the derivative was recorded as an oil revenue reductioncommodity prices in the amount of $0.3 million.

     The notional amount of each financial instrument is based on expected sales of crude oil production from existingconjunction with our capital resources and future development wells and the related incremental oil production associated with production from high gas-to-oil ratio wells after the installation of a gas pipeline. These instruments protect our projected investment return and cash flow derived from our production by reducing the impact of a downward crude oil price movement until their expiration.

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liquidity requirements.

Asset Retirement Liability

     Effective January 1, 2003, we adopted

     Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). As a result of adopting this statement, Benton-Vinccler recorded under the full cost method of accounting for oil and gas properties an increase in oil and gas properties as well as a corresponding liability in the amount of $4.3 million. This asset retirement obligation is associated with the plugging and abandonment of certain wells in Venezuela. (“SFAS 143143”) 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. Historically, we determined that there would be noNo wells to plugwere abandoned in the year ended December 31, 2005 and abandon before returning the fields to PDVSA. In January 2003, one of ournine wells suffered a leakwere abandoned in its casing allowing natural gas to flow to the surface. The well was plugged and abandoned and a comprehensive study of all existing wells was undertaken. This study indicated an increased likelihood that we would have to plug and abandon certain of the wells during the term of the agreement. No prior provision was undertaken and no cumulative adjustment was required. We abandoned 11 wells in 2003.year ended December 31, 2004. Changes in asset retirement obligations during the yearyears ended December 31, 20032005 and 2004 were as follows:
     
Asset retirement obligations as of January 1, 2003 $— 
Liabilities recorded during the first quarter  4,237 
Liabilities settled during the year  (733)
Revisions in estimated cash flows  (2,125)
Accretion expense  80 
   
 		 
Asset retirement obligations as of December 31, 2003 $1,459 
   
 		 

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  December 31,  December 31, 
  2005  2004 
Asset retirement obligations beginning of period $1,941  $1,459 
Liabilities recorded during the period  96   1,454 
Liabilities settled during the period  —   (540)
Revisions in estimated cash flows  (17)  (470)
Accretion expense  109   38 
       
Asset retirement obligations end of period $2,129  $1,941 
       
Accounts and Notes Receivable

     Allowance for doubtful accounts related to former employee notes at December 31, 20032005 and 20022004 was $3.4$2.8 million. During 2004, we received $0.5 million through the exercise of stock options and $3.5$0.1 million respectively (seeNote 13 – Related Party Transactions).

through the excess income provision of a settlement and release agreement.

Other Assets

     Other assets consist of costs associated with the issuance of long-term debt and investigative costs associated with new projects. Debt issuance costs are amortized on a straight-line basis over the life of the debt, which approximates the effective interest method of amortizing these costs. New project 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 the full cost method of accounting for oil and natural gas properties with costs accumulated in cost centers on a country-by-country basis, subject to a cost center ceiling (as defined by the Securities and Exchange Commission [“SEC”]). All costs associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized as incurred, including exploration overhead of $0.6 million for the year ended December 31, 2001, and capitalized interest of $0.5 million and $0.9 million for the years ended December 31, 2002 and 2001, respectively. There was no capitalized overhead in 2003 and 2002, and no capitalized interest in 2003.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.

     The costs of unproved properties are excluded from amortization until the properties are evaluated. At least annuallyquarterly 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, 2002 and 2001, we recognized $0.2 million $14.5 million and $0.5 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, 20032005 consisted of property acquisition costs in the amount of $2.9 million which were all incurred prior to 2001. All of the excluded costs at December 31, 20032005 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.

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     Statement of Financial Accounting Standards No. 141 – Business Combinations (“FAS 141”) and No. 142 – Goodwill and Other Intangible Assets (“FAS 142”) included new terminology on the disclosure of what constitutes an intangible asset. One interpretation being considered relative to these standards is that a mineral interest associated with proved and undeveloped oil and gas leasehold acquisition costs should be classified separately in Oil and Gas Properties on the Consolidated Balance Sheet as intangible assets, and the disclosures required by FAS 141 and FAS 142 would be included in the Notes to Financial Statements. We believe that the presentation and disclosure of the $2.9 million excluded costs attributed to the China cost center is appropriate pending further guidance on this matter.

     All capitalized costs (including oilfield inventory and future abandonment costs under SFAS 143) and estimated future development costs (including estimated dismantlement, restoration and abandonment costs) of proved reserves are depleted using the units of production method based on the total proved reserves of the country cost center. Depletion expense, which was substantially all attributable to the Venezuelan cost center for the years ended December 31, 2005, 2004 and 2003 2002was $41.2 million, $34.1 million and 2001 was $19.6 million $24.9 million and $22.1 million ($2.52,3.16, $2.56 and $2.26$2.52 per equivalent barrel), respectively.

     A gain or loss is recognized on the sale of oil and natural 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.

     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

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over the life of the applicable lease. Depreciation expense was $1.6$2.8 million, $1.4$1.9 million and $3.4$1.6 million for the years ended December 31, 2005, 2004 and 2003, 2002 and 2001, respectively.

     The major components of property and equipment at December 31 are as follows (in thousands):
               
 2003
 2002
 2005 2004 
Proved property costs $582,456 $566,415  $630,634 $621,679 
Costs excluded from amortization 2,900 2,900  2,900 2,900 
Material and supply inventories 8,266 7,286 
Oilfield inventories 8,150 6,503 
Other administrative property 8,948 7,503  9,568 10,008 
 
 		 
 		      
 602,570 584,104  651,252 641,090 
Accumulated depletion, impairment and depreciation  (418,507)  (439,344)  (491,924)  (453,941)
 
 		 
 		      
 $184,063 $144,760  $159,328 $187,149 
 
 		 
 		      

     We perform a quarterly cost center ceiling test of our oil and natural 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 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.

2005 or 2004.

Stock-Based Compensation

     At December 31, 20032005 and 2002,2004, we had several stock-based employee compensation plans, which are more fully described inNote 65 – 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 Statement No. 123 (“FAS 123”), Accounting for Stock-Based Compensation as amended by Statement of Financial accounting Standards No. 148 (“SFAS 148”), prospectively to all employee awards granted, modified, or settled after January 1, 2003. Effective January 1, 2005, we adopted Statement of Financial Accounting Standard 123 (revised 2004) Share-Based Payment (“SFAS 123R”) to all employee awards granted, modified, or settled after October 1, 2005. The effect of adopting 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 years ended December 31, 20032005 and 20022004 are less than that which would have been 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.

             
  2005  2004  2003 
Net income, as reported $50,839  $34,360  $27,303 
             
Add: Stock-based employee compensation cost, net of tax  2,635   999   296 
             
Less: Total stock-based employee compensation cost determined under fair value based method, net of tax  (2,711)  (1,382)  (1,056)
          
             
Net income – proforma $50,763  $33,977  $26,543 
          
Net income per common share:            
Basic – as reported $1.38  $0.95  $0.77 
          
Basic – proforma $1.37  $0.94  $0.75 
          
             
Diluted – as reported $1.32  $0.90  $0.74 
          
Diluted – proforma $1.32  $0.89  $0.72 
          
     Stock options of 0.2 million, 1.1 million and 0.5 million were exercised in the years ended December 31, 2005, 2004 and 2003, respectively, with cash proceeds of $0.8 million, $8.0 million and $1.2 million, respectively.

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  2003
 2002
 2001
Net income, as reported $27,303  $100,362  $43,237 
Add: Stock-based employee compensation cost, net of tax  296   915   35 
Less: Total stock-based employee compensation cost determined under fair value based method, net of tax  (1,056)  (2,905)  (2,459)
   
 		   
 		   
 		 
Net income – proforma $26,543  $98,372  $40,813 
   
 		   
 		   
 		 
Net income per common share:            
Basic – as reported $0.77  $2.90  $1.27 
   
 		   
 		   
 		 
Basic – proforma $0.75  $2.87  $1.20 
   
 		   
 		   
 		 
Diluted – as reported $0.74  $2.78  $1.27 
   
 		   
 		   
 		 
Diluted – proforma $0.72  $2.75  $1.20 
   
 		   
 		   
 		 

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. In the third quarter of 2003, a portion of the valuation allowance was reversed based on the utilization of net operating losses which offset U.S. taxable income generated by the sale of our minority equity investment in Geoilbent.

Foreign Currency

     We have significant operations outside of the United States, principally in Venezuela and, until September 25, 2003, a minority equity investment in Russia. The U.S. dollarDollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in U.S. dollars,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.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 purchasespays for 100 percent of our Venezuelan oil and natural gas production.production under the terms of the operating service agreement and the Transitory Agreement. Although we do not currently foresee a credit risk associated with these receivables, collection is dependent upon the financial stability of PDVSA. The payment for the fourth quarter 2002 sales, which was due February 28, 2003, was delayed until March 7, 2003, which was approximately seven days late due to the effect of the national civil work stoppage on PDVSA.

     The book values of all financial instruments, other than long-term debt, 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 and 2002, was approximately $85.0 million and $77.4 million, respectively.

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-

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market gains/(losses)mark-to-market losses from cash flow hedging activities as other comprehensive income/(loss)loss during the yearsyear ended December 31, 20032004 and 2002.

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 Venezuela and Barbados subsidiaries. The minority interests in net income and losses are generally subtracted from or added to arrive at consolidated net income.

New Accounting Pronouncements

     In May 2003,March 2005, the Financial Accounting Standards Board (“FASB”FASB’) issued Statement of Financial Accounting Standard No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (the “Statement”). The Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The Statement is generally effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this Statement had no effect on our consolidated financial statements.

     In January 2003, the FASB issuedStaff Interpretation No. 46 (“FIN 46”)46(R) — 5 Consolidation of Variable Interest Entities (“FSP FIN 46(R) — 5”), which addresses the consolidation of variable interest entities (“VIEs”) by business enterprises that are the primary beneficiaries. A VIEFSP FIN 46(R) — 5 is an entity that does not have sufficient equity investment at riskapplicable 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 majority of the risks 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,both nonpublic and to defer certain entities from adopting until the end of the first interim or annualpublic reporting period ending after March 15, 2004.enterprises. 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 types of VIEs is required in financial statements for periods endingthe first reporting period beginning after March 3, 2005 in accordance with the transition provisions of FSP FIN 46(R) — 5. The adoption of this interpretation will not impact our consolidated financial position, results of operations or cash flows.

     In April 2005, the FASB issued Staff Interpretation No. 19-1 (“FSP 19-1”) Accounting for Suspended Well Costs, which provides guidance on the accounting for exploratory well costs and proposes an amendment to FASB Statement No. 19 (“FASB 19”), Financial Accounting and Reporting by Oil and Gas Producing Companies. The

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guidance in FSP 19-1 applies to enterprises that use the successful efforts method of accounting as described in FASB 19. The guidance in FSP 19-1 will not impact our consolidated financial position, results of operations or cash flows.
     In June 2005, the Financial Accounting Standards Board (“FASB’) issued Statement of Financial Accounting Standard 154 – Accounting Changes and Error Corrections (“SFAS 154”), which changes the requirements for the accounting for and reporting of a change in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. Application is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2004. We believe we2005. Early adoption is permitted. The adoption of SFAS 154 is not expected to have no arrangements that would require the applicationa material effect on our consolidated financial position, results of FIN 46R. We have no material 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 America 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 20012003 and 20022004 have been reclassified to conform to the 20032005 financial statement presentation.

Note 2 — Investments In and Advances To Affiliated Companies

     On September 25, 2003, we sold our minority equity investment in Geoilbent to Yukos Operational Holding Limited and recognized a pre-tax gain on the sale of $46.6 million (seeNote 9 – Russian Operations). Prior to the sale, our 34 percent minority equity investment in Geoilbent was accounted for using the equity method due to the significant influence we exercised over their operations and management. Investments included amounts paid to the investee company for shares of stock and other costs incurred associated with the acquisition and evaluation of technical data for the oil fields operated by the investee company. Equity in earnings of Geoilbent is based on a fiscal year ending September 30. No dividends have been paid to us from Geoilbent.

     Equity in earnings and losses and investments in and advances to Geoilbent are as follows (in thousands):

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  LLC Geoilbent
  2003
 2002
Investments:        
In equity in net assets $—  $28,056 
Other costs, net of amortization  —   (263)
   
 		   
 		 
Total investments  —   28,319 
Advances  —   2,527 
Equity in earnings  —   20,937 
   
 		   
 		 
Total $—  $51,783 
   
 		   
 		 

Note 3 — Long-Term Debt and Liquidity

Long-Term Debt

     Long-term debt consists of the following (in thousands):
                
 December 31, December 31, December 31, December 31, 
 2003
 2002
 2005 2004 
Senior unsecured notes with interest at 9.375% 
Note payable with interest at 9.0% 
See description below $85,000 $85,000  $300 $1,500 
Note payable with interest at 6.1% 
See description below 2,700 3,900 
Note payable with interest at 39.7% 
See description below — 2,167 
Note payable with interest at 7.1% 15,500 15,500 
Note payable with interest at 10.1% 5,167 10,333 
 
 		 
 		      
 103,200 106,567  5,467 11,833 
Less current portion 6,367 1,867  5,467 11,833 
 
 		 
 		      
 $96,833 $104,700  $— $— 
 
 		 
 		      

     In November 1997, we issued $115.0 million in 9.375 percent senior unsecured notes due

     Our 2007 Notes were redeemed on November 1, 2007 (“2007 Notes”),2004, and we were released from all obligations. The redemption of which we repurchased $30.0 million. Interest on the 2007 Notes is due May 1 andtriggered an obligation under the terms of Harvest Vinccler’s U.S. Dollar loans from a Venezuelan commercial bank to renegotiate the terms of those loans or, if agreement on renegotiated terms could not be reached within 30 days after November 1, of each year. At2004, the loans could be declared due and payable. As a result, the entire amount has been reclassified from long term to current debt. It is possible that agreement will not be reached in negotiated terms and Harvest Vinccler will be required to repay the remaining December 31, 2003, we were in compliance with all covenants2005 balance of the indenture.

$5.5 million.

     In March 2001, Benton-VincclerHarvest 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). 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 thisthe remaining loan.

     In October 2002, Benton-Vinccler, C.A.Harvest Vinccler 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

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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 natural gas sales.

     Benton-Vinccler’s oil and gas pipeline project loans allow the lender to accelerate repayment if production ceases for a period greater than thirty days. During the production shut-in which started in December 2002, Benton-Vinccler was granted a waiver

     We have classified all of this provision until February 18, 2003 in exchange for a prepayment of the next two principal obligations aggregating $0.9 million. This prepayment, while using cash reserves, reduced our net interest expenseoutstanding debt as the current interest expense was more than the current interest income earned on the invested funds. On February 8, 2003, Benton-Vinccler commenced production, thereby eliminating the need for an additional waiver. A future disruption of production could trigger the debt acceleration provision again. While no assurances can be given, we believe Benton-Vinccler would be able to obtain another waiver.

     The terms of the 2007 Notes require that net cash proceeds in excess of $25 million from the sale of Geoilbent must be invested in the oil and gas business within one year of the sale, or any amount not so invested must be used to repay or prepay the 2007 Notes or certain debts of subsidiaries.

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     The principal payment requirements for our long-term debt outstanding at December 31, 2003 are as follows (in thousands):2005.

     
2004 $6,367 
2005  6,367 
2006  5,466 
2007  85,000 
   
 		 
  $103,200 
   
 		 

Liquidity

     We currently have a significant debt obligation payable in November 2007 of $85 million. Our ability to meet our debt obligations and to reduce our level of debt depends on the successful implementation of our strategic objectives. Our cash flow from operations complemented with our cash and cash equivalents of $139 million at December 31, 2003, can be invested in other opportunities used to develop our significant proved undeveloped reserves or used to repurchase our outstanding debt.

Note 43 — Commitments and Contingencies

     We have employment contracts with fivesix 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, 2005.

2006 for five of the executives and on May 7, 2007 for the other executive.

     In July 2001,April 2004, we leasedsigned a ten-year lease for three years office space in Houston, Texas, for approximately $11,000$17,000 per month. Also during 2004, Harvest Vinccler leased office space in Maturin and Caracas, Venezuela for $13,200 and $4,000 per month, respectively. We leaseleased 17,500 square feet of space in a California building that we no longer occupy under a lease agreement that expiresexpired in December 2004, all of which has beenwas subleased for rents that approximateapproximated our lease costs.

Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-Vinccler,Harvest 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. We dispute Excel’s claims and plan to vigorously defend against them.
Uracoa Municipality Tax Assessments. In July 2004, Harvest Vinccler received three tax 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. Harvest Vinccler has filed a motion with the tax court in Barcelona, Venezuela, seeking to enjoin the payment order and dismiss the assessment. We dispute all of the tax assessments and believe we have a substantial basis for our positions.
Libertador Municipality Tax Assessment. In April 2005, Harvest Vinccler received a tax assessment from a tax inspector for the Libertador municipality in which part of the South Monagas Unit is located. Harvest Vinccler has submitted a protest to the assessment at the Mayor’s Office, and if no favorable resolution is obtained, it will file a motion with the tax court seeking to enjoin the payment order and dismiss the assessment. We dispute the allegations set forth in the assessment and believe we have a substantial basis for our position. We are unable to estimate the amount or range of any possible loss.
The SENIAT Tax Assessment. On July 22, 2005, the SENIAT, the Venezuelan income tax authority, issued a preliminary tax assessment to Harvest Vinccler of 184 billion Venezuelan Bolivars related to fiscal years 2001 through 2004. At the official exchange rate of 2,150 Bolivars per U.S. Dollar, the dollar equivalent of the preliminary tax assessment is approximately $85 million. In addition, the SENIAT imposed penalties equal to 10 percent of the preliminary tax assessment claim for a total claim of 202 billion Bolivars, or approximately $94 million. Upon review of the preliminary tax assessment, we determined not to contest two elements of the claim and made payments totaling 11.3 billion Bolivars or $5.3 million in August and September, 2005. In September and October 2005, we filed a response and evidentiary support with the SENIAT contesting all other claims. We believe Harvest Vinccler has met its tax obligations in all material respects. We intend to take all measures necessary to protect our rights, and will vigorously challenge all elements of the tax assessment that are not supported by Venezuelan law.
International Arbitration. As a result of the actions taken by PDVSA, MEP and the SENIAT, in July 2005, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank.

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     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 iswill have a material to us.

adverse impact on our financial condition, results of operations and cash flows.

Note 54 — Taxes

Taxes Other Than on Income

     Benton-Vinccler

     Harvest Vinccler pays a municipal taxtaxes on operating fee revenues it receives for production from the South Monagas Unit. The year ended December 31, 2002 included a non-recurring foreign payroll tax adjustment of $0.7 million. The components of taxes other than on income were (in thousands):
                        
 2003
 2002
 2001
 2005 2004 2003 
Venezuelan municipal taxes $2,741 $3,805 $4,447  $5,788 $4,485 $2,741 
Franchise taxes 341 139 121   (70) 464 341 
Payroll and other taxes 291 124 802  640 612 291 
 
 		 
 		 
 		        
 $3,373 $4,068 $5,370  $6,358 $5,561 $3,373 
 
 		 
 		 
 		        

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Taxes on Income

     The tax effects of significant items comprising our net deferred income taxes as of December 31, 20032005 and 20022004 are as follows (in thousands):
                
 2003
 2002
 2005 2004 
Deferred tax assets:  
Operating loss carryforwards $20,442 $19,690  $2,020 $14,748 
Difference in basis of property 29,602 21,495  25,343 28,753 
Other 3,070 2,043  3,052 3,276 
Valuation allowance  (48,365)  (39,146)  (27,363)  (40,492)
 
 		 
 		      
Net deferred tax asset $4,749 $4,082  3,052 6,285 
Less current portion 3,052 251 
 
 		 
 		      
 $— $6,034 
     

     The valuation allowance increaseddecreased by $9.2$13.1 million as a result of the change in the U.S. deferred tax assets related to the net operating loss carryforward as well as a Venezuelan deferred tax asset impairment. Realization of deferred tax assets associated with net operating loss carryforwards is dependent upon generating sufficient taxable income prior to their expiration. Management believes it is more likely than not that they will not be realized through future taxable income.

The difference in interpretation of oil pricing under the Transitory Agreement has been recognized and represents our entire deferred tax asset.

     The components of income before income taxes and minority interest are as follows (in thousands):
                      
 2003
 2002
 2001
 2005 2004 2003 
Income (loss) before income taxes  
United States $21,812 $89,455 $(26,572) $8,178 $(16,593) $34,236 
Foreign 49,976 80,356 33,754  114,916 97,859 37,552 
 
 		 
 		 
 		        
Total $71,788 $169,811 $7,182  $123,094 $81,266 $71,788 
 
 		 
 		 
 		        

     The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):
                        
 2003
 2002
 2001
 2005 2004 2003 
Current:  
United States $1,188 $353 $1  $739 $(8) $1,187 
Foreign 9,136 6,324 6,700  53,304 34,581 9,137 
 
 		 
 		 
 		        
 $10,324 $6,677 $6,701  54,043 34,573 10,324 
 
 		 
 		 
 		  
Deferred:  
United States $— $53,413  (42,405)
Foreign  (667) 205 6  2,982  (1,285)  (667)
 
 		 
 		 
 		        
  (667) 53,618  (42,399) $57,025 $33,288 $9,657 
 
 		 
 		 
 		        
 $9,657 $60,295 $(35,698)
 
 		 
 		 
 		 

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     During 2003, we reduced our foreign tax provision approximately $3.9 million related to the resolution of certain prior year foreign income tax matters. Additionally, we recorded a domestic tax provision of approximately $1.1 million related to certain domestic tax matters identified during the year.

     A comparison of the income tax expense (benefit) at the federal statutory rate to our provision for income taxes is as follows (in thousands):
             
  2003
 2002
 2001
Computed tax expense at the statutory rate $15,025  $59,348   4,580 
State income taxes  1,188   353   — 
Effect of foreign source income and rate differentials on foreign income  (15,849)  (19,373)  1,675 
Change in valuation allowance  9,219   19,446   (53,413)
Prior year adjustments  —   —   2,304 
Reclass paid-in capital  —   —   11,007 
All other  74   80   215 
   
 		   
 		   
 		 
Sub-total income tax expense (benefit)  9,657   59,854   (33,632)
Effects of recording equity income of certain affiliated Companies on an after-tax basis  —   441   (2,066)
   
 		   
 		   
 		 
Total income tax expense (benefit) $9,657  $60,295  $(35,698)
   
 		   
 		   
 		 
             
  2005  2004  2003 
Computed tax expense at the statutory rate $43,083  $28,443  $15,025 
State income taxes  —   25   1,188 
Effect of foreign source income and rate differentials on foreign income  16,065   (2,169)  (15,849)
Change in valuation allowance  13,129   7,020   9,219 
Alternative minimum tax  739   —   — 
Net operating loss utilization  (15,567)  —   — 
Other  (424)  (31)  74 
          
Total income tax expense $57,025  $33,288  $9,657 
          

     Rate differentials for foreign income result from tax rates different from the U.S. tax rate being applied in foreign jurisdictions and from the effect of foreign currency devaluation in foreign subsidiaries which use the U.S. dollarDollar as their functional currency.

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     At December 31, 2003,2005, we had, for federal income tax purposes, operating loss carryforwards of approximately $58.4$5.4 million, expiring in the years 20182022 through 2022.

2025.

     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.

Note 65 — Stock Option and Stock Purchase Plans

     In May 2004, our shareholders approved the 2004 Long Term Incentive Plan (the “Plan”). The 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 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 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 Company and is subject to forfeiture under certain circumstances. The 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 iswas 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. 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-qualifiedNon-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 plan must be no less than the fair market value of our common stock on the

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date of grant. No officer may be granted more than 500,000 options during any one fiscal year, as adjusted for any changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date.

     Since 1989 we have adopted several other stock option plans under which options to purchase shares of our common stock have been granted to employees, officers, directors, independent contractors and consultants. Options granted under these plans have been at prices equal to the fair market value of the stock on the grant dates. Options granted under the plans are generally exercisable in varying cumulative periodic installments after one year and cannot be exercised more than ten years after the grant dates. Following the adoption of the 2001 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, 2003, 20022005, 2004 and 20012003 and changes during the years ending on those dates is presented below (shares in thousands):
                                             
 2003
 2002
 2001
 2005 2004 2003
 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: $7.42 5,223 $6.36 6,865 7.74 5,660  $8.18   3,793  $7.52   4,523  $7.42   5,223 
Options granted 6.26 246 4.84 165 1.65 1,684   11.51   922   13.36   378   6.26   246 
Options exercised 2.32  (494) 2.21  (1,515) — —   (3.45)  (241)  (7.41)  (955)  2.32   (494)
Options cancelled 11.37  (452) 8.03  (292) 6.43  (479)  (14.24)  (404)  (6.31)  (153)  11.37   (452)
 
 		 
 		 
 		                         
Outstanding at end of the year 7.52 4,523 7.42 5,223 6.36 6,865   8.61   4,070   8.18   3,793   7.52   4,523 
 
 		 
 		 
 		                         
Exercisable at end of the year 8.18 3,857 8.49 4,360 8.32 4,800   7.40   2,886   7.71   3,236   8.18   3,857 
 
 		 
 		 
 		                         

     Significant option groups outstanding at December 31, 20032005 and related weighted average price and life information follow:follow (in thousands):
                             
          Outstanding
 Exercisable
Range of Number Weighted-Average     Number  
Exercise Outstanding At Remaining Weighted-Average Exercisable at Weighted-Average
Prices
 December 31, 2003
 Contractual Life
 Exercise Price
 December 31, 2003
 Exercise Price
$1.55  - $2.75   2,027,150   5.91  $1.97   1,679,983  $2.03 
$4.80  - $7.00   621,000   4.69   5.81   337,667   5.87 
$7.25  - $11.00   488,633   1.69   8.77   452,633   8.90 
$11.50  - $16.50   946,665   1.42   13.52   946,665   13.52 
$17.38  - $24.13   439,833   1.78   21.21   439,833   21.21 
           
 		           
 		     
           4,523,281           3,856,781     
           
 		           
 		     
                             
  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 12/31/05  Life  Price  Value  at 12/31/05  Price  Value 
$1.55 - $2.75  1,523   1.78  $1.98  $10,513   1,523  $1.98  $10,513 
$4.80 - $7.10  356   3.82   5.66   1,145   291   5.52   975 
$8.72 - $10.88  696   5.40   10.30   23   136   8.72   22 
$11.50 - $16.90  1,085   3.64   13.04   —   526   13.05   — 
$17.88 - $24.13  410   0.14   21.21   —   410   21.21   — 
                         
   4,070          $11,681   2,886      $11,510 
                         

     The aggregate intrinsic value in the preceding table represents the total pretax intrinsic value based on our closing stock price of $8.88 as of December 30, 2005, which would have been received by the option holders had all option holders exercised their options as of that date. Of the number outstanding, 733,750 options are pledged to us to secure a repayment of debt.
     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:
             
  2005 2004 2003
Weighted average fair value $6.35  $10.33  $4.83 
Weighted averaged expected life  7   2-10   5-10 
Valuation assumptions:            
Expected volatility  50.0%-53.4%  69.6%  79.8%
Risk-free interest rate  3.9%-4.6%  2.6%-4.8%  2.8%-4.2%
Expected dividend yield  0%  0%  0%
Expected annual forfeitures  3%  0%  0%
     The Black-Scholes option pricing model was developed for use in estimating the value of traded options that have no vesting restrictions and are fully transferable. In addition, option pricing models require the input of

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     Of

highly subjective assumptions, including the number outstanding, 1,108,750expected stock price volatility and expected life. The expected volatility is based on historical volatilities of our stock. Historical data is used to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options are controlled by us throughexpected to be outstanding. The risk-free rate for the A. E. Benton settlement. SeeNote 13 – Related Party Transactions.

periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. Under the Black-Scholes option pricing model, the weighted-average estimated values of stock options granted during 2005, 2004 and 2003 were $6.35, $10.33 and $4.83, respectively.

     A summary of our nonvested shares as of December 31, 2005, and changes during the year ended December 31, 2005, is presented below (in thousands):
         
      Weighted-Average 
      Grant-Date 
Nonvested Shares Shares  Fair Value 
Nonvested at January 1, 2005  557  $8.46 
Granted  922   6.73 
Vested  (243)  7.51 
Forfeited  (51)  9.05 
        
Nonvested at December 31, 2005  1,185  $7.30 
        
     As of December 31, 2005, there was $6.5 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under our plans. That cost is expected to be recognized over the next three years. The total fair value of shares vested during the years ended December 31, 2005, 2004 and 2003, was $2.7 million, $1.4 million and $1.1 million, respectively.
     In connection with our acquisition of Benton Offshore China Company in December 1996, we adopted the Benton Offshore China Company 1996 Stock Option Plan. Under the plan, Benton Offshore China Company 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 shares of our common stock. All options were issued upon the acquisition of Benton Offshore China Company and vested upon issuance. At December 31, 2003,2005, options to purchase 74,427 shares of common stock were both outstanding and exercisable.

     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 $5.63 to $11.88 which vest over three to four years. At December 31, 2003,2005, a total of 61,00010,000 options issued outside of the plans were both outstanding and exercisable.

Note 7 — Stock Warrants

     The dates the warrants were issued, the expiration dates, the exercise prices and the number of warrants issued and outstanding at December 31, 2003 were (warrants in thousands):

               
        Warrants
Date Issued
 Expiration Date
 Exercise Price
 Issued
 Outstanding
July 1994 July 2004 $7.50   150   8 
December 1994 December 2004  12.00   50   50 
June 1995 June 2007  17.09   125   125 
         
 		   
 		 
         325   183 
         
 		   
 		 

Note 86 — 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. Revenue from Venezuela is derived primarily from the production and sale of oil and natural gas. Other income from USAUnited States and Other is derived primarily from interest earnings on various investments and consulting revenues.investments. Operations included under the heading “USA“Russia” include project evaluation costs and other costs to maintain an office in Russia. Operations included under the heading “United States and Other” include corporate management, exploration activities, cash management 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.

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  2005  2004  2003 
Segment Revenues
            
Oil and gas sales:            
Venezuela $236,941  $186,066  $106,095 
          
Total oil and gas sales  236,941   186,066   106,095 
          
             
Segment Income (Loss)
            
Venezuela  64,096   54,469   23,874 
Russia  (3,471)  (3,524)  (29,620)
United States and other  (9,786)  (16,585)  33,049 
          
Net income $50,839  $34,360  $27,303 
          
         
  December 31,  December 31, 
  2005  2004 
Operating Segment Assets
        
Venezuela $258,268  $309,794 
Russia  317   385 
United States and other  161,011   108,408 
       
   419,596   418,587 
Intersegment eliminations  (18,798)  (51,101)
       
  $400,798  $367,486 
       
Year ended December 31, 2003:
                     
(in thousands)
 Venezuela
 USA and Other
 Russia
 Eliminations
 Consolidated
Revenues                    
Oil sales $103,920  $—  $—  $—  $103,920 
Gas sales  2,740   —   —   —   2,740 
Ineffective hedge activity  (565)  —   —   —   (565)
   
 		   
 		   
 		   
 		   
 		 
   106,095   —   —   —   106,095 
   
 		   
 		   
 		   
 		   
 		 
Expenses                    
Operating expenses  31,309   76   (492)  —   30,893 
Depletion, depreciation and amortization  21,035   109   44   —   21,188 
General and administrative  4,031   10,514   1,201   —   15,746 
Arbitration settlement  —   1,477   —   —   1,477 
Bad debt recovery  —   (374)  —   —   (374)
Taxes other than on income  2,921   447   5   —   3,373 
   
 		   
 		   
 		   
 		   
 		 
Total expenses  59,296   12,249   758   —   72,303 
   
 		   
 		   
 		   
 		   
 		 
Income (loss) from operations  46,799   (12,249)  (758)  —   33,792 
Other non-operating income (expense)                    
Gain on disposition of assets  —   46,619   —   —   46,619 
Investment earnings and other  435   983   —   —   1,418 
Interest expense  (1,944)  (8,470)  —   9   (10,405)
Net gain on exchange rates  495   34   —   —   529 
Intersegment revenues (expenses)  (7,484)  7,484   —   —   — 
Equity in losses of affiliated companies  —   —   (28,860)  —   (28,860)
   
 		   
 		   
 		   
 		   
 		 
   (8,498)  46,650   (28,860)  9   9,301 
   
 		   
 		   
 		   
 		   
 		 
Income (loss) before income taxes  38,301   34,401   (29,618)  9   43,093 
Income tax expense  8,459   1,187   2   9   9,657 
   
 		   
 		   
 		   
 		   
 		 
Operating segment income (loss)  29,842   33,214   (29,620)  —   33,436 
Write-downs of oil and gas properties and impairments  —   (165)  —   —   (165)
Minority interest  (5,968)  —   —   —   (5,968)
   
 		   
 		   
 		   
 		   
 		 
Net income (loss) $23,874  $33,049  $(29,620) $—  $27,303 
   
 		   
 		   
 		   
 		   
 		 
Total assets $241,855  $180,768  $237  $(48,512) $374,348 
   
 		   
 		   
 		   
 		   
 		 
Additions to properties $60,589  $245  $91  $—  $60,925 
   
 		   
 		   
 		   
 		   
 		 

Year ended December 31, 2002

                     
(in thousands)
 Venezuela
 USA and Other
 Russia
 Eliminations
 Consolidated
Revenues                    
Oil sales $127,015  $—  $—  $—  $127,015 
   
 		   
 		   
 		   
 		   
 		 
Ineffective hedge activity  (284)  —   —   —   (284)
   
 		   
 		   
 		   
 		   
 		 
   126,731   —   —   —   126,731 
   
 		   
 		   
 		   
 		   
 		 
Expenses                    
Operating expenses  31,457   360   2,133   —   33,950 
Depletion, depreciation and amortization  23,850   2,483   30   —   26,363 
General and administrative  4,310   11,420   774   —   16,504 
Bad debt recovery  —   (3,276)  —       (3,276)
Taxes other than on income  3,997   71   —   —   4,068 
   
 		   
 		   
 		   
 		   
 		 
Total expenses  63,614   11,058   2,937   —   77,609 
   
 		   
 		   
 		   
 		   
 		 
Income (loss) from operations  63,117   (11,058)  (2,937)  —   49,122 
Other non-operating income (expense):                    
Gain on disposition of assets  —   144,032   (3)  —   144,029 
Gain on early extinguishment of debt  —   874   —   —   874 
Investment earnings and other  1,889   1,653   —   (1,462)  2,080 
Interest expense  (4,237)  (13,611)  —   1,538   (16,310)
Net gain on exchange rates  4,356   197   —   —   4,553 
Intersegment revenues (expenses)  15,156   (15,156)  —   —   — 
Equity in income of affiliated companies  —   —   165   —   165 
   
 		   
 		   
 		   
 		   
 		 
   17,164   117,989   162   76   135,391 
   
 		   
 		   
 		   
 		   
 		 
Income (loss) before income taxes  80,281   106,931   (2,775)  76   184,513 
Income tax expense  6,453   53,764   2   76   60,295 
   
 		   
 		   
 		   
 		   
 		 
Operating segment income (loss)  73,828   53,167   (2,777)  —   124,218 
Write-downs of oil and gas properties and impairments  —   (14,537)  —   —   (14,537)
Minority interest  (9,319)  —   —   —   (9,319)
   
 		   
 		   
 		   
 		   
 		 
Net income (loss) $64,509  $38,630  $(2,777) $—  $100,362 
   
 		   
 		   
 		   
 		   
 		 
Total assets $209,733  $122,355  $52,302  $(49,198) $335,192 
   
 		   
 		   
 		   
 		   
 		 
Additions to properties $42,486   738   122   —   43,346 
   
 		   
 		   
 		   
 		   
 		 

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Year ended December 31, 2001:

                     
(in thousands)
 Venezuela
 USA and Other
 Russia
 Eliminations
 Consolidated
Revenues                    
Oil sales $122,386  $—  $—  $—  $122,386 
   
 		   
 		   
 		   
 		   
 		 
Expenses                    
Operating expenses  42,037   55   667   —   42,759 
Depletion, depreciation and amortization  22,096   3,408   12   —   25,516 
General and administrative  4,151   14,972   949   —   20,072 
Taxes other than on income  4,666   704   —   —   5,370 
   
 		   
 		   
 		   
 		   
 		 
Total expenses  72,950   19,139   1,628   —   93,717 
   
 		   
 		   
 		   
 		   
 		 
Income (loss) from operations  49,436   (19,139)  (1,628)  —   28,669 
Other non-operating income (expense):                    
Investment earnings and other  5,995   2,053   60   (5,020)  3,088 
Interest expense  (7,403)  (22,695)  —   5,223   (24,875)
Net gain on exchange rates  732   36   —   —   768 
Intersegment revenues (expenses)  (14,983)  14,983   —   —   — 
Equity in income of affiliated companies  —   —   5,902   —   5,902 
   
 		   
 		   
 		   
 		   
 		 
   (15,659)  (5,623)  5,962   203   (15,117)
   
 		   
 		   
 		   
 		   
 		 
Income (loss) before income taxes  33,777   (24,762)  4,334   203   13,552 
Income tax (benefit) expense  6,491   (42,392)  —   203   (35,698)
   
 		   
 		   
 		   
 		   
 		 
Operating segment income  27,286   17,630   4,334   —   49,250 
Write-down of oil and gas properties and impairments  —   (468)  —   —   (468)
Minority interest  (5,545)  —   —   —   (5,545)
   
 		   
 		   
 		   
 		   
 		 
Net income $21,741  $17,162   4,334   —  $43,237 
   
 		   
 		   
 		   
 		   
 		 
Total assets $167,671  $165,254  $100,801  $(85,575) $348,151 
   
 		   
 		   
 		   
 		   
 		 
Additions to properties $43,411  $—  $31  $—  $43,442 
   
 		   
 		   
 		   
 		   
 		 

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Note 9 -7 — Russian Operations

Geoilbent

     On September 25, 2003, we sold our minority equity investment in Geoilbent to Yukos Operational Holding Limited for $69.5 million plus the repayment of the subordinated loan and certain payables owed to us by Geoilbent in the amount of $5.5 million. Prior to the sale, we owned 34 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 region of Russia. Our minority equity investment in Geoilbent was accounted for using the equity method and was based 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 years ended September 30, 2002 and 2001 were 5.6 million barrels (3.3 million domestic and 2.3 million export), 6.9 million barrels (4.6 million domestic and 2.3 million export) and 5.2 million barrels (0.8 million domestic and 4.4 million export), respectively.. Prices for crude oil for the period until it was sold on September 25, 2003 and for the years ended September 30, 2002 and 2001 averaged $14.52 ($8.61 domestic and $23.05 export), $13.25 ($8.89 domestic and $21.73 export) and $19.51 ($13.69 domestic and $20.48 export) per barrel, respectively.barrel. Depletion expense attributable to Geoilbent for the period until it was sold on September 25, 2003 and for the years ended September 30, 2002 and 2001 was $3.23 $3.93 and $2.88 per barrel, respectively.barrel. All amounts represent 100 percent of Geoilbent. Summarized financial information for Geoilbent follows (in thousands):
             
  2003
 2002
 2001
Year ended September 30:
            
Revenues            
Oil sales $81,724  $91,598  $101,159 
   
 		   
 		   
 		 
Expenses            
Selling and distribution expenses  5,893   6,696   9,876 
Operating expenses  15,897   15,360   11,415 
Depletion, depreciation and amortization  18,182   27,168   14,918 
Write-downs of oil and gas properties  95,000   —   — 
General and administrative  9,456   8,335   5,650 
Taxes other than on income  25,626   27,657   26,011 
   
 		   
 		   
 		 
   170,054   85,216   67,870 
   
 		   
 		   
 		 
Income (loss) from operations  (88,330)  6,382   33,289 
Other non-operating income (expense)            
Investment earnings and other  1,064   381   648 
Interest expense  (1,992)  (4,629)  (7,547)
Net gain on exchange rates  1,566   2,053   781 
   
 		   
 		   
 		 
   638   (2,195)  (6,118)
   
 		   
 		   
 		 
Income (loss) before income taxes  (87,692)  4,187   27,171 
Income tax expense  (3,117)  302   6,751 
   
 		   
 		   
 		 
   (84,575)  3,885   20,420 
Effects of change in accounting policy  310   —   — 
   
 		   
 		   
 		 
Net income (loss) $(84,885) $3,885  $20,420 
   
 		   
 		   
 		 
At September 30:
            
Current assets     $18,785  $35,447 
Other assets      186,815   187,706 
Current liabilities      54,051   60,439 
Other liabilities      7,500   22,550 
Net equity      144,049   140,164 

     As of September 30, 2002, the Geoilbent shareholders had provided Geoilbent with subordinate loans totaling $7.5 million ($2.5 million from us). These loans were unsecured, repayable in January 2004 and recorded as a current liability at September 30, 2003. The loan by us was repaid as part of the sale of our minority equity investment in Geoilbent. As of January 1, 2003, the Russian economy was no longer a highly inflationary economy. As a result, the Russian Ruble became the functional currency and not the U.S. dollar.

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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 and $1.1 million for the period ended April 12, 2002 and September 30, 2001, respectively. Summarized financial information for Arctic Gas follows (in thousands). All amounts represent 100 percent of Arctic Gas.

       
 2002
 2001
    
Year ended September 30:
  2003 
Revenues  
Oil Sales $7,880 $13,374 
Oil sales $81,724 
   
 
 		 
 		  
Expenses  
Selling and distribution expenses 3,170 3,867  5,893 
Operating expense 2,473 3,483 
Operating expenses 15,897 
Depletion, depreciation and amortization 333 1,032  18,182 
Write-downs of oil and gas properties 95,000 
General and administrative 2,112 3,025  9,456 
Taxes other than on income 1,261 3,881  25,626 
 
 		 
 		    
 9,349 15,288  170,054 
 
 		 
 		    
 
Loss from operations  (1,469)  (1,914)  (88,330)
 
Other non-operating income (expense)    
Other income (expense)  (4) 54 
Interest and foreign exchange expense  (1,722)  (1,848)
Investment earnings and other 1,064 
Interest expense  (1,992)
Net gain on exchange rates 1,566 
   
 
 		 
 		  638 
  (1,726)  (1,794)   
 
 		 
 		  
Loss before income taxes  (3,195)  (3,708)  (87,692)
Income tax expense — — 
Income tax benefit  (3,117)
   
  (84,575)
Effects of change in accounting policy 310 
 
 		 
 		    
Net loss $(3,195) $(3,708) $(84,885)
 
 		 
 		    

Note 10 -8 — Venezuela Operations

     On July 31, 1992, we and our partner, Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), signed an operating service agreement to reactivate and further develop three Venezuelan oil fields with Lagoven, S.A., then one of three exploration and production affiliates of the national oil company, PDVSA. The operating service agreement covers the Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit. Under the terms of the operating service agreement, Benton-Vinccler,Harvest Vinccler, a Venezuelan corporation owned 80 percent by us and 20 percent by Vinccler, is a contractor for PDVSA and 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. Benton-Vinccler receivesThe operating service agreement stipulates that Harvest Vinccler is to receive an operating fee in U.S. dollarsDollars deposited into a U.S. commercial bank account for each barrel of crude oil produced (subject to periodic adjustments to reflect changes in a special energy index of the U.S. Consumer Price Index) and is to be reimbursed according to a prescribed formula in U.S. dollarsDollars 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.

On August 4, 2005, Harvest Vinccler entered into the Transitory Agreement with PDVSA. The Transitory Agreement provides that effective January 1, 2005, the total amounts 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. Historically, our maximum total fee under the OSA averaged approximately 48 percent of the price of WTI. Under the fee limit in the Transitory Agreement, the new fee has historically averaged approximately 47 percent of the price of WTI. In the first quarter 2005, PDVSA paid the fee 50 percent in U.S. Dollars and 50 percent in Bolivars. Subsequent quarterly payments have been received 75 percent in U.S. Dollars and 25 percent in Bolivars. The OSA stipulated payment was to be in U.S. Dollars or a currency selected by Harvest Vinccler.

     In September 2002, Benton-VincclerHarvest Vinccler and PDVSA signed an amendment to the operating service agreement,OSA, providing for the delivery of up to 198 Bcf of natural gas through July 2012 at a price of $1.03 per Mcf. Natural gas sales commenced in the fourth quarter of 2003. In addition, Benton-VincclerHarvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the natural gas production at $7.00 per barrel beginning with our first natural gas sale. Initial gas production will come from Uracoa, which allows us to more efficiently manage the reservoir and eliminate the restrictions on producing oil wells with high gas to oil ratios. The gas reservesWe drilled one well in Bombal will be used to meet the future terms of the gas contract in 2005.

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     The Venezuelan government maintains full ownership of all hydrocarbons in the fields. During 2005, the government of Venezuela initiated a series of actions to compel companies with operating service agreements to convert those agreements into new companies in which PDVSA has a majority interest. As a result of the actions

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     We drilled three oil wells and converted two gas injection wells

taken by the government of Venezuela, we were unable to producing wells in 2003.

carry out our planned development program for 2005. Moreover, our ability to carry out future programs is uncertain.

Note 11 - United States Operations

     We acquired a 100 percent interest in three California State offshore oil and gas leases (“California Leases”) and a parcel of onshore property from Molino Energy Company, LLC. All capitalized costs associated with the California Leases have been fully impaired. The California Leases have expired and we have listed the onshore property for sale.

Note 12 -9 — 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 area under 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. An evaluation was performed again at December 31, 2003 and such evaluation indicated that noNo further impairment of the property had been incurred in 2003.is currently required. WAB-21 represents the $2.9 million excluded from the full cost pool as reflected on our December 31, 20032005 balance sheet.

Note 13 -10 — Related Party Transactions

     We have

     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 Benton-Vinccler.Harvest Vinccler. Vinsa has provided $1.7 million, $0.5$0.3 million and $0.6$1.7 million in construction services onfor our Venezuelan gas pipeline and field operations for the years ended December 31, 2004 and 2003, 2002 and 2001, respectively.

     We have 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 owns 20 percent of Benton-Vinccler.Harvest Vinccler. Payment for services is due when earnings are not reinvested in Benton-VincclerHarvest Vinccler operations. Expenses related to this consulting agreement waswere $1.5 million, $2.6 million and $2.5 million at December 31, 2003, 2002 and 2001, 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. We subsequently obtained a security interest in Mr. Benton’s shares of our stock and stock options. In August 1999, Mr. Benton filed a chapter 11 (reorganization) bankruptcy petition in the U.S. Bankruptcy Court for the Central District of California, in Santa Barbara, California. In February 2000, we entered into a separation agreement with Mr. Benton pursuant to which we retained Mr. Benton under a consulting agreement to perform certain services for us. In addition, the consulting agreement provided Mr. Benton with incentive bonuses tied to our net cash receipts from the sale of our interests in Arctic Gas and Geoilbent. In June 2002, we made an incentive bonus payment to Mr. Benton of $1.5 million, subject to future adjustment, in connection with the Arctic Gas sale. We recorded the bonus payment as a reduction of the gain on the Arctic Gas sale. In November 2003, we made a payment to Mr. Benton of $0.5 million for the incentive bonus associated with the sale of our minority equity investment in Geoilbent.

     In May 2001, we and Mr. Benton entered into a settlement and release agreement under which the2003. The consulting agreement was terminated as to future services and Mr. Benton agreed to propose a plan of reorganization in his bankruptcy case that provided for the repayment of our loans to him. In March 2002, Mr. Benton filed a plan of reorganization, and on July 31, 2002, the bankruptcy court confirmed the plan of reorganization. At the time the plan became final, Mr. Benton’s indebtedness to us was about $6.7 million for which we provided a full allowance for bad debt. On August 14, 2002, we exercised our rights with respect to 600,000 shares of our stock pledged to us as partial repayment of the loan and took the shares into our treasury stock. Based on a $3.56 closing price for the stock on that date, the value of the shares was $2.1 million. Also, in September 2002 and July 2003, we received payments of approximately $1.3 million as distributions from Mr.

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cancelled January 1, 2004.

Benton’s debtor-in-possession account. Finally, under the terms of the settlement agreement, we have retained about $0.2 million from the Arctic Gas and Geoilbent bonus payments to Mr. Benton, bringing the total recovery on Mr. Benton’s debt to $3.7 million. We continue to accrue interest and provide a bad debt allowance on the remaining amount due. In addition, we hold the rights to direct the exercise of Mr. Benton’s stock options.

     We and Mr. Benton disagreed over Mr. Benton’s remaining obligations to us under the settlement agreement and plan of reorganization. In addition, Mr. Benton claimed that he was due significant additional amounts with respect to the incentive bonus associated with the Arctic Gas sale. We and Mr. Benton submitted our dispute to binding arbitration and in October 2003 the arbitrator found in favor of Mr. Benton in all material respects. As a result, in October 2003, we made a payment to Mr. Benton of $1.9 million for the balance of the incentive bonus associated with the Arctic Gas sale and released certain funds for the payment of Mr. Benton’s taxes and expenses related to the disposition of his 600,000 shares of stock.

Note 14 -11 — 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 35.336.9 million, 34.636.1 million and 33.935.3 million for the years ended December 31, 2003, 20022005, 2004 and 2001,2003, 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 36.838.4 million, 36.138.1 million, and 34.036. 8 million for the years ended December 31, 2005, 2004 and 2003, 2002 and 2001, respectively.

     An aggregate of 2.51.9 million options and warrants were excluded from the earnings per share calculations because they were anti-dilutivetheir exercise price exceeded the average price for the year ended December 31, 2003.2005. For the years ended December 31, 20022004 and 2001, 3.52003, 0.9 million and 6.72.5 million options and warrants, respectively, were excluded from the earnings per share calculations because they were anti-dilutive.

their exercise price exceeded the average price.

S-23S-20

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, 2003
                
Revenues $18,825  $28,576  $27,834  $30,860 
Expenses  (13,901)  (19,911)  (20,037)  (18,619)
Non-operating income (expense)  (1,864)  (2,288)  44,056   (1,743)
   
 		   
 		   
 		   
 		 
Income from consolidated companies before income taxes and minority interests  3,060   6,377   51,853   10,498 
Income tax expense  1,056   3,104   3,603   1,894 
   
 		   
 		   
 		   
 		 
Income before minority interests  2,004   3,273   48,250   8,604 
Minority interests  887   1,216   1,367   2,498 
   
 		   
 		   
 		   
 		 
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 
   
 		   
 		   
 		   
 		 
Net income (loss) $(15,458) $(11,413) $46,410  $7,764 
Other comprehensive income (loss)  2,614   (3,001)  21   366 
   
 		   
 		   
 		   
 		 
Total comprehensive income (loss) $(12,844) $(14,414) $46,431  $8,130 
   
 		   
 		   
 		   
 		 
Net income (loss) per common share:                
Basic $(0.44) $(0.32) $1.31  $0.22 
   
 		   
 		   
 		   
 		 
Diluted $(0.44) $(0.32) $1.25  $0.21 
   
 		   
 		   
 		   
 		 
                            
 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, 2002
 
Year ended December 31, 2005
 
Revenues $27,247 $33,022 $38,841 $27,621  $60,986 $56,442 $61,221 $58,292 
Expenses  (18,720)  (35,747)  (17,914)  (19,765)  (27,300)  (26,207)  (32,245)  (31,664)
Non-operating income (expense)  (3,948) 142,940  (818)  (2,948) 3,054 277  (1,827) 2,065 
 
 		 
 		 
 		 
 		          
Income from consolidated companies before income taxes and minority interests 4,579 140,215 20,109 4,908 
Income tax expense (benefit) 1,801 59,692 6,612  (7,810)
Income before income taxes and minority interests 36,740 30,512 27,149 28,693 
Income tax expense 13,533 11,959 16,332 15,201 
 
 		 
 		 
 		 
 		          
Income before minority interests 2,778 80,523 13,497 12,718  23,207 18,553 10,817 13,492 
Minority interests 1,380 2,031 2,590 3,318  5,172 4,402 2,674 2,982 
 
 		 
 		 
 		 
 		          
Income from consolidated companies 1,398 78,492 10,907 9,400 
Equity in net income (losses) of affiliated companies 87  (2,172) 1,209 1,041 
 
 		 
 		 
 		 
 		 
Net income $1,485 $76,320 $12,116 $10,441  $18,035 $14,151 $8,143 $10,510 
 
 		 
 		 
 		 
 		          
Other comprehensive loss — —  (658) 658 
 
 		 
 		 
 		 
 		 
Total comprehensive income 1,485 76,320 11,458 11,099 
 
 		 
 		 
 		 
 		  
Net income per common share:  
Basic $0.04 $2.20 $0.35 $0.30  $0.49 $0.38 $0.22 $0.28 
 
 		 
 		 
 		 
 		          
Diluted $0.04 $2.10 $0.33 $0.28  $0.47 $0.37 $0.21 $0.27 
 
 		 
 		 
 		 
 		          
 
Other comprehensive income (loss)  (6,048) 1,770 2,287 1,991 
         
Total comprehensive income $11,987 $15,921 $10,430 $12,501 
         

     In the second quarter of 2002, we recognized in non-operating income, the $144.0 million pre-tax gain on the Arctic Gas Sale, and in expense, the write-down of capitalized costs of $13.4 million associated with our WAB-21 offshore China concession.

S-24

                 
  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 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 (loss) $7,507  $6,248  $5,306  $15,299 
             
                 
Net income (loss) 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 (loss) $7,507  $6,248  $2,949  $17,169 
             

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 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.

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TABLE I -— Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
                
 United States   
 Venezuela China and Other Total 
Year Ended December 31, 2005
 
Development costs $8,912 $— $— $8,912 
Exploration costs — 42 — 42 
         
 $8,912 $42 $— $8,954 
         
 
Year Ended December 31, 2004
 
Development costs $39,161 $— $— $39,161 
Exploration costs 10 53 — 63 
         
               $39,171 $53 $— $39,224 
 United States           
 Venezuela
 China
 and Other
 Total
 
Year Ended December 31, 2003
  
Development costs $58,079 $— $2 $58,081  $58,079 $— $2 $58,081 
Exploration costs 11 39 133 183  11 39 133 183 
 
 		 
 		 
 		 
 		          
 $58,090 $39 $135 $58,264  $58,090 $39 $135 $58,264 
 
 		 
 		 
 		 
 		          
Year Ended December 31, 2002
 
Development costs $49,163 $120 $577 $49,860 
Exploration costs 794  (149) 88 733 
 
 		 
 		 
 		 
 		 
 $49,957 $(29) $665 $50,593 
 
 		 
 		 
 		 
 		 
Year Ended December 31, 2001
 
Acquisition costs $ $ $ $ 
Development costs 35,194 77 28 35,299 
Exploration costs 7,694 — 909 8,603 
 
 		 
 		 
 		 
 		 
 $42,888 $77 $937 $43,902 
 
 		 
 		 
 		 
 		 

TABLE II -— Capitalized costs related to oil and natural gas producing activities (in thousands):
            
 Venezuela China Total 
Year Ended December 31, 2005
 
Proved property costs $617,137 $13,497 $630,634 
Costs excluded from amortization — 2,900 2,900 
Oilfield inventories 8,150 — 8,150 
Less accumulated depletion and impairment  (473,496)  (13,497)  (486,993)
       
 $151,791 $2,900 $154,691 
       
 
Year Ended December 31, 2004
 
Proved property costs $608,225 $13,454 $621,679 
Costs excluded from amortization — 2,900 2,900 
Oilfield inventories 6,503 — 6,503 
Less accumulated depletion and impairment  (432,302)  (13,454)  (445,756)
       
                 $182,426 $2,900 $185,326 
 United States         
 Venezuela
 China
 and Other
 Total
 
December 31, 2003
  
Proved property costs $569,055 $13,401 $— $582,456  $569,055 $13,401 $582,456 
Costs excluded from amortization — 2,900 — 2,900  — 2,900 2,900 
Oilfield inventories 8,266 — — 8,266  8,266 — 8,266 
Less accumulated depletion and impairment  (398,206)  (13,401) —  (411,607)  (398,206)  (13,401)  (411,607)
 
 		 
 		 
 		 
 		        
 $179,115 $2,900 $— $182,015  $179,115 $2,900 $182,015 
 
 		 
 		 
 		 
 		        
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 
 
 		 
 		 
 		 
 		 
December 31, 2001
 
Proved property costs $469,218 $12,892 $19,813 $501,923 
Costs excluded from amortization — 16,248 560 16,808 
Oilfield inventories 15,219 — — 15,219 
Less accumulated depletion and impairment  (361,313)  (12,892)  (19,544)  (393,749)
 
 		 
 		 
 		 
 		 
 $123,124 $16,248 $829 $140,201 
 
 		 
 		 
 		 
 		 

S-25S-22

TABLE III -— Results of operations for oil and natural gas producing activities (in thousands):
                            
 United States   United States   
 Venezuela
 China
 and Other
 Total
 Venezuela China and Other Total 
Year ended December 31, 2005
 
Oil and natural gas revenues $236,941 $— $— $236,941 
Expenses: 
Operating, selling and distribution expenses and taxes other than on income 39,969 — — 39,969 
Depletion 41,175 — — 41,175 
Income tax expense 65,943 — — 65,943 
         
Total expenses 147,087 — — 147,087 
         
Results of operations from oil and natural gas producing activities $89,854 $— $— $89,854 
         
 
Year ended December 31, 2004
 
Oil and natural gas revenues $186,066 $— $— $186,066 
Expenses: 
Operating, selling and distribution expenses and taxes other than on income 33,297 — 214 33,511 
Depletion 34,108 — — 34,108 
Income tax expense 38,968 — — 38,968 
         
Total expenses 106,373 — 214 106,587 
         
Results of operations from oil and natural gas producing activities $79,693 $— $(214) $79,479 
         
 
Year ended December 31, 2003
  
Oil sales $106,095 $— $— $106,095 
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  31,445 — 76 31,521 
Write-down of oil and gas properties and impairments — 23 142 165  — 23 142 165 
Depletion 19,599 — — 19,599  19,599 — — 19,599 
Income tax expense 12,158 — 1,187 13,345  12,158 — 1,187 13,345 
 
 		 
 		 
 		 
 		          
Total expenses 63,202 23 1,405 64,630  63,202 23 1,405 64,630 
 
 		 
 		 
 		 
 		          
Results of operations from oil and natural gas producing activities $42,893 $(23) $(1,405) $41,465  $42,893 $(23) $(1,405) $41,465 
 
 		 
 		 
 		 
 		          
Year ended December 31, 2002
 
Oil sales $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 
 
 		 
 		 
 		 
 		 
Year ended December 31, 2001
 
Oil and natural gas sales $122,386 $— $— $122,386 
Expenses: 
Operating, selling and distribution expenses and taxes other than on income 42,212 — 722 42,934 
Write-down of oil and gas properties and impairments — 13 455 468 
Depletion 22,119 — — 22,119 
Income tax expense 11,156 — 13 11,169 
 
 		 
 		 
 		 
 		 
Total expenses 75,487 13 1,190 76,690 
 
 		 
 		 
 		 
 		 
Results of operations from oil and natural gas producing activities $46,899 $(13) $(1,190) $45,696 
 
 		 
 		 
 		 
 		 

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 agreement between Benton-VincclerHarvest Vinccler and PDVSA, under which all mineral rights are owned by the government of Venezuela. Venezuelan reserves include production projected through the end of the operating service agreement in July 2012. Benton-Vinccler
     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 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.

S-23

     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 requestedconfirmed 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 as of December 31, 2005, 2004 and 2003 were prepared by Ryder Scott Company L.P., independent petroleum engineers. The 2005 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 have been reduced to remove undeveloped reserves because the actions taken by the Venezuelan government in 2005 under our operating service agreement periodhave created uncertainty as to whether those reserves will be extended for the time sales were halted by the national civil work stoppagerecovered under the force majeure clause.economic and operating conditions which currently exist in Venezuela. For ease of reference, the reclassified reserves are hereafter referred to as “Contractually Restricted Reserves”.
     The tables shown below represent our interests in Venezuela 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, 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 
          
             
             
     (a) Includes primarily Contractually Restricted Reserves as well as other minor revisions.    
             
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)
Production  (8,152)  1,630   (6,522)
          
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)
          
Proved Reserves at end of the year  87,872   (17,574)  70,298 
          

S-24

             
      Minority    
      Interest in    
  Venezuela  Venezuela  Net Total 
Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at:
            
December 31, 2005  35,311   (7,062)  28,249 
December 31, 2004  45,488   (9,098)  36,390 
December 31, 2003  45,860   (9,172)  36,688 
January 1, 2003  53,833   (10,767)  43,066 
             
Proved Reserves-Natural gas (MMcf)
            
             
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.    
             
Year ended December 31, 2004
            
Proved Reserves beginning of the year  195,500   (39,100)  156,400 
Revisions of previous estimates  (159)  32   (127)
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 
Production  (2,660)  532   (2,128)
          
Proved Reserves end of the year  195,500   (39,100)  156,400 
          
             
Proved Developed Reserves-Natural gas (MMcf) at:
            
December 31, 2005  58,918   (11,784)  47,134 
December 31, 2004  80,897   (16,179)  64,718 
December 31, 2003  106,147   (21,229)  84,918 
January 1, 2003  105,000   (21,000)  84,000 
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 interest in Venezuela in each of the years. We report the results of Ryder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan reserves.

S-25

             
      Minority    
      Interest in    
  Venezuela  Venezuela  Net Total 
  (amounts 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 
          
             
December 31, 2004
            
Future cash inflows from sales of oil and gas $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 income tax expenses  (428,833)  85,767   (343,066)
          
Future net cash flows  939,274   (187,854)  751,420 
Effect of discounting net cash flows at 10%  (258,049)  51,609   (206,440)
          
Standardized measure of discounted future net cash flows $681,225  $(136,245) $544,980 
          
             
December 31, 2003
            
Future cash inflows from sales of oil and gas $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 income tax expenses  (317,018)  63,404   (253,614)
          
Future net cash flows  683,770   (136,754)  547,016 
Effect of discounting net cash flows at 10%  (225,306)  45,060   (180,246)
          
Standardized measure of discounted future net cash flows $458,464  $(91,694) $366,770 
          
(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 
  2005  2004  2003 
  (amounts in thousands) 
Standardized Measure at January 1 $544,980  $366,770  $317,799 
Sales of oil and natural gas, net of related costs  (124,638)  (122,215)  (59,720)
Revisions to estimates of proved reserves            
Net changes in prices, development and production costs  262,852   333,237   76,037 
Quantities  (365,565)  (7,597)  (1,584)
Extensions, discoveries and improved recovery, net of future costs  —   —   4,971 
Accretion of discount  80,202   54,531   48,128 
Net change in income taxes  109,030   (78,504)  (15,053)
Development costs incurred  7,130   31,329   46,463 
Changes in timing and other  (184,553)  (32,571)  (50,271)
          
Standardized Measure at December 31 $329,438  $544,980  $366,770 
          

S-26

Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)
for Russia Equity Affiliate as of September 30, their fiscal year end.
     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 percent ownership until sold September 25, 2003) which was accounted for under the equity method, has been included at its respective ownership interest in the consolidated financial statements and the following Tables based on a fiscal period ending September 30 and, accordingly, results of operations for oil and natural gas producing activities in Russia reflect the year ended September 30, 2003.
TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
     
  Geoilbent 
Year Ended September 25, 2003
    
Development costs $3,474 
Exploration costs  1,034 
    
  $4,508 
    
TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):
     
  Geoilbent 
September 25, 2003
    
Proved property costs $102,753 
Oilfield inventories  2,530 
Less accumulated depletion and impairment  (72,333)
    
  $32,950 
    
TABLE III — Results of operations for oil and natural gas producing activities (in thousands):
     
  Geoilbent 
Year ended September 25, 2003
    
Oil sales $27,876 
Expenses:    
Operating, selling and distribution expenses and taxes other than on income  16,088 
Depletion  6,215 
Write-down of oil and gas properties  32,300 
Income tax expense  2,073 
    
Total expenses  56,676 
    
Results of operations from oil and natural gas producing activities $(28,800)
    

S-27

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 oil fields are situated on land belonging to the Government of the Russian Federation. It obtained licenses from the local authorities and paid unified production taxes to explore and produce oil from these fields. Geoilbent had licenses to develop the North Gubkinskoye and South Tarasovskoye fields in western Siberia. Our 34 percent equity investment in Geoilbent was sold September 25, 2003.
     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 and economic changes. 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.

S-26

     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 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 evaluations of the oil and natural gas reserves as of December 31, 2003, 2002 and 2001 were prepared by Ryder Scott Company L.P., independent petroleum engineers.

     The tables shown below represent our interests in the United Sates and Venezuela 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, 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 
           
 		 
Year ended December 31, 2001
            
Proved Reserves at beginning of the year  123,039   (24,608)  98,431 
Revisions of previous estimates  (8,747)  1,749   (6,998)
Purchases of reserves in place  —   —   — 
Extensions, discoveries and improved recovery  —   —   — 
Production  (9,778)  1,956   (7,822)
Sales of reserves in place  —   —   — 
   
 		   
 		   
 		 
Proved Reserves at end of the year  104,514   (20,903)  83,611 
   
 		   
 		   
 		 
Russia – Arctic Gas (39%) Proved Reserves at end of the year          20,964 
           
 		 
Russia – Geoilbent (34%) Proved Reserves at end of the year          29,668 
           
 		 

S-27S-28

             
      Minority  
      Interest in  
  Venezuela
 Venezuela
 Net Total
Proved Developed Reserves at:
            
December 31, 2003  45,860   (9,172)  36,688 
December 31, 2002  53,833   (10,767)  43,066 
December 31, 2001  51,465   (10,293)  41,172 
January 1, 2001  67,217   (13,443)  53,774 
Russia – Arctic Gas Proved Reserves at end of the year            
2001 (39%)          2,483 
2000 (29%)          2,325 
Russia – Geoilbent (34%) Proved Reserves at end of the year            
2002          11,840 
2001          15,658 
2000          14,913 
Proved Reserves-natural gas (MMcf)
            
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 
   
 		   
 		   
 		 
Russia – Arctic Gas (39%) Proved Reserves – December 31, 2001     ��    208,010 
           
 		 
Russia – Arctic Gas (39%) Proved Reserves – December 31, 2000          152,496 
           
 		 
Proved Developed Reserves at:
            
December 31, 2003  106,147   (21,229)  84,918 
December 31, 2002  105,000   (21,000)  84,000 
Russia – Arctic Gas 2001 (39%)          21,292 
Russia – Arctic Gas 2000 (29%)          17,801 

TABLE V -Standardized MeasureGeoilbent
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls)
Year ended September 30, 2003
Proved reserves beginning of Discounted Future Net Cash Flows Related to the year25,356
Revisions of previous estimates537
Extensions, discoveries and improved recovery962
Production(1,942)
Sales of reserves in place(24,913)
Proved Oil and Natural Gas Reserve Quantitiesreserves at end of the year—
Proved Developed Reserves at:
September 30, 2003—
October 1, 200213,200

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 interest in Venezuela in each of the years. In addition to these reserves is our 34 percent interest in Geoilbent at December 31, 2002 and our Arctic Gas interest of 39% at December 31, 2001. This combined with our Venezuela crude oil and natural gas reserves represent our net interest in all reserves as of December 31, 2003. We report the results of Ryder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan reserves.

S-28

                
 Minority   Geoilbent 
 Interest in   (amounts in thousands) 
 Venezuela
 Venezuela
 Net Total
 (amounts in thousands)
December 31, 2003
 
September 30, 2003
 
Future cash inflow $1,513,525 $(302,705) $1,210,820  $481,557 
Future production costs  (382,577) 76,515  (306,062)  (229,982)
Future development costs  (130,160) 26,032  (104,128)  (36,666)
 
 		 
 		 
 		    
Future net revenue before income taxes 1,000,788  (200,158) 800,630  214,909 
10% annual discount for estimated timing of cash flows  (319,152) 63,830  (255,322)  (99,948)
 
 		 
 		 
 		    
Discounted future net cash flows before income taxes 681,636  (136,328) 545,308  114,961 
Future income taxes, discounted at 10% per annum  (223,172) 44,634  (178,538)  (23,163)
 
 		 
 		 
 		    
Standardized measure of discounted future net cash flows $458,464 $(91,694) $366,770  $91,798 
 
 		 
 		 
 		    
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 
 
 		 
December 31, 2001
 
Future cash inflow $1,030,404 $(206,081) $824,323 
Future production costs  (558,431) 111,686  (446,745)
Future development costs  (142,006) 28,401  (113,605)
 
 		 
 		 
 		 
Future net revenue before income taxes 329,967  (65,994) 263,973 
10% annual discount for estimated timing of cash flows  (109,704) 21,941  (87,763)
 
 		 
 		 
 		 
Discounted future net cash flows before income taxes 220,263  (44,053) 176,210 
Future income taxes, discounted at 10% per annum  (16,103) 3,221  (12,882)
 
 		 
 		 
 		 
Standardized measure of discounted future net cash flows $204,160 $(40,832) $163,328 
 
 		 
 		 
 		 
Russia – Arctic Gas (29%) $82,205 
 
 		 
Russia – Geoilbent (34%) $70,648 
 
 		 

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

             
      Net Venezuela
  
  2003
 2002
 2001
  (amounts in thousands)
Present Value at January 1 $317,799  $163,328  $284,549 
Sales of oil and natural gas, net of related costs  (59,720)  (76,098)  (64,139)
Revisions to estimates of Proved Reserves            
Net changes in prices, development and production costs  76,037   310,043   (141,429)
Quantities  (1,584)  611   (26,198)
Extensions, discoveries and improved recovery, net of future costs  4,971   89,670   — 
Accretion of discount  48,128   17,621   36,846 
Net change in income taxes  (15,053)  (150,603)  71,033 
Development costs incurred  46,463   40,532   23,768 
Changes in timing and other  (50,271)  (77,305)  (21,102)
   
 		   
 		   
 		 
Present Value at December 31 $366,770  $317,799  $163,328 
   
 		   
 		   
 		 

S-29

Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Russia Equity Affiliates as of September 30, their fiscal year end.

     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

TABLE 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 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 are accounted for under the equity method, have been included at their respective ownership interests-Changes in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, resultsStandardized Measure of operations for oil and natural gas producing activities in Russia reflect the years ended September 30, 2002 and 2001.

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

             
          Total Equity
  Arctic Gas
 Geoilbent
 Affiliates
Year Ended September 25, 2003
            
Development costs $—  $3,474  $3,474 
Exploration costs  —   1,034   1,034 
   
 		   
 		   
 		 
  $—  $4,508  $4,508 
   
 		   
 		   
 		 
Year Ended September 30, 2002
            
Development costs $—  $8,599  $8,599 
Exploration costs  16,156   498   16,654 
   
 		   
 		   
 		 
  $16,156  $9,097  $25,253 
   
 		   
 		   
 		 
Year Ended September 30, 2001
            
Development costs $—  $11,483  $11,483 
Exploration costs  8,136   2,074   10,210 
   
 		   
 		   
 		 
  $8,136  $13,557  $21,693 
   
 		   
 		   
 		 

TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):

             
          Total Equity
  Arctic Gas
 Geoilbent
 Affiliates
September 25, 2003
            
Proved property costs $—  $102,753  $102,753 
Oilfield inventories  —   2,530   2,530 
Less accumulated depletion and impairment  —   (72,333)  (72,333)
   
 		   
 		   
 		 
  $—  $32,950  $32,950 
   
 		   
 		   
 		 
September 30, 2002
            
Proved property costs $—  $94,404  $94,404 
Costs excluded from amortization  —   272   272 
Oilfield inventories  —   2,348   2,348 
Less accumulated depletion and impairment  —   (31,440)  (31,440)
   
 		   
 		   
 		 
  $—  $65,584  $65,584 
   
 		   
 		   
 		 
September 30, 2001
            
Proved property costs $5,786  $85,677  $91,463 
Costs excluded from amortization  11,549   —   11,549 
Oilfield inventories  175   4,357   4,532 
Less accumulated depletion and impairment  (389)  (22,203)  (22,592)
   
 		   
 		   
 		 
  $17,121  $67,831  $84,952 
   
 		   
 		   
 		 

S-30

TABLE III — Results of operations for oil and natural gas producing activities (in thousands):

             
          Total Equity
  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 
Depletion  —   6,215   6,215 
Write-down of oil and gas properties  —   32,300   32,300 
Income tax expense  —   2,073   2,073 
   
 		   
 		   
 		 
Total expenses  —   56,676   56,676 
   
 		   
 		   
 		 
Results of operations from oil and natural gas producing activities $—  $(28,800) $(28,800)
   
 		   
 		   
 		 
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 
   
 		   
 		   
 		 
Year ended September 30, 2001
            
Oil sales $4,016  $34,261  $38,277 
Expenses:            
Operating, selling and distribution expenses and taxes other than on income  3,381   16,083   19,464 
Depletion  311   5,072   5,383 
Income tax expense  80   3,742   3,822 
   
 		   
 		   
 		 
Total expenses  3,772   24,897   28,669 
   
 		   
 		   
 		 
Results of operations from oil and natural gas producing activities $244  $9,364  $9,608 
   
 		   
 		   
 		 

TABLE IV — Quantities of Oil and Natural Gas Reserves

Discounted Future Net Cash Flows from 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 fields are situated on land belonging 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 fields 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.

     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 and economic changes. 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 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.

S-31

     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.

             
          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 
   
 		   
 		   
 		 
Year ended September 30, 2001
            
Proved Reserves beginning of the year  15,821   32,614   48,435 
Revisions of previous estimates  5,327   (5,594)  (267)
Extensions, discoveries and improved recovery  —   4,411   4,411 
Production  (183)  (1,763)  (1,946)
Sales of reserves in place  —   —   — 
   
 		   
 		   
 		 
Proved Reserves at end of the year  20,965   29,668   50,633 
   
 		   
 		   
 		 
Proved Developed Reserves at:
            
September 30, 2003  —   —   — 
September 30, 2002  —   13,200   13,200 
September 30, 2001  2,483   15,658   18,141 
October 1, 2000  2,325   14,913   17,238 
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  —   —   — 
   
 		   
 		   
 		 

S-32

             
          Total Equity
  Arctic Gas
 Geoilbent
 Affiliates
Year ended September 30, 2001
            
Proved Reserves beginning of the year  152,496   —   152,496 
Revisions of previous estimates  55,514   —   55,514 
Extensions, discoveries and improved recovery  —   —   — 
Production  —   —   — 
Sales of reserves in place  —   —   — 
   
 		   
 		   
 		 
Proved Reserves end of the year  208,010   —   208,010 
   
 		   
 		   
 		 
Proved Developed Reserves at:
            
September 30, 2002  —   —   — 
September 30, 2001  21,292   —   21,292 
October 1, 2000  17,801   —   17,801 
   
TABLE V -
 Standardized MeasureGeoilbent
2003
(amounts in thousands)
Present Value at October 1$92,939
Sales of Discounted Future Net Cash Flows Relatedoil and natural gas, net of related costs(20,410)
Revisions to estimates of Proved Oil and Natural Gas Reserve QuantitiesReserves

     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
  Arctic Gas
 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 
   
 		   
 		   
 		 
September 30, 2001
            
Future cash inflow $630,340  $434,348  $1,064,688 
Future production costs  (373,458)  (251,335)  (624,793)
Future development costs  (49,139)  (37,020)  (86,159)
   
 		   
 		   
 		 
Future net revenue before income taxes  207,743   145,993   353,736 
10% annual discount for estimated timing of cash flows  (99,343)  (64,868)  (164,211)
   
 		   
 		   
 		 
Discounted future net cash flows before income taxes  108,400   81,125   189,525 
Future income taxes, discounted at 10% per annum  (26,195)  (10,477)  (36,672)
   
 		   
 		   
 		 
Standardized measure of discounted future net cash flows $82,205  $70,648  $152,853 
   
 		   
 		   
 		 

S-33

   
TABLE VI - Net changes in prices, development and production costs
(5,522)
Quantities3,178
Sales of reserves in place(91,798)
Extensions, discoveries and improved recovery, net of future costs1,246
Accretion of discount11,723
Net change in income taxes1,127
Development costs incurred4,507
Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reservestiming and other3,010
Present Value at September 30$—
             
      Equity Affiliates  
  
  2003
 2002
 2001
  (amounts in thousands)
Present Value at October 1 $92,939  $152,853  $171,605 
Sales of oil and natural gas, net of related costs  (20,410)  (23,644)  (19,001)
Revisions to estimates of Proved Reserves            
Net changes in prices, development and production costs  (5,522)  76,545   (39,880)
Quantities  3,178   (10,007)  8,881 
Sales of reserves in place  (91,797)  (82,205)  — 
Extensions, discoveries and improved recovery, net of future costs  1,245   2,031   18,767 
Accretion of discount  11,723   7,065   21,468 
Net change in income taxes  1,127   1,145   6,400 
Development costs incurred  4,507   8,999   17,110 
Changes in timing and other  3,010   (39,843)  (32,497)
   
 		   
 		   
 		 
Present Value at September 30 $—  $92,939  $152,853 
   
 		   
 		   
 		 

S-34S-30

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: March 9, 2004February 27, 2006 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 9th27th day of March, 2004,February, 2006, on behalf of the registrant and in the capacities indicated:
   
Signature
 Title
/s/Peter J. HillDirector, President and Chief Executive
Officer
Peter J. Hill
   
/s/ James A. Edmiston
James A. Edmiston
Director, President and Chief Executive Officer
/s/ Steven W. Tholen
Steven W. Tholen
 Senior Vice President — Finance, Chief Financial
Officer and Treasurer
Steven W. Tholen
(Principal Financial Officer)		  
   
/s/ Kurt A. Nelson
Kurt A. Nelson
 Vice President-Controller,
Kurt A. Nelson Chief
Accounting Officer
(Principal Accounting Officer)  
   
/s/ Stephen D. Chesebro’
Stephen D. Chesebro’
 Chairman of the Board and Director
  
Stephen D. Chesebro’
/s/ John U. Clarke
John U. Clarke
 Director
   
/s/ John U. ClarkeH. H. Hardee
H. H. Hardee
 Director
John U. Clarke
   
/s/ Byron A. DunnPeter J. Hill
Peter J. Hill
 Director
Byron A. Dunn
   
/s/ H. H. HardeePatrick M. Murray
Patrick M. Murray
 Director
H.H. Hardee
   
/s/ Patrick M. MurrayJ. Michael Stinson
J. Michael Stinson
 Director
Patrick M. Murray

S-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 Deductions Balance at
 Beginning Charged to Other From End of Beginning Charged to Other From End of
 of Year Income Accounts Reserves Year
At December 31, 2005
 
Amounts deducted from applicable assets 
Accounts receivable $2,757 $— $— $— $2,757 
Deferred tax valuation allowance 40,492  (13,129) — — 27,363 
Investment at cost 1,350 — — — 1,350 
 
At December 31, 2004
 
Amounts deducted from applicable assets 
Accounts receivable $3,355 $— $— $598 $2,757 
Deferred tax valuation allowance 48,365  (7,873) — — 40,492 
Investment at cost 1,350 — — — 1,350 
 of Year
 Income
 Accounts
 Reserves
 Year
 
At December 31, 2003
  
Amounts deducted from applicable assetsAmounts deducted from applicable assets 
Accounts receivable $3,525 $205 $— $375 $3,355  $3,525 $205 $— $375 $3,355 
Deferred tax valuation allowance 39,146 9,219 — — 48,365  39,146 9,219 — — 48,365 
Investment at cost 1,350 — — — 1,350  1,350 — — — 1,350 
At December 31, 2002
 
Amounts deducted from applicable assets
Accounts receivable $6,512 $289 $— $3,276 $3,525 
Deferred tax valuation allowance 19,700 20,577 — 1,131 39,146 
Investment at cost 1,350 — — — 1,350 
At December 31, 2001
 
Amounts deducted from applicable assets
Accounts receivable $6,518 $330 $— $336 $6,512 
Deferred tax valuation allowance 54,207 14,352  (11,008) 37,851 19,700 
Investment at cost 1,350 — — — 1,350 

S-36

SCHEDULE III

Financial Statements and Notes
for LLC Geoilbent

LLC Geoilbent
Financial Statements
30 September 2003

 

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 20032004

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-temlong-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 concecutiveconsecutive 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 dicusseddiscussed 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
 outstanding
30 September 2003 to 27 January 2004  50,000 
27 January 2004 to 27 July 2004  41,667 
27 July 2004 to 27 January 2005  33,333 
27 January 2005 to 27 July 2005  25,000 
27 July 2005 to 27 January 2006  16,667 
27 January 2006 to 27 January 2007  8,333 
Thereafter  — 
   
 		 

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

     
Thousands of US dollars
    
Year ended 30 September 2004  7,500 
Year ended 30 September 2005  5,000 
Year ended 30 September 2006  8,333 
Year ended 30 September 2007  8,333 
Year ended 30 September 2008  8,333 
   
 		 

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 period  5.6 
Increase related to DTA resulting from the December ceiling test writedown  12.0 
Net other increase in DTA movements during the December quarter  1.0 
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 writedown  3.2 
Net other increase in DTA movements  1.0 
   
 		 
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

EXHIBIT INDEX
3. Exhibits:
   
ExhibitsDescription of Exhibit
3.1 Amended and Restated Certificate of Incorporation filed September 9, 1988Incorporation. (Incorporated by reference to Exhibit 3.13.1(i) to our Registration Statement (RegistrationForm 10-Q filed on August 13, 2002, File No. 33-26333)1-10762.).
   
3.2 Amendment to Certificate of Incorporation filed June 7, 1991 (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-39214)).
3.3Amended and Restated Bylaws as of December 11, 2003.May 19, 2005. (Incorporated by reference to Exhibit 3.2 to our Form 10-Q filed on April 29, 2005, File No. 1-10762.)
   
4.1 Form of Common Stock Certificate (Previously filed as an exhibitCertificate. (Incorporated by reference to the exhibits to our S-1 Registration Statement Form S-1 (Registration No. 33-26333).).
   
4.2 Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.)
   
4.3 Second Amended and Restated Rights Agreement, dated as of April 15, 2005, between Benton OilHarvest Natural Resources, Inc. and Gas Company and First InterstateWells Fargo Bank, Rights Agent dated April 28, 1995.N.A. (Incorporated by reference to Exhibit 4.14.3 to our Form 10-Q filed on August 13, 2002,April 29, 2005, File No. 1-10762.)
   
10.1Form of Employment Agreements (Exhibit 10.19)(Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-26333)).
10.2 Operating 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—Exhibit 10.25)(Previously filed as an exhibitCommission. (Incorporated by reference to the exhibits to our S-1 Registration Statement Form S-1 (Registration No. 33-52436).).

 

   
ExhibitsDescription of Exhibit
10.3Indenture dated November 1, 1997 between Benton Oil and Gas Company and First Trust of New York, National Association, Trustee related to an aggregate of $115,000,000 principal amount of 9 3/8 percent Senior Notes due 2007 (Incorporated by reference to Exhibit 10.1 to our Form 10-Q for the quarter ended September 30, 1997, File No. 1-10762).
10.410.2 Note payable agreementPayable Agreement dated March 8, 2001 between Benton-Vinccler,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 PipelinePipeline. (Incorporated by reference to Exhibit 10.24 to our Form 10-Q, filed on May 15, 2001, File No. 1-10762).1-10762.)
   
10.5Change 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.).
10.610.3 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.).
   
10.7First 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.).
10.810.4 Sale 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.)
   
10.910.5 2001 Long Term Stock Incentive PlanPlan. (Incorporated by reference to Exhibit 4.1 to our S-8 (Registration Statement No. 333-85900).).
   
10.1010.6 Addendum No. 2 to Operating ServicesService Agreement Monagas SUR dated 19th19th September, 2002. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.)
   
10.1110.7 Bank Loan Agreement between Banco Mercantil, C.A. and Benton-VincclerHarvest 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.)
   
10.1210.8 Guaranty 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.)
   
10.13Employment 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.)
10.14Employment 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.)
10.15Employment 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.)
10.1610.9† 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.)
   
10.1710.10 Sale 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.)
   
10.1810.11† Employment Agreement dated November 17, 2003 between Harvest Natural Resources Inc.

ExhibitsDescription of2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit
and Karl L. Nesselrode. 4.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).)
   
10.12†Indemnification Agreement between Harvest Natural Resources, Inc. and the Directors and Executive Officers of the Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
10.13†Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
10.14†Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
10.15†Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.22 to our Form 10-K filed on February 23, 2005, File No. 1-10762.)
10.16The Transitory Agreement between Harvest Natural Resources, Inc. and PDVSA Petroleo S.A., dated August 4, 2005. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)

10.17†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.)
10.18†Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
10.19†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.)
10.20†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.)
10.21†Employment Agreement dated September 26, 2005 between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
10.22†Separation Agreement dated September 30, 2005, between Harvest Natural Resources, Inc. and Dr. Peter J. Hill. (Incorporated by reference to Exhibit 10.7 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
10.23†Consulting Agreement dated October 1, 2005, between Harvest Natural Resources, Inc. and Dr. Peter J. Hill. (Incorporated by reference to Exhibit 10.8 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.)
10.24†Stock Options Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston.
10.25†Stock Options Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston.
10.26†Stock Options Agreement dated September 26, 2005 between Harvest Natural Resources, Inc. and Byron A. Dunn.
21.1 List of subsidiaries.
 
 
23.1 Consent of PricewaterhouseCoopers LLP -— Houston
 
 
23.2 Consent of ZAO PricewaterhouseCoopers Audit -— Moscow
 
 
23.3 Consent of Ryder Scott Company, LP
 
 
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.
 
32.1 CertificationsCertification accompanying the annual reportAnnual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.2002 executed by James A. Edmiston, President and Chief Executive Officer.
32.2Certification accompanying Annual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer.

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