HARVEST NATURAL RESOURCES, INC.

FORM 10-K

(Annual Report)

Filed 03/16/10 for the Period Ending 12/31/09

 

Address 1177 ENCLAVE PARKWAY

STE 300

HOUSTON, TX 77077

Telephone 281-899-5700

CIK 0000845289

Symbol HNR

SIC Code 1311 - Crude Petroleum and Natural Gas

Industry Oil & Gas Operations

Sector Energy

Fiscal Year 12/31

 

http://www.edgar-online.com

© Copyright 2010, EDGAR Online, Inc. All Rights Reserved.

Distribution and use of this document restricted under EDGAR Online, Inc. Terms of Use.
Table of Contents 
Table of Contents 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION 

WASHINGTON, DC 20549 

FORM 10-K 

(Mark One) 

For the fiscal year ended December 31, 2009 

or 

Commission File No.: 1-10762 

HARVEST NATURAL RESOURCES, INC. 

(Exact name of registrant as specified in its charter) 

Registrant’s telephone number, including area code: (281) 899-5700 

Securities registered pursuant to Section 12(b) of the Act: 

Securities registered pursuant to Section 12(g) of the Act: Preferred Share Purchase Rights 

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  No  

Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  No  

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  No  

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File 

required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for 

such shorter period that the registrant was required to submit and post such files). Yes  No  

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.  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a smaller reporting company. See the definition 

of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No  

The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates computed by reference to the price at 

which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 2009 was: $144,812,960. 

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practical date. Class: Common 

Stock, par value $0.01 per share, on March 9, 2010, shares outstanding: 33,260,554. 

 

 

 

 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE 

ACT OF 1934 

 

 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES 

EXCHANGE ACT OF 1934 

 

Delaware 77-0196707 

(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number) 

 

1177 Enclave Parkway, Suite 300 

Houston, Texas 77077 

(Address of principal executive offices) (Zip Code) 

 

Title of each class Name of each exchange on which registered 

 

Common Stock, $.01 Par Value NYSE 

 

Large Accelerated Filer  Accelerated Filer  Non-Accelerated Filer  Smaller Reporting Company  

 (Do not check if a smaller reporting company) 
DOCUMENTS INCORPORATED BY REFERENCE 

Portions of the registrant’s Proxy Statement for the 2010 Annual Meeting of Stockholders to be filed with the Securities and Exchange 

Commission, not later than 120 days after the close of the registrant’s fiscal year, pursuant to Regulation 14A, are incorporated by reference into 

Items 10, 11, 12, 13 and 14 of Part III of this annual report. 

 

 

 
 

HARVEST NATURAL RESOURCES, INC. 

FORM 10-K 

TABLE OF CONTENTS 

 

 

 Page 

Part I 

 

 Item 1. Business 1 

 Item 1A. Risk Factors 16 

 Item 1B. Unresolved Staff Comments 21 

 Item 2. Properties 21 

 Item 3. Legal Proceedings 22 

 Item 4. [Reserved] 

 

Part II 

 

 Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 23 

 Item 6. Selected Financial Data 25 

 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 26 

 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 39 

 Item 8. Financial Statements and Supplementary Data 39 

 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 39 

 Item 9A. Controls and Procedures 40 

 Item 9B. Other Information 40 

 

Part III 

 

 Item 10. Directors, Executive Officers and Corporate Governance 40 

 Item 11. Executive Compensation 41 

 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 41 

 Item 13. Certain Relationships and Related Transactions, and Director Independence 41 

 Item 14. Principal Accountant Fees and Services 41 

 

Part IV 

 

 Item 15. Exhibits and Financial Statement Schedules 42 

 

Financial Statements S-2 

 

Signatures S-39 

 EX-21.1 

 EX-23.1 

 EX-23.2 

 EX-23.3 

 EX-31.1 

 EX-31.2 

 EX-32.1 

 EX-32.2 

 EX-99.1 

 EX-99.2 
Table of Contents 

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”, “expect”, “believes”, “goals”, “projects”, “plans”, “anticipates”, “estimates”, “should”, “could”, “assume” and similar 

expressions are intended to identify forward-looking statements. In accordance with the provisions of the Private Securities Litigation Reform 

Act of 1995, we caution you that important factors could cause actual results to differ materially from those in the forward-looking statements. 

Such factors include our concentration of operations in Venezuela, the political and economic risks associated with international operations 

(particularly those in Venezuela), the anticipated future development costs for undeveloped reserves, drilling risks, the risk that actual results 

may vary considerably from reserve estimates, the dependence upon the abilities and continued participation of certain of our key employees, 

the risks normally incident to the exploration, operation and development of oil and natural gas properties, risks incumbent to holding a 

noncontrolling interest in a corporation, the permitting and the drilling of oil and natural gas wells, the availability of materials and supplies 

necessary to projects and operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, the Company’s 

ability to acquire oil and natural gas properties that meet its objectives, availability and cost of drilling rigs and seismic crews, overall 

economic conditions, political stability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or 

potential tariffs, duties or quotas, changes in taxes, changes in governmental policy, availability of sufficient financing including the Company’s 

ability to obtain the Islamic (sukuk) financing described in Item 1A — Risk Factors, changes in weather conditions, and ability to hire, retain 

and train management and personnel. See Item 1A — Risk Factors and Item 7 — Management’s Discussion and Analysis of Financial Condition 

and Results of Operations. 

Item 1. Business 

Executive Summary 

 Harvest Natural Resources, Inc. is an international petroleum exploration and production company incorporated under Delaware law in 1989. 

Our focus is on acquiring exploration, development and producing properties in geological basins with proven active hydrocarbon systems. Our 

experienced technical, business development and operating staffs have identified low entry cost exploration opportunities in areas with large 

hydrocarbon resource potential. We operate from our Houston, Texas headquarters. We also have regional/technical offices in the United 

Kingdom and Singapore, and small field offices in Jakarta, Indonesia, Muscat, Sultanate of Oman (“Oman”) and Roosevelt, Utah to support field 

operations in those areas. We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”) through 

our 40 percent equity affiliate, Petrodelta, S.A. (“Petrodelta”), which operates a portfolio of properties in eastern Venezuela including large 

proven oil fields as well as properties with very substantial opportunities for both development and exploration. We have seconded key technical 

and managerial personnel into Petrodelta and participate on Petrodelta’s board of directors. Geophysical, geosciences, and reservoir engineering 

support services are available to our in-house experts through our minority equity investment in Fusion Geophysical, LLC (“Fusion”). Fusion is 

a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering headquartered in the Houston area. Through the 

pursuit of technically-based strategies guided by conservative investment philosophies, we are building a portfolio of exploration prospects to 

complement the low-risk production, development, and exploration project in Venezuela. Currently, we hold interests in Venezuela, the Gulf 

Coast Region of the United States through an Area of Mutual Intent (“AMI”) agreement with two private third parties, the Antelope prospect in 

the Western United States through a Joint Exploration and Development Agreement (“JEDA”), and exploration acreage mainly onshore West 

Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in Oman and offshore of the 

People’s Republic of China (“China”). 

 HNR Finance B.V. (“HNR Finance”) has a 40 percent ownership interest in Petrodelta. As we indirectly own 80 percent of HNR Finance, we 

indirectly own a net 32 percent interest in Petrodelta, and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A. 

(“OGTC”), a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining eight 

percent interest. 

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Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petrodelta is governed by its own board of 

directors, charter and bylaws. 

 On April 11, 2009, we signed an Exploration and Production Sharing Agreement (“EPSA”) with Oman for the Al Ghubar / Qarn Alam 

license (“Block 64 EPSA”). 

 On April 23, 2009, Petrodelta’s board of directors declared a dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net 

to our 32 percent interest), which represents Petrodelta’s net income as reported under International Financial Reporting Standards (“IFRS”) for 

the six months ended June 30, 2008. HNR Finance received the cash related to this dividend in the form of an advance dividend in October 2008. 

 In June 2009, drilling operations commenced on a deep natural gas test well (the Bar F #1-20-3-2 [“Bar F”]). The Bar F was drilled as a tight 

hole and was permitted to 18,000 feet. Drilling was completed in the fourth quarter of 2009 at a depth of 17,566 feet and production casing has 

been run. Production testing of the well commenced in November 2009 and continues in the first quarter of 2010. The testing program is 

expected to be completed by the end of the first quarter of 2010. 

 In December 2009, drilling operations commenced in an eight well appraisal and development drilling program to produce oil and natural gas 

from the Green River formation on the southern portion of our Antelope land position. As of March 1, 2010, all eight wells have been drilled. 

Seven wells are currently on production. One additional well is waiting on completion operations and is anticipated to commence production in 

early March 2010. 

 During the year ended December 31, 2009, Petrodelta drilled and completed 14 successful development wells, suspended one well due to 

problems with the well and drilled two appraisal wells. Petrodelta currently has one drilling rig working in the Uracoa field. 

 On January 28, 2010, we entered into an agreement with one of the private third parties in our AMI for an option to participate in a new 

project. We paid $1.5 million for the option to acquire up to a 50 percent interest in the new project. If we exercise our option to participate, we 

will participate in this project with essentially the same terms as the other existing projects in the AMI. The option to participate expires on 

June 1, 2010. 

 On February 17, 2010, we closed a debt offering of $32 million in aggregate principal amount of our 8.25 percent senior convertible notes 

due 2013, which resulted in net proceeds to us, after deducting underwriting discounts, commissions and estimated offering expenses, of 

approximately $30 million. 

 See Item 1 — Business, Operations, Item 1A — Risk Factors, and Item 7 — Management’s Discussion and Analysis of Financial Condition 

and Results of Operations for a more detailed description of these and other events during 2009. 

 As of December 31, 2009, we had total assets of $348.8 million, unrestricted cash of $32.3 million and no long-term debt. For the year ended 

December 31, 2009, we had revenues of $0.2 million and net cash used in operating activities of $34.9 million. Subsequent to December 31, 

2009, we offered and issued $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes due 2013. As of 

December 31, 2008, we had total assets of $362.3 million, unrestricted cash of $97.2 million and no long-term debt. For the year ended 

December 31, 2008, we had no revenues and net cash provided by operating activities of $50.4 million. 

 Our strategy has broadened from our primary focus on Venezuela to identify, access and integrate hydrocarbon assets to include organic 

growth through exploration in basins globally with proven hydrocarbon systems as an alternative to purchasing proved producing assets. We 

seek to leverage our Venezuelan experience as well as our recently expanded business development and technical platform to create a diversified 

resource base. With the addition of exploration technical resources, opening of our London and Singapore offices, as well as our minority equity 

investment in Fusion, we have made significant investments to provide the necessary foundation and global reach required for an organic growth 

focus. While exploration will become a larger part of our overall portfolio, we generally restrict ourselves to basins with known hydrocarbon 

systems and favorable risk-reward profiles. 

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 We intend to use our available cash to pursue additional growth opportunities in the United States, Indonesia, Gabon, Oman, China and other 

countries that meet our strategy. However, the execution of this strategy may be limited by factors including access to additional capital and the 

receipt of dividends from Petrodelta as well as the need to preserve adequate development capital in the interim. As described in Item 7 — 

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Capital Resources and Liquidity , on February 17, 

2010, we incurred indebtedness of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. As a result of this 

offering, we received net proceeds, after deduction of underwriting discounts, commissions and estimated offering expenses, of approximately 

$30.0 million. We intend to use these net proceeds to fund capital expenditures and for working capital needs and general corporate purposes. 

 The ability to successfully execute our strategy is subject to significant risks including, among other things, payment of Petrodelta dividends, 

exploration, operating, political, legal and financial risks. See Item 1A — Risk Factors , Item 7 — Management’s Discussion and Analysis of 

Financial Condition and Results of Operations and other information set forth elsewhere in this Annual Report on Form 10-K for a description 

of these and other risk factors. 

Available Information 

 We file annual, quarterly and current reports, proxy statements and other documents with the Securities and Exchange Commission (“SEC”) 

under the Securities Exchange Act of 1934 (“Exchange Act”). The public may read and copy any materials that we file with the SEC at the 

SEC’s Office of Investor Education and Advocacy at 100 F Street NE, Washington, DC 20549-0213. The public may obtain information on the 

operation of the Office of Investor Education and Advocacy 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 at http://www.sec.gov. 

 We also make available, free of charge on or through our Internet website (http://www.harvestnr.com), our Annual Report on Form 10-K, 

Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and if applicable, amendments to those reports filed or furnished pursuant to 

Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 

Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Exchange Act are also available on our website. In 

addition, we have adopted a Code of Business Conduct and Ethics that applies to all of our employees, including our chief executive officer, 

principal financial officer and principal accounting officer. The text of the Code of Business Conduct and Ethics has been posted on the 

Corporate Governance section of our website. We intend to post on our website any amendments to, or waivers from, our Code of Business 

Conduct and Ethics applicable to our senior officers. Additionally, the Code of Business Conduct and Ethics is available in print to any person 

who requests the information. Individuals wishing to obtain this printed material should submit a request to Harvest Natural Resources, Inc., 

1177 Enclave Parkway, Suite 300, Houston, Texas 77077, Attention: Investor Relations. 

Operations 

 Since April 1, 2006, our Venezuelan operations have been conducted through our equity affiliate Petrodelta which is governed by the 

Contract of Conversion (“Conversion Contract”) signed on September 11, 2007. All of the equity investment in HNR Finance and Harvest 

Vinccler, S.C.A. (“Harvest Vinccler”) is owned by Harvest-Vinccler Dutch Holding B.V., a Netherlands private company with limited liability. 

We own an 80 percent equity investment in Harvest-Vinccler Dutch Holding B.V. The remaining 20 percent noncontrolling interest is owned by 

OGTC. In addition, we have an interest varying from 50 to 55 percent by prospect in an area of the Gulf Coast Region of the United States 

covered by an AMI agreement with private third parties, a 60 percent interest in the Antelope prospect in the Western United States covered by a 

JEDA, a 47 percent interest in the Budong-Budong production sharing contract (“Budong PSC”) which we may operate during the production 

phase, a 66.667 percent interest in the production sharing contract related to the Dussafu Marin Permit production sharing contract (“Dussafu 

PSC”) for which we are the operator, a 100 percent interest in an Exploration and Production Sharing Agreement (“EPSA”) with Oman for the 

Al Ghubar/Qarn Alam license, and a 100 percent interest in the WAB-21 petroleum contract in the South China Sea for which we are the 

operator. See Item 1 — Business, United States; Budong-Budong, Onshore Indonesia; Dussafu Marin, Offshore Gabon, Block 64 Project, Oman, 

and WAB-21, South China Sea for a more detailed description. 

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Reserves 

 In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve 

information. The primary impacts of the SEC’s final rule on our reserve estimates include: 

 Under the SEC’s final rule, prior period reserves were not restated. 

 The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, 

which include verification of data provided for, management reviews and review of the independent third party reserves report. The technical 

employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Arts in Engineering Science, a 

Master of Science in Petroleum Engineering, has more than 25 years of experience in reservoir engineering and is a member of the Society of 

Petroleum Engineers. 

 All reserve information in this report is based on estimates prepared by Ryder Scott Company L.P. (“Ryder Scott”), independent petroleum 

engineers. The technical personnel responsible for preparing the reserve estimates at Ryder Scott meet the requirements regarding qualifications, 

independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves 

Information promulgated by the Society of Petroleum Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, 

geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis. 

 The following table shows, by country and in the aggregate, a summary of our proved, probable and possible oil and gas reserves as of 

December 31, 2009. Probable and possible reserves are not reported for Domestic — Utah due to the ongoing evaluation of assets within these 

categories. 

4 

 • In Venezuela, the use of the unweighted 12-month average of the first-day-of-the-month contracted reference price of $56.83 per barrel for 

oil compared to the year-end contracted reference price of $69.87 per barrel, and 

 

 • In the United States, the use of the unweighted 12-month average of the first-day-of-the-month reference prices of $48.21 per barrel for oil

and $3.31 per Mcf for gas compared to year-end reference prices of $61.73 per barrel of oil and $4.25 per Mcf for gas. 

 

 • The disclosure of probable and possible reserves. 
Table of Contents 

 Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2009, 2008 and 2007 and 

changes in proved reserves during the last three years are contained in Part IV, Item 15 — Supplemental Information on Oil and Natural Gas 

Producing Activities (unaudited) . See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, 

Critical Accounting Policies for additional information on our reserves. 

Petrodelta 

General 

 On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Petrodelta Fields subject 

to the conditions of the Conversion Contract was published in the Official Gazette. Petrodelta will engage in the exploration, production, 

gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from that date. Petrodelta has 

undertaken its operations in accordance with its business plan as set forth in the Conversion Contract. Under the Conversion Contract, work 

programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be 

modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. On February 4, 2010, Petrodelta’s 

board of directors endorsed a capital budget of $205 million for Petrodelta’s 2010 business plan. 

 Petrodelta shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Currently, 

Petrodelta has one drilling rig operating in the Uracoa field. For 2010, the planned drilling program includes utilizing two rigs to drill both 

development and appraisal wells for both maintaining production capacity and appraising the substantial resource bases in the El Salto field and 

presently non-producing Isleño field. 

5 

 

 Oil and Natural 

 Condensate Gas Total 

 (MBls) (MMcf) (MBls) (1)  

Proved Developed Reserves: 

Domestic — Utah 131 653 240 

International — Venezuela (2)  14,242 24,015 18,244 

    

Total Proved Developed 14,373 24,668 18,484 

 

 

 

 

 

 

 

 

Proved Undeveloped Reserves: 

Domestic — Utah 95 473 174 

International — Venezuela (2)  33,177 38,695 39,626 

    

Total Proved Undeveloped 33,272 39,168 39,800 

 

 

 

 

 

 

 

 

Total Proved Reserves 47,645  63,836  58,284  

 

Probable Developed Reserves: 

International — Venezuela (2)  118 93 134 

 

Probable Undeveloped Reserves: 

International — Venezuela (2)  43,689 14,593 46,121 

    

 

Total Probable Reserves 43,807 14,686 46,255 

 

 

 

 

 

 

 

 

Possible Developed Reserves: 

International — Venezuela (2)  11 — 11 

 

Possible Undeveloped Reserves: 

International — Venezuela (2)  168,506 46,434 176,245 

    

 

Total Possible Reserves 168,517 46,434 176,256 

 

 

 

 

 

 

 

 

(1) 

 MBls is determined using the ratio of one barrel of crude oil or condensate to six Mcf of natural gas.

 

(2) 

 Information represents HNR Finance’s 40 percent interest. 
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 During 2009, Petrodelta drilled and completed 14 successful development wells and two appraisal wells, produced approximately 7.8 million 

barrels of oil and sold 4.4 billion cubic feet (“BCF”) of natural gas. Petrodelta was advised by the Venezuelan government that the 2009 

production target was approximately 16,000 barrels of oil per day following the December 17, 2008 Organization of the Petroleum Exporting 

Countries (“OPEC”) meeting establishing new production quotas. However, Petrodelta was allowed to produce at capacity to help fulfill other 

companies’ production shortfalls, thus averaging 21,464 barrels of oil per day during 2009. 

 Petrodelta began the appraisal and testing of its large portfolio of undeveloped resources in the second quarter of 2009. During the second 

quarter 2009, Petrodelta drilled two successful appraisal wells in the El Salto field, and pilot production commenced from one of the appraisal 

wells through temporary facilities. The well commenced production on July 18, 2009 and has produced 349,000 barrels of oil through the end of 

2009. The second appraisal well is still waiting on permits from the Ministry of Energy and Petroleum (“MENPET”) for testing. 

 On April 15, 2008, the Venezuelan government published in the Official Gazette the Law of Special Contribution to Extraordinary Prices at 

the Hydrocarbons International Market (the “original Windfall Profits Tax”). The original Windfall Profits Tax was based on prices for Brent 

crude. On July 10, 2008, the Venezuelan government published the amended Windfall Profits Tax to be calculated on the Venezuelan Export 

Basket (“VEB”) of prices as published by MENPET. The amended Windfall Profits Tax was made retroactive to April 15, 2008, the date of the 

original Windfall Profits Tax. As instructed by CVP, Petrodelta has applied the amended Windfall Profits Tax to gross oil production delivered 

to Petroleos de Venezuela S.A. (“PDVSA”) since April 15, 2008 when the tax was enacted. The amended Windfall Profits Tax established a 

special 50 percent tax to the Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar manner, the 

percentage is increased from 50 percent to 60 percent when the average price of the VEB exceeds $100 per barrel. The amended Windfall Profits 

Tax is reported as expense on the income statement and is deductible for Venezuelan tax purposes. Petrodelta recorded $0.9 million and 

$56.4 million for the years ended December 31, 2009 and 2008, respectively, for the amended Windfall Profits Tax. 

 During the second quarter of 2009, PDVSA completed an actuarial study for their pension and retirement plan. This pension and retirement 

plan covers all PDVSA employees and mixed companies employees. Petrodelta is not required to reimburse the pension costs to PDVSA until 

PDVSA pays the pension benefits to employees. In May 2009, upon completion of the review of this actuarial study, PDVSA sent a statement to 

Petrodelta for its respective costs associated with the pension and retirement plan. Petrodelta recorded additional pension expense of $15.6 

million ($5.0 million net to our 32 percent interest) in the three month period ended June 30, 2009 based on the statement received. The pension 

adjustment resulted from the completion of the first full actuary study by PDVSA related to its employees that provide services to the mixed 

companies and a refinement of management’s assumptions related to credit for past service costs covering the period from January 2008, when 

the Harvest Vinccler employees were migrated to PDVSA payroll, through May 2009. At this time PDVSA did not have specific benefit 

information related to each individual mixed company and thus allocated the pension obligation to each mixed company assuming that the 

employees serving each of the mixed companies had the same characteristics. The pension adjustment was a change in Petrodelta management’s 

estimate based on the new information provided by PDVSA. 

 During the fourth quarter of 2009, PDVSA completed an updated actuarial study as of December 31, 2009. This study was based on a further 

refinement of assumptions for each of the mixed companies, including Petrodelta and a new allocation methodology as PDVSA gathered during 

2009 all relevant information for each of the mixed companies. The revised pension obligation allocated to Petrodelta resulted in a decrease of 

$8.4 million ($2.7 million net to our 32 percent interest) to the pension and retirement plan costs as compared to those previously recorded to 

Petrodelta in May 2009. This change in management’s estimate related to the pension and retirement plan costs was recorded in December 2009. 

Pension costs at December 31, 2009 reasonably reflect Petrodelta’s employee demographic and plan conditions. The additional pension cost is 

not tax deductible until future periods when the pension is settled in cash. The provision for the pension plan is subject to future revisions, both 

upwards and downwards, based on changes in assumptions, the terms of the relevant plans, the allocation methodology or other prospective 

amendments or changes as determined by PDVSA. 

 In June 2009, CVP issued instructions to Petrodelta to set up a reserve within the equity section of the balance sheet for deferred tax assets. 

Petrodelta’s bylaws state that Petrodelta’s shareholders are required to approve the setting up of special reserves. In August 2009, Petrodelta’s 

board of directors approved the setting up of the reserve. Although this reserve has no effect on Petrodelta’s financial position, results of 

operation or cash flows, it has the effect of limiting future dividends to net income adjusted for deferred tax assets. Past dividends received from 

Petrodelta represented Petrodelta’s net income as reported under IFRS. Article 307 of the Venezuelan Commerce Code states that shareholders 

are not obligated to restore dividends that have been distributed in good faith according to the entity’s balances and sets the statute of limitations 

for an entity to claim restoration of dividends at five years. 

 In 2005, Venezuela modified the Science and Technology Law (referred to as “LOCTI” in Venezuela) to require companies doing business in 

Venezuela to invest, contribute, or spend a percentage of their gross revenue 

6 
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on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. LOCTI requires major corporations engaged 

in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law (“OHL”) to contribute two percent of their gross revenue generated in 

Venezuela from activities specified in the OHL. The contribution is based on the previous year’s gross revenue and is due the following year. 

LOCTI requires that each company file a separate declaration stating how much has been contributed; however, waivers have been granted in the 

past to allow PDVSA to file a declaration on a consolidated basis covering all of its and its consolidating entities liabilities. Since Petrodelta 

expects PDVSA to continue requesting and receiving waivers, Petrodelta has not accrued a liability to LOCTI for the year ended December 31, 

2009. The potential exposure to LOCTI for the year ended December 31, 2009 is $9.5 million, $4.8 million net of tax ($1.5 million net to our 

32 percent interest). 

 In our Annual Report on Form 10-K for the year ended December 31, 2008, we reported that Petrodelta had not received all information 

regarding production and operating costs during the conversion period for the Temblador field in order to invoice all volumes produced in that 

field during that period. As Temblador production was processed through the PDVSA system, PDVSA had allocated only partial, estimated 

production to Petrodelta. As a result, Petrodelta had not, and still has not, received full credit for the Temblador field production nor has 

Petrodelta been invoiced for the related operating costs. Although we believe the amount of production, related revenue and operating costs to be 

immaterial to Petrodelta, discussions are ongoing to settle figures. During the third quarter of 2009, Petrodelta completed the facilities and 

pipelines to segregate approximately 80 percent of the Temblador field’s production into Petrodelta’s system. 

 PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. 

PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for 

operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including 

contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to 

Petrodelta, which payments Petrodelta would otherwise use to pay its contractors. As a result, Petrodelta has experienced, and may continue to 

experience, difficulty in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether 

or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is having an 

adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan. 

 On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement which establishes new exchange 

rates for the Venezuela Bolivar (“Bolivar”)/United States Dollar (“U.S. Dollar”) currencies that will enter into force on January 11, 2010. Each 

exchange rate will be applied to foreign currency sales and purchases conducted through the Foreign Currency Administration Commission 

(“CADIVI”), in the cases expressly provided in the Exchange Agreement. In this regard, the exchange rates established in the Agreement are: 

2.60 Bolivars per U.S. Dollar and 4.30 Bolivars per U. S. Dollar. The 2.60 Bolivar exchange rate applies to the food, health, medical and 

technology sectors. The 4.30 Bolivar exchange rate applies to all other sectors not expressly established by the 2.60 Bolivar exchange rate. The 

U.S. Dollar is the functional reporting currency for both Petrodelta and Harvest Vinccler. 

Location and Geology 

Petrodelta Fields 

Uracoa Field 

 There are currently 78 oil and natural gas producing wells and six water injection wells in the field. 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 delivered by Petrodelta is produced from the Uracoa field. 

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Tucupita Field 

 There are currently 16 oil producing wells and four water injection wells in the field. 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 of oil per day pipeline from the Tucupita field to the Uracoa plant facilities. 3-D seismic is available over the entire field and is currently 

being reprocessed and reinterpreted. 

Bombal Field 

 East Bombal was drilled in 1992, and currently remains underdeveloped. The West Bombal field is currently inactive pending facility and 

pipeline upgrades. Development of East Bombal and West Bombal has been incorporated into Petrodelta’s business plan. 

Isleño Field 

 The Isleño field was discovered in 1953. 2-D seismic data is available over a portion of the field. Seven oil appraisal wells were drilled by 

PDVSA prior to the field being contributed to Petrodelta which have confirmed the presence of commercial oil deposits. The field is located near 

the Uracoa field existing infrastructure. Petrodelta’s business plan projects full development of the Isleño field over the next four years. 

Temblador Field 

 The Temblador field was discovered in 1936 and developed in the 1940s and 1950s. There are currently 19 oil producing wells in the field. 

The fluid produced from Temblador field flows through two flow stations operated by Petrodelta. Approximately 80 percent of the Temblador 

field’s production flows through Petrodelta pipelines directly into PDVSA’s system. The remaining 20 percent of the Temblador field’s 

production flows through the EPT-1 plant operated by PDVSA. 3-D seismic is available over the entire field. 

El Salto Field 

 The El Salto field was discovered in 1936. Currently there is one oil producing well in the field. A total of 31 appraisal wells were drilled by 

PDVSA prior to the field being contributed to Petrodelta, identifying nine productive structures and six productive formations. Pilot production 

from the one producing well commenced in the second quarter of 2009 through temporary facilities. The second appraisal well will be tested 

after the permitting process with MENPET is completed. 3-D seismic data is available over one-third of the field. We believe the El Salto field 

has substantial exploration upside from several fault blocks, which have been identified using 2-D seismic data but have not yet been confirmed 

through drilling. 

Infrastructure and Facilities 

 Petrodelta has a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA’s storage facility, the custody transfer point. The 

marketing contract specifies that the oil stream may contain no more than one percent base sediment and one percent water. Quality 

measurements are conducted both at Petrodelta’s facilities and at PDVSA’s storage facility. Approximately 20 percent of the Temblador 

production is currently delivered to the sales point in the EPT-1 PDVSA facility through gathering systems integrated with the Jobo and Pilon 

fields operated by PDVSA and is allocated to Petrodelta based on well tests. Petrodelta is working to segregate completely Temblador’s 

production. 

 Petrodelta has a 64-mile pipeline from Uracoa with a normal capacity of 70 million cubic feet (“MMcf”) of natural gas per day and a design 

capacity of 90 MMcf of natural gas per day. 

 Petrodelta has agreements in place for purchase of power for the electrical needs, leasing of compression, and operation and maintenance of 

the gas treatment and compression facilities at the Uracoa and Tucupita fields through 2012. 

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Business Plan of Petrodelta 

 Petrodelta’s focus in 2009 was the resumption of drilling in the Uracoa field, development drilling in the Temblador field and appraisal 

drilling in the El Salto field which resulted in an increase in production. Petrodelta is reprocessing existing 3-D seismic over Petrodelta’s fields. 

Temblador field production is processed at existing field facilities. El Salto production is being process through temporary facilities. The El Salto 

field is believed to contain substantial undeveloped and unexplored reserves. We expect to acquire additional 3-D seismic and undergo 

significant appraisal and development in a timely manner to provide for larger scale development implementation. Isleño field production can be 

integrated into the existing Uracoa field infrastructure providing for early production from the field. Overall, production is expected to peak in 

approximately ten years under Petrodelta’s 2010 business plan. 

Risk Factors 

 We face significant risks in holding a minority equity investment in Petrodelta. These risks and other risk factors are discussed in Item 1A — 

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

United States Operations 

 During 2008, we initiated a domestic exploration program in two different basins. We are the operator of both exploration programs and have 

complemented our existing personnel with the addition of highly experienced management and technical personnel and with the acquisition of 

our minority equity investment in Fusion. 

Gulf Coast 

General 

 In March 2008, we executed an AMI agreement with a private third party for an area in the upper Gulf Coast Region of the United States. We 

are the operator and have initial working interests of 55 percent in Starks, the first prospect in the AMI, and 50 percent in West Bay, the second 

prospect in the AMI. The private third party contributed these two prospects, including the leases and proprietary 3-D seismic data sets, and 

numerous leads generated over the last three decades of regional geological focus. We agreed to fund the first $20 million of new lease 

acquisitions, geological and geophysical studies, seismic reprocessing and drilling costs. At June 30, 2009, we had met the $20 million funding 

obligation under the terms of the AMI. All costs incurred after June 30, 2009 are being shared by the parties in proportion to their working 

interests as defined in the AMI. In August 2009, the AMI became a three party arrangement when the private third party restructured and 

assigned a portion of its interest to one of its affiliates. 

 The private third parties are obligated to evaluate and present additional opportunities at their sole cost. As each prospect is accepted it will be

covered by the AMI. Although several additional potential prospects had been screened and evaluated within the AMI since its inception, we had 

not pursued leasing or drilling on any new projects within the AMI as of December 31, 2009. On January 28, 2010, we entered into an agreement 

with one of the private third parties in our AMI for an option to participate in a new project. We paid $1.5 million for the option to acquire up to 

a 50 percent interest in the new project. If we exercise our option to participate, we will participate in this project with essentially the same terms 

as the other existing projects in the AMI. The option to participate expires on June 1, 2010. 

Location and Geology 

 The AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana, including state waters. 

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Drilling and Development Activity 

 We drilled an exploratory dry hole on the Starks prospect in 2008. In December 2009, we wrote off the remaining carrying value of 

$0.7 million of the Starks prospect as we have no plans for further activities relating to this prospect. 

 During the year ended December 31, 2009, operational activities in the West Bay prospect included the interpretation of 3-D seismic, site 

surveying, and preparation of engineering documents. Interpretation of 3-D seismic data on the West Bay project was completed in 2009 and 

resulted in the identification of a set of drilling leads and prospects for the project. On July 14, 2009, we, along with our partner in the AMI, 

acquired 880 acres of shallow water offshore bay leases representing two separate tracts from the State of Texas General Land Office at a state 

lease sale for a total gross cost of $0.5 million. Acquisition of these two tracts completes the planned land acquisition activities on the project. 

 The AMI participants are currently continuing to evaluate the leads and prospects to determine priorities and drilling plans for the West Bay 

project and have identified the likely initial drilling prospect. Land, regulatory, and surface access preparations are currently in progress focused 

on taking the initial drilling prospect to drill-ready status. Current plans are to drill the initial well in 2011. 

Western United States — Antelope 

 In October 2007, we entered into a JEDA with a private third party to pursue a lease acquisition program and drilling program on the 

Antelope prospect in the Western United States. We are the operator and had an initial working interest of 50 percent in the Antelope prospect. 

The private third party is obligated to assemble the lease position on the Antelope prospect. The JEDA provides that we would earn our initial 

50 percent working interest in the Antelope prospect by compensating the private third party for leases acquired in accordance with terms 

defined in the JEDA, and by drilling and completing one deep natural gas test well (the Bar F) at our sole expense. In November 2008, we 

entered into a Letter Agreement/Amendment of the JEDA (the “Letter Agreement”) with the private third party. The Letter Agreement clarifies 

several open issues in the JEDA, such as classification of $2.7 million of prepaid land costs for the Antelope prospect as a note receivable, 

addition of a requirement for the private third party to partially assign leases to us prior to meeting the lease earning obligation, and clarification 

of the private third party’s cost obligations for any shallow wells to be drilled on the Antelope prospect prior to the Bar F. Per the Letter 

Agreement, payment of the $2.7 million note receivable was due from the private third party on or by spud date of the Bar F. Since payment was 

not received prior to the Bar F spud date, our interest in the Antelope prospect was increased to 60 percent, with the incremental 10 percent 

working interest being earned by drilling and completing the Bar F. The note receivable remains outstanding and will be collected through sales 

revenues taken from a portion of the private third party’s net revenue from the Bar F provided the Bar F is commercial. 

 Activities are in progress on two separate projects on the Antelope prospect in Duchesne County, Utah. 

Mesaverde 

General 

 The Mesaverde project is targeted to explore for and develop oil and natural gas from multiple reservoir horizons in the Uintah Basin of 

northeastern Utah in Duchesne and Uintah Counties. Leads and/or prospects were identified in three prospective reservoir horizons in 

preparation for drilling. 

Drilling and Development Activity 

 Operational activities during 2009 on the Mesaverde project focused on continuing leasing activities on private, Allottee, and tribal land, and 

surveying, preliminary engineering, permitting preparations, and conducting drilling operations on a deep natural gas test well (the Bar F) that 

commenced drilling on June 15, 2009. The Bar F was permitted to 18,000 feet. The Bar F was drilled to a total depth of 17,566 feet, and an 

extended production test 

10 
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of multiple potential reservoir horizons is now in progress. To date, testing has been focused on the evaluation of the natural gas potential of the 

Mesaverde tight gas reservoir over a prospective interval from 14,000 to 17,400 feet. Completion activities consisted of hydraulic fracturing of 

eight separate reservoir intervals in the Mesaverde and multiple extended flow tests of the individual fractured intervals, along with a flow test of 

the commingled eight intervals. While the results to date have not definitively determined the commerciality of a stand-alone development of the 

Mesaverde, we believe these results indicate progress toward that determination and that the Mesaverde reservoir remains potentially prospective 

over a portion of our land position. 

Earning of Undeveloped Acreage

 Acreage for Mesaverde reflects the acreage that will be earned by us upon completion of the drilling and testing of the first deep natural gas 

test well on the project. We anticipate completing the lease earning obligation in 2010. If, however, the earning well is not completed in 

accordance with the requirements of the JEDA, we will have an obligation to assign our interest in the acreage back to the private third party in 

accordance with the terms of the Letter Agreement. 

Monument Butte 

General 

 The Monument Butte project is an eight well appraisal and development drilling program to produce oil and natural gas from the Green River 

formation on the southern portion of our Antelope land position. The Monument Butte project is non-operated and we hold a 43 percent working 

interest. The parties have formed a 320 acre AMI which contained the eight drilling locations. 

Drilling and Development Activity 

 Operational activities during 2009 on the Monument Butte project focused on resolution of forced pooling issues with non-consenting 

interests, negotiations and finalization of an agreement with the operator for the joint drilling operations. As of March 1, 2010, all eight wells 

have been drilled. Seven wells are currently on production. One additional well is waiting on completion operations and is anticipated to 

commence production in early March 2010. 

Budong-Budong, Onshore Indonesia 

General 

 In February 2008, Indonesia’s oil and gas regulatory authority, BP Migas, approved the assignment to us of a 47 percent interest in the 

Budong PSC located mainly onshore West Sulawesi, Indonesia. Final government approval from the Ministry of Energy and Mineral Resources, 

Migas, was received in April 2008. Our partner will be the operator through the exploration phase as required by the terms of the Budong PSC. 

We will have control of major decisions and financing for the project with an option to become operator, if approved by BP Migas, in the 

subsequent development and production phase. 

Location and Geology 

 The Budong PSC covers 1.35 million acres and includes the Lariang and Karama sub-basins, which are the eastern onshore extension of the 

West Sulawesi foldbelt (“WSFB”). Exploration to date in the basin is immature due to previously difficult jungle terrain, which is now 

accessible with the development of palm oil plantations and their related infrastructure. Field work performed over the last 10 years, as outcrops 

have been more accessible, has given a new understanding to the presence of Eocene source and reservoir potential that had not previously been 

recognized. Recent seismic surveys have greatly improved the understanding of the geology and enhanced the prospectivity of the offshore 

WSFB and, by analogy, the sparsely explored onshore area. 

11 
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Drilling and Development Activity 

 Operational activities during 2009 focused on the interpretation of 650 kilometers of 2-D seismic and well planning. Two drill sites have been 

selected. Currently, the locations for the two test wells are being constructed and the rig and ancillary equipment is being mobilized to the area. It 

is expected that the first of two exploration wells will spud early in the second quarter of 2010. In accordance with the farm-in agreement, we 

expect to fund 100 percent of the well expenditures to earn our 47 percent working interest up to a cap of $10.7 million; thereafter, we will pay 

in proportion to our working interest. 

Title to Undeveloped Acreage 

 We acquired the 47 percent interest in the Budong PSC by committing to fund the first phase of the exploration program including the 

acquisition of 2-D seismic and drilling of the first two exploration wells. This commitment is capped at $17.2 million. Prior to drilling the first 

exploration well, subject to the estimated cost of that well, our partner will have a one-time option to increase the level of the carried interest to a 

maximum of $20.0 million, and as compensation for the increase, we will increase our participation to a maximum of 54.65 percent. This 

equates to a total carried cost for the farm-in of $9.1 million. 

Dussafu Marin, Offshore Gabon 

General 

 In 2008, we completed the purchase of a 66.667 percent interest in the Dussafu PSC for $6.0 million. We are the operator of the Dussafu 

PSC. 

Location and Geology 

 The Dussafu PSC contract area is located offshore Gabon, adjacent to the border with the Republic of Congo. It contains 680,000 acres with 

water depths to 1,000 feet. The Dussafu PSC has two small oil discoveries in the Gamba and Dentale reservoirs and a small natural gas 

discovery. Production and infrastructure exists in the blocks contiguous to the Dussafu PSC. 

Drilling and Development Activity 

 The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources 

(“Republic of Gabon”), entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. The second 

exploration phase comprises a three-year work commitment which includes the acquisition and processing of 500 kilometers of 2-D seismic, 

geology and geophysical interpretation, engineering studies and the drilling of a conditional well. Operational activities during 2009 focused on 

completion of the processing and reprocessing of 1,330 kilometers of 2-D seismic and the pre-stack depth reprocessing of 1,076 square 

kilometers of 3-D seismic data. The improved imaging from this work has allowed the interpretation to mature the prospect inventory to provide 

the partnership a number of prospective targets in the sub-salt section, in both the Gamba and Syn-rift plays that are productive in the nearby 

Etame, Lucina and M’Bya fields. Subject to drilling rig availability, we expect to drill an exploration well in the third quarter of 2010. 

Oman 

General 

 On April 11, 2009, we signed an Exploration and Production Sharing Agreement (“EPSA”) with Oman for the Al Ghubar/Qarn Alam license. 

We have a 100 percent working interest in Block 64 EPSA during the exploration phase. Oman Oil Company has the option to back-in to up to a 

20 percent interest in Block 64 EPSA after the discovery of gas. 

12 
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Location and Geology 

 Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate which the Oman 

Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). The 3,867 square 

kilometer (955,600 acres) block is located in the gas and condensate rich Ghaba Salt Basin in close proximity to the Barik, Saih Rawl and Saih 

Nihayda gas and condensate fields. 

Drilling and Development Activity 

 PDO will continue to produce oil from several fields within Block 64 EPSA area. We have an obligation to drill two wells over a three year 

period with a funding commitment of $22.0 million. Current activities include the compilation of existing data, over two prospect areas of 

approximately 1,000 square kilometers and geological studies to determine drillable prospects. Well planning is expected to commence in 2010 

for exploration drilling in 2011. 

WAB-21, South China Sea 

General 

 In December 1996, we acquired 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 (“China”) and Socialist 

Republic of Vietnam (“Vietnam”). Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The 

border dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the 

dispute. 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. 

Location and Geology 

 The WAB-21 contract area is located in the West Wan’ an Bei Basin (Nam Con Son) of the South China Sea. Its western edge lies 

approximately 20 miles to the east of significant producing natural gas fields, Lan Tay and Lan Do, which are reported to contain two trillion 

cubic feet (“Tcf”) of natural gas and commenced production in November 2002. Also located to the west of WAB-21 are the Dua and Chim Sao 

(formerly Blackbird) discoveries and the discovery in 2009 of Ca’ Rong. The Chim Sao oil field has recently received development approval. 

The WAB-21 contract area covers a large unexplored area of the Wan’ an Bei Basin where the same successful Lower Miocene through to 

Upper Miocene plays to the west are present. Exploration success in the basin to date has resulted in discoveries estimated to total in excess of 

500 million barrels of oil and 7.5 Tcf of natural gas. Several similar structural trends and geological formations, each with significant potential 

for hydrocarbon reserves in traps with multiple pay zones similar to the known fields and discoveries to the west are present within WAB-21. 

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, 2011. While no assurance can be 

given, we believe we will continue to receive contract extensions so long as the border disputes persist. Recently, Vietnam, along with the 

company that is the party to the agreement with Vietnam, announced plans for exploration drilling during 2010. While no assurance can be 

given, we believe this announcement may provide some resolution with the border disputes, although we do not know in what manner any 

resolution might appear. 

Production, Prices and Lifting Cost Summary 

 In the following table we have set forth, by country, our net production, average sales prices and average operating expenses for the years 

ended December 31, 2009, 2008 and 2007. The presentation for Venezuela 

13 
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includes 100 percent of Petrodelta’s production. The United States is presented at our ownership interest. In thousands, except per unit 

information: 

Drilling and Undeveloped Acreage 

 For acquisitions of leases, development and exploratory drilling, we spent approximately (excluding our share of capital expenditures 

incurred by equity affiliates) $28.0 million, $26.3 million and $0.6 million in 2009, 2008 and 2007, respectively. These numbers do not include 

any costs for the development of proved undeveloped reserves in 2009, 2008 or 2007. 

 We have participated in the drilling of wells as follows: 

14 

 

 Year Ended December 31, 

 2009 2008 2007 

Venezuela (a) 

Crude Oil Production (Bbls) 7,835 5,505 5,374 

Natural Gas Production (Mcf)(b) 4,397 10,700 13,456 

Average Crude Oil Sales Price ($per Bbl) $ 57.62 $ 83.22 $ 58.61 

Average Natural Gas Sales Price ($ per Mcf) $ 1.54 $ 1.54 $ 1.54 

Average Operating Expenses ($ per Boe)(c) $ 8.46 $ 10.90 $ 4.20 

United States 

Monument Butte (d) 

Net Crude Oil Production (Bbls) 3 — — 

Natural Gas Production (Mcf) 6 — — 

Average Crude Oil Sales price ($per Bbl) $ 61.61 $ — $ — 

Average Natural Gas Sales Price ($ per Mcf) $ 2.77 $ — $ — 

Average Operating Expenses ($ per Boe) $ — $ — $ — 

 

(a) Information represents 100 percent of production. 

 

(b) Royalty-in-kind paid on gas used as fuel was 3,323 Mcf and 3,830 Mcf for 2009 and 2008, respectively. 

 

(c) Net of royalty and excluding workovers. 

 

(d) Information represents our ownership interest. 
Table of Contents 

 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 concession as of December 31, 

2009: 

Regulation 

General 

 Our operations and our ability to finance and fund our growth strategy are affected by political developments and laws and regulations in the 

areas in which we operate. In particular, oil and natural gas production operations and economics are affected by: 

15 

 

 Year Ended December 31, 

 2009 2008 2007 

 Gross Net Gross Net Gross Net 

Wells Drilled: 

Venezuela (Petrodelta) 

Development 15 4.8 9 2.9 — — 

Appraisal 2 0.6 — — — — 

United States 

Development 5 2.1 — — — — 

Exploration 1 1.0 1 1.0 — — 

 

Average Depth of Wells (Feet) 

Venezuela (Petrodelta) 

Crude Oil — 6,500 — 6,500 — — 

United States 

Crude Oil — 6,751 — — — — 

Natural Gas — 17,566 — 12,290 — — 

 

Producing Wells (1) : 

Venezuela (Petrodelta) 

Crude Oil 114 36.5 118 37.8 97 31.0 

United States 

Crude Oil 2 0.7 — — — — 

 

(1) 

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

 

 Developed Undeveloped 

 Gross Net Gross Net 

Venezuela — Petrodelta 23,050 9,220 224,063 89,625 

China — — 7,470,080 7,470,080 

United States: 

West Bay — — 12,808 6,316 

Antelope 212 90 111,457 36,536 

Indonesia — — 1,357,723 638,130 

Gabon — — 685,470 456,982 

Oman — — 955,600 955,600 

     

Total 23,262 9,310 10,817,201 9,653,269 

 

 

 

 

 

 

 

 

 

 • change in governments; 
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 In any country in which we may do business, the oil and natural gas industry legislation and agency regulation are periodically changed, 

sometimes retroactively, for a variety of political, economic, environmental and other reasons. Numerous governmental departments and 

agencies issue rules and regulations binding on the oil and natural gas industry, some 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 and our potential for economic loss. 

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, 2009, our Houston office had 23 full-time employees. Our Utah, Caracas, London, Singapore, Jakarta and Muscat offices 

had 1, 14, 7, 3, 4 and 3 employees, respectively. We augment our employees from time to time with independent consultants, as required. We 

closed our Moscow office on March 31, 2009. 

Item 1A. Risk Factors 

 In addition to other information set forth elsewhere in this Annual Report on Form 10-K , the following factors should be carefully 

considered when evaluating us. 

 Our cash position and limited ability to access additional capital may limit our growth opportunities. At December 31, 2009, we had 

$32 million of available cash and, until Petrodelta pays a dividend or the revenue from our U.S. operations increases substantially, cash available 

from operations will not be sufficient to meet operational requirements. Having a Petrodelta dividend as our primary source of cash flow limits 

our access to additional capital, and our concentration of political risk in Venezuela may limit our ability to leverage our assets. In addition, our 

future cash position depends upon the payment of dividends by Petrodelta or success with our exploration program. While we believe that 

Petrodelta will reinvest any excess cash which might be available for payment of dividends into Petrodelta in 2010 and 2011, there is no 

assurance this will be the case, nor that if the cash is not reinvested that it will be paid as dividends. These factors could have a material adverse 

effect on our financial condition and liquidity and may limit our ability to grow through the acquisition or exploration of additional oil and gas 

properties and projects. 

16 

 • 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. 
Table of Contents 

 We have incurred long-term indebtedness obligations, which significantly increased our leverage. On February 17, 2010, we closed a 

debt offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes due 2013. Prior to the offering, we had 

no long-term debt obligations. The degree to which we are leveraged could, among other things: 

 Our ability to meet our debt service obligations will depend upon our future performance, which will be subject to financial, business and 

other factors affecting our operations, many of which are beyond our control. Additionally, the covenants contained in the indenture governing 

the notes restrict, among other things, our ability to incur certain indebtedness. Any failure to comply with these covenants could result in an 

event of default under the indenture, which could permit acceleration of the indebtedness under the notes. If our indebtedness were to be 

accelerated, we cannot assure you that we would be able to repay it. 

 We may incur significant indebtedness in the near future. We continually assess our need for additional sources of financing based on 

our operational, working capital and other needs from time to time. In addition, we are currently contemplating one particular additional source 

of financing through an Islamic (sukuk) financing, in which one of our subsidiaries would form and contribute certain assets to a partnership and 

subsequently sell a minority interest in the partnership to one or more third parties for approximately $250 million. Although the terms of this 

transaction have not been finalized, we anticipate that the terms would include our agreement to pay all or a substantial portion of the future 

dividends paid by Petrodelta over the next five or six years to reacquire all of the third-party partnership interests, including premiums thereon. 

While we may be able to consummate this financing transaction during the first half of 2010, there can be no assurances that this transaction will 

be consummated, and we may consider alternative forms of additional financing if we deem necessary or advisable with respect to our 

operations from time to time. 

 Global market and economic conditions, including those related to the credit markets, could have a material adverse effect on our 

business, financial condition and results of operations . A general slowdown in economic activity could adversely affect our business by 

impacting our ability to access additional capital, the receipt of dividends from Petrodelta as well as the need to preserve adequate development 

capital in the interim. 

 We may not be able to meet the requirements of the global expansion of our business strategy. We have added a significant global 

exploration component to diversify our overall portfolio. In many locations, we may be required to post performance bonds in support of a work 

program. We also intend to acquire underdeveloped, undeveloped and exploration properties from time to time for which the primary risks may 

be technical, operational or both. 

 Our strategy to identify, access and integrate hydrocarbon assets in known hydrocarbon basins globally carries greater deal 

execution, operating, financial, legal and political risks. The environments in which we operate are often difficult and the ability to operate 

successfully will depend on a number of factors, including our ability to control the pace of development, our ability to apply “best practices” in 

drilling and development, and the fostering of productive and transparent relationships with local partners, the local community and 

governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, often the legal 

systems of these countries are not mature and their reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty 

in our rights to develop and operate oil and natural gas projects, as well as our ability to obtain adequate compensation for any resulting losses. 

Our strategy depends on our ability to have significant influence over operations and financial control. 

 Operations in areas outside the United States are subject to various risks inherent in foreign operations. Our operations are subject to 

various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as a result of 

hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and 

governmental 

17 

 • make it difficult for us to make payments on the notes; 

 

 • make it difficult for us to obtain financing for working capital, acquisitions or other purposes on favorable terms, if at all; 

 

 • make us more vulnerable to industry downturns and competitive pressures; and 

 

 • limit our flexibility in planning for, or reacting to changes in, our business. 
Table of Contents 

royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts or tribunals, renegotiation of contracts with 

governmental entities, changes in laws and policies, including taxes, governing operations of foreign-based companies, currency restrictions and 

exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations. Our 

international operations may also be adversely affected by laws and policies of the United States affecting foreign policy, foreign trade, taxation 

and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States. 

 Operations on the Uintah and Ouray Reservation of the Ute Indian Tribe in the western United States are subject to various risks 

similar to those for foreign operations. Similar to our operations in foreign jurisdictions, our operations on the Uintah and Ouray Reservation

of the Ute Indian Tribe are subject to certain risks. These risks may include, among other things, loss of revenue, property and equipment as a 

result of hazards such as civil unrest, strikes and other political risks, increases in taxes or fees, being subject to tribal laws, changes in tribal laws 

and policies and other uncertainties arising out of tribal sovereignty. 

 Estimates of oil and natural gas reserves are uncertain and inherently imprecise . This Annual Report on Form 10-K contains estimates 

of our oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to 

oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. 

 The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of 

available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual 

future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and 

natural gas reserves likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present 

value of reserves set forth. Actual production, revenue, taxes, development expenditures and operating expenses with respect to our reserves will 

likely vary from the estimates used, and these variances may be material. 

 You should not assume that the present value of future net revenues referred to in Part IV, Item 15 — Supplemental Information on Oil and 

Natural Gas Producing Activities (unaudited), TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil 

and Natural Gas Reserve Quantities 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 the unweighted average price of the 

first day of the month during the 12-month period before the ending date of the period covered by the reserve report and costs as of the date of 

the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any 

changes in demand, changes in our ability to produce or changes in governmental regulations, policies or taxation will also affect actual future 

net cash flows. The timing of both the production and the expenses from the development and production of oil and natural gas properties will 

affect the timing of actual future net cash flows from estimated proved reserves and their present value. In addition, the 10 percent discount 

factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most 

accurate discount factor. The effective interest rate at various times and the risks associated with the oil and natural gas industry in general will 

affect the accuracy of the 10 percent discount factor. 

 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 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 give any assurance 

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 future operations and our investments in equity affiliates are subject to numerous risks of oil and natural gas drilling and 

production activities. Oil and natural gas exploration and development drilling and production activities are subject to numerous risks, 

including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is often 

uncertain. Oil and natural gas 

18 
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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: 

 The prevailing price of oil also affects the cost of and availability for drilling rigs, production equipment and related services. We cannot give 

any assurance 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. 

 Our oil and natural gas operations are subject to various governmental regulations that materially affect our operations . Our oil and 

natural gas operations are subject to various governmental regulations. These regulations may be changed in response to economic or political 

conditions. Matters regulated may include permits for discharges of wastewaters and other substances generated in connection with drilling 

operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports 

concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. At various times, regulatory agencies have 

imposed price controls and limitations on oil and natural gas production. In order to conserve or limit supplies of oil and natural gas, these 

agencies have restricted the rates of the 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. 

 We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Exploration and development and the 

production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make 

large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include: 

 Under these laws, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and 

clean-up costs, natural resource damages and other environmental damages. We also could be required to install expensive pollution control 

measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure 

to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal 

penalties as well as the imposition of corrective action orders. Moreover, these laws could change in ways that substantially increase our costs. 

Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition, 

results of operations or cash flows. 

 Potential regulations regarding climate change could alter the way we conduct our business. Governments around the world are 

beginning to address climate change matters. This may result in new 

19 

 • unexpected drilling conditions; 

 

 • pressure or irregularities in formations; 

 

 • equipment failures or accidents; 

 

 • weather conditions; 

 

 • shortages in experienced labor; 

 

 • delays in receiving necessary governmental permits;

 

 • delays in receiving partner approvals; 

 

 • 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 amounts and types of substances and materials that may be released into the environment; 

 

 • response to unexpected releases to the environment;

 

 • reports and permits concerning exploration, drilling, production and other operations; 

 

 • the spacing of wells; 

 

 • unitization and pooling of properties; 

 

 • calculating royalties on oil and gas produced under federal and state leases; and 

 

 • taxation. 
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environmental regulations that may unfavorably impact us, our suppliers and our customers. The cost of meeting these requirements may have 

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

 Competition within the industry may adversely affect our operations . We operate in a highly competitive environment. We compete 

with major, national and independent oil and natural gas companies for the acquisition of desirable oil and natural gas properties and the 

equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially 

greater than ours. 

 The loss of key personnel could adversely affect our ability to successfully execute our strategy. We are a small organization and 

depend on the skills and experience of a few individuals in key management and operating positions to execute our business strategy. Loss of 

one or more key individuals in the organization could hamper or delay achieving our strategy. 

 We no longer directly manage operations of Petrodelta. PDVSA, through CVP, exercises substantial control over Petrodelta’s operations, 

making Petrodelta subject to some internal policies and procedures of PDVSA as well as being subject to constraints in skilled personnel 

available to Petrodelta. These issues may have an adverse effect on the efficiency and effectiveness of Petrodelta’s operations. 

 We hold a minority equity investment in Petrodelta. Even though we have substantial negative control provisions as a minority equity 

investor in Petrodelta, our control of Petrodelta is limited to our rights under the Conversion Contract and its annexes and Petrodelta’s charter 

and bylaws. As a result, our ability to implement or influence Petrodelta’s business plan, assure quality control, and set the timing and pace of 

development may be adversely affected. In addition, the majority partner, CVP, has initiated and undertaken numerous unilateral decisions that 

can impact our minority equity investment. 

 Petrodelta’s business plan will be sensitive to market prices for oil. Petrodelta operates under a business plan, the success of which will 

rely heavily on the market price of oil. To the extent that market values of oil decline, the business plan of Petrodelta may be adversely affected. 

 A decline in the market price of crude oil could uniquely affect the financial condition of Petrodelta. Under the terms of the Conversion 

Contract and other governmental documents, Petrodelta is subject to a special advantage tax (“ventajas especiales”) which requires that if in any 

year the aggregate amount of royalties, taxes and certain other contributions is less than 50 percent of the value of the hydrocarbons produced, 

Petrodelta must pay the government of Venezuela the difference. In the event of a significant decline in crude prices, the ventajas especiales 

could force Petrodelta to operate at a loss. Moreover, our ability to control those losses by modifying Petrodelta’s business plan or restricting the 

budget is limited under the Conversion Contract. 

 An increase in oil prices could result in increased tax liability in Venezuela affecting Petrodelta’s operations and profitability, which 

in turn could affect our dividends and profitability . Prices for oil fluctuate widely. On July 10, 2008, the Venezuelan government published 

the amended Windfall Profits Tax to be calculated on the VEB of prices as published by MENPET. The amended Windfall Profits Tax 

established a special 50 percent tax to the Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar 

manner, the percentage is increased from 50 percent to 60 percent when the average price of the VEB exceeds $100 per barrel. Any increase in 

the taxes payable by Petrodelta, including the Windfall Profits Tax, as a result of increased oil prices will reduce cash available for dividends to 

us and our partner, CVP. 

 Oil price declines and volatility could adversely affect Petrodelta’s operations and profitability, which in turn could affect our 

dividends and profitability. Prices for oil also affect the amount of cash flow available for capital expenditures and dividends from Petrodelta. 

Lower prices may also reduce the amount of oil that we can produce economically and lower oil production could affect the amount of natural 

gas we can produce. We cannot predict future oil prices. Factors that can cause fluctuations in oil prices include: 

20 

 • relatively minor changes in the global supply and demand for oil; 

 

 • export quotas; 

 

 • market uncertainty; 

 

 • the level of consumer product demand; 
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 The total capital required for development of Petrodelta’s assets may exceed the ability of Petrodelta to finance such developments. 

Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Petrodelta’s future capital requirements for the 

development of its assets may exceed the cash available from existing cash flow. Petrodelta’s ability to secure financing is currently limited and 

uncertain, and has been, and may be, affected by numerous factors beyond its control, including the risks associated with operating in Venezuela. 

Because of this financial risk, Petrodelta may not be able to secure either the equity or debt financing necessary to meet its future cash needs for 

investment, which may limit its ability to fully develop the properties, cause delays with their development or require early divestment of all or a 

portion of those projects. This could negatively impact our minority equity investment. If we are called upon to fund our share of Petrodelta’s 

operations, our failure to do so could be considered a default under the Conversion Contract and cause the forfeiture of some or all our shares in 

Petrodelta. In addition, CVP may be unable or unwilling to fund its share of capital requirements and our ability to require them to do so is 

limited. 

 The legal or fiscal regime for Petrodelta may change and the Venezuelan government may not honor its commitments. While we 

believe that the Conversion Contract and Petrodelta provide a basis for a more durable arrangement in Venezuela, the value of the investment 

necessarily depends upon Venezuela’s maintenance of legal, tax, royalty and contractual stability. Our recent experiences in Venezuela 

demonstrate that such stability cannot be assured. While we have and will continue to take measures to mitigate our risks, no assurance can be 

provided that we will be successful in doing so or that events beyond our control will not adversely affect the value of our minority equity 

investment in Petrodelta. 

 PDVSA’s failure to timely pay contractors could have an adverse affect on Petrodelta. PDVSA has failed to pay on a timely basis 

certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. 

PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures, and 

PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to provide services to 

Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise 

use to pay its contractors. As a result, Petrodelta has experienced, and may continue to experience, difficulty in retaining contractors who provide 

services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment 

obligations. Inability to retain contractors or to pay them on a timely basis is having an adverse effect on Petrodelta’s operations and on 

Petrodelta’s ability to carry out its business plan. 

 Tax claims by municipalities in Venezuela may adversely affect Harvest Vinccler’s financial condition. The municipalities of Uracoa 

and Libertador have asserted numerous tax claims against Harvest Vinccler which we believe are without merit. However, the reliability of 

Venezuela’s judicial system is a source of concern and it can be subject to local and political influences. 

Item 1B. Unresolved Staff Comments 

 None. 

Item 2. Properties 

 In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month. In December 2008, we 

signed a five-year lease for additional office space in Houston, Texas, for approximately $15,000 per month. In November 2008, Harvest 

Vinccler extended its lease for office space in Caracas, Venezuela for two years for approximately $10,000 per month. In August 2008, we 

signed a two-year lease in Roosevelt, Utah for approximately $6,000 per month. In October 2008, we signed a two-year lease for 

21 

 • 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. 
Table of Contents 

office space in Singapore for approximately $19,000 per month. In April 2009, we signed a two-year lease for office space in Indonesia for 

approximately $5,000 per month. In September 2009, we signed a two-year lease for office space in Oman for approximately $5,000 per month. 

In November 2009, we signed a one-year lease for office space in London for approximately $24,000 per month. See Item 1 — Business for a 

description of our oil and gas properties. 

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, 

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 April 2007, the court set the case for trial. The trial 

date, reset for the first quarter of 2009, had been stayed indefinitely. On October 20, 2009, the stay was lifted. A trial date of November 1, 2010 

has been set. We dispute Excel’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any 

possible loss. 

 Uracoa Municipality Tax Assessments . Our Venezuelan subsidiary, Harvest Vinccler has received nine assessments from a tax inspector for 

the Uracoa municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows: 

Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is unable to 

estimate the amount or range of any possible loss. As a result of the SENIAT’s, the Venezuelan income tax authority, interpretation of the tax 

code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa Municipality 

for the refund of all municipal taxes paid since 1997. 

 Libertador Municipality Tax Assessments . Harvest Vinccler has received five assessments from a tax inspector for the Libertador 

municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows: 

22 

 • Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the 

capital fee reimbursement and related interest paid by PDVSA under the Operating Service Agreement (“OSA”). Harvest Vinccler has 

filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the 

municipality the remaining claims. 

 

 • Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a 

protest with the Tax Court in Barcelona, Venezuela, on these claims. 

 

 • Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a 

withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, 

Venezuela, on one claim and filed a protest with the municipality on the other claim. 

 

 • Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. 

Harvest Vinccler has filed a protest with the municipality on these claims. 

 • One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a 

protest with the Mayor’s Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. On April 10, 

2008, the Tax Court suspended the case pending a response from the Mayor’s Office to the protest. If the municipality’s response is to 

confirm the assessment, Harvest Vinccler will defer to the competent Tax Court to enjoin and dismiss the claim. 
Table of Contents 

Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest 

Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to 

operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the refund of 

all municipal taxes paid since 2002. 

 In June 2007, the SENIAT issued an assessment for taxes in the amount of $0.4 million for Harvest Vinccler’s failure to withhold VAT from 

vendors during 2005. Also, the SENIAT imposed penalties and interest in the amount of $1.3 million for Harvest Vinccler’s failure to withhold 

VAT. In July 2008, the SENIAT adjusted the assessment for penalties and interest to the change in tax units as mandated by the Venezuelan tax 

code and issued a new assessment for $2.3 million. The change in assessment resulted in an additional $1.0 million expense recorded in the year 

ended December 31, 2008. In August 2008, Harvest Vinccler filed an appeal in the tax courts and presented a proposed settlement with the 

SENIAT. In October 2008, after consideration of our proposed settlement, the SENIAT offered a counter-proposal which Harvest Vinccler 

accepted. Throughout 2009, the General Attorney Office and Harvest Vinccler agreed several times to resuspend the case while the Finance 

Minister and the SENIAT confirmed their acceptance to the proposed settlement. On December 30, 2009, Harvest Vinccler settled the case for 

3.1 million Bolivars (approximately $1.4 million) for penalties and interest and closed the case with the SENIAT’s concurrence. As a result of 

the settlement, in December 2009, Harvest Vinccler reversed $0.9 million of accrued penalties and interest previously accrued based on notices 

received from the SENIAT. 

 We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such 

litigation which will have a material adverse impact on our financial condition, results of operations and cash flows. 

PART II 

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY 

 Our common stock is traded on the NYSE under the symbol “HNR”. As of December 31, 2009, there were 33,281,385 shares of common 

stock outstanding, with approximately 515 stockholders of record. The following table sets forth the high and low sales prices for our Common 

Stock reported by the NYSE. 

23 

 • Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by 

PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. 

Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims. 

 

 • Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed 

a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims. 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
Table of Contents 

 On March 9, 2010, the last sales price for the common stock as reported by the NYSE was $5.48 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. 

STOCK PERFORMANCE GRAPH 

 The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2009, assuming an investment 

of $100 on December 31, 2004 in each of Harvest’s common stock, the Dow Jones U.S. Exploration & Production Index and the S&P 

Composite 500 Stock Index. 

 This graph assumes that the value of the investment in Harvest stock and each index was $100 at December 31, 2004 and that all dividends 

were reinvested. 

 

24 

 

Year Quarter High Low 

2008 First quarter $ 13.02 $ 10.32 

 Second quarter 12.84 9.03 

 Third quarter 11.31 9.06 

 Fourth quarter 9.59 3.84 

 

2009 First quarter 4.69 2.70 

 Second quarter 5.66 3.25 

 Third quarter 6.64 4.24 

 Fourth quarter 6.39 4.90 
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PLOT POINTS 

(December 31 of each year) 

 Total Return Data provided by S&P’s Institutional Market Services, Dow Jones & Company, Inc. is composed of companies that are 

classified as domestic oil companies under Standard Industrial Classification codes (1300-1399, 2900-2949, 5170-5179 and 5980-5989). The 

Dow Jones US Exploration & Production Index is accessible at http://www.djindexes.com/mdsidx/index.cfm?event=showTotalMarket . 

Item 6. Selected Financial Data 

SELECTED CONSOLIDATED FINANCIAL DATA 

 The following table sets forth our selected consolidated financial data for each of the years in the five-year period ended December 31, 

2009. In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts 

method from the full cost method. 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. 

25 

 

 2004 2005 2006 2007 2008 2009 

Harvest Natural Resources, Inc. $ 100 $ 51 $ 62 $ 72 $ 25 $ 31 

Dow Jones US E&P Index $ 100 $ 166 $ 174 $ 244 $ 142 $ 201 

S&P 500 Index $ 100 $ 105 $ 121 $ 128 $ 81 $ 102 

 

 Year Ended December 31, 

 2009 2008 2007 (1)  2006 (1)  2005 

 (in thousands, except per share data) 

Statement of Operations: 

Total revenues $ 181 $ — $ 11,217 $ 59,506 $ 236,941 

Operating income (loss) (30,959 ) (54,440 ) (19,536 ) 574 104,571 

Net income from Unconsolidated Equity Affiliates 35,757 34,576 55,297 — — 

Net income (loss) attributable to Harvest (3,107 ) (21,464 ) 60,118 (62,502 ) 38,876 

Net income (loss) attributable to Harvest per common 

share: 

Basic $ (0.09 ) $ (0.63 ) $ 1.65 $ (1.68 ) $ 1.05 

 

 

 

 

 

 

 

 

 

 

 

Diluted $ (0.09 ) $ (0.63 ) $ 1.59 $ (1.68 ) $ 1.01 

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding 

Basic 33,084 34,073 36,550 37,225 36,949 

Diluted 33,084 34,073 37,950 37,225 38,444 

 

 Year Ended December 31, 

 2009 2008 2007 (1)  2006 (1)  2005 

 (in thousands) 

Balance Sheet Data: 

Total assets $ 348,779 $ 362,266 $ 417,071 $ 468,365 $ 451,377 

Long-term debt, net of current maturities — — — 66,977 — 

Total Harvest’s Stockholders’ equity (2)  274,593 273,242 316,647 281,409 337,975 

 

(1) 

 Activities under our former OSA in Venezuela are reflected under the equity method of accounting effective April 1, 2006. The results of 

Petrodelta’s operations from April 1, 2006 until December 31, 2007 are reflected in 2007 when Petrodelta was formed. 

 

(2) 

 No cash dividends were declared or paid during the periods presented. 
Table of Contents 

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

Operations 

 We had a net loss attributable to Harvest of $3.1 million, or $(0.09) per diluted share, for the twelve months ended December 31, 2009 

compared with a net loss attributable to Harvest of $21.5 million, or $(0.63) per diluted share, for the twelve months ended December 31, 2008. 

Net loss attributable to Harvest for the year ended December 31, 2009 includes $7.8 million of exploration expense and the net equity income 

from Petrodelta’s operations of $40.7 million. Net loss attributable to Harvest for the year ended December 31, 2008 includes $16.4 million of 

exploration expense, $10.8 million of dry hole expense and the net equity income from Petrodelta’s operations of $35.9 million. 

Petrodelta – Venezuela 

 During 2009, Petrodelta drilled and completed 14 successful development wells, suspended one well due to problems with the well and 

drilled two appraisal wells, produced approximately 7.8 million barrels of oil and sold 4.4 billion cubic feet (“BCF”) of natural gas. Petrodelta 

was advised by the Venezuelan government that the 2009 production target was approximately 16,000 barrels of oil per day following the 

December 17, 2008 OPEC meeting establishing new production quotas. However, Petrodelta was allowed to produce at capacity to help fulfill 

other companies’ production shortfalls, thus averaging 21,464 barrels of oil per day during 2009. 

 Petrodelta began the appraisal and testing of its large portfolio of undeveloped resources in the second quarter of 2009. During the second 

quarter 2009, Petrodelta drilled two successful appraisal wells in the El Salto field, and pilot production commenced from one of the appraisal 

wells through temporary facilities. The well commenced production on July 18, 2009 and has produced 349,000 barrels of oil through the end of 

2009. The second appraisal well will be tested after the permitting process with MENPET is completed. 

 Petrodelta shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Currently, 

Petrodelta has one drilling rig operating in the Uracoa field. On February 4, 2010, Petrodelta’s board of directors endorsed a capital budget of 

$205 million for Petrodelta’s 2010 business plan. For 2010, the planned drilling program includes utilizing two rigs to drill both development 

and appraisal wells for both maintaining production capacity and appraising the substantial resource bases in the El Salto field and presently nonproducing Isleño field. 

 On April 23, 2009, Petrodelta’s board of directors declared a dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million 

net to our 32 percent interest). HNR Finance received the cash related to this dividend in the form of an advance dividend in October 2008. We 

expect to receive future dividends from Petrodelta; however, we expect the amount of any future dividends to be lower in the near term as 

Petrodelta reinvests most of its earnings into the company in support of its drilling and appraisal activities. Petrodelta’s results and operating 

information is more fully described in Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 7 – Investment in Equity Affiliates 

– Petrodelta, S.A. 

Diversification 

 Beginning in 2005, we recognized the need to diversify our asset base as part of our strategy. We broadened our strategy from our primary 

focus on Venezuela to identify, access and integrate hydrocarbon assets to include organic growth through exploration in basins globally with 

proven hydrocarbon systems. We seek to leverage our Venezuelan experience as well as our recently expanded business development and 

technical platform to create a diversified resource base. With the addition of technical resources, opening of our London and Singapore offices, 

as well as our minority equity investment in Fusion, we have made significant investments to provide the necessary foundation and global reach 

required for an organic growth focus. Our organic growth is focused on undeveloped or underdeveloped fields, field redevelopments and 

exploration. While exploration will become a larger part of our overall portfolio, we will generally restrict ourselves to basins with known 

hydrocarbon systems and favorable risk-reward profiles. Exploration will be technically driven with a low entry cost and high 

26 
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resource potential that provides sustainable growth. We will continue to seek opportunities where perceived geopolitical risk may provide high 

reward opportunities in the long term. In 2009, we acquired an exploration asset in Oman that fit our strategy and began production at Monument 

Butte described below. 

United States 

 On January 28, 2010, we entered into an agreement with one of the private third parties in our AMI for an option to participate in a new 

project. We paid $1.5 million for the option to acquire up to a 50 percent interest in the new project. If we exercise our option to participate, we 

will participate in this project with essentially the same terms as the other existing projects in the AMI. The option to participate expires on 

June 1, 2010. 

Gulf Coast – West Bay 

 During the year ended December 31, 2009, operational activities in the West Bay prospect included the interpretation of 3-D seismic, site 

surveying, and preparation of engineering documents. Interpretation of 3-D seismic data on the West Bay project was completed in the second 

quarter 2009 and resulted in the identification of a revised set of drilling leads and prospects for the project. 

 The AMI participants are currently evaluating the leads and prospects to determine priorities and drilling plans for the West Bay project. 

Depending on the selected drilling prospects and locations, the drilling may or may not require permit(s) from the U.S. Army Corps of Engineers 

– Galveston District (“Corps of Engineers”). We expect to firm up plans for initial drilling on the West Bay project during 2010, with the 

expectation of initial drilling on the West Bay project in 2011. During the year ended December 31, 2009, we incurred $0.4 million for lease 

acquisition, surveying, permitting and site preparation and $1.5 million for seismic data interpretation. The 2010 budget for the West Bay project 

is $0.1 million. 

Western United States – Antelope 

 Activities are in progress on two separate projects on the Antelope prospect in Duchesne County, Utah. 

Mesaverde 

 The Mesaverde project is targeted to explore for and develop oil and natural gas from multiple reservoir horizons in the Uintah Basin of 

northeastern Utah in Duchesne and Uintah Counties. Leads and prospects have been identified in three prospective reservoir horizons and initial 

drilling activities commenced in 2009 on one prospect. 

 Operational activities during 2009 on the Mesaverde project focused on continuing leasing activities on private, Allottee, and tribal land, 

and surveying, preliminary engineering, permitting preparations, and conducting drilling operations on a deep natural gas test well (the Bar F) 

that commenced drilling on June 15, 2009. The Bar F was permitted to 18,000 feet. The Bar F was drilled to a total depth of 17,566 feet and an 

extended production test is now in progress. To date, testing has been focused on the evaluation of the natural gas potential of the Mesaverde 

tight gas reservoir over a prospective interval from 14,000 to 17,400 feet. Completion activities consisted of hydraulic fracturing of eight 

separate reservoir intervals in the Mesaverde and multiple extended flow tests of the individual fractured intervals, along with a flow test of the 

commingled eight intervals. While the results to date have not definitively determined the commerciality of a stand-alone development of the 

Mesaverde, we believe these results indicate progress toward that determination and that the Mesaverde reservoir remains potentially prospective 

over a portion of our land position. During the year ended December 31, 2009, we incurred $23.4 million for drilling, lease acquisition, 

surveying, permitting and site preparation and $0.3 million for seismic data program planning. The 2010 budget for the Mesaverde project is 

$5.7 million; however, contingent on successful results of the Bar F and availability of funds, we plan to increase this budget to $33.0 million. 

Monument Butte 

 The Monument Butte project is an eight well appraisal and development drilling program to produce oil and natural gas from the Green 

River formation on the southern portion of our Antelope land position. The 

27 
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Monument Butte project is non-operated and we hold a 43 percent working interest. The parties have formed a 320 acre AMI which contained 

the eight drilling locations. 

 Operational activities during 2009 on the Monument Butte project focused on resolution of forced pooling issues with a non-consenting 

interest, negotiations and finalization of an agreement with the operator for the joint drilling operations. As of March 1, 2010, all eight wells 

have been drilled. Seven wells are currently on production. One additional well is waiting on completion operations and is anticipated to 

commence production in early March 2010. During the year ended December 31, 2009, we incurred $1.8 million for drilling (including drilling 

accruals), lease acquisition, surveying, permitting and site preparation. The 2010 budget for the Monument Butte project is $1.1 million which 

has already been spent in the first quarter of 2010. We are currently evaluating the potential expansion of this drilling program. Contingent on 

the successful results of this evaluation, negotiation with the operator and availability of funds, this budget could be increased to $4.6 million. 

Budong-Budong Project, Indonesia 

 Operational activities during 2009 focused on the interpretation of 650 kilometers of 2-D seismic and well planning. Two drill sites have 

been selected. Currently, the locations for the two test wells are being constructed and the rig and ancillary equipment is being mobilized to the 

area. It is expected that the first of two exploration wells will spud early in the second quarter of 2010. In accordance with the farm-in 

agreement, we expect to fund 100 percent of the well expenditures to earn our 47 percent working interest up to a cap of $10.7 million; 

thereafter, we will pay in proportion to our working interest. During the year ended December 31, 2009, we incurred $0.3 million for surveying, 

permitting, engineering and well planning and $1.8 million for seismic data processing and interpretation. The 2010 budget for the Budong PSC 

is $14.9 million. Contingent on the successful results of the two exploratory test wells and availability of funds, this budget could be increased to 

$28.0 million. 

Dussafu Project — Gabon 

 Operational activities during 2009 focused on completion of the processing and reprocessing of 1,330 kilometers of 2-D seismic and the 

pre-stack depth reprocessing of 1,076 square kilometers of 3-D seismic data. The improved imaging from this work has allowed the 

interpretation to mature the prospect inventory to provide the partnership a number of prospective targets in the sub-salt section, in both the 

Gamba and Syn-rift plays that are productive in the nearby Etame, Lucina and M’Bya fields. Subject to drilling rig availability, we expect to drill 

an exploration well in the third quarter of 2010. During the year ended December 31, 2009, we incurred $1.2 million for seismic data processing 

and reprocessing. The 2010 budget for the Dussafu PSC is $2.2 million. Contingent on rig availability and successful results from the 

exploration well and availability of funds, this budget could be increased to $20.1 million. 

Block 64 EPSA Project — Oman 

 On April 11, 2009, we signed an EPSA with Oman for the Block 64 EPSA. Current activities include the compilation of existing data over 

two prospect areas of approximately 1,000 square kilometers and geological studies to determine drillable prospects. Well planning is expected 

to commence in 2010 for exploration drilling in 2011. We incurred $2.3 million for costs associated with signing the license, including signature 

bonus and data compilation and $0.5 million for seismic data processing and reprocessing. The 2010 budget for the Block 64 EPSA is 

$2.8 million. Contingent on the availability of funds, an additional $1.9 million are planned for this project. 

WAB-21 Project – China 

 The WAB-21 petroleum contract lies within an area which is the subject of a border dispute between China and Vietnam. The border 

dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the dispute. 

However, Vietnam, along with the company that is the party to the agreement with Vietnam, recently announced plans for exploration drilling 

during 2010. While no assurance can be given, we believe this announcement may provide some resolution with the border disputes, although 

we do not know in what manner any resolution might appear. 

28 
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Other Exploration Projects 

 Relating to other projects, we incurred $1.3 million during the year ended December 31, 2009. The 2010 budget for other projects is 

$0.3 million. Contingent upon successful test results in Utah and Indonesia and availability of funds, we may increase this budget to 

$20.4 million. 

 Either one of the two exploratory wells to be drilled in 2010 on the Budong PSC or the completion of the well on the Mesaverde project 

can have a significant impact on our ability to obtain financing, record reserves and generate cash flow in 2010 and beyond. 

 In Item 1 – Business and Item 1A – Risk Factors, we discuss the situation in Venezuela and how the actions of the Venezuelan government 

have and continue to adversely affect our operations. Low crude oil prices and the expectation that dividends from Petrodelta will be minimal 

over the next two years has restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and 

develop growth opportunities elsewhere. 

 We will use our available cash and future access to capital markets to expand our diversified strategy in a number of countries that fit our 

strategic investment criteria. In executing our business strategy, we will strive to: 

29 

 • maintain financial prudence and rigorous investment criteria; 

 

 • access capital markets; 

 

 • continue to create a diversified portfolio of assets; 

 

 • preserve our financial flexibility; 

 

 • use our experience and skills to acquire new projects; and 

 

 • keep our organizational capabilities in line with our rate of growth. 

 

 To accomplish our strategy, we intend to: 

 

 • Diversify our Political Risk: Acquire oil and natural gas fields in a number of countries to diversify and reduce the overall political risk 

of our investment portfolio. 

 

 • Seek Operational 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 Presence Through Joint Venture Partners and the Use of Local Personnel: We seek to establish a presence in the countries 

and areas we operate through joint venture partners to facilitate stronger governmental and business relationships. In addition, we use 

local personnel to help us take advantage of local knowledge and experience and to minimize costs. 

 

 • Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time: We are willing to agree to minimum capital 

expenditures or development commitments at the outset of new projects, but we endeavor to structure such commitments to 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. 

 

 • Provide Technical Expertise: We believe there is an advantage in being able to provide geological, geophysical and engineering 

expertise beyond what many companies or countries possess internally. In addition to our in-house technical capabilities, we acquired a 

minority equity investment in Fusion, a technical firm with significant experience in providing leading edge geophysical, geosciences 

and reservoir engineering services in many places in the world. Through this acquisition we have strategic access to these services. 

 

 • Maintain a Prudent Financing Plan : We intend to maintain our financial flexibility by closely monitoring spending, holding sufficient 

cash reserves, minimizing the use of restricted cash, actively seeking 
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Results of Operations 

 The following discussion should be read with the results of operations for each of the years in the three-year period ended December 31, 

2009 and the financial condition as of December 31, 2009 and 2008 in conjunction with our consolidated financial statements and related notes 

thereto. 

Years Ended December 31, 2009 and 2008 

 We reported a net loss attributable to Harvest of $3.1 million, or $(0.09) diluted earnings per share, for the year ended December 31, 2009, 

compared with a net loss attributable to Harvest of $21.5 million, or $(0.63) diluted earnings per share, for the year ended December 31, 2008. 

 Revenues were higher for the year ended December 31, 2009 compared with the year ended December 31, 2008 due to the Monument 

Butte wells coming on production in December 2009. 

 Total expenses and other non-operating (income) expense (in millions): 

 Depletion and amortization expense per Boe produced during 2009 was $6.59. 

 Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2009, we incurred 

$4.3 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, $2.8 million related to 

other general business development activities and $0.7 million related to the write off of the remaining carrying value of the Starks prospect. 

During the year ended December 31, 2008, we incurred $16.4 million of exploration costs related to the purchase and re-processing of seismic 

data related to our U.S. operations, acquisition of seismic data related to our Indonesia operations, and other general business development 

activities. Also during the year ended December 31, 2008, we incurred $10.8 million of dry hole costs related to the Harvest Hunter #1 well, 

which in January 2009 was determined to have no commercial quantities of hydrocarbons and was plugged and abandoned. 

 General and administrative costs were lower in the year ended December 31, 2009, than in the year ended December 31, 2008, primarily 

due to employee related expenses, lower general operations and office costs, and the reversal of accruals no longer required, including penalties 

and interest of $0.9 million on the resolved SENIAT 

30 

 opportunities to reduce our weighted average cost of capital and increase our access to debt and equity markets. 

 

 • Manage Exploration Risks . We seek to manage the higher risk of exploration by diversifying our prospect portfolio, applying state-ofthe-art technology for analyzing targets and focusing on opportunities in proven active hydrocarbon systems with infrastructure. 

 

 • Establish Various Sources of Production . We seek to establish new production from our exploration and development efforts in a 

number of diverse markets and expect to monetize production through operations or the sale of assets. 

 

 Year Ended 

 December 31, Increase 

 2009 2008 (Decrease) 

Depletion, depreciation and amortization $ 0.4 $ 0.2 $ 0.2 

Exploration expense 7.8 16.4 (8.6 ) 

Dry hole costs — 10.8 (10.8 ) 

General and administrative 21.9 27.2 (5.3 ) 

Taxes other than on income 1.0 (0.2 ) 1.2 

Gain on financing transactions — (3.4 ) 3.4 

Investment earnings and other (1.1 ) (3.7 ) 2.6 

Interest expense — 1.7 (1.7 ) 

Income tax expense 1.2 — 1.2 
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assessments. Taxes other than on income for the year ended December 31, 2009, were higher than the year ended December 31, 2008 due to the 

reversal in 2008 of a $1.1 million franchise tax provision that was no longer required. 

 We did not participate in any security exchange transactions in the year ended December 31, 2009. During the year ended December 31, 

2008, we entered into a securities exchange transaction exchanging U.S. government securities for U.S. Dollar indexed debt issued by the 

Venezuelan government. This security exchange transaction resulted in a $3.4 million gain on financing transactions for the year ended 

December 31, 2008. 

 Investment earnings and other decreased in the year ended December 31, 2009 compared to the year ended December 31, 2008 due to 

lower interest rates earned on lower average cash balances. Interest expense was lower for the year ended December 31, 2009 compared to the 

year ended December 31, 2008 due to the repayment of debt in 2008. 

 For the year ended December 31, 2009, income tax expense was higher than that of the year ended December 31, 2008 primarily due to 

additional income tax assessed in the Netherlands of $0.7 million as a result of financing activities, which was recorded in the first quarter of 

2009, and additional current income tax in the Netherlands of $0.5 million due to interest income earned from loans to affiliates and on cash 

balances. No income tax benefit is recorded for the net operating losses incurred as a full valuation allowance has been placed on the related 

deferred tax asset as management believes that is more likely than not that additional net losses will not be realized through future taxable 

income. There was no utilization of net operating loss carryforwards in the year ended December 31, 2009. 

 Net income from unconsolidated equity affiliates includes two non-recurring adjustments: 

See Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 7 – Investment in Equity Affiliates for additional information. 

Years Ended December 31, 2008 and 2007 

 We reported a net loss attributable to Harvest of $21.5 million, or $(0.63) diluted earnings per share, for the year ended December 31, 

2008 compared to net income attributable to Harvest of $60.1 million, or $1.59 diluted earnings per share, for the year end December 31, 2007. 

 We included the results of operations of Harvest Vinccler in our consolidated financial statements and reflected the 20 percent ownership 

interest of OGTC as a noncontrolling interest in 2005 and the first quarter of 2006. Since April 1, 2006, our minority equity investment in 

Petrodelta has been reflected under the equity method of accounting. We recorded the cumulative effect from April 1, 2006 to December 31, 

2007 in the three months ended December 31, 2007. The year ended December 31, 2008 includes net income from unconsolidated equity 

affiliates for Petrodelta on a current basis. See Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 7 – Investment in Equity 

Affiliates – Petrodelta, S.A. for Petrodelta’s results of operations which reflect the results for the years ended December 31, 2009, 2008 and 

2007, comparatively. 

31 

 • During the second quarter of 2009, Petrodelta recorded additional pension expense of $15.6 million ($5.0 million net to our 32 percent 

interest) in the three month period ended June 30, 2009 based on an actuarial study commissioned by PDVSA which was finalized 

during the second quarter of 2009. During the fourth quarter of 2009, Petrodelta received a revised allocation of its pension obligation 

from PDVSA which reflected an update to the actuarial study based on a further refinement of assumption and a revised allocation 

methodology as a result of an analysis of more detailed census data specific to each mixed company not previously available. This 

revised allocation resulted in a decrease of $8.4 million ($2.7 million net to our 32 percent interest) to the pension and retirement plan 

costs as compared to those previously recorded to Petrodelta in May 2009. This change in management’s estimate related to the pension 

and retirement plan costs was recorded in December 2009. 

 

 • Based on cash flow projections and considering Fusion’s current liquidity, we performed a review at December 31, 2009 for impairment 

of our minority equity investment in Fusion. Based on this review, we concluded that Fusion’s potential business opportunities did not 

support its on-going cash flow requirements; and therefore, we recorded a $1.6 million charge to fully impair the carrying value of our 

equity investment in Fusion at December 31, 2009. 
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 Revenue recorded for the year ended December 31, 2007 reflects the reversal of deferred revenue recorded by Harvest Vinccler for 2005 

and first quarter of 2006 deliveries pending clarification on the calculation of crude prices under the Transitory Agreement. See Part IV, Item 15, 

Notes to the Consolidated Financial Statements, Note 1 – Organization and Summary of Significant Account Policies – Revenue Recognition . 

There were no sales of oil and natural gas in 2008 or 2007 due to the conversion of the OSA to a minority equity investment in Petrodelta. 

 Total expenses and other non-operating (income) expense (in millions): 

 In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts 

method from the full cost method. During the year ended December 31, 2008, we incurred $16.4 million of exploration costs related to the 

purchase and re-processing of seismic data related to our U.S. operations, acquisition of seismic data related to our Indonesia operations, and 

other general business development activities. Also during the year ended December 31, 2008, we incurred $10.8 million of dry hole costs 

related to the Harvest Hunter #1 well, which in January 2009 was determined to have no commercial quantities of hydrocarbons and was 

plugged and abandoned. During the year ended December 31, 2007, we incurred $0.9 million of exploration costs related to other foreign general 

business development. 

 General and administrative costs were lower in the year ended December 31, 2008, than in the year ended December 31, 2007, primarily 

due to employee related expenses and lower contract services. Taxes other than on income for the year ended December 31, 2008, were lower 

than the year ended December 31, 2007 due to the reversal of a $1.1 million franchise tax provision that was no longer required. 

 During the years ended December 31, 2008 and 2007, we entered into securities exchange transactions exchanging U.S. government 

securities for U.S. Dollar indexed debt issued by the Venezuelan government. These security exchange transactions resulted in a $3.4 million 

and $49.6 million gain on financing transactions for the years ended December 31, 2008 and 2007, respectively. 

 Investment earnings and other decreased in the year ended December 31, 2008, as compared to the same period of the prior year due to 

lower interest rates earned on lower cash balances. Interest expense decreased due to the payment of Harvest Vinccler’s Bolivar denominated 

debt in July of 2008. 

 For the year ended December 31, 2008, income tax expense, which is comprised of income tax on our foreign activities and withholding 

tax on interest income from Harvest Vinccler, was lower than that of the year ended December 31, 2007, partially due to the $49.6 million gain 

on financing transactions occurring in the year ended December 31, 2007 compared to a $3.4 million gain on financing transactions occurring in 

the year ended December 31, 2008. The reduction in income tax expense was also partially due to the reduction in the rate of withholding tax on 

the Venezuela interest, which went from 10 percent to 5 percent under the Netherlands-Venezuela double tax treaty. No income tax benefit is 

recorded for the net operating losses incurred as a full valuation allowance has been placed on the related deferred tax asset as management 

believes that is more likely than not that additional net losses will not be realized through future taxable income. There was no utilization of net 

operating loss carryforwards in the year ended December 31, 2008. 

32 

 

 Year Ended 

 December 31, Increase 

 2008 2007 (Decrease) 

Depreciation $ 0.2 $ 0.4 $ (0.2 ) 

Exploration expense 16.4 0.9 15.5 

Dry hole costs 10.8 — 10.8 

General and administrative 27.2 29.1 (1.9 ) 

Taxes other than on income (0.2 ) 0.4 (0.6 ) 

Gain on financing transactions (3.4 ) (49.6 ) 46.2 

Investment earnings and other (3.7 ) (9.1 ) 5.4 

Interest expense 1.7 8.2 (6.5 ) 

Income tax expense — 6.3 (6.3 ) 
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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 Item 1A —

Risk Factors ). We require capital principally to fund the exploration and development of new oil and gas properties. For calendar year 2010, we 

have preliminarily established an exploration and drilling budget of approximately $27.1 million. We are concentrating a substantial portion of 

this budget on the development of our Antelope prospect and Budong PSC. Contingent upon the successful test results of the exploratory well 

drilled on the Antelope prospect, the exploratory wells to be drilled on the Budong PSC and availability of funds, we have planned capital 

expenditures of up to $110.8 million to evaluate and develop our prospect portfolio in the United States and international locations, excluding 

Venezuela’s self funding program. We currently believe that Petrodelta will fund its own operations and continue to pay dividends although no 

dividends are expected in 2010 based on our current forecast. In Item 1A – Risk Factors , we discuss a number of variables and risks related to 

our minority equity investment in Petrodelta and exploration projects that could significantly utilize our cash balances, affect our capital 

resources and liquidity. We also point out that the total capital required to develop the fields in Venezuela may exceed Petrodelta’s available 

cash and financing capabilities, and that there may be operational or contractual consequences due to this inability. 

 Based on our cash balance of $32 million at December 31, 2009, we will be required to raise additional funds in order to fund our future 

operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration projects and to a 

lesser extent general and administrative costs. Through December 31, 2009, our exploration expenditures outside of Venezuela have resulted in a 

modest amount of new proved reserves in Utah in the United States. If we are not able to raise additional capital or prove up additional sources 

of revenue, there will be a need to reduce our projected expenditures which could limit our ability to operate our business. Currently, our primary 

source of cash is dividends from Petrodelta. However, there is no certainty that Petrodelta will pay dividends in 2010 or 2011. Our lack of cash 

flow and the unpredictability of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance 

adequate financing can be raised. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of 

financing sources, accessing equity and debt markets, exploration of our properties worldwide, and cost reductions. In addition, we could delay 

discretionary capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, if necessary. 

There can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and 

liquidity could be materially adversely affected. 

 On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. 

Under the terms of the notes, we will pay interest semi-annually and the notes will mature on March 1, 2013, unless earlier redeemed, 

repurchased or converted. The notes are convertible into shares of our common stock at a conversion rate of 175.2234 shares of common stock 

per $1,000 principal amount of convertible notes, equivalent to a conversion price of approximately $5.71 per share of common stock, subject to 

adjustment. The notes are our general unsecured obligations, ranking equally with all of our other unsecured senior indebtedness, if any, and 

senior in right of payment to any of our subordinated indebtedness, if any. The notes are also redeemable in certain circumstances at our option 

and may be repurchased by us at the purchaser’s option in connection with occurrence of certain events. The net proceeds of the offering to us 

were approximately $30.0 million, after deducting underwriting discounts, commissions and estimated offering expenses. We intend to use these 

net proceeds to fund capital expenditures and for working capital needs and general corporate purposes. 

 In addition, we are currently contemplating one particular additional source of financing through an Islamic (sukuk) financing, in which 

one of our subsidiaries would form and contribute certain assets to a partnership and subsequently sell a minority interest in the partnership to 

one or more third parties for approximately $250 million. Although the terms of this transaction have not been finalized, we anticipate that the 

terms would include our agreement to pay all or a substantial portion of the dividends paid by Petrodelta to which we are entitled over the next 

five or six years to reacquire all of the third-party partnership interests, including premiums thereon. While we may be able to consummate this 

financing transaction during the first half of 2010, there can be no assurances that this transaction will be consummated, and we may consider 

alternative forms of additional financing if we deem necessary or advisable with respect to our operations from time to time. 

 On February 5, 2003, Venezuela imposed currency controls and created CADIVI with the task of establishing the detailed rules and 

regulations and generally administering the exchange control regime. These 

33 
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controls fix the exchange rate between the Bolivar and the U.S. Dollar and restrict the ability to exchange Bolivars for U.S. Dollars and vice 

versa. The U.S. Dollar and Bolivar exchange rates had not been adjusted since March 2005 until January 8, 2010 when the Venezuelan 

government adjusted the exchange rate from 2.15 Bolivars per U.S. Dollar to 2.60 Bolivars per U. S. Dollar for the food, health, medical and 

technology sectors; and 4.30 Bolivars per U. S. Dollar for all other sectors not expressly established by the 2.60 Bolivar exchange rate. The U.S. 

Dollar is the functional reporting currency for both Petrodelta and Harvest Vinccler. The Bolivar is not readily convertible into the U.S. Dollar. 

The Venezuelan currency conversion restriction has not adversely affected our ability to meet short-term loan obligations and operating 

requirements for the foreseeable future. 

 Working Capital . Our capital resources and liquidity are affected by the ability of Petrodelta to pay dividends. On April 23, 2009, 

Petrodelta’s board of directors declared a dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent 

interest). HNR Finance received the cash related to this dividend in the form of an advance dividend in October 2008. We expect to receive 

future dividends from Petrodelta; however, we expect the amount of any future dividends to be lower in the near term as Petrodelta reinvests 

most of its earnings into the company in support of its drilling and appraisal activities. In June 2009, CVP issued instructions to all mixed 

companies regarding the accounting for deferred tax assets. The mixed companies have been instructed to set up a reserve within the equity 

section of the balance sheet for deferred tax assets. The setting up of the reserve had no effect on Petrodelta’s financial position, results of 

operation or cash flows. However, the new reserve could have a negative impact on the amount of dividends received in the future. In addition to 

reinvesting earnings into the company in support of its drilling and appraisal activities, the decline in the price per barrel affects Petrodelta’s 

ability to pay dividends. All available cash will be used to meet current operating requirements and will not be available for dividends. See 

Item 1 — Business, Petrodelta and Item 1A — Risk Factors for a more complete description of the situation in Venezuela and other matters. 

 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: 

 The decrease in working capital of $42.8 million was for capital expenditures and administrative expenses. 

 Cash Flow from Operating Activities . During the year ended December 31, 2009, net cash used in operating activities was approximately 

$34.9 million. During the year ended December 31, 2008, net cash provided by operating activities was approximately $50.4 million. The 

$85.3 million decrease was primarily due to the receipts in 2008 of a $72.5 million dividend net to HNR Finance ($58.0 million net to our 

32 percent interest) and advance dividend of $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest) from our 

unconsolidated equity affiliate and payment of advances by PDVSA offset by payment of the accounts payable related party, repurchase of 

treasury stock, payment of a dividend to the noncontrolling interest in Harvest-Vinccler Dutch Holding, B.V., and capital expenditures. 

 Cash Flow from Investing Activities. During the year ended December 31, 2009, we had cash capital expenditures of approximately 

$28.0 million. Of the 2009 expenditures, $0.4 million was attributable to the West Bay project, $23.7 million was attributable to the Antelope 

prospect, $0.3 million was attributable to exploration 

34 

 

 Year Ended December 31, 

 (in thousands except as indicated) 

 2009 2008 2007 

Net cash provided by (used in) operating activities $ (34,945 ) $ 50,380 $ (20,655 ) 

Net cash provided by (used in) investing activities (28,603 ) (23,055 ) 69,960 

Net cash used in financing activities (1,300 ) (51,001 ) (76,543 ) 

    

Net decrease in cash $ (64,848 ) $ (23,676 ) $ (27,238 ) 

 

 

 

 

 

 

 

 

Working Capital 34,206 77,010 111,534 

Current Ratio 3.0 3.0 3.6 

Total Cash, including restricted cash 32,317 97,165 127,610 

Total Debt — — 9,302 
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activity on the Budong PSC, $2.3 million was attributable to the Block 64 EPSA project and $1.3 million on other projects. During the year 

ended December 31, 2008, we had cash capital expenditures of approximately $26.3 million. Of the 2008 expenditures, $4.7 million was 

attributable to the Gulf Coast prospects, $10.8 million was attributable to the Harvest Hunter #1 exploration well, $4.2 million was attributable to 

the Antelope prospect, $0.1 million was attributable to the Budong PSC, $5.3 million was attributable to the Dussafu PSC, and $1.2 million on 

other projects. During the year ended December 31, 2008, we increased our minority equity investment in Fusion by purchasing an additional 

two percent interest for $2.2 million. During the year ended December 31, 2008, $6.8 million of restricted cash used as collateral for loans which 

were repaid was returned to us. During the year ended December 31, 2009 and 2008, we incurred $0.6 million and $1.3 million, respectively, of 

investigatory costs related to various international and domestic exploration studies. 

 With the conversion to Petrodelta, Petrodelta’s capital commitments will be determined by its business plan. Petrodelta’s capital 

commitments are expected to be funded by internally generated cash flow. Our budgeted capital expenditures of $27.1 million for 2010 for U.S., 

Indonesia, Gabon and Oman operations will be funded through our existing cash balances, the February 2010 debt offering, other financing 

sources, accessing equity and debt markets, and cost reductions. In addition, we could delay discretionary capital spending to future periods or 

sell assets as necessary to maintain the liquidity required to run our operations, as warranted. 

 Cash Flow from Financing Activities. During the year ended December 31, 2009 we incurred $1.7 million in legal fees associated with 

prospective financing. During year ended December 31, 2008, Harvest Vinccler repaid 20 million Bolivars (approximately $9.3 million) of its 

Bolivar denominated debt, we redeemed the 20 percent minority interest in our Barbados affiliate, incurred $1.1 million in legal fees associated 

with prospective financing, and we paid a dividend of $14.9 million to the noncontrolling interest in Harvest-Vinccler Dutch Holding, B.V. 

 In July 2008, our Board of Directors authorized the purchase of up to $20 million of our common stock from time to time through open 

market transactions. As of December 31, 2008, 1.2 million shares of stock had been purchased at an average cost of $10.17 per share for a total 

cost of $12.2 million of the $20 million authorization. During the year ended December 31, 2009, no stock was purchased under the program. 

Contractual Obligations 

 We have a lease obligation of approximately $32,000 per month for our Houston office space. This lease runs through July 2014. In addition, 

Harvest Vinccler has lease obligations for office space in Caracas, Venezuela for approximately $10,000 per month. This lease runs through 

November 2010. We also have lease commitments for an office in Utah for approximately $6,000 per month, an office in Singapore for 

approximately $19,000 per month, an office space in Indonesia for approximately $5,000 per month, an office in Oman for approximately 

$5,000 per month and an office in London for approximately $24,000 per month. These leases expire in September 2010, October 2010, 

March 2011, August 2011 and November 2010, respectively. Our London office space is leased on a month-to-month basis with no long term 

commitment. We do not have any long-term contractual commitments for any of our projects. 

Effects of Changing Prices, Foreign Exchange Rates and Inflation 

 Our results of operations and cash flow are affected by changing oil prices. Fluctuations in oil prices may affect our total planned 

development activities and capital expenditure program. 

 Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004, March 2005 

and again in January 2010. The currency conversion restrictions or the adjustment in the exchange rate have not had a material impact on us at 

this time. Dividends from Petrodelta will be denominated in U.S. Dollars when paid. Within the United States and other countries in which we 

conduct business, inflation has had a minimal effect on us, but it is potentially an important factor with respect to results of operations in 

Venezuela. 

35 

 

 Payments (in thousands) Due by Period 

 Less than After 4 

Contractual Obligation Total 1 Year 1-2 Years 3-4 Years Years 

Office Leases $ 2,674 $ 1,215 $ 459 $ 407 $ 593 

Asset Retirement Obligation 50 — — — 50 

 

 

    

Total Contractual Obligations $ 2,724 $ 1,215 $ 459 $ 407 $ 643 

 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

 During the years ended December 31, 2009 and 2008, our net foreign exchange gains attributable to our international operations were 

minimal. The U.S. Dollar and Bolivar exchange rates have not been adjusted from March 2005 until January 2010. However, there are many 

factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our control. We have recognized 

significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan currency to the U.S. Dollar. It 

is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls. 

 An exemption under the Venezuelan Criminal Exchange Law for transactions in certain securities results in an indirect securities transaction 

market of foreign currency exchange, through which companies may obtain foreign currency legally without requesting it from the Venezuelan 

government. Publicly available quotes do not exist for the securities transaction exchange rate but such rates may be obtained from brokers. 

Securities transaction markets are used to move financial securities in and out of Venezuela. 

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. 

Reporting and Functional Currency 

 The U.S. Dollar is our reporting and functional currency. Amounts denominated in non-U.S. Dollar currencies are re-measured in U.S. 

Dollars, and all currency gains or losses are recorded in the consolidated statement of operations. We attempt to manage our operations in such a 

manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting 

exchange gains and losses, many of which are beyond our influence. 

 The U.S. Dollar is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. 

Revenue Recognition 

 We record revenue for our U.S. oil and natural gas operations when we deliver our production to the customer and collectability is reasonably 

assured. Revenues from the production of oil and natural gas on properties in which we have joint ownership are recorded under the sales 

method. Differences between these sales and our entitled share of production are not significant. 

Investment in Equity Affiliates 

 Investments in unconsolidated companies in which we have less than a 50 percent interest and have significant influence are accounted for 

under the equity method of accounting. Investment in equity affiliates is increased by additional investment and earnings and decreased by 

dividends and losses. We review our investment in equity affiliates for impairment whenever events and circumstances indicate a decline in the 

recoverability of its carrying value. 

Property and Equipment 

 We follow the successful efforts method of accounting for our oil and gas properties. Under this method, oil and natural gas lease acquisition 

costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-byproperty basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are 

aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average 

36 
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holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas 

properties. Lease rentals are expensed as incurred. 

 Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of 

drilling exploratory wells are capitalized pending determination of whether the wells have discovered proved reserves. Exploratory drilling costs 

are capitalized when drilling is completed if it is determined that there is economic producibility supported by either actual production, 

conclusive formation test or by certain technical data. If proved reserves are not discovered, such drilling costs are expensed. In some 

circumstances, it may be uncertain whether proved reserves have been found when drilling has been completed. Such exploratory well drilling 

costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in 

assessing the reserves and the economic and operating viability of the projects is being made. Costs to develop proved reserves, including the 

costs of all development wells and related equipment used in production of natural gas and crude oil, are capitalized. 

 Depreciation, depletion, and amortization of the cost of proved oil and natural gas properties are calculated using the unit of production 

method. The reserve base used to calculate depletion, depreciation or amortization for leasehold acquisition costs and the cost to acquire proved 

properties is proved reserves. With respect to lease and well equipment costs, which include costs and successful exploration drilling costs, the 

reserve base is proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken 

into account. Certain other assets are depreciated on a straight-line basis. 

 Assets are grouped in accordance with paragraph 30 of the accounting standard for financial accounting and reporting by oil and gas 

producing companies. The basis for grouping is reasonable aggregation of properties with a common geological structural feature or stratigraphic 

condition, such as a reservoir or field. 

 Amortization rates are updated to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) 

property acquisitions and/or property dispositions and 4) impairments. 

 We account for impairments of proved propertied under the provisions of the accounting standard for accounting for the impairment or 

disposal of long-lived assets. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows 

at a producing field level to the amortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future 

crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the 

amortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an 

appropriate risk-adjusted discount rate. 

Reserves 

 In December 2009, we adopted revised oil and gas reserve estimation and disclosure requirements which conforms the definition of proved, 

probable and possible reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. 

The new accounting standard requires that the unweighted average, first-day-of-the-month price during the 12-month period preceding the end of 

the year, rather than the year-end price, be used when estimating reserve quantities and permits the use of reliable technologies to determine 

proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Prior-year data are 

presented in accordance with FASB oil and gas disclosure requirements effective during those periods. 

 Proved reserves are those quantities of oil and gas which by analysis of geoscience and engineering data can be estimated with reasonable 

certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating 

methods, government regulations, etc., i.e ., at prices as described above and costs as of the date the estimates are made. Prices include 

consideration of changes in existing prices provided only by contractual arrangements, and do not include adjustments based upon expected 

future conditions. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together 

with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves which are less certain to be recovered 

than probable reserves and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low. 

 Reserves may be estimated using probabilistic methods in which there is at least a 90 percent probability of recovery of proved reserves, at 

least a 50 percent probability of recovery of probable reserves, and at least a 10 percent probability of recovery of possible reserves. Our 

probable reserves were calculated using probabilistic methods and represent the 50 percent probability that the actual quantities recovered will be 

equal to or greater than the proved plus probable estimate. The larger quantity of proved reserves plus probable reserves, as compared to proved 

reserves only, is attributable largely to using a less conservative interpretation of reservoir size and recovery factor in estimating probable 

reserves. 

37 
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 The estimate of reserves is made using available geological and reservoir data as well as production performance data. These estimates are 

prepared by an independent third party petroleum engineering consulting firm and revised, either upward or downward, as warranted by 

additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and 

governmental restrictions, as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause 

a reduction in some proved reserves due to reaching economic limits earlier. A material adverse change in the estimated volumes of proved 

reserves could have a negative impact on DD&A expense and could result in the recognition of an impairment. 

Accounting for Asset Retirement Obligation 

 If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be 

made, we record a liability (an asset retirement obligation or “ARO”) on our consolidated balance sheet and capitalize the present value of the 

asset retirement cost in oil and gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and 

the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation assuming the normal operation of the asset, 

using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the 

date that the abandonment obligation was incurred using an assumed cost of funds for our Company. After recording these amounts, the ARO is 

accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on a unit-ofproduction basis within the related asset group. Accretion is included in operating expenses and depreciation is included in depreciation, 

depletion and amortization on our consolidated statement of income. 

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. 

New Accounting Pronouncements 

 In June 2009, the Financial Accounting Standards Board (“FASB”) issued an accounting standard for subsequent events which establishes 

general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. 

This standard is effective for interim or annual periods ending after June 15, 2009. We adopted this standard effective June 15, 2009. The 

adoption of this standard did not have an effect on our consolidated financial position, results of operations or cash flows. 

 In June 2009, the FASB issued an accounting standard for accounting for transfers of financial assets. The objective in issuing this standard is 

to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial 

statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a 

transferor’s continuing involvement, if any, in transferred financial assets. This standard is effective for annual periods beginning after 

November 15, 2009. The adoption of this standard did not have a material impact on our consolidated financial position, results of operations or 

cash flows. 

 In June 2009, the FASB issued an amendment to the financial interpretation to improve financial reporting by enterprises involved with 

variable interest entities. This amendment is effective for annual periods beginning after November 15, 2009. This amendment did not have a 

material impact on our consolidated financial position, results of operations or cash flows. 

 In June 2009, the FASB issued an accounting standard that codifies and modifies the hierarchy of generally accepted accounting principles. 

This standard is the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive 

releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This standard 

superseded all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature 

38 
Table of Contents 

not included in this standard is now nonauthoritative. This standard is effective for financial statements issued for interim and annual periods 

ending after September 15, 2009. The adoption of this standard did not have an impact on our consolidated financial position, results of 

operations or cash flows. 

 In December 2009, the FASB issued its final updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure 

requirements of Extractive Industries — Oil and Gas (Topic 932) with the requirements in the SEC’s final rule, Modernization of the Oil and 

Gas Reporting Requirements, which was issued on December 31, 2008 and is effective as of December 31, 2009. 

Off-Balance Sheet Arrangements 

 We do not have any off-balance sheet arrangements. 

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

Oil Prices 

 As an independent oil producer, our revenue, other income and profitability, reserve values, access to capital and future rate of growth are 

substantially dependent upon the prevailing prices of crude oil and natural gas. 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. 

Foreign Exchange 

 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 Venezuela, and therefore our financial results are subject to favorable or unfavorable fluctuations in exchange rates and 

inflation in that country. Venezuela has imposed currency exchange controls (See Item 7 — Management’s Discussion and Analysis of Financial 

Condition and Results of Operations, Capital Resources and Liquidity above). 

 The information required by this item is included herein on pages S-1 through S-40. 

 None. 

39 

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 
Table of Contents 

 Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures that are designed to ensure the 

information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and 

reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our 

management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding 

required disclosure. 

 Management of the Company, with the participation of our principal executive officer and principal financial officer, evaluated the 

effectiveness of the Company’s disclosure controls and procedures. Based on their evaluation as of December 31, 2009, our principal executive 

officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) 

under the Exchange Act) were effective. 

 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 Rule 13a-15(f) and 15d-15(f). Under the supervision 

and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an 

evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control Integrated Framework issued by the 

Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the Internal Control Integrated 

Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2009. The 

effectiveness of our internal control over financial reporting as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an 

independent registered public accounting firm, as stated in their report which appears herein. 

 Management’s Remediation Efforts. In our Annual Report on Form 10-K for the year ended December 31, 2008, management concluded 

that the Company did not maintain effective controls over the period-end financial reporting process as of December 31, 2008. Specifically, 

effective controls did not exist to ensure that the deferred tax adjustments to reconcile net income reported by Petrodelta under IFRS to that 

required by GAAP were completely and accurately identified and that the necessary adjustments were appropriately analyzed and recorded on a 

timely basis. 

 During 2009, management has enhanced the controls over its equity investment to ensure that the adequate information regarding Petrodelta’s 

temporary deferred tax differences is obtained and that a comprehensive analysis of such information is performed. Specifically, management 

has requested further information related to the nature of each temporary deferred tax difference which enables management to determine the 

impact on the deferred tax adjustment to reconcile net income reported by Petrodelta under IFRS to that required under GAAP. The enhanced 

controls have enabled management to ensure that the deferred tax adjustment to reconcile net income reported by Petrodelta under IFRS to that 

required under GAAP is identified and completely and accurately reconciled. 

 During the year ended December 31, 2009, management further enhanced the controls necessary to ensure that all necessary adjustments are 

appropriately analyzed and recorded on a timely basis. These enhancements were in place and operating effectively as of December 31, 2009. 

 Changes in Internal Control over Financial Reporting. There have been no changes in internal control over financial reporting during the 

quarter ended December 31, 2009 that have materially affected or are reasonably likely to materially affect that Company’s internal control over 

financial reporting. 

 None. 

PART III 

Item 10. Directors, Executive Officers and Corporate Governance 

 Please refer to the information under the captions “Election of Directors” and “Executive Officers” in our Proxy Statement for the 2010 

Annual Meeting of Stockholders. 

40 

Item 9A. Controls and Procedures 

Item 9B. Other Information 
Table of Contents 

 Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the 2010 Annual Meeting of 

Stockholders. 

 Please refer to the information under the caption “Stock Ownership” in our Proxy Statement for the 2010 Annual Meeting of Stockholders. 

 Please refer to the information under the caption “Certain Relationships and Related Transactions” in our Proxy Statement for the 2010 

Annual Meeting of Stockholders. 

Item 14. Principal Accountant Fees and Services 

 Please refer to the information under the caption “Independent Registered Public Accounting Firm” in our Proxy Statement for the 2010 

Annual Meeting of Stockholders. 

41 

Item 11. Executive Compensation 

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

Item 13. Certain Relationships and Related Transactions, and Director Independence 
Table of Contents 

PART IV 

Item 15. Exhibits and Financial Statement Schedules

 All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes 

thereto. 

(b) 3. Exhibits: 

42 

 

(a) 1. Index to Financial Statements: Page 

 

 

 Report of Independent Registered Public Accounting Firm S-1 

 

 Consolidated Balance Sheets at December 31, 2009 and 2008 S-2 

 

 Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008 and 2007 S-3 

 

 Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2009, 2008 and 2007 S-4 

 

 Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007 S-5 

 

 Notes to Consolidated Financial Statements S-7 

 

 2. Consolidated Financial Statement Schedules and Other: 

 

 Schedule II — Valuation and Qualifying Accounts S-40 

 

 Schedule III — Financial Statements and Notes for Petrodelta, S.A. S-41 

 3.1 Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1(i) to our Form 10-Q filed on 

August 13, 2002, File No. 1-10762.) 

 

 3.2 Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on May 23, 2007, File No. 1-

10762.) 

 

 4.1 Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.1 to our Form 10-K filed on March 17, 2008, File 

No. 1-10762.) 

 

 4.2 Certificate of Designation, Rights and Preferences of the Series B Preferred Stock of Benton Oil and Gas Company, filed May 12, 

1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.) 

 

 4.3 Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells 

Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A filed on October 23, 2007, File No. 1-10762.) 

 

 4.4 Indenture dated as of February 17, 2010, between Harvest Natural Resources, Inc. and U.S. Bank National Association, as trustee. 

(Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on February 18, 2010, File No. 1-10762.) 

 

 4.5 First Supplemental Indenture dated as of February 17, 2010 between Harvest Natural Resources, Inc. and U.S. Bank National 

Association, as trustee. (Incorporated by reference to Exhibit 4.2 to our Form 8-K filed on February 18, 2010, File No. 1-10762.) 
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43 

 4.6 Form of 8.25% Senior Convertible Notes due 2013. (Incorporated by reference to Exhibit 4.3 to our Form 8-K filed on 

February 18, 2010, File No. 1-10762.) 

 

 10.1 2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-8 filed 

on April 9, 2002 (Registration Statement No. 333-85900).) 

 

 10.2 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).) 

 

 10.3 †  Form of Indemnification Agreement between Harvest Natural Resources, Inc. and each Director and Executive Officer of the 

Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) 

 

 10.4 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.) 

 

 10.5 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.) 

 

 10.6 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.) 

 

 10.7 †  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.) 

 

 10.8 †  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.) 

 

 10.9 †  Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. 

(Incorporated by reference to Exhibit 10.24 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) 

 

 10.10 †  Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. 

(Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) 

 

 10.11 †  Stock Option Agreement dated September 26, 2005, between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated 

by reference to Exhibit 10.26 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) 

 

 10.12 Harvest Natural Resources 2006 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration 

Statement on Form S-8 filed on June 1, 2006 [Registration Statement No. 333-134630].) 

 

 10.13 Form of 2006 Long Term Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q 

filed on August 9, 2006, File No. 1-10762.) 

 

 10.14 Form of 2006 Long Term Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.3 to our 

Form 10-Q filed on August 9, 2006, File No. 1-10762.) 
Table of Contents 

44 

 10.15 Form of 2006 Long Term Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.4 to 

our Form 10-Q filed on August 9, 2006, File No. 1-10762.) 

 

 10.16 †  Stock Unit Award Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. 

(Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) 

 

 10.17 †  Stock Unit Award Agreement dated March 2, 2006 between Harvest Natural Resources, Inc. and James A. Edmiston. 

(Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) 

 

 10.18 Form of 2006 Long Term Incentive Plan Stock Option Agreement — Five Year Vesting, Seven Year Term. (Incorporated by 

reference to Exhibit 10.33 to our Form 10-K filed on March 13, 2007, File No. 1-10762.) 

 

 10.19 Amendment to Harvest Natural Resources 2006 Long Term Incentive Plan adopted July 19, 2006. (Incorporated by reference to 

Exhibit 10.1 to our Form 10-Q filed on May 3, 2007, File No. 1-10762.) 

 

 10.20 †  Employment Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by 

reference to Exhibit 10.1 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) 

 

 10.21 †  Stock Option Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by 

reference to Exhibit 10.2 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) 

 

 10.22 †  Employee Restricted Stock Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. 

(Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) 

 

 10.23 Contract for Conversion to a Mixed Company between Corporación Venezolana del Petróleo, S.A., Harvest-Vinccler, S.C.A. and 

HNR Finance B.V. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on November 1, 2007, File No. 1-10762.) 

 

 10.24 †  Employment Agreement dated April 14, 2008 between Harvest Natural Resources, Inc. and Patrick R. Oenbring. (Incorporated 

by reference to Exhibit 10.1 to our Form 10-Q filed on May 1, 2008, File No. 1-10762.) 

 

 10.25 †  Stock Option Agreement dated April 14, 2008 between Harvest Natural Resources, Inc. and Patrick R. Oenbring. (Incorporated 

by reference to Exhibit 10.2 to our Form 10-Q filed on May 1, 2008, File No. 1-10762.) 

 

 10.26 †  Employee Restricted Stock Agreement dated April 14, 2008 between Harvest Natural Resources, Inc. and Patrick R. Oenbring. 

(Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on May 1, 2008, File No. 1-10762.) 

 

 10.27 †  Employment Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and Stephen C. Haynes. (Incorporated by 

reference to Exhibit 10.1 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.) 

 

 10.28 †  Stock Option Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and Stephen C. Haynes. (Incorporated by 

reference to Exhibit 10.2 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.) 
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45 

 10.29 †  Employee Restricted Stock Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and Stephen C. Haynes. 

(Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.) 

 

 10.30 †  Employment Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and G. Michael Morgan. (Incorporated by 

reference to Exhibit 10.4 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.) 

 

 10.31 †  Stock Option Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and G. Michael Morgan. (Incorporated by 

reference to Exhibit 10.5 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.) 

 

 10.32 †  Employee Restricted Stock Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and G. Michael Morgan. 

(Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.) 

 

 10.33 Placement Agent Agreement dated February 10, 2010, by and among Harvest Natural Resources, Inc., as issuer, and Lazard 

Capital Markets LLC and Madison Williams and Company LLC, as placement agents, relating to the 8.25% Senior Convertible 

Notes due 2013. (Incorporated by reference to Exhibit 10.1 to our Form 8-K filed on February 11, 2010, File No. 1-10762.) 

 

 10.34 Form of Standard Subscription Agreement, to be entered into by and among Harvest Natural Resources, Inc. and certain 

purchasers signatory thereto. (Incorporated by reference to Exhibit 10.2 to our Form 8-K filed on February 11, 2010, File No. 1-

10762.) 

 

 10.35 Form of Subscription Agreement, to be entered into by and among Harvest Natural Resources, Inc. and certain purchasers 

signatory thereto. (Incorporated by reference to Exhibit 10.3 to our Form 8-K filed on February 11, 2010, File No. 1-10762.) 

 

 21.1 List of subsidiaries. 

 

 23.1 Consent of PricewaterhouseCoopers LLP. 

 

 23.2 Consent of Ryder Scott Company, LP. 

 

 23.3 Consent of HLB PGFA Perales, Pistone & Asociados — Caracas, Venezuela. 

 

 31.1 Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 executed by James A. Edmiston, President and Chief 

Executive Officer. 

 

 31.2 Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 executed by Stephen C. Haynes, Vice President, Chief 

Financial Officer and Treasurer. 

 

 32.1 Certification accompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. 

Section 1350 executed by James A. Edmiston, President and Chief Executive Officer. 

 

 32.2 Certification accompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. 

Section 1350 executed by Stephen C. Haynes, Vice President, Chief Financial Officer and Treasurer. 

 

 99.1 Reserve report dated February 26, 2009 between Harvest (US) Holdings, Inc. and Ryder Scott Company. 

 

 99.2 Reserve report dated February 26, 2009 between HNR Finance B.V. and Ryder Scott Company. 

 

† 

 

Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15(a) and 

(b) of Form 10-K. 
Table of Contents 

Report of Independent Registered Public Accounting Firm 

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

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, 2009 and December 31, 2008, and the results of their 

operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles 

generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing as 

Schedule II in 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. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial 

reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of 

Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and 

financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of 

internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under 

Item 9A. Our responsibility is to express opinions on these financial statements, the financial statement schedule and on the Company’s internal 

control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company 

Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about 

whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained 

in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and 

disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating 

the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal 

control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating 

effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered 

necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. 

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for noncontrolling 

interests effective January 1, 2009. As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it 

estimates the quantities of proved oil and natural gas reserves in 2009. 

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. 

S-1 

 

 

/s/ PricewaterhouseCoopers LLP 

Houston, Texas 

March 16, 2010 

 
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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

CONSOLIDATED BALANCE SHEETS 

See accompanying notes to consolidated financial statements. 

S-2 

 

 December 31, 

 2009 2008 

 (in thousands, except per share data) 

ASSETS 

CURRENT ASSETS: 

Cash and cash equivalents $ 32,317 $ 97,165 

Accounts and notes receivable, net 11,478 11,570 

Advances to equity affiliate 4,927 3,732 

Prepaid expenses and other 2,214 3,964 

   

TOTAL CURRENT ASSETS 50,936 116,431 

 

OTHER ASSETS 3,613 3,316 

INVESTMENT IN EQUITY AFFILIATES 233,989 218,982 

PROPERTY AND EQUIPMENT: 

Oil and gas properties (successful efforts method) 58,543 22,328 

Other administrative property 3,085 2,368 

 

 

 

 61,628 24,696 

Accumulated depreciation and amortization (1,387 ) (1,159 ) 

 

 

 

 60,241 23,537 

   

 $ 348,779 $ 362,266 

 

 

 

 

 

LIABILITIES AND EQUITY 

CURRENT LIABILITIES: 

Accounts payable, trade and other $ 696 $ 1,662 

Advance from equity affiliate — 20,750 

Accrued expenses 10,253 12,241 

Accrued interest 4,691 4,691 

Income taxes payable 1,090 77 

   

TOTAL CURRENT LIABILITIES 16,730 39,421 

 

ASSET RETIREMENT LIABILITY 50 — 

 

COMMITMENTS AND CONTINGENCIES — — 

 

EQUITY 

STOCKHOLDERS’ EQUITY: 

Preferred stock, par value $0.01 a share; authorized 5,000 shares; outstanding, none — — 

Common stock, par value $0.01 a share; authorized 80,000 shares at December 31, 2009 and 2008; 

issued 39,495 shares and 39,128 shares at December 31, 2009 and 2008, respectively 395 391 

Additional paid-in capital 213,337 208,868 

Retained earnings 126,244 129,351 

Treasury stock, at cost, 6,448 shares and 6,444 shares at December 31, 2009 and 2008, respectively (65,383 ) (65,368 ) 

   

TOTAL HARVEST STOCKHOLDERS’ EQUITY 274,593 273,242 

NONCONTROLLING INTEREST 57,406 49,603 

   

TOTAL EQUITY 331,999 322,845 

 

 

 

 $ 348,779 $ 362,266 

 

 

 

 

 
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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF OPERATIONS 

See accompanying notes to consolidated financial statements. 

S-3 

 

 Years Ended December 31, 

 2009 2008 2007 

 (in thousands, except per share data) 

Revenues 

Oil sales $ 160 $ — $ 11,217 * 

Gas sales 21 — — 

 

 

 

 

 181 — 11,217 

    

 

Expenses 

Depletion, depreciation and amortization 436 201 384 

Exploration expense 7,824 16,402 850 

Dry hole costs — 10,828 — 

General and administrative 21,854 27,215 29,096 

Taxes other than on income 1,026 (206 ) 423 

 

 

 

 

 31,140 54,440 30,753 

    

 

Loss from Operations (30,959 ) (54,440 ) (19,536 ) 

Other Non-Operating Income (Expense) 

Gain on Financing Transactions — 3,421 49,623 

Investment earnings and other 1,085 3,663 9,051 

Interest expense (5 ) (1,730 ) (8,224 ) 

    

 1,080 5,354 50,450 

 

 

 

 

 

Income (Loss) from Consolidated Companies Before Income Taxes (29,879 ) (49,086 ) 30,914 

Income Tax Expense 1,182 25 6,312 

 

 

 

 

Income (Loss) from Consolidated Companies (31,061 ) (49,111 ) 24,602 

Net Income from Unconsolidated Equity Affiliates 35,757 34,576 55,297 

    

Net Income (Loss) 4,696 (14,535 ) 79,899 

 

Less: Net Income Attributable to Noncontrolling Interest 7,803 6,929 19,781 

    

 

Net Income (Loss) Attributable to Harvest $ (3,107 ) $ (21,464 ) $ 60,118 

 

 

 

 

 

 

 

 

Net Income (Loss) Attributable to Harvest Per Common Share: 

Basic $ (0.09 ) $ (0.63 ) $ 1.65 

 

 

 

 

 

 

 

Diluted $ (0.09 ) $ (0.63 ) $ 1.59 

 

 

 

 

 

 

 

 

* Recognition of deferred revenue in 2007 – See Note 1 – Organization and Summary of Significant Accounting Policies – Revenue 

Recognition. 
Table of Contents 

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 

(in thousands) 

See accompanying notes to consolidated financial statements. 

S-4 

 

 Common Additional Non- 

 Shares Common Paid-in Retained Treasury Controlling Total 

 Issued Stock Capital Earnings Stock Interest Equity 

Balance at January 1, 2007 37,974 $ 380 $ 194,176 $ 90,697 $ (3,844 ) $ 37,765 $ 319,174 

 

Issuance of common shares: 

Exercise of stock options 402 4 1,934 — — — 1,938 

Employee stock-based 

compensation 137 1 5,828 — — — 5,829 

Purchase of Treasury Shares — — — — (32,647 ) — (32,647 ) 

Net Income — — — 60,118 — 19,781 79,899 

        

 

Balance at December 31, 2007 38,513 385 201,938 150,815 (36,491 ) 57,546 374,193 

 

Issuance of common shares: 

Exercise of stock options 547 5 1,560 — — — 1,565 

Employee stock-based 

compensation 68 1 5,370 — — — 5,371 

Purchase of Treasury Shares — — — — (28,877 ) — (28,877 ) 

Distribution to noncontrolling 

Interests — — — — — (14,872 ) (14,872 ) 

Net Income (Loss) — — — (21,464 ) — 6,929 (14,535 ) 

 

 

  

 

 

 

 

 

Balance at December 31, 2008 39,128 391 208,868 129,351 (65,368 ) 49,603 322,845 

 

Issuance of common shares: 

Exercise of stock options 205 2 384 — — — 386 

Employee stock-based 

compensation 162 2 4,085 — — — 4,087 

Purchase of Treasury Shares — — — — (15 ) — (15 ) 

Net Income (Loss) — — — (3,107 ) — 7,803 4,696 

        

 

Balance at December 31, 2009 39,495 $ 395 $ 213,337 $ 126,244 $ (65,383 ) $ 57,406 $ 331,999 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF CASH FLOWS 

(in thousands) 

See accompanying notes to consolidated financial statements. 

S-5 

 

 Years Ended December 31, 

 2009 2008 2007 

 (in thousands) 

Cash Flows From Operating Activities: 

Net income (loss) $ 4,696 $ (14,535 ) $ 79,899 

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating 

activities: 

Depletion, depreciation and amortization 436 201 384 

Dry hole costs — 10,828 — 

Gain on financing transactions — (3,421 ) (49,623 ) 

Net income from unconsolidated equity affiliates (35,757 ) (34,576 ) (55,297 ) 

Non-cash compensation related charges 4,087 6,061 6,108 

Deferred income taxes — — 5,608 

Dividend received from equity affiliate — 72,530 — 

Changes in operating assets and liabilities: 

Accounts and notes receivable 92 548 393 

Advances to equity affiliate (1,195 ) 12,620 2,794 

Prepaid expenses and other (1,055 ) (5,632 ) 214 

Accounts payable (966 ) (2,957 ) 2,122 

Accounts payable, related party — (10,093 ) 456 

Advance from equity affiliate — 20,750 — 

Accrued expenses (6,296 ) (1,073 ) (1,251 ) 

Accrued interest — (445 ) (1,714 ) 

Deferred revenue — — (11,217 ) 

Income taxes payable 1,013 (426 ) 469 

    

Net Cash Provided By (Used In) Operating Activities (34,945 ) 50,380 (20,655 ) 

    

Cash Flows from Investing Activities: 

Additions of property and equipment (28,022 ) (26,317 ) (647 ) 

Investments in equity affiliates — (2,161 ) (7,388 ) 

(Increase) decrease in restricted cash — 6,769 82,120 

Investment costs (581 ) (1,346 ) (4,125 ) 

    

Net Cash Provided By (Used In) Investing Activities (28,603 ) (23,055 ) 69,960 

 

 

  

Cash Flows from Financing Activities: 

Net proceeds from issuances of common stock 386 1,565 1,938 

Purchase of treasury stock — (29,416 ) (32,755 ) 

Financing costs (1,686 ) (1,075 ) — 

Payments of note payable — (7,211 ) (45,726 ) 

Dividend paid to minority interest — (14,864 ) — 

 

 

  

Net Cash Used In Financing Activities (1,300 ) (51,001 ) (76,543 ) 

 

 

  

Net Decrease in Cash and Cash Equivalents (64,848 ) (23,676 ) (27,238 ) 

Cash and Cash Equivalents at Beginning of Year 97,165 120,841 148,079 

    

Cash and Cash Equivalents at End of Year $ 32,317 $ 97,165 $ 120,841 

 

 

 

 

 

 

 

Supplemental Disclosures of Cash Flow Information: 

Cash paid during the year for interest expense $ 5 $ 768 $ 7,972 

 

 

 

 

 

 

 

Cash paid during the year for income taxes $ 169 $ 456 $ 201 

 

 

 

 

 

 

 
Table of Contents 

Supplemental Schedule of Noncash Investing and Financing Activities: 

 During the year ended December 31, 2009, we issued 0.2 million shares of restricted stock valued at $0.7 million. Also, some of our 

employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 3,757 shares being added to treasury 

stock at cost. 

 During the year ended December 31, 2008, we issued 0.2 million of restricted stock valued at $2.0 million; most of our employees elected to 

pay withholding tax on restricted stock grants on a cashless basis which resulted in 14,457 shares being added to treasury at cost; and 106,000 

shares held in treasury were reissued as restricted stock. 

 During the year ended December 31, 2007, we issued 0.3 million shares of restricted stock valued at $2.6 million; most of our employees 

elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 16,042 shares being added to treasury stock at cost; 

and 20,000 shares held in treasury were reissued as restricted stock. 

See accompanying notes to consolidated financial statements. 

S-6 
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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

Notes to Consolidated Financial Statements 

Note 1 — Organization and Summary of Significant Accounting Policies 

 Harvest Natural Resources, Inc. (“Harvest”) is an independent energy company engaged in the acquisition, exploration, development, 

production and disposition of oil and natural gas properties since 1989, when it was incorporated under Delaware law. We have significant 

interests in the Bolivarian Republic of Venezuela (“Venezuela”) through our ownership in Petrodelta, S.A. (“Petrodelta”). HNR Finance B.V. 

(“HNR Finance”) has a 40 percent ownership interest in Petrodelta. As we indirectly own 80 percent of HNR Finance, we indirectly own a net 

32 percent interest in Petrodelta, and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of 

Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining eight percent equity interest. Corporación 

Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petrodelta is governed by its own charter and bylaws. We 

have exploration acreage in the Gulf Coast Region of the United States, the Antelope prospect in the Western United States, mainly onshore in 

West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in the Sultanate of Oman 

(“Oman”), and offshore of the People’s Republic of China (“China”). We also have production from the Monument Butte project in the Antelope 

prospect. See Note 8 – United States, Note 9 – Indonesia , Note 10 – Gabon, Note 11 – Oman and Note 12 – China . 

Principles of Consolidation 

 The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. All intercompany profits, 

transactions and balances have been eliminated. 

Investment in Equity Affiliates 

 Investments in unconsolidated companies in which we have less than a 50 percent interest and have significant influence are accounted for 

under the equity method of accounting. Investment in Equity Affiliates is increased by additional investments and earnings and decreased by 

dividends and losses. We review our Investment in Equity Affiliates for impairment whenever events and circumstances indicate a decline in the 

recoverability of its carrying value. 

Reporting and Functional Currency 

 The United States Dollar (“U.S. Dollar”) is our reporting and functional currency. Amounts denominated in non-U.S. Dollar currencies are 

re-measured in U.S. Dollars, and all currency gains or losses are recorded in the consolidated statement of operations. We attempt to manage our 

operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange 

rates and resulting exchange gains and losses, many of which are beyond our influence. 

 The U.S. Dollar is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. 

Revenue Recognition 

 Until March 31, 2006, each quarter, Harvest Vinccler, S.C.A. (“Harvest Vinccler”) invoiced Petroleos de Venezuela S.A. (“PDVSA”), based 

on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. Dollar contract service fees per barrel. With the formation 

of Petrodelta in 2007, Harvest Vinccler recognized deferred revenue of $11.2 million for 2005 and first quarter 2006 deliveries that had been 

deferred pending clarification on the calculation of crude prices under a transitory agreement signed in August 2005 between Harvest Vinccler 

and PDVSA. 

S-7 
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 We record revenue for our U.S. oil and natural gas operations when we deliver our production to the customer and collectability is reasonably 

assured. Revenues from the production of oil and natural gas on properties in which we have joint ownership are recorded under the sales 

method. Differences between these sales and our entitled share of production are not significant. 

Cash and Cash Equivalents 

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

Fair Value Measurements 

 We adopted the accounting standard for fair value measurements for financial assets as of January 1, 2008 and for non-financial assets and 

liabilities as of January 1, 2009. This standard provides guidance for using fair value to measure assets and liabilities. This standard also clarifies 

the principle that fair value should be based on the assumptions that market participants would use when pricing the asset or liability and 

establishes a fair value hierarchy, giving the highest priority to quoted prices in active markets and the lowest priority to unobservable data. The 

standard applies whenever other standards require assets or liabilities to be measured at fair value. The adoption of this standard had no impact 

on our consolidated financial position, results of operations or cash flows. 

 At December 31, 2009 and 2008, cash and cash equivalents include $26.8 million and $88.6 million, respectively, in a money market fund 

comprised of high quality, short term investments with minimal credit risk which are reported at fair value. The fair value measurement of these 

securities is based on quoted prices in active markets for identical assets which are defined as “Level 1” of the fair value hierarchy based on the 

criteria in the accounting standard for fair value measurements. 

Credit Risk and Operations 

 All of our total consolidated revenues in 2007 related to operations in Venezuela. Petrodelta’s sole source of revenues for its production is 

PDVSA Petroleo S.A. (“PPSA”), a 100 percent owned subsidiary of PDVSA, which maintains full ownership of all hydrocarbons in its fields. 

The sale of oil and natural gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with 

PPSA which was signed on January 17, 2008. 

Accounts and Notes Receivable 

 Notes receivable relate to prospect leasing cost financing arrangements, bear interest and can have due dates that are less than one year or 

more than one year. Amounts outstanding under the notes bear interest at a rate based on the current prime rate and are recorded at face value. 

Interest is recognized over the life of the note. We may or may not require collateral for the notes. 

 Each note is analyzed to determine if it is impaired pursuant to the accounting standard for accounting by creditors for impairment of a loan. 

A note is impaired if it is probable that we will not collect all principal and interest contractually due. We do not accrue interest when a note is 

considered impaired. All cash receipts on impaired notes are applied to reduce the accrued interest on the note until the interest is made current 

and, thereafter, applied to reduce the principal amount of such notes. 

 During the year ended December 31, 2008, we reclassified $2.7 million of prepaid land costs for the Antelope project to notes receivable. The 

note is due in less than one year and bears interest at a rate of 12 percent and is secured by a revenue interest in a well currently being evaluated. 

At December 31, 2009, notes receivable plus accrued interest was approximately $3.3 million. 

Other Assets 

 Other assets consist of investigative costs associated with new business development projects. These costs are reclassified to oil and natural 

gas properties or expensed depending on management’s assessment of the likely outcome 

S-8 
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of the project. During the year ended December 31, 2009, $1.4 million was reclassified to oil and gas properties and $1.7 million was reclassified 

to exploration expense. During the year ended December 31, 2008, $3.8 million was reclassified to oil and gas properties and $1.2 million was 

reclassified to exploration expense. 

Property and Equipment 

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

 Properties and equipment are stated at cost less accumulated depletion, depreciation and amortization (“DD&A”). Costs of improvements that 

appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are 

expensed as incurred. Upon retirement or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if 

appropriate, gains or losses are recognized in investment earnings and other. 

 We follow the successful efforts method of accounting for our oil and gas properties. Under this method, exploration costs such as 

exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling 

exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If 

management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory 

wells are charged to exploration expense. During the year ended December 31, 2008, we charged to exploration expense $10.8 million of 

exploratory well costs associated with the Harvest Hunter #1. Costs of drilling successful exploratory wells, all development wells, and related 

production equipment and facilities are capitalized and depleted or depreciated using the unit-of-production method as oil and gas is produced. 

Depletion expense, which was all attributable to the Monument Butte project, for the year ended December 31, 2009, was $0.03 million ($6.59 

per equivalent barrel). 

 Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding 

period and transferred to proved oil and gas properties to the extent associated with successful exploration activities. Costs of maintaining and 

retaining undeveloped leaseholds, as well as amortization and impairment of unsuccessful leases, are included in exploration expense. Costs of 

expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. 

 Proved oil and gas properties are reviewed for impairment at a level for which identifiable cash flows are independent of cash flows of other 

assets when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows 

are determined based on estimated future oil and gas sales revenues less future expenditures necessary to develop and produce the reserves. If the 

sum of these undiscounted estimated future net cash flows is less than the carrying amount of the property, an impairment loss is recognized for 

the excess, if any, of the property’s carrying amount over its estimated fair value, which is generally based on discounted future net cash flows. 

No impairment of proved oil and gas properties was required in 2009. 

 Costs of drilling and equipping successful exploratory wells, development wells, asset retirement liabilities and costs to construct or acquire 

offshore platforms and other facilities, are depreciated using the unit-of-production method based on total estimated proved developed reserves. 

Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved leaseholds, are depleted using the unit-ofproduction method 

S-9 

 

 2009 2008 

Proved property costs $ 1,646 $ — 

Unproved property costs 54,111 20,960 

Oilfield inventories 2,786 1,368 

Furniture and fixtures 3,085 2,368 

   

 61,628 24,696 

Accumulated depletion, impairment and depreciation (1,387 ) (1,159 ) 

   

 $ 60,241 $ 23,537 

 

 

 

 

 
Table of Contents 

based on total estimated proved reserves. All other properties are stated at historical acquisition cost, net of allowance for impairment, and 

depreciated using the straight-line method over the useful lives of the assets. 

 Undeveloped property costs, including oilfield inventories, consist of $3.1 million for West Bay, $36.4 million for Mesaverde, $2.0 million 

for the Budong-Budong production sharing contract (“Budong PSC”), $6.9 million for the Dussafu Marin exploration production sharing 

contract (“Dussafu PSC”), $3.8 million for the Oman exploration and production sharing agreement (“Block 64 EPSA”), $3.0 million for WAB21, and $1.7 million for other projects. 

 Depreciation of furniture and fixtures is computed using the straight-line method with depreciation rates based upon the estimated useful life 

of the property, generally 5 years. Leasehold improvements are depreciated over the life of the applicable lease. Depreciation expense was 

$0.4 million, $0.2 million and $0.4 million for the years ended December 31, 2009, 2008 and 2007, respectively. 

Reserves 

 In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve 

information. In January 2010, the Financial Accounting Standards Board (“FASB”) issued its authoritative guidance on extractive activities for 

oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our yearend reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Such a change is accounted for 

prospectively under the authoritative accounting guidance. Comparative disclosures applying the new for periods before the adoption of the 

FASB’s final rule are not required. 

 The adoption of the FASB’s final rule on December 31, 2009 impacted our financial statements and other disclosures in our Annual Report 

on Form 10-K for the year ended December 31, 2009, as follows: 

 The impact of the adoption of the FASB’s final rule on our financial statements is not practicable to estimate due to the operational and 

technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules. 

 The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, 

which include verification of data provided for, management reviews and review of the independent third party reserves report. The technical 

employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Arts in Engineering Science, a 

Master of Science in Petroleum Engineering, has more than 25 years of experience in reservoir engineering and is a member of the Society of 

Petroleum Engineers. 

 All reserve information in this report is based on estimates prepared by Ryder Scott Company L.P. (“Ryder Scott”), independent petroleum 

engineers. The technical personnel responsible for preparing the reserve estimates at Ryder Scott meet the requirements regarding qualifications, 

independence, objectivity and confidentiality set 

S-10 

 • All oil and gas reserves volumes presented as of and for the year ended December 31, 2009 were prepared using the updated reserves 

rules and are not on a basis comparable with prior periods. The change in comparability occurred because the FASB’s final rule requires 

the use of the unweighted 12-month average of the first-day-of-the-month reference price for the prior twelve month period and permits 

the use of reliable technologies to support reserve estimates. Under the previous reserve estimation rules, which are no longer in effect, 

our reserves would have been calculated using end of period prices. 

 • The impairment review of our proved oil and gas properties used undiscounted estimated future net cash flows models for our estimated 

proved developed reserves which were calculated using the FASB’s final rule. 

 • We historically have applied a policy of using our year-end proved reserves to calculate our fourth quarter depletion rate. As a result, the 

estimate of proved reserves for determining our deletion rate and resulting expense for the fourth quarter of 2009 is not on a basis 

comparable to the prior quarters of prior years. 
Table of Contents 

forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum 

Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest 

in our properties and are not employed on a contingent fee basis. 

Asset Retirement Liability 

 The accounting for asset retirement obligations standard requires entities to record the fair value of a liability for a legal obligation to retire an 

asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. No wells were abandoned in the year 

ended December 31, 2009. Changes in asset retirement obligations during the year ended December 31, 2009 were as follows (in thousands): 

Income Taxes 

 Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to 

events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit 

carryforwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax 

asset will not be realized. With the formation of Petrodelta, Harvest Vinccler recognized the deferred tax related to the deferred revenue 

discussed above. 

Financial Instruments 

 Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents 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. 

Noncontrolling Interests 

 We adopted the accounting standard for noncontrolling interests in consolidated financial statements as of January 1, 2009. This standard 

establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of 

consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of 

retained noncontrolling equity investments when a subsidiary is deconsolidated. This standard also establishes reporting requirements that 

provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owner. 

The retrospective adoption of this standard impacted the presentation of our consolidated financial position, results of operations and cash flows. 

New Accounting Pronouncements 

 In June 2009, the Financial Accounting Standards Board (“FASB”) issued an accounting standard for subsequent events which establishes 

general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. 

This standard is effective for interim or annual periods ending after June 15, 2009. We adopted this standard effective June 15, 2009. The 

adoption of this standard did not have an effect on our consolidated financial position, results of operations or cash flows. 

S-11 

 

 December 31, 

 2009 

Asset retirement obligations beginning of period $ — 

Liabilities recorded during the period 50 

Liabilities settled during the period — 

Revisions in estimated cash flows — 

Accretion expense — 

  

Asset retirement obligations end of period $ 50 

 

 

 
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 In June 2009, the FASB issued an accounting standard for accounting for transfers of financial assets. The objective in issuing this standard is 

to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial 

statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a 

transferor’s continuing involvement, if any, in transferred financial assets. This standard is effective for annual periods beginning after 

November 15, 2009. The adoption of this standard did not have a material impact on our consolidated financial position, results of operations or 

cash flows. 

 In June 2009, the FASB issued an amendment to the financial interpretation to improve financial reporting by enterprises involved with 

variable interest entities. This amendment is effective for annual periods beginning after November 15, 2009. This amendment did not have a 

material impact on our consolidated financial position, results of operations or cash flows. 

 In June 2009, the FASB issued an accounting standard that codifies and modifies the hierarchy of generally accepted accounting principles. 

This standard is the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive 

releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative GAAP 

for SEC registrants. This standard superseded all then-existing non-SEC accounting and reporting standards. All other nongrandfathered nonSEC accounting literature not included in this standard is now nonauthoritative. This standard is effective for financial statements issued for 

interim and annual periods ending after September 15, 2009. The adoption of this standard did not have an impact on our consolidated financial 

position, results of operations or cash flows. 

 In December 2009, the FASB issued its final updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure 

requirements of Extractive Industries – Oil and Gas (Topic 932) with the requirements in the SEC’s final rule, Modernization of the Oil and Gas 

Reporting Requirements, which was issued on December 31, 2008 and is effective for the year ended December 31, 2009. We have complied 

with the disclosure requirements in our Annual Report on Form 10-K for the year ended December 31, 2009. 

Use of Estimates 

 The preparation of financial statements in conformity with GAAP 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 and natural gas reserve 

volumes and future development costs. Actual results could differ from those estimates. 

Reclassifications 

 Certain items in 2008 have been reclassified to conform to the 2009 financial statement presentation. 

Note 2 — Long-Term Debt and Liquidity 

 In November 2006, Harvest Vinccler entered into a three-year term loan with a Venezuelan bank to pay the SENIAT, the Venezuelan income 

tax authority, income tax assessments and related interest, refinance a portion of a 105 million Venezuela Bolivar (“Bolivar”) loan and to fund 

operating requirements. The loan was collateralized by a $6.8 million deposit plus interest in a U.S. bank. On July 9, 2008, the loan was repaid in 

full and the cash collateral returned to us. We have no other debt obligations. 

 We have incurred $2.8 million in costs related to ongoing negotiations for a future financing. If successful, these costs will be amortized over 

the life of the financial instrument. 

 Liquidity — Based on our cash balance of $32.3 million at December 31, 2009, we will be required to raise additional funds in order to fund 

our future operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration projects 

and to a lesser extent general and administrative costs. Currently, our primary source of cash is dividends from Petrodelta. However, there is no 

certainty that 

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Petrodelta will pay dividends in 2010 or 2011. Our lack of cash flow and the unpredictability of cash dividends from Petrodelta could make it 

difficult to obtain financing, and accordingly, there is no assurance adequate financing can be raised. We continue to pursue, as appropriate, 

additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, exploration of our 

properties worldwide, and cost reductions. In addition, we could delay discretionary capital spending to future periods or sell assets as necessary 

to maintain the liquidity required to run our operations, if necessary. There can be no assurances that any of these possible efforts will be 

successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected. 

Note 3 — Commitments and Contingencies 

 We have employment contracts with seven 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, outplacement services 

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 or after May 31, 2010. 

 In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month. In December 2008, we 

signed a five-year lease for additional office space in Houston, Texas, for approximately $15,000 per month. In November 2008, Harvest 

Vinccler extended its lease for office space in Caracas, Venezuela for two years for approximately $10,000 per month. In August 2008, we 

signed a two-year lease in Roosevelt, Utah for approximately $6,000 per month. In October 2008, we signed a two-year lease for office space in 

Singapore for approximately $19,000 per month. In April 2009, we signed a two-year lease for office space in Indonesia for approximately 

$5,000 per month. In September 2009, we signed a two-year lease for office space in Oman for approximately $5,000 per month. In November 

2009, we signed a one-year lease for office space in London for approximately $24,000 per month. We do not have any long-term contractual 

commitments for any of our projects. 

 Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-Vinccler, 

C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, Texas . This suit was brought in May 2003 by Excel alleging, 

among other things, breach of a consulting agreement between Excel and us, misappropriation of proprietary information and trade secrets, and 

fraud. Excel seeks actual and exemplary damages, injunctive relief and attorneys’ fees. In April 2007, the court set the case for trial. The trial 

date, reset for the first quarter of 2009, had been stayed indefinitely. On October 20, 2009, the stay was lifted. A trial date of November 1, 2010 

has been set. We dispute Excel’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any 

possible loss. 

 Uracoa Municipality Tax Assessments . Our Venezuelan subsidiary, Harvest Vinccler, has received nine assessments from a tax inspector for 

the Uracoa municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows: 

S-13 

 • Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the 

capital fee reimbursement and related interest paid by PDVSA under the Operating Service Agreement (“OSA”). Harvest Vinccler has 

filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the 

municipality the remaining claims. 

 • Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a 

protest with the Tax Court in Barcelona, Venezuela, on these claims. 

 • Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a 

withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, 

Venezuela, on one claim and filed a protest with the municipality on the other claim. 
Table of Contents 

Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is unable to 

estimate the amount or range of any possible loss. As a result of the SENIAT’s, the Venezuelan income tax authority, interpretation of the tax 

code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa Municipality 

for the refund of all municipal taxes paid since 1997. 

 Libertador Municipality Tax Assessments . Harvest Vinccler has received five assessments from a tax inspector for the Libertador 

municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows: 

Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest 

Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to 

operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the refund of 

all municipal taxes paid since 2002. 

 In June 2007, the SENIAT issued an assessment for taxes in the amount of $0.4 million for Harvest Vinccler’s failure to withhold VAT from 

vendors during 2005. Also, the SENIAT imposed penalties and interest in the amount of $1.3 million for Harvest Vinccler’s failure to withhold 

VAT. In July 2008, the SENIAT adjusted the assessment for penalties and interest to the change in tax units as mandated by the Venezuelan tax 

code and issued a new assessment for $2.3 million. The change in assessment resulted in an additional $1.0 million expense recorded in the year 

ended December 31, 2008. In August 2008, Harvest Vinccler filed an appeal in the tax courts and presented a proposed settlement with the 

SENIAT. In October 2008, after consideration of our proposed settlement, the SENIAT offered a counter-proposal which Harvest Vinccler 

accepted. Throughout 2009, the General Attorney Office and Harvest-Vinccler agreed several times to resuspend the case while the Finance 

Minister and the SENIAT confirmed their acceptance to the proposed settlement. On December 30, 2009, Harvest Vinccler settled the case for 

3.1 million Bolivars (approximately $1.4 million) for penalties and interest and closed the case with the SENIAT’s concurrence. As a result of 

the settlement, in December 2009, Harvest Vinccler reversed $0.9 million of accrued penalties and interest previously accrued based on notices 

received from the SENIAT. 

 We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such 

litigation which will have a material adverse impact on our financial condition, results of operations and cash flows. 

S-14 

 • Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. 

Harvest Vinccler has filed a protest with the municipality on these claims. 

 • One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a 

protest with the Mayor’s Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. On April 10, 

2008, the Tax Court suspended the case pending a response from the Mayor’s Office to the protest. If the municipality’s response is to 

confirm the assessment, Harvest Vinccler will defer to the competent Tax Court to enjoin and dismiss the claim. 

 • Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by 

PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. 

Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims. 

 • Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed 

a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims. 
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Note 4 — Taxes 

Taxes Other Than on Income 

 The components of taxes other than on income were (in thousands): 

 During the year ended December 31, 2008, we reversed a $1.1 million franchise tax provision that is no longer required. 

Taxes on Income 

 The tax effects of significant items comprising our net deferred income taxes as of December 31, 2009, are as follows (in thousands): 

 We currently have undistributed earnings from foreign affiliates of $5.9 million at our Netherlands Antilles subsidiary, HNR Energia B.V. 

The full amount would be subject to United States income tax if distributed to us. 

 The valuation allowance increased by $9.2 million as a result of additional net operating losses and tax benefits that we do not expect to fully 

realize through future taxable income. Realization of deferred tax assets associated with net operating loss carryforwards is dependent upon 

generating sufficient taxable income prior to their expiration. Management anticipates that additional losses will be generated and that it is more 

likely than not that they will not be realized through future taxable income. Management further anticipates that any unremitted foreign earnings 

will be reinvested outside of the U.S. 

 The components of income before income taxes are as follows (in thousands): 

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 2009 2008 2007 

Franchise taxes $ 182 $ (951 ) $ 166 

Severance taxes 11 — — 

Payroll and other taxes 833 745 257 

    

 $ 1,026 $ (206 ) $ 423 

 

 

 

 

 

 

 

 

 2009 2008 

Deferred tax assets: 

Operating loss carryforwards $ 15,599 $ 7,547 

Dry hole costs — 4,060 

Stock options 1,426 1,680 

Valuation allowance (17,025 ) (7,841 ) 

   

Net deferred tax asset — 5,446 

 

Deferred tax liability: 

Tax on undistributed earnings — (5,446 ) 

   

Net deferred tax asset (liability) $ — $ — 

 

 

 

 

 

 

 2009 2008 2007 

Income (loss) before income taxes 

United States $ (22,357 ) $ (34,760 ) $ (17,786 ) 

Foreign (7,522 ) (14,326 ) 48,700 

    

Total $ (29,879 ) $ (49,086 ) $ 30,914 

 

 

 

 

 

 

 
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 The provision (benefit) for income taxes consisted of the following at December 31, (in thousands): 

 A comparison of the income tax expense (benefit) at the federal statutory rate to our provision for income taxes is as follows (in thousands): 

 Rate differentials for foreign income result from tax rates different from the U.S. tax rate being applied in foreign jurisdictions. 

 At December 31, 2009, we had, for federal income tax purposes, operating loss carryforwards of approximately $44.4 million, expiring in the 

years 2026 through 2029. 

Accounting for Uncertainty in Income Taxes 

 Effective January 1, 2007, we adopted the interpretation for accounting for uncertainty in income taxes which was an interpretation of the 

accounting standard accounting for income taxes. This interpretation created a single model to address accounting for uncertainty in tax 

positions. This interpretation clarifies the accounting for income taxes, by prescribing a minimum recognition threshold a tax position is required 

to meet before being recognized in the financial statements. 

 We or one of our subsidiaries files income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions. With few 

exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years prior to 

2006. To date, the Internal Revenue Service (“IRS”) has not performed an examination of our U.S. income tax returns for 2006 through 2008. 

 We do not have any unrecognized tax benefits or loss contingencies. 

Note 5 — Stock Option and Stock Purchase Plans 

 In May 2006, our shareholders approved the 2006 Long Term Incentive Plan (the “2006 Plan”). The 2006 Plan provides for the issuance of 

up to 1,825,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to 

eligible participants including employees, non-employee directors and consultants of our company or subsidiaries. Under the 2006 Plan, no more 

than 325,000 shares may be granted as restricted stock. No individual may be granted more than 900,000 options or SARs and no more than 

175,000 shares of restricted stock during any period of three consecutive calendar years. The exercise price of stock options granted under the 

2006 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted through December 31, 2006 

vest ratably over a three to five year period 

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 2009 2008 2007 

Current: 

United States $ 39 $ (128 ) $ 400 

Foreign 1,143 153 5,912 

    

 1,182 25 6,312 

Deferred: 

Foreign — — — 

    

 $ 1,182 $ 25 $ 6,312 

 

 

 

 

 

 

 

 

 2009 2008 2007 

Computed tax expense (benefit) at the statutory rate $ (10,458 ) $ (17,180 ) $ 10,820 

Effect of foreign source income and rate differentials on foreign income 3,775 5,167 (11,140 ) 

Change in valuation allowance 9,184 6,059 1,085 

Tax on undistributed earnings — 5,446 — 

Deemed income inclusion under Subpart F — 968 12,942 

Net operating loss utilization — — (7,306 ) 

Foreign disregarded entities 21 (268 ) — 

Return to accrual adjustment (1,093 ) (166 ) — 

Other (247 ) (1 ) (89 ) 

 

 

 

 

Total income tax expense $ 1,182 $ 25 $ 6,312 

 

 

 

 

 

 

 
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from their dates of grant and expire seven to ten years from grant date. Restricted stock granted to employees or consultants to date is subject to a 

restriction period of not less than 36 months during which the stock will be deposited with Harvest and is subject to forfeiture under certain 

circumstances. Restricted stock granted to non-employee directors vests as to one-third of the shares on each anniversary of the date of grant of 

the award provided that he is still a director on that date. The 2006 Plan also permits the granting of performance awards to eligible employees 

and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an 

established period of time of at least one year. No employee or consultant shall be granted a performance award during a calendar year that could 

result in a cash payment of more than $5.0 million. In the event of a change in control, any restrictions on restricted stock will lapse, the 

indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest 

and become exercisable. 

 In May 2004, our shareholders approved the 2004 Long Term Incentive Plan (the “2004 Plan”). The 2004 Plan provides for the issuance of 

up to 1,750,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to 

eligible participants including employees, non-employee directors and consultants of our company or subsidiaries. Under the 2004 Plan, no more 

than 438,000 shares may be granted as restricted stock, and no individual may be granted more than 110,000 shares of restricted stock or 

438,000 in options over the life of the Plan. The exercise price of stock options granted under the 2004 Plan must be no less than the fair market 

value of our common stock on the date of grant. All options granted to date vest ratably over a three-year period from their dates of grant and 

expire ten years from grant date. Restricted stock granted to employees or consultants to date is subject to a restriction period of not less than 

36 months during which the stock will be deposited with Harvest and is subject to forfeiture under certain circumstances. Restricted stock 

granted to non-employee directors vests as to one-third of the shares on each anniversary of the date of grant of the award provided that he is still 

a director on that date (as amended). The 2004 Plan also permits the granting of performance awards to eligible employees and consultants. 

Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time 

of at least one year. Performance awards granted under the Plan may not exceed $5.0 million in a calendar year and may not exceed $2.5 million 

to any one individual in a calendar year. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of 

performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become 

exercisable. 

 In July 2001, our shareholders approved the 2001 Long Term Stock Incentive Plan (the “2001 Plan”). The 2001 Plan provides for grants of 

options to purchase up to 1,697,000 shares of our common stock in the form of Incentive Stock Options and Non-Qualified Stock Options to 

eligible participants including employees of our company or subsidiaries, directors, consultants and other key persons. The exercise price of 

stock options granted under the 2001 Plan must be no less than the fair market value of our common stock on the date of grant. No officer may 

be granted more than 500,000 options during any one fiscal year, as adjusted for any 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 Plan, no options 

may be granted under any of these plans. 

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Table of Contents 

 A summary of the status of our stock option plans as of December 31, 2009, 2008 and 2007 and changes during the years ending on those 

dates is presented below (shares in thousands): 

 Significant option groups outstanding at December 31, 2009 and related weighted average price and life information follow (shares in 

thousands): 

 The aggregate intrinsic value in the preceding table represents the total pretax intrinsic value based on our closing stock price of $5.29 of 

December 31, 2009, which would have been received by the option holders had all option holders exercised their options as of that date. 

 The value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weightedaverage assumptions: 

 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 highly subjective assumptions, including the expected 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 expected to be outstanding. The risk-free rate for the periods within the 

contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. 

 A summary of our nonvested options as of December 31, 2009, and changes during the year ended December 31, 2009, is presented below 

(shares in thousands): 

S-18 

 

 2009 2008 2007 

 Weighted Weighted Weighted 

 Average Average Average 

 Exercise Exercise Exercise 

 Price Shares Price Shares Price Shares 

Outstanding at beginning of the year: $ 8.54 3,783 $ 7.80 4,172 $ 7.70 4,123 

Options granted 4.60 118 10.28 444 9.63 866 

Options exercised (2.11 ) (205 ) (2.86 ) (548 ) (4.73 ) (397 ) 

Options cancelled (2.95 ) (333 ) (11.34 ) (285 ) (13.49 ) (420 ) 

    

Outstanding at end of the year 9.35 3,363 8.54 3,783 7.80 4,172 

 

 

 

 

 

 

 

Exercisable at end of the year 9.09 2,066 7.23 2,147 5.87 2,372 

 

 

 

 

 

 

 

 

 Outstanding Exercisable 

 Weighted- 

 Average Weighted WeightedRange of Number Remaining Average Aggregate Number Average Aggregate 

Exercise Outstanding Contractual Exercise Intrinsic Exercisable Exercise Intrinsic 

Prices at 12/31/09 Life Price Value at 12/31/09 Price Value 

$1.55 - $2.07 336 0.6 $ 1.71 $ 1,205 336 $ 1.71 $ 1,205 

$4.60 - $7.10 274 4.2 5.31 107 156 5.86 25 

$8.78 - $10.91 2,167 5.0 10.02 — 1,001 9.75 — 

$12.25 - $13.90 586 3.6 13.13 — 573 13.15 — 

     

 3,363 $ 1,312 2,066 $ 1,230 

 

 

 

 

 

 

 

 

 

 

For options granted during: 2009 2008 2007 

Weighted average fair value $ 4.60 $ 5.85 $ 4.67 

Weighted averaged expected life 7 7 7 

Valuation assumptions: 

Expected volatility 68.9 % 46.6-49.7 % 47.7-48.7 % 

Risk-free interest rate 3.5 % 3.0-3.9 % 4.5%-4.6 % 

Expected dividend yield 0 % 0 % 0 % 

Expected annual forfeitures 3 % 3 % 3 % 
Table of Contents 

 As of December 31, 2009, there was $3.7 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 to four years. The total fair value of shares 

vested during the years ended December 31, 2009, 2008 and 2007 was $2.6 million, $4.0 million and $4.5 million, respectively. 

 In addition to options issued pursuant to the plans, options have been issued to new hire employees as employment inducement grants under a 

New York Stock Exchange (“NYSE”) exception. These options were granted in 2007 and 2008 between $10.07 and $12.63 and vest over three 

years. At December 31, 2009, a total of 360,000 options issued outside of the plans were outstanding and 136,666 options were exercisable. 

 Stock options of 0.2 million were exercised in the year ended December 31, 2009 resulting in cash proceeds of $0.4 million. Stock options of 

0.5 million were exercised in the year ended December 31, 2008 resulting in cash proceeds of $1.6 million. 

Treasury Stock Buy-Back Program 

 In July 2008, our Board of Directors authorized the purchase of up to $20 million of our common stock from time to time through open 

market transactions. As of December 31, 2008, 1.2 million shares of stock had been purchased at an average cost of $10.17 per share for a total 

cost of $12.2 million of the $20 million authorization. During the year ended December 31, 2009, no stock was purchased under this program. 

Note 6 — 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. The 

results of operations and economic benefits of our minority equity investment in Petrodelta from April 1, 2006 through December 31, 2007 were 

recorded in the three months ended December 31, 2007 as Net Income from Unconsolidated Equity Affiliates. Oil and gas sales for 2007 is the 

recognition of the deferred revenue recorded by Harvest Vinccler for 2005 and first quarter 2006 deliveries pending clarification on the 

calculation of crude prices under the Transitory Agreement (see Note 1 – Organization and Summary of Significant Accounting Policies, 

Revenue Recognition ). Operations included under the heading “United States and Other” include U.S. operations, corporate management, cash 

management, business development and financing activities performed in the United States and other countries which do not meet the 

requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in 

order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the United States and Other 

segment and are not allocated to other operating segments. 

S-19 

 

 Weighted-Average 

 Nonvested Grant-Date 

 Options Fair Value 

Nonvested at January 1, 2009 1,979 $ 5.80 

Granted 118 3.13 

Vested (567 ) (5.82 ) 

Forfeited (10 ) (5.64 ) 

 

 

Nonvested at December 31, 2009 1,520 5.59 

 

 

 
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Note 7 – Investment in Equity Affiliates 

Petrodelta, S.A. 

 On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Petrodelta Fields subject 

to the conditions of the Conversion Contract was published in the Official Gazette. Petrodelta will engage in the exploration, production, 

gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from that date. Petrodelta has 

undertaken its operations in accordance with Petrodelta’s business plan as set forth in the Conversion Contract. Under the Conversion Contract, 

work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be 

modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. On February 4, 2010, Petrodelta’s 

board of directors endorsed a capital budget of $205 million for Petrodelta’s 2010 business plan. 

 The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with 

PPSA signed on January 17, 2008. The form of the agreement is set forth in the Conversion Contract. Crude oil delivered from the Petrodelta 

Fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets, and adjusted for variations in gravity and 

sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Natural gas 

delivered from the Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make payment to Petrodelta of each 

invoice within 60 days of the end of the invoiced production month by wire transfer, in U.S. Dollars in the case of payment for crude oil and 

natural gas liquids delivered, and in Bolivars in the case of payment for natural gas delivered, in immediately available funds to the bank 

accounts designated by Petrodelta. Any dividend paid by Petrodelta will be made in U.S. Dollars. 

 On April 23, 2009, Petrodelta’s board of directors declared a dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net 

to our 32 percent interest), which represents Petrodelta’s net income as reported under International Financial Reporting Standards (“IFRS”) for 

the six months ended June 30, 2008. HNR Finance received the cash related to this dividend in the form of an advance dividend in October 2008. 

 On April 15, 2008, the Venezuelan government published in the Official Gazette the Law of Special Contribution to Extraordinary Prices at 

the Hydrocarbons International Market (“original Windfall Profits Tax”). The original Windfall Profits Tax was based on prices for Brent crude. 

On July 10, 2008, the Venezuelan government published an amendment to the Windfall Profits Tax (“amended Windfall Profits Tax”) to be 

calculated on the Venezuelan Export Basket (“VEB”) of prices as published by the Ministry of the People’s Power for Energy and Petroleum 

(“MENPET”). The amended Windfall Profits Tax was made retroactive to April 15, 2008, the date of the original Windfall Profits Tax. As 

instructed by CVP, Petrodelta has applied the amended Windfall Profits Tax to gross oil production delivered to PDVSA since April 15, 2008 

when the tax was enacted. The amended Windfall Profits Tax established a special 50 percent tax to the Venezuelan government when the 

average price of the VEB exceeds $70 per barrel. In a similar manner, the percentage is increased from 50 percent to 60 percent when the 

average price of the VEB exceeds $100 per barrel. The amended Windfall Profits Tax is reported as expense on the income statement and is 

deductible for Venezuelan tax purposes. Petrodelta recorded $0.9 million and $56.4 million of expense for the amended Windfall Profits Tax 

during the years ended December 31, 2009 and 2008, respectively. 

S-20 

 

 2009 2008 2007 

 (in thousands) 

Segment Revenues 

Oil and gas sales: 

United States and other $ 181 $ — $ — 

Venezuela — — 11,217 

    

Total oil and gas sales 181 — 11,217 

 

 

  

Segment Income (Loss) Attributable to Harvest 

Venezuela 39,696 33,020 79,878 

Indonesia (5,124 ) (8,966 ) (7 ) 

United States and other (37,679 ) (45,518 ) (19,753 ) 

    

Net income (loss) attributable to Harvest $ (3,107 ) $ (21,464 ) $ 60,118 

 

 

 

 

 

 

 

 

 December 31, 

 2009 2008 

 (in thousands) 

Operating Segment Assets 

Venezuela $ 249,484 $ 231,755 

Indonesia 5,893 1,556 

United States and other 113,555 152,184 

   

 368,932 385,495 

Intersegment eliminations (20,153 ) (23,229 ) 

   

 $ 348,779 $ 362,266 

 

 

 

 

 
Table of Contents 

 During the second quarter of 2009, PDVSA completed an actuarial study for their pension and retirement plan. This pension and retirement 

plan covers all PDVSA employees and mixed companies employees. Petrodelta is not required to reimburse the pension costs to PDVSA until 

PDVSA pays the pension benefits to employees. In May 2009, upon completion of the review of this actuarial study, PDVSA sent a statement to 

Petrodelta for its respective costs associated with the pension and retirement plan. Petrodelta recorded additional pension expense of $15.6 

million ($5.0 million net to our 32 percent interest) in the three month period ended June 30, 2009 based on the statement received. The pension 

adjustment resulted from the completion of the first full actuary study by PDVSA related to its employees that provide services to the mixed 

companies and a refinement of management’s assumptions related to credit for past service costs covering the period from January 2008, when 

the Harvest Vinccler employees were migrated to PDVSA payroll, through May 2009. At this time PDVSA did not have specific benefit 

information related to each individual mixed company and thus allocated the pension obligation to each mixed company assuming that the 

employees serving each of the mixed companies had the same characteristics. The pension adjustment was a change in Petrodelta management’s 

estimate based on the new information provided by PDVSA. 

 During the fourth quarter of 2009, PDVSA completed an updated actuarial study as of December 31, 2009. This study was based on a further 

refinement of assumptions for each of the mixed companies, including Petrodelta and a new allocation methodology as PDVSA gathered during 

2009 all relevant information for each of the mixed companies. The revised pension obligation allocated to Petrodelta resulted in a decrease of 

$8.4 million ($2.7 million net to our 32 percent interest) to the pension and retirement plan costs as compared to those previously recorded to 

Petrodelta in May 2009. This change in management’s estimate related to the pension and retirement plan costs was recorded in December 2009. 

Pension costs at December 31, 2009 reasonably reflect Petrodelta’s employee demographic and plan conditions. The additional pension cost is 

not tax deductible until future periods when the pension is settled in cash. The provision for the pension plan is subject to future revisions, both 

upwards and downwards, based on changes in assumptions, the terms of the relevant plans, the allocation methodology or other prospective 

amendments or changes as determined by PDVSA. 

 In June 2009, CVP issued instructions to Petrodelta to set up a reserve within the equity section of the balance sheet for deferred tax assets. 

Petrodelta’s bylaws state that Petrodelta’s shareholders are required to approve the setting up of special reserves. In August 2009, Petrodelta’s 

board of directors approved the setting up of the reserve. Although this reserve has no effect on Petrodelta’s financial position, results of 

operation or cash flows, it has the effect of limiting future dividends to net income adjusted for deferred tax assets. Past dividends received from 

Petrodelta represented Petrodelta’s net income as reported under IFRS. However, Article 307 of the Venezuelan Commerce Code states that 

distributions and payments of dividends must meet two conditions: 1) the retained earnings of the entity should be liquid and realizable, and 2) 

the entity has enough cash to pay and distribute the dividend. Deferred taxes are not liquid or realizable as cash until the items giving rise to the 

deferred tax are recognized in the entity’s tax return. Therefore, CVP’s instructions are to ensure future dividends are declared and paid as stated 

under Venezuelan law. Article 307 also states that shareholders are not obligated to restore dividends that have been distributed in good faith 

according to the entity’s balances and sets the statute of limitations for an entity to claim restoration of dividends at five years. 

 In 2005, Venezuela modified the Science and Technology Law (referred to as “LOCTI” in Venezuela) to require companies doing business in 

Venezuela to invest, contribute, or spend a percentage of their gross revenue on projects to promote inventions or investigate technology in areas 

deemed critical to Venezuela. LOCTI requires major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon 

Law (“OHL”) to contribute two percent of their gross revenue generated in Venezuela from activities specified in the OHL. The contribution is 

based on the previous year’s gross revenue and is due the following year. LOCTI requires that each company file a separate declaration stating 

how much has been contributed; however, waivers have been granted in the past to allow PDVSA to file a declaration on a consolidated basis 

covering all of its and its consolidating entities liabilities. Since Petrodelta expects PDVSA to continue requesting and receiving waivers, 

Petrodelta has not accrued a liability to LOCTI for the year ended December 31, 2009. The potential exposure to LOCTI for the year ended 

December 31, 2009 is $9.5 million, $4.8 million net of tax ($1.5 million net to our 32 percent interest). 

 Petrodelta’s reporting and functional currency is the U.S. Dollar. HNR Finance owns a 40 percent interest in Petrodelta and recorded its share 

of the earnings of Petrodelta from April 1, 2006 to December 31, 2007 in the three months ended December 31, 2007. The years ended 

December 31, 2009 and 2008 include net income from unconsolidated equity affiliates for Petrodelta on a current basis. Petrodelta’s financial 

information is prepared in accordance with IFRS which we have adjusted to conform to GAAP. All amounts through Net Income Equity 

Affiliate represent 100 percent of Petrodelta. Summary financial information has been presented below at December 31, 2009, 2008 and 2007, 

and for the years ended December 31, 2009, 2008 and 2007: 

S-21 
Table of Contents 

S-22 

 

 Year Ended December 31, 

 2009 2008 2007 

 (in thousands) 

Barrels of oil sold 7,835 5,505 5,374 

MCF of gas sold 4,397 10,700 13,456 

Total Boe 8,568 7,288 7,616 

 

Average price per barrel $ 57.62 $ 83.22 $ 58.61 

Average price per mcf $ 1.54 $ 1.54 $ 1.54 

 

Revenues: 

Oil sales $ 451,473 $ 458,113 $ 314,928 

Gas sales 6,778 16,506 20,789 

Royalty (156,799 ) (168,790 ) (114,847 ) 

    

 301,452 305,829 220,870 

 

Expenses: 

Operating expenses 48,311 52,946 21,352 

Workovers — 24,663 2,400 

Depletion, depreciation and amortization 33,666 25,509 18,549 

General and administrative 9,746 5,974 19,880 

Windfall profits tax 882 56,377 — 

Taxes other than on income — — 2,747 

    

 92,605 165,469 64,928 

    

 

Income from Operations 208,847 140,360 155,942 

Interest expense (3,617 ) (2,329 ) — 

    

Income before Income Tax 205,230 138,031 155,942 

 

Current income tax expense 105,868 69,374 85,849 

Deferred income tax benefit (43,922 ) (52,560 ) (21,348 ) 

    

Net Income 143,284 121,217 91,441 

Adjustment to reconcile to reported Net Income from Unconsolidated Equity Affiliate: 

Deferred income tax benefit 38,516 34,827 12,343 

 

 

 

 

Net Income Equity Affiliate 104,768 86,390 79,098 

Equity interest in unconsolidated equity affiliate 40 % 40 % 40 % 

 

 

 

 

Income before amortization of excess basis in equity affiliate 41,907 34,556 31,639 

Amortization of excess basis in equity affiliate (1,356 ) (1,155 ) (2,530 ) 

Conform depletion expense to GAAP 183 2,533 — 

 

 

 

 

Net income from unconsolidated equity affiliate $ 40,734 $ 35,934 $ 29,109 

 

 

 

 

 

 

 

 

 December 31, December 31, 

 2009 2008 

 (in thousands) 

Current assets $ 404,825 $ 311,017 

Property and equipment 265,442 211,760 

Other assets 141,245 97,323 

Current liabilities 345,812 260,234 

Other liabilities 33,600 19,174 

Net equity 432,100 340,692 
Table of Contents 

Fusion Geophysical, LLC (“Fusion”) 

 Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering. The purchase of Fusion extends our 

technical ability and global reach to support a more organic growth and exploration strategy. Our 49 percent minority equity investment in 

Fusion is accounted for using the equity method of accounting. In October 2008, we increased our minority equity investment in Fusion from 

45 percent to 49 percent for $2.2 million. Operating revenue and total assets represent 100 percent of Fusion. No dividends were declared or paid 

during the years ended December 31, 2009, 2008 and 2007, respectively. Summarized financial information for Fusion follows: 

 Approximately 29 percent, 26 percent and 7 percent of Fusion’s revenue for the years ended December 31, 2009, 2008 and 2007, 

respectively, was earned from Harvest or equity affiliates. 

 On April 9, 2009, we entered into a service agreement with Fusion whereby we prepaid $1.5 million for certain services to be performed in 

connection with certain projects as defined in the service agreement. The services are to be performed in accordance with the existing consulting 

agreement. Upon written notice to Fusion, the projects and types of services can be amended. The unapplied portion of the prepayment advance 

bears interest at an annual rate of 12 percent which will be added to the prepayment advance balance and used to offset future service invoices 

from Fusion. Services rendered have been applied against the prepayment, and as of December 31, 2009, the balance for prepaid services was 

approximately $1.0 million. 

 As of December 31, 2009, we updated the review for impairment of our minority equity investment in Fusion. In preparing this update, future 

net cash flows prepared by Fusion based on different business opportunities that Fusion is currently pursuing were updated for current activities. 

These business opportunities were weighted with a probability of success. Based on these cash flow projections and considering Fusion’s current 

liquidity, we concluded that the potential business opportunities did not support Fusion’s on-going cash flow requirements; and therefore, we 

recorded a $1.6 million charge to fully impair the carrying value of our equity investment in Fusion at December 31, 2009. 

Note 8 – United States 

 During 2008, we initiated a domestic exploration program in two different basins. We are the operator of both exploration programs and have 

complemented our existing personnel with the addition of highly experienced management and technical personnel and with the acquisition of 

our minority equity investment in Fusion. 

S-23 

 

 Year Ended December 31, 

 2009 2008 2007 

 (in thousands) 

Operating Revenues $ 11,089 $ 13,063 $ 7,392 

Net Income (Loss) $ (4,798 ) $ (1,290 ) $ 527 

Equity interest in unconsolidated equity affiliate 49 % 49 % 45 % 

    

Net income (loss) from unconsolidated equity affiliate (2,351 ) (632 ) 237 

Amortization of fair value of intangibles (995 ) (726 ) (656 ) 

Impairment of investment (1,631 ) — — 

    

Net loss from unconsolidated equity affiliate $ (4,977 ) $ (1,358 ) $ (419 ) 

 

 

 

 

 

 

 

 

 December 31, December, 31 

 2009 2008 

Current assets $ 2,726 $ 7,864 

Total assets 30,205 30,633 

Current liabilities 8,024 7,294 

Total liabilities 12,242 8,281 
Table of Contents 

Gulf Coast 

 In March 2008, we executed an AMI agreement with a private third party for an area in the upper Gulf Coast Region of the United States. The 

AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana, including state waters. We are the operator and have 

initial working interests of 55 percent in Starks, the first prospect in the AMI, and 50 percent in West Bay, the second prospect in the AMI. The 

private third party contributed these two prospects, including the leases and proprietary 3-D seismic data sets, and numerous leads generated 

over the last three decades of regional geological focus. We agreed to fund the first $20 million of new lease acquisitions, geological and 

geophysical studies, seismic reprocessing and drilling costs. At June 30, 2009, we had met the $20 million funding obligation under the terms of 

the AMI. All costs incurred after June 30, 2009 are being shared by the parties in proportion to their working interests as defined in the AMI. In 

August 2009, the AMI became a three party arrangement when the private third party restructured and assigned a portion of its interest to one of 

its affiliates. 

 The private third party is obligated to evaluate and present additional opportunities at their sole cost. As each prospect is accepted it will be 

covered by the AMI. Although several additional potential prospects had been screened and evaluated within the AMI since its inception, we had 

not pursued leasing or drilling on any new projects within the AMI as of December 31, 2009. On January 29, 2010, we entered into an agreement 

with one of the private third parties in our AMI for an option to participate in a new project (see Note 14 – Subsequent Events ). 

Starks Project 

 We drilled an exploratory dry hole on the Starks prospect in 2008. In December 2009, we wrote off the remaining carrying value of 

$0.7 million of the Starks prospect as we have no plans for further activities relating to this prospect. 

West Bay Project 

 During the year ended December 31, 2009, operational activities in the West Bay prospect included the interpretation of 3-D seismic, site 

surveying, and preparation of engineering documents. Interpretation of 3-D seismic data on the West Bay project was completed in 2009 and 

resulted in the identification of a set of drilling leads and prospects for the project. On July 14, 2009, we, along with our partner in the AMI, 

acquired 880 acres of shallow water offshore bay leases representing two separate tracts from the State of Texas General Land Office at a state 

lease sale for a total gross cost of $0.5 million. Acquisition of these two tracts completes the planned land acquisition activities on the project. 

 The AMI participants are currently continuing to evaluate the leads and prospects to determine priorities and drilling plans for the West Bay 

project and have identified the likely initial drilling prospect. Land, regulatory, and surface access preparations are currently in progress focused 

on taking the initial drilling prospect to drill-ready status. The West Bay project represents $3.1 million and $2.9 million of unproved oil and gas 

properties on our December 31, 2009 and 2008 balance sheets, respectively. 

Western United States – Antelope 

 In October 2007, we entered into a JEDA with a private third party to pursue a lease acquisition program and drilling program on the 

Antelope prospect in the Western United States. We are the operator and had an initial working interest of 50 percent in the Antelope prospect. 

The private third party is obligated to assemble the lease position on the Antelope prospect. The JEDA provides that we would earn our initial 

50 percent working interest in the Antelope prospect by compensating the private third party for leases acquired in accordance with terms 

defined in the JEDA, and by drilling and completing one deep natural gas test well (the Bar F) at our sole expense. In November 2008, we 

entered into a Letter Agreement/Amendment of the JEDA (the “Letter Agreement”) with the private third party. The Letter Agreement clarifies 

several open issues in the JEDA, such as classification of $2.7 million of prepaid land costs for the Antelope prospect as a note receivable, 

addition of a requirement for the private third party to partially assign leases to us prior to meeting the lease earning obligation, and clarification 

of the private third party’s cost obligations for any shallow wells to be drilled on the Antelope prospect prior to the Bar F. Per the Letter 

Agreement, payment of the $2.7 million note receivable was due from the private third party on or by 

S-24 
Table of Contents 

spud date of the Bar F. Since payment was not received prior to the Bar F spud date, our interest in the Antelope prospect was increased to 

60 percent, with the incremental 10 percent working interest being earned by drilling and completing the Bar F. The note receivable remains 

outstanding and will be collected through sales revenues taken from a portion of the private third party’s net revenue from the Bar F provided the 

Bar F is commercial. 

 Activities are in progress on two separate projects on the Antelope prospect in Duchesne County, Utah. 

Mesaverde 

 The Mesaverde project is targeted to explore for and develop oil and natural gas from multiple reservoir horizons in the Uintah Basin of 

northeastern Utah in Duchesne and Uintah Counties. Leads and/or prospects were identified in three prospective reservoir horizons in 

preparation for drilling. 

 Operational activities during 2009 on the Mesaverde project focused on continuing leasing activities on private, Allottee, and tribal land, and 

surveying, preliminary engineering, permitting preparations, and conducting drilling operations on a deep natural gas test well (the Bar F) that 

commenced drilling on June 15, 2009. The Bar F was permitted to 18,000 feet. The Bar F was drilled to a total depth of 17,566 feet and an 

extended production test of multiple potential reservoir horizons is now in progress. To date, testing has been focused on the evaluation of the 

natural gas potential of the Mesaverde tight gas reservoir over a prospective interval from 14,000 to 17,400 feet. Completion activities consisted 

of hydraulic fracturing of eight separate reservoir intervals in the Mesaverde and multiple extended flow tests of the individual fractured 

intervals, along with a flow test of the commingled eight intervals. While the results to date have not definitively determined the commerciality 

of a stand-alone development of the Mesaverde, we believe these results indicate progress toward that determination and that the Mesaverde 

reservoir remains potentially prospective over a portion of our land position. The Mesaverde project represents $36.4 million and $8.3 million of 

unproved oil and gas properties on our December 31, 2009 and 2008 balance sheets, respectively. 

Monument Butte 

 The Monument Butte project is an eight well appraisal and development drilling program to produce oil and natural gas from the Green River 

formation on the southern portion of our Antelope land position. The Monument Butte project is non-operated and we hold a 43 percent working 

interest. The parties have formed a 320 acre AMI which contained the eight drilling locations. 

 Operational activities during 2009 on the Monument Butte project focused on resolution of forced pooling issues with non-consenting 

interests, negotiations and finalization of an agreement with the operator for the joint drilling operations. As of December 31, 2009, five wells 

had been drilled: two of the five wells were on production, and three wells waiting on completion. These three wells were placed on production 

in the first quarter 2010. The three additional wells were drilled by the end of February 2010: two wells had been placed on production and the 

one remaining well was waiting on completion operations. The Monument Butte project represents $1.6 million of proved oil and gas properties 

and $0.3 million of unproved oil and gas properties on our December 31, 2009 and 2008 balance sheets, respectively. 

Note 9 – Indonesia 

 In 2008, we acquired a 47 percent interest in the Budong-Budong Production Sharing Contract (“Budong PSC”) by committing to fund the 

first phase of the exploration program including the acquisition of 2-D seismic and drilling of the first two exploration wells. This commitment is 

capped at $17.2 million. The commitment is comprised of $6.5 million for the acquisition of seismic and $10.7 million for the drilling of the first 

two exploratory wells. After the commitment of each component is met, all subsequent costs will be shared by the parties in proportion to their 

ownership interests. The $6.5 million carry obligation for the 2-D seismic acquisition was met in December 2008. Prior to drilling the first 

exploration well, subject to the estimated cost of that well, our partner will have a one-time option to increase the level of the carried interest to a 

maximum of $20.0 million, and as compensation for the increase, we will increase our participation to a maximum of 54.65 percent. This 

equates to a total carried cost for the farm-in of $9.1 million. Our partner will be the operator through the exploration phase as required by the 

terms of the Budong PSC. We will have control of major decisions and financing for the project 

S-25 
Table of Contents 

with an option to become operator if approved by BP Migas, Indonesia’s oil and gas regulatory authority, in the subsequent development and 

production phase. 

 The Budong PSC covers 1.35 million acres and includes the Lariang and Karama sub-basins which are the eastern onshore extension of the 

West Sulawesi foldbelt (“WSFB”). Exploration to date in the basin is immature due to previously difficult jungle terrain, which is now 

accessible with the development of palm oil plantations and their related infrastructure. Field work performed over the last 10 years, as outcrops 

have been more accessible, has given a new understanding to the presence of Eocene source and reservoir potential that had not previously been 

recognized. Recent seismic surveys have greatly improved the understanding of the geology and enhanced the prospectivity of the offshore 

WSFB and, by analogy, the sparsely explored onshore area. The Budong PSC includes a ten-year exploration period and a 20-year development 

phase. During the initial three-year exploration phase, which began January 2007, operational activities during 2009 focused on the interpretation 

of 650 kilometers of 2-D seismic and well planning. Two drill sites have been selected. Currently, the locations for the two test wells are being 

constructed and the rig and ancillary equipment is being mobilized to the area. It is expected that the first of two exploration wells will spud 

early in the second quarter of 2010. In accordance with the farm-in agreement, we expect to fund 100 percent of the well expenditures to earn 

our 47 percent working interest up to a cap of $10.7 million; thereafter, we will pay in proportion to our working interest. The Budong PSC 

represents $2.0 million and $0.2 million, respectively, of unproved oil and gas properties on our December 30, 2009 and 2008 balance sheets. 

Note 10 – Gabon 

 We are the operator of the Dussafu Marin Permit offshore Gabon in West Africa (“Dussafu PSC”) with a 66.667 percent interest in the 

Dussafu PSC. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC contains 680,000 acres with water 

depths up to 1,000 feet. The Dussafu PSC has two small oil discoveries in the Gamba and Dentale reservoirs and a small natural gas discovery. 

Production and infrastructure exists in the blocks contiguous to the Dussafu PSC. 

 The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources 

(“Republic of Gabon”), entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. The second 

exploration phase comprises a three-year work commitment which includes the acquisition and processing of 500 kilometers of 2-D seismic, 

geology and geophysical interpretation, engineering studies and the drilling of a conditional well. Operational activities during 2009 focused on 

completion of the processing and reprocessing of 1,330 kilometers of 2-D seismic and the pre-stack depth reprocessing of 1,076 square 

kilometers of 3-D seismic data. The improved imaging from this work has allowed the interpretation to mature the prospect inventory to provide 

the partnership a number of prospective targets in the sub-salt section, in both the Gamba and Syn-rift plays that are productive in the nearby 

Etame, Lucina and M’Bya fields. Subject to drilling rig availability, we expect to drill an exploration well in the third quarter of 2010. The 

Dussafu PSC represents $6.9 million and $5.9 million, respectively, of unproved oil and gas properties on our December 31, 2009 and 2008 

balance sheets. 

Note 11 – Oman 

 On April 11, 2009, we signed an Exploration and Production Sharing Agreement (“EPSA”) with Oman for the Al Ghubar / Qarn Alam 

license. We have a 100 percent working interest in Block 64 EPSA during the exploration phase. Oman Oil Company has the option to back-in 

to up to a 20 percent interest in Block 64 EPSA after the discovery of gas. 

 Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate which the Oman 

Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). PDO will continue to 

produce oil from several fields within Block 64 EPSA area. The 3,867 square kilometer (955,600 acres) block is located in the gas and 

condensate rich Ghaba Salt Basin in close proximity to the Barik, Saih Rawl and Saih Nihayda gas and condensate fields. We have an obligation 

to drill two wells over a three year period with a funding commitment of $22.0 million. Current activities include the compilation of existing 

data, over two prospect areas of approximately 1,000 square kilometers and geological studies to determine drillable prospects. Well planning is 

expected to commence in 2010 for exploration 

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drilling in 2011. During the year ended December 31, 2009, we incurred $1.6 million for costs associated with negotiating Block 64 EPSA and 

$2.2 million for costs associated with signing the license, including signature bonus and data compilation. The Block 64 EPSA represents 

$3.8 million of unproved oil and gas properties on our December 31, 2009 balance sheet. 

Note 12 — China 

 In December 1996, we acquired 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 (“China”) and Socialist 

Republic of Vietnam (“Vietnam”). Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The 

border dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the 

dispute. 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, 2011. While no assurance can be 

given, we believe we will continue to receive contract extensions so long as the border disputes persist. Recently, Vietnam, along with the 

company that is the party to the agreement with Vietnam, announced plans for exploration drilling during 2010. While no assurance can be 

given, we believe this announcement may provide some resolution with the border disputes, although we do not know in what manner any 

resolution might appear. WAB-21 represents $3.0 million of unproved oil and gas properties on our December 31, 2009 and 2008 balance sheets, 

respectively. 

Note 13 — 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 33.1 million, 34.1 million and 36.5 million for the years ended December 31, 2009, 2008 and 2007, 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 33.1 million, 

34.1 million and 37.9 million for the years ended December 31, 2009, 2008 and 2007, respectively. 

 An aggregate of 3.7 million options were excluded from earnings per share calculations because there exercise price exceeded the average 

price for the year ended December 31, 2009. An aggregate of 4.0 million options were excluded from the earnings per share calculations because 

their exercise price exceeded the average price for the year ended December 31, 2008. For the year ended December 31, 2007, 1.1 million was 

excluded from the earnings per share calculations because their exercise price exceeded the average price. 

Note 14 – Subsequent Events 

 We conducted our subsequent events review up through the date of the issuance of this Annual Report on Form 10-K. 

 On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement which establishes new exchange 

rates for the Bolivar/U.S. Dollar currencies that will enter into force on January 11, 2010. Each exchange rate will be applied to foreign currency 

sales and purchases conducted through the Foreign Currency Administration Commission (“CADIVI”), in the cases expressly provided in the 

Exchange Agreement. In this regard, the exchange rates established in the Agreement are: 2.60 Bolivars per U.S. Dollar and 4.30 Bolivars per U. 

S. Dollar. The 2.60 Bolivar exchange rate applies to the food, health, medical and technology sectors. The 4.30 Bolivar exchange rate applies to 

all other sectors not expressly established by the 2.60 Bolivar exchange rate. The U.S. Dollar is the functional reporting currency for both 

Petrodelta and Harvest Vinccler. 

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 On January 28, 2010, we entered into an agreement with one of the private third parties in our AMI for an option to participate in a new 

project. We paid $1.5 million for the option to acquire up to a 50 percent interest in the new project. If we exercise our option to participate, we 

will participate in this project with essentially the same terms as the other existing projects in the AMI. The option to participate expires on 

June 1, 2010. 

 On February 17, 2010, we closed an offering of $32 million in aggregate principal amount of our 8.25 percent senior convertible notes due 

2013, which resulted in net proceeds to us, after deducting underwriting discounts, commissions and estimated offering expenses, of 

approximately $30 million. 

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Table of Contents 

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

Quarterly Financial Data (unaudited) 

 Summarized quarterly financial data is as follows: 

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

 The following tables summarize our proved reserves, drilling and production activity, and financial operating data at the end of each year. 

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. 

S-29 

 

 Quarter Ended 

 March 31 June 30 September 30 December 31 

 (amounts in thousands, except per share data) 

Year ended December 31, 2009 

Revenues $ — $ — $ — $ 181 

Expenses (7,825 ) (10,217 ) (7,286 ) (5,812 ) 

Non-operating income 331 296 224 229 

 

 

  

 

Loss from consolidated companies before income taxes (7,494 ) (9,921 ) (7,062 ) (5,402 ) 

Income tax expense 889 147 109 37 

 

 

  

 

Loss from consolidated companies (8,383 ) (10,068 ) (7,171 ) (5,439 ) 

Net income from unconsolidated equity affiliates 4,410 7,476 9,890 13,981 

 

 

  

 

Net income (loss) (3,973 ) (2,592 ) 2,719 8,542 

Less: Net income attributable to noncontrolling interest 803 1,597 1,936 3,467 

     

Net income (loss) attributable to Harvest $ (4,776 ) $ (4,189 ) $ 783 $ 5,075 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to Harvest per common share: 

Basic $ (0.15 ) $ (0.13 ) $ 0.02 $ 0.15 

 

 

 

 

 

 

 

 

 

Diluted $ (0.15 ) $ (0.13 ) $ 0.02 $ 0.15 

 

 

 

 

 

 

 

 

 

 

 Quarter Ended 

 March 31 June 30 September 30 December 31 

 (amounts in thousands, except per share data) 

Year ended December 31, 2008 

Expenses $ (7,869 ) $ (9,530 ) $ (10,621 ) $ (26,420 ) 

Non-operating income (expense) 2,002 1,582 1,100 670 

     

Loss from consolidated companies before income taxes (5,867 ) (7,948 ) (9,521 ) (25,750 ) 

Income tax expense (benefit) 64 37 (20 ) (56 ) 

     

Loss from consolidated companies (5,931 ) (7,985 ) (9,501 ) (25,694 ) 

Net income from unconsolidated equity affiliates 8,809 9,409 5,309 11,049 

     

Net income (loss) 2,878 1,424 (4,192 ) (14,645 ) 

Less: Net income attributable to noncontrolling interest 1,673 2,057 1,045 2,154 

     

Net income (loss) attributable to Harvest $ 1,205 $ (633 ) $ (5,237 ) $ (16,799 ) 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to Harvest per common share: 

Basic $ 0.03 $ (0.02 ) $ (0.16 ) $ (0.51 ) 

 

 

 

 

 

 

 

 

 

Diluted $ 0.03 $ (0.02 ) $ (0.16 ) $ (0.51 ) 

 

 

 

 

 

 

 

 

 
Table of Contents 

 We regularly evaluate our unproved properties to determine whether impairment has occurred. We have excluded from amortization our 

interest in unproved properties and the cost of uncompleted exploratory activities. The principal portion of such costs, excluding those related the 

acquisition of WAB-21, are expected to be included in amortizable costs during the next two to three years. The ultimate timing of when the 

costs related to the acquisition of WAB-21 will be included in amortizable costs is uncertain. 

 Unproved property costs at December 31, 2009 consisted of the following by year incurred (in thousands): 

S-30 

TABLE I —

 

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

 

 United States 

 Oman Gabon Indonesia and Other Total 

Year Ended December 31, 2009 

Acquisition costs $ 3,757 $ 941 $ 1,800 $ 28,170 $ 34,668 

Exploration costs 459 225 1,793 2,563 5,040 

Development costs — — — 1,547 1,547 

   

 

  

 $ 4,216 $ 1,166 $ 3,593 $ 32,280 $ 41,255 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2008 

Acquisition costs $ — $ 5,792 $ 71 $ 13,302 $ 19,165 

Exploration costs — 3,016 7,647 14,020 24,683 

      

 $ — $ 8,808 $ 7,718 $ 27,322 $ 43,848 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2007 

Acquisition costs $ — $ 136 $ 168 $ 160 $ 464 

Exploration costs — — — 204 204 

   

 

  

 $ — $ 136 $ 168 $ 364 $ 668 

 

 

 

 

 

 

 

 

 

 

 

TABLE II —

 

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

 

 United States 

 Oman Gabon Indonesia and Other Total 

Year Ended December 31, 2009 

Proved property costs $ — $ — $ — $ 1,646 $ 1,646 

Unproved property costs 3,757 6,869 670 42,815 54,111 

Oilfield Inventories — — 1,369 1,417 2,786 

Less accumulated depletion — — — (29 ) (29 ) 

      

 $ 3,757 $ 6,869 $ 2,039 $ 45,849 $ 58,514 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2008 

Unproved property costs $ — $ 5,927 $ 239 $ 16,162 $ 22,328 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2007 

Unproved property costs $ — $ 136 $ 168 $ 2,859 $ 3,163 

 

 

 

 

 

 

 

 

 

 

 

 

 Total 2009 2008 2007 Prior 

Property acquisition costs $ 56,897 $ 34,569 $ 19,165 $ 263 $ 2,900 

 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

 Estimating oil and gas reserves is a very complex process requiring significant subjective decisions in the evaluation of all available 

geological, engineering and economic data for each reservoir. This data may change substantially over time as a result of numerous factors such 

as production history, additional development activity and continual reassessment of the viability of production under various economic and 

political conditions. Consequently, material upward or downward revisions to existing reserve estimates may occur from time to time; although, 

every reasonable efforts is made to ensure that reported results are the most accurate assessment available. We ensure that the data provided to 

our external independent experts, and their interpretation of that data, corresponds with our development plans and management’s assessment of 

each reservoir. The significance of subjective decisions required and variances in available data make estimates generally less precise than other 

estimates presented in connection with financial statement disclosures. 

 In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve 

information. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the 

SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting 

principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, prior period reserves were not restated. For the 

United States, the primary impacts of the SEC’s final rule on our reserve estimates include: 

 The impact of the adoption of the SEC’s final rule on our financial statements is not practicable to estimate due to the operational and 

technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules. 

 The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, 

which include verification of data provided for, management reviews and review of the independent third party reserves report. The technical 

employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Arts in Engineering Science, a 

Master of Science in Petroleum Engineering, has more than 25 years of experience in reservoir engineering and is a member of the Society of 

Petroleum Engineers. 

 All reserve information in this report is based on estimates prepared by Ryder Scott Company L.P. (“Ryder Scott”), independent petroleum 

engineers. The technical personnel responsible for preparing the reserve estimates at Ryder Scott meet the requirements regarding qualifications, 

independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves 

Information promulgated 

S-31 

TABLE III —

 

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

 

 United States 

Year Ended December 31, 2009 

Revenues: 

Oil and natural gas revenues $ 181 

 

Expenses: 

Operating, selling, and distribution expenses and taxes other than on income 15 

Depletion 29 

Income Tax expense — 

  

Total expenses 44 

  

Results of operations from oil and natural gas producing activities $ 137 

 

 

 

TABLE IV —

 

Quantities of Oil and Natural Gas Reserves 

 • The use of the unweighted 12-month average of the first-day-of-the-month reference price of $48.21 per barrel for oil compared to yearend reference price of $61.73 per barrel, and 

 

 • The use of the unweighted 12-month average of the first-day-of-the-month reference price of $3.31 per Mcf for gas compared to yearend reference price of $4.25 per Mcf. 
Table of Contents 

by the Society of Petroleum Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; 

they do not own an interest in our properties and are not employed on a contingent fee basis. 

 Reserves for Petrodelta are reflected in the following section Additional Supplemental Information on Oil and Natural Gas Producing 

Activities (unaudited) for Venezuela Equity Affiliate as of December 31, 2009, 2008 and 2007, TABLE IV — Quantities of Oil and Natural Gas 

Reserves . 

 The table shown below represents our interests in the United States. All of our other properties are unproved and have no associated reserves. 

There were no reserves prior to December 31, 2009 and all amounts are reflected as discoveries. During 2009, we identified and approved the 

development of eight locations in the Monument Butte project in Utah. At year end 2009, we have drilled and moved to the proved developed 

category three of these locations. At year end 2009, we have five identified proved undeveloped (“PUD”) locations. All PUD locations have 

subsequently been converted to proved developed (“PDP”) locations or are scheduled to be converted to PDP locations by the end of the first 

quarter 2010. These reserves are in a new geographic area for us. 

 The standardized measure of discounted future net cash flows is presented in accordance with the provisions of the accounting standard on 

disclosures about oil and gas producing activities. 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 an applying the average price during the 12-month period, determined as an unweighted arithmetic 

average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the 

contract, to the estimated future production of year-end proved reserves. Our average prices used were $48.21 per barrel for oil and $3.31 per 

Mcf for gas. 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 table shown below represents our net interest at December 31, 2009. This is the first year to report our reserves in the United States, 

based on the results of Ryder Scott Company L.P. 

S-32 

 

 As of 

 December 31, 2009 

 Oil Gas 

 (MBbls) (MMcf) 

 (in thousands) 

Proved 

Developed 

United States 131 653 

 

Undeveloped 

United States 95 473 

   

Total Proved 226 1,126 

 

 

 

 

 

TABLE V —

 

Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities 
Table of Contents 

S-33 

 

 United States 

 (in thousands) 

December 31, 2009 

Future cash inflows from sales of oil and gas $ 14,626 

Future production costs (3,674 ) 

Future development costs (1,171 ) 

Future income tax expenses (3,147 ) 

  

Future net cash flows 6,634 

Effect of discounting net cash flows at 10% (1,911 ) 

  

Standardized measure of discounted future net cash flows $ 4,723 

 

 

 

TABLE VI —

 

Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (in thousands): 

 

 United States 

Standardized Measure at January 1 $ — 

Sales of oil and natural gas, net of related costs (166 ) 

Extensions, discoveries and improved recovery, net of future costs 6,978 

Net change in income taxes (2,089 ) 

  

Standardized Measure at December 31 $ 4,723 

 

 

 

 
Table of Contents 

Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Petrodelta S.A. as of December 31, 

2009, 2008 and 2007 

 The following tables summarize our proved reserves, drilling and production activity, and financial operating data at the end of each year. 

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. 

 Petrodelta (32 percent ownership) is accounted for under the equity method, and has been included at its ownership interest in the 

consolidated financial statements and the following Tables based on a year ending December 31 and, accordingly, results of operations for oil 

and natural gas producing activities in Venezuela reflect the year ended December 31, 2009, 2008 and 2007. 

 In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve 

information. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the 

SEC’s final rule. We adopted the guidance as 

S-34 

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

 

 Year ended December 31, 

 2009 2008 2007 

Development costs $ 26,605 $ 17,144 $ 972 

Exploration costs — — — 

    

 $ 26,605 $ 17,744 $ 972 

 

 

 

 

 

 

 

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

 

 Year ended December 31, 

 2009 2008 2007 

Proved property costs $ 108,696 $ 79,807 $ 64,415 

Unproved property costs 163 3,036 2,653 

Oilfield inventories 10,748 7,892 4,426 

Less accumulated depletion and impairment (27,089 ) (16,966 ) (11,063 ) 

    

 $ 92,518 $ 73,769 $ 60,431 

 

 

 

 

 

 

 

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

 

 Year Ended December 31, 

 2009 2008 2007 

Revenue: 

Oil and natural gas revenues $ 146,640 $ 151,878 $ 107,429 

Royalty (50,176 ) (54,013 ) (36,751 ) 

 

   

 96,464 97,865 70,678 

 

Expenses: 

Operating, selling and distribution expenses and taxes other than on income 15,742 42,876 7,601 

Depletion 10,123 5,903 5,746 

Income tax expense 35,300 23,530 28,666 

 

   

Total expenses 61,165 72,309 42,013 

 

   

Results of operations from oil and natural gas producing activities $ 35,299 $ 25,556 $ 28,665 

 

 

 

 

 

 

 

TABLE IV – Quantities of Oil and Natural Gas Reserves 
Table of Contents 

of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in 

accounting estimate. Under the SEC’s final rule, prior period reserves were not restated. For Petrodelta, the primary impact of the SEC’s final 

rule on our reserve estimates include: 

 Petrodelta is producing from, and continuing to develop, the Petrodelta Fields. Petrodelta has both developed and undeveloped oil and gas 

reserves identified in all six fields. Petrodelta produces the fields in accordance with a business plan defined by its conversion contract executed 

in late 2007. Proved Undeveloped (“PUD”) oil and gas reserves are drilled in accordance with Petrodelta’s business plan, but can be revised 

where drilling results indicate a change is warranted. This was the case when two wells drilled in El Salto in 2009 justified a modification to the 

El Salto PUD program. 

 As of year end 2009, Petrodelta has a total of 164 PUD (39,626 Boe) locations identified. Since the implementation of its business plan, 

Petrodelta has drilled 24 gross wells (2008 nine wells [1,743 Boe] and 2009 15 wells [2,498 Boe]) which have moved to the proved developed 

producing (“PDP”) category. Of these 24 locations, 17 (3,511 Boe) represent the movements of PUD locations to PDP locations. The other seven 

new producing wells (731 Boe) were previously classified Probable, Possible or un-defined. All above Boe represent HNR Finance’s interest, 

net of a 33.33 percent royalty. 

 All PUD locations are scheduled to be drilled by 2014; however, there are some PUD locations that are scheduled to be drilled in the sixth 

year after the PUD locations were first identified. Petrodelta has a track record of identifying, executing and converting its PUD locations to PDP 

locations, and there are special circumstances to account for this drilling delay. Petrodelta commenced drilling operations in the second quarter 

of 2008; however, shortly thereafter Petrodelta was advised by the Venezuelan government that Petrodelta’s 2009 production target was to be 

approximately 16,000 barrels of oil per day following the December 17, 2008 Organization of the Petroleum Exporting Countries (“OPEC”) 

meeting establishing new production quotas. Subsequently, Petrodelta was allowed to produce at capacity to help fulfill other companies’ 

production shortfalls. Also, PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do 

work for Petrodelta. As a result, Petrodelta has experienced difficulty in retaining contractors who provide equipment and/or services for 

Petrodelta’s operations. Inability to retain contractors or to pay them on a timely basis is having an adverse effect on Petrodelta’s ability to carry 

out its business plan. These events have been outside of the control of Petrodelta. Petrodelta has recently taken specific actions to improve its 

ability to execute on its established business plan in a timely manner. 

 In summary, Petrodelta has a demonstrated track record of identifying, executing and converting its PUD locations to PDP locations. PUD 

locations are expected to be drilled at a similar pace with 27 wells drilled in 2010 and an average 36 wells per year in 2011 through 2014. 

 The tables shown below represent HNR Finance’s interest, net of a 33.33 percent royalty, in Venezuela in each of the years. 

S-35 

 • The use of the unweighted 12-month average of the first-day-of-the-month contracted reference price of $56.83 per barrel for oil compared 

to the year-end contracted reference price of $69.87 per barrel for oil. 
Table of Contents 

S-36 

 

 Minority 

 Interest in 32% 

 HNR Finance Venezuela Net Total 

 (in thousands) 

Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls) 

 

As of December 31, 2009 

Proved Reserves at January 1, 2009 42,809 (8,561 ) 34,248 

Revisions (875 ) 175 (700 ) 

Extensions 7,574 (1,515 ) 6,059 

Production (2,089 ) 418 (1,671 ) 

    

Proved Reserves at end of the year 47,419 (9,483 ) 37,936 

 

 

 

 

 

 

 

 

As of December 31, 2009 Proved 

Developed 14,242 (2,848 ) 11,394 

Undeveloped 33,177 (6,635 ) 26,542 

    

Total Proved 47,419 (9,483 ) 37,936 

 

 

 

 

 

 

 

 

As of December 31, 2008 

Proved Reserves at January 1, 2008 47,261 (9,452 ) 37,809 

Revisions (2,984 ) 597 (2,387 ) 

Production (1,468 ) 294 (1,174 ) 

 

  

 

Proved Reserves at end of the year 42,809 (8,561 ) 34,248 

 

 

 

 

 

 

 

 

Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at: 

December 31, 2008 13,415 (2,683 ) 10,732 

 

As of December 31, 2007 

Proved Reserves at January 1, 2007 — — — 

Additions (a)  50,085 (10,017 ) 40,068 

Production (2,824 ) 565 (2,259 ) 

    

Proved Reserves at end of the year 47,261 (9,452 ) 37,809 

 

 

 

 

 

 

 

 

(a) Petrodelta was formed in 2007 

 

Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at: 

December 31, 2007 14,779 (2,956 ) 11,823 

 

Proved Reserves-Natural gas (MMcf) 

 

As of December 31, 2009 

Proved Reserves at January 1, 2009 67,804 (13,561 ) 54,243 

Revisions (5,862 ) 1,172 (4,690 ) 

Extensions 1,941 (388 ) 1,553 

Production (1,173 ) 235 (938 ) 

    

Proved Reserves at end of the year 62,710 (12,542 ) 50,168 

 

 

 

 

 

 

 
Table of Contents 

 The standardized measure of discounted future net cash flows is presented in accordance with the provisions of the accounting standard on 

disclosures about oil and gas producing activities. 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 an applying the average price during the 12-month period, determined as an unweighted arithmetic 

average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the 

contract, to the estimated future production of year-end proved reserves. Our average prices used were $56.83 per barrel for oil and $1.54 per 

Mcf for gas. 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 table shown below represents HNR Finance’s net interest in Petrodelta. 

S-37 

 

 Minority 

 Interest in 32% 

 HNR Finance Venezuela Net Total 

 (in thousands) 

As of December 31, 2009 Proved 

Developed 24,015 (4,803 ) 19,212 

Undeveloped 38,695 (7,739 ) 30,956 

    

Total Proved 62,710 (12,542 ) 50,168 

 

 

 

 

 

 

 

 

As of December 31, 2008 

Proved Reserves at January 1, 2008 43,084 (8,617 ) 34,467 

Additions 27,574 (5,515 ) 22,059 

Production (2,854 ) 571 (2,283 ) 

 

  

 

Proved Reserves at end of the year 67,804 (13,561 ) 54,243 

 

 

 

 

 

 

 

 

Proved Developed Reserves-Natural gas (MMcf) at: 

December 31, 2008 30,168 (6,034 ) 24,134 

 

As of December 31, 2007 

Proved Reserves at January 1, 2007 — — — 

Additions (a)  50,019 (10,004 ) 40,015 

Production (6,935 ) 1,387 (5,548 ) 

 

  

 

Proved Reserves at end of the year 43,084 (8,617 ) 34,467 

 

 

 

 

 

 

 

 

(a) Petrodelta was formed in 2007 

 

Proved Developed Reserves-Natural gas (MMcf) at: 

December 31, 2007 7,755 (1,551 ) 6,204 

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

S-38 

 

 Minority 

 Interest in 

 HNR Finance Venezuela Net Total 

 (in thousands) 

December 31, 2009 

Future cash inflows from sales of oil and gas $ 2,772,840 $ (554,568 ) $ 2,218,272 

Future production costs (630,225 ) 126,045 (504,180 ) 

Future development costs (282,306 ) 56,461 (225,845 ) 

Future income tax expenses (886,622 ) 177,324 (709,298 ) 

    

Future net cash flows 973,687 (194,738 ) 778,949 

Effect of discounting net cash flows at 10% (473,317 ) 94,663 (378,654 ) 

 

 

  

Standardized measure of discounted future net cash flows $ 500,370 $ (100,075 ) $ 400,295 

 

 

 

 

 

 

 

 

December 31, 2008 

Future cash inflows from sales of oil and gas $ 1,576,312 $ (315,262 ) $ 1,261,050 

Future production costs (557,043 ) 111,409 (445,634 ) 

Future development costs (306,500 ) 61,300 (245,200 ) 

Future income tax expenses (355,746 ) 71,149 (284,597 ) 

    

Future net cash flows 357,023 (71,404 ) 285,619 

Effect of discounting net cash flows at 10% (217,822 ) 43,564 (174,258 ) 

    

Standardized measure of discounted future net cash flows $ 139,201 $ (27,840 ) $ 111,361 

 

 

 

 

 

 

 

 

December 31, 2007 

Future cash inflows from sales of oil and gas $ 3,650,110 $ (730,022 ) $ 2,920,088 

Future production costs (685,368 ) 137,074 (548,294 ) 

Future development costs (358,759 ) 71,752 (287,007 ) 

Future income tax expenses (1,274,005 ) 254,801 (1,019,204 ) 

    

Future net cash flows 1,331,978 (266,395 ) 1,065,583 

Effect of discounting net cash flows at 10% (677,756 ) 135,551 (542,205 ) 

 

 

  

Standardized measure of discounted future net cash flows $ 654,222 $ (130,844 ) $ 523,378 

 

 

 

 

 

 

 

 TABLE VI – Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (in thousands): 

 

 Net Venezuela 

 2009 2008 

Standardized Measure at January 1 $ 111,361 $ 523,378 

Sales of oil and natural gas, net of related costs (80,725 ) (54,988 ) 

Revisions to estimates of proved reserves 

Net changes in prices, development and production costs 408,054 (673,320 ) 

Quantities (25,424 ) (119,678 ) 

Extensions, discoveries and improved recovery, net of future costs 187,636 50,515 

Accretion of discount 24,940 106,481 

Net change in income taxes (262,214 ) 457,582 

Development costs incurred 26,756 7,791 

Changes in estimated development costs (429 ) 13,128 

Timing differences and other 10,340 (199,528 ) 

   

Standardized Measure at December 31 $ 400,295 $ 111,361 

 

 

 

 

 
Table of Contents 

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. 

 Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the 16 th day of 

March, 2010, on behalf of the registrant and in the capacities indicated: 

S-39 

 

 HARVEST NATURAL RESOURCES, INC. 

 (Registrant) 

 

 

Date: March 16, 2010 By: /s/ James A. Edmiston 

 James A. Edmiston 

 Chief Executive Officer 

 

 

Signature Title 

 

 

/s/ James A. Edmiston 

 

 

 Director, President and Chief Executive Officer 

James A. Edmiston (Principal Executive Officer) 

 

/s/ Stephen C. Haynes 

 

Stephen C. Haynes 

 

 

 

Vice President — Finance, Chief Financial Officer 

and Treasurer (Principal Financial Officer and 

Principal Accounting Officer) 

 

/s/ Stephen D. Chesebro’ 

 

Stephen D. Chesebro’ 

 

 

Chairman of the Board and Director 

 

/s/ Igor Effimoff 

 

Igor Effimoff 

 

 

Director 

 

/s/ H. H. Hardee 

 

H. H. Hardee 

 

 

Director 

 

/s/ R. E. Irelan 

 

R. E. Irelan 

 

 

Director 

 

/s/ Patrick M. Murray 

 

Patrick M. Murray 

 

 

Director 

 

/s/ J. Michael Stinson 

 

J. Michael Stinson 

 

 

Director 
Table of Contents 

SCHEDULE II 

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

Valuation and Qualifying Accounts 

(in thousands) 

S-40 

 

 Additions 

 Balance at Charged to Other Deductions From Balance at End of 

 Beginning of Year Charged to Income Accounts Reserves Year 

At December 31, 2009 

Amounts deducted from applicable assets 

Accounts receivable $ 2,757 $ — $ 2,757 $ — $ — 

Deferred tax valuation allowance 7,841 9,184 — — 17,025 

Investment at cost 1,350 — — — 1,350 

At December 31, 2008 

Amounts deducted from applicable assets 

Accounts receivable $ 2,757 $ — $ — $ — $ 2,757 

Deferred tax valuation allowance 1,782 6,059 — — 7,841 

Investment at cost 1,350 — — — 1,350 

At December 31, 2007 

Amounts deducted from applicable assets 

Accounts receivable $ 2,757 $ — $ — $ — $ 2,757 

Deferred tax valuation allowance 33,704 (31,922 ) — — 1,782 

Investment at cost 1,350 — — — 1,350 
Table of Contents 

SCHEDULE III 

Financial Statements and Notes 

for Petrodelta, S.A. 

S-41 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Financial Statements at December 31, 2009 and 2008 

and Independent Auditor’s Report 

 
 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Index 

 

 

 Pages 

INDEPENDENT AUDITOR’S REPORT 1 - 2 

 

FINANCIAL STATEMENTS AS OF DECEMBER 31 2009 AND 2008 

 

Statements of financial position 3 

Statements of comprehensive income 4 

Statements of changes in equity (expressed in thousands of US dollars) 5 

Statements of changes in equity (expressed in thousands of US bolivars) 6 

Cash flow statements 7 

 

Notes to the financial statement 

 

Nota 1 Reporting Entity 8 

Note 2 Basis of Preparation 10 

Note 3 Summary of Significant Accounting Policies 12 

Note 4 Exchange Agreement with the Central Bank of Venezuela (BCV) 22 

Note 5 Determination of Fair Values 22 

Note 6 Financial Risk Management 23 

Note 7 Taxes 24 

Note 8 Property, Plant and Equipment, Net 29 

Note 9 Accrual for Asset Retirement Obligations 32 

Note 10 Prepaid Expenses and Other Assets 33 

Note 11 Inventories 33 

Note 12 Accounts Receivable 33 

Note 13 Cash and cash equivalents 34 

Note 14 Equity 34 

Note 15 Accounts Payable 36 

Note 16 Accruals and Other Payables 37 

Note 17 Financial Instruments 38 

Note 18 Commitments and Contingencies 41 

Note 19 Related Party Transactions 42 

Note 20 Laws, Resolutions and Legal Contributions 44 

Note 21 Subsequent events 46 

Note 22 Subsequent events after Independent Accountants Opinion 47 

Note 23 Supplementary Information on Oil and Gas Exploration and Production Activities (unaudited) 47 
Table of Contents 

 

INDEPENDENT AUDITOR’S REPORT 

To the Stockholders and Board of Director of 

Petrodelta, S.A. 

We have audited the accompanying financial statements of PETRODELTA, S.A., which comprise the statement of financial position as at 

December 31, 2009 and 2008, and the statements of comprehensive income, statements of changes in equity and statements of cash flow for the 

years then ended, and a summary of significant accounting policies and other explanatory notes. 

Management’s Responsibility for the Financial Statements 

Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial 

Reporting Standards. This responsibility includes: designing, implementing and maintaining internal control relevant to the preparation and fair 

presentation of financial statements that are free from material misstatement, whether due to fraud or error; selecting and applying appropriate 

accounting policies; and making accounting estimates that are reasonable in the circumstances. 

Auditor’s Responsibility 

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. These 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 involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures 

selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether 

due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair 

presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of 

expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting 

policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial 

statements. 

Urbanización Valles de Camoruco. Las 4 Avenidas. Reda Building. Torre B. Oficina 5-11. Valencia. Carabobo. Venezuela. 

Telf.: 58-241 8253518 / 8255337 Fax: 8259828. RIF: J-30785734-0 

PGFA Perales, Pistone & Asociados es firma miembro de International 

 
Table of Contents 

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. 

Opinion 

In our opinion, the financial statements present fairly, in all material respects, the financial position of Petrodelta, S.A. as of December 31, 2009 

and 2008, and of its financial performance and its cash flows for the year then ended in accordance with International Financial Reporting 

Standards. 

Emphasis of matter 

Without qualifying our opinion as indicated in Note 19 to the financial statements, the Company belongs to a group of related companies and 

conducts transactions and maintains balances for significant amounts with other members of the group, with significant effects on the results of 

its operations and financial position. Because of those relationships, these transactions may have taken place on terms other than those that 

would characterize transactions between unrelated companies. 

Por PGFA PERALES, PISTONE & ASOCIADOS 

José G. Perales S. 

C.P.C. No 9.578 

Valencia, January 22, 2010 

Except for the matters indicated in Note 22, whose date is February 26, 2010 

2 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Statements of Financial Position 

(Expressed In Thousands) 

The accompanying notes from 1 to 23 are an integral part of these financial statements 

3 

 

 December 31 st 

, 

 Note 2009 2008 2009 2008 

 U.S. dollars Bolivars 

Assets 

 

Property, plant and equipment, net 8 265,442 211,760 570,698 455,284 

Deferred income tax 7-(a) 141,245 97,323 303,676 209,244 

     

 

Total non-current assets 406,687 309,083 874,374 664,528 

 

  

  

 

Prepaid expenses and other assets 10 559 21,477 1,202 46,176 

Inventories 11 21,472 14,391 46,167 30,941 

Accounts receivable 12 379,732 267,786 816,425 575,740 

Cash and cash equivalents 13 3,062 7,363 6,582 15,830 

     

 

Total current asset 404,825 311,017 870,376 668,687 

     

 

Total assets 811,512 620,100 1,744,750 1,333,215 

 

 

 

 

 

 

 

 

 

 

Equity 

Equity, see statements of changes in equity 14 432,100 340,692 929,013 732,487 

 

  

  

 

Liabilities 

 

Provision for abandonment cost 9 y 16 24,416 19,174 52,492 41,224 

Provision for retirement benefits 16 9,184 1,306 19,746 2,808 

     

 

Total non-current liabilities 33,600 20,480 72,238 44,032 

 

  

  

 

Accounts payable 15 105,332 89,104 226,465 191,574 

Dividends payable 14 31,126 — 66,921 — 

Accruals and other liabilities 16 154,863 169,824 332,956 365,122 

Income tax payable 7 54,491 — 117,157 — 

     

 

Total current liabilities 345,812 258,928 743,499 556,696 

 

  

  

 

Total liabilities 379,412 279,408 815,737 600,728 

 

 

 

 

 

 

 

 

 

 

Total equity and liabilities 811,512 620,100 1,744,750 1,333,215 

 

 

 

 

 

 

 

 

 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Statements of Comprehensive Income 

(Expressed In Thousands) 

The accompanying notes from 1 to 23 are an integral part of these financial statements 

4 

 

 Years ended December 31 st 

, 

 Note 2009 2008 2009 2008 

 U.S. dollars Bolivars 

Income 

 

Sales of crude oil 451,473 458,113 970,667 984,943 

Sales of gas 6,778 16,506 14,572 35,488 

     

 19 458,251 474,619 985,239 1,020,431 

     

 

Cost and expenses 

 

Operational cost (48,311 ) (77,609 ) (103,869 ) (166,859 ) 

Depletion, depreciation and amortization 8 (32,571 ) (24,778 ) (70,029 ) (53,273 ) 

Sales, general and administrative expenses (10,841 ) (6,705 ) (23,307 ) (14,416 ) 

Royalties 7 — (b) (157,681 ) (225,167 ) (339,014 ) (484,109 ) 

Financial expenses (3,617 ) (2,329 ) (7,777 ) (5,007 ) 

     

 (253,021 ) (336,588 ) (543,996 ) (723,664 ) 

     

 

Profit before tax 205,230 138,031 441,243 296,767 

 

Income tax expense 7 — (a) (61,946 ) (16,814 ) (133,184 ) (36,150 ) 

  

 

 

 

 

Profit and total comprehensive income for the year 143,284 121,217 308,059 260,617 

 

 

 

 

 

 

 

 

 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Statements of changes in equity 

Years ended December 31, 2009 and 2008 

(Expressed In Thousands of US dollar) 

The accompanying notes from 1 to 23 are an integral part of these financial statements 

5 

 

 Retained earnings 

 Shareholder Legal reserve and 

 Note Capital stock contribution Share premium other reserves Distributable Total 

Balances at December 31, 2007 465 6,512 212,451 47 181,325 400,800 

 

Profit and total comprehensive 

income for the year — — — — 121,217 121,217 

 

Shareholders contribution 

capitalization 14 6,512 (6,512 ) — — — — 

 

Appropriation to legal reserve 14 — — — 651 (651 ) — 

 

Dividends declared 14 — — — — (181,325 ) (181,325 ) 

       

 

Balances at December 31, 2008 6,977 — 212,451 698 120,566 340,692 

 

Profit and total comprehensive 

income for the year — — — — 143,284 143,284 

 

Appropriation to other reserves 14 — — — 141,245 (141,245 ) — 

 

Dividends declared 14 — — — — (51,876 ) (51,876 ) 

  

  

   

 

Balances at December 31, 2009 6,977 — 212,451 141,943 70,729 432,100 

 

 

 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Statements of changes in equity 

Years ended December 31, 2009 and 2008 

(Expressed in Thousands of bolivars) 

The accompanying notes from 1 to 23 are an integral part of these financial statements 

6 

 

 Retained earnings 

 Shareholder Legal reserve and 

 Note Capital stock contribution Share premium other reserves Distributable Total 

Balances at December 31, 2007 1,000 14,000 456,770 100 389,846 861,716 

 

Profit and total comprehensive 

income for the year — — — — 260,617 260,617 

 

Shareholders contribution 

capitalization 14 14,000 (14,000 ) — — — — 

 

Appropriation to legal reserve 14 — — — 1,400 (1,400 ) — 

 

Dividends declared 14 — — — — (389,846 ) (389,846 ) 

       

 

Balances at December 31, 2008 15,000 — 456,770 1,500 259,217 732,487 

 

Profit and total comprehensive 

income for the year — — — — 308,059 308,059 

 

Appropriation to other reserves 14 — — — 303,676 (303,676 ) — 

 

Dividends declared 14 — — — — (111,533 ) (111,533 ) 

 

 

 

 

   

 

Balances at December 31, 2009 15,000 — 456,770 305,176 152,067 929,013 

 

 

 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

PETRODELTA, S.A 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Statements of Cash Flow 

(Expressed In Thousands) 

The accompanying notes from 1 to 23 are an integral part of these financial statements 

7 

 

 Years ended December 31 st 

, 

 2009 2008 2009 2008 

 U.S. dollars Bolivars 

Cash flow from operating activities 

Profit and total comprehensive income for the year 143,284 121,217 308,059 260,617 

     

Adjustments to reconcile net income to net cash (used in) provided 

by operating activities - 

Depletion, depreciation and amortization 33,188 25,508 71,352 54,843 

Provision for abandonment cost (3,603 ) (10,866 ) (7,745 ) (23,362 ) 

Deferred income tax (43,922 ) (52,560 ) (94,432 ) (113,004 ) 

Financial cost on provision for abandonment cost 1,639 2,344 3,523 5.039 

Tax credit financial cost 1,792 — 3,853 — 

Net changes in operating assets - 

Accounts receivable (113,738 ) (133,756 ) (244,538 ) (287,575 ) 

Material and supplies Inventories (8,923 ) (10,833 ) (19,185 ) (23,291 ) 

Prepaid expenses and other assets 20,918 (20,604 ) 44,974 (44,299 ) 

Net changes in operating liabilities 

Accounts payable 16,228 321,555 34,891 691,343 

Income taxes payable 54,491 (153,037 ) 117,157 (329,030 ) 

Accruals and other liabilities (3,480 ) 132,090 (7,483 ) 283,994 

     

 

Total adjustments (45,410 ) 99,841 (97,633 ) 214,658 

     

 

Net cash provided by operating activities 97,874 221,058 210,426 475,275 

     

 

Net cash used in investing activities: 

 

Acquisition of property, plant and equipment (81,425 ) (39,347 ) (175,062 ) (84,596 ) 

     

 

Net cash used in investing activities (81,425 ) (39,347 ) (175,062 ) (84,596 ) 

  

 

 

 

 

Net cash provided by (used in) financing activities: 

Paid dividends (20,750 ) (181,325 ) (44,612 ) (389,849 ) 

     

 

Net cash used in financing activities (20,750 ) (181,325 ) (44,612 ) (389,849 ) 

     

 

Net cash increase (4,301 ) 386 (9,248 ) 830 

 

Cash and equivalents at the beginning of the period 7,363 6,977 15,830 15,000 

  

 

 

 

 

Cash and equivalents at the end of the period 3,062 7,363 6,582 15,830 

 

 

 

 

 

 

 

 

 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

8 

(1) Reporting Entity 

 

 Petrodelta, S.A. (the Company) was incorporated in Venezuela in October 2007, as published in Official Gazette No. 38,786. Its business 

objective is primary exploration to discover oil reserves, extraction of oil in its natural state, and its subsequent collection, transportation and 

storage pursuant to Article No. 9 of the Venezuelan Hydrocarbon Law (LOH). The Company operates within an area of approximately 

1,000 square kilometers in the Uracoa, Bombal and Tucupita fields (formerly the Monagas Sur Unit) and in the El Salto, El Isleño and 

Temblador fields in the Monagas and Delta Amacuro states in Venezuela (the assigned operating area). 

 

 The Company was created as a result of the process for conversion into mixed-capital companies of the Operating Agreement signed on 

July 31, 1992 between PDVSA Petróleo, S.A. (PDVSA Petróleo) (formerly Lagoven, S.A.), Harvest Natural Resources, Inc. (Harvest) 

(formerly Benton Oil and Gas Company) and Venezolana de Inversiones y Construcciones Clérico, C.A. (Vinccler). As part of this process, 

on March 31, 2006, PDVSA Petróleo, S.A., Corporación Venezolana del Petróleo, S.A. (CVP) and Harvest Vinccler, S.C.A. (HVSCA), the 

agreement operator and a related company of Harvest and Vinccler, signed a memorandum of understanding for conversion into a mixed 

company. In June 2007, the National Assembly of the Bolivarian Republic of Venezuela approved the incorporation of the mixed company 

Petrodelta, S.A. In August 2006, the National Assembly approved the inclusion of the Temblador, El Isleño and El Salto areas into the 

Monagas Sur Unit for further development of the Company’s primary activities. An agreement for conversion into a mixed company was 

signed between CVP and HNR Finance B.V. (HNR Finance) in September 2007. The Company will operate for 20 years as from 

October 2007 when the decree for transfer of field operations was published in the Official Gazette. 

 

 Petrodelta, S.A. is 60%-owned by CVP, a wholly owned subsidiary of Petróleos de Venezuela, S.A. (PDVSA), and 40%-owned by HNR 

Finance. 

 

 The Company was incorporated and is domiciled in Venezuela. Its legal address is: Avenida Veracruz con Calle Cali, Urbanización Las 

Mercedes, Edificio Pawa, Piso 5, Caracas, Distrito Capital. Its main offices are located at Avenida Alirio Ugarte Pelayo, Edificio Harvest 

Vinccler, Ala Norte, Planta Baja in Maturín, Monagas State. 

 

 On February 26, 2010, the Board of Directors of the Company approved the issuance of the financial statements under International 

Financial Reporting Standards and submitted said financial statements to the Shareholders of the Company for approval purposes. Once the 

aforementioned financial statements are duly approved and issued, no amendment of which applies. 

 

 Company management considers that it operates in a single business segment (hydrocarbons) in one country, the Bolivarian Republic of 

Venezuela, in conformity with its social statutes. 

 

 During the transition period from April 1, 2006 to December 31, 2007, Harvest Vinccler, S.C.A. (HVSCA) was in charge of managing and 

developing the Company’s activities and provided its financial and operational structure for this purpose. The Company’s operating costs 

during this period were paid by HVSCA and CVP and subsequently charged to PDVSA Petróleo, which, in 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

9 

 turn, will bill the Company. These costs were recognized in the income statements for the respective periods and include, but are not limited 

to, general, administrative, operating and capital expenses required to continue activities in the assigned operating area. At December 31, 

2009 the Company had not received all information regarding production during the conversion period for the Temblador field in order to 

invoice all volumes produced in that field during that period. As Temblador production was handled in PDVSA system, PDVSA had 

allocated only partial, estimated production to Petrodelta. As a result, Petrodelta had not, and still has not, received full credit for the 

Temblador field production. Discussions are ongoing to settle figures. During the third quarter 2009, Petrodelta completed the facilities and 

pipelines to segregate approximately 80 percent of the Temblador field’s production out of PDVSA’s system. 

 

 During the years ended December 31, 2009 and 2008, the Company has operated with employees assigned by its shareholders or their 

related companies since it has no direct employees. At December 31, 2009, the Company had 356 employees assigned by its shareholders or 

their related companies. During the first quarter of 2008, 238 employees were transferred from HVSCA to PDVSA. 

 

 During 2009 the Company drilled 18 development wells, produced approximately 7.8 million barrels of oil and sold 4.4 billion cubic feet of 

natural gas. Petrodelta’s reserves increased primarily by the drilling of two appraisal wells in the largely undeveloped El Salto field. 

Production was initiated from El Salto field during the month of July 2009 with the drilling and completion of one well which has produced 

349,000 barrels of oil through the end of 2009. 

 

 Applicable regulations 

 

 The Company’s main activities are regulated by the Venezuelan Hydrocarbon Law (LOH), effective from January 2002. Gas-related 

operations are regulated by the Venezuelan Gaseous Hydrocarbon Law of September 1999 and its Regulations of June 2000. 

 

 Below are the main regulations included in the LOH:

 a) A 30% royalty on volumes of hydrocarbon extracted. 

 

 b) A Partial Reform of the Extraction Tax was enacted and published in Official Gazette No. 38,443 of May 24, 2006, establishing a rate 

equivalent to one-third of the value of all liquid hydrocarbons extracted from any reservoir, calculated on the same basis as royalties. 

The taxpayer has the right to deduct from the extraction tax any sum payable as royalties (30%), including the additional royalty paid 

for special advantages (3.33%). 

 

 c) A surface tax equivalent to 100 tax units for each square kilometer or fraction thereof per year for licensed areas that are not under 

production. This tax will increase by 2% during the first five years, and by 5% during all subsequent years. Company management 

considers that there are no nonproductive areas. 

 

 d) An internal consumption tax equivalent to 10% of the value of each cubic meter of hydrocarbon derivatives produced and consumed as 

fuel in internal operations, calculated on 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

 Hydrocarbon purchase sale agreement 

10 

 the final selling price. Company management considers that, other than associated gas, no hydrocarbon derivatives are consumed. 

 The Company signed a hydrocarbon purchase sale agreement with PDVSA Petróleo, whereby the Company undertakes to sell to the latter 

all hydrocarbons produced within the delimited operating area that are not being used in its operations. The Company may assign or 

transfer this agreement, or any rights and obligations thereunder, to another company in accordance with Article No. 27 of the LOH. This 

agreement is for 20 years. 

(2) Basis of Preparation 

 (a) Statement of compliance 

 

 The financial statements as of December 31, 2009 and 2008 are prepared in accordance with International Financial Reporting 

Standards (IFRS) adopted by the International Accounting Standards Board (IASB) and their interpretations, issued by the International 

Financial Reporting Interpretations Committee (IFRIC) of the IASB. 

 

 The financial statements for the year ended December 31, 2008 have been prepared and are presented for purposes of comparison with 

the financial statements for the year ended December 31, 2009. 

 

 (b) Basis of measurement 

 

 The financial statements have been prepared on the historic cost basis, except for certain assets and liabilities measured at fair value. 

Assets measured and stated at fair value are: recoverable tax credits, accounts receivable and cash. 

 

 The methods used for measuring fair value are discussed in Note 5. 

 

 (c) Functional and presentation currency 

 

 The financial statements are presented in U.S. dollars, the Company’s functional currency, since the main economic environment in 

which the Company operates is the international market for crude oil and its products. In addition, a significant portion of its revenues, 

as well as most costs, expenses and investments are denominated in this currency. 

 

 The financial statements in bolivars are presented for statutory purposes. The Company’s financial statements are translated into 

bolivars, a currency other than the functional currency, in accordance with International Accounting Standard No. 21 The Effects of 

Changes in Foreign Exchange Rates. This standard requires each entity to determine its functional currency based on an analysis of the 

primary economic environment in which the entity operates, which is normally the one in which it primarily generates and expends 

cash. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

11 

 The financial statements are translated into bolivars based on the following criteria: 

 - Assets and liabilities of each statement of financial position at the exchange rates in effect at date. 

 

 - Income and expenses at the average exchange rate for each year. 

 

 - Exchange gains or losses resulting from translation are recognized as a separate equity component under Cumulative translation 

adjustment. During the year ended December 31, 2009 and 2008 the official exchange rate did not change. Consequently, a 

cumulative translation adjustment was not originated. 

 All financial information presented in U.S. dollars has been rounded in thousands. 

 (d) Use of estimates, risks and uncertainty 

 

 The preparation of financial statements in conformity with IFRS requires management to make estimates, judgments and assumptions 

that affect the application of accounting policies and the amounts of assets, liabilities, income and expense. The Company applies its 

best estimates and judgments; however, actual results may differ from initial estimates. 

 

 The related estimates and assumptions are based on experience and other factors which are considered reasonable under current 

circumstances and form the basis for making judgments on the carrying value of assets and liabilities not easily determined by other 

means. Estimates and assumptions are reviewed periodically, and revisions to accounting estimates are recognized in the period in 

which the estimate is revised and in any future periods affected. 

 

 Significant areas of uncertainty affecting management’s estimates and judgment in the application of accounting policies, which 

significantly affect financial statement amounts are: 

 - Note 8 — Depletion, depreciation and amortization 

 

 - Note 7 — Deferred income tax 

 

 - Note 9 — Provision for abandonment costs 

 

 - Note 17 — Valuation of financial instruments 

 

 - Note 3 -s- Measurement of contract-based retirement benefit obligations and other post-retirement benefits other than pensions, 

which are being calculated by PDVSA for subsequent billing to the Company. 

 

 - Note 18 — Liabilities, contingencies and accruals in respect of environmental issues 

 The Company’s operations may be affected by the political, legislative, regulatory and legal environment, both at the national and 

international level. In addition, significant changes in 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

12 

 prices or availability of crude oil and its products may have an impact on the Company’s results of operations in any given year. 

(3) Summary of Significant Accounting Policies 

 

 The accounting policies used for the preparation of these financial statements have been applied consistently for all periods presented. 

 (a) Transactions in currencies other than the U.S dollar 

 

 Transactions in currencies other than the U.S. dollar are translated into the Company’s functional currency using the exchange rate in 

effect at the transaction date. Monetary assets and liabilities denominated in currencies other than the U.S. dollar are translated into U.S. 

dollars using the exchange rate prevailing at the date of the statement of financial position. Exchange gains or losses on monetary items 

in currencies other than the U.S. dollar represent the difference between the net cost in the functional currency at the beginning of the 

year, adjusted by the effective interest rate and payments made during the year, and the net cost in currencies other than the U.S. dollar 

translated using the year-end exchange rate. Nonmonetary assets and liabilities in currencies other than the U.S. dollar stated at fair 

value are retranslated to the functional currency using the exchange rate prevailing at the date fair value was determined. Exchange 

gains or losses resulting from retranslation are recognized in the statement of comprehensive income. 

 

 (b) Financial instruments 

 

 Non-derivative financial instruments consist of cash and cash equivalents, recoverable tax credits, accounts receivable, accounts 

payable to suppliers and other liabilities. 

 

 Non-derivate financial instruments classified as at fair value through profit or loss are initially recognized at fair value, plus any direct 

transaction costs. 

 

 A financial instrument is recorded when the Company engages or commits to the contractual clauses thereof. Financial assets are 

reversed if the Company’s contractual rights over the asset’s cash flows expire or if the Company transfers the financial asset to another 

entity without retaining control or a significant portion of the asset’s risks and rewards. Regular purchases and sales of financial assets 

are accounted for at trade date, which is generally the date on which the Company commits to purchase or sell the asset. Financial 

liabilities are derecognized when the Company’s specific contractual obligation expires or is paid. 

 

 During the years ended December 31, 2009 and 2008, the Company conducted no transactions with derivative instruments. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

13 

 (c) Property, plant and equipment 

 

 Property, plant and equipment are stated at cost, net of accumulated depreciation and impairment losses (See Note 8). The successful 

efforts accounting method is used for exploration and production activities of crude oil and natural gas. All costs for development wells, 

related plant and equipment, and property used for oil recovery are capitalized. Costs of exploratory wells are capitalized until it is 

determined whether they are commercially feasible; otherwise, such costs are charged to operating expenses. Other exploratory 

expenditures, including geological and geophysical costs, are expensed as incurred. Costs for major maintenance or general repairs are 

capitalized when identified as a separate component of the asset to which such maintenance and repair corresponds and are depreciated 

between one maintenance period and the other. Disbursements for minor maintenance, repairs and renewals incurred to maintain 

facilities in operating conditions are expensed. Gains or losses arising from asset retirement or disposal are included in the income 

statement. 

 

 The cost of property, plant and equipment also includes, when relevant, the amounts associated with asset retirement obligations (See 

Note 8). 

 

 Finance costs of projects requiring major investments over long-term construction periods and those incurred for specific projects are 

capitalized and amortized over the estimated useful lives of the related assets. 

 

 The cost of assets built by the Company includes materials and direct labor, as well as any other direct cost attributable to bringing the 

asset to working condition. Costs for dismantling and removal from the construction site are also included. All disbursements relating to 

construction or purchase of property, plant and equipment in the stage prior to implementation are stated at cost as work in progress. 

Once the assets are ready for use, they are transferred to the respective component of property, plant and equipment and depreciation or 

amortization commences. 

 

 When parts of a property, plant and equipment asset have different useful lives, they are recorded separately as a significant component 

of that asset. 

 

 Gains or losses on disposal of a property, plant and equipment item are determined by the difference between the proceeds from 

disposal, if any, and the net carrying amount of the asset, and is recognized under other income (expense), net in the statement of 

comprehensive income. 

 

 Depreciation and amortization of capitalized costs related to wells and facilities for the production of crude oil and gas are determined 

by the units of production method by field, based on proved developed reserves. The rates used are reviewed annually based on an 

analysis of reserves and are applied retroactively at the beginning of the year. Capitalized costs of other plant and equipment are 

depreciated over their estimated useful lives, mainly using the straight-line method with an average useful life of 15 years for 

administrative 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

14 

 buildings and between 3 and 5 years for the remaining assets. Ordinary withdrawals are eliminated against the respective accumulated 

depreciation; net gains or losses from extraordinary withdrawals are included in the statement of comprehensive income. 

 

 Depreciation methods and average useful lives of property, plant and equipment are reviewed annually. 

 

 Certain materials and supplies accounted for as inventory and considered strategic since they will be used as spare parts for two years 

operation in the production facilities and in specific investment projects are reported under property, plant and equipment. 

 (d) Inventories 

 

 Inventories are stated at the lower of cost and net realizable value. The cost of inventories of crude oil and its products is determined 

using the average cost method. Materials and supplies are valued mainly at average cost, less an allowance for possible losses, and are 

classified into two groups: current assets and non-current assets. 

 

 Net realizable value is the estimated selling price in the normal course of business, less costs to complete and estimated selling costs. 

 

 (e) Trade accounts receivable 

 

 Trade accounts receivable are accounted for according to price formulas established in the hydrocarbon purchase sale agreement 

between the mixed companies and PDVSA Petróleo, whereby the former undertake to sell and PDVSA Petróleo undertakes to buy all 

hydrocarbons produced that are not being used in their operations within the delimited operating areas. At December 31, 2009 and 

2008, the Company does not expect to incur losses on uncollectible accounts and, therefore, has not set aside a provision in this 

connection. 

 

 (f) Cash and cash equivalent 

 

 Petrodelta, S.A. considers as cash and cash equivalents placements and time deposits maturing within three months that are readily 

convertible. 

 

 (g) Impairment in the value of long-lived assets 

 

 Financial assets 

 

 The Company assesses possible impairment in the value of its financial assets at each reporting date. A financial asset is impaired if 

there is objective evidence that one or more events have had a negative effect on the estimated future cash flows of the asset. 

 

 Significant financial assets are assessed individually to determine their impairment. All other financial assets sharing similar credit risk 

characteristics are evaluated as a group. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

15 

 Impairment losses are recognized in the statement of comprehensive income. An impairment loss is reversed if it can be objectively 

associated with an event occurring after the impairment loss was recognized. 

 

 Non-financial assets 

 

 The carrying value of non-financial assets, excluding inventories and deferred tax, is reviewed for possible impairment at each reporting 

date. The recoverable amount of the asset is estimated if evidence of impairment exists. 

 

 An impairment loss is recognized for the amount by which the asset’s carrying amount or its cash-generating unit exceeds its 

recoverable amount. A cash-generating unit is the assets grouped at the lowest levels for which there are separately identifiable cash 

flows. Recoverability of assets to be held and used is measured by comparing their carrying amount to the net discounted future cash 

flows expected to be generated by these assets. If the carrying amount of the assets exceeds the estimated value of discounted future 

cash flows, an impairment loss is recognized in the income statement in the amount of such excess. The asset cost is shown net of this 

impairment charge. Impairment is determined by the Company based on cash-generating units, in accordance with its business 

segments, geographical locations and the final use of the production generated by each unit. Impairment losses may be reversed only if 

there has been a change in the estimates used after the impairment loss was recognized. 

 (h) Costs associated with asset retirement obligations 

 

 The Company capitalizes estimated costs associated with obligations from retirement of assets used for exploration and crude oil and 

natural gas production activities, based on the future retirement plan for those assets. Cost is capitalized as part of the related long-lived 

asset and is amortized over its useful life with a charge to operating costs. 

 

 Obligations associated with the retirement of long-lived assets are recorded at fair value as incurred, based on discounted future cash 

flows. Fair value is determined based on current regulations and technologies. 

 

 (i) Income tax 

 

 Income tax expense comprises current and deferred tax. Income tax expense is recognized in the results for each year, except for items 

that should be directly recognized in other comprehensive income. 

 

 Current tax is the estimated amount payable based on taxable income for the year, using the tax rate and the methodology established in 

current regulations at the balance sheet date and any adjustment to taxes payable from previous years.
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

16 

 Deferred income tax is accounted for using the balance sheet method. Deferred assets and liabilities are recognized for future tax 

consequences attributable to differences between the carrying amounts of assets and liabilities and their respective tax bases, and 

operating loss and tax credit carryforwards. The value of deferred assets and liabilities is determined based on tax rates expected to be 

applicable to taxable income for the year in which temporary differences will be recovered or settled pursuant to law. The effect on 

deferred assets and liabilities of changes in tax rates is recorded in the results for the year in which such changes become effective. 

A deferred tax asset is recognized only to the extent that future taxable income will be available for offsetting. Deferred tax assets are 

reviewed at each reporting date and reduced to the extent that it is no longer probable that the related tax benefit will be realized. 

 (j) Provisions 

 

 A provision is recorded if as a result of a past event the Company has a present legal or constructive obligation that can be reliably 

estimated and it is probable that an outflow of economic benefits will be required to settle the obligation. 

 

 In conformity with the environmental policy established by PDVSA and current legislation, the Company recognizes a liability when 

costs are likely and can be reasonably estimated. Environmental expenditures that relate to income from current or future operations are 

recorded as expenses or assets, as applicable. Expenditures that relate to past operations that do not contribute to current or future 

revenue generation are expensed. These provisions are created when an obligation related to environmental remediation is identified, in 

respect of which the Company has the necessary information to determine a reasonable estimate of the related cost. Subsequent 

adjustments, if required, are made upon receipt of additional information. 

 

 (k) Revenue recognition 

 

 Income from sales of crude oil and gas is recorded in the statement of comprehensive income when risks and significant rights of 

ownership are transferred to PDVSA Petróleo and MPPEP as stipulated in the hydrocarbon purchase sale agreement. Income is 

recognized when it can be reasonably measured and it is probable that future economic benefits will flow to the Company. Income from 

activities other than the Company’s main business is recognized when realized. Income is not recognized when there is significant 

uncertainty as to the recoverability of the obligation acquired by the buyer. All of the Company results are from continuing operations. 

 

 (l) Capital stock 

 

 Common shares are classified as equity. For the years ended December 31, 2009 and 2008, the Company has no preferred shares (See 

Note 14). 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

17 

 (m) Share premium 

 

 The Company recognizes as share premium any excess in the value of contributions made by shareholders for Company incorporation 

over the par value at the incorporation date (See Note 14). 

 

 (n) Legal reserve 

 

 The Venezuelan Code of Commerce requires companies to set aside 5% of their net income each year to a legal reserve until it reaches 

an amount equivalent to at least 10% of their capital stock in bolivars (See Note 14). 

 

 (o) Other equity reserves 

 

 The Company has the policy of transferring from retained earnings to other equity reserves the balance of deferred tax account when 

the latter is an asset. This reserve is recognized in retained earnings to the extent that such asset gets realized when the temporary 

differences that gave rise to it are deducted for tax purposes and consequently would be available for dividend payments. 

 

 (p) Dividend distribution 

 

 Dividend distribution to the Company’s shareholders is recognized as a liability in the financial statements in the period in which the 

dividends are approved by the shareholders. 

 

 (q) Accounting estimates requiring a high degree of judgment 

 

 The Company continually evaluates judgments used to record its accounting estimates, which are recorded based on historical 

experience and other factors, including expectation of future events that are believed to be reasonable under the circumstances. 

Significant future changes to assumptions established by management may significantly affect the carrying value of assets and 

liabilities. 

 

 Below is a summary of the most significant accounting estimates made by the Company: 

 

 Estimates of oil reserves 

 

 Oil and gas reserves are key elements in the Company’s decision-making process. They are also important in evaluating impairment in 

the carrying amount of long-lived assets. Calculation of depreciation, amortization and depletion of property, plant and equipment 

accounts related to hydrocarbon production requires quantification of proved developed hydrocarbon reserves expected to be recovered 

by the Company in the future. Reserve estimates are only approximate amounts due to the high degree of judgment and specialization 

required to develop the information. Reserves are calculated by specialized technical departments at Petróleos de Venezuela, S.A. 

(PDVSA) (related company that owns the Company’s main shareholder) and results are submitted for approval by MPPEP 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

18 

 in order to guarantee the reasonableness of the information. Additionally, reserve studies are regularly updated to guarantee that any 

change in estimates is timely recorded in the Company’s financial statements. 

 

 To date, reserves studies assigned to the Company are currently under revision, update and certification. 

 

 Assessment of impairment in the value of property, plant and equipment 

 

 Management annually assesses impairment in the value of property, plant and equipment. The main key assumptions considered by 

management to determine the recoverable amount of property, plant and equipment were income projections, oil prices, royalties, 

operating and capital costs and the discount rate. Projections include proved developed reserves to be produced during the development 

period of production activities in the assigned fields. At December 31, 2009 and 2008, the Company has not identified impairment in 

the carrying value of property, plant and equipment as a result of these estimates. 

 

 Abandonment cost calculation 

 

 The Company’s financial statements include an asset and a provision for property, plant and equipment used in hydrocarbon production 

that is expected to be abandoned in the future and in relation to which the Company will make future disbursements. Assumptions 

considered for the calculation of this asset and the provision for abandonment (asset abandonment costs, date of abandonment, and 

inflation and discount rates) may vary depending on factors such as performance in the field, changes in technology and legal 

requirements. Assumptions made by the Company are recorded based on technical studies and management’s experience and are 

regularly reviewed (See Note 9). 

 (r) Related party transactions 

 

 The Company does not disclose, as part of balances and transactions with related companies (See Note 19), transactions with 

government entities conducted in the normal course of business, the terms and conditions of which are consistently applied to other 

public and private entities and for which there are no other suppliers, i.e., electricity, telecommunications, taxes, etc. 

 

 (s) Accrual for employee benefits 

 

 Following corporate instructions from PDVSA, the related company PDVSA, S.A. assumed the employer role for employees who 

accepted the transfer, and are working as assigned employees to Petrodelta, S.A. operations. According to this, PDVSA Petróleo, S.A. 

administer and prepare those employees’ payroll and invoice direct payroll and benefits of the Company, which recognize those costs 

against a liability to PDVSA Petróleo, S.A. The direct payroll and benefits costs are determined by PDVSA according the following 

policies: 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

19 

 Termination benefits 

 

 The Company accrues for its liability in respect of employee termination benefits based on the provisions of the Venezuelan Labor Law 

and the prevailing oil-sector collective labor agreement. Under certain circumstances, the Law provides for an additional indemnity for 

unjustified dismissals. Most of this accrual for indemnification has been deposited in trust accounts in the name of each employee. 

 

 On October 11, 2007, PDVSA entered into a Collective Labor Agreement, effective through 2009, so improving salaries and labor 

benefits for staff in the contract payroll in Venezuela. Those liabilities resulting of the application of said Collective Labor Agreement 

are in full effect as from November 2007. At the end of 2009, the United Federation of Workers for Oil, Gas and Similar (FUTPV) and 

PDVSA, are waiting for the approval by the president of the Bolivarian Republic of Venezuela to sign the contract for the period 2009 

to 2011 (See Note 21). 

 

 Profit sharing and bonuses 

 

 Liabilities in respect of labor benefits and bonuses for staff, vacation leaves, and other benefits are accounted for as incurred along with 

the staff’s provision of services. 

 

 During the years ended December 31, 2009 and 2008, the Company has not had direct employees and, therefore, has not recorded 

liabilities derived from these labor-related benefits. 

 

 Retirement Plan 

 

 The amount to be provision for retirement benefits is received from PDVSA based on actuary studies. Net liabilities in respect of the 

retirement plan as defined in the contract are accounted for separately per each participant in said plan, by estimating the amount of 

future benefits to be acquired by staff versus their length of service during current and prior periods; said benefits are discounted in 

order to determine their current value, then it is deducted the fair market value of those assets associated to the plan. The discount rate 

reflects the yield rate that, as of the date of the financial statements, is reported through financial instruments issued by credit 

institutions with high ratings and maturity dates that are in line with those due dates applicable to said liabilities. This calculation is 

made by an actuary by using the projected unit credit method. 

 

 Improvements made to the plan’s benefits, in connection with past service cost, are expensed in the statement of profit and loss per the 

estimated period that, on average, will last until the moment said benefits will be paid in full. As said benefits fall under irrevocable 

acquired rights after approval, said expense is recorded, immediately, in the statement of comprehensive income. 

 

 It is accounted for as income or expense the share corresponding to the total of unrecorded actuarial earnings or loss in excess of 10% of 

the greater of these sums: a) the current 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

20 

 value of liabilities in respect of those benefits defined as of that date; and b) the reasonable value of the plan’s assets as of that date. Said 

caps are computed and apply separately per each plan’s benefit so defined. 

 

 Post-retirement benefits other than retirement 

 

 Net liabilities in respect of post-retirement benefits other than retirement, as defined in the contract, equal the total of future benefits 

earned by staff along with their length of service during current and prior periods. Said benefits include mainly: health and dental plans, 

burial and funeral insurance, and food electronic card. Said liabilities are computed by using the projected unit credit method; then they 

are deducted to reflect their current value and, if applicable, the fair market value of related assets is deducted as well. The discount rate 

should reflect the yield rate that, as of the date of the financial statements, is reported through financial instruments issued by credit 

institutions with high ratings and maturity dates that are in line with those due dates applicable to said liabilities. 

 

 Past service cost and the actuarial income or loss are recorded by using the method set out in the retirement plan per the contract. 

 

 The provision for this concept is provided by PDVSA which is based on actuary studies. 

 

 (t) New accounting standards not yet adopted 

 

 Certain new standards, amendments and interpretations to existing standards were not effective for the year ended December 31, 2009 

and have not been applied in the preparation of the Company’s financial statements. The most important standards, amendments and 

interpretations for the Company are as follows: 

 - In November 2009, IASB issued revised IAS 24, Related Party Transactions. This review applies for accounting periods beginning 

on or after January 1, 2011. This version simplify the disclosure requirements for government-related entities and clarifies the 

definition of related parties. 

 

 - In July 2009, IASB issued amendments to IFRS 1 First-time Adoption of International Financial Reporting Standards , effective 

for accounting periods beginning on or after January 1, 2010 with earlier application permitted. IFRS 1 amendments address the 

retrospective application of IFRSs to particular situations and are aimed at ensuring that entities applying IFRSs will not face undue 

cost or effort in the transition process. The amendments 1) exempt entities using the full cost method from retrospective application 

of IFRSs for oil and gas assets; 2) exempt entities with existing leasing contracts from reassessing the classification of those 

contracts in accordance with IFRIC 4 Determining whether an Arrangement contains a Lease when the application of their national 

accounting requirements produced the same result. 

 

 - In April 2009, the IASB published the annual IFRS improvement project that included amendments to certain existing standards 

and interpretations not effective for the year 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

21 

 ended December 31, 2009. The most important standards and interpretations for the Company are: IFRS 2 Share-based Payment ; 

IFRS 5 Non-current Assets held for sale and discounted operations ; IFRS 8 Operating Segments ; IAS 1 Presentation of Financial 

Statements ; IAS 7 Statement of Cash Flows ; IAS17 Leases ; IAS 18 Revenue ; IAS 36 Impairment of Assets ; IAS 38 Intangible 

Assets ; IAS 39 Financial Instruments: recognition and Measurement ; IFRIC 9 Reassessment of Embedded Derivatives ; and 

IFRIC 16 Hedges of a Net Investment in a Foreign Operation. 

 

 - In November 2009, the IASB issued IFRS 9 — Financial Instruments — on the classification and measurement of financial assets. 

Publication of IFRS 9 represents the completion of the first part of a three part project to replace IAS 39 - Financial Instruments: 

Recognition and Measurement. IFRS 9 will be effective for accounting periods beginning on or after January 1, 2013. This standard 

uses a simple approach to determine whether a financial asset is measured at amortized cost or fair value. The new approach is 

based on how an entity manages its financial instruments (its business model) and the contractual cash flow characteristics of the 

financial assets. The standard also requires a single impairment method to be used. 

 The Company completed the analysis of these standards and determined no significant effects on its financial statements. 

 

 (u) Recently adopted accounting pronouncements 

 

 The following standards and interpretations became effective during 2009: 

 - In March 2009, IASB published amendments to IFRIC 9 and IAS 39: Embedded derivatives . The amendment clarifies the 

treatment of embedded derivatives for entities that make use of the reclassification amendment issued by the IASB in October 2008. 

The reclassification amendment allows entities to reclassify particular financial instruments out of the ‘at fair value through profit 

or loss’ category in specific circumstances. The amendments to IFRIC 9 and IAS 39 issued clarify that on reclassification of a 

financial asset out of the ‘at fair value through profit or loss’ category all embedded derivatives have to be assessed and, if 

necessary, separately accounted for in financial statements. 

 

 - In March 2009, IASB published amendments to IFRS 7 — Financial Instruments: Disclosures. The amendments provide enhanced 

disclosure about fair value measurements and reinforce existing principles for disclosures about liquidity risk. Disclosures introduce 

a three-level hierarchy for fair value measurement disclosures and require entities to provide additional disclosures about the 

relative reliability of fair value measurements. These disclosures will help to improve comparability between entities about the 

effects of fair value measurements. 

 

 - In January 2008, the IASB issued revised IAS 32, Financial Instruments: Disclosure and Presentation, which requires certain 

financial instruments to be classified as equity when 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

22 

 they are available and impose an obligation on the Company’s equity. This standard will be effective for accounting periods 

beginning on or after January 1, 2009. 

 

 - In September 2007 the IAS 1, Presentation of Financial Statements was revised and introduced a statement of comprehensive 

income, which includes the profit or loss for the period and other comprehensive income containing income and expense items not 

recognized in the results for the period due to requirements of other standards. In addition, according to this standard, the balance 

sheet will become the statement of financial position since it better reflects the function of the statement and is consistent with the 

terms used in the Concept Framework of International Accounting Standards. 

 

 - In March 2007 was revised IAS 23, Borrowing Costs eliminates the option to expense borrowing costs and requires capitalization 

of borrowing costs directly attributable to the acquisition, construction or production of a qualifying asset as part of the cost of that 

asset. 

 The Company’s accounting policies have been revised and modified, when necessary, to adopt the requirements established in these 

new standards or interpretations. Adoption of these standards and interpretations did not significantly affect the Company’s financial 

statements. 

 (4) Exchange Agreement with the Central Bank of Venezuela (BCV) 

 

 On November 21, 2005, the Ministry of Finance and BCV published Exchange Agreement No. 9, which establishes that foreign 

currency obtained from hydrocarbon exports, including gaseous hydrocarbons, must be sold to BCV, except for foreign currency 

earmarked for activities conducted by PDVSA in conformity with the BCV Law Reform. Under this agreement, PDVSA and its 

subsidiaries may not maintain foreign currency funds in Venezuela for more than 48 hours, and establishes how these funds will be used 

by PDVSA and monthly information to be presented to BCV in respect of foreign currency flows generated by its activities, asset and 

liability positions in foreign currency, and payments made by PDVSA abroad. 

 

 Exchange Agreement No. 2 of February 6, 2004 was amended on March 2, 2005 to establish exchange rates of Bs. 2,144.60/US$1 

(Bs.F. 2.14) (purchase) and Bs. 2,150/US$1 (Bs.F. 2.15) (sale) (See Note 21). 

 (5) Determination of Fair Values 

 

 Certain of the Company’s accounting policies and disclosures require the determination of fair values for financial and non-financial 

assets and liabilities. Fair values have been estimated for purposes of valuation and disclosure using available market information and 

appropriate 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

23 

 valuation methods. Additional information on fair value estimates is disclosed in the specific notes to the assets and liabilities. 

 

 The fair value of property, plant and equipment recognized as a result of a business acquisition is essentially based on market values and 

other suitable valuation methods. The market value of assets is the estimated amount at which these assets could be exchanged on the 

valuation date between a willing buyer and seller in an arm’s length transaction wherein the parties had each acted knowledgeably, 

prudently and without compulsion. 

 

 The fair value of recoverable tax credits and other liabilities has been determined by discounting net cash flows expected to be 

generated by the asset, using interest rates applicable in the monetary market. 

 

 The carrying value of cash and cash equivalents, accounts receivable, prepaid expenses and other assets, and accounts payable to 

suppliers approximates their estimated fair value due to the short-term maturities of these instruments. 

 

 The net carrying value of the account payable to PDVSA approximates the estimated fair value since its payment depends on the 

volume and nature of transactions conducted by the Company with the Parent Company and its subsidiaries. 

 (6) Financial Risk Management 

 

 Local and international conditions, i.e., recession periods, inflation, interest rates, devaluation, and hydrocarbon price volatility may 

have a significant effect on the Company’s financial position. The Company is exposed to a variety of financial risks: market risk 

(including exchange rate fluctuation risk, interest rate risk and price risk), liquidity risk and capital risk. Financial instruments exposed 

to concentration of credit risk consist primarily of cash and trade accounts receivable. 

 

 At December 31, 2009 and 2008, the Company’s cash is placed with a local and foreign financial institution. In addition, there is some 

concentration of credit risk in trade accounts receivable since all crude oil and gas produced is sold to PDVSA Petróleo. 

 

 Market risk 

 

 The Company’s general risk management focuses on the uncertainty surrounding financial markets and seeks to minimize the potential 

adverse effects on the Company’s performance. At December 31, 2009 and 2008, the Company is exposed to the following market 

risks: 

 

 Exchange rate fluctuation risk 

 

 The Company operates in Venezuela and is exposed to foreign exchange risk from variations in the exchange rate of the Venezuelan 

Bolívar relative to the U.S. dollar. Foreign exchange risk is mainly derived from future commercial operations and assets and liabilities 

shown in bolivars. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

24 

 Price risk 

 

 The Company is exposed to risks stemming from changes in the sale price of hydrocarbons, which depend on external market factors. 

At December 31, 2009 and 2008, hydrocarbon sales prices are calculated based on predetermined formulas that consider the price of 

hydrocarbons in different international markets. Price fluctuations may have a significant impact on the Company’s income. At 

December 31, 2009 and 2008, the Company has no mechanisms in place to protect against exposure to hydrocarbon sales price 

fluctuations. 

 

 Interest rate fluctuation risk 

 

 The Company has accounts receivable from PDVSA which earn interest on arrears 45 days after bills are due and are, therefore, 

exposed to interest rate fluctuation. 

 

 Capital risk management 

 

 The Company is focused on safeguarding its ability to continue as a going concern in order to provide returns for the shareholders and 

maintain an optimal capital structure to reduce capital costs. In order to maintain or adjust the capital structure, the Company may adjust 

the amount of dividends paid to shareholders, return capital to shareholders or issue new shares. 

 

 Liquidity risk 

 

 Handling prudently liquidity risk implies maintaining sufficient funds in cash and short term marketable securities, as well as having 

working capital credit facility available. The Company permanently evaluates its future cash flows through short and long term 

projections from estimated sales and cash requirements which correspond mainly to operation and maintenance of production facilities, 

payment of payroll, payment of fiscal and financial obligations, etc. 

 (7) Taxes 

 

 Below is a summary of taxes affecting the Company’s operations, stated in thousands: 

 

 Years ended December 31, 

 2009 2008 2009 2008 

 U.S. Dollars Bolivars 

Income tax 61,946 16,814 133,184 36,150 

Royalties (See Note 7-b) 157,681 225,167 339,014 484,109 

 

  

  

Total 219,627 241,981 472,198 520,259 

 

 

 

 

 

 

 

 

 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

25 

 (a) Income tax 

 

 Net income tax expense is summarized below, stated in thousands: 

 

 Years ended December 31, 

 2009 2008 2009 2008 

 U.S. Dollars Bolivars 

Estimated income tax expense (105,868 ) (69,374 ) (227,616 ) (149,154 ) 

Deferred income tax 43,922 52,560 94,432 113,004 

     

Total (61,946 ) (16,814 ) (133,184 ) (36,150 ) 

 

 

 

 

 

 

 

 

 

 Reconciliation between the nominal and the effective income tax rates for each year is shown below: 

 

 Years ended December 31, 

 2009 2008 

 Thousands Thousands 

 % U.S. Dollars Bolivar’s % U.S. Dollars Bolivars 

Income tax: 

Net income 143,284 308,059 121,217 260,617 

Income tax 61,946 133,184 16,814 36,150 

  

   

Net income before income tax 205,230 441,243 138,031 296,767 

 

 

 

 

 

 

 

 

 

 

Oil-sector nominal income tax rate 50 102,615 220,621 50 69,016 148,383 

Tax inflation adjustment and effect 

from translation into U.S. dollars (11 ) (23,096 ) (49,655 ) (28 ) (38,697 ) (83,199 ) 

Deferred income tax (21 ) (43,922 ) (94,432 ) (38 ) (52,560 ) (113,004 ) 

Non-deductible provisions and other 13 26,349 56,650 28 39,055 83,970 

       

Effective rate 30 61,946 133,184 12 16,814 36,150 

 

 

 

 

 

 

 

 

 

 

 

 

 

 The partial reform of the Income Tax Law, published in Official Gazette No. 38,529 on September 25, 2006, repealed investment tax 

credits applicable to companies engaged in hydrocarbon production and related activities, and prohibits application of tax credits 

available for activities other than those related to hydrocarbons. 

 

 Prevailing and former Venezuelan Income Tax Law allows tax losses to be carried forward for three years to offset taxable income, 

except losses arising from the annual inflation adjustment, which may be carried forward for only one year. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

26 

 Venezuelan Income Tax Law requires an initial inflation adjustment to compute taxable income. The Law provides that the initially 

adjusted values of property, plant and equipment should be depreciated or amortized for tax purposes over the remaining useful lives of 

such assets. The Law also requires that an annual inflation adjustment be included in income tax reconciliation as a taxable or deductible 

item. 

 

 According to the Income Tax Law, taxpayers subject to this tax that conduct import, export and loan transactions with related parties 

abroad are required to calculate income, costs and deductions applying the methodology set out in the Law. The Company conducts no 

transactions with related parties abroad. 

 

 Official Gazette No. 38,529 of the Bolivarian Republic of Venezuela, published on September 25, 2006, modifies Article No. 11 of the 

Law regarding the rate applicable to companies engaged in hydrocarbon production and related activities, establishing a 50% general 

rate. However, only companies that conduct integrated or non-integrated activities related to exploration and production of nonassociated gas, and processing, transportation, distribution, storage, marketing and export of gas and its components, or those 

exclusively engaged in refining of hydrocarbons or enhancement of heavy and extra-heavy crude oil are subject to a 34% tax rate. 

Therefore, application of the 34% rate for companies incorporated under the joint venture agreements executed under the superseded 

Law Reserving Hydrocarbon Trade and Industry to the State is eliminated. 

 

 The components of deferred income tax expense at December 31, 2008 and 2009 shown in the results of each year are as follows (in 

thousands): 

 

 Benefit 

 2008 Recognized in 

 Assets results 2009 Assets 

In U.S. dollarsAccounts receivable — (2,653 ) (2,653 ) 

Property, plant and equipment 66,004 38,552 104,556 

Inventories 5,184 (664 ) 4,520 

Accruals and other payables 26,135 8,687 34,822 

    

 97,323 43,922 141,245 

 

 

 

 

 

 

 

 

In bolivarsAccounts receivable — (5,704 ) (5,704 ) 

Property, plant and equipment 141,909 82,887 224,796 

Inventories 11,145 (1,428 ) 9,717 

Accruals and other payables 56,190 18,677 74,867 

 

 

  

 209,244 94,432 303,676 

 

 

 

 

 

 

 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

27 

 (b) Royalties 

 

 Royalties are paid based on crude oil produced and associated natural gas processed in Venezuela. Volumes of hydrocarbons produced 

in traditional areas are taxed with a 30% rate. 

 

 The partial reform of the Hydrocarbon Law was approved in May 2006, whereby operators should pay 33.33% of the wellhead value of 

each barrel to the Venezuelan government by means of royalties and additional taxes. 

 

 On November 14, 2006, a new calculation of royalties was established for companies that conduct primary oil activities in the country 

requiring that contents of sulphur and API gravity of liquid hydrocarbons extracted be measured on a monthly basis and be reported 

together with taxed production. This information will be part of the royalty payment price and will be used for calculation of any special 

advantage. This information will result in adjustments for gravity and sulphur, which will be published by Ministry for Energy and Oil 

(MPPEP). 

 

 The Company pays MPPEP a 30% royalty in kind for crude oil produced and associated natural gas transferred to PDVSA Petróleo, 

S.A. Royalty expenses for 2009 and 2008 amounted to US$137,925 thousands and US$149,605 thousands (Bs 296,538 thousands and 

Bs 321,651 thousands), respectively, included in the income statement under Royalties. 

 

 The Company is subject to special advantage taxes, which are determined based on: a) an interest as additional royalty of 3.33% on 

volumes of hydrocarbons extracted in the delimited areas and delivered to Petróleos de Venezuela, S.A. and b) an amount equivalent to 

the difference, if any, between (i) 50% of the value of the hydrocarbons extracted in the delimited areas and delivered to Petróleos de 

Venezuela, S.A. in each calendar year and (ii) the sum of payments made by the mixed companies to the Bolivarian Republic of 

Venezuela, for activities developed during the calendar year, for royalties on hydrocarbons and investments in endogenous development 

projects, equivalent to 1% of pre-tax income. Taxes for special advantages must be paid before April 20 of each year, pursuant to 

Exhibit F of the Agreement for Conversion into a Mixed Company. In relation to a) above, Petrodelta, S.A. incurred in this tax during 

2009 and 2008 for US$15,548 thousands and US$16,030 thousands (Bs 33,428 thousands and Bs 34,464 thousands), respectively, 

included in the statements of comprehensive income under royalties. In relation to b) above, at December 31, 2009 and 2008, this 

special advantage tax was lower than what the Company paid and accrued for royalties and special advantages tax. 

 

 Official Gazette No. 39.273 of the Bolivarian Republic of Venezuela, published on September 28, 2009, approved the modification of 

article regulating special advantages tax levied on mix companies to redistribute the use of funds by the additional royalty of 3.33% that 

mix companies have to pay on hydrocarbons volumes extracted from delimited areas. The modified article establish deliver 1.11% to 

municipalities where oil activities in the country take place and 2.22% for a special fund to be administered by the Executive branch to 

finance endogenous development projects. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

28 

 Following a detail of the caused royalties is shown: 

 

 Years ended December 31, 

 2009 2008 2009 2008 

 Dollars Bolivars 

Royalty on oil production 135,442 138,311 291,200 297,369 

Royalty on gas production 2,483 11,294 5,338 24,282 

Royalty for the municipalities 8,613 10,687 18,518 22,977 

Royalty for endogenous development projects 6,935 5,343 14,910 11,487 

Surface tax 1,946 1,596 4,184 3,431 

Windfall tax 882 56,377 1,896 121,211 

Accrual for investments in social project 1,380 1,559 2,968 3,352 

 

  

  

 157,681 225,167 339,014 484,109 

 

 

 

 

 

 

 

 

 

 (c) Extraction tax 

 

 The Venezuelan Hydrocarbon Law Reform establishes a rate equivalent to 33.33% of the value of all liquid hydrocarbons extracted 

from any reservoir, calculated on the same basis as for royalties. The taxpayer may deduct from the extraction tax any sum payable as 

royalties, including the additional royalty paid as special advantage. This tax is effective since 2006. The Company incurred no tax in 

this connection for 2009 and 2008. 

 

 (d) Value added tax (VAT) 

 

 A Partial Reform of the Value Added Tax Law was published in Official Gazette No. 38,632 on February 26, 2007 changing the 

applicable tax rate from 14% to 11% as from March 1 until June 30, 2007 and to 9% as from July 1, 2007. On March 26, 2009, under 

Official Gazette No. 39,147 modification of applicable tax rate to 12% was published, having effect from April 1, 2009. 

 

 The VAT Law establishes an exemption on trading of certain hydrocarbon-derived fuels. Recoverable amounts bear no interest. 

 

 Below is a summary of the movement of recoverable tax credits (in thousands): 

 

 December 31, 

 2009 2008 2009 2008 

 U.S. dollars Bolivars 

Recoverable amounts at the beginning of the year 9,604 — 20,649 — 

Generate during the year 10,110 9,604 21,736 20,649 

Adjustment to net realizable value (1,792 ) — (3,853 ) — 

Recoverable amounts at end of the year 17,922 9,604 38,532 20,649 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

29 

 At the end of 2009, the Company adjusted the amount of recoverable tax credits to the net realizable value applying a discount rate for 

assets deterioration of 13%. This rate is calculated by its main shareholder annually with the financial statements of the prior year and 

using outside parameters updated each year. At December 31, 2009, the adjustment for US$1,792 thousands (Bs. 3,853 thousands) is 

included in the statement of comprehensive income under the category of financial expenses. 

 

 (e) Law on Special Contributions over Extraordinary Prices of the International Hydrocarbons Market 

 

 In April 2008, the Venezuelan government, by means of a decree-law, established a special contribution over extraordinary prices of the 

international hydrocarbons market, amended in July 2008, which levies the sale of crude oil whenever the average price for the month 

in question of the Venezuelan oil production exceeds the price of US$70/barrel. The amount of said contribution equals 50% of the 

difference resulting of the average price per month and the aforementioned cap of US$70/barrel. In addition, this decree-law sets forth 

that whenever the average price per month exceeds the price of US$100/barrel, the total amount of said special contribution will be 

equivalent to 60% of the above defined difference. 

 (8) Property, Plant and Equipment, Net 

 

 Property, plant and equipment, net at December 31 comprises the following (in thousands): 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

30 

 U.S. dollars -

 

 Wells and 

 production Furniture and Construction in 

 facilities equipment progress Total 

Cost: 

Balances at December 31, 2007 215,581 2,821 — 218,402 

Additions — 916 38,431 39,347 

Transfers 7,485 — (7,485 ) — 

Strategic Inventories 4,279 — — 4,279 

Assets retirement obligations 10,866 — — 10,866 

 

  

 

 

 

Balances at December 31, 2008 238,211 3,737 30,946 272,894 

Additions — 3,729 77,696 81,425 

Transfers 75,730 — (75,730 ) — 

Strategic inventories 1,842 — — 1,842 

Asset retirement obligations 3,603 — — 3,603 

     

Balances at December 31, 2009 319,386 7,466 32,912 359,764 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization: 

Balances at December 31, 2007 34,572 1,054 — 35,626 

Depreciation and amortization 21,677 730 — 22,407 

Assets retirement obligations 3,101 — — 3,101 

     

Balances at December 31, 2008 59,350 1,784 — 61,134 

Depreciation and amortization 30,198 1,095 — 31,293 

Assets retirement obligations 1,895 — — 1,895 

 

  

 

 

Balances at December 31, 2009 91,443 2,879 — 94,322 

 

  

 

 

 

Total net cost at December 31, 2009 227,943 4,587 32,912 265,442 

 

 

 

 

 

 

 

 

 

 

Total net cost at December 31, 2008 178,861 1,953 30,946 211,760 

 

 

 

 

 

 

 

 

 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

31 

 Bolivars -

 

 Wells and 

 production Furniture and Construction in 

 facilities equipment progress Total 

Cost: 

Balances at December 31, 2007 463,500 6,065 — 469,565 

Additions — 1,969 82,627 84,596 

Transfers 16,093 — (16,093 ) — 

Strategic Inventories 9,200 — — 9,200 

Assets retirement obligations 23,362 — — 23,362 

  

  

 

 

Balances at December 31, 2008 512,155 8,034 66,534 586,723 

Additions — 8,017 167,045 175,062 

Transfers 162,819 — (162,819 ) — 

Strategic inventories 3,959 — — 3,959 

Asset retirement obligations 7,745 — — 7,745 

     

Balances at December 31, 2009 686,678 16,051 70,760 773,489 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization: 

Balances at December 31, 2007 74,329 2,267 — 76,596 

Depreciation and amortization 46,606 1,570 — 48,176 

Assets retirement obligations 6,667 — — 6,667 

     

Balances at December 31, 2008 127,602 3,837 — 131,439 

Depreciation and amortization 64,926 2,352 — 67,278 

Assets retirement obligations 4,074 — — 4,074 

  

  

 

Balances at December 31, 2009 196,602 6,189 — 202,791 

  

  

 

 

Total net cost at December 31, 2009 490,076 9,862 70,760 570,698 

 

 

 

 

 

 

 

 

 

 

Total net cost at December 31, 2008 384,553 4,197 66,534 455,284 

 

 

 

 

 

 

 

 

 

 During the years ended December 31, 2009 and 2008, the Company made additions to production assets and construction in progress for 

approximately US$81,425 thousands and US$39,347 thousands (Bs 175,062 thousands and Bs 84,596 thousands), respectively. 

 

 During 2009 and 2008, the Company assessed asset impairment, taking into account new market and business conditions, and determined 

that there was no evidence of impairment of production assets. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

(9) Accrual for Asset Retirement Obligations 

32 

 At December 31, 2009 and 2008, accruals and other payables include US$3,603 thousands and US$10,866 thousands (Bs 7,745 thousands 

and Bs 23,362 thousands), respectively, in respect of the accrual for asset retirement obligations (See Note 9). 

 

 The balance of construction in progress mainly comprises investment projects for exploration and production activities related to drilling, 

maintenance, electrical systems, pipelines, well reconditioning and adaptation, expansion and infrastructure aimed at maintaining production 

capacity and adapting the infrastructure to production levels set out in the Corporation’s business plan. At December 31, 2009 and 2008, the 

balance of construction in progress for investments related to the aforementioned activities amounts to approximately US$32,912 thousands 

and US$30,946 (Bs 70,760 thousands and Bs 66,534 thousands). 

 The movement of the accrual for asset retirement obligations at December 31 is shown below (in thousands): 

 

 U.S. dollars Bolivars 

Balance at December 31, 2007 5,964 12,823 

 

Change on estimation 10,866 23,362 

Financial cost 2,344 5,039 

   

Balance at December 31, 2008 19,174 41,224 

 

Change on estimation 3,603 7,745 

Financial cost 1,639 3,523 

   

Balance at December 31, 2009 24,416 52,492 

 

 

 

 

 

 During 2009, Company management reviewed, based on new information, estimates on assumptions used for calculating the provision for 

abandonment costs. 

 

 At December 31, 2009 and 2008, the variation of the estimation in of the provision for well abandonment cost of US$3,603 thousands and 

US$10,866 thousands (Bs 7,745 thousands and Bs 23,362 thousands) is includes the balance of Property, plant and equipment (See Note 8). 

The Petrodelta, S.A. business plan as of December 31, 2009, contemplates the realization of hydrocarbons drilling and production activities 

until the year 2025; therefore, the accrual for asset retirement obligations was calculated based on the disbursements for this concept during 

this period. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

(10) Prepaid Expenses and Other Assets 

Prepaid expenses and other assets comprise the following (in thousands): 

(11) Inventories 

(12) Accounts Receivable 

33 

 

 December 31, 

 2009 2008 2009 2008 

 U.S. dollars Bolivars 

Prepaid income tax — 20,876 — 44,883 

Prepaid insurance 458 472 984 1,016 

Prepaid services 62 88 134 189 

Prepaid rent 39 41 84 88 

     

 559 21,477 1,202 46,176 

 

 

 

 

 

 

 

 

 

 Estimated tax paid during 2008 exceeded the final tax liability by US$20,876 thousands (Bs 44,883 thousands), and was used to offset part 

of 2009 tax liability. 

 A summary of inventories is shown below (in thousands): 

 

 December 31, 

 2009 2008 2009 2008 

 U.S. dollars Bolivars 

Materials and supplies, net 33,586 24,663 72,211 53,026 

     

 33,586 24,663 72,211 53,026 

Less: Materials and supplies classified under other non-current assets 

(See Note 8) 12,114 10,272 26,044 22,085 

 

   

 

 21,472 14,391 46,167 30,941 

 

 

 

 

 

 

 

 

 

 Accounts receivable comprise the following (in thousands): 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

(13) Cash and cash equivalents 

(14) Equity 

34 

 

 December 31, 

 2009 2008 2009 2008 

 U.S. Dollars Bolivars 

Related parties (See Note 19) 361,137 257,292 776,445 553,178 

Recoverable tax credits (See Note 7 and 17) 17,922 9,604 38,532 20,649 

Other 673 890 1,448 1,913 

 

    

 379,732 267,786 816,425 575,740 

 

 

 

 

 

 

 

 

 

 Cash and cash equivalent comprises the following (in thousands): 

 

 December 31, 

 2009 2008 2009 2008 

 U.S. Dollars Bolivars 

Cash on hand 3 2 7 4 

Cash at banks 3,059 7,361 6,575 15,826 

   

  

 3,062 7,363 6,582 15,830 

 

 

 

 

 

 

 

 

 

 Capital stock 

 

 At December 31, 2009 and 2008, the Company’s nominal capital stock is represented by 1,500,000 common shares, fully authorized and 

paid in, with a par value of US$4.65 each (Bs 10 each). 

 

 The Company’s capital stock is divided into two types of shares: Class “A” and Class “B” shares. Only the Venezuelan government or 

Venezuelan state-owned companies can own Class “A” shares. In October 2007, when the Company was incorporated, shareholders made 

an initial capital contribution of approximately Bs 1,000 thousands (US$465,000). Capital stock has been fully subscribed and paid in as 

follows: 

 

Shareholders Type of shares Number of shares US$ Bs. Share of equity 

Corporación Venezolana del Petróleo, S.A. (CVP) A 900,000 4,186,047 9,000,000 60 % 

HNR Finance, B.V. (HNR Finance) B 600,000 2,790,698 6,000,000 40 % 

  

   

 1,500,000 6,976,745 15,000,000 100 % 

 

 

 

 

 

 

 

 

 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

35 

 Contributions for future capital increases 

 

 In November 2007, the shareholders made contributions for future capital increases of approximately US$6,512 thousands, equivalent to 

approximately Bs 14,000 thousands. In August 2008, this contribution was capitalized in compliance with Article No. 1, Paragraph 1.4 of 

the Agreement for Conversion into a Mixed Company. 

 

 Legal reserve 

 

 Venezuelan companies are required to set aside a legal reserve. According to Venezuelan Law, the legal reserve is not available for dividend 

distribution. 

 

 At December 31, 2008, the Company has set aside a legal reserve of approximately US$651 thousands, equivalent to Bs 1,400 thousands, 

equivalent to 10% of capital stock. 

 

 Deferred tax asset equity reserve 

 

 In June 2009, CVP issued instructions to all mixed companies regarding the accounting for deferred tax assets. The mixed companies have 

been instructed to set up a reserve within the equity section of the balance sheet for deferred tax assets. The setting up of the reserve had no 

effect on the Company financial position, results of operations or cash flows. However, the new reserve reduces the amount of dividends 

received in the future. 

 

 On August 2009, the Board of Directors of the Company approved the creation of the deferred tax asset equity reserve with retained 

earnings accumulated to end of June 2009 for US$116,273 thousands (Bs.249.987 thousands). At December 31, 2009 management has 

recorded as equity reserve and amount equal to the balance of deferred tax asset at that date equivalent to US$141,245 thousands 

(Bs.303,676 thousands) and which has been approved by the Board of Directors of the Company. 

 

 Share premium 

 

 The share premium is in respect of contributions of fixed assets and inventories made by shareholders in conformity with the Agreement for 

Conversion into a Mixed Company, whose value exceeds the par value of common shares issued. At December 31, 2009 and 2008, the share 

premium amounts to approximately US$212,451 thousands, equivalent to approximately Bs 456,770 thousands, included in equity. 

 

 Class “A” share premiums are in respect of fixed assets contributed by CVP. The value of this share premium amounts to approximately 

US$191,206 thousands, equivalent to approximately Bs 411,093 thousands, pursuant to Exhibit H of the Agreement for Conversion into a 

Mixed Company. 

 

 Class “B” share premiums are in respect of fixed assets and inventories contributed by HNR Finance. The value of this share premium 

amounts to approximately US$21,245 thousands, 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

36 

 equivalent to approximately Bs 45,677 thousands, pursuant to Exhibit G of the Agreement for Conversion into a Mixed Company. 

 

 In conformity with the Company’s bylaws, in case of Company liquidation, all assets will be transferred only to the Class “A” shareholder. 

 

 Dividends 

 

 On May 2008, the shareholders resolved to pay dividends of US$181,325 thousands, equivalent to Bs 389,846 thousands, out of 

unappropriated retained earnings for December 2007.

 

 On August 2008, the shareholders resolved to pay dividends in advance based on retained earnings as the end of June 2008 of US$51,876 

thousands, equivalent to Bs 111,533 thousands. The dividend in advance approved was paid to HNR Finance for its share in the Company in 

the amount of US$20,750 thousands, equivalent to Bs 44,612 thousands. At December 31, 2009 the Company decided to record the 

dividend in advance against unappropriated retained earnings at the end of 2009, recording as dividends payable the unpaid portion to CVP 

for an amount of US$31,126 thousands equivalent to Bs 66,921 thousands. 

(15) Accounts Payable 

 Accounts payable comprise the following (in thousands): 

 

 December 31, 

 2009 2008 2009 2008 

 U.S. dollars Bolivars 

Trade 35,021 8,536 75,295 18,353 

Related parties (See Note 19) 70,311 80,568 151,170 173,221 

   

 

 

Total 105,332 89,104 226,465 191,574 

 

 

 

 

 

 

 

 

 

 Foreign currency and liquidity risk exposure in respect of accounts payable to suppliers is shown in Note 17. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

37 

(16) Accruals and Other Payables 

 Accruals and other payables at December 31 comprise the following: 

 

 December 31, 

 2009 2008 2009 2008 

 U.S. dollars Bolivars 

Royalties 49,277 44,017 105,946 94,637 

Provision for abandonment cost (See Note 9) 24,416 19,174 52,492 41,224 

Provision for retirement benefits 9,184 1,306 19,746 2,808 

Endogenous and social development 5,728 4,347 12,315 9,346 

LOCTISEP 6,392 3,056 13,743 6,570 

Other 93,466 118,404 200,952 254,569 

 

 

  

 

 188,463 190,304 405,194 409,154 

Less: Non current portion of accruals and other payables 33,600 20,480 72,238 44,032 

 

 

  

 

 

Short-term portion 154,863 169,824 332,956 365,122 

 

 

 

 

 

 

 

 

 

 At December 31, 2009 and 2008, included as non-current liabilities: a) US$24,416 thousands and US$19,174 thousands, (Bs 52,492 

thousands and Bs 41,224 thousands), in respect of the provision for abandonment cost for retirement obligations for exploration and 

production assets. Asset retirement costs and obligations related to the main structures used in drilling activities were not estimated because 

these assets have an indefinite useful life as a result of maintenance and mayor repairs and no information is available to reasonably 

determine their retirement date; and b) US$9,184 thousands and US$1,306 thousands, (Bs.19,746 thousands and Bs. 2,808 thousands), as 

provision for retirement benefits for personnel assigned to the Company. During 2009, PDVSA completed an actuarial study for their 

pension and retirement plan. This pension and retirement plan covers all PDVSA employees and mixed companies payroll. In May 2009, 

PDVSA sent a statement to the Company for its respective costs associated with the pension and retirement plan. The pension adjustment 

was for past service costs covering the period from January 2008, when HVSCA employees were migrated to PDVSA payroll. It is a nonrecurring adjustment. Pension costs at the end of 2009 recorded in the books reasonably reflect the Company’s employee demographic and 

plan conditions. Pension cost is not tax deductible until future periods when the pension is settled in cash. The Company is not required to 

reimburse the pension costs to PDVSA until PDVSA pays. 

 

 Additionally, at December 31, 2009 and 2008, under other, it is included the accruals in respect of drilling services and infrastructure 

totaling US$47,892 thousands and US$50,845 thousands (Bs 102,968 thousands and Bs 109,317 thousands), approximately, and a special 

contribution over the extraordinary prices of the international hydrocarbons market totaling US$882 thousands and US$56,377 thousands 

(Bs 1,896 thousands and Bs 121,211 thousands). 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

38 

 Below are the movements of accruals and other payables during 2009 (in thousands): 

 

 Balance at Balance at Long- 

 December 31, December Current term 

 2008 Increase Decrease 31, 2009 portion portion 

U.S. dollars 

Royalties 44,017 5,260 — 49,277 49,277 — 

Provision for abandonment cost (See 

Note 9) 19,174 5,242 — 24,416 — 24,416 

Provision for retirement benefits 1,306 7,878 — 9,184 9,184 

Endogenous and social development 4,347 1,381 — 5,728 5,728 — 

LOCTISEP 3,056 3,336 — 6,392 6,392 — 

Other 118,404 — (24,938 ) 93,466 93,466 — 

    

  

 

 

Total accruals and other payables 190,304 23,097 (24,938 ) 188,463 154,863 33,600 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Bolivars 

 

Royalties 94,637 11,309 — 105,946 105,946 — 

Provision for abandonment cost (See 

Note 9) 41,224 11,268 — 52,492 — 52.492 

Provision for retirement benefits 2,808 16,938 — 19,746 — 19,746 

Endogenous and social development 9.346 2,969 — 12,315 12,315 — 

LOCTISEP 6,570 7,173 — 13,743 13,743 — 

Other 254,569 — (53,617 ) 200,952 200,952 — 

    

  

 

 

Total accruals and other payables 409,154 49,657 (53,617 ) 405,194 332,956 72,238 

 

 

 

 

 

 

 

 

 

 

 

 

 

(17) Financial Instruments 

 Credit Risk 

 

 Exposure to Credit Risk 

 

 The book value of financial assets represents the highest level of credit risk exposure. A breakdown is shown below (in thousands): 

 

 December 31, 

 2009 2008 2009 2008 

 U.S. dollars Bolivars 

Accounts receivable (Note 12) 361,137 257,292 776,445 553,178 

Recoverable tax credits (See Note 7 and 12) 17,922 9,604 38,532 20,649 

Accounts receivable other (See Note 12) 673 890 1,448 1,913 

Cash and cash equivalents 3,062 7,363 6,582 15,830 

     

 

 382,794 275,149 823,007 591,570 

 

 

 

 

 

 

 

 

 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

39 

 Aging of the account receivables are shown below (in thousands): 

 

 December 31, 

 2009 2008 2009 2008 

 U.S. dollars Bolivars 

Under 30 days 136,755 232,822 294,022 500,568 

Between 31 and 180 days 113,666 24,470 244,383 52,610 

Between 180 days and one year 109,186 — 234,751 — 

More than one year 1,530 — 3,289 — 

     

 

 361,137 257,292 776,445 553,178 

 

 

 

 

 

 

 

 

 

 Liquidity risk 

 

 Maturity of financial liabilities, including estimated interest payments and excluding the impact of offset agreements, is shown below (in 

thousands): 

 

 Book value Contractual cash flows 6 months or less 

 

 Non-derivative financial liabilities 

 

 2009 2008 2009 2008 2009 2008 

U.S. dollars 

 

Accounts payable to suppliers (See 

Note 15) 35,021 8,536  35,021 8,536  35,021 8,536  

 

Bolivars 

 

Accounts payable to suppliers (See 

Note 15) 75,295 18,353  75,295 18,353  75,295 18,353  

 Foreign Currency Risk 

 

 Petrodelta, S.A. has the following monetary assets and liabilities denominated in currencies other than the U.S. dollar, which were converted 

into U.S. dollars at the exchange rate in effect at the balance sheet date (in thousands): 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

40 

 

 December 31, 

 2009 2008 

Monetary assets: 

Bolivars 391,383 254,740 

   

 391,383 254,740 

   

 

Monetary liabilities: 

 

Bolivars 691,588 342,635 

   

 691,588 342,635 

   

Net monetary liability position (300,205 ) (87,895 ) 

 

 

 

 

 

 The year-end exchange rate, the average exchange rate for the year and the interannual increases in the exchange rate and the Consumer 

Price Index (CPI), as published by BCV, were as follows: 

 

 December 31, 

 2009 2008 

Exchange rate at year end (Bs./US$1) 2.15 2.15 

 

 

 

 

 

Average exchange rate for the year (Bs./US$1) 2.15 2.15 

 

 

 

 

 

Interannual increase in the CPI (%) 25,06 30.90 

 

 

 

 

 

 Fair Value of Financial Instruments 

 

 The following estimated amounts do not necessarily reflect the amounts at which the instruments could be exchanged in the current market. 

The use of different market assumptions and valuation methods can significantly affect the estimated fair values. The bases for determining 

the fair value are disclosed in Note 5 (in thousands): 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

41 

 

 December 31, December 31, 

 2009 2008 2009 2008 

 Book Fair Book Fair Book Fair Book Fair 

 value value value value value value value value 

 U.S. dollars Bolivars 

Assets: 

Accounts receivable 361,137 361,137 257,292 257,292 776,445 776,445 553,178 553,178 

Recoverable tax credits 19,714 17,922 9,604 9,604 42,385 38,532 20,649 20,649 

Accounts receivable other 673 673 890 890 1,448 1,448 1,913 1,913 

Cash and cash equivalents 3,062 3,062 7,363 7,363 6,582 6,582 15,830 15,830 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities: 

 

Accounts payable to 

suppliers 35,021 35,021 8,536 8,536 75,295 75,295 18,353 18,353 

Other liabilities (included in 

accruals and other 

payables) 154,863 154,863 169,824 169,824 332,956 332,956 365,122 365,122 

Accounts and dividends 

payables to shareholders 

and related companies 101,437 101,437 80,568 80,568 218,091 218,091 173,221 173,221 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(18) Commitments, Contingencies and Claims 

 At December 31, 2009 and 2008, the Company has not set aside a provision for litigations and other claims. Should the outcome of existing 

lawsuits and claims be unfavorable to the Company, it could have a material adverse effect on its results of operations. Although it is not 

possible to predict the outcome, Company management, based in part on the opinion of its legal advisors, does not believe it is likely that 

losses related to the aforementioned legal procedures will exceed recognized estimated amounts or generate significant amounts that could 

affect the Company’s financial position or results of operations. 

 

 Environmental Protection 

 

 The subsidiaries of CVP are subject to different environmental laws and regulations which may require significant expenditures to modify 

facilities and prevent or remedy the environmental effects from waste disposal and spills of pollutants. 

 

 Petrodelta, S.A. and its parent company CVP are taking steps to prevent environmental risks, protect employee health and preserve the 

integrity of their facilities. 

 

 Conditions that require additional expenditures may exist at various sites including, but not limited to, CVP’s operating complexes and 

crude oil storage terminals. Company management believes that these matters, in the normal course of operations, will not significantly 

affect the Company’s financial position or liquidity in the results of its operations. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

42 

 Agreements with the Organization of Petroleum Exporting Countries (OPEC) 

 

 The Bolivarian Republic of Venezuela is a member of OPEC, an organization mainly dedicated to establishing agreements to maintain 

stable crude oil prices by setting production quotas. To date, the reduction in crude oil production resulting from changes in the production 

quotas set by OPEC and price fluctuations has not significantly affected the Company’s results of operations, cash flows or financial results. 

(19) Related Party Transactions 

 Petrodelta, S.A. considers its shareholders and related subsidiaries and affiliates, Company directors and executives, as well as other 

governmental institutions, as related parties. 

 

 A summary of transactions and balances with related parties is shown below (in thousands): 

 

 December 31, 

 2009 2008 2009 2008 

 U.S. dollars Bolivars 

Activities for the year: 

Crude oil and natural gas sales 458,251 474,619 985,239 1,020,431 

 

 

 

 

 

 

 

 

 

Operating expenses 35,442 21,298 76,200 45,791 

 

 

 

 

 

 

 

 

 

General, administrative and selling expenses 6,589 3,506 14,167 7,538 

 

 

 

 

 

 

 

 

 

Royalties (See Note 7) 137,925 149,605 296,538 321,651 

 

 

 

 

 

 

 

 

 

Reimbursement of expenses 149,058 272,852 320,475 586,632 

 

 

 

 

 

 

 

 

 

 

Balances at the end of the year: 

Accounts receivable (See Note 12) 361,137 257,292 776,445 553.178 

 

 

 

 

 

 

 

 

 

Prepaid dividends-B Partners (See Note 14) — 20,750 — 44,612 

 

 

 

 

 

 

 

 

 

Accounts payable to Shareholders (See Note 15) 4,060 2,327 8,729 5,003 

 

 

 

 

 

 

 

 

 

Dividends payable-A Partners (See Note 14) 31,126 — 66,921 — 

 

 

 

 

 

 

 

 

 

Accounts payable to PDVSA (See Note 15) 66,251 78,241 142,441 168,218 

 

 

 

 

 

 

 

 

 

 As of April 2006, due to the migration of operating agreements to mixed companies, PDVSA Petróleo signed purchase and sale agreements 

with these companies, which set out that mixed companies will notify PDVSA Petróleo of the estimated volume of hydrocarbons expected 

to be delivered the following month. PDVSA Petróleo must pay the mixed companies for delivered volumes, net of volumes for royalties in 

kind and paid to the Venezuelan government. 

 

 In conformity with the terms and conditions of the agreements, CVP mixed companies agree to sell and deliver to PDVSA Petróleo, and the 

latter agrees to purchase and receive from these mixed companies, crude oil and natural gas produced in the delimited areas that are not used 

for primary activities or for payment of royalties in kind to the Venezuelan government. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

43 

 Crude oil delivered from the Petrodelta fields to PDVSA is priced with reference to Merey 16 published prices, weighted for different 

markets and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the 

reference price and prevailing market conditions. Market prices for crude oil of the type produced in the fields operated by Petrodelta 

averaged approximately $57.62 and $84.52 per barrel for the year ended December 31, 2009 and 2008, respectively. 

 

 During the years ended December 31, 2009 and 2008, the Company sold crude oil and natural gas to PDVSA Petróleo for US$458,251 

thousands and US$474,619 thousands (Bs 985,239 thousands and Bs 1,020,431 thousands), respectively, included in the income statement 

under Income. At December 31, 2009 and 2008, the statement of financial position includes US$361,137 thousands and US$257.292 

thousands (Bs 776,445 thousands and Bs 553.178 thousands) of accounts receivable in this connection. 

 

 During 2009 and 2008, PDVSA Petróleo charged Petrodelta, S.A. US$261 million and US$370 million (Bs 561 million and Bs 

798 million), respectively, for labor and other costs, included in general, administrative and selling expenses. 

 

 Certain Company directors hold key positions in other related entities; some of their attributions include influencing the operational and 

financial policies of these entities. 

 

 At December 31, 2009 and 2008, transactions with related parties do not necessarily reflect the results that would have been obtained had 

these transactions been held with third parties. 

 

 At a Board of Directors’ Meeting in December 2008, it was resolved to offset receivables and payables with PDVSA and its affiliates. In 

this regard, it was established that 75% of accounts receivable and 100% of accounts payable and billed to PDVSA would be recorded with 

no interest charges. Subsequently, in December 2008, CVP agreed to offset the remaining unbilled accounts payable. During 2009, in 

February, July and November it was resolved to offset receivables and payables between PDVSA and the Company. As a result, accounts 

payable in respect of reimbursement of capital costs and operating expenses were offset against accounts receivable in respect of estimated 

hydrocarbons extracted and transferred to PDVSA in accordance with the purchase sale agreement. 

(20) Laws, Resolutions and Legal Contributions 

 a) Laws Decreed within the Framework of the Enabling Law 

 

 On July 31, 2008, 26 laws were decreed within the framework of the Enabling Law concerning economic, social, legal, and military 

matters. The following are among the most important laws approved in the social, administrative and financial areas: 

 - Decree No. 6,071 for the Agro-Food Security and Sovereignty Law published in Official Gazette No. 5,889. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

44 

 - Decree No. 6,128 for the Law for the Creation of the Social Fund Aimed at Gathering and Disposing of Excess Resources of 

Government Entities published in Official Gazette No. 5,890. 

 

 - Decree No. 6,215 for the Law for Fostering and Developing Small and Medium-sized Industries and Units of Social Property 

published in Official Gazette No. 5,890. 

 

 - Decree No. 6,217 for the Public Administration Law published in Official Gazette No. 5,890. 

 

 - Decree No. 6,233 for the Reform of the Public Sector Financial Administration Law published in Official Gazette No. 5,891. 

 

 - Decree No. 6,265 for the Law for the Simplification of Administrative Formalities published in Official Gazette No. 5,891. 

 

 Company management and its legal advisors are assessing the possible impact of these laws on PDVSA. 

 b) Law for Special Contributions on Extraordinary International Hydrocarbon Market Prices 

 

 On April 15, 2008, the Law for Special Contributions on Extraordinary International Hydrocarbon Market Prices was published in 

Official Gazette No. 38,910. Subsequently, Resolutions No. 151 and No. 195 of MPPEP were published in Official Gazette 

No. 38,939 of May 27, 2008 and Official Gazette No. 38,970 of July 10, 2008. This Law and its resolutions require entities that 

export or transport liquid hydrocarbons and hydrocarbon derivatives abroad to pay a special monthly contribution. The contribution 

will be equivalent to: a) 50% of the difference between the average monthly price of the Venezuelan crude oil basket and the 

threshold price of US$70 per barrel and b) 60% of the difference between the average monthly price of the Venezuelan crude oil 

basket and the threshold price over US$100 per barrel. This contribution shall be paid on every barrel of oil exported or transported 

abroad and shall be collected and paid monthly by MPPEP to FONDEN for execution of infrastructure development projects, 

production and social development projects aimed at strengthening Communal Power. This Law became effective on April 15, 2008. 

 

 c) Law on Narcotic and Psychotropic Substances 

 

 The Law on Narcotic and Psychotropic Substances was published in Official Gazette No. 38,287 on December 16, 2005. This Law 

repeals the previous Law of September 30, 1993 and requires all companies, public or private, with 50 or more employees to earmark 

1% of their annual net income for social programs for the prevention of illegal drug consumption and traffic, one-half of which is to 

be set aside for child welfare protection programs.
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

45 

 In December 29, 2009 providence 007-2009 was published in Official Gazette No. 39,336 whereas the National Anti-Drug Agency 

(ONA) establishes norms and procedures to collect, control and fiscalize contributions by public and private companies. The 

providence among other things lay out the amount subject to the calculation set as taxable income and not net income applied in prior 

years. During the years ended December 31, 2009 and 2008, the Company recorded an expense of approximately US$3,336 

thousands and US$1,224 thousands (Bs 7,173 thousands and Bs 2.633 thousands), respectively, in this connection, included in the 

income statement for each year under General and administrative expenses, net. As a result of the change in the methodology used to 

calculate the contribution from applying the providence No. 007-2009, for the amount recorded during the year ended December 31, 

2009 approximately US$1.082 thousands and US$168 thousands (Bs.2.327 thousands y Bs.362 thousands), correspond to 2008 and 

2007, respectively. 

 

 d) Financial Transaction Tax Law 

 

 On October 5, 2007, the Venezuelan government enacted by Decree the Tax on Financial Transactions for Incorporated and 

Unincorporated Entities. This tax is levied upon all financial transactions performed by incorporated and unincorporated entities. The 

tax rate was set at 1.5% as from November 1, 2007 until December 31, 2008. 

 

 e) Enabling Law 

 

 On February 1, 2007, the National Assembly approved the Enabling Law granting the Venezuelan president special powers for 

18 months to pass decrees governing different areas of national interest, including transformation of state institutions, popular, 

economic and social participation, as well as financial, tax and energy-related matters. 

 

 f) Law for the Advancement of Science, Technology and Innovation 

 

 The Law for the Advancement of Science, Technology and Innovation was enacted in August 2005. This Law establishes that, 

beginning January 1, 2006, the country’s major corporations will annually earmark 0.5% of gross income generated in Venezuela to 

support activities which, according to the Law, relate to investments in science, technology and innovation. This Law defines major 

corporations as those whose annual gross income exceeds 100,000 tax units. In addition, Article No. 35 of the aforementioned Law 

requires major corporations in the country engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law to 

contribute 2% a year of their gross income generated in Venezuela from any of the activities specified in Article No. 42 of this Law. 

This Law’s Regulations will establish the mechanisms, methods and procedures for mandatory contributions from major 

corporations, as well as the timeframe and procedures that must be complied with for the purpose of determining which activities will 

be considered by the Ministry of Science and Technology in connection with these contributions. At December 31, 2009 and 2008 

following instructions 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

46 

 from its shareholder CVP, the Company Management did not record any provision related to the contribution establish in the Law for 

the Advancement of Science, Technology and Innovation. According with these instructions, PDVSA will file on consolidated basis 

the contribution established in this Law. 

(21) Subsequent events 

 a) Exchange Agreement No. 14 

 

 On January 8, 2010, the Ministry of Finance and BCV published Exchange Agreement No. 14, which establishes a dual exchange 

rate of Bs.2.60/1US$ for essentials imports and Bs.4.30/1US$ for other concepts. This agreement allows for the purchase and sale of 

currency for the following concepts at the Bs 2,60/1US$: 

 I. Imports for food, health, education, machinery and equipment, science and technology, according to commercial policy set by 

the Executive branch. 

 

 II. Remittance of funds to famillies living abroad. 

 

 III. Payments to students undergoing academic activities outside the country. 

 

 IV. Payments of expenses for health recovery, sport, culture, scientific investigations and other cases of urgent matter authorized by 

CADIVI. 

 

 V. Payments to retired individuals living abroad. 

 

 VI. Purchase of currency by diplomatic representations, consulates, embassies and public individuals assigned to International 

organizations accredited by the goverment. 

 

 VII. The Exchange Agreement establishes that the parchase and sale of currency for operations different than those mentioned 

above are to be at Bs 4,30 /U$1. 

 This agreement did not have an effect on the Company’s right to maintain foreign currency funds at financial institutions outside the 

country on revenues proceeds from sale of crude in order to make payments and disbursements outside the country. 

 

 b) Labor Collective Contract 

 

 On January 12, 2010 a pre-agreement was reached among PDVSA and oil labor union (FUTPV) regarding the approval of the new 

labor contract and the impact on labor cost affecting mix companies. The pre-agreement establish a salary raise and payroll and 

retirement benefits which has a significant impact on the Company’s payroll cost. The most significant impacts are: 

 I. A salary raise of Bs.35 daily which represents an increase of 80% of current salary. The increase shall be pay in two 

portions, the first of Bs.25 at the signing of the contract and the second of Bs.10 from January 1 st , 2011. 

 

 II. An increase in the monthly amount for electronic food from Bs.1.300 to Bs. 1.700. 

 

 III. An increase in the retirement benefit from Bs. 1.000 to Bs. 1.600. 

 

 IV. The increase will be retroactively from October 1, 2009 and not from January 21, 2009, date which expired the prior 

contract, in compensation it was agreed a one-
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

47 

 time bonus of Bs. 8.000 which has no effect in the severance benefits of employees. 

 The impact of the new collective contract, according to the changes mentioned above, has been estimated and is reflected in the 

statement of comprehensive income of the Company. 

(22) Subsequent events after Independents Accountant Opinion 

 

 On February 4, 2010, providence No. 0002344 from the National Integrated Service on Tributes and Customs Administration 

(SENIAT) was published in Official Gazette No. 39,361 in which the current tax unit value was adjusted from Bs. 55 to Bs. 65. 

 

 On February 26, 2010, the Board of Directors of the Company approved the issuance of the financial statements under International 

Financial Reporting Standards and submitted said financial statements to the Shareholders of the Company for approval purposes. 

(23) Supplementary Information on Oil and Gas Exploration and Production Activities (unaudited) 

 

 The following tables provide supplementary information on oil and gas exploration, development and production activities. All exploration 

and production activities are conducted mainly by CVP and Mixed Companies in Venezuela. 

 

 Table I — Crude Oil and Natural Gas Reserves 

 

 All crude oil and natural gas reserves located in Venezuela are owned by the Bolivarian Republic of Venezuela. Crude oil and natural gas 

reserves are estimated by PDVSA and reviewed by the People’s Power Ministry for Energy and Oil using reserve criteria that are 

consistent with those prescribed by the American Petroleum Institute (API) of the United States of America. 

 

 Proved reserves are the estimated quantities of crude oil and gas which, with reasonable certainty, are recoverable in future years from 

known deposits under existing economic and operating conditions. Due to the inherent uncertainties and limited nature of reservoir data, 

reserve estimates are subject to changes over time, as additional information becomes available. Proved reserves do not include additional 

volumes which may result from the extension of currently explored areas or from the application of secondary recovery processes not yet 

tested and determined to be economically feasible. 

 

 Proved developed oil and gas reserves are the quantities that can be recovered from existing wells with existing equipment and methods. 

Proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage or from existing 

wells. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

48 

 A summary of annual changes in proved crude oil and natural gas reserves is shown below: 

 (a) Conventional Crude Oil (in thousands of barrels) 

 

 Years ended December 31 

 2009 2008 2007 

Proved developed and undeveloped reserves of conventional crude oil at January 1 214,658 220,163 225,537 

Revisions — — — 

Expansions and discoveries — — — 

Production (7,835 ) (5,505 ) (5,374 ) 

    

Proved developed and undeveloped reserves of conventional crude oil at December 31 206,823 214,658 220,163 

 

 

 

 

 

 

 

 

Proved developed reserves of conventional crude oil at December 31 (included on the 

previous amount) 54,110 47,298 52,803 

 

 

 

 

 

 

 

 At December 31, 2009, 2008 and 2007, certified reserves assigned to the Company amounted to 206,823 thousands, 214,658 thousands 

and 220,163 thousands barrels, respectively. Production for the year ended December 31, 2009, 2008 and 2007 was 7,835 thousands, 5,505 

thousands and 5,374 thousands barrels. 

 (b) Natural Gas Reserves (in millions of cubic feet ) 

 

 Years ended December 31 

 2009 2008 2007 

Proved developed and undeveloped reserves of natural gas at January 1 273,281 283,981 297,437 

Revisions (2,592 ) — — 

Expansions and discoveries — — — 

Production (4,397 ) (10,700 ) (13,456 ) 

 

   

Proved developed and undeveloped reserves of natural gas at December 31 266,292 273,281 283,981 

 

 

 

 

 

 

 

 

Proved developed reserves of natural gas at December 31 (included on the previous amount) 25,641 32,630 43,330 

 

 

 

 

 

 

 

 Natural gas production is shown on the basis of actual volumes before the extraction of liquefiable hydrocarbons. 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

49 

 Table II — Costs Incurred in Exploration and Development Activities 

 

 Exploration costs include costs incurred from geological and geophysical activities, and drilling and equipping exploratory wells. The 

Company did not conduct exploration activities in 2009. Development costs include those for drilling and equipping development wells, 

enhanced recovery projects and facilities to extract, treat and store crude oil and natural gas. Annual costs, summarized below, include 

amounts both expensed and capitalized for the Company’s conventional crude oil reserves (In thousands): 

 

 Conventional Crude 

 U.S. dollars Bolivars 

 2009 2008 2009 2008 

Development costs 83,141 53,576 178,753 115,188 

 

 

   

 

Total costs incurred from development activities 83,141 53,576 178,753 115,188 

 

 

 

 

 

 

 

 

 

 Table III — Costs Recorded as Assets in Oil and Gas Production Activities 

 

 Costs recorded as assets for oil and gas exploration and production activities, as well as the related accumulated depreciation and 

amortization at December 31 for PDVSA’s conventional and extra-heavy crude oil reserves are summarized below (In thousands): 

 

 Conventional Crude 

 U.S. dollars Bolivars 

 2009 2008 2009 2008 

Assets used in production 319,386 238,211 686,678 512,155 

 

Equipment and facilities 7,466 3,737 16,051 8,034 

     

 326,852 241,948 702,729 520,189 

 

Accumulated Depletion, depreciation and amortization (94,322 ) (61,134 ) (202,791 ) (131,439 ) 

 

Construction in progress 32,912 30,946 70,760 66,534 

     

 

Total net costs capitalized as assets 265,442 211,760 570,698 455,284 

 

 

 

 

 

 

 

 

 
Table of Contents 

PETRODELTA, S.A. 

(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2009 and 2008 

50 

 Table IV — Results of Operations for Oil and Gas Production Activities for Each Year (In thousands) : 

 

 Conventional Crude 

 Years ended December 31 

 U.S. Dollar Bolivars 

 2009 2008 2009 2008 

Net production income 

Sales 458,251 474,619 985,239 1,020,431 

Production costs (59,152 ) (84,314 ) (127,176 ) (181,275 ) 

Royalties (157,681 ) (225,167 ) (339,014 ) (484,109 ) 

Depletion, depreciation and amortization (32,571 ) (24,778 ) (70,029 ) (53,273 ) 

  

 

  

 

Results of operation before income Tax 208,847 140,360 449,020 301,774 

 

Income tax (105,868 ) (69,374 ) (227,616 ) (149,154 ) 

     

 

Results production operation 102,979 70,986 221,404 152,620 

 

 

 

 

 

 

 

 

 

 Income from oil production is calculated at international market price as if all production were sold.

 

 Production costs are lifting costs incurred to operate and maintain productive wells and related facilities and equipment, including 

operating labor costs, materials, supplies, fuel consumed in operations and operating costs of natural liquid gas plants. 

 

 Depreciation and amortization expenses relate to assets used in exploration and production activities. Income tax expense is computed 

using the statutory rate for the year. For these purposes, the results of production operations do not include finance costs and corporate 

overhead nor their associated tax effects. 

 

 A summary of average per unit sale prices and production costs is shown below: 

 

 Years ended December 31 

 2009 2008 2009 2008 

 U.S. dollar Bolivars 

Average sale price 

 

Crude oil per barrel 57.62 84.52 123.88 181.72 

 

 

 

 

 

 

 

 

 

 

Natural gas per barrel 1.54 1.54 3.31 3.31 

 

 

 

 

 

 

 

 

 

 

Average production cost per BOE 6.90 11.57 14.84 24.88 

 

 

 

 

 

 

 

 

 
Exhibit 21.1 

EXHIBITS 

EXHIBIT 21.1 

HARVEST NATURAL RESOURCES, INC. 

LIST OF SUBSIDIARIES 

 The names of certain subsidiaries have been omitted in reliance upon Item 601(b)(21)(ii) of Regulation S-K. 

 

 

 Jurisdiction 

Name of Incorporation 

Harvest-Vinccler Dutch Holding B.V.* The Netherlands 

 

HNR Energia B.V. The Netherlands 

 

* All subsidiaries are wholly-owned by Harvest Natural Resources, Inc., except Harvest-Vinccler Dutch Holding B.V. which is indirectly 

owned 80 percent by Harvest Natural Resources, Inc.
Exhibit 23.1 

EXHIBIT 23.1 

HARVEST NATURAL RESOURCES, INC. 

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-134630, 333-115841, 333-94823, 

333-49114 and 333-85900) and Form S-3 (No. 333-162858) of Harvest Natural Resources, Inc. (formerly Benton Oil and Gas Company) of our 

report dated March 16, 2010 relating to the financial statements, financial statement schedule and the effectiveness of internal control over 

financial reporting which appears in this Annual Report on Form 10-K. 

/s/ PricewaterhouseCoopers LLP 

Houston, Texas 

March 16, 2010 

 
Exhibit 23.2 

EXHIBIT 23.2 

HARVEST NATURAL RESOURCES, INC. 

INDEPENDENT PETROLEUM ENGINEERS’ CONSENT 

 We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-115841, 333-94823, 333-49114 

and 333-85900) and Form S-3 (No. 333-162858) of Harvest Natural Resources, Inc. (formerly Benton Oil and Gas Company) of our reports 

dated February 26, 2010 relating to the reserve reports, which appears in this Annual Report on Form 10-K. 

/s/ Ryder Scott Company, L.P. 

Denver, Colorado 

March 16, 2010 

 
Exhibit 23.3 

EXHIBIT 23.3 

HARVEST NATURAL RESOURCES, INC. 

CONSENT OF INDEPENDENT ACCOUNTANTS 

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-134630, 333-115841, 333-94823, 

333-49114, and 333-85900), Form S-3 (No. 333-162858) and Form S-4 (No. 333-42139) of Harvest Natural Resources, Inc. (formerly Benton 

Oil and Gas Company) of our report dated January 22, 2010, except for the matters indicated in Note 22 whose date is February 26, 2010, 

relating to the financial statements of Petrodelta, S. A. at December 31, 2009 presented in accordance with International Reporting Standards, 

which appears in this Annual Report on Form 10-K. 

/s/ PGFA Perales, Pistone & Asociados 

Caracas, Venezuela 

March 16, 2010 

 
Exhibit 31.1 

EXHIBIT 31.1 

I, James A. Edmiston, certify that: 

Date: March 16, 2010 

 

 1. I have reviewed this report on Form 10-K of Harvest Natural Resources, Inc.; 

 

 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to 

make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the 

period covered by this report; 

 

 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material 

respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 

 

 4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as 

defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act 

Rules 13a-15(f) and 15d-15(f)) for the registrant and have: 

 a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our 

supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to 

us by others within those entities, particularly during the period in which this report is being prepared; 

 

 b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under 

our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial 

statements for external purposes in accordance with generally accepted accounting principles; 

 

 c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about 

the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such 

evaluation; and 

 

 d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s 

most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is 

reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 

 5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial 

reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent 

functions): 

 a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are 

reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and 

 

 b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s 

internal control over financial reporting. 

 

 

 /s/ James A. Edmiston 

 James A. Edmiston 

 President and Chief Executive Officer 
Exhibit 31.2 

EXHIBIT 31.2 

I, Stephen C. Haynes, certify that: 

Date: March 16, 2010 

 

 

 1. I have reviewed this report on Form 10-K of Harvest Natural Resources, Inc.; 

 

 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to 

make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the 

period covered by this report; 

 

 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material 

respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 

 

 4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as 

defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act 

Rules 13a-15(f) and 15d-15(f)) for the registrant and have: 

 a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our 

supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to 

us by others within those entities, particularly during the period in which this report is being prepared; 

 

 b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under 

our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial 

statements for external purposes in accordance with generally accepted accounting principles; 

 

 c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about 

the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such 

evaluation; and 

 

 d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s 

most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is 

reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 

 5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial 

reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent 

functions): 

 a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are 

reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and 

 

 b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s 

internal control over financial reporting. 

 

 

 /s/ Stephen C. Haynes 

 Stephen C. Haynes 

 

Vice President - Finance, Chief Financial 

Officer and Treasurer 
Exhibit 32.1 

EXHIBIT 32.1 

Accompanying Certificate 

Pursuant to Rule 13a-14(b) or Rule 15d-14(b) 

and 18 U.S.C. Section 1350 

Not Filed Pursuant to the Securities Exchange Act of 1934 

 The undersigned Chief Executive Officer of Harvest Natural Resources, Inc. (the “Company”) does hereby certify as follows: 

 This report on Form 10-K of Harvest Natural Resources, Inc. for the period ended December 31, 2009 and filed with the Securities and 

Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of Section 13a or 15d of the Securities Exchange 

Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations 

of the Company. 

 

 

 

 

Date: March 16, 2010 By: /s/ James A. Edmiston 

 James A. Edmiston 

 President and Chief Executive Officer 
Exhibit 32.2 

EXHIBIT 32.2 

Accompanying Certificate 

Pursuant to Rule 13a-14(b) or Rule 15d-14(b) 

and 18 U.S.C. Section 1350 

Not Filed Pursuant to the Securities Exchange Act of 1934 

 The undersigned Chief Financial Officer of Harvest Natural Resources, Inc. (the “Company”) does hereby certify as follows: 

 This report on Form 10-K of Harvest Natural Resources, Inc. for the period ended December 31, 2009 and filed with the Securities and 

Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of Section 13a or 15d of the Securities Exchange 

Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations 

of the Company. 

 

 

 

 

Date: March 16, 2010 /s/ Stephen C. Haynes 

 Stephen C. Haynes 

 

Vice President - Finance, Chief Financial 

Officer and Treasurer 

 
Exhibit 99.1 

February 26, 2010 

Harvest (US) Holdings, Inc. 

1177 Enclave Parkway, Suite 300 

Houston, Texas, 77077 

Gentlemen: 

 At your request, we have prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold of 

Harvest (US) Holdings, Inc. (Harvest) as of December 31, 2009. The subject properties are located in the state of Utah, in the United States of 

America and are in a new geologic basin for Harvest. Optional Probable and Possible volumes are not reported for this basin due to the ongoing 

evaluation of assets within these categories. The reserves and income data were estimated based on the definitions and disclosure guidelines 

contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas 

Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The results of our third party study, completed on 

February 26, 2010, are presented herein. The properties reviewed by Ryder Scott represent 0.5 percent (0.005) of the total net proved liquid 

hydrocarbon reserves and 2.2 percent (0.022) of the total net proved gas reserves of Harvest. 

 The estimated reserves and future net income amounts presented in this report, as of December 31, 2009 are related to hydrocarbon prices. 

The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date 

of the period covered in this report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each 

month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. Actual future prices may 

vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income 

actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized on the 

next page. 

 

 

 

 

 FAX (303) 623-4258 

 

 621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 

80293 TELEPHONE (303) 623-9147 

 

Attention: Steven Haynes 

 Phil Harries 

 

1100 LOUISIANA, SUITE 3800HOUSTON, TEXAS 77002-5218 TEL (713) 651-9191 FAX (713) 651-0849 

530 8TH AVENUE, S.W., SUITE 1200CALGARY, ALBERTA T2P 3S8TEL (403) 262-2799 FAX (403) 262-2790 
 

Harvest (US) Holdings, Inc. 

February 26, 2010 

Page 2 

SEC PARAMETERS 

Estimated Net Reserves and Income Data 

Certain Leasehold and Royalty Interests of 

Harvest (US) Holdings, Inc. 

As of December 31, 2009 

 Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels. All gas volumes are reported on an “as sold” basis expressed in 

millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. 

 PHDWin Petroleum Economic Evaluation Software (version 2.8 Build 10), a copyrighted program of TRC Consultants L.C was used solely 

at the request of Harvest. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may 

vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may 

vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not 

material. 

 The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, 

ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The future net income is before the 

deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist 

nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 75 percent 

and gas reserves account for the remaining 25 percent of total future gross revenue from proved reserves. 

 The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future 

net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as 

follows. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 

 

 Proved 

 Developed Total 

 Producing Non-Producing Undeveloped Proved 

Net Remaining Reserves 

Oil/Condensate — Barrels 32,117 98,482 95,401 225,999 

Gas — MMCF 161 492 473 1,126 

 

Income Data 

Future Gross Revenue $ 1,990 $ 6,102 $ 5,899 $ 13,990 

Deductions 523 925 2,761 4,210 

 

 

 

  

Future Net Income (FNI) $ 1,466 $ 5,176 $ 3,138 $ 9,780 

 

Discounted FNI @ 10% $ 1,053 $ 3,987 $ 1,773 $ 6,812 

 

 Discounted Future 

 Net Income- $M 

 As of December 31, 2009 

Discount Rate Total 

Percent Proved 

 5 $ 7,940 

 8 $ 7,206 

 12 $ 6,476 

 15 $ 6,054 
 

Harvest (US) Holdings, Inc. 

February 26, 2010 

Page 3 

 The results shown above are presented for your information and should not be construed as our estimate of fair market value. 

Reserves Included in This Report 

 The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations 

Part 210.4-10 (a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as 

an attachment to this report. 

 The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. 

 No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The gas volumes 

included herein attributes gas consumed in operations as reserves. 

 While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs 

relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, 

omitted from consideration in making this evaluation. 

 Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with 

reasonable certainty to be economically producible from a given date forward. Moreover, estimates of reserves may increase or decrease as a 

result of future operations, effects of regulation by governmental agencies or geopolitical risks. As a result, the estimates of oil and gas reserves 

have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being exact 

quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be 

more or less than the estimated amounts. 

 The reserves reported herein are limited to the period prior to expiration of current contracts providing the legal right to produce or a revenue 

interest in such production unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different 

countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Harvest for the production of these 

volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, 

when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Harvest the net economic benefit attributed to such 

operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or 

verification of such contractual information. Neither our review of such contractual information or our acceptance of Harvest’s representations 

regarding such contractual information should be construed as a legal opinion on this matter. 

 Ryder Scott did not evaluate country and geopolitical risks in the countries where Harvest operates or has interests. Harvest’s operations may 

be subject to various levels of governmental controls and regulations. These controls and regulations may include matters relating to land tenure, 

drilling, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, 

and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause 

volumes of reserves 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 
 

Harvest (US) Holdings, Inc. 

February 26, 2010 

Page 4 

actually recovered and amounts of income actually received to differ significantly from the estimated quantities. 

 The estimates of reserves presented herein were based upon a detailed study of the properties in which Harvest owns an interest; however, we 

have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may 

exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. 

Estimates of Reserves 

 The reserves for the properties included herein were estimated by performance methods or the volumetric method. In general, reserves 

attributable to producing wells and/or reservoirs were estimated by performance methods such as decline curve analysis, material balance and/or 

reservoir simulation which utilized extrapolations of historical production and pressure data available through December 31, 2009 in those cases 

where such data were considered to be definitive. In certain cases, producing reserves were estimated by the volumetric method where there 

were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the 

reserve estimates was considered to be inappropriate. Reserves attributable to non-producing and undeveloped reserves included herein were 

estimated by the volumetric method which utilized all pertinent well and seismic data available through December 31, 2009. 

 In general, the reserves included herein were estimated by performance methods or the volumetric method; however, other methods were 

used in certain cases where characteristics of the data indicated such other methods were more appropriate in our opinion. The reserves estimated 

by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were 

estimated by the volumetric method in those cases where there were inadequate historical performance data to establish a definitive trend or 

where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. 

 To estimate economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and assumptions 

including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be 

measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the 

SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic 

conditions including the prices and costs at which economic producibility from a reservoir is to be determined as of the effective date of the 

report. Harvest has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other 

data required for this investigation. In preparing our forecast of future production and income, we have relied upon data furnished by Harvest 

with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, 

other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment 

costs after salvage, product prices based on the SEC regulations, geological structural and isochore maps, well logs, core analyses, and pressure 

measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the 

data supplied by Harvest. 

Future Production Rates 

 Our forecasts of future production rates are based on historical performance from wells now on production. Test data and other related 

information were used to estimate the anticipated initial 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 
 

Harvest (US) Holdings, Inc. 

February 26, 2010 

Page 5 

production rates for those wells or locations that are not currently producing. If no production decline trend has been established, future 

production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was 

anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used 

as the basis for estimating future production rates. For reserves not yet on production, sales were estimated to commence at an anticipated date 

furnished by Harvest. 

 The future production rates from wells now on production may be more or less than estimated because of changes in market demand or 

allowables set by regulatory bodies. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our 

estimates. 

Hydrocarbon Prices 

 As previously stated, the hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month 

period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on 

the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products 

sold under contract, the contract prices including fixed and determinable escalations, exclusive of inflation adjustments, were used until 

expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously 

described. Product prices which were actually used for each property reflect adjustment for gravity, quality, local conditions, and/or distance 

from market. 

 The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property 

evaluations. 

Costs 

 Operating costs for the leases and wells in this report are based on the operating expense reports of Harvest and include only those costs 

directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases 

and wells. When applicable for operated properties, the operating costs include an appropriate level of corporate general administrative and 

overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and 

wells under terms of operating agreements. No deduction was made for loan repayments, interest expenses, or exploration and development 

prepayments that were not charged directly to the leases or wells. 

 Development costs were furnished to us by Harvest and are based on authorizations for expenditure for the proposed work or actual costs for 

similar projects. Harvest’s estimates of zero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott 

has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Harvest’s estimate. 

 Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved 

undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled. Harvest has assured 

us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, 

regulatory or political obstacles that would significantly alter their plans. 

 Current costs used by Harvest were held constant throughout the life of the properties. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 
 

Harvest (US) Holdings, Inc. 

February 26, 2010 

Page 6 

Standards of Independence and Professional Qualification 

 Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the 

world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, 

Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients 

for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors 

of any publicly traded oil and gas company and are separate and independent from the operating and investment decision-making process of our 

clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services. 

 Ryder Scott actively participates in industry related professional societies and organizes an annual public forum focused on the subject of 

reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related 

topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education. 

 Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional 

accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, 

or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. 

 We are independent petroleum engineers with respect to Harvest. Neither we nor any of our employees have any interest in the subject 

properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which 

were reviewed. 

 The professional qualifications of the undersigned, the technical person(s) primarily responsible for reviewing and approving the reserves 

information discussed in this report, are included as an attachment to this letter. 

Terms of Usage 

 This report was prepared for the exclusive use and sole benefit of Harvest and may not be put to other use without our prior written consent 

for such use. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. 

Please contact us if we can be of further service. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 

 

 Very truly yours, 

 

 RYDER SCOTT COMPANY, L.P. 

 TBPE Firm Registration No. F-1580 

 

 /s/ Scott Wilson 

 Scott Wilson, P.E., M.B.A. 

 Senior Vice President 

/sm 

 
 

Harvest (US) Holdings, Inc. 

February 26, 2010 

Page 8 

Professional Qualifications of Primary Technical Person 

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott 

Company, L.P. Mr. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and 

income presented herein. 

Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2000, is a Senior Vice President responsible for coordinating and 

supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, 

Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company. For more information regarding Mr. Wilson’s 

geographic and job specific experience, please refer to the Ryder Scott Company website at 

http://www.ryderscott.com/Experience/Employees.php. 

Mr. Wilson earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance 

from the University of Colorado in 1985, graduating from both with High Honors. He is a registered Professional Engineer by exam in the States 

of Alaska, Colorado, and Wyoming. He is also an active member of the Society of Petroleum Engineers; serving as co-Chairman of the SPE 

Reserves and Economics Technology Interest Group, and Gas Technology Editor for SPE’s Journal of Petroleum Technology. He is a member 

and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers. Mr. Wilson has published several technical papers 

and holds two US patents. 

In addition to gaining experience and competency through prior work experience, the Wyoming Board of Professional Engineers requires a 

minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson 

fulfills. As part of his 2009 continuing education hours, Mr. Wilson attended an internally presented sixteen hours of formalized training as well 

as a public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 

17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. 

Mr. Wilson attended an additional seven hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE 

Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, procedures and software and 

ethics for consultants. 

Based on his educational background, professional training and more than 25 years of practical experience in the estimation and evaluation of 

petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III 

of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum 

Engineers as of February 19, 2007. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 
 

PETROLEUM RESERVES DEFINITIONS 

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) 

PREAMBLE 

 On January 14, 2009, the United States Securities and Exchange Commission (“the Commission”) published the “Modernization of Oil and 

Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and 

Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to 

the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of 

Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the 

“SEC Regulations”. The SEC Regulations take effect with all filings made with the United States Securities and Exchange Commission as of 

December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, 

Regulation S-X Part 210, Rule 4-10 (a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in 

part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein). 

 Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date 

forward under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of 

reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty 

may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to 

be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing 

uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally 

disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations 

continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any 

document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as 

noted in §229.102 (5). 

 Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. 

 Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for 

supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure 

maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other 

improved recovery methods may be developed in the future as petroleum technology continues to evolve. 

 
 

PETROLEUM RESERVES DEFINITIONS 

Page 2 

RESERVES (SEC DEFINITIONS) 

 Securities and Exchange Commission Regulation S-X §229.4-10(a) (26) defines reserves as follows: 

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a 

given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable 

expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or 

related substances to market, and all permits and financing required to implement the project. 

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those 

reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a 

known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas 

may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations). 

PROVED RESERVES (SEC DEFINITIONS) 

 Securities and Exchange Commission Regulation S-X §229.4-10(a) (22) defines proved oil and gas reserves as follows: 

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering 

data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under 

existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to 

operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are 

used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will 

commence the project within a reasonable time. 

(i) The area of the reservoir considered as proved includes: 

(A) The area identified by drilling and limited by fluid contacts, if any, and 

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain 

economically producible oil or gas on the basis of available geoscience and engineering data. 

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a 

well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable 

certainty. 

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an 

associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or 

performance data and reliable technology establish the higher contact with reasonable certainty. 

 
 

RESERVES DEFINITIONS 

Page 3 

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid 

injection) are included in the proved classification when: 

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the 

operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the 

reasonable certainty of the engineering analysis on which the project or program was based; and 

(B) The project has been approved for development by all necessary parties and entities, including governmental entities. 

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price 

shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an 

unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual 

arrangements, excluding escalations based upon future conditions. 

[Remainder of this page is left blank intentionally] 

 
 

PETROLEUM RESERVES DEFINITIONS 

Page 4 

RESERVES STATUS DEFINITIONS AND GUIDELINES 

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) 

and 

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS) 

Sponsored and Approved by: 

SOCIETY OF PETROLEUM ENGINEERS (SPE), 

WORLD PETROLEUM COUNCIL (WPC) 

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG) 

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) 

 Reserves status categories define the development and producing status of wells and reservoirs. 

DEVELOPED RESERVES (SEC DEFINITIONS) 

 Securities and Exchange Commission Regulation S-X §229.4-10(a) (6) defines developed oil and gas reserves as follows: 

Developed oil and gas reserves are reserves of any category that can be expected to be recovered: 

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor 

compared to the cost of a new well; and 

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means 

not involving a well. 

Developed Producing (SPE-PRMS Definitions) 

 While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according 

to the guidance contained in the SPE-PRMS as Producing or Non-Producing. 

Developed Producing Reserves 

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the 

estimate. 

Improved recovery reserves are considered producing only after the improved recovery project is in operation. 

Developed Non-Producing 

Developed Non-Producing Reserves include shut-in and behind-pipe reserves. 

 
 

PETROLEUM RESERVES DEFINITIONS 

Page 5 

Shut-In 

Shut-in Reserves are expected to be recovered from:

Behind-Pipe 

Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. 

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. 

UNDEVELOPED RESERVES (SEC DEFINITIONS) 

 Securities and Exchange Commission Regulation S-X §229.4-10(a) (31) defines undeveloped oil and gas reserves as follows: 

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or 

from existing wells where a relatively major expenditure is required for recompletion. 

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of 

production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at 

greater distances. 

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they 

are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. 

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid 

injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in 

the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology 

establishing reasonable certainty. 

 

 (1) completion intervals which are open at the time of the estimate but which have not yet started producing; 

 

 (2) wells which were shut-in for market conditions or pipeline connections; or 

 

 (3) wells not capable of production for mechanical reasons. 
Exhibit 99.2 

HNR Finance B.V. 

Prins Bernhardplein 200 

P.O. Box 990 

1000 AZ Amsterdam, Netherlands 

Gentlemen: 

 At your request, we have prepared an estimate of the reserves, future production, and income attributable to HNR Finance B.V.’s (“HNR”) 

interest in certain properties located in the Greater Oficina Trend of Eastern Venezuela. These properties have been included in a company called 

Petrodelta S.A., in which HNR Finance B.V. has a 40 percent interest, and Corporación Venezolana del Petroleo S.A. (CVP) has 60 percent 

interest. The properties include six fields, Uracoa, Tucupita, Bombal, Temblador, Isleño, and El Salto (“Petrodelta fields”). 

 At your request, we have prepared an estimate of the proved, probable and possible reserves, future production, and income attributable to 

certain leasehold and royalty interests of HNR Finance B.V. as of December 31, 2009. The subject properties are located in the state of 

Monagas, Venezuela. The reserves and income data were estimated based on the definitions and disclosure guidelines contained in the United 

States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released 

January 14, 2009 in the Federal Register (SEC regulations). The results of our third party study, completed on February 26, 2010, are presented 

herein. The properties reviewed by Ryder Scott represent 100 percent of the total net proved, probable and possible liquid hydrocarbon reserves 

and 100 percent of the total net proved, probable and possible gas reserves of HNR Finance B.V.. 

 The estimated reserves and future net income amounts presented in this report, as of December 31, 2009 are related to hydrocarbon prices. 

The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date 

of the period covered in this report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each 

month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. Actual future prices may 

vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income 

actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized on the 

next page. 

1100 LOUISIANA, SUITE 3800 HOUSTON, TEXAS 77002-5218 TEL (713) 651-9191 FAX (713) 651-0849 

530 8TH AVENUE, S.W., SUITE 1200 CALGARY, ALBERTA T2P 3S8TEL (403) 262-2799 FAX (403) 262-2790 

 

 

 

 

 FAX (303) 623-4258 

 

 621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 

80293 TELEPHONE (303) 623-9147 

 

 February 26, 2010 

 

Attention: Harvest (US) Holdings, Inc. — Director A 

 Fortis Intertrust (Netherlands) B.V. — Director B 
 

HNR Finance B.V. 

February 26, 2010 

Page 2 

SEC PARAMETERS 

Estimated Net Reserves and Income Data 

Certain Leasehold and Royalty Interests of 

Petrodelta S.A. 

As of December 31, 2009 

 Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold” basis expressed in millions of 

cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. 

 PHDWin Petroleum Economic Evaluation Software (version 2.8 Build 3), a copyrighted program of TRC Consultants L.C.; the program was 

used solely at the request of HNR Finance B.V. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries 

and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line 

economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding 

differences are not material. 

 The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, 

ad valorem taxes, recompletion costs and development costs. The future net income is before the deduction of state and federal income taxes and 

general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on 

hand or undistributed income. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 

 

 Proved 

 Developed Total 

 Producing Non-Producing Undeveloped Proved 

Net Remaining Reserves 

Oil/Condensate — Barrels 11,404,822 2,836,884 33,177,013 47,418,720 

Gas — MMCF 23,217 797 38,695 62,710 

 

Income Data $M 

Future Gross Revenue $ 665,351 $ 162,448 $ 1,945,040 $ 2,772,840 

Deductions 143,274 39,202 730,074 912,550 

  

   

Future Net Income (FNI) $ 522,077 $ 123,246 $ 1,214,966 $ 1,860,289 

 

Discounted FNI @ 10% $ 322,904 $ 66,901 $ 624,855 $ 1,014,660 

 

 Total Total 

 Probable Possible 

Net Remaining Reserves 

Oil/Condensate — Barrels 43,806,586 168,516,762 

Gas — MMCF 14,686 46,434 

 

Income Data M$ 

Future Gross Revenue $ 2,512,145 $ 9,648,315 

Deductions 919,142 3,102,372 

   

Future Net Income (FNI) $ 1,593,003 $ 6,545,943 

 

Discounted FNI @ 10% $ 698,265 $ 2,388,673 
 

HNR Finance B.V. 

February 26, 2010 

Page 3 

 Liquid hydrocarbon reserves account for approximately 97 percent of the total future gross revenue from proved reserves and gas reserves 

account for the remaining 3 percent of total future gross revenue from proved reserves. Liquid hydrocarbon reserves account for approximately 

99 percent of the total future gross revenue from probable reserves and gas reserves account for the remaining 1 percent of total future gross 

revenue from probable reserves. Liquid hydrocarbon reserves account for approximately 99 percent of the total future gross revenue from 

possible reserves and gas reserves account for the remaining 1 percent of total future gross revenue from possible reserves. 

 The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future 

net income was discounted at four other discount rates, which were also compounded monthly. These results are shown in summary form as 

follows. 

 The results shown above are presented for your information and should not be construed as our estimate of fair market value. 

Reserves Included in This Report 

 The proved, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange 

Commission’s Regulations Part 210.4-10 (a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum 

Reserves Definitions” is included as an attachment to this report. 

 The various reserve status categories are defined in the attachment to this report entitled “Petroleum Reserves Definitions.” 

 No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The gas volumes 

included herein attributes gas consumed in operations as reserves. 

 While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs 

relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, 

omitted from consideration in making this evaluation. 

 Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with 

reasonable certainty to be economically producible from a given date forward. Probable reserves are those additional reserves that are less 

certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are 

those additional reserves which are less certain to be recovered than probable reserves and thus the probability of achieving or exceeding the 

proved plus probable plus possible reserves is low. The reserves included herein were estimated using 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 

 

 Discounted Future Net Income 

 As of December 31, 2009 

Discount Rate Total Total Total 

Percent Proved Probable Possible 

 5 $ 1,340,542 $ 1,032,335 $ 3,851,928 

 8 $ 1,128,363 $ 812,682 $ 2,874,765 

12 $ 918,104 $ 603,382 $ 1,999,587 

15 $ 798,559 $ 489,450 $ 1,551,800 
 

HNR Finance B.V. 

February 26, 2010 

Page 4 

deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are 

estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. 

 The reserves and income quantities attributable to the different reserve classifications that are included herein have not been adjusted to 

reflect these varying degrees of risk associated with them and thus are not comparable. Moreover, estimates of reserves may increase or decrease 

as a result of future operations, effects of regulation by governmental agencies or geopolitical risks. As a result, the estimates of oil and gas 

reserves have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being 

exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could 

be more or less than the estimated amounts. 

 The reserves reported herein are limited to the period prior to expiration of current contracts providing the legal right to produce or a revenue 

interest in such production unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different 

countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Petrodelta, S.A. for the production of 

these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. 

Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with HNR Finance B.V. the net economic 

benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an 

exhaustive audit or verification of such contractual information. Neither our review of such contractual information or our acceptance of HNR 

Finance B.V.’s representations regarding such contractual information should be construed as a legal opinion on this matter. 

 Ryder Scott did not evaluate country and geopolitical risks in the countries where HNR Finance B.V. operates or has interests. HNR Finance 

B.V.’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include matters 

relating to land tenure, drilling, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies 

including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations 

and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the 

estimated quantities. 

 The estimates of reserves presented herein were based upon a detailed study of the properties in which Petrodelta, S.A. owns an interest; 

however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental 

liabilities that may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating 

practices. 

Estimates of Reserves 

The reserves for the properties included herein were estimated by performance methods or the volumetric method. In general, reserves 

attributable to producing wells and/or reservoirs were estimated by performance methods such as decline curve analysis, material balance and/or 

reservoir simulation which utilized extrapolations of historical production and pressure data available through December 31, 2009 in those cases 

where such data were considered to be definitive. In certain cases, producing reserves were estimated by the volumetric method where there 

were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the 

reserve estimates was considered to be inappropriate. Reserves attributable to proved, 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 
 

HNR Finance B.V. 

February 26, 2010 

Page 5 

probable and possible non-producing and undeveloped reserves included herein were estimated by the volumetric method which utilized all 

pertinent well and seismic data available through 2009. 

 To estimate economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and assumptions 

including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be 

measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the 

SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be demonstrated to be economically producible based 

on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined as of the 

effective date of the report. HNR Finance B.V. has informed us that they have furnished us all of the accounts, records, geological and 

engineering data, and reports and other data required for this investigation. In preparing our forecast of future production and income, we have 

relied upon data furnished by HNR Finance B.V. with respect to property interests owned, production and well tests from examined wells, 

normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, 

recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, geological structural and 

isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we 

have not conducted an independent verification of the data supplied by HNR Finance B.V. 

Future Production Rates 

 Our forecasts of future production rates are based on historical performance from wells now on production. Test data and other related 

information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. If no 

production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where 

appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a 

decline trend has been established, this trend was used as the basis for estimating future production rates. For reserves not yet on production, 

sales were estimated to commence at an anticipated date furnished by HNR Finance B.V. 

 The future production rates from wells now on production may be more or less than estimated because of changes in market demand or 

allowables set by regulatory bodies. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our 

estimates. 

Hydrocarbon Prices 

 As previously stated, the hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month 

period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on 

the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products 

sold under contract, the contract prices including fixed and determinable escalations, exclusive of inflation adjustments, were used until 

expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously 

described. Product prices which were actually used for each property reflect adjustment for gravity, quality, local conditions, and/or distance 

from market. 

 The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property 

evaluations. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 
 

HNR Finance B.V. 

February 26, 2010 

Page 6 

Costs 

 Operating costs for the leases and wells in this report are based on the operating expense reports of HNR Finance B.V. and include only those 

costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the 

leases and wells. When applicable for operated properties, the operating costs include an appropriate level of corporate general administrative 

and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases 

and wells under terms of operating agreements. No deduction was made for loan repayments, interest expenses, or exploration and development 

prepayments that were not charged directly to the leases or wells. 

 Development costs were furnished to us by HNR Finance B.V. and are based on authorizations for expenditure for the proposed work or 

actual costs for similar projects. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net 

of salvage were significant. The estimates of the net abandonment costs furnished by HNR Finance B.V. were accepted without independent 

verification. 

 Because of the direct relationship between volumes of proved, probable and possible undeveloped reserves and development plans, we 

include in the proved, probable and possible undeveloped category only reserves assigned to undeveloped locations that we have been assured 

will definitely be drilled. HNR Finance B.V. has assured us of their intent and ability to proceed with the development activities included in this 

report, and that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. 

 Although some development capital is projected for blowdown recompletions, operations, and maintenance beyond 2014, these amounts are 

in accordance with long-term project plans and are insignificant compared to activities pursued within 5 years of December 31, 2009 

(approximately 2%). 

 Accounting for past bookings under previous SEC rules, a portion of Harvest’s 164-well proved undeveloped portfolio may not be drilled 

until the sixth year after the initial booking, but still within 5 years of December 31, 2009. Under the new SEC regulations, undeveloped reserves 

should be developed within 5 years of the initial booking unless special circumstances exist. Ryder Scott has discussed these reserves with 

Harvest and Harvest believes that, in accordance with guidance provided by the SEC, special circumstances do exist with respect to these 

reserves and warrant classification of these reserves as proved undeveloped reserves. Ryder Scott has included these reserves in this report based 

on our understanding of these exceptional circumstances. 

 Current costs used by HNR Finance B.V. were held constant throughout the life of the properties. 

Standards of Independence and Professional Qualification 

 Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the 

world for over seventy years. Ryder Scott is employee owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, 

Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients 

for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors 

of any publicly traded oil and gas company and are separate and independent from the operating and investment decision-making process of our 

clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 
 

HNR Finance B.V. 

February 26, 2010 

Page 7 

 Ryder Scott actively participates in industry related professional societies and organizes an annual public forum focused on the subject of 

reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related 

topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education. 

 Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional 

accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, 

or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. 

 We are independent petroleum engineers with respect to HNR Finance B.V. Neither we nor any of our employees have any interest in the 

subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties 

which were reviewed. 

 The professional qualifications of the undersigned, the technical person primarily responsible for reviewing and approving the reserves 

information discussed in this report, are included as an attachment to this letter. 

Terms of Usage 

 This report was prepared for the exclusive use and sole benefit of HNR Finance B.V. Company and may not be put to other use without our 

prior written consent for such use. The data and work papers used in the preparation of this report are available for examination by authorized 

parties in our offices. Please contact us if we can be of further service. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 

 

 Very truly yours, 

 

 RYDER SCOTT COMPANY, L.P. 

 TBPE Firm Registration No. F-1580 

 

 /s/ Scott Wilson 

 Scott J. Wilson, P.E., MBA 

 Senior Vice President 

 

 

 
 

HNR Finance B.V. 

February 26, 2010 

Page 9 

Professional Qualifications of Primary Technical Person 

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott 

Company, L.P. Mr. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and 

income presented herein. 

Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2000, is a Senior Vice President responsible for coordinating and 

supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, 

Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company. For more information regarding Mr. Wilson’s 

geographic and job specific experience, please refer to the Ryder Scott Company website at 

http://www.ryderscott.com/Experience/Employees.php. 

Mr. Wilson earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance 

from the University of Colorado in 1985, graduating from both with High Honors. He is a registered Professional Engineer by exam in the States 

of Alaska, Colorado, and Wyoming. He is also an active member of the Society of Petroleum Engineers; serving as co-Chairman of the SPE 

Reserves and Economics Technology Interest Group, and Gas Technology Editor for SPE’s Journal of Petroleum Technology. He is a member 

and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers. Mr. Wilson has published several technical papers 

and holds two US patents. 

In addition to gaining experience and competency through prior work experience, the Wyoming Board of Professional Engineers requires a 

minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson 

fulfills. As part of his 2009 continuing education hours, Mr. Wilson attended an internally presented sixteen hours of formalized training as well 

as a public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 

17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. 

Mr. Wilson attended an additional seven hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE 

Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, procedures and software and 

ethics for consultants. 

Based on his educational background, professional training and more than 25 years of practical experience in the estimation and evaluation of 

petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III 

of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum 

Engineers as of February 19, 2007. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS — TBPE FIRM LIC. NO. F-1580 

 
 

PETROLEUM RESERVES DEFINITIONS 

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) 

PREAMBLE 

 On January 14, 2009, the United States Securities and Exchange Commission (“the Commission”) published the “Modernization of Oil 

and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil 

and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions 

to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization 

of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as 

the “SEC Regulations”. The SEC Regulations take effect with all filings made with the United States Securities and Exchange Commission as of 

December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, 

Regulation S-X Part 210, Rule 4-10 (a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in 

part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein). 

 Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date 

forward under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of 

reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty 

may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to 

be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing 

uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally 

disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations 

continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any 

document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as 

noted in §229.102 (5). 

 Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. 

 Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for 

supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure 

maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other 

improved recovery methods may be developed in the future as petroleum technology continues to evolve. 

 
 

PETROLEUM RESERVES DEFINITIONS 

Page 2 

RESERVES (SEC DEFINITIONS) 

 Securities and Exchange Commission Regulation S-X §229.4-10(a) (26) defines reserves as follows: 

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a 

given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable 

expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or 

related substances to market, and all permits and financing required to implement the project. 

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those 

reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a 

known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas 

may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations). 

PROVED RESERVES (SEC DEFINITIONS) 

 Securities and Exchange Commission Regulation S-X §229.4-10(a) (22) defines proved oil and gas reserves as follows: 

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering 

data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under 

existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to 

operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are 

used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will 

commence the project within a reasonable time. 

(i) The area of the reservoir considered as proved includes: 

(A) The area identified by drilling and limited by fluid contacts, if any, and 

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain 

economically producible oil or gas on the basis of available geoscience and engineering data. 

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a 

well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable 

certainty. 

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an 

associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or 

performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced 

economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved 

classification when: 

 
 

PETROLEUM RESERVES DEFINITIONS 

Page 3 

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the 

operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the 

reasonable certainty of the engineering analysis on which the project or program was based; and 

(B) The project has been approved for development by all necessary parties and entities, including governmental entities. 

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price 

shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an 

unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual 

arrangements, excluding escalations based upon future conditions. 

PROBABLE RESERVES (SEC DEFINITIONS) 

 Securities and Exchange Commission Regulation S-X §229.4-10(a) (18) defines probable oil and gas reserves as follows: 

Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, 

together with proved reserves, are as likely as not to be recovered. 

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated 

proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities 

recovered will equal or exceed the proved plus probable reserves estimates. 

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available 

data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. 

Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the 

proved reservoir. 

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the 

hydrocarbons in place than assumed for proved reserves. 

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. 

POSSIBLE RESERVES (SEC DEFINITIONS) 

 Securities and Exchange Commission Regulation S-X §229.4-10(a) (17) defines possible oil and gas reserves as follows: 

 
 

PETROLEUM RESERVES DEFINITIONS 

Page 4 

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. 

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved 

plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities 

ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. 

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of 

available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define 

clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than 

the recovery quantities assumed for probable reserves. 

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical 

and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in 

successful similar projects. 

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the 

same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological 

discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication 

with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if 

these areas are in communication with the proved reservoir. 

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the 

potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the 

HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not 

meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure 

gradient interpretations. 

[Remainder of this page is left blank intentionally] 

 
 

PETROLEUM RESERVES DEFINITIONS 

Page 5 

RESERVES STATUS DEFINITIONS AND GUIDELINES 

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) 

and 

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS) 

Sponsored and Approved by: 

SOCIETY OF PETROLEUM ENGINEERS (SPE), 

WORLD PETROLEUM COUNCIL (WPC) 

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG) 

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) 

 Reserves status categories define the development and producing status of wells and reservoirs. 

DEVELOPED RESERVES (SEC DEFINITIONS) 

 Securities and Exchange Commission Regulation S-X §229.4-10(a) (6) defines developed oil and gas reserves as follows: 

Developed oil and gas reserves are reserves of any category that can be expected to be recovered: 

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor 

compared to the cost of a new well; and 

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means 

not involving a well. 

Developed Producing (SPE-PRMS Definitions) 

 While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according 

to the guidance contained in the SPE-PRMS as Producing or Non-Producing. 

 Developed Producing Reserves 

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the 

estimate. 

Improved recovery reserves are considered producing only after the improved recovery project is in operation. 

 Developed Non-Producing 

Developed Non-Producing Reserves include shut-in and behind-pipe reserves. 

 
 

PETROLEUM RESERVES DEFINITIONS 

Page 6 

 Shut-In 

 Shut-in Reserves are expected to be recovered from:

 Behind-Pipe 

Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. 

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. 

UNDEVELOPED RESERVES (SEC DEFINITIONS) 

 Securities and Exchange Commission Regulation S-X §229.4-10(a) (31) defines undeveloped oil and gas reserves as follows: 

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or 

from existing wells where a relatively major expenditure is required for recompletion. 

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of 

production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic 

producibility at greater distances. 

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that 

they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. 

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid 

injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in 

the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable 

technology establishing reasonable certainty. 

 

 (1) completion intervals which are open at the time of the estimate but which have not yet started producing; 

 

 (2) wells which were shut-in for market conditions or pipeline connections; or 

 

 (3) wells not capable of production for mechanical reasons.