UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No.: 1-10762

HARVEST NATURAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware	77-0196707
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)
1177 Enclave Parkway, Suite 300
Houston, Texas	77077
(Address of principal executive offices)	(Zip Code)

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

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

Title of each class	Name of each exchange on which registered
Common Stock, $.01 Par Value	NYSE

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

Preferred Share Purchase Rights

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

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  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    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  x    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.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

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, 2011 was: $372,593,974.

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 2, 2012, shares outstanding: 34,317,087.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for the 2012 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		17
Item 1B.	Unresolved Staff Comments		22
Item 2.	Properties		23
Item 3.	Legal Proceedings		23
Item 4.	Mine Safety Disclosures		25
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		26
Item 6.	Selected Financial Data		27
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		48
Item 8.	Financial Statements and Supplementary Data		48
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		48
Item 9A.	Controls and Procedures		48
Item 9B.	Other Information		49
Part III
Item 10.	Directors, Executive Officers and Corporate Governance		50
Item 11.	Executive Compensation		50
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		50
Item 13.	Certain Relationships and Related Transactions, and Director Independence		50
Item 14.	Principal Accountant Fees and Services		50
Part IV
Item 15.	Exhibits and Financial Statement Schedules		51
Financial Statements			S-2
Signatures			S-48

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, as amended [the “PSLRA”]) contained in this report or made by management of the Company involve risks and uncertainties and are subject to change based on various important factors. When used in this report, the words “budget”, “forecast”, “expect”, “believes”, “goals”, “projects”, “plans”, “anticipates”, “estimates”, “should”, “could”, “assume” and similar expressions are intended to identify forward-looking statements. In accordance with the provisions of the PSLRA, we caution you that important factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include our concentration of operations in Venezuela, the political and economic risks associated with international operations (particularly those in Venezuela), the anticipated future development costs for undeveloped reserves, drilling risks, the risk that actual results may vary considerably from reserve estimates, the dependence upon the abilities and continued participation of certain of our key employees, the risks normally incident to the exploration, operation and development of oil and natural gas properties, risks incumbent to being a noncontrolling interest shareholder in a corporation, the permitting and the drilling of oil and natural gas wells, the availability of materials and supplies necessary to projects and operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, the Company’s ability to acquire oil and natural gas properties that meet its objectives, availability and cost of drilling rigs 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, lack of liquidity, availability of sufficient financing, 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 a petroleum exploration and production company incorporated under Delaware law in 1989. Our focus is on acquiring exploration, development and producing properties in geological basins with proven active hydrocarbon systems. Our experienced technical, business development and operating personnel have identified low entry cost exploration opportunities in areas with large hydrocarbon resource potential. We operate from our Houston, Texas headquarters. We also have regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Republic of Indonesia (“Indonesia”); Port Gentil, Republic of Gabon (“Gabon”); and Muscat, Sultanate of Oman (“Oman”) to support field operations in those areas.

We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through HNR Finance, B.V. (“HNR Finance”). Our ownership of HNR Finance is through several corporations in all of which we have direct controlling interests. Through these corporations, we indirectly own 80 percent of HNR Finance and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining 20 percent interest of HNR Finance. HNR Finance owns 40 percent of Petrodelta, S.A. (“Petrodelta”). As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta, and Vinccler indirectly owns eight percent. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. HNR Finance has a direct controlling interest in Harvest Vinccler S.C.A. (“Harvest Vinccler”). Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with Petroleos de Venezuela S.A. (“PDVSA”). We do not have a business relationship with Vinccler outside of Venezuela.

Through the pursuit of technically-based strategies guided by conservative investment philosophies, we are building a portfolio of exploration prospects to complement the low-risk production, development and exploration prospects we hold in Venezuela. In addition to our interests in Venezuela, we hold exploration acreage mainly onshore West Sulawesi in Indonesia, offshore of Gabon, onshore in Oman, and offshore of the People’s Republic of China (“China”).

1

From time to time we learn of possible third party interests in acquiring ownership in certain assets within our property portfolio. We evaluate these potential opportunities taking into consideration our overall property mix, our operational and liquidity requirements, our strategic focus and our commitment to long-term shareholder value. For example, we have received such expressions of interest in acquiring some of our international exploration assets, and we are currently evaluating these potential opportunities. There can be no assurances that our discussions will continue or that any transaction may ultimately result from our discussions.

As of December 31, 2011, we had total assets of $513.0 million, unrestricted cash of $58.9 million and long-term debt of $31.5 million. For the year ended December 31, 2011, we had no revenues from continuing operations and net cash used in operating activities of $52.7 million. As of December 31, 2010, we had total assets of $485.5 million, unrestricted cash of $58.7 million and long-term debt of $81.2 million. For the year ended December 31, 2010, we had no revenues from continuing operations and net cash used in operating activities of $5.3 million.

Petrodelta’s Proved reserves, net to our 32 percent interest, are 43.3 MMBOE at December 31, 2011. Petrodelta’s Probable reserves, net to our 32 percent interest, are 60.5 MMBOE at December 31, 2011. Petrodelta’s Possible reserves, net to our 32 percent interest, are 106.8 MMBOE. Proved plus Probable reserves at 103.8 MMBOE are virtually unchanged from last year. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies – Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve estimates.

In September 2010, our ownership interest in the Budong-Budong Production Sharing Contract (“Budong PSC”) increased from 47 percent to 54.4 percent. In March 2011, the Government of Indonesia and BPMIGAS, Indonesia’s oil and gas regulatory authority, approved the change in ownership interest. In January 2011, our ownership interest in the Budong PSC increased from 54.4 percent to 64.4 percent. In August 2011, the Government of Indonesia and BPMIGAS approved the change in ownership interest. See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia – General.

The Lariang-1 (“LG-1”), the first exploratory well on the Budong PSC, spud January 6, 2011. The Karama-1 (“KD-1”), the second exploratory well on the Budong PSC, spud June 20, 2011. See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia – Drilling and Development Activity.

On January 28, 2011, Fusion Geophysical, LLC’s (“Fusion”) 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations – Fusion Geophysical, LLC.

In March 2011, the Direction Generale Des Hydrocarbures (“DGH”) approved another one year extension to May 27, 2012 of the second exploration phase on the Dussafu Marin Permit (“Dussafu PSC”). See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon – General.

In March 2011, China National Offshore Oil Corporation (“CNOOC”) granted us an extension of Phase One of the Exploration Period for the WAB-21 contract area to May 2013. See Item 1. Business, Operations, Wab-21, South China Sea – General.

The Dussafu Ruche Marin-A (“DRM-1”), our first exploratory well on the Dussafu PSC, spud April 28, 2011. The DRM-1 is currently suspended pending further exploration and development activities. In November 2011, an additional 545 square kilometers of seismic was acquired on the Dussafu PSC and is being processed. See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon – Drilling and Development Activity.

On May 17, 2011, we closed the transaction to sell all of our interest in the oil and gas assets in Utah’s Uinta Basin (“Antelope Project”). The transaction included the Mesaverde Gas Exploration and Appraisal Project (“Mesaverde”), the Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) and the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”). See Item 1. Business, Operations, United States Operations, Western United States – Antelope.

Pursuant to the terms of the term loan facility with MSD Energy Investments Private II, LLC, on May 17, 2011, we paid amounts outstanding under the term loan facility with the net cash proceeds received from the sale of our Antelope Project. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 5 – Long-Term Debt.

2

In June 2011, we and our partners in the West Bay project agreed to relinquish the exploration acreage we held to the farmor. See Item 1. Business, Operations, United States Operations, Gulf Coast – West Bay Project.

In August 2011, Oman’s Ministry of Oil and Gas approved a one-year extension to May 23, 2013 of the Initial Period of the Exploration and Production Sharing Agreement (“EPSA”) for the Al Ghubar/Qarn Alam License (“Block 64 EPSA”). See Item 1. Business, Operations, Block 64 EPSA, Oman – General.

The Mafraq South-1 (“MFS-1”), the first exploratory well on the Block 64 EPSA, spud October 29, 2011. The Al Ghubar North-1 (“AGN-1”), the second exploratory wells on the Block 64 EPSA, spud December 21, 2011. See Item 1. Business, Operations, Block 64 EPSA, Oman – Drilling and Development Activity.

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 2011.

Our strategy has broadened from our primary focus on Venezuela to identify, access and integrate organic growth hydrocarbon assets through exploration in basins with proven hydrocarbon systems globally as an alternative to purchasing proved producing assets. We seek to leverage our Venezuelan experience as well as our expanded business development and technical platform to create a diversified resource base. We have made significant investments to provide the foundation and global reach required for an organic growth focus. While exploration became a larger part of our overall portfolio, we generally restricted ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles.

We intend to use our available cash to pursue additional growth opportunities in Indonesia, Gabon, Oman, China and other countries that meet our strategy. However, the execution of this strategy maybe limited by factors including, among other things, access to additional capital and the receipt of dividends from Petrodelta as well as the need to preserve adequate development capital in the interim.

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 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.

3

Reserves

We adopted the SEC’s Modernization of Oil and Gas Reporting and the Financial Accounting Standards Board’s (“FASB”) guidance on extractive activities for oil and gas (Accounting Standards Codification [“ASC”] 932) as of December 31, 2009. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies – Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve estimates.

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, 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.

In Venezuela during 2011, Petrodelta drilled and completed 15 production wells. Four of the wells were previously identified Proved Undeveloped (“PUD”) locations and 11 wells were previously classified as probable, possible or undefined locations. In 2011, an additional 54 PUD locations were identified through drilling activity, however 69 PUD locations which are scheduled to be drilled 5 years after the wells were originally identified have been reclassified as Probable reserves. At December 31, 2011, Petrodelta has a total of 163 identified PUD locations.

Petrodelta’s 2011 business plan, as approved by PDVSA, contemplates sustained drilling activities through the year 2024 to fully develop the El Salto and Temblador fields. As a noncontrolling interest shareholder in Petrodelta, HNR Finance has limited ability to control the development plans that are periodically prepared and/or approved by the Venezuelan government. The PUD locations which are now scheduled to be drilled 5 years after they were originally identified have been reclassified as Probable reserves.

Probable undeveloped reserves of 60.3 MMBOE include 16.1 MMBOE from 69 gross undeveloped locations that would otherwise meet the definition of proved undeveloped reserves, except that they are scheduled to be drilled at least 5 years after the date that they were originally identified. These 69 locations are all scheduled to be drilled from 2013 to 2016.

Proved undeveloped reserves of 26.2 MMBOE from 163 gross PUD locations are all scheduled to be drilled within the period from 2012 to 2015 and within 5 years from when these locations were first identified. All above MMBOE represent our net 32 percent interest, net of a 33.33 percent royalty.

4

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, 2011.

	Oil and NGLs		Natural Gas		Total
	(MBls)		(MMcf)		(MBOE)(a)
Proved Developed Reserves:
International – Venezuela(b)		13,717		20,291		17,099
Total Proved Developed		13,717		20,291		17,099
Proved Undeveloped Reserves:
International – Venezuela(b)		24,948		7,549		26,206
Total Proved Undeveloped		24,948		7,549		26,206
Total Proved Reserves		38,665		27,840		43,305
Probable Developed Reserves:
International – Venezuela(b)		127		82		141
Total Probable Developed		127		82		141
Probable Undeveloped Reserves:
International – Venezuela(b)		53,341		41,828		60,312
Total Probable Undeveloped		53,341		41,828		60,312
Total Probable Reserves		53,468		41,910		60,453
Possible Developed Reserves:
International – Venezuela(b)		—		—		—
Total Possible Developed		—		—		—
Possible Undeveloped Reserves:
International – Venezuela(b)		101,855		29,548		106,780
Total Possible Undeveloped		101,855		29,548		106,780
Total Possible Reserves		101,855		29,548		106,780

^(a) Thousand barrels of oil equivalent (“MBOE”) is determined using the approximate heat content ratio of one barrel of crude oil or condensate to six thousand cubic feet (“Mcf”) of natural gas, which ratio does not necessarily reflect price equivalency.

^(b) Information represents our net 32 percent ownership interest in Petrodelta.

Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves as of December 31, 2011, 2010 and 2009 and changes in proved reserves during the last three years are contained in 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 Operation, Critical Accounting Policies – Reserves for additional information on our reserves.

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 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 Vinccler. In addition, we have a 64.4 percent interest in the Budong PSC which we may operate during the production phase, a 66.667 percent interest in the production sharing contract related to the Dussafu PSC for which we are the operator, a 100 percent interest in the Block 64 EPSA for which we are the operator, and a 100 percent interest in the WAB-21 petroleum contract in the South China for which we are the operator.

5

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 is to undertake the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from that date. Petrodelta is governed by its own charter and bylaws. Petrodelta’s portfolio of properties in eastern Venezuela include 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

Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Under its conversion contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. Petrodelta’s 2011 capital expenditures were expected to be approximately $200 million. Petrodelta’s 2011 proposed business plan included a planned drilling program to utilize two rigs to drill both development and appraisal wells for maintaining production capacity, the continued appraisal of the substantial resource base in the El Salto field and further drilling in the Isleño field. It also included engineering work for production facilities required for the full development of the El Salto and Temblador fields. Due to insufficient monetary and contractual support by PDVSA, Petrodelta incurred only $137.5 million of its 2011 planned capital expenditures.

As disclosed in previous filings, PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors. As a result, Petrodelta is continuing to experience difficulty in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is continuing to have an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.

Crude oil delivered from the Petrodelta fields to PDVSA Petroleo S.A. (“PPSA”) is priced with reference to Merey 16 published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices are quoted and sold in U.S. Dollars. Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per Mcf. PPSA is obligated to make payment to Petrodelta in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered. Natural gas deliveries are paid in Venezuelan Bolivars (“Bolivars”), but the pricing for natural gas is referenced to the U.S. Dollar.

In April 2011, the Venezuelan government published in the Official Gazette the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (the “amended Windfall Profits Tax”). See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Venezuela – Petrodelta for a discussion of the effects of the amended Windfall Profits Tax on Petrodelta’s business.

The Science and Technology Law (referred to as “LOCTI” in Venezuela) requires major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law (“OHL”) to contribute 0.5 percent (two percent prior to January 1, 2011) of their gross revenue generated in Venezuela from activities specified in the OHL on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. The contribution is based on the previous year’s gross revenue and is due the following year. Each company is required to file a separate declaration. Prior to January 1, 2011, contributions were allowed to be paid in-kind through self-funded programs and direct contributions to projects performed by other institutions. Effective January 1, 2011, LOCTI requires all contributions to be paid in cash directly to the National Fund for Science, Technology and Innovation (“FONDACIT”), the entity responsible for the administration of LOCTI contributions. Self-funded programs and direct contributions to projects performed by other institutions are no longer allowed. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Venezuela – Petrodelta for a discussion of LOCTI related to prior years.

6

In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, as of March 7, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain.

Business Plan of Petrodelta

As of March 7, 2012, the 2012 budget for Petrodelta’s business plan had not yet been approved by its shareholders. Since Petrodelta only executed approximately 69 percent its 2011 planned capital expenditures primarily due to insufficient monetary and contractual support by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2012 budget. Should PDVSA continue in insufficient monetary and contractual support of Petrodelta, underinvestment in the development plan may lead to continued under-performance. However, Petrodelta’s 2012 proposed business plan includes a planned drilling program to utilize three rigs to drill both development and appraisal wells for maintaining production capacity and the continued appraisal of the substantial resource base in the El Salto and Isleño fields. It also includes engineering work for the additional infrastructure enhancement projects in El Salto and Temblador.

Location and Geology

Petrodelta Fields

Uracoa Field

At December 31, 2011, there were 86 (2010: 83) oil and natural gas producing wells and seven (2010: 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. The oil is transported through a 25-mile oil pipeline from the Uracoa plant facilities to PDVSA’s EPT-1 storage facility. All natural gas presently being delivered by Petrodelta is produced from the Uracoa field and is delivered to PDVSA through a 64-mile pipeline to Mamo gas station and PDVSA Gas network.

Tucupita Field

At December 31, 2011, there were 17 (2010: 14) oil producing wells and four (2010: 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. It is then transported through the 25-mile oil pipeline from the Uracoa plant facilities to PDVSA’s EPT-1 storage facility.

Bombal Field

East Bombal was drilled in 1992, and currently remains underdeveloped. In West Bombal, at December 31, 2011, there were four (2010: three) oil producing wells. The oil is transported through Petrodelta’s pipelines from the West Bombal field to the Uracoa plant facilities. It is then transported through the 25-mile oil pipeline from the Uracoa plant facilities to PDVSA’s EPT-1 storage facility.

Isleño Field

The Isleño field was discovered in 1953. Seven oil appraisal wells were drilled by PDVSA prior to the field being contributed to Petrodelta. Petrodelta drilled an appraisal well, the ILM-8, in Isleño in January 2011. In December 2011, the well was shut in due to high production of gas. At December 31, 2011 and 2010, no wells were producing in the field. A reentry of the ILM-8 was completed in February 2012, and the well is currently producing. The oil is transported through Petrodelta’s pipelines to the Uracoa plant facilities. It is then transported through the 25-mile oil pipeline from the Uracoa plant facilities to PDVSA’s EPT-1 storage facility.

Temblador Field

The Temblador field was discovered in 1936 and developed in the 1940s and 1950s. At December 31, 2011, there were 27 (2010: 25) oil producing wells in the field. The fluid produced from Temblador field flows through two flow stations operated by Petrodelta. The Temblador field’s production flows through Petrodelta pipelines to TY23 station then into PDVSA’s EPT-1 storage facility.

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El Salto Field

The El Salto field was discovered in 1936. 31 appraisal wells were drilled by PDVSA prior to the field being contributed to Petrodelta. At December 31, 2011, there were nine (2010: three) oil producing wells and one (2010: none) water injection well in the El Salto field. During 2011, Petrodelta completed facilities at PDVSA’s EPM-1 transfer point at PDVSA Morichal for the El Salto field. Completion of the facilities has enabled Petrodelta to increase production from the El Salto field.

Infrastructure and Facilities

Petrodelta has a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA’s EPT-1 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.

Petrodelta has a 64-mile pipeline from Uracoa to Mamo gas station and PDVSA Gas network with a nominal 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 a 5.6-mile trunkline from the Temblador field to TY23 station which is next to PDVSA’s EPT-1 storage facility.

Petrodelta completed facilities at PDVSA’s EPM-1 transfer point at PDVSA Morichal for El Salto field. Petrodelta is continuing additional infrastructure enhancement projects in El Salto and Temblador.

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.

Drilling and Development Activity

During the year ended December 31, 2011, Petrodelta drilled and completed 15 development wells, one successful appraisal well and two water injector wells. Petrodelta delivered approximately 11.4 million barrels (“MBls”) of oil and 2.3 billion cubic feet (“Bcf”) of natural gas, averaging 32,240 barrels of oil equivalent (“BOE”) per day during the year ended December 31, 2011. During the year ended December 31, 2010, Petrodelta drilled and completed 16 development wells. Petrodelta delivered approximately 8.6 MBls of oil and 2.2 Bcf of natural gas, averaging 23,455 BOE per day during the year ended December 31, 2010.

Petrodelta took possession of a third drilling rig at the end of September 2011. Currently, two drilling rigs are operating in the El Salto field, and one drilling rig is operating in the Isleño field. A workover rig is operating in the Uracoa field.

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 were the operator of both exploration programs.

Gulf Coast – West Bay Project

We held exploration acreage in the Gulf Coast Region of the United States through an Area of Mutual Interest (“AMI”) agreement with two private third parties. As of June 30, 2011, we and our partners in the West Bay project agreed to relinquish the exploration acreage we held to the farmor. The relinquishment was completed

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with an effective date of October 31, 2011. Neither we nor our partners intend to continue any activity in West Bay. Based on the decision in the second quarter 2011 to relinquish the exploration acreage, the carrying value of West Bay of $3.3 million was impaired as of June 30, 2011.

Western United States – Antelope

On May 17, 2011, we closed the transaction to sell all of our interest in the oil and gas assets located in our Antelope Project area in the Uinta Basin of Utah which consisted of approximately 69,000 gross acres (47,600 net acres), and the related contracts, reserves, production, wells, pipelines production facilities and other rights, title and interests located in the Uintah Basin in Duchesne and Uintah Counties, Utah. The transaction included the Mesaverde, the Lower Green River/Upper Wasatch and the Monument Butte Extension. We owned an approximate working interest of 70 percent in the Mesaverde and Lower Green River/Upper Wasatch, an approximate 60 percent working interest in one well in the Monument Butte Extension, an approximate 43 percent working interest in the initial eight well program in the Monument Butte Extension, and 37 percent working interest in the follow-up six well program in the Monument Butte Extension. The initial eight well program and follow-up six well program in the Monument Butte Extension were non-operated. The sale had an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. All activities associated with the Antelope Project have been reflected as discontinued operations on the statement of operations. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 4 – Dispositions.

Budong-Budong, Onshore Indonesia

General

In 2007, we entered into a Farmout Agreement to acquire a 47 percent interest in the Budong PSC located mostly onshore West Sulawesi, Indonesia. In April 2008, the Government of Indonesia approved the assignment to us of the 47 percent interest in the Budong PSC. Our partner is the operator through the exploration phase as required by the terms of the Budong PSC, and we have an option to become operator, if approved by the Government of Indonesia and BPMIGAS in any subsequent development and production phase.

We acquired our original 47 percent interest in the Budong PSC by committing to fund the first phase of the exploration program up to a cap of $17.2 million, including the acquisition of 2-D seismic and drilling of the first two exploration wells under a Farmout Agreement with our partner in the Budong PSC. Prior to drilling the first exploration well, our partner had a one-time option to increase the level of the carried interest to a maximum of $20.0 million. On September 15, 2010, our partner exercised their option to increase the carry obligation by $2.7 million to a total of $19.9 million. The additional carry increased our ownership by 7.4 percent to 54.4 percent. On March 3, 2011, the Government of Indonesia and BPMIGAS approved this change in ownership interest.

On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator to a third party, which allowed us to acquire an additional 10 percent equity in the Budong PSC at a cost of $3.7 million payable ten business days after completion of the first exploration well. The $3.7 million was paid on April 18, 2011. On August 11, 2011, we received notice from the Government of Indonesia and BPMIGAS that the transfer of the additional interest had been approved. Closing of this acquisition increased our participating ownership interest in the Budong PSC to 64.4 percent with our cost sharing interest becoming 64.51 percent until first commercial production.

The remaining work commitment for the current exploration phase on the Budong PSC is for geological and geophysical work to be completed in the year 2012 at a minimum of $0.5 million ($0.3 million net to our 64.51 percent cost sharing interest).

Location and Geology

During the initial exploration period, the Budong PSC covered 1.35 million acres. The Budong PSC includes a ten-year exploration period and a 20-year development phase. Pursuant to the terms of the Budong PSC, at the end of the first three-year exploration phase, 45 percent of the original area was to be relinquished to BPMIGAS. In January 2010, 35 percent of the original area was relinquished and ten percent of the required relinquishment was deferred until 2011. On January 20, 2011, the deferred ten percent of the original total contract area was relinquished to BPMIGAS. The Budong PSC now covers 0.75 million acres.

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The Budong PSC includes the Lariang and Karama sub-basins, which are the eastern onshore extension of the West Sulawesi foldbelt (“WSFB”). Field work performed over the last ten years has given a new understanding to the presence of Eocene source and reservoir potential that had not previously been recognized. Recent offshore 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.

Drilling and Development Activity

Operational activities during 2011 focused on drilling of the first two exploratory wells, the LG-1, which spud on January 6, 2011, and the KD-1, which spud on June 20, 2011.

The LG-1, the first of the two exploratory wells in the Budong PSC, targeted the Miocene and Eocene reservoirs to a planned depth of approximately 7,200 feet. The LG-1 was drilled to a total depth of 5,311 feet and encountered multiple oil and gas shows within the secondary Miocene objective. Wireline logs and samples of reservoir fluids confirmed the presence of hydrocarbons, trap and seal thus greatly de-risking the exploration potential of the license as well as proving the LG structure to be hydrocarbon bearing. The high formation pressures, well control difficulties, and a poor cementing job on the 9-5/8^ths casing required the use of more casing strings at shallower depths than were originally planned. At a depth of 5,300 feet, losses of heavy drilling mud into the formation were encountered which, when coupled with the very high formation pressures, led the partners to the decision to discontinue operations and plug and abandon the well for safety reasons on April 8, 2011. The primary Eocene targets had not yet been reached, as the well was planned for a total measured depth of approximately 7,200 feet. The costs for drilling the LG-1, $14.0 million, were suspended at March 31, 2011 pending further evaluation and appraisal.

The KD-1, the second of the two exploratory wells in the Budong PSC, is located approximately 50 miles south of the LG-1. The KD-1 was drilled to test a thrusted surface anticline with stacked Miocene and Eocene targets to a planned total measured depth of approximately 10,800 feet. The well design allowed the KD-1 to be drilled to a total depth of approximately 14,400 feet. The well was initially drilled to a depth of 9,633 feet and sidetracked after the drill string was severed. The sidetrack, the KD-1ST, was initially drilled to a total depth of 11,800 feet and logged. The evaluation of cuttings, logs and sidewall cores demonstrated the presence of oil over a 200 feet low permeability and low porosity clastic section. As the Eocene had not yet been encountered, on November 4, 2011, Harvest continued drilling as an exclusive operation to explore for the main Eocene objective. Although the well encountered both Oligocene and Eocene stratigraphy, at a final total depth of 14,437 feet (13,576 feet true vertical depth [“TVD”]), the primary Eocene clastic reservoir target had not yet been reached. Biostratigraphy indicates the section at total depth to be Eocene deep water shales. On January 2, 2012, the KD-1ST was plugged and abandoned. Drilling costs of $26.0 million related to the drilling of the KD-1 and the KD-1ST have been expensed to dry hole costs as of December 31, 2011.

In January 2012, after completion of drilling of the KD-1, all information gathered from the drilling of the LG-1 and KD-1 was reevaluated in connection with our plans for the Budong PSC and overall corporate strategy. Based on this reevaluation, we determined that the original LG-1 well bore would not be used for re-entry. Since plans for the Budong PSC no longer include re-entry of the LG-1 well bore, the drilling costs of $14.0 million related to the drilling of the LG-1 have been expensed to dry hole costs as of December 31, 2011. Based on the multiple oil and gas shows encountered in both the LG-1 and KD-1, we are working on an exploration program targeting the Pliocene and Miocene targets encountered in the previous two wells. As such, the other costs incurred related to the Budong PSC of $6.8 million remain capitalized on our balance sheet as of December 31, 2011.

Dussafu Marin, Offshore Gabon

General

In 2008, we acquired a 66.667 percent ownership interest in the Dussafu PSC. We are the operator.

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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. At that time, it was agreed that the second three-year exploration phase be extended until May 27, 2011, at which time the partners can elect to enter a third exploration phase. In order to complete drilling activities of the first exploratory well, in March 2011, the DGH approved another one year extension to May 27, 2012 of the second exploration phase.

During 2011, we established an operational and logistics base in Port Gentil, Gabon to support the Dussafu PSC drilling program.

We do not have any remaining work commitments for the current exploration phase of the Dussafu PSC, but as of May 28, 2012, the Dussafu PSC enters the third exploration phase. If the partners elect to enter the third exploration phase, there will be a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a two-year period.

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

Drilling and Development Activity

Operational activities during 2011 focused on drilling of our first exploratory well, the DRM-1, which spud April 28, 2011, and two appraisal sidetracks. The DRM-1 is in a water depth of 380 feet and was drilled to test multiple stacked pre-salt targets to a planned total measured depth of approximately 10,100 feet with an option to deepen to 12,500 feet.

On June 10, 2011, we announced the DRM-1 had reached a total depth of 10,044 (true vertical depth subsea [“TVDSS”] of 9,953 feet) feet within the Upper Dentale Formation. Log evaluation, pressure data and samples indicated an oil discovery of approximately 55 feet of pay in a 90 foot oil column within the Gamba Formation. We also announced plans to deepen the well to test Middle and Lower Dentale exploration potential and sidetrack to appraise the extent of the Gamba oil discovery.

Subsequently the DRM-1 was deepened to reach a total depth of 11,450 feet (TVDSS of 11,355 feet) to test the prospectivity of the Middle and Lower Dentale Formations. Log evaluation, pressure data and a fluid sample indicate that we had discovered a second oil accumulation with approximately 35 feet of oil pay within the secondary objective of the Middle Dentale Formation.

The Gamba discovery has been appraised by drilling a sidetrack (“DRM-1ST1”) 0.75 miles to the southwest to test the lateral extent and structural elevation of the Gamba reservoir. The sidetrack was drilled to a total depth in the Upper Dentale of 11,562 feet, (9,428 feet of TVDSS) and found 19 feet of oil pay in the Gamba reservoir. A second sidetrack (“DRM-1ST2”) was drilled 0.5 miles to the northwest of the original DRM-1 wellbore to a total depth in the Upper Dentale of 10,615 feet, (9,429 feet of TVDSS) and found 40 feet of oil pay in the Gamba reservoir.

Drilling operations are currently suspended pending further exploration and development activities. The DRM-1 information is being used to refine the 3-D seismic depth model and improve our understanding for predicting the Gamba structure under the salt to define potential resources in the nearby satellite structures for future drilling targets. Initial reservoir characterization and conceptual engineering studies have begun with the aim of evaluating the commerciality of the discovered oil and to determine the forward plan for the Dussafu PSC.

The partners in the Dussafu PSC began a 3-D seismic acquisition in a joint program with a third party. The program, which was operated by the third party and commenced on October 23, 2011, was completed November 18, 2011. We acquired an additional 545 square kilometers of seismic which is currently being processed. The seismic data was acquired in the northern area of the Dussafu PSC between the two existing 3-D seismic surveys acquired in 1994 and 2005 and the 2-D seismic survey we acquired in 2008.

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Block 64 EPSA, Oman

General

In 2009, we signed an EPSA with Oman for the Block 64 EPSA. We have an 80 percent working interest and our partner, Oman Oil Company, has a 20 percent carried interest in the Block 64 EPSA during the initial period. We will pay Oman Oil Company’s participating interest share of costs until the date of a declaration of commerciality. Ninety days following the declaration of commerciality, Oman Oil Company may elect to continue to participate in the Block 64 EPSA. If Oman Oil Company elects to continue to participate, it will reimburse us for its participating interest share of all recoverable costs under the Block 64 EPSA incurred before the declaration of commerciality. Reimbursement is due within 30 days of election to participate.

We have a minimum work obligation to reprocess 375 square kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup during the Initial Term of the EPSA. The parties to the EPSA acknowledge that $22.0 million is indicative of the costs needed to complete the work program during the three-year initial period which expires in May 2012. In order to complete drilling activities of the two exploratory wells, on August 24, 2011, Oman’s Ministry of Oil and Gas approved a one-year extension to May 23, 2013 of the initial period of the EPSA. Through December 31, 2011, we have incurred $16.2 million of the minimum work obligation. As of February 29, 2012, we have expended more than $22.0 million and completed the minimum work obligations.

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”). PDO will continue to produce oil from several shallow oil fields within Block 64 EPSA area. The 955,600 acre 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

Operational activities during 2011 included well planning and procurement of long lead items. On October 21, 2011, a Standby Letter of Credit in the amount of $1.2 million was issued as a payment guarantee for electric wireline services to be provided during the drilling of the two exploratory wells on the Block 64 EPSA.

The first of the two exploratory wells, the MFS-1, spud October 29, 2011. The MFS-1 was drilled to test the Mafraq South fault block. On December 8, 2011, we announced that the MFS-1 had reached a revised total depth of 10,348 feet. Logs did not indicate the presence of hydrocarbons within the stacked reservoir targets in the Barik, Miqrat and Amin reservoirs. The reservoirs were encountered shallower than expected with reduced seal thickness, and failure is attributed to the lack of effective seal. Drilling operations on the MFS-1 progressed ahead of schedule with the well reaching total depth 28 days ahead of the forecast drill time. On December 11, 2011, the MFS-1 was plugged and abandoned. Drilling costs of $6.9 million related to the drilling of the MFS-1 have been expensed to dry hole costs as of December 31, 2011.

The AGN-1, the second exploratory wells on the Block 64 EPSA, spud December 23, 2011 and was drilling at December 31, 2011. On February 3, 2012, we announced that the AGN-1 had reached a total depth of 10,482 feet. Interpretation of the mud log and wireline log did not indicate hydrocarbon saturations within the principal stacked Haima targets in the Barik, Miqrat and Amin reservoirs. On February 6, 2012, the AGN-1 was plugged and abandoned. Total estimated drilling costs for the AGN-1 are approximately $7.6 million. Drilling costs incurred through December 31, 2011 of $2.8 million have been expensed to dry hole costs as of December 31, 2011. Drilling costs incurred after December 31, 2011 will be expensed to dry hole costs in the first quarter of 2012.

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WAB-21, South China Sea

General

In 1996, we acquired a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. The WAB-21 petroleum contract area lies within an area which is the subject of a border dispute between 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. Although 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, there has been a small increase in exploration activity in the area starting in 2009.

Location and Geology

The WAB-21 contract area covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under certain circumstances, and 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 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 MBls 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, 2013. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist.

While no assurance can be given, we believe activity in the area may provide some resolution with the border disputes, although we do not know in what manner any resolution might appear.

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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, 2011, 2010 and 2009. The presentation for Venezuela is presented at our net 32 percent ownership interest in Petrodelta. The United States is presented at our ownership interest.

	Year Ended December 31,
	2011		2010		2009
Venezuela
Crude Oil Production (MBbls) (b)		2,430		1,826		1,671
Natural Gas Production (MMcf) (a) (c)		483		470		938
Average Crude Oil Sales Price ($ per Bbl)	$	98.52	$	70.57	$	57.62
Average Natural Gas Sales Price ($ per Mcf)	$	1.54	$	1.54	$	1.54
Average Operating Expenses ($ per BOE) (d)	$	8.99	$	6.01	$	5.64
United States (e)
Monument Butte(e)
Net Crude Oil Production (MBbls)		21		106		3
Natural Gas Production (MMcf)		324		417		6
Average Crude Oil Sales Price ($ per Bbl)	$	77.91	$	64.85	$	61.57
Average Natural Gas Sales Price ($ per Mcf)	$	3.73	$	3.43	$	2.77
Average Operating Expenses ($ per BOE)	$	10.34	$	4.26	$	—
Lower Green River/Upper Wasatch (e)
Net Crude Oil Production (MBbls)		40		34		—
Natural Gas Production (MMcf)		13		6		—
Average Crude Oil Sales Price ($ per Bbl)	$	89.6	$	69.63	$	—
Average Natural Gas Sales Price ($ per Mcf)	$	4.62	$	3.97	$	—
Average Operating Expenses ($ per BOE)	$	56.86	$	25.41	$	—

^(a)  Royalty-in-kind paid on gas used as fuel by Petrodelta net to our 32 percent interest was 3,226 MMcf for 2011 (2010: 1,015 MMcf, 2009: 1,063 MMcf).

^(b) Crude oil sales net to our 32 percent interest after deduction of royalty. Crude oil sales for Petrodelta at 100 percent were 11,390 MBbls for 2011(2010: 8,561 MBbls, 2009: 7,835 MBbls).

^(c) Natural gas sales net to our 32 percent interest after deduction of royalty. Natural gas sales for Petrodelta at 100 percent were 2,266 MMcf for 2011 (2010: 2,204 MMcf, 2009: 4,397 MMcf).

^(d) Petrodelta is not subject to ad valorem or severance taxes. Average operating expenses per BOE net of royalties and workovers were $9.84 for 2011 (2010: $7.52 per BOE, 2009: $8.46 per BOE).

^(e) Property was sold effective March 1, 2011 and is reported as discontinued operations.

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) $108.4 million in 2011(2010: $59.6 million, 2009: $28.0 million). These numbers do not include any costs for the development of proved undeveloped reserves in 2011, 2010 or 2009.

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We have participated in the drilling of wells as follows:

	Year Ended December 31,
	2011				2010				2009
	Gross		Net		Gross		Net		Gross		Net
Wells Drilled:
Venezuela (Petrodelta)
Development		15		4.8		16		5.1		15		4.8
Appraisal		1		0.3		—		—		2		0.6
Indonesia
Exploration		2		1.3		—		—		—		—
Gabon
Exploration		1		0.7		—		—		—		—
Oman
Exploration		1		0.8		—		—		—		—
United States
Development		1		0.7		8		2.6		5		2.1
Exploration		2		0.7		3		1.0		1		1.0
Average Depth of Wells (Feet)
Venezuela (Petrodelta)
Crude Oil		—		7,298		—		6,839		—		6,500
Indonesia
Crude Oil		—		9,874		—		—		—		—
Gabon
Crude Oil		—		11,355		—		—		—		—
Oman
Natural Gas		—		10,348		—		—		—		—
United States
Crude Oil		—		10,021		—		7,938		—		6,751
Natural Gas		—		—		—		—		—		17,566
Producing Wells (1):
Venezuela (Petrodelta)
Crude Oil		143		46		127		40.6		114		36.5
United States
Crude Oil		—		—		16		8.3		2		0.7

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

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

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Acreage

The following table summarizes the developed and undeveloped acreage that we owned, leased or held under concession as of December 31, 2011:

	Developed				Undeveloped
	Gross		Net		Gross		Net
Venezuela – Petrodelta		25,500		8,160		221,613		70,916
China		—		—		7,470,080		7,470,080
Indonesia		—		—		747,862		481,623
Gabon		—		—		685,470		456,982
Oman		—		—		955,600		764,480
Total		25,500		8,160		10,080,625		9,244,081

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:

• change in governments;

• civil unrest;

• price and currency controls;

• limitations on oil and natural gas production;

• tax, environmental, safety and other laws relating to the petroleum industry;

• changes in laws relating to the petroleum industry;

• changes in administrative regulations and the interpretation and application of such rules and regulations; and

• changes in contract interpretation and policies of contract adherence.

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

Our operations are subject to various federal, state, local and international laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The cost of compliance could be significant. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial and damage payment obligations, or the issuance of injunctive relief (including orders to cease operations). Environmental laws and regulations are complex, and have tended to be come more stringent over time. We also are subject to various environmental permit requirements. Some environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or

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third parties. To the extent laws are enacted or other governmental action is taken that prohibits or restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected.

Employees

At December 31, 2011, full-time employees in our various offices were: Houston – 19; Caracas – 11; London – 7; Singapore – 2; Jakarta – 3; and Muscat – 7. We augment our employees from time to time with independent consultants, as required.

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, 2011, we had $58.9 million of available cash and, until Petrodelta pays a dividend, our available cash may not be sufficient to meet capital and operational commitments. 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, success with our exploration program, possible delay of discretionary capital spending to future periods, or possible sale, farm-out or otherwise monetization of assets as necessary to maintain the liquidity required to run our operations. While we believe that Petrodelta will reinvest any excess cash into Petrodelta in 2012 and 2013 which might otherwise be available for payment of dividends, 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.

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 March 1, 2013. Prior to February 2010, we had no long-term debt obligations. The degree to which we are leveraged could, among other things:

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

• 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.

Our ability to meet our debt service obligation 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.

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 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 or the work program may include minimum funding requirements to keep the contract. We may not have the funds available to meet the minimum funding requirements when they come due and be required to forfeit the contracts.

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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.

We do not 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. In April 2011, the Venezuelan government published the amended Windfall Profits Tax which establishes a special contribution for extraordinary prices to the Venezuelan government of 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $40 per barrel for 2011[$50 per barrel for 2012]) and $70 per barrel. The amended Windfall Profits Tax also establishes a special contribution for exorbitant prices to the Venezuelan government of (1) 80 percent when the average price of the Venezuelan Export Basket (“VEB”) exceeds $70 per barrel but is less than $90 per barrel; (2) 90 percent when the average price of the VEB exceeds $90 per barrel but is less that $100 per barrel; and (3) 95 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:

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

• export quotas;

• market uncertainty;

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• the level of consumer product demand;

• weather conditions;

• domestic and foreign governmental regulations and policies;

• the price and availability of alternative fuels;

• political and economic conditions in oil-producing and oil consuming countries; and

• overall economic conditions.

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. Since Petrodelta only executed approximately 69 percent its 2011 planned capital expenditures primarily due to insufficient monetary and contractual support by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2012 budget. Should PDVSA continue in insufficient monetary and contractual support of Petrodelta, underinvestment in the development plan may lead to continued under-perfomance.

The legal or fiscal framework 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 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 effect 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 is continuing to experience difficulty in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is continuing to have an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.

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.

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You should not assume that the present value of future net revenues referred to in Item 15. Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Petrodelta S.A., 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 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:

• shortages or delays in the delivery of equipment;

• shortages in experienced labor;

• pressure or irregularities in formations;

• unexpected drilling conditions;

• equipment or facilities failures or accidents;

• remediation and other costs resulting from oil spills or releases of hazardous materials;

• government actions or changes in regulations;

• delays in receiving necessary governmental permits;

• delays in receiving partner approvals; and

• weather conditions.

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.

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 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

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arising out of foreign government sovereignty over our international operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign policy, foreign trade, taxation and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States.

Our 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:

• 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; and

• taxation.

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.

The oil and gas business involves many operating risks that can cause substantial losses, and insurance may not protect us against all of these risks. We are not insured against all risks. Our oil and gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the risk of:

• fires and explosions;

• blow-outs;

• uncontrollable or unknown flows of oil, gas, formation water or drilling fluids;

• adverse weather conditions or natural disasters;

• pipe or cement failures and casing collapses;

• pipeline ruptures;

• discharges of toxic gases;

• build up of naturally occurring radioactive materials; and

• vandalism.

If any of these events occur, we could incur substantial losses as a result of:

• injury or loss of life;

• severe damage or destruction of property and equipment, and oil and gas reservoirs;

• pollution and other environmental damage;

• investigatory and clean-up responsibilities;

• regulatory investigation and penalties;

• suspension of our operations; and

• repairs to resume operations.

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If we experience any of these problems, our ability to conduct operations could be adversely affected.

We maintain insurance against some, but not all, of these potential risks and losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not insurable.

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.

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.

Potential regulations regarding climate change could alter the way we conduct our business. Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that requires reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of oil, gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change and the Kyoto Protocol address greenhouse gas emissions, and several countries including the European Union have established greenhouse gas regulatory systems. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and gas that we produce and as a result, negatively impact our financial condition, results of operations and cash flows.

Our business is dependent upon the proper functioning of our internal business processes and information systems and modification or interruption of such systems may disrupt our business, processes and internal controls. The proper functioning of our internal business processes and information systems is critical to the efficient operation and management of our business. If these information technology systems fail or are interrupted, our operations may be adversely affected and operating results could be harmed. Our business processes and information systems need to be sufficiently scalable to support the future growth of our business and may require modifications or upgrades that expose us to a number of operational risks. Our information technology systems, and those of third party providers, may also be vulnerable to damage or disruption caused by circumstances beyond our control. These include catastrophic events, power anomalies or outages, natural disasters, computer system or network failures, viruses or malware, physical or electronic break-ins, unauthorized access and cyber attacks. Any material disruption, malfunction or similar challenges with our business processes or information systems, or disruptions or challenges relating to the transition to new processes, systems or providers, could have a material adverse effect on our financial condition, results of operations and cash flows.

Item 1B. Unresolved Staff Comments

None.

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Item 2. Properties

We have regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Indonesia; Port Gentil, Gabon; and Muscat, Oman to support field operations in those areas. The field office in Port Gentil, Gabon is a month-to-month agreement. At December 31, 2011, we had the following lease commitments for office space:

	Date			Monthly
Location	Lease Signed	Term		Expense
Houston, Texas	April 2004		10 years	$	17,000
Houston, Texas	December 2008		5 years		13,400
Caracas, Venezuela	December 2011		1 year		7,000
London, U.K.	September 2010		5 years		9,000
Singapore	October 2010		2 years		7,000
Jakarta, Indonesia	April 2011		2 years		5,000
Muscat, Oman	September 2011		2 years		5,200

See Item 1. Business, Operations for a description of our oil and gas properties.

Item 3. Legal Proceedings

In October 2007, we entered into a Joint Exploration and Development Agreement (“JEDA”) with a private third party with respect to the Antelope Project. On January 11, 2011, in connection with the sale of each party’s interests in the Antelope Project (see Note 4 – Dispositions), we entered into a letter agreement with the private third party wherein the private third party agreed to reimburse us for certain expenses related to the sale of the two parties’ interests in the Antelope Project. The private third party disputes our calculation of the amount owed to us pursuant to the January 11, 2011 letter agreement. On March 11, 2011, we entered into a letter agreement with the private third party regarding certain obligations between the parties related to the JEDA. The private third party disputes our calculation of the amount due pursuant to one of the items in the March 11, 2011 letter agreement. At December 31, 2011, we have a note receivable outstanding from the private third party of $3.3 million (see Note 2 – Summary of Significant Accounting Policies, Accounts and Notes Receivable) and an account payable outstanding to the private third party of $3.6 million related to the purchase in July 2010 of an incremental 10 percent interest in the Antelope Project. In the event that the dispute is not resolved, the parties would arbitrate pursuant to the JEDA. At this time, we cannot predict the outcome of this dispute with the private third party.

On May 31, 2011, the United Kingdom branch of our subsidiary, Harvest Natural Resources, Inc. (UK), initiated a wire transfer of approximately $1.1 million ($0.7 million net to our 66.667 percent interest) intending to pay Libya Oil Gabon S.A. (“LOGSA”) for fuel that LOGSA supplied to our subsidiary in the Netherlands, Harvest Dussafu, B.V., for the company’s drilling operations in Gabon. On June 1, 2011, our bank notified us that it had been required to block the payment in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”), because the payee, LOGSA, may be a blocked party under the sanctions. The bank further advised us that it could not release the funds to the payee or return the funds to us unless we obtain authorization from OFAC. On October 26, 2011, we filed an application with OFAC for return of the blocked funds to us. Unless that application is approved, the funds will remain in the blocked account, and we can give no assurance when, or if, OFAC will permit the funds to be released.

On June 30, 2011, we filed a voluntary self-disclosure with OFAC to report that we had possibly violated the U.S. sanctions by attempting to remit funds to LOGSA. On September 20, 2011, we received a response from OFAC which stated that OFAC had decided to address the matter by issuing us a cautionary letter instead of pursuing a civil penalty. The cautionary letter represents OFAC’s final response to the apparent violation, but does not constitute a final agency determination as to whether a violation occurred.

On June 30, 2011, we applied for a license with OFAC that would authorize us to pay LOGSA for the fuel provided. In late 2011 and while our June 30, 2011 application was pending with OFAC, OFAC issued a series of general licenses easing U.S. sanctions against Libya which allowed us to pay the full amount we owed LOGSA. As of December 31, 2011, all monies owed to LOGSA had been paid. Our October 26, 2011 application for the return of the blocked funds remains pending with OFAC.

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Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc., Branta Exploration & Production, LLC, Ute Energy LLC, Cameron Cuch, Paula Black, Johnna Blackhair, and Elton Blackhair in the United States District Court for the District of Utah. This suit was served in April 2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the defendants, among other things, intentionally interfered with Plaintiffs’ employment agreement with the Ute Indian Tribe – Energy & Minerals Department and intentionally interfered with Plaintiffs’ prospective economic relationships. Plaintiffs seek actual damages, punitive damages, costs and attorney’s fees. We dispute Plaintiffs’ claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.

Uracoa Municipality Tax Assessments. Our Venezuelan subsidiary, Harvest Vinccler has received nine assessments from a tax inspector for the Uracoa municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:

• Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the capital fee reimbursement and related interest paid by PDVSA under the Operating Service Agreement (“OSA”). Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims.

• Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims.

• Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim.

• Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims.

Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s, the Venezuelan income tax authority, interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.

Libertador Municipality Tax Assessments. Harvest Vinccler has received five assessments from a tax inspector for the Libertador municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:

• One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Mayor’s Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. On April 10, 2008, the Tax Court suspended the case pending a response from the Mayor’s Office to the protest. If the municipality’s response is to confirm the assessment, Harvest Vinccler will defer to the competent Tax Court to enjoin and dismiss the claim.

• Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.

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• 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.

Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the refund of all municipal taxes paid since 2002.

We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such litigation which will have a material adverse impact on our financial condition, results of operations and cash flows.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

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

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

Our common stock is traded on the NYSE under the symbol “HNR”. As of December 31, 2011, there were 34,317,087 shares of common stock outstanding, with approximately 457 stockholders of record. The following table sets forth the high and low sales prices for our Common Stock reported by the NYSE.

Year	Quarter	High		Low
2010	First quarter		7.80		4.36
	Second quarter		9.00		7.10
	Third quarter		10.42		6.54
	Fourth quarter		14.02		10.44
2011	First quarter		16.75		10.59
	Second quarter		15.71		10.51
	Third quarter		13.81		8.57
	Fourth quarter		12.04		6.58

On March 2, 2012, the last sales price for the common stock as reported by the NYSE was $6.31 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, 2011, assuming an investment of $100 on December 31, 2006 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, 2006 and that all dividends were reinvested.

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PLOT POINTS

(December 31 of each year)

	2006		2007		2008		2009		2010		2011
Harvest Natural Resources, Inc.	$	100	$	118	$	40	$	50	$	114	$	69
Dow Jones US E&P Index	$	100	$	140	$	82	$	116	$	138	$	134
S&P 500 Index	$	100	$	105	$	66	$	84	$	97	$	99

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, 2011 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.

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	Year Ended December 31,
	2011			2010 (1)			2009 (1)			2008 (1)			2007 (1)(2)
				(in thousands, except per share data)
Statement of Operations:
Total revenues	$	—		$	—		$	—		$	—		$	11,217
Operating loss		(86,302	)		(34,403	)		(30,586	)		(54,144	)		(19,536	)
Net income from Unconsolidated Equity Affiliates		73,451			66,291			35,253			33,226			54,279
Net income (loss) from continuing operations		(29,545	)		24,400			4,434			(15,589	)		78,881
Net income (loss) attributable to Harvest		56,429			15,442			(3,510	)		(22,544	)		59,304
Net income (loss) from continuing operations attributable to Harvest per common share:
Basic	$	(1.28	)	$	0.35		$	(0.10	)	$	(0.65	)	$	1.62
Diluted	$	(1.11	)	$	0.32		$	(0.10	)	$	(0.65	)	$	1.56
Weighted average common shares outstanding
Basic		34,117			33,541			33,084			34,073			36,550
Diluted		39,461			36,767			33,084			34,073			37,950
	As of December 31,
	2011			2010 (1)			2009 (1)			2008 (1)			2007 (1)(2)
				(in thousands)
Balance Sheet Data:
Total assets	$	513,047		$	485,499		$	345,907		$	359,763		$	416,053
Long-term debt, net of current maturities		31,535			81,237			—			—			—
Total Harvest’s Stockholders’ equity(3)		363,777			304,609			272,296			271,348			315,833

⁽¹⁾ Certain amounts have been revised. See Notes to Consolidated Financial Statements, Note 2 – Summary of Significant Accounting Policies – Revision for additional information.

⁽²⁾ Activities under our former Operating Service Agreement 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.

⁽³⁾ No cash dividends were declared or paid during the periods presented.

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

Operations

Venezuela

In January 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate for purchases and the 2.5935 Bolivars per U.S. Dollar exchange rates for the sale of foreign currency which was established in the January 2010 Exchange Agreement. The elimination of the 2.60 Bolivars per U.S. Dollar exchange rate for purchases and the 2.5935 Bolivars per U.S. Dollar exchange rates for the sale of foreign currency did not have an impact on our business in Venezuela.

In May 2010, the government of Venezuela established the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) for exchanging Bolivars. SITME’s purpose is to assist companies and individuals requiring foreign currency (U.S. Dollars) for the import of goods and services into Venezuela. SITME may also be used for buying or selling of Venezuela’s bonds. The establishment of SITME has not had, nor is it expected to have, an impact on our business in Venezuela.

Harvest Vinccler’s and Petrodelta’s functional and reporting currency is the U.S. Dollar, and they do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). However, during the year ended December 31, 2011,

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Harvest Vinccler exchanged approximately $1.2 million (2010: $0.2 million) through SITME and received an average exchange rate of 5.19 Bolivars (2010: 5.19 Bolivars) per U.S. Dollar. Harvest Vinccler currently does not have any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. Petrodelta does not have, and has not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate.

The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. At December 31, 2011, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 4.3 million Bolivars and 6.0 million Bolivars, respectively. At December 31, 2011, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 172.8 million Bolivars and 2,535.0 million Bolivars, respectively.

Petrodelta

In Item 1A. Risk Factors, we disclosed that PDVSA’s failure to timely pay contractors, including Petrodelta, was having an adverse effect on Petrodelta. We have advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, operations and seismic interpretation, and employee salaries and related benefits for Harvest employees seconded into Petrodelta. Currently, we have three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. We are considered a contractor to Petrodelta, and as such, we are also experiencing the slow payment of invoices. During the year ended December 31, 2011, we advanced Petrodelta $0.8 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advances. Advances to equity affiliate has increased $0.7 million, to a balance of $2.4 million, during the year ended December 31, 2011. During the year ended December 31, 2010, we advanced Petrodelta $2.0 million for continuing operations costs, and Petrodelta repaid $4.8 million of the advances. Although payment is slow, payments continue to be received. As a Petrodelta contractor, Harvest Vinccler assessed the possibility of recording an allowance for doubtful accounts on its receivable from Petrodelta. After considering many factors, including the slow but continuous payments received from Petrodelta, Harvest Vinccler determined that an allowance for doubtful accounts is not required.

We are unable to provide an indication of when PDVSA will become and remain current in its payment obligations. However, we believe that PDVSA’s debt will not disappear completely in the short term, but the risk of contractor work stoppage is minimal due to PDVSA guaranteeing payments as publicly stated by top officials. Increased costs due to PDVSA’s debt financing are already imbedded in current contractor’s rates.

Petrodelta’s 2011 capital expenditures were expected to be approximately $200 million. Petrodelta’s 2011 proposed business plan included a planned drilling program to utilize two rigs to drill both development and appraisal wells for maintaining production capacity, the continued appraisal of the substantial resource base in the El Salto field and further drilling in the Isleño field. It also included engineering work for production facilities required for the full development of the El Salto and Temblador fields. Due to insufficient monetary and contractual support by PDVSA, Petrodelta incurred only $137.5 million of its 2011 planned capital expenditures.

As of March 7, 2012, the 2012 budget for Petrodelta’s business plan had not yet been approved by its shareholders. Since Petrodelta only executed approximately 69 percent of its 2011 planned capital expenditures primarily due to insufficient monetary and contractual support by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2012 budget. Should PDVSA continue in insufficient monetary and contractual support of Petrodelta, underinvestment in the development plan may lead to continued under-performance. However, Petrodelta’s 2012 proposed business plan includes a planned drilling program to utilize three rigs to drill both development and appraisal wells for maintaining production capacity and the continued appraisal of the substantial resource base in the El Salto and Isleño fields. It also includes engineering work for the additional infrastructure enhancement projects in El Salto and Temblador.

In April 2011, the Venezuelan government published in the Official Gazette the amended Windfall Profits Tax. The amended Windfall Profits Tax establishes a special contribution for extraordinary prices to the Venezuelan government of 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $40 per barrel for 2011[$50 per barrel for 2012]) and $70 per barrel. The

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amended Windfall Profits Tax also establishes a special contribution for exorbitant prices to the Venezuelan government of (1) 80 percent when the average price of the VEB exceeds $70 per barrel but is less than $90 per barrel; (2) 90 percent when the average price of the VEB exceeds $90 per barrel but is less that $100 per barrel; and (3) 95 percent when the average price of the VEB exceeds $100 per barrel. The amended Windfall Profits Tax caps the cash royalty paid on production at $70 per barrel. By placing a cap on the royalty barrels, the amended Windfall Profits Tax reduces the royalties paid to the government and increases payments to the National Development Fund (“FONDEN”).

Windfall Profits Tax is deductible for Venezuelan income tax purposes. Petrodelta recorded $237.6 million for Windfall Profits Tax during the year ended December 31, 2011(2010: $14.1 million, 2009: $0.9 million).

There are many sections of the amended Windfall Profits Tax which have yet to be clarified. One section for which Petrodelta is waiting for clarity is how the $70 cap on royalty barrels will be applied to royalties paid in-kind. Petrodelta pays royalties on production of 30 percent in-kind and 3.33 percent in cash. In October 2011, Petrodelta received preliminary instructions from PDVSA that royalties, whether paid in cash or in-kind, should be reported at $70 per barrel (royalty barrels x $70). The difference between the $70 royalty cap and the current oil price is to be reflected on the income statement as a reduction in oil sales. PDVSA also instructed Petrodelta to make the reporting change retroactive to April 18, 2011, the date of enactment of the amended Windfall Profits Tax. From April 18, 2011 to December 31, 2011, the reduction to oil sales due to the $70 cap applied to all royalty barrels was $85.0 million ($27.2 million net to our 32 percent interest). Net oil sales (oil sales less royalties) are the same under the method advised by PDVSA and the method of applying the current oil price to total barrels produced and to total royalty barrels; however, the method advised by PDVSA understates gross oil sales.

Per our interpretation of the amended Windfall Profits Tax, the $70 cap on royalty barrels should only be applied to the 3.33 percent royalty which Petrodelta pays in cash. Pending receipt of final guidance from the Ministry of the People’s Power for Energy and Petroleum (“MENPET”), we have applied the $70 cap to only the 3.33 percent royalty paid in cash and the current oil sales price to the 30 percent royalty paid in-kind. With the assistance of Petrodelta, we have recalculated Petrodelta’s oil sales and royalties to apply the current oil price to its total barrels produced and to the 30 percent royalty paid in-kind and applied the $70 cap to the 3.33 percent royalty paid in cash for the year ended December 31, 2011. From April 18, 2011 to December 31, 2011, net oil sales (oil sales less royalties) are slightly higher, $8.5 million ($2.7 million net to our 32 percent interest), under this method than the method advised by PDVSA and the method of applying the current oil price to total barrels produced and to total royalty barrels.

Another section of the amended Windfall Profits Tax for which Petrodelta is waiting for clarity relates to an exemption of this tax that can be granted by MENPET for the incremental production of projects and grass root developments until the specific investments are recovered. This exemption has to be considered and approved in a case by case basis by MENPET. We believe several of the fields operated by Petrodelta may qualify for the exemption from the amended Windfall Profits Tax. We are waiting for clarification from MENPET on the definitions of incremental production and grass roots developments, as well as guidance on the process for applying for the exemption.

LOCTI requires major corporations engaged in activities covered by the OHL to contribute 0.5 percent (two percent prior to January 1, 2011) of their gross revenue generated in Venezuela from activities specified in the OHL on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. The contribution is based on the previous year’s gross revenue and is due the following year. Each company is required to file a separate declaration. Prior to January 1, 2011, contributions were allowed to be paid in-kind through self-funded programs and direct contributions to projects performed by other institutions. Effective January 1, 2011, LOCTI requires all contributions to be paid in cash directly to FONDACIT, the entity responsible for the administration of LOCTI contributions. Self-funded programs and direct contributions to projects performed by other institutions are no longer allowed. Since all contributions are now to be paid in cash, Petrodelta has accrued the 2011 liability to LOCTI.

Because contributions were allowed to be paid in-kind prior to January 1, 2011, LOCTI had granted waivers to allow PDVSA to file declarations on a consolidated basis covering all of its and its consolidating entities liabilities. For filing years 2007, 2008 and 2010, PDVSA provided Petrodelta with a copy of the waiver acceptance letter from LOCTI. PDVSA has stated that a waiver was granted for filing year 2009; however, LOCTI has not yet issued the acceptance letter to PDVSA for the 2009 filing year. The potential exposure to LOCTI for the year ended December 31, 2009 after devaluation is $4.8 million, $2.4 million net of tax ($0.8 million net to our 32 percent interest).

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In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, as of March 7, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain.

During the year ended December 31, 2011, Petrodelta drilled and completed 15 development wells, one successful appraisal well and two water injector wells compared to 16 development wells in the year ended December 31, 2010. Petrodelta delivered approximately 11.4 million barrels (“MBls”) of oil and 2.3 billion cubic feet (“Bcf”) of natural gas, averaging 32,240 barrels of oil equivalent (“BOE”) per day during the year ended December 31, 2011 compared to deliveries of 8.6 MBls of oil and 2.2 Bcf of gas, averaging 23,455 BOE per day during the year ended December 31, 2010.

During the year ended December 31, 2011, Petrodelta completed facilities at EPM transfer point for El Salto field. Completion of the facilities has enabled Petrodelta to increase production from the El Salto field. Petrodelta is continuing additional infrastructure enhancement projects in El Salto and Temblador. Petrodelta took possession of a third drilling rig at the end of September 2011. Currently, one drilling rig is operating in the El Salto field, and two drilling rigs are operating in the Temblador field. A workover rig is operating in the Tucupita field.

Petrodelta’s Proved reserves, net to our 32 percent interest, are 43.3 MMBOE at December 31, 2011. Petrodelta’s Probable reserves, net to our 32 percent interest, are 60.5 MMBOE at December 31, 2011. Petrodelta’s Possible reserves, net to our 32 percent interest, are 106.8 MMBOE. Proved plus Probable reserves at 103.8 MMBOE are virtually unchanged from last year. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies – Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve estimates.

Certain operating statistics for the years ended December 31, 2011, 2010, and 2009 for the Petrodelta fields operated by Petrodelta are set forth below. This information is provided at 100 percent.

	December 31,
	2011		2010		2009
Thousand barrels of oil sold		11,390		8,561		7,835
Million cubic feet of gas sold		2,266		2,204		4,397
Total thousand barrels of oil equivalent		11,768		8,928		8,568
Average price per barrel	$	98.52	$	70.57	$	57.62
Average price per thousand cubic feet	$	1.54	$	1.54	$	1.54
Cash operating costs ($millions)	$	77.2	$	44.7	$	48.2
Capital expenditures ($millions)	$	137.5	$	98.7	$	77.5

Petrodelta’s results and operating information is more fully described in Item 15. Exhibits and Financial Statement Schedules, Notes to the Consolidated Financial Statements, Note 11 – 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 through the opening of our London and Singapore offices, 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 has become a larger part of our overall portfolio, we will generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles.

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Exploration will be technically driven with a low entry cost and high resource potential that provides sustainable growth.

United States

Gulf Coast – West Bay

We held exploration acreage in the Gulf Coast Region of the United States through an Area of Mutual Interest (“AMI”) agreement with two private third parties. As of June 30, 2011, we and our partners in the West Bay project agreed to relinquish the exploration acreage we held to the farmor. The relinquishment was completed with an effective date of October 31, 2011. Neither we nor our partners intend to continue any activity in West Bay. Based on the decision in the second quarter 2011 to relinquish the exploration acreage, the carrying value of West Bay of $3.3 million was impaired as of June 30, 2011.

Western United States – Antelope

On May 17, 2011, we closed the transaction to sell all of our interest in the oil and gas assets located in our Antelope Project area in the Uinta Basin of Utah which consisted of approximately 69,000 gross acres (47,600 net acres), and the related contracts, reserves, production, wells, pipelines production facilities and other rights, title and interests located in the Uintah Basin in Duchesne and Uintah Counties, Utah. The transaction included the Mesaverde, the Lower Green River/Upper Wasatch and the Monument Butte Extension. We owned an approximate working interest of 70 percent in the Mesaverde and Lower Green River/Upper Wasatch, an approximate 60 percent working interest in one well in the Monument Butte Extension, an approximate 43 percent working interest in the initial eight well program in the Monument Butte Extension, and 37 percent working interest in the follow-up six well program in the Monument Butte Extension. The initial eight well program and follow-up six well program in the Monument Butte Extension were non-operated. The sale had an effective date of March 1, 2011 (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 4 – Dispositions). We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. All activities associated with the Antelope Project have been reflected as discontinued operations on the statement of operations.

Budong-Budong Project, Indonesia

Operational activities during 2011 focused on drilling of the first two exploratory wells, the LG-1, which spud on January 6, 2011, and the KD-1, which spud on June 20, 2011.

The LG-1, the first of the two exploratory wells in the Budong PSC, targeted the Miocene and Eocene reservoirs to a planned depth of approximately 7,200 feet. The LG-1 was drilled to a total depth of 5,311 feet and encountered multiple hydrocarbon shows and overpressure in Late Miocene rocks requiring up to 16.5 pound per gallon mud. After encountering difficulty in controlling the well due to high pressures, the well was plugged and abandoned on April 8, 2011. The primary Eocene targets had not yet been reached, as the well was planned for a total measured depth of approximately 7,200 feet. Fluid samples and log evaluation confirmed the presence of a proven petroleum system in the Lariang Sub-Basin. The costs for drilling the LG-1, $14.0 million, were suspended at March 31, 2011 pending further evaluation and appraisal.

The KD-1, the second of the two exploratory wells in the Budong PSC, is located approximately 50 miles south of the LG-1. The KD-1 was initially drilled to a total depth of 9,633 feet and sidetracked after the drill string was severed. The KD-1ST was initially drilled to 11,880 feet and logged. Evaluation of cuttings, logs and sidewall cores demonstrated presence of oil over a 200 foot section of low permeability and porosity clastics in the Early Miocene. The presence of oil shows proved the existence of a working petroleum system. On November 4, 2011, we elected to deepen the KD-1ST to a final total depth of 14,437 feet (13,576 feet TVD) as a sole risk operation. The KD-1ST encountered both Oligocene and Eocene rocks before drilling had to be stopped as the well reached the blow-out-preventer pressure limit. This resulted in the primary Eocene fluvial reservoir target not being reached. On January 2, 2012, the KD-1ST was plugged and abandoned with oil shows. Drilling costs of $26.0 million related to the drilling of the KD-1 and KD-1ST have been expensed to dry hole costs as of December 31, 2011.

In January 2012, after completion of drilling of the KD-1, all information gathered from the drilling of the LG-1 and KD-1 was reevaluated in connection with our plans for the Budong PSC and overall corporate strategy.

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Based on this reevaluation, we determined that the original LG-1 well bore would not be used for re-entry. Since plans for the Budong PSC no longer include re-entry of the LG-1 well bore, the drilling costs of $14.0 million related to the drilling of the LG-1 have been expensed to dry hole costs as of December 31, 2011. Based on the multiple oil and gas shows encountered in both the LG-1 and KD-1, we are working on an exploration program targeting the Pliocene and Miocene targets encountered in the previous two wells. As such, the other costs incurred related to the Budong PSC of $6.8 million remain capitalized on our balance sheet as of December 31, 2011.

During the year ended December 31, 2011, we had cash capital expenditures of $19.7 million for drilling, construction and plugging and abandonment costs and $3.7 million for the purchase of the additional 10 percent equity interest. The 2012 budget for the Budong PSC is $4.6 million.

Dussafu Project - Gabon

Operational activities during 2011 focused on the drilling of our first exploratory well, the DRM-1, which spud April 28, 2011, and appraisal sidetracks. The DRM-1 was drilled in a water depth of 380 feet to test multiple stacked pre-salt targets to a planned total measured depth of approximately 11,450 feet.

The DRM-1 reached an initial total depth of 10,044 feet (9,953 feet of TVDSS) within the Upper Dentale Formation. Log evaluation, pressure data and samples indicated an oil discovery of approximately 55 feet of oil pay in a 90 foot oil column within the Gamba Formation.

Subsequently the DRM-1 was deepened to reach a final total depth of 11,450 feet (11,355 feet TVDSS) to test the prospectivity of both the Middle and Lower Dentale Formations. Log evaluation, pressure data and a fluid sample indicated the discovery of a second oil accumulation with approximately 35 feet of oil pay within the secondary objective of the Middle Dentale Formation.

The first sidetrack, the DRM-1ST1, 0.75 miles to the southwest, was drilled to a total depth of 11,562 feet (9,428 feet TVDSS) in the Upper Dentale and found 19 feet of oil pay in the Gamba reservoir. The second sidetrack, the DRM-1ST2, 0.5 miles to the northwest of the DRM-1, was drilled to a total depth of 10,615 feet (9,429 feet TVDSS) in the Upper Dentale and found 40 feet of oil pay in the Gamba reservoir.

Drilling operations on the Dussafu PSC are currently suspended pending further exploration and development activities. The DRM-1 information is being used to refine the 3-D seismic depth model and improve our understanding for predicting the Gamba structure under the salt to define potential resources in the nearby satellite structures for future drilling targets. Reservoir characterization and concept engineering studies have started with the aim of evaluating the potential for commerciality of the discovered oil.

The partners in the Dussafu PSC began a 3-D seismic acquisition in a joint program with a third party. The program, which was operated by the third party and commenced on October 23, 2011, was completed November 18, 2011. We acquired an additional 545 square kilometers of seismic which is currently being processed. The seismic data was acquired in the northern area of the Dussafu PSC between the two existing 3-D seismic surveys acquired in 1994 and 2005 and the 2-D seismic survey we acquired in 2008.

During the year ended December 31, 2011, we had cash capital expenditures of $40.6 million for well planning and drilling. The 2012 budget for the Dussafu PSC is $5.6 million.

Block 64 EPSA Project - Oman

Operational activities during 2011 included well planning and procurement of long lead items. On October 21, 2011, a Standby Letter of Credit in the amount of $1.2 million was issued as a payment guarantee for electric wireline services to be provided during the drilling of the two exploratory wells on the Block 64 EPSA.

The first of the two exploratory wells, the MFS-1, spud October 29, 2011. The MFS-1 was drilled to test the Mafraq South fault block. The MFS-1 reached a revised final total depth of 10,348 feet. The logs indicated no presence of hydrocarbons within the stacked reservoir targets of the Haima Group. On December 11, 2011, the MFS-1 was plugged and abandoned. Drilling costs of $6.9 million related to the drilling of the MFS-1 have been expensed to dry hole costs as of December 31, 2011.

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The AGN-1, the second exploratory wells on the Block 64 EPSA, spud December 21, 2011 and was drilling at December 31, 2011. On February 3, 2012, the AGN-1 reached a final total depth of 10,482 feet. The logs indicated no presence of moveable hydrocarbons within the stacked reservoir targets of the Haima Group, although residual gas saturations appear to be present in the overlying Permian carbonate and dolomites of the Khuff Formation. Gas shows and saturations on the logs were recorded. On February 6, 2012, the AGN-1 was plugged and abandoned with gas shows. Total estimated drilling costs for the AGN-1 are approximately $7.6 million. Drilling costs incurred through December 31, 2011 of $2.8 million have been expensed to dry hole costs as of December 31, 2011. Drilling costs incurred after December 31, 2011 will be expensed to dry hole costs in the first quarter of 2012.

During the year ended December 31, 2011, we had cash capital expenditures of $10.2 million for well planning, drilling and plugging and abandonment costs. The 2012 budget for the Block 64 EPSA is $14.3 million.

WAB-21 Project – China

In March 2011, CNOOC granted us an extension of Phase One of the Exploration Period for the WAB-21 contract area to May 2013. Operational activities during 2011 include costs related to maintenance of the license. The 2012 budget for WAB 21 is minimal consisting of costs required to maintain the license.

Other Exploration Projects

Relating to other projects, we incurred $0.3 million during the year ended December 31, 2011. The 2012 budget for other projects is minimal consisting of costs required to complete projects started in 2011.

Fusion Geophysical, LLC (“Fusion”)

On January 28, 2011, Fusion’s 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. We received $1.4 million for our equity investment and $0.7 million for the repayment in full of the outstanding balance of the prepaid service agreement, short term loan and accrued interest. The Agreement and Plan of Merger included an Earn Out provision wherein we would receive an additional payment of up to a maximum of $2.7 million if FusionGeo, Inc.’s 2011 gross profit exceeds $5.6 million. Based on the financial results for the period January 29, 2011 through January 28, 2012, FusionGeo’s gross profit did not exceed $5.6 million, the 2011 Earn Out Threshold, as described in the Agreement and Plan of Merger. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 11 – Investment in Equity Affiliates – Fusion Geophysical LLC.

Business Strategy

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. The expectation that dividends from Petrodelta will be minimal over the next two yearshas 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:

• 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.

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To accomplish our strategy, we intend to:

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

• Seek Operational 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.

• 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 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-of-the-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.

Results of Operations

We had net income attributable to Harvest of $53.9 million, or $1.37 per diluted share, for the year ended December 31, 2011 compared to net income attributable to Harvest of $15.4 million, or $0.42 per diluted share, for the year ended December 31, 2010. Net income attributable to Harvest for the year ended December 31, 2011 includes $13.7 million of exploration expense and the net equity income from Petrodelta’s operations of $72.1 million. Net income attributable to Harvest for the year ended December 31, 2010 includes $8.0 million of exploration expense and the net equity income from Petrodelta’s operations of $66.3 million.

The following discussion should be read with the results of operations for each of the years in the three-year period ended December 31, 2011 and the financial condition as of December 31, 2011 and 2010 in conjunction with our consolidated financial statements and related notes thereto.

Years Ended December 31, 2011 and 2010

We reported net income attributable to Harvest of $53.9 million, or $1.37 diluted earnings per share, for the year ended December 31, 2011, compared with net income attributable to Harvest of $15.4 million, or $0.42 diluted earnings per share, for the year ended December 31, 2010.

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

	Year Ended December 31,						Increase
	2011			2010			(Decrease)
Depreciation and amortization	$	0.5		$	0.5		$	—
Exploration expense		13.7			8.0			5.7
Dry hole costs		49.7			—			49.7
General and administrative		22.5			25.9			(3.4	)
Investment earnings and other		(0.7	)		(0.6	)		0.1
Interest expense		5.3			2.7			2.6
Loss on extinguishment of debt		9.7			—			9.7
Other non-operating expense		1.4			4.0			(2.6	)
Loss on exchange rates		0.1			1.6			(1.5	)
Income tax expense (benefit)		0.8			(0.2	)		1.0

Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2011, we incurred $10.1 million of exploration costs for the acquisition, processing and reprocessing of seismic data related to ongoing operations, $0.3 million related to other general business development activities, and $3.3 million of impairment for the carrying value of West Bay (see Item 1. Business, Operations – United States Operations, Gulf Coast – West Bay Project). During the year ended December 31, 2010, we incurred $6.4 million of exploration costs for seismic, geological and geophysical, and exploration support costs and $1.6 million related to other general business development activity. Included in the $6.4 million of exploration costs is the one-time charge of $1.2 million for acquisition of seismic data for the Budong PSC related to our partner in the Budong PSC exercising their option to increase the carry obligation.

During the year ended December 31, 2011, we expensed to dry hole costs $14.0 million related to the drilling of the LG-1 on the Budong PSC, $26.0 million related to the drilling of the KD-1 and KD-1ST on the Budong PSC, $6.9 million related to the drilling of the MFS-1 on the Block 64 ESPA and $2.8 million related to the drilling of the AGN-1 on the Block 64 EPSA (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 13 – Indonesia and Note 15 – Oman).

The decrease in general and administrative costs in the year ended December 31, 2011 from the year ended December 31, 2010 was primarily due to lower general office expense and overhead ($2.7 million), employee related costs ($0.9 million) and public relations ($0.3 million) offset by higher travel costs ($0.3 million) and contract services ($0.2 million). The employee related costs include $0.5 million of special consideration bonuses related to the sale of our Antelope Project.

The increase in investment earnings and other in the year ended December 31, 2011 from the year ended December 31, 2010 was due to income earned on transition services provided on the Antelope Project after closing of the sale.

The increase in interest expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to the interest associated with our $32 million convertible debt offering in February 2010, our $60 million term loan facility occurring in October 2010 and amortization of discount on the term loan facility related to the warrants issued in connection with the $60 million term loan facility offset by interest capitalized to oil and gas properties of $2.3 million.

During the year ended December 31, 2011, we incurred a loss on extinguishment of debt related to early payment of our $60 million term loan facility. The loss on extinguishment of debt includes the write off of the discount on debt ($7.2 million), prepayment premium of 3.5 percent of the amount outstanding ($2.1 million), expensing of financing costs related to the term loan facility ($0.3 million), and the cost to repurchase 4.4 million unvested warrants issued in connection with the term loan facility.

The decrease in loss on exchange rates in the year ended December 31, 2011 from the year ended December 31, 2010 is due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. There was no Bolivar/U.S. Dollar exchange rate devaluations in the year ended December 31, 2011.

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The decrease in other non-operating expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to costs incurred related to our strategic alternative process and evaluation which resulted in the sale of our Antelope Project.

The increase in income tax expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to higher income tax assessed in 2011 in the Netherlands offset by a U.S. tax refund received in 2010.

For the year ended December 31, 2011, net income from unconsolidated equity affiliates reflects an increase in Petrodelta’s revenue from oil sales due to higher sales volumes and prices which was partially offset by the amended Windfall Profits Tax. The increase in operating expense and workovers in the year ended December 31, 2011 from the year ended December 31, 2010 was due to increased oil production and having a workover rig on location for the full year of 2011. Petrodelta took possession of the workover rig in September 2010 and operated it for only four months in the year ending December 31, 2010. The decrease in gain on exchange rates in the year ended December 31, 2011 from the year ended December 31, 2010 was due to there not being a Bolivar/U.S. Dollar currency exchange rate devaluation during 2011. There was a Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. The decrease in Petrodelta’s effective tax rate (inclusive of the adjustments to reconcile to reported net income from unconsolidated equity affiliate) in the year ended December 31, 2011 from the year ended December 31, 2010 was primarily due to the tax effects of the currency devaluation in 2010 partially offset by an increase in current tax on increased earnings.

At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion. Accordingly, we did not record net losses incurred by Fusion of $0.2 million ($0.1 million net to our 49 percent interest) in the year ended December 31, 2011 (2010: $2.4 million [$1.2 million net to our 49 percent interest]), as doing so would have caused our equity investment to go into a negative position. However, we have recognized a $1.4 million gain on the sale of Fusion in the year ended December 31, 2011.

Discontinued Operations

On May 17, 2011, we closed the transaction to sell our Antelope Project. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 4 – Dispositions. The sale had an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale was reported in the second quarter of 2011.

Revenue and net income on discontinued operations for the years ended December 31, 2011 and 2010 are shown in the table below:

	December 31,
	2011		2010
	(in thousands)
Revenue applicable to discontinued operations	$	6,488	$	10,696
Net income from discontinued operations	$	97,616	$	3,712

Net income from discontinued operations for the year ended December 31, 2011 includes $106.0 million gain on the sale of our Antelope Project, $3.8 million for employee severance and special accomplishment bonuses, and $5.7 million of U.S. income tax related to the sale of our Antelope Project. Severance costs for key employees include 58,000 stock appreciation rights (“SAR”) granted at an exercise price of $4.595 per SAR. These SARs are exercisable by the key employee for up to one year after termination.

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Years Ended December 31, 2010 and 2009

Revisions for the Years Ended 2010 and 2009

We are revising our historical financial statements for the year ended December 31, 2010 and quarterly information for the quarters ended March 31, 2010, June 30, 2010, September 30, 2010, December 31, 2010, March 31, 2011, June 30, 2011 and September 30, 2011 (see Item 15. Exhibits and Financial Statement Schedules, Quarterly Financial Data (unaudited)). The revisions relate to the correction of an error in the deferred tax adjustment to reconcile our share of Petrodelta’s net income reported under International Financial Reporting Standards (“IFRS”) to that required under accounting principles generally accepted in the United States of America (“USGAAP”) and recorded within Net income from unconsolidated equity affiliates. Previously, Petrodelta had an incorrect tax basis associated with its asset retirement cost which caused us to overstate or understate the deferred tax expense associated with this temporary difference for USGAAP purposes. We have revised the tax basis to record the correct deferred tax expense in each reporting period. The error has no impact to the consolidated statements of cash flows.

We have determined that the impact of this error is not significant to the previously issued annual and interim financial statements as defined by Accounting Standards Codification (“ASC”) 250 – Accounting Changes and Error Corrections (“ASC 250”). The audited financial statements, related notes and analyses for the years ended December 31, 2011, 2010 and 2009 have been retrospectively revised in this Annual Report on Form 10-K for the year ended December 31, 2011. All future filings, including interim financial statements, will be revised appropriately.

We reported net income attributable to Harvest of $15.4 million, or $0.42 diluted earnings per share, for the year ended December 31, 2010, compared with a net loss attributable to Harvest of $3.5 million, or $(0.10) diluted earnings per share, for the year ended December 31, 2009.

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

	Year Ended December 31,						Increase
	2010			2009			(Decrease)
Depreciation and amortization	$	0.5		$	0.4		$	0.1
Exploration expense		8.0			7.8			0.2
General and administrative		25.9			22.4			3.5
Investment earnings and other		(0.6	)		(1.2	)		0.6
Interest expense		2.7			—			2.7
Other non-operating expense		4.0			—			4.0
Loss on exchange rates		1.6			0.1			1.5
Income tax expense (benefit)		(0.2	)		1.2			(1.4	)

Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2010, we incurred $6.4 million of exploration costs for seismic, geological and geophysical, and exploration support costs and $1.6 million related to other general business development activity. Included in the $6.4 million of exploration costs is the one-time charge of $1.2 million for acquisition of seismic data for the Budong PSC related to our partner in the Budong PSC exercising their option to increase the carry obligation. During the year ended December 31, 2009, we incurred $4.5 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations, $2.8 million related to other general business development activities and $0.5 million related to the write off of the remaining carrying value of the first prospect in the AMI.

The increase in general and administrative costs in the year ended December 31, 2010 from the year ended December 31, 2009 was primarily due to higher employee related costs ($3.0 million), the reversal in 2009 of accruals no longer required ($1.3 million) offset by a reduction in other general office costs ($0.8 million).

The decrease in investment earnings and other in the year ended December 31, 2010 from the year ended December 31, 2009 was due to lower interest rates earned on lower average cash balances.

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The increase in interest expense in the year ended December 31, 2010 from the year ended December 31, 2009 was due to interest associated with our $32.0 million senior convertible note offering in February 2010, our $60.0 million term loan facility occurring in October 2010 and amortization of discount on the term loan facility related to the warrants issued in connection with the $60 million term loan facility offset by interest capitalized to oil and gas properties of $1.8 million.

The increase in other non-operating expense in the year ended December 31, 2010 from the year ended December 31, 2009 was due to the expensing of $2.9 million of costs related to a future financing which was no longer being pursued and $1.1 million of costs related to other strategic alternatives.

The decrease in income tax expense in the year ended December 31, 2010 from the year ended December 31, 2009 was due to the receipt a $1.0 million U.S. income tax refund related to the recovery of alternative minimum tax for the tax years 2005 and 2007,$0.2 million reversal of a tax provision no longer needed, and lower tax assessed in the Netherlands of $0.7 million offset by $0.5 million of additional income taxes assessed to Harvest Vinccler in 2010 for the 2007 and 2008 tax years. The 2010 tax assessment for Harvest Vinccler was the result of a tax audit conducted by the SENIAT.

Net income from unconsolidated equity affiliates includes an $84.4 million remeasurement gain on revaluation of monetary assets and liabilities due to the Bolivar devaluation in January 2010 and a $19.5 million financing charge related to the blended exchange rate charged by the Central Bank of Venezuela for the purchase of foreign currency.

At December 31, 2009, we recorded a $1.6 million charge to fully impair the carrying value of our equity investment in Fusion. For the year ended December 31, 2010, Fusion reported a net loss of $2.4 million ($1.2 million net to our 49 percent interest) (2009: $4.8 million [$2.4 million net to our 49 percent interest]). The loss for 2010 is not reported in the year ended December 31, 2010 net income from unconsolidated equity affiliates as reporting it would take our equity investment into a negative position. On January 28, 2011, our minority equity investment in Fusion’s 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. We received $1.4 million for our equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full of the outstanding balance of the prepaid service agreement, short term loan and accrued interest. See Item 15. Exhibits and Financial Statement Schedules, Notes to the Consolidated Financial Statements, Note 11 – Investment in Equity Affiliates – Fusion Geophysical, LLC for additional information.

Discontinued Operations

On May 17, 2011, we closed the transaction to sell all of our oil and gas assets in Utah’s Uinta Basin (Antelope Project) for $217.8 million in cash. Accordingly, these operations have been classified as discontinued operations.

Revenue and net income (loss) on discontinued operations for the years ended December 31, 2010 and 2009 are shown in the table below:

	December 31,
	2010		2009
	(in thousands)
Revenue applicable to discontinued operations	$	10,696	$	181
Net income (loss) from discontinued operations	$	3,712	$	(242	)

Capital Resources and Liquidity

The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. In Item 1A. Risk Factors, we discuss a number of variables and risks related to our exploration projects and our minority equity investment in Petrodelta that could significantly utilize our cash balances, affect our capital resources and liquidity. We also point out that the total capital required to develop the fields in Venezuela may exceed Petrodelta’s available cash and financing capabilities, and that there may be operational or contractual consequences due to this inability.

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Our cash is being used to fund oil and gas exploration projects and to a lesser extent general and administrative costs. We require capital principally to fund the exploration and development of new oil and gas properties. For calendar year 2012, we have established a preliminary exploration and drilling budget of approximately $25.5 million of which approximately $10.0 million is non-discretionary. A substantial portion of this budget is for the completion of the drilling program on the Block 64 EPSA.

As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. Currently, we have a minimum work obligation to reprocess 375 square kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup during the Initial Term of the EPSA. The parties to the EPSA acknowledge that $22.0 million is indicative of the costs needed to complete the work program during the three-year initial period which expires in May 2013. Through December 31, 2011, we have incurred $16.2 million of the minimum work obligation. As of February 29, 2012, we have expended more than $22.0 million and completed the minimum work obligations. The remaining work commitment for the current exploration phase on the Budong PSC is for geological and geophysical work to be completed in the year 2012 at a minimum of $0.5 million ($0.3 million net to our 64.51 percent cost sharing interest). We do not have any remaining work commitments for the current exploration phase of the Dussafu PSC, but as of May 28, 2012, the Dussafu PSC enters the third exploration phase. If the partners elect to enter the third exploration phase, there will be a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a two year period. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidation Financial Statements, Note 13 – Indonesia and Note 14 – Gabon.

Our primary ongoing source of cash is still dividends from Petrodelta. In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, as of March 7, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain. We expect to receive future dividends from Petrodelta; however, we expect that in the near term Petrodelta will reinvest most of its earnings into the company in support of its drilling and appraisal activities. Therefore, there is uncertainty that Petrodelta will pay dividends in 2012 or 2013.

Additionally, any dividend received from Petrodelta carries a liability to our non-controlling interest holder, Vinccler, for its 20 percent share. Dividends declared and paid by Petrodelta are paid to HNR Finance, our consolidated subsidiary. HNR Finance must declare a dividend in order for us and our non-controlling interest holder, Vinccler, to receive our respective shares of Petrodelta’s dividends. A dividend from HNR Finance is due upon demand. As of March 7, 2012, Vinccler’s share of the undistributed dividends is $9.0 million inclusive of the unpaid November 2010 dividend. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 16 – Related Party Transactions.

We incurred debt during 2010 which has imposed restrictions on us and increased our vulnerability to adverse economic and industry conditions. Our semi-annual interest expense has increased significantly, and our senior convertible notes impose restrictions on us that limit our ability to obtain additional financing. Our ability to meet these covenants is primarily dependent on meeting customary affirmative covenant clauses. Our inability to satisfy the covenants contained in our senior convertible notes would constitute an event of default, if not waived. An uncured default could result in the senior convertible notes becoming immediately due and payable. If this were to occur, we may not be able to obtain waivers or secure alternative financing to satisfy our obligations, either of which would have a material adverse impact on our business. As of December 31, 2011, we were in compliance with all of our long term debt covenants.

At December 31, 2011, we had cash on hand of $58.9 million. We believe that this cash plus cash generated from Petrodelta dividends and funding from debt or equity financing combined with our ability to vary the timing of our capital expenditures is sufficient to fund our operations and capital commitments through at least December 31, 2012. Our 8.25 percent senior convertible notes are due March 1, 2013. We expect some, if not all, debt holders will convert their debt into shares of our common stock on or before the March 1, 2013 due date. However, if the debt is not converted or is only partially converted, we believe that Petrodelta dividends and funding from debt or equity financing combined with our ability to vary the timing of our capital expenditures will be sufficient to repay the outstanding debt at March 1, 2013. However, if the Petrodelta dividend payment is not received or our cash sources and requirements are different than expected, it could have a material adverse effect on our operations.

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In order to increase our liquidity to levels sufficient to meet our commitments, we are currently pursuing a number of actions including our ability to delay discretionary capital spending to future periods, possible farm-out or sale of assets, or other monetization of asset as necessary to maintain the liquidity required to run our operations. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, and cost reductions. However, there is no assurance that our plans will be successful. Although we believe that we will have adequate liquidity to meet our near term operating requirements and to remain compliant with the covenants under our long term debt arrangements, the factors described above create uncertainty. Our lack of cash flow and the unpredictability of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance adequate financing can be raised. Accordingly, there can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.

Working Capital. Our capital resources and liquidity are affected by the ability of Petrodelta to pay dividends. We expect to receive future dividends from Petrodelta; however, we expect that in the near term Petrodelta will reinvest most of its earnings into the company in support of its drilling and appraisal activities. However, in November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, as of March 7, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain. There is no certainty that Petrodelta will pay dividends in 2012 or 2013. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a complete description of the situation in Venezuela and other matters.

At December 31, 2011, we had cash on hand of $58.9 million, of which approximately $7.5 million is held by our foreign affiliates. Such amounts are permanently invested in our foreign operations and not available to fund domestic operations. If such funds were to be repatriated to the U.S., we would need to accrue and pay U.S. income tax on the amount repatriated. However, it is not our intention to repatriate these funds.

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

	Year Ended December 31,
	(in thousands except as indicated)
	2011			2010			2009
Net cash used in operating activities	$	(52,737	)	$	(5,296	)	$	(34,945	)
Net cash provided by (used in) investing activities		109,710			(59,061	)		(28,603	)
Net cash provided by (used in) used in financing activities		(56,730	)		90,743			(1,300	)
Net increase (decrease) in cash	$	243		$	26,386		$	(64,848	)
Working Capital		62,618			133,310			34,539
Current Ratio		2.9			5.7			3.1
Total Cash, including restricted cash		60,146			58,703			32,317
Total Debt		31,535			81,237			—

The decrease in working capital of $70.7 million at December 31, 2011 from December 31, 2010 was primarily a result of the completion of the sale of the Antelope Project, which was classified as a current asset at December 31, 2010, and the reclassification of a value added tax (“VAT”) receivable from current to long-term offset by an increase in capital expenditures and accounts payable due to drilling activities and income taxes related to the sale of the Antelope Project.

Cash Flow from Operating Activities. During the year ended December 31, 2011, net cash used in operating activities was approximately $52.7 million (2010: $5.3 million). The $47.4 million increase in use of cash was primarily due to drilling activities.

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Cash Flow from Investing Activities. Our cash capital expenditures for property and equipment are summarized in the following table:

	December 31,
	2011		2010
	(in millions)
Budong PSC	$	23.4	$	8.5
Dussafu PSC		40.6		2.6
Block 64 EPSA		10.2		0.4
Other projects		0.3		3.0
Total additions of property and equipment – continuing operations		74.5		14.5
Assets Held for Sale – Antelope Project(1)		33.9		45.1
Total additions of property and equipment	$	108.4	$	59.6

⁽¹⁾  See Notes to Consolidated Financial Statements, Note 4 – Dispositions.

During the year ended December 31, 2011, we:

• Received $217.8 million for the sale of our Antelope Project (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 4 – Dispositions);

• Received $1.0 million for the sale of pipe inventory associated with the Antelope Project;

• Received $1.4 million from the sale of our equity investment in Fusion (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 11 – Investments in Equity Affiliates, Fusion Geophysical, LLC);

• Deposited with a U.S. bank $1.2 million as collateral for a Standby Letter of Credit issued as a payment guarantee for drilling activities on the Block 64 EPSA (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 15 – Oman); and

During the year ended December 31, 2010, we:

• Expensed $0.5 million of investigative costs related to new business development projects which are no longer being pursued; and

• Expensed $2.9 million of costs related to a future financing which is no longer being pursued.

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 $25.5 million for 2012 for U.S., Indonesia, Gabon and Oman operations will be funded through our existing cash balances, accessing equity and debt markets, and cost reductions. In addition, we could delay the discretionary portion of our capital spending to future periods or sell 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, 2011, we:

• Repaid $60.0 million of our term loan facility (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 5 – Long-Term Debt);

• Recorded $2.5 million of tax benefits related to the difference between book and tax deductions allowed for equity compensation; and

• Incurred $0.2 million in legal fees associated with financings.

During the year ended December 31, 2010, we:

• Closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 5 – Long-Term Debt);

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• Closed a $60.0 million term loan facility (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 5 – Long-Term Debt);

• Incurred $2.5 million in deferred financings costs related to the $32.0 million convertible debt offering that is being amortized over the life of the convertible debt;

• Incurred $0.4 million in deferred financings costs related to the $60.0 million term loan facility that is being amortized over the life of the term loan facility; and

Contractual Obligations

At December 31, 2011, we had the following lease commitments for office space in Houston, Texas, regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Indonesia; Port Gentil, Gabon; and Muscat, Oman that support field operations in those areas. The field office in Port Gentil, Gabon is a month-to-month agreement.

	Date			Monthly
Location	Lease Signed	Term		Expense
Houston, Texas	April 2004		10 years	$	17,000
Houston, Texas	December 2008		5 years		13,400
Caracas, Venezuela	December 2011		1 year		7,000
London, U.K.	September 2010		5 years		9,000
Singapore	October 2010		2 years		7,000
Jakarta, Indonesia	April 2011		2 years		7,000
Muscat, Oman	September 2011		2 years		5,200

We have various contractual commitments pertaining to exploration, development and production activities:

• We have a minimum work obligation to reprocess 375 square kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup during the Initial Term of the EPSA. The parties to the EPSA acknowledge that $22.0 million is indicative of the costs needed to complete the work program during the three-year initial period which expires in May 2013. Through December 31, 2011, we have incurred $16.2 million of the minimum work obligation. As of February 29, 2012, we have expended more than $22.0 million and completed the minimum work obligations.

• The remaining work commitment for the current exploration phase on the Budong PSC is for geological and geophysical work to be completed in the year 2012 at a minimum of $0.5 million ($0.3 million net to our 64.51 percent cost sharing interest).

	Payments (in thousands) Due by Period
Contractual Obligation	Total		Less than 1 Year		1-2 Years		3-4 Years		After 4 Years
Debt:
8.25% Senior Convertible Note Due 2013	$	31,535	$	—	$	31,535	$	—	$	—
Total Debt		31,535		—		31,535		—		—
Other obligations:
Interest payments		3,903		2,602		1,301		—		—
Oil and gas activities		8,344		323		8,021		—		—
Office leases		2,020		837		694		401		88
Total other obligations		14,267		3,762		10,016		401		88
Total contractual obligations	$	45,802	$	3,762	$	41,551	$	401	$	88

We do not have any remaining work commitments for the current exploration phase of the Dussafu PSC, but as of May 28, 2012, the Dussafu PSC enters the third exploration phase. If the partners elect to enter the third exploration phase, there will be a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a two year period.

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Senior Convertible Note

On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. Under the terms of the notes, interest is payable semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2010. The senior convertible notes will mature on March 1, 2013, unless earlier redeemed, repurchased or converted. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Capital Resources and Liquidity.

Effects of Changing Prices, Foreign Exchange Rates and Inflation

Our results of operations and cash flow are affected by changing oil prices. Fluctuations in oil prices may affect our total planned development activities and capital expenditure program.

Our net foreign exchange losses attributable to our international operations were minimal for the year ended December 31, 2011 and $1.6 million for the year ended December 31, 2010. There are many factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our control. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.

Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004, March 2005, January 2010 and again in January 2011. On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate with an effective date of January 1, 2011.

Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). However, during the year ended December 31, 2011, Harvest Vinccler exchanged approximately $1.2 million through SITME and received an average exchange rate of 5.19 Bolivars per U.S. Dollar. The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Petrodelta does not have, and has not had, any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate. Harvest Vinccler currently does not have any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate.

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Venezuela for a more complete discussion of the exchange agreements and their effects on our Venezuelan operations.

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.

Critical Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. All intercompany profits, transactions and balances have been eliminated.

Reporting and Functional Currency

The United States Dollar (“U.S. Dollar”) is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. Amounts denominated in non-U.S. Dollar currencies are re-measured into U.S. Dollars, and all currency gains or losses are recorded in the consolidated statement of operations. We attempt to manage our operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence.

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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 (ASC 323). Investment in Equity Affiliates is increased by additional investments and earnings and decreased by dividends and losses. We review our Investment in Equity Affiliates for impairment whenever events and circumstances indicate a decline in the recoverability of its carrying value.

There are many factors we consider when evaluating our equity investments for possible impairment, including, but not limited to, currency devaluations, inflationary economies and cash flow analysis.

Capitalized Interest

We capitalize interest costs for qualifying oil and gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation.

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 are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. 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. Costs to develop proved reserves, including the costs of all development wells and related equipment used in production of crude oil and natural gas, are capitalized.

Depletion, depreciation, and amortization (“DD&A”) of the cost of proved oil and natural gas properties are calculated using the unit of production method. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is proved reserves. With respect to lease and well equipment costs, which include development 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 ASC 932. 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 properties under the provisions of ASC 360. 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.

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Suspended Exploratory Drilling Costs

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.

Reserves

In December 2009, we adopted the SEC’s Modernization of Oil and Gas Reporting and the FASB’s guidance on extractive activities for oil and gas (ASC 932). ASC 932 requires the unweighted average, first-day-of-the-month price during the 12-month period preceding the end of the year 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.

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. 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.

The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

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 depleted on a unit-of-production basis within the related asset group. Accretion is included in operating expenses and depletion is included in DD&A on our consolidated statement of income.

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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.

We do not provide deferred income taxes on undistributed earnings of our foreign subsidiaries for possible future remittances as all such earnings are reinvested as port of our ongoing business.

New Accounting Pronouncements

In April 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-04, which is included in ASC 820, “Fair Value Measurement” (“ASC 820”). This update explains how to measure fair value. It does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. ASU No. 2011-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption is not permitted. The adoption of ASU No. 2011-04 will not have a material impact on our consolidated financial position, results of operation or cash flows.

In June 2011, the FASB issued ASU No. 2011-05, which is included in ASC 220, “Comprehensive Income” (“ASC 220”). This update requires that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and will be applied retrospectively. Early adoption is permitted. The adoption of ASU No. 2011-05 will impact the presentation of our results of operations.

In September 2011, the FASB issued ASU No. 2011-08, which is included in ASC 350, “Intangibles – Goodwill and Other” (“ASC 350”). The objective of this update is to simplify how entities, both public and nonpublic, test goodwill for impairment. This update permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in ASC 350. ASU No. 2011-08 is effective for annual and interim fiscal years beginning after December 15, 2011. Early adoption is permitted. The adoption of ASU No. 2011-08 will not have a material impact on our consolidated financial position, results of operation or cash flows.

In December 2011, The FASB issued ASU No. 2011-11, which is included in ASC 210, “Balance Sheet” (ASC 210”). The amendments in ASU No. 2011-11 require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of these arrangements on its financial position. An entity is required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. ASU No. 2011-11 will be applied retrospectively. The adoption of ASU No. 2011-08 will not have a material impact on our consolidated financial position, results of operation or cash flows.

In December 2011, the FASB issued ASU No. 2011-12, which is included in ASC 220. ASU No. 2011-12 defers those changes in ASU 2011-05 that pertain to how, when, and where reclassification adjustments are presented. All other requirements of ASU No. 2011-05 are not affected by ASU No. 2011-12. ASU No. 2011-12 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and will be applied retrospectively. Early adoption is permitted. The adoption of ASU No. 2011-12 will not impact the presentation of our results of operations.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

Oil Prices

Oil and natural gas prices historically have been volatile, and this volatility is expected to continue. 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. Being primarily a crude oil producer, we are more significantly impacted by changes in crude oil prices than by changes in natural gas 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.

We currently do not have any oil production that is hedged. While hedging limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements.

Interest Rates

Total long-term debt at December 31, 2011 consisted of $31.5 million of fixed-rate unsecured senior convertible notes maturing in 2013 unless earlier redeemed, purchased or converted. A hypothetical 10 percent adverse change in the prime rate would not have a material effect on our results of operations for the year ended December 31, 2011.

Foreign Exchange

The Bolivar is not readily convertible into the U.S. Dollar. We have not utilized 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, Effects of Changing Prices, Foreign Exchange Rates and Inflation above.

Item 8. Financial Statements and Supplementary Data

The information required by this item is included herein on pages S-1 through S-40.

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

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures that are designed to ensure the information required to be disclosed by us in the reports that we file or submit under the 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, 2011, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) were effective.

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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, 2011. The effectiveness of our internal control over financial reporting as of December 31, 2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Changes in Internal Control over Financial Reporting. There have been no changes in internal control over financial reporting during the quarter ended December 31, 2011 that have materially affected or are reasonably likely to materially affect that Company’s internal control over financial reporting.

Item 9B. Other Information

None.

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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 2012 Annual Meeting of Stockholders.

Item 11. Executive Compensation

Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the 2012 Annual Meeting of Stockholders.

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

Please refer to the information under the caption “Stock Ownership” in our Proxy Statement for the 2012 Annual Meeting of Stockholders.

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

Please refer to the information under the caption “Certain Relationships and Related Transactions” in our Proxy Statement for the 2012 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 2012 Annual Meeting of Stockholders.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

			Page
(a)	1.	Index to Financial Statements:
		Report of Independent Registered Public Accounting Firm		S-1
		Consolidated Balance Sheets at December 31, 2011 and 2010		S-2
		Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009		S-3
		Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2011, 2010 and 2009		S-4
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		S-5
		Notes to Consolidated Financial Statements		S-7
	2.	Consolidated Financial Statement Schedules and Other:
	Schedule II – Valuation and Qualifying Accounts			S-49
	Schedule III – Financial Statements and Notes for Petrodelta, S.A			S-50

All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto.

(b) 3. Exhibits:

3.1	Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.)
3.2	Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on 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 4.2 to our Form 10- Q filed on November 9, 2010, File No. 1-10762.)
4.3	Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A12G filed on October 23, 2007, File No. 1-10762.)
4.4	Amendment to Third Amended and Restated Rights Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
4.5	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.)

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4.6	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.)
4.7	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.)
4.8	Warrant Purchase Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.2 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
4.9	Common Stock Purchase Warrant No. W-1, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.3 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)
4.10	Common Stock Purchase Warrant No. W-2, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.4 to our Form 8-K filed on October 29, 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†	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.)
10.8†	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.)
10.9†	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.)
10.10	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].)

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10.11	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.)
10.12	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.)
10.13	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.)
10.14†	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.)
10.15†	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.)
10.16	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.)
10.17	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.)
10.18†	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.)
10.19	Contract for Conversion to a Mixed Company between Corporación Venezolana delPetróleo, 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.)
10.20†	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.)
10.21†	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.)
10.22†	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.)
10.23†	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.)
10.24	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.)
10.25	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.)

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10.26	2010 Long Term Incentive Plan. (Incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed with the Securities and Exchange Commission on April 9, 2010, File No. 1-10762.)
10.27	Form of 2010 Long Term Incentive Plan Employee Restricted Stock Award Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2010, File No. 1- 10762.)
10.28	Form of 2010 Long Term Incentive Plan Stock Option Award Agreement. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2010, File No. 1-10762.)
10.29	Form of 2010 Long Term Incentive Plan Director Restricted Stock Award Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2010, File No. 1- 10762.)
10.30†	Employment Agreement dated January 1, 2009 between Harvest Natural Resources, Inc. and Karl L. Nesselrode.
10.31†	Employment Agreement dated January 1, 2009 between Harvest Natural Resources, Inc. and James A. Edmiston.
10.32†	Employment Agreement dated January 1, 2009 between Harvest Natural Resources, Inc. and Keith L. Head.
10.33†	Employment Agreement dated January 1, 2009 between Harvest Natural Resources, Inc. and Stephen C. Haynes.
10.34†	Employment Agreement dated May 31, 2008 between Harvest Natural Resources, Inc. and Robert Speirs.
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 24, 2012 between HNR Finance B.V. and Ryder Scott Company.
101.INS	XBRL Instance Document
101.SCH	XBRL Schema Document

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101.CAL	XBRL Calculation Linkbase Document
101.LAB	XBRL Label Linkbase Document
101.PRE	XBRL Presentation Linkbase Document
101.DEF	XBRL Definition Linkbase Document

^†  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.

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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, 2011 and December 31, 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 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, 2011, 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 inManagement’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits 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.

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/ PricewaterhouseCoopers LLP

Houston, Texas

March 15, 2012

S-1

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011			2010*
	(in thousands, except per share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	58,946		$	58,703
Restricted cash		1,200			—
Accounts and notes receivable, net
Oil and gas revenue receivable		—			1,907
Dividend receivable – equity affiliate		12,200			—
Joint interest and other		14,342			2,325
Note receivable		3,335			3,420
Advances to equity affiliate		2,388			1,706
Assets held for sale (See Note 4)		—			88,774
Deferred income taxes		2,628			—
Prepaid expenses and other		728			4,793
TOTAL CURRENT ASSETS		95,767			161,628
OTHER ASSETS		5,427			2,477
INVESTMENT IN EQUITY AFFILIATES		345,054			285,188
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		65,671			34,679
Other administrative property		3,176			3,209
TOTAL PROPERTY AND EQUIPMENT		68,847			37,888
Accumulated depreciation and amortization		(2,048	)		(1,682	)
TOTAL PROPERTY AND EQUIPMENT, NET		66,799			36,206
TOTAL ASSETS	$	513,047		$	485,499
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable, trade and other	$	7,381		$	3,205
Accounts payable – carry obligation		3,596			8,395
Accrued expenses		15,247			15,087
Liabilities held for sale (See Note 4)		—			663
Accrued interest		1,372			896
Deferred tax liability		4,835			—
Income taxes payable		718			72
TOTAL CURRENT LIABILITIES		33,149			28,318
OTHER LONG TERM LIABILITIES		908			1,834
LONG TERM DEBT		31,535			81,237
COMMITMENTS AND CONTINGENCIES (See Note 6)		—			—
EQUITY
STOCKHOLDERS’ EQUITY:
Preferred stock, par value $0.01 a share; authorized 5,000 shares; outstanding, none		—			—
Common stock, par value $0.01 a share; authorized 80,000 shares at December 31, 2011 (2010: 80,000 shares); issued 40,625 shares at December 31, 2011 (2010: 40,103 shares)		406			401
Additional paid-in capital		236,192			230,362
Retained earnings		193,283			139,389
Treasury stock, at cost, 6,521 shares at December 31, 2011 (2010: 6,475 shares)		(66,104	)		(65,543	)
TOTAL HARVEST STOCKHOLDERS’ EQUITY		363,777			304,609
NONCONTROLLING INTEREST		83,678			69,501
TOTAL EQUITY		447,455			374,110
TOTAL LIABILITIES AND EQUITY	$	513,047		$	485,499

* Certain amounts have been revised. See Note 2 – Summary of Significant Accounting Policies – Revision for additional information.

See accompanying notes to consolidated financial statements.

S-2

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2011			2010*			2009*
	(in thousands, except per share data)
Expenses
Depreciation and amortization		462			484			407
Exploration expense		13,690			8,016			7,757
Dry hole costs		49,676			—			—
General and administrative		22,474			25,903			22,422
		86,302			34,403			30,586
Loss from Operations		(86,302	)		(34,403	)		(30,586	)
Other Non-Operating Income (Expense)
Investment earnings and other		665			557			1,168
Interest expense		(5,336	)		(2,689	)		(5	)
Loss on extinguishment of debt		(9,682	)		—			—
Other non-operating expense		(1,375	)		(3,952	)		—
Foreign currency transaction loss		(146	)		(1,588	)		(83	)
		(15,874	)		(7,672	)		1,080
Loss from Consolidated Companies Continuing Operations Before Income Taxes		(102,176	)		(42,075	)		(29,506	)
Income Tax Expense (Benefit)		820			(184	)		1,313
Loss from Consolidated Companies Continuing Operations		(102,996	)		(41,891	)		(30,819	)
Net Income from Unconsolidated Equity Affiliates		73,451			66,291			35,253
Net Income (Loss) from Continuing Operations		(29,545	)		24,400			4,434
Discontinued Operations:
Income (loss) from discontinued operations		(2,636	)		3,712			(373	)
Gain on sale of assets		106,000			—			—
Income tax (expense) benefit on discontinued operations		(5,748	)		—			131
Income (loss) from discontinued operations		97,616			3,712			(242	)
Net Income		68,071			28,112			4,192
Less: Net Income Attributable to Noncontrolling Interest		14,177			12,670			7,702
Net Income (Loss) Attributable to Harvest	$	53,894		$	15,442		$	(3,510	)
Net Income (Loss) Attributable to Harvest Per Common Share:
(See Note 3 – Earnings Per Share):
Basic	$	1.58		$	0.46		$	(0.11	)
Diluted	$	1.37			0.42		$	(0.11	)

* Certain amounts have been revised. See Note 2 – Summary of Significant Accounting Policies – Revision for additional information.

See accompanying notes to consolidated financial statements.

S-3

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands)

	Common Shares Issued		Common Stock		Additional Paid-in Capital			Retained Earnings			Treasury Stock			Non- Controlling Interest		Total Equity
Balance at January 1, 2009*		39,128	$	391	$	208,868		$	127,457		$	(65,368	)	$	49,129	$	320,477
Issuance of common shares:
Exercise of stock options		205		2		384			—			—			—		386
Restricted stock awards		162		2		731			—			—			—		733
Employee stock-based compensation		—		—		3,354			—			—			—		3,354
Purchase of Treasury Shares		—		—		—			—			(15	)		—		(15	)
Net Income (Loss)		—		—		—			(3,510	)		—			7,702		4,192
Balance at December 31, 2009*		39,495		395		213,337			123,947			(65,383	)		56,831		329,127
Issuance of common shares:
Exercise of stock options		419		4		1,670			—			—			—		1,674
Restricted stock awards		189		2		1,837			—			—			—		1,839
Employee stock-based compensation		—		—		2,396			—			—			—		2,396
Discount on debt		—		—		11,122			—			—			—		11,122
Purchase of treasury shares		—		—		—			—			(160	)		—		(160	)
Net Income		—		—		—			15,442			—			12,670		28,112
Balance at December 31, 2010*		40,103		401		230,362			139,389			(65,543	)		69,501		374,110
Issuance of common shares:
Exercise of stock options		167		2		922			—			—			—		924
Restricted stock awards		273		2		2,028			—			—			—		2,030
Employee stock-based compensation		—		—		2,611			—			—			—		2,611
8.25% senior convertible notes		82		1		464			—			—			—		465
Discount on debt		—		—		(2,730	)		—			—			—		(2,730	)
Purchase of treasury shares		—		—		—			—			(561	)		—		(561	)
Tax benefits related to equity compensation		—		—		2,535			—			—			—		2,535
Net Income		—		—		—			53,894			—			14,177		68,071
Balance at December 31, 2011		40,625	$	406	$	236,192		$	193,283		$	(66,104	)	$	83,678	$	447,455

* Certain amounts have been revised. See Note 2 – Summary of Significant Accounting Policies – Revision for additional information.

See accompanying notes to consolidated financial statements.

S-4

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Years Ended December 31,
	2011			2010*			2009*
	(in thousands)
Cash Flows From Operating Activities:
Net income	$	68,071		$	28,112		$	4,192
Adjustments to reconcile net income to net cash used in operating activities:
Depletion, depreciation and amortization		1,272			3,817			436
Dry hole costs		40,467			—			—
Impairment of long-lived assets		4,707			—			—
Amortization of debt financing costs		975			793			—
Amortization of discount on debt		816			359			—
Write off of deferred financing costs		—			2,795			—
Gain on sale of assets		(106,225	)		—			—
Loss on early extinguishment of debt		7,533			—			—
Net income from unconsolidated equity affiliates		(73,451	)		(66,291	)		(35,253	)
Share-based compensation-related charges		4,642			4,234			4,087
Dividend received from equity affiliate		—			12,220			—
Deferred tax asset		(2,628	)		—			—
Deferred tax liability		4,835			—			—
Changes in operating assets and liabilities:
Accounts and notes receivable		(13,305	)		3,826			92
Advances to equity affiliate		(682	)		3,221			(1,195	)
Prepaid expenses and other		4,065			(2,579	)		(1,055	)
Accounts payable		(623	)		10,905			(966	)
Accrued expenses		7,475			(2,657	)		(6,629	)
Accrued interest		(400	)		(4,534	)		—
Other long term liabilities		(927	)		1,501			333
Income taxes payable		646			(1,018	)		1,013
Net Cash Used In Operating Activities		(52,737	)		(5,296	)		(34,945	)
Cash Flows from Investing Activities:
Proceeds from sale of assets		218,823			—			—
Additions of property and equipment		(74,468	)		(14,553	)		(4,265	)
Additions to assets held for sale		(33,930	)		(45,066	)		(23,757	)
Proceeds from sale of equity affiliates		1,385			—			—
Increase in restricted cash		(1,200	)		—			—
Investment costs		(900	)		558			(581	)
Net Cash Provided By (Used In) Investing Activities		109,710			(59,061	)		(28,603	)
Cash Flows from Financing Activities:
Net proceeds from issuances of common stock		924			1,674			386
Tax benefits related to equity compensation		2,535			—			—
Proceeds from issuance of long-term debt		—			92,000			—
Payments of long-term debt		(60,000	)		—			—
Financing costs		(189	)		(2,931	)		(1,686	)
Net Cash Provided By (Used In) Financing Activities		(56,730	)		90,743			(1,300	)
Net Increase (Decrease) in Cash and Cash Equivalents		243			26,386			(64,848	)
Cash and Cash Equivalents at Beginning of Year		58,703			32,317			97,165
Cash and Cash Equivalents at End of Year	$	58,946		$	58,703		$	32,317
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for interest expense (net of capitalization)	$	2,685		$	1,380		$	5
Cash paid during the year for income taxes	$	8,241		$	834		$	169

* Certain amounts have been revised. See Note 2 – Summary of Significant Accounting Policies – Revision for additional information.

See accompanying notes to consolidated financial statements.

S-5

Supplemental Schedule of Noncash Investing and Financing Activities:

During the year ended December 31, 2011, we issued 0.2 million shares of restricted stock valued at $2.0 million. Also, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 45,532 shares being added to treasury stock at cost.

During the year ended December 31, 2010, we issued 0.3 million shares of restricted stock valued at $1.8 million. Also some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis, which resulted in 26,260 shares being added to treasury stock at cost; and 1,000 shares held in treasury that had been reissued as restricted stock were forfeited and returned to treasury.

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.

See accompanying notes to consolidated financial statements.

S-6

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Note 1 - Organization

Harvest Natural Resources, Inc. (“Harvest”) is an independent energy company engaged in the acquisition, exploration, development, production and disposition of oil and natural gas properties since 1989, when it was incorporated under Delaware law.

We have significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through HNR Finance, B.V. (“HNR Finance”). Our ownership of HNR Finance is through several corporations in all of which we have direct controlling interests. Through these corporations, we indirectly own 80 percent of HNR Finance and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining 20 percent interest in HNR Finance. HNR Finance owns 40 percent of Petrodelta, S.A. (“Petrodelta”). As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta, and Vinccler indirectly owns eight percent. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. HNR Finance also has a direct controlling interest in Harvest Vinccler S.C.A. (“Harvest Vinccler”). Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with Petroleos de Venezuela S.A. (“PDVSA”). We do not have a business relationship with Vinccler outside of Venezuela.

In addition to our interests in Venezuela, we have exploration acreage 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”). See Note 13 – Indonesia, Note 14 – Gabon, Note 15 – Oman and Note 16 – China.

Note 2 - Summary of Significant Accounting Policies

Revision to Prior Period Financial Statements

We are revising our historical financial statements for the year ended December 31, 2010 and quarterly information for the quarters ended March 31, 2010, June 30, 2010, September 30, 2010, December 31, 2010, March 31, 2011, June 30, 2011 and September 30, 2011 (see Item 15. Exhibits and Financial Statement Schedules, Quarterly Financial Data (unaudited)). The revisions relate to the correction of an error in the deferred tax adjustment to reconcile our share of Petrodelta’s net income reported under International Financial Reporting Standards (“IFRS”) to that required under accounting principles generally accepted in the United States of America (“USGAAP”) and recorded within Net income from unconsolidated equity affiliates. Previously, Petrodelta had an incorrect tax basis associated with its asset retirement cost which caused us to overstate or understate the deferred tax expense associated with this temporary difference for USGAAP purposes. We have revised the tax basis to record the correct deferred tax expense in each reporting period. The error has no impact to the consolidated statements of cash flows.

We have determined that the impact of this error is not material to the previously issued annual and interim financial statements as defined by Accounting Standards Codification (“ASC”) 250 – Accounting Changes and Error Corrections (“ASC 250 “). The audited financial statements, related notes and analyses for the years ended December 31, 2011, 2010 and 2009 have been retrospectively revised in this Annual Report on Form 10-K for the year ended December 31, 2011. All future filings, including interim financial statements, will be revised appropriately.

The following tables set forth the effect of the adjustments described above on the consolidated statement of operations for the years ended December 31, 2010 and 2009 and the consolidated balance sheet as of December 31, 2010. There was no impact on net cash used in operating activities in the consolidated statements of cash flows.

S-7

Consolidated Statements of Operations

	December 31, 2010									December 31, 2009
	As Previously Reported			Adjustment			As Revised			As Previously Reported			Adjustment			As Revised
Loss from Consolidated Companies Continuing Operations	$	(41,891	)	$	—		$	(41,891	)	$	(30,688	)	$	—		$	(30,688	)
Net Income from Unconsolidated Equity Affiliates		66,164			127			66,291			35,757			(504	)		35,253
Net Income from Continuing Operations		24,273			127			24,400			5,069			(504	)		4,565
Income (Loss) from Discontinued Operations		3,712			—			3,712			(373	)		—			(373	)
Net Income		27,985			127			28,112			4,696			(504	)		4,192
Less: Net Income Attributable To Noncontrolling Interest		12,645			25			12,670			7,803			(101	)		7,702
Net Income (Loss) Attributable To Harvest	$	15,340		$	102		$	15,442		$	(3,107	)	$	(403	)	$	(3,510	)
Net Income (Loss) Attributable to Harvest Per Common Share:
Basic	$	0.46		$	—		$	0.46		$	(0.09	)	$	(0.02	)	$	(0.11	)
Diluted	$	0.43		$	(0.01	)	$	0.42		$	(0.09	)	$	(0.02	)	$	(0.11	)

Consolidated Balance Sheets

	December 31, 2010
	As Previously Reported		Adjustment			As Revised
	(in thousands)
Investment in equity affiliates	$	287,933	$	(2,745	)	$	285,188
Total assets		488,244		(2,745	)		485,499
Retained earnings		141,584		(2,195	)		139,389
Total Harvest shareholders’ equity		306,804		(2,195	)		304,609
Noncontrolling Interest		70,051		(550	)		69,501
Total liabilities and shareholders’ equity		488,244		(2,745	)		485,499

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.

Reporting and Functional Currency

The United States Dollar (“U.S. Dollar”) is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. Amounts denominated in non-U.S. Dollar currencies are re-measured into U.S. Dollars, and all currency gains or losses are recorded in the consolidated statement of operations. We attempt to manage our operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and the resulting exchange gains and losses, many of which are beyond our influence.

See Note 10 – Venezuela for a discussion of currency exchange risk on Harvest Vinccler’s and Petrodelta’s businesses.

S-8

Cash and Cash Equivalents

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

Restricted Cash

Restricted cash is classified as current or non-current based on the terms of the agreement. Restricted cash at December 31, 2011 represents cash held in a U.S. bank used as collateral for a standby letter of credit issued as a payment guarantee for electric wireline services to be provided during the drilling of the two exploratory wells on the Oman Exploration and Production Sharing Agreement Al Ghubar / Qarn Alam license (“Block 64 EPSA”) (see Note 15 – Oman).

Financial Instruments

Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents, accounts receivable and notes payable. Cash and cash equivalents are placed with commercial banks with high credit ratings. This diversified investment policy limits our exposure both to credit risk and to concentrations of credit risk.

Total long-term debt at December 31, 2011 consisted of $31.5 million of fixed-rate unsecured senior convertible notes maturing on March 1, 2013 unless earlier redeemed, purchased or converted. Total long-term debt at December 31, 2010 consisted of $32 million of fixed-rate unsecured senior convertible notes maturing in 2013 unless earlier redeemed, purchased or converted and $60 million of fixed-rate unsecured term loan facility, which was repaid in May 2012. See Note 5 – Long-Term Debt.

Accounts and Notes Receivable

Notes receivable bear interest and can have due dates that are less than one year or more than one year. Amounts outstanding under the notes bear interest at a rate based on the current prime rate and are recorded at face value. Interest is recognized over the life of the note. We may or may not require collateral for the notes.

Each note is analyzed to determine if it is impaired pursuant to Accounting Standards Updates (“ASU”) 2010-20. A note is impaired if it is probable that we will not collect all principal and interest contractually due. We do not accrue interest when a note is considered impaired. All cash receipts on impaired notes are applied to reduce the accrued interest on the note until the interest is made current and, thereafter, applied to reduce the principal amount of such notes.

At December 31, 2011 and 2010, our note receivable relates to a prospect leasing cost financing arrangement. The note receivable plus accrued interest was approximately $3.3 million at December 31, 2011 (2010: $3.4 million), and was secured by a portion of the production from the Bar F #1-20-3-2 in Utah. With the sale of our oil and gas assets in Utah’s Uinta Basin (“Antelope Project”) effective March 1, 2011, the note receivable plus accrued interest will be settled upon finalization of certain terms of the Joint Exploration and Development Agreement (“JEDA”) which defined the participating parties’ obligations over our Antelope Project. See Note 4 – Dispositions and Note 6 – Commitments and Contingencies.

Other Assets

Other assets consist of investigative costs associated with new business development projects, deferred financing costs and a long-term receivable for value added tax (“VAT”) credits related to the Budong PSC. Investigative costs are reclassified to oil and gas properties or expensed depending on management’s assessment of the likely outcome of the project. Deferred financing costs relate to specific financing and are amortized over the life of the financing to which the costs relate. See Note 5 – Long-Term Debt.

At December 31, 2011, other assets consisted of $0.4 million of investigative costs, $1.0 million of deferred financing costs and $3.3 million of long-term VAT receivable. During the year ended December 31, 2011, $0.1 million of investigative costs were reclassified to expense. At December 31, 2010, other assets consisted of $0.3 million of investigative costs and $2.2 million of deferred financing costs. During the year ended December 31, 2010, $2.9 million of costs related to a future financing which we ceased to pursue and $0.5 million of investigative costs were reclassified to expense.

S-9

Other Assets at December 31, 2011 also includes a blocked payment of $0.7 million net to our 66.667 percent interest related to our drilling operations in Gabon in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”). See Note 6 – Commitments and Contingencies.

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 (ASC 323). Investment in Equity Affiliates is increased by additional investments and earnings and decreased by dividends and losses. We review our Investment in Equity Affiliates for impairment whenever events and circumstances indicate a decline in the recoverability of its carrying value.

There are many factors to consider when evaluating an equity investment for possible impairment. Currency devaluations, inflationary economies and cash flow analysis are some of the factors we consider in our evaluation for possible impairment. At December 31, 2011 and December 31, 2010, there were no events that caused us to evaluate our investment in equity affiliates for impairment.

Oil and Gas Properties

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

	2011			2010
Unproved property costs	$	62,842		$	29,279
Oilfield inventories		2,829			5,400
Other administrative property		3,176			3,209
		68,847			37,888
Accumulated depletion, impairment and depreciation		(2,048	)		(1,682	)
	$	66,799		$	36,206

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 proved reserves, as that term is defined in Securities and Exchange Commission (“SEC”) regulations, have not been discovered, capitalized costs associated with the drilling of the exploratory well are charged to expense. Costs of drilling successful exploratory wells, all development wells, and related production equipment and facilities are capitalized and depleted or depreciated using the unit-of-production method as oil and gas is produced. At December 31, 2011, we expensed to dry hole costs $14.0 million related to the drilling of the Lariang-1 (“LG-1”) on the Budong-Budong Production Sharing Contract (“Budong PSC”), $26.0 million related to the drilling of the Karama-1 (“KD-1”) and first sidetrack, the KD-1ST on the Budong PSC, $6.9 million related to the drilling of the Mafraq South-A (“MFS-1”) on the Exploration and Production Sharing Agreement (“EPSA”) for the Al Ghubar/Qarn Alam License (“Block 64 EPSA”) and $2.8 million related to the drilling of the Al Ghubar North-A (“AGN-1”) on the Block 64 EPSA (see Note 13 – Indonesia and Note 15 – Oman.) Total drilling costs for the AGN-1 are estimated to be approximately $7.6 million. Drilling costs incurred after December 31, 2011 will be expensed to dry hole costs in the first quarter of 2012.

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Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period. 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 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 2011, 2010 or 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 depleted 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-of-production method 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, excluding oilfield inventories, consist of (in millions):

	2011		2010
Budong PSC	$	6.6	$	9.5
Dussafu Marin Permit (“Dussafu PSC”)		47.9		9.2
Block 64 EPSA		5.1		4.2
WAB-21		3.2		3.1
West Bay		—		3.3
	$	62.8	$	29.3

Other Administrative Property

Furniture, fixtures and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which ranges from three to five years. Leasehold improvements are recorded at cost and amortized using the straight-line method over the life of the applicable lease. For the year ended December 31, 2011, depreciation expense was $0.5 million (2010: $0.5 million, 2009: $0.4 million).

Reserves

We adopted the SEC’s Modernization of Oil and Gas Reporting and the Financial Accounting Standards Board’s (“FASB”) guidance on extractive activities for oil and gas (ASC 932) as of December 31, 2009.

Capitalized Interest

We capitalize interest costs for qualifying oil and gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation. During the year ended December 31, 2011, we capitalized interest costs for qualifying oil and gas property additions of $2.3 million (2010: $1.8 million).

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Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

At December 31, 2011, cash and cash equivalents include $51.4 million (2010: $51.0 million) in a money market fund comprised of high quality, short term investments with minimal credit risk which are reported at fair value. The fair value measurement of these securities is based on quoted prices in active markets (level 1 input) for identical assets. The estimated fair value of our senior convertible notes based on observable market information (level 2 input) as of December 31, 2011 is $39.2 million (2010: $61.7 million). The estimated fair value of our term loan facility based on internally developed discounted cash flow model and inputs based on management’s best estimates (level 3 input) for identical liabilities as of December 31, 2010 was $49.2 million.

Our current assets and liabilities accounts include financial instruments, the most significant of which are accounts receivables and trade payables. We believe the carrying values of our current assets and liabilities approximate fair value with the exception of the note receivable. Because this note receivable is not publicly-traded and not easily transferable, the estimated fair value of our note receivable is based on the market approach and time value of money which approximates the note receivable book value of $3.3 million at December 31, 2011 (2010: $3.4 million). The majority of inputs used in the fair value calculation of the note receivable are Level 3 inputs and are consistent with the information used in determining impairment of the note receivable.

The following is a reconciliation of the net beginning and ending balances recorded for financial assets and liabilities classified as Level 3 in the fair value hierarchy.

	December 31, 2011			December 31, 2010
	(in thousands)
Financial assets:
Beginning balance	$	3,420		$	3,265
Issuances		—			200
Accrued interest		200			398
Payments		(285	)		(443	)
Ending balance	$	3,335		$	3,420
Financial liabilities:
Beginning balance	$	49,237		$	—
Debt issuance		—			60,000
Discount on debt		—			(11,122	)
Amortization of discount on debt		10,763			359
Payments		(60,000	)		—
Ending balance	$	—		$	49,237

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Asset Retirement Liability

ASC 410, “Asset Retirement and Environmental Obligations” (“ASC 410”) requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. No wells were abandoned during the years ended December 31, 2011 or 2010. Changes in asset retirement obligations during the years ended December 31, 2011 and 2010 were as follows:

	December 31, 2011			December 31, 2010
	(in thousands)
Asset retirement obligations beginning of period	$	663		$	50
Liabilities recorded during the period		52			382
Liabilities settled during the period		—			—
Revisions in estimated cash flows		(120	)		197
Accretion expense		4			34
Reclassify to gain on sale of assets		(599	)		—
Asset retirement obligations end of period	$	—		$	663

Share-Based Compensation

We use a fair value-based method of accounting for stock-based compensation. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and stock appreciation rights (“SARs”). Restricted stock and restricted stock units (“RSUs”) are measured at their intrinsic values. See Note 8 – Stock-Based Compensations and Stock Purchase Plans.

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.

We do not provide deferred income taxes on undistributed earnings of our foreign subsidiaries for possible future remittances as all such earnings are reinvested as port of our ongoing business.

Noncontrolling Interests

We adopted the accounting standard for noncontrolling interests in consolidated financial statements (ASC 810) as of January 1, 2009. Our noncontrolling interest relates to Vinccler’s indirectly owned 20 percent interest in HNR Finance (see Note 1 – Organization).

Liquidity

The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. There are a number of variables and risks related to our exploration projects and our minority equity investment in Petrodelta that could significantly utilize our cash balances, affect our capital resources and liquidity. We also point out that the total capital required to develop the fields in Venezuela may exceed Petrodelta’s available cash and financing capabilities, and that there may be operational or contractual consequences due to this inability.

Our cash is being used to fund oil and gas exploration projects and to a lesser extent general and administrative costs. We require capital principally to fund the exploration and development of new oil and gas properties. As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. Currently, we have a minimum work obligation to reprocess 375 square kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup during the Initial Term of the EPSA. The parties to the EPSA acknowledge that $22.0 million is indicative of the costs needed to complete the work program during the three-year initial period which expires in May 2013. Through December 31, 2011, we have incurred $16.2 million of the minimum work obligation. As of February 29, 2012, we have expended more than $22.0 million and completed the minimum work obligations. The remaining work commitment for the current exploration phase on the Budong PSC is for geological and geophysical work to be completed in the year 2012 at a minimum of $0.5 million ($0.3 million net to our 64.51 percent cost sharing interest). We do not have any remaining work commitments for the current

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exploration phase of the Dussafu PSC, but as of May 28, 2012, the Dussafu PSC enters the third exploration phase. If the partners elect to enter the third exploration phase, there will be a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a two-year period.

Our primary ongoing source of cash is still dividends from Petrodelta. In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, as of March 7, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain. We expect to receive future dividends from Petrodelta; however, we expect that in the near term Petrodelta will reinvest most of its earnings into the company in support of its drilling and appraisal activities. Therefore, there is uncertainty that Petrodelta will pay additional dividends in 2012 or 2013.

Additionally, any dividend received from Petrodelta carries a liability to our non-controlling interest holder, Vinccler, for its 20 percent share. Dividends declared and paid by Petrodelta are paid to HNR Finance, our consolidated subsidiary. HNR Finance must declare a dividend in order for us and our non-controlling interest holder, Vinccler, to receive our respective shares of Petrodelta’s dividends. A dividend from HNR Finance is due upon demand. As of March 7, 2012, Vinccler’s share of the undistributed dividends is $9.0 million inclusive of the unpaid November 2010 dividend. See Note 17 – Related Party Transactions.

We incurred debt during 2010 which has imposed restrictions on us and increased our vulnerability to adverse economic and industry conditions. Our semi-annual interest expense has increased significantly, and our senior convertible notes impose restrictions on us that limit our ability to obtain additional financing. Our ability to meet these covenants is primarily dependent on meeting customary affirmative covenant clauses. Our inability to satisfy the covenants contained in our senior convertible notes would constitute an event of default, if not waived. An uncured default could result in the senior convertible notes becoming immediately due and payable. If this were to occur, we may not be able to obtain waivers or secure alternative financing to satisfy our obligations, either of which would have a material adverse impact on our business. As of December 31, 2011, we were in compliance with all of our long term debt covenants.

At December 31, 2011, we had cash on hand of $58.9 million. We believe that this cash plus cash generated from Petrodelta dividends and funding from debt or equity financing combined with our ability to vary the timing of our capital expenditures is sufficient to fund our operations and capital commitments through at least December 31, 2012. Our 8.25 percent senior convertible notes are due March 1, 2013. We expect some, if not all, debt holders will convert their debt into shares of our common stock on or before the March 1, 2013 due date. However, if the debt is not converted or is only partially converted, we believe that Petrodelta dividends and funding from debt or equity financing combined with our ability to vary the timing of our capital expenditures will be sufficient to repay the outstanding debt at March 1, 2013. However, if the Petrodelta dividend payment is not received or our cash sources and requirements are different than expected, it could have a material adverse effect on our operations.

In order to increase our liquidity to levels sufficient to meet our commitments, we are currently pursuing a number of actions including our ability to delay discretionary capital spending to future periods, possible farm-out or sale of assets, or other monetization of assets as necessary to maintain the liquidity required to run our operations. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, and cost reductions. However, there is no assurance that our plans will be successful. Although we believe that we will have adequate liquidity to meet our near term operating requirements and to remain compliant with the covenants under our long term debt arrangements, the factors described above create uncertainty. Our lack of cash flow and the unpredictability of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance adequate financing can be raised. Accordingly, there can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.

New Accounting Pronouncements

In April 2011, the FASB issued ASU No. 2011-04, which is included in ASC 820, “Fair Value Measurement” (“ASC 820”). This update explains how to measure fair value. It does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of

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financial reporting. ASU No. 2011-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption is not permitted. The adoption of ASU No. 2011-04 will not have a material impact on our consolidated financial position, results of operation or cash flows.

In June 2011, the FASB issued ASU No. 2011-05, which is included in ASC 220, “Comprehensive Income” (“ASC 220”). This update requires that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and will be applied retrospectively. Early adoption is permitted. The adoption of ASU No. 2011-05 will impact the presentation of our results of operations.

In September 2011, the FASB issued ASU No. 2011-08, which is included in ASC 350, “Intangibles – Goodwill and Other” (“ASC 350”). The objective of this update is to simplify how entities, both public and nonpublic, test goodwill for impairment. This update permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in ASC 350. ASU No. 2011-08 is effective for annual and interim fiscal years beginning after December 15, 2011. Early adoption is permitted. The adoption of ASU No. 2011-08 will not have a material impact on our consolidated financial position, results of operation or cash flows.

In December 2011, The FASB issued ASU No. 2011-11, which is included in ASC 210, “Balance Sheet” (ASC 210”). The amendments in ASU No. 2011-11 require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of these arrangements on its financial position. An entity is required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. ASU No. 2011-11 will be applied retrospectively. The adoption of ASU No. 2011-08 will not have a material impact on our consolidated financial position, results of operation or cash flows.

In December 2011, the FASB issued ASU No. 2011-12, which is included in ASC 220. ASU No. 2011-12 defers those changes in ASU 2011-05 that pertain to how, when, and where reclassification adjustments are presented. All other requirements of ASU No. 2011-05 are not affected by ASU No. 2011-12. ASU No. 2011-12 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and will be applied retrospectively. Early adoption is permitted. The adoption of ASU No. 2011-12 will not impact the presentation of our results of operations.

Use of Estimates

The preparation of financial statements in conformity with USGAAP requires management t