Harvest Natural Resources 10Q 2009 Q2 Quarterly report

Harvest Natural Resources (HNR) 10-Q2009 Q2 Quarterly report

Content analysis

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


þ		Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Quarterly Period Ended June 30, 2009 or


o		Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934


		for the transition period from to

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)		(IRS Employer Identification No.)

1177 Enclave Parkway, Suite 300
Houston, Texas		77077
(Address of Principal Executive Offices)		(Zip Code)

(281) 899-5700
(Registrant’s Telephone Number, Including Area Code)

Not Applicable
(Former name, former address and former fiscal year, if changed since last report)

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

Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yeso Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yeso Noþ

At July 31, 2009, 33,170,205 shares of the Registrant’s Common Stock were outstanding.

HARVEST NATURAL RESOURCES, INC.

FORM 10-Q

TABLE OF CONTENTS


	Page
PART I FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS
Unaudited Consolidated Balance Sheets at June 30, 2009 and December 31, 2008		3
Unaudited Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2009 and 2008		4
Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008		5
Notes to Consolidated Financial Statements		6

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		17

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		25

Item 4. CONTROLS AND PROCEDURES		25

PART II OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS		26

Item 1A. RISK FACTORS		26

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		27

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		27

Item 6. EXHIBITS		27

Signatures		29
EX-10.1
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,			December 31,
	2009			2008
	(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	64,391		$	97,165
Accounts and notes receivable, net		11,029			11,570
Advances to equity affiliate		4,207			3,732
Prepaid expenses and other		2,937			3,964

TOTAL CURRENT ASSETS		82,564			116,431

OTHER ASSETS		3,401			3,316
INVESTMENT IN EQUITY AFFILIATES		210,118			218,982
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		38,366			22,328
Other administrative property		2,648			2,368

		41,014			24,696
Accumulated depreciation and amortization		(1,108	)		(1,159	)

		39,906			23,537

	$	335,989		$	362,266


LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable, trade and other	$	689		$	1,662
Advance from equity affiliate		—			20,750
Accrued expenses		10,960			12,241
Accrued interest		4,691			4,691
Income taxes payable		1,054			77

TOTAL CURRENT LIABILITIES		17,394			39,421

COMMITMENTS AND CONTINGENCIES		—			—

EQUITY
STOCKHOLDERS’ EQUITY:
Preferred stock, par value $0.01 a share; authorized 5,000 shares; outstanding, none		—			—
Common stock, par value $0.01 a share; authorized 80,000 shares at June 30, 2009 and December 31, 2008, respectively; issued 39,285 shares and 39,128 shares at June 30, 2009 and December 31, 2008, respectively		393			391
Additional paid-in capital		211,187			208,868
Retained earnings		120,386			129,351
Treasury stock, at cost, 6,447 shares and 6,444 shares at June 30, 2009 and December 31, 2008, respectively		(65,374	)		(65,368	)

TOTAL HARVEST STOCKHOLDERS’ EQUITY		266,592			273,242
NONCONTROLLING INTEREST		52,003			49,603

TOTAL EQUITY		318,595			322,845

	$	335,989		$	362,266

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(in thousands, except per share data)
EXPENSES
Depreciation	$	88		$	47		$	157		$	92
Exploration expense		3,456			2,866			4,428			4,215
General and administrative		6,432			6,422			12,899			12,634
Taxes other than on income		241			195			558			458

		10,217			9,530			18,042			17,399


LOSS FROM OPERATIONS		(10,217	)		(9,530	)		(18,042	)		(17,399	)

OTHER NON-OPERATING INCOME (EXPENSE)
Gain on financing transactions		—			2,091			—			3,421
Investment earnings and other		296			751			627			1,882
Interest expense		—			(1,260	)		—			(1,719	)

		296			1,582			627			3,584


LOSS FROM CONSOLIDATED COMPANIES BEFORE INCOME TAXES		(9,921	)		(7,948	)		(17,415	)		(13,815	)

INCOME TAX EXPENSE		147			37			1,036			101

LOSS FROM CONSOLIDATED COMPANIES		(10,068	)		(7,985	)		(18,451	)		(13,916	)

NET INCOME FROM UNCONSOLIDATED EQUITY AFFILIATES		7,476			9,409			11,886			18,218


NET INCOME (LOSS)		(2,592	)		1,424			(6,565	)		4,302

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		1,597			2,057			2,400			3,730


NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST	$	(4,189	)	$	(633	)	$	(8,965	)	$	572


NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	(0.13	)	$	(0.02	)	$	(0.27	)	$	0.02

Diluted	$	(0.13	)	$	(0.02	)	$	(0.27	)	$	0.02

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended June 30,
	2009			2008
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	(6,565	)	$	4,302
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation		157			92
Gain on financing transactions		—			(3,421	)
Net income from unconsolidated equity affiliate		(11,886	)		(18,218	)
Non-cash compensation-related charges		2,120			2,578
Dividends from unconsolidated equity affiliate		—			72,530
Changes in operating assets and liabilities:
Accounts and notes receivable		541			(278	)
Advances to equity affiliate		(475	)		13,775
Prepaid expenses and other		(1,780	)		(3,173	)
Accounts payable		(973	)		(3,879	)
Accounts payable, related party		—			185
Accrued expenses		(1,963	)		122
Accrued interest		—			(53	)
Income taxes payable		977			(258	)

NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(19,847	)		64,304


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions of property and equipment		(11,341	)		(11,217	)
Decrease in restricted cash		—			3,244
Investment costs		(310	)		(1,153	)

NET CASH USED IN INVESTING ACTIVITIES		(11,651	)		(9,126	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuances of common stock		201			1,310
Purchase of treasury stock		—			(17,207	)
Payments of notes payable		—			(2,560	)
Financing costs		(1,477	)		—
Dividends paid to noncontrolling interest		—			(358	)

NET CASH USED IN FINANCING ACTIVITIES		(1,276	)		(18,815	)


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(32,774	)		36,363

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		97,165			120,841

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	64,391		$	157,204

Supplemental Schedule of Noncash Investing and Financing Activities:

During the six months ended June 30, 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 2,937 shares being added to treasury stock at cost.

During the six months ended June 30, 2008, 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 12,582 shares being added to treasury stock at cost. In addition, 106,000 shares held in treasury were reissued as restricted stock.

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2009 and 2008 (unaudited)

Note 1 — Organization and Summary of Significant Accounting Policies

Interim Reporting

In our opinion, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position as of June 30, 2009, and the results of operations for the three and six months ended June 30, 2009 and 2008, and cash flows for the six months ended June 30, 2009 and 2008. The unaudited consolidated financial statements are presented in accordance with the requirements of Form 10-Q and do not include all disclosures normally required by accounting principles generally accepted in the United States of America (“GAAP”). Reference should be made to our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2008, which include certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year.

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”) through our ownership in Petrodelta, S.A. (“Petrodelta”). HNR Finance B.V. (“HNR Finance”) has a 40 percent ownership interest in Petrodelta. As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta, and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining eight percent equity interest. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petrodelta is governed by its own charter and bylaws. We have exploration acreage in the Gulf Coast Region of the United States, the Antelope project in the Western United States, offshore of the People’s Republic of China (“China”), mainly onshore West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), and in the Sultanate of Oman (“Oman”). SeeNote 6 — United States Operations, Note 7 — Indonesia,Note 8 — GabonandNote 9 — Oman.

Principles of Consolidation

The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. The equity method of accounting is used for companies in which we have significant influence. All intercompany profits, transactions and balances have been eliminated.

Investment in Equity Affiliates

Investments in unconsolidated companies in which we have less than a 50 percent interest and have significant influence are accounted for under the equity method of accounting. Investment in equity affiliates is increased by additional investments and earnings and decreased by dividends and losses. We review our Investment in equity affiliates for impairment under Accounting Principles Board (“APB”) Opinion 18 — The Equity Method of Accounting for Investments in Common Stock (“APB 18”) whenever events and circumstances indicate a decline in the recoverability of its carrying value.

Fair Value Measurements

We adopted Statement of Financial Accounting Standard (“SFAS”) No. 157 — Fair Value Measurements (“SFAS 157”) for financial assets as of January 1, 2008. We adopted SFAS 157 for non-financial assets and liabilities as of January 1, 2009. SFAS 157 provides guidance for using fair value to measure assets and liabilities. SFAS 157 clarifies the principle that fair value should be based on the assumptions that market participants would

use when pricing the asset or liability. SFAS 157 establishes a fair value hierarchy, giving the highest priority to quoted prices in active markets and the lowest priority to unobservable data. SFAS 157 applies whenever other standards require assets or liabilities to be measured at fair value. The adoption of SFAS 157 had no impact on our consolidated financial position, results of operations or cash flows.

At June 30, 2009 and December 31, 2008, cash and cash equivalents include $55.2 million and $88.6 million, respectively, in a money market fund comprised of high quality, short term investments with minimal credit risk which are reported at fair value. The fair value measurement of these securities is based on quoted prices in active markets for identical assets which are defined as “Level 1” of the fair value hierarchy based on the criteria in SFAS No. 157.

Property and Equipment

Our accounting method for oil and gas exploration and development activities is the successful efforts method. We have $38.4 million and $22.3 million in oil and gas properties as of June 30, 2009 and December 31, 2008, respectively, all of which is unproved property. During the three and six months ended June 30, 2009, we incurred $2.4 million and $2.8 million, respectively, of exploration costs related to the processing and reprocessing of seismic data for our foreign operations, and $1.1 million and $1.6 million, respectively, related to other general business development activities. In addition, we reclassified $2.8 million of lease bonus associated with our Antelope project from Prepaid expenses and other to Oil and gas properties and $1.4 million of Oman acquisition costs from Other assets to Oil and gas properties. SeeNote 6 — United States OperationsandNote 9 — Oman.

Noncontrolling Interests

We adopted SFAS 160 — Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51 (“SFAS 160”) as of January 1, 2009. SFAS 160 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owner. The adoption of SFAS 160 impacted the presentation of our consolidated financial position, results of operations and cash flows.

Earnings Per Share

Basic earnings per common share (“EPS”) are computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. The weighted average number of common shares outstanding for computing basic EPS was 33.0 million for the three and six months ended June 30, 2009, respectively, and 34.7 million and 34.9 million for the three and six months ended June 30, 2008, respectively. Diluted EPS reflects the potential dilution that would occur if securities or other contracts to issue common stock were exercised or converted into common stock. The weighted average number of common shares outstanding for computing diluted EPS, including dilutive stock options, was 33.0 million for the three and six months ended June 30, 2009, respectively, and 34.7 million and 36.1 million for the three and six months ended June 30, 2008, respectively.

An aggregate of 3.3 million options to purchase common stock were excluded from the earnings per share calculations because their exercise price exceeded the average stock price for the three and six months ended June 30, 2009, respectively. An aggregate of 0.8 million options to purchase common stock were excluded from the earnings per share calculations because their exercise price exceeded the average stock price for the three and six months ended June 30, 2008, respectively.

Stock options to purchase 0.1 million shares of common stock were exercised in the six months ended June 30, 2009 resulting in cash proceeds of $0.2 million. Stock options to purchase 0.4 million shares of common stock were exercised in the six months ended June 30, 2008 resulting in cash proceeds of $1.3 million.

In June 2009, stock options to purchase 0.1 millions shares of common stock, 0.1 million shares of restricted stock, 0.3 million stock appreciation rights (“SARs”) and 0.3 million phantom restricted stock units

(“RSUs”) were granted to some of our employees and 0.1 million shares of restricted stock were granted to non- employee directors. The stock options vest ratably over a three year period from date of grant and expire seven years from grant date. The restricted stock granted to employees is subject to a restriction period of not less than 36 months during which the stock will be deposited with Harvest and is subject to forfeiture under certain circumstances. Restricted stock granted to non-employee directors vests as to one-third of the shares on each anniversary of the date of grant of the award provided that he is still a director on that date. The SARs vest ratably over a three year period beginning in 2012 and expire seven years from grant date. The RSUs vest as to one-third of the shares on each anniversary of the date of grant of the award beginning in 2012 provided that the employee is still an employee on that date. Payments under the SAR and RSU agreements will be in cash.

New Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (“FASB”) issued SFAS 165 — Subsequent Events (“SFAS 165”) which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. SFAS 165 is effective for interim or annual periods ending after June 15, 2009. We adopted SFAS 165 effective June 15, 2009. The adoption of SFAS 165 did not have a material effect on our consolidated financial position, results of operations or cash flows. SeeNote 10 — Subsequent Events.

In June 2009, the FASB issued SFAS 166 — Accounting for Transfers of Financial Assets — an amendment of SFAS No. 140 (“SFAS 166”). The objective in issuing SFAS 166 is to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. SFAS 166 is effective for annual periods beginning after November 15, 2009. The adoption of SFAS 166 is not expected to have a material impact on our consolidated financial position, results of operations or cash flows.

In June 2009, the FASB issued SFAS 167 — Amendments to Financial Interpretation No. 46(R) (“SFAS 167”). The objective in issuing SFAS 167 is to improve financial reporting by enterprises involved with variable interest entities. SFAS 167 is effective for annual periods beginning after November 15, 2009. Management is still assessing the impact, if any, that SFAS 167 will have on our consolidated financial position, results of operations and cash flows.

In June 2009, the FASB issued SFAS 168 — The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162 (“SFAS 168”). SFAS 168 will become the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of SFAS 168, SFAS 168 will supersede all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in SFAS 168 will become nonauthoritative. SFAS 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of SFAS 168 will not have an impact on our consolidated financial position, results of operations or cash flows.

Reclassifications

Certain items in 2008 have been reclassified to conform to the 2009 financial statement presentation.

Note 2 — Commitments and Contingencies

Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-Vinccler, C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, Texas. This suit was brought in May 2003 by Excel alleging, among other things, breach of a consulting agreement between Excel and us, misappropriation of proprietary information and trade secrets, and fraud. Excel seeks actual and exemplary damages, injunctive relief and attorneys’ fees. In April 2007, the Court set the case for trial. The trial date, reset for the first quarter of 2009, has been stayed indefinitely. We dispute Excel’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.

Uracoa Municipality Tax Assessments. Our Venezuelan subsidiary, Harvest Vinccler, S.C.A. (“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 Petroleos de Venezuela, S.A. (“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.

	•		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.

In June 2007, the SENIAT issued an assessment for taxes in the amount of $0.4 million for Harvest Vinccler’s failure to withhold VAT from vendors during 2005. Also, the SENIAT imposed penalties and interest in the amount of $1.3 million for Harvest Vinccler’s failure to withhold VAT. In July 2008, the SENIAT adjusted the assessment for penalties and interest to the change in tax units as mandated by the Venezuelan tax code and issued a new assessment for $2.3 million. The change in assessment resulted in an additional $1.0 million expense recorded in the year ended December 31, 2008. A tax court has ruled against the SENIAT stating that penalties and interest cannot be calculated on tax units. The case is currently pending a decision in the Venezuelan Supreme Court. The SENIAT has recognized a payment made by Harvest Vinccler in 2006 for the underwithheld VAT and has partially confirmed that some of the affected vendors have remitted the underwithheld VAT. Harvest Vinccler has received credit, less penalties and interest, from the SENIAT for the VAT remitted by the vendors. Harvest Vinccler has filed claims against the SENIAT for the portion of VAT not recognized by the SENIAT and believes it has a substantial basis for its position. In August 2008, Harvest Vinccler filed an appeal in the tax courts and presented a proposed settlement with the SENIAT. In October 2008, after consideration of our proposed settlement, the SENIAT offered a counter-proposal which Harvest Vinccler has tentatively accepted. In January 2009, the case was suspended while the tax court notified the Venezuelan General Attorney’s Office (“GAO”) of our intention to settle the case. The Venezuelan Tax Code establishes that once the taxpayer files a request to settle a case, the tax court will admit the request and suspend the filing for 60 consecutive court working days following the notification of the GAO. The 60 consecutive court working days are for the taxpayer and GAO to agree on the terms of settlement to be proposed to the tax court. In Harvest Vinccler’s case, the wording of the settlement is in the advanced stages, the amounts are already agreed upon and comments were received from the GAO on April 24, 2009. The suspension of the case expired June 30, 2009, but the GAO agreed to extend the suspension for another 40 court working days. With such extension, the Court case is still suspended while the GAO waits for confirmation from the Finance Ministry. The GAO will monitor the case to obtain authorization from the SENIAT before the extension expires. We are waiting for final confirmation from the SENIAT.

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

Note 3 — Taxes Other Than on Income

The components of taxes other than on income were:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(in thousands)
Franchise Taxes	$	57	$	42	$	99	$	83
Payroll and Other Taxes		184		153		459		375

	$	241	$	195	$	558	$	458

Note 4 — Operating Segments

We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Operations included under the heading “United States and other” include corporate management, cash management, business development and financing activities performed in the United States and other countries which do not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the United States and other segment and are not allocated to other operating segments:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(in thousands)
Segment Income (Loss)
Venezuela	$	8,074		$	9,997		$	12,790		$	18,108
Indonesia		(2,957	)		(1,745	)		(2,792	)		(1,776	)
United States and other		(9,306	)		(8,885	)		(18,963	)		(15,760	)

Net income (loss) attributable to Harvest	$	(4,189	)	$	(633	)	$	(8,965	)	$	572


	June 30,			December 31,
	2009			2008
	(in thousands)
Operating Segment Assets
Venezuela	$	224,771		$	231,755
Indonesia		3,469			1,556
United States and other		145,593			152,184

		373,833			385,495
Intersegment eliminations		(37,844	)		(23,229	)

	$	335,989		$	362,266

Note 5 — Investment in Equity Affiliates

Petrodelta

HNR Finance owns a 40 percent interest in Petrodelta. On April 23, 2009, Petrodelta’s board of directors declared a dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest). HNR Finance received the cash related to this dividend in the form of an advance dividend in October 2008. The advance dividend was reclassified in April 2009 from Advance from equity affiliate to reduce our Investment in equity affiliates.

In 2005, Venezuela modified the Science and Technology Law (referred to as “LOCTI” in Venezuela) to require companies doing business in Venezuela to invest, contribute, or spend a percentage of their gross revenue on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. LOCTI requires major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law (“OHL”) to contribute two percent of their gross revenue generated in Venezuela from activities specified in the OHL. The contribution is based on the previous year’s gross revenue and is due the following year. LOCTI requires that each company file a separate declaration stating how much has been contributed; however, waivers have been granted in the past to allow PDVSA to file a declaration on a consolidated basis covering all of its and its consolidating entities liabilities. PDVSA was granted a waiver to file its 2008 declaration on a consolidated basis, and based on this waiver, Petrodelta reversed $12.4 million, $6.2 million net of tax ($2.0 million net to our 32 percent interest) for contributions to LOCTI in the fourth quarter 2008. The waiver to file the declaration on a consolidated basis has to be requested each year and granted each year. For the six months ended June 30, 2009, Petrodelta’s potential share for LOCTI contributions is $4.8 million, $2.4 million net of tax ($0.8 million net to our 32 percent interest). Although the OHL requires the recording of LOCTI contributions, in the second quarter 2009, Harvest management reversed the accrual, of which $2.4 million, $1.2 million net of tax ($0.4 million net to our 32 percent interest) related to the first quarter of 2009, as Harvest management expects that PDVSA will continue requesting and receiving waivers.

During the first quarter of 2009, PDVSA completed an actuarial study for their pension and retirement plan. This pension and retirement plan covers all PDVSA employees and mixed companies. In May 2009, upon completion of the review of this actuarial study, PDVSA sent a statement to Petrodelta for its respective costs associated with the pension and retirement plan. The pension adjustment was for past service costs covering the period from January 2008, when the Harvest Vinccler employees were migrated to PDVSA payroll, through May 2009. It is a non-recurring adjustment. Pension costs at June 30, 2009 reasonably reflect Petrodelta’s employee demographic and plan conditions. The additional pension cost is not tax deductible until future periods when the pension is settled in cash. Petrodelta is not required to reimburse the pension costs to PDVSA until PDVSA pays

the pension benefits to employees. Petrodelta recorded additional pension expense of $15.6 million ($5.0 million net to our 32 percent interest) in the three month period ended June 30, 2009 based on the statement received. Following this true-up, future pension expense will be based on current service incurred.

In June 2009, CVP issued instructions to Petrodelta to set up a reserve within the equity section of the balance sheet for deferred tax assets. Although this reserve has no effect on Petrodelta’s financial position, results of operation or cash flows, it has the effect of limiting future dividends to net income adjusted for deferred tax assets. Past dividends received from Petrodelta represented Petrodelta’s net income as reported under International Financial Reporting Standards (“IFRS”). However, Article 307 of the Venezuelan Commerce Code states that distributions and payments of dividends must meet two conditions: 1) the retained earnings of the entity should be liquid and realizable, and 2) the entity has enough cash to pay and distribute the dividend. Deferred taxes are not liquid or realizable as cash until the items giving rise to the deferred tax are recognized in the entity’s tax return. Therefore, CVP’s instructions are to ensure future dividends are declared and paid as stated under Venezuelan law. Article 307 also states that shareholders are not obligated to restore dividends that have been distributed in good faith according to the entity’s balances and sets the statute of limitations for an entity to claim restoration of dividends at five years.

Petrodelta’s financial information is prepared in accordance with IFRS which we have adjusted to conform to GAAP. All amounts through Net Income represent 100 percent of Petrodelta. Summary financial information has been presented below at June 30, 2009 and December 31, 2008 and for the three and six months ended June 30, 2009 and 2008 (in thousands, except per unit information):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Barrels of oil sold		2,007			1,238			3,732			2,447
Thousand cubic feet of gas sold		1,306			3,049			2,720			6,221
Total barrels of oil equivalent		2,225			1,746			4,185			3,484

Average price per barrel	$	53.39		$	83.12		$	47.48		$	81.09
Average price per thousand cubic feet	$	1.54		$	1.54		$	1.54		$	1.54

Revenues:
Oil sales	$	107,154		$	102,897		$	177,183		$	198,432
Gas sales		2,016			4,695			4,199			9,580
Royalty		(36,125	)		(43,130	)		(60,912	)		(77,089	)

		73,045			64,462			120,470			130,923

Expenses:
Operating expenses		20,809			18,851			32,525			33,194
Depletion, depreciation and amortization		9,025			7,754			16,713			12,052
General and administrative		6,989			2,056			9,214			3,734
Taxes other than on income		(1,536	)		3,602			1,535			7,088

		35,287			32,263			59,987			56,068

Income from operations		37,758			32,199			60,483			74,855

Investment Earnings and Other		1			4,955			3			5,008


Income before Income Tax		37,759			37,154			60,486			79,863

Current income tax expense		22,414			9,115			32,200			30,611
Deferred income tax benefit		(19,284	)		(8,293	)		(23,367	)		(14,976	)

Net Income		34,629			36,332			51,653			64,228
Adjustment to reconcile to reported Net Income From Unconsolidated Equity Affiliate:
Deferred income tax benefit		11,086			12,874			16,087			16,430

Net Income Equity Affiliate		23,543			23,458			35,566			47,798
Equity interest in unconsolidated equity affiliate		40	%		40	%		40	%		40	%

Income before amortization of excess basis in equity affiliate		9,417			9,383			14,226			19,119
Amortization of excess basis in equity affiliate		(352	)		(277	)		(663	)		(552	)
Conform depletion expense to GAAP		(263	)		408			440			(258	)

Net income from unconsolidated equity affiliate	$	8,802		$	9,514		$	14,003		$	18,309


	June 30,		December 31,
	2009		2008
Current assets	$	330,835	$	311,017
Property and equipment		244,751		211,760
Other assets		119,122		97,323
Current liabilities		263,210		260,234
Other liabilities		39,153		19,174
Net equity		392,345		340,692

Fusion Geophysical, LLC (“Fusion”)

We own a 49 percent noncontrolling equity investment in Fusion Geophysical, LLC (“Fusion”). Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering. The purchase of Fusion extends our technical ability and global reach to support a more organic growth and exploration strategy. Our noncontrolling equity investment in Fusion is accounted for using the equity method of accounting. Operating revenue and total assets represent 100 percent of Fusion. No dividends were declared or paid during the three and six months ended June 30, 2009 and 2008, respectively. Summarized financial information for Fusion follows (in thousands, except per unit information):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Operating Revenues	$	2,165		$	2,302		$	5,344		$	4,994

Net Income (Loss)	$	(2,306	)	$	131		$	(3,371	)	$	526
Equity interest in unconsolidated equity affiliate		49	%		45	%		49	%		45	%

Net income from unconsolidated equity affiliate		(1,130	)		59			(1,652	)		237
Amortization of fair value of intangibles		(196	)		(164	)		(465	)		(328	)

Net loss from unconsolidated equity affiliate	$	(1,326	)	$	(105	)	$	(2,117	)	$	(91	)


	June 30,		December 31,
	2009		2008
Current assets	$	4,401	$	7,864
Total assets		27,353		30,633
Current liabilities		8,471		7,294
Total liabilities		8,916		8,281

Approximately 47.9 percent and 40.7 percent of Fusion’s revenue for the three and six months ended June 30, 2009, respectively, was earned from Harvest or equity affiliates. Approximately 11.3 percent and 12.5 percent of Fusion’s revenue for the three and six months ended June 30, 2008, respectively, was earned from Harvest or equity affiliates.

On April 9, 2009, we entered into a service agreement with Fusion whereby we prepaid $1.5 million for certain services to be performed in connection with certain projects as defined in the service agreement. The services are to be performed in accordance with the existing consulting agreement. Upon written notice to Fusion, the projects and types of services can be amended. The unapplied portion of the prepayment advance bears interest at an annual rate of 12 percent which will be added to the prepayment advance balance and used to offset future service invoices from Fusion.

Due to recent liquidity issues Fusion is encountering, we reviewed our noncontrolling equity investment in Fusion for impairment under APB 18. In performing this review, future net cash flows were prepared by Fusion based on different business opportunities that Fusion is currently pursuing. These business opportunities were weighted with a probability of success. Based on this review, there was no impairment to the carrying value of $2.9 million to our noncontrolling equity investment in Fusion at June 30, 2009.

Note 6 — United States Operations

During 2008, we initiated a domestic exploration program in two different basins. We are the operator of both exploration programs and have complemented our existing personnel with the addition of highly experienced management and technical personnel and with the acquisition of our noncontrolling equity investment in Fusion.

Gulf Coast — AMI

In March 2008, we executed an Area of Mutual Interest Participation Agreement (“AMI”) with a private third party for an area in the upper Gulf Coast Region of the United States. We are the operator and have an initial working interest of 55 percent in the AMI. The AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana, including state waters. The private third party contributed two prospects, including the leases and proprietary 3-D seismic data sets, and numerous leads generated over the last three decades of regional geological focus. We agreed to fund the first $20 million of new lease acquisitions, geological and geophysical studies, seismic reprocessing and drilling costs. The parties focused on two initial prospects for evaluation. The other party is obligated to evaluate and present additional opportunities at their sole cost. As each prospect is accepted it will be covered by the AMI. Although several additional potential prospects have been screened and evaluated within the AMI since its inception, we have not pursued leasing or drilling on any new projects within the AMI as of June 30, 2009. At June 30, 2009, we have met the $20 million funding obligation under the terms of the AMI. All costs incurred after June 30, 2009 will be shared by the parties in proportion to their working interests as defined in the AMI agreement.

Gulf Coast AMI — West Bay Project

Interpretation of 3-D seismic data on the project was completed during the second quarter 2009 and resulted in the identification of a revised set of drilling leads and prospects for the project. The AMI participants are currently evaluating the leads and prospects to determine priorities and drilling plans for the project.

Based on the initial concepts for the project and prior to completion of the 3-D data interpretation, we submitted an Application to Install Structures to Drill and Produce Oil and Gas (“Application to Install Structures”) with the U.S. Army Corps of Engineers — Galveston District (“Corps of Engineers”) for the project on Dec 8, 2008. On April 7, 2009, the Corps of Engineers completed internal review of the permit application. Upon completion of the interpretation of the 3-D data and review of the drilling leads and prospects, and in consultation with the Corps of Engineers, we determined that the resulting changes in the scope and plans for the project resulted in our Application to Install Structures no longer being valid. As a result, we withdrew the Application to Install Structures in June 2009. As noted previously, the AMI participants are currently developing drilling plans for the project. Dependent on the selected drilling prospects and locations, the drilling may or may not require permits from the Corps of Engineers. We expect to firm up plans for initial drilling on the project during the third quarter 2009, with the expectation of initial drilling on the project in early 2010. The West Bay project represents $3.6 million and $3.7 million, respectively, of oil and gas properties on our June 30, 2009 and December 31, 2008 balance sheets.

On July 14, 2009, we, along with our partner in the AMI, acquired 880 acres of shallow water offshore bay leases representing two separate tracts from the State of Texas General Land Office at a state lease sale for a total gross cost of $0.5 million. Acquisition of these two tracts completes the planned land acquisition activities on the project.

Western United States — Antelope

In October 2007, we entered into a Joint Exploration and Development Agreement (“JEDA”) with a private third party to pursue a lease acquisition program and drilling program on the Antelope project in the Western United States. We are the operator and had an initial working interest of 50 percent in the project. The private third party is obligated to assemble the lease position on the project. We will earn our 50 percent working interest in the project by compensating the private third party for leases acquired in accordance with terms defined in the JEDA, and by drilling one deep natural gas test well at our sole expense. In November 2008, we entered into a Letter Agreement/Amendment of the JEDA (the “Letter Agreement”) with the private third party. The Letter Agreement clarifies several open issues in the JEDA, such as classification of $2.7 million of prepaid land costs for

the Antelope project as a note receivable, addition of a requirement for the private third party to partially assign leases to us prior to meeting the lease earning obligation, and clarification of the private third party’s cost obligations for any shallow wells to be drilled on the project prior to the initial deep test well. Per the Letter Agreement, payment of the $2.7 million note receivable was due from the private third party on or by spud date of the commitment well. Since payment was not received prior to spud, our interest in the project has now increased to 60 percent. The note receivable remains outstanding and will be collected through sales revenues taken from the private third party’s net revenue from the Bar F #1-20-3-2 well (“Bar F”) provided the Bar F is commercial. We currently hold 58,000 gross undeveloped acres under lease (34,800 acres net to us) in the Antelope project.

The Antelope project is targeted to explore for and develop oil and natural gas from multiple reservoir horizons in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties. Leads and/or prospects have been identified in three prospective reservoir horizons in preparation for drilling. On June 15, 2009, we spud the

Bar F. The Bar F is a tight hole and is permitted to 18,000 feet. Drilling is expected to be completed in September 2009, with the potential for 90 days of production testing upon completion of drilling. Operational activities on the project during the quarter primarily focused on continuing leasing activities, concentrating primarily on Allottee leases administered by the Bureau of Indian Affairs. Other operational activities during the quarter included surveying, obtaining regulatory approvals from the Board of Oil, Gas, and Mining of the Utah Department of Natural Resources, preliminary engineering, and permitting preparations for the Bar F and other potential planned wells. The Antelope project represents $19.5 million and $8.2 million, respectively, of oil and gas properties on our June 30, 2009 and December 31, 2008 balance sheets.

In December 2008, we filed Applications for Permits to Drill eight shallow oil wells with the State of Utah Department of Natural Resources Division of Oil, Gas and Mining (“DOGM”). On April 22, 2009, the Board of DOGM approved our proposal establishing 40 acre spacing for the eight shallow oil wells. We expect to receive the permits to drill the eight shallow oil wells in the near future. We are currently in negotiations with a previously non-consenting third party regarding a potential joint drilling project in the area covering these eight wells, and we believe that an agreement will be reached. If the negotiations on the joint project are successful, our average working interest in the eight wells will be approximately 33 percent. If these negotiations are successful, there will still be a requirement for Force Pooling of the remaining non-consenting interests in the eight proposed shallow oil wells. The Board of DOGM is scheduled to consider this request at a hearing in August 2009. The cost of the eight shallow oil wells will be borne by the parties participating in the drilling project proportionately to their working interest. We expect to commence drilling of the eight shallow oil wells in the next 12 months.

Note 7 — Indonesia

In 2008, we acquired a 47 percent interest in the Budong-Budong Production Sharing Contract (“Budong PSC”) by committing to fund the first phase of the exploration program including the acquisition of 2-D seismic and drilling of the first two exploration wells. This commitment is capped at $17.2 million. The commitment is comprised of $6.5 million for the acquisition of seismic and $10.7 million for the drilling of the first exploratory well. After the commitment of each component is met, all subsequent costs will be shared by the parties in proportion to their ownership interests. Through June 30, 2009, we have incurred the $6.5 million of the carry obligation for the 2-D seismic acquisition. Prior to drilling the first exploration well, subject to the estimated cost of that well, our partner will have a one-time option to increase the level of the carried interest to $20.0 million, and as compensation for the increase, we will increase our participation to a maximum of 54.65 percent. This equates to a total carried cost for the farm-in of $9.1 million. Our partner will be the operator through the exploration phase as required by the terms of the Budong PSC. We will have control of major decisions and financing for the project with an option to become operator if approved by BP Migas, Indonesia’s oil and gas regulatory authority, in the subsequent development and production phase.

The Budong PSC includes a ten-year exploration period and a 20-year development phase. During the initial three-year exploration phase, which began January 2007, we plan to acquire, process and interpret 2-D seismic and drill two exploration wells. The acquisition program of 650 kilometers of 2-D seismic was completed in 2008. Processing of this 2-D seismic data was completed in the second quarter 2009 and current activities include interpretation of the data and well planning. It is expected that the first of two exploration wells will spud in the fourth quarter of 2009. The Budong PSC represents $0.3 million and $0.2 million, respectively, of oil and gas properties on our June 30, 2009 and December 31, 2008 balance sheets.

Note 8 — Gabon

In 2008, we completed the purchase of a 66.667 percent interest in the production sharing contract related to the Dussafu Marin Permit offshore Gabon in West Africa (“Dussafu PSC”). We are the operator of the Dussafu PSC. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC contains 680,000 acres with water depths up to 1,000 feet. The Dussafu PSC has two small oil discoveries in the Gamba and Dentale reservoirs and a small natural gas discovery. Production and infrastructure exists in the blocks contiguous to the Dussafu PSC.

The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources (“Republic of Gabon”), entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. The second exploration phase comprises a three-year work commitment which includes the acquisition and processing of 500 kilometers of 2-D seismic, geology and geophysical interpretation, engineering studies and the drilling of a conditional well. In October 2008, the acquisition of 650 kilometers of 2-D seismic was completed. Current activities include the continued processing of the 2-D seismic to define the syn-rift potential similar to the Lucina and M’Bya fields and the pre-stack depth reprocessing of 1,076 square kilometers of existing 3-D seismic to define the sub-salt structure to unlock the potential of the Gamba play that is producing in the Etame field to the north. Processing of both the 2-D and 3-D seismic should be completed in the third quarter 2009. We expect the seismic to mature the prospect inventory to make a decision in 2009 for a well in 2010. The Dussafu PSC represents $6.9 million and $5.9 million, respectively, of oil and gas properties on our June 30, 2009 and December 31, 2008 balance sheets.

Note 9 — Oman

On April 11, 2009, we signed an Exploration and Production Sharing Agreement (“EPSA”) with Oman for the Al Ghubar / Qarn Alam license (“Block 64 EPSA”). We will have a 100 percent working interest in the EPSA during the exploration phase. Oman Oil Company will have the option to back-in to up to a 20 percent interest in the block after the discovery of gas.

Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate which the Oman Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). PDO will continue to produce oil from several fields within the Block 64 EPSA area. The 3,867 square kilometer (955,600 acres) block is located in the gas and condensate rich Ghaba Salt Basin in close proximity to the Barik, Saih Rawl and Saih Nihayda gas and condensate fields. We have an obligation to drill two wells over a three year period with a funding commitment of $22.0 million. During the six months ended June 30, 2009, we incurred $1.4 million for costs associated with negotiating Block 64 EPSA and $2.2 million for costs associated with signing the license, including signature bonus and data compilation. The Block 64 EPSA represents $3.6 million of oil and gas properties on our June 30, 2009 balance sheet.

Note 10 — Subsequent Events

We have performed an evaluation of subsequent events through August 4, 2009, which is the date the financial statements were issued.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Harvest Natural Resources, Inc. (“Harvest” or the “Company”) cautions that any forward-looking statements (as such term is defined in the Private Securities Litigation Reform Act of 1995) contained in this report or made by management of the Company involve risks and uncertainties and are subject to change based on various important factors. When used in this report, the words “budget”, “guidance”, forecast”, “anticipate”, “expect”, “believes”, “goals”, “projects”, “plans”, “anticipates”, “estimates”, “should”, “could”, “assume” and similar expressions are intended to identify forward-looking statements. In accordance with the provisions of the Private Securities Litigation Reform Act of 1995, we caution you that important factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include our concentration of operations in Venezuela, the political and economic risks associated with international operations (particularly those in Venezuela), the anticipated future development costs for 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, seismic crews, overall economic conditions, political stability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in governmental policy, availability of sufficient financing, changes in weather conditions, and ability to hire, retain and train management and personnel. A discussion of these factors is included in our Annual Report on Form 10-K for the year ended December 31, 2008, which includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q.

Executive Summary

Harvest Natural Resources, Inc. is a petroleum exploration and production company of international scope since 1989, when it was incorporated under Delaware law. Our focus is on acquiring exploration, development and producing properties in geological basins with proven active hydrocarbon systems. Our experienced technical, business development and operating staffs have identified low entry cost exploration opportunities in areas with large hydrocarbon resource potential. We operate from our Houston, Texas headquarters. We also have an expanded regional/technical office in the United Kingdom, an eastern hemisphere regional office in Singapore, and small field offices in Jakarta, Indonesia and Roosevelt, Utah to support field operations in the area. We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”) originally through our subsidiary Harvest Vinccler, S.C.A. (“Harvest Vinccler”) and subsequently through our 40 percent equity affiliate, Petrodelta, S. A. (“Petrodelta”) which operates a portfolio of properties in eastern Venezuela including large proven oil fields as well as properties with very substantial opportunities for both development and exploration. We have seconded key technical and managerial personnel into Petrodelta and participate on Petrodelta’s board of directors. Geophysical and geosciences support services are available to our in-house experts through our noncontrolling equity investment in Fusion Geophysical, LLC (“Fusion”). Fusion is a technical firm specializing in the areas of geophysics and geosciences headquartered in the Houston area and working around the world. 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. Currently, we hold interests in Venezuela, the Gulf Coast Region of the United States through an Area of Mutual Interest Participation Agreement (“AMI”) with a private third party, the Antelope project in the Western United States through a Joint Exploration and Development Agreement (“JEDA”), and exploration acreage offshore of the People’s Republic of China (“China”), mainly onshore West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), and in the Sultanate of Oman (“Oman”).

Venezuela

During the six months ended June 30, 2009, Petrodelta drilled and completed nine successful development wells, sold approximately 3.7 million barrels of oil and sold 2.7 billion cubic feet (“BCF”) of natural gas. Petrodelta has been advised by the Venezuelan government that the 2009 production target is approximately 16,000 barrels of

oil per day following the December 17, 2008 OPEC meeting establishing new production quotas. However, Petrodelta has been allowed to produce at capacity to help fulfill other companies’ production shortfalls, thus averaging 20,620 barrels of oil per day during the six months ended June 30, 2009.

Petrodelta shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. The management and board of directors of Petrodelta have taken actions to reduce both operating and capital expenditures. On April 23, 2009, Petrodelta’s board of directors endorsed a 2009 budget for Petrodelta’s Business Plan. The proposed 2009 budget has been submitted to Petrodelta’s shareholders for approval. For 2009, the drilling program was to utilize two rigs to drill development and appraisal wells for both maintaining production capacity and appraising the substantial resource bases in the presently non-producing Isleño and El Salto fields. However, Petrodelta reduced its rig count to one drilling rig for most of the second quarter. Petrodelta began the appraisal and testing of its large portfolio of undeveloped resources in the second quarter of 2009. On April 30, 2009, Petrodelta began drilling in the El Salto field, which is currently undeveloped, and drilled two successful appraisal wells. The results of these wells are currently under evaluation by Petrodelta. Pilot production has recently commenced from one of the appraisal wells through temporary facilities. The second appraisal well is waiting on permits from the Ministry of the People’s Power for Energy and Petroleum (“MENPET”) for testing.

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

On April 23, 2009, Petrodelta’s board of directors declared a dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest). HNR Finance received the cash related to this dividend in the form of an advance dividend in October 2008.

In 2005, Venezuela modified the Science and Technology Law (referred to as “LOCTI” in Venezuela) to require companies doing business in Venezuela to invest, contribute, or spend a percentage of their gross revenue on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. LOCTI requires major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law (“OHL”) to contribute two percent of their gross revenue generated in Venezuela from activities specified in the OHL. The contribution is based on the previous year’s gross revenue and is due the following year. LOCTI requires that each company file a separate declaration stating how much has been contributed; however, waivers have been granted in the past to allow Petroleos de Venezuela, S.A. (“PDVSA”) to file a declaration on a consolidated basis covering all of its and its consolidating entities liabilities. PDVSA was granted a waiver to file its 2008 declaration on a consolidated basis, and based on this waiver, Petrodelta reversed $12.4 million, $6.2 million net of tax ($2.0 million net to our 32 percent interest) for contributions to LOCTI in the fourth quarter 2008. The waiver to file the declaration on a consolidated basis has to be requested each year and granted each year. For the six months ended June 30, 2009, Petrodelta’s potential share for LOCTI contributions is $4.8 million, $2.4 million net of tax ($0.8 million net to our 32 percent interest). Although the OHL requires the recording of LOCTI contributions, in the second quarter 2009, Harvest management reversed the accrual, of which $2.4 million, $1.2 million net of tax ($0.4 million net to our 32 percent interest), related to the first quarter of 2009, as Harvest management expects that PDVSA will continue requesting and receiving waivers.

net to our 32 percent interest) in the three month period ended June 30, 2009 based on the statement received. Following this true-up, future pension expense will be based on current service incurred.

Certain operating statistics for the three and six months ended June 30, 2009 and 2008 for the Petrodelta fields operated by Petrodelta are set forth below. This information is provided at 100 percent. This information may not be representative of future results.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Oil production (million barrels)		2.0		1.2		3.7		2.4
Natural gas production (billion cubic feet)		1.3		3.0		2.7		6.2
Barrels of oil equivalent		2.2		1.7		4.2		3.5
Operating expense ($millions)		20.8		18.9		32.5		33.2
Capital expenditures ($millions)		7.7		7.3		37.4		9.4

Crude oil delivered from the Petrodelta fields to PDVSA is priced with reference to Merey 16 published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Market prices for crude oil of the type produced in the fields operated by Petrodelta averaged approximately $53.39 and $47.48 per barrel for the three and six months ended June 30, 2009, respectively. Market prices for crude oil of the type produced in the fields operated by Petrodelta averaged approximately $83.12 and $81.09 per barrel net of the impact of the Law of Special Contribution to Extraordinary Prices at the Hydrocarbon International Market (“Windfall Profits Tax”) implemented by the Venezuelan government, for the three and six months ended June 30, 2008, respectively. The price for natural gas is $1.54 per thousand cubic feet. The decrease in gas production is due to reservoir management.

United States

Gulf Coast — West Bay

During the six months ended June 30, 2009, operational activities in the West Bay prospect, one of the two initial prospects of the AMI, included the interpretation of 3-D seismic, site surveying, and preparation of engineering documents. Interpretation of 3-D seismic data on the project was completed in second quarter 2009 and resulted in the identification of a revised set of drilling leads and prospects for the project. The AMI participants are currently evaluating the leads and prospects to determine priorities and drilling plans for the project.

Based on the initial concepts for the project and prior to completion of the 3-D data interpretation, we submitted an Application to Install Structures to Drill and Produce Oil and Gas (“Application to Install Structures”) with the U.S. Army Corps of Engineers — Galveston District (“Corps of Engineers”) for the project on Dec 8, 2008. On April 7, 2009, the Corps of Engineers completed internal review of the permit application. Upon completion of the interpretation of the 3-D data and review of the revised drilling leads and prospects, and in consultation with the Corps of Engineers, we determined that the resulting changes in the scope and plans for the project resulted in our Application to Install Structures no longer being valid. As a result, we withdrew the Application to Install Structures in June 2009. As noted previously, the AMI participants are currently developing drilling plans for the project. Dependent on the selected drilling prospects and locations, the drilling may or may not require permits from the Corps of Engineers. We expect to firm up plans for initial drilling on the project during the third quarter 2009, with the expectation of initial drilling on the project in early 2010. During the six months ended June 30, 2009, we incurred $1.4 million for seismic interpretation.

Western United States — Antelope

During the six months ended June 30, 2009, operational activities in the Antelope prospect primarily focused on continuing leasing activities, concentrating primarily on Allottee leases administered by the Bureau of Indian Affairs. Other operational activities included surveying, preliminary engineering, and permitting preparations for a deep natural gas test well that commenced drilling on June 15, 2009. On February 10, 2009, we filed a Request for Agency Action with the Board of the State of Utah Department of Natural Resources Division of Oil, Gas, and Mining (“DOGM”) requesting establishment of 640 acre spacing of the lands associated with the deep natural gas test well. This proposal was accepted on May 27, 2009, by the DOGM. Also on February 10, 2009, we filed a Request for Agency Action with the Board of DOGM requesting Force Pooling of the non-consenting interests in the deep test well. We have since reached an agreement with the non-consenting interests and no hearing is necessary. On April 21, 2009, we filed an Application for Permit to Drill the deep natural gas test well with DOGM. The Permit to Drill was approved on May 27, 2009 and drilling of the Bar F #1-20-3-2 well (“Bar F”) commenced on June 15, 2009. The Bar F is currently estimated to reach total depth in September 2009. During the six months ended June 30, 2009, we incurred $7.6 million for drilling, lease acquisition, surveying, permitting and site preparation and $0.3 million for seismic program planning. The expected remaining 2009 budget for this project is $9.5 million.

In December 2008, we filed Applications for Permits to Drill eight shallow oil wells with DOGM. On April 22, 2009, the Board of DOGM approved our proposal establishing 40 acre spacing for the eight shallow oil wells. We expect to receive the permits to drill the eight shallow oil wells in the near future. We are currently in negotiations with a previously non-consenting third party regarding a potential joint drilling project in the area covering these eight wells, and we believe that an agreement will be reached. If the negotiations on the joint project are successful, our average working interest in the eight wells will be approximately 33 percent. If these negotiations are successful, there will still be a requirement for Force Pooling of the remaining non-consenting interests in the eight proposed shallow oil wells. The Board of DOGM is scheduled to consider this request at a hearing in August 2009. The cost of the eight shallow oil wells will be borne by the parties participating in the drilling project proportionately to their working interest. We expect to commence drilling of the eight shallow oil wells in the next 12 months.

Budong-Budong Project, Indonesia (“Budong PSC”)

The acquisition program of 650 kilometers of 2-D seismic was completed in 2008. Processing of this 2-D seismic data was completed in the second quarter 2009 and current activities include interpretation of the data and well planning. It is expected that the first of two exploration wells will spud in the fourth quarter of 2009. In accordance with the farm-in agreement, we expect to fund 100 percent of the well expenditures to earn our 47 percent working interest up to a cap of $10.7 million; thereafter, we will pay in proportion to our working interest. During the six months ended June 30, 2009, we incurred $1.0 million for seismic processing and interpretation and began well planning. The projected 2009 project expenditures (net to us including our funding commitment) for the exploratory well drilling are $8.1 million.

Dussafu Project, Gabon (“Dussafu PSC”)

The acquisition of 650 kilometers of 2-D seismic was completed in 2008. Current activities include the continued processing of the 2-D seismic to define the syn-rift potential similar to the Lucina and M’Bya fields and the pre-stack depth reprocessing of 1,076 square kilometers of existing 3-D seismic to define the sub-salt structure to unlock the potential of the Gamba play that is producing in the Etame field to the north. Processing of both the 2-D and 3-D seismic should be completed in the third quarter 2009. We expect the seismic to mature the prospect inventory to make a decision in 2009 for a well in 2010. During the six months ended June 30, 2009, we incurred $0.1 million related to Dussafu PSC commitment costs and $0.5 million for seismic processing and reprocessing.

The projected 2009 project expenditures (net to our working interest) for exploration activities are $2.0 million. This includes $1.8 million of well planning and long-lead well items if the decision is made to drill a well.

Block 64 Project, Oman (“Block 64 EPSA”)

On April 11, 2009, we signed an Exploration and Production Sharing Agreement (“EPSA”) with the Sultanate of Oman (“Oman”) for the Al Ghubar / Qarn Alam license (“Block 64 EPSA”). We will have a 100 percent working interest in the EPSA during the exploration phase. Oman Oil Company will have the option to back-in to up to a 20 percent interest in the block after the discovery of gas.

Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate which the Oman Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). PDO will continue to produce oil from several fields within the Block 64 EPSA area. The 3,867 square kilometer (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. During the six months ended June 30, 2009, we incurred $2.2 million for costs associated with signing the license, including signature bonus and data compilation. The projected 2009 project expenditures for exploration activities are $2.3 million in 2009 for geological studies, reprocessing and interpretation of existing 3-D seismic and drilling preparations. We have an obligation to drill two wells over a three year period with a funding commitment of $22.0 million.

Other Exploration Projects

Relating to other projects, we incurred $1.4 million during the six months ended June 30, 2009. We have budgeted to spend $1.6 million in leasehold acquisition costs, $4.1 million in seismic acquisition and processing costs and $2.8 million on other project related costs in 2009.

Either one of the two exploratory wells to be drilled in 2009 on the Antelope project and the Budong PSC can have a significant impact on our ability to obtain financing, increase reserves and generate cash flow in the future.

Capital Resources and Liquidity

Working Capital.Our capital resources and liquidity are affected by the ability of Petrodelta to pay dividends. On April 23, 2009, Petrodelta’s board of directors declared a dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest). HNR Finance received the cash related to this dividend in the form of an advance dividend in October 2008. We expect to receive future dividends from Petrodelta; however, we expect the amount of any future dividends to be much lower over the next several years as Petrodelta reinvests most of its earnings into the company in support of its drilling and appraisal activities. In June 2009, CVP issued instructions to all mixed companies regarding the accounting for deferred tax assets. The mixed companies have been instructed to set up a reserve within the equity section of the balance sheet for deferred tax assets. The setting up of the reserve had no effect on Petrodelta’s financial position, results of operation or cash flows. However, the new reserve could have a negative impact on the amount of dividends received in the future. In addition to reinvesting earnings into the company in support of its drilling and appraisal activities, the recent decline in the price per barrel affects Petrodelta’s ability to pay dividends. Until oil prices increase, all available cash will be used to meet current operating requirements and will not be available for dividends. SeeItem 1A — Risk FactorsandItem 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operationsin our Annual Report on Form 10-K for the year ended December 31, 2008 andItem 1A — Risk Factorsin Part II of this Quarterly Report on Form 10-Q for a more complete description of the situation in Venezuela and other matters.

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


	Six Months Ended June 30,
	2009			2008
	(in thousands)
Net cash provided by (used in) operating activities	$	(19,847	)	$	64,304
Net cash used in investing activities		(11,651	)		(9,126	)
Net cash used in financing activities		(1,276	)		(18,815	)

Net increase (decrease) in cash	$	(32,774	)	$	36,363

At June 30, 2009, we had current assets of $82.6 million and current liabilities of $17.4 million, resulting in working capital of $65.2 million and a current ratio of 4.8:1. This compares with a working capital of $77.0 million and a current ratio of 3.0:1 at December 31, 2008. The decrease in working capital of $11.8 million was primarily due to a reduction in cash and cash equivalents, primarily for capital expenditures.

Cash Flow from Operating Activities.During the six months ended June 30, 2009, net cash used in operating activities was approximately $19.8 million. During the six months ended June 30, 2008, net cash provided by operating activities was approximately $64.3 million. The $84.1 million decrease was primarily due to repayments of advances to equity affiliate received by HNR Finance in the first quarter of 2008 and receipt of a dividend from unconsolidated equity affiliate.

Cash Flow from Investing Activities.During the six months ended June 30, 2009, we had cash capital expenditures of approximately $11.3 million. Of the 2009 expenditures, $7.6 million was attributable to activity on the Antelope project, $2.2 million to Block 64 EPSA, $0.1 million to the Dussafu PSC and $1.4 million to other projects. During the six months ended June 30, 2008, we had cash capital expenditures of approximately $11.2 million. Of the 2008 expenditures, $3.2 million was attributable to activity on the West Bay project, $4.8 million to the Dussafu PSC, $1.4 million to the Antelope project and $1.8 million was attributable to other projects.

During the three months ended March 31, 2009, we deposited with a U.S. bank $1.7 million as collateral for two standby letters of credit issued in support of bank guarantees required as part of a project bidding process. During the three months ended June 30, 2009, both standby letters of credit were cancelled and the collateral returned to us. During the six months ended June 30, 2008, we had $3.2 million of restricted cash returned to us. During the six months ended June 30, 2009 and 2008, we incurred $0.3 million and $1.2 million, respectively, of investigatory costs related to various international and domestic exploration studies.

With the conversion to Petrodelta, Petrodelta’s capital commitments will be determined by their business plan. Petrodelta’s capital commitments will be funded by internally generated cash flow. Our expected capital expenditures will be funded through our existing cash balances and future Petrodelta dividends.

Cash Flow from Financing Activities.During the six months ended June 30, 2009, we incurred $1.5 million in legal fees associated with prospective financing. During the six months ended June 30, 2008, Harvest Vinccler repaid 10 million Bolivars (approximately $4.7 million) of its Bolivar denominated debt, and we redeemed the 20 percent noncontrolling interest in our Barbados affiliate.

In June 2007, we announced that our Board of Directors had authorized the purchase of up to $50 million of our common stock from time to time through open market transactions. As of June 30, 2008, 4.6 million shares had been purchased, at an average cost of $10.93 per share, including commissions. The repurchase program is now complete.

In July 2008, our Board of Directors authorized the purchase of up to $20 million of our common stock from time to time through open market transactions. As of December 31, 2008, 1.2 million shares of stock had been purchased at an average cost of $10.17 per share for a total cost of $12.2 million of the $20 million authorization. During the six months ended June 3, 2009, no stock was purchased under the program.

Results of Operations

You should read the following discussion of the results of operations for the three and six months ended June 30, 2009 and 2008 and the financial condition as of June 30, 2009 and December 31, 2008 in conjunction with

our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2008.

Three Months Ended June 30, 2009 Compared with Three Months Ended June 30, 2008

We reported a net loss attributable to Harvest of $4.2 million, or $0.13 diluted earnings per share, for the three months ended June 30, 2009 compared with net loss of $0.6 million, or $0.02 diluted earnings per share, for the three months ended June 30, 2008.

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


	Three Months Ended
	June 30,						Increase
	2009			2008			(Decrease)
Exploration expense	$	3.5		$	2.9		$	0.6
General and administrative		6.4			6.4			—
Taxes other than on income		0.2			0.2			—
Gain on financing transactions		—			(2.1	)		2.1
Investment earnings and other		(0.3	)		(0.8	)		0.5
Interest expense		—			1.3			(1.3	)
Income tax expense		0.1			—			0.1

Our accounting method for oil and gas properties is the successful efforts method. During the three months ended June 30, 2009, we incurred $2.4 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, and $1.1 million related to other general business development activities. During the three months ended June 30, 2008, we incurred $2.2 million of exploration costs related to the purchase and reprocessing of seismic data related to our U.S. operations, acquisition of seismic data related to our Indonesian operations and $0.7 million related to other general business development activities.

General and administrative costs were consistent in the three months ended June 30, 2009 compared to the three months ended June 30, 2008. Taxes other than on income were consistent in the three months ended June 30, 2009 compared to the three months ended June 30, 2008.

We did not participate in any financing transactions in the three months ended June 30, 2009. During the three months ended June 30, 2008, we entered into an exchange transaction exchanging U.S. government securities for U.S. Dollar indexed debt issued by the Venezuelan government. This security exchange transaction resulted in a $2.1 million gain on financing transactions for the three months ended June 30, 2008.

Investment earnings and other decreased due to lower interest rates earned on lower average cash balances. Interest expense was lower for the three months ended June 30, 2009 compared to the three months ended June 30, 2008 due to the repayment of debt in 2008.

Income tax expense was higher in the three months ended June 30, 2009 compared to the three months ended June 30, 2008 primarily due to current income tax due in The Netherlands on interest income earned on cash balances.

Six Months Ended June 30, 2009 Compared with Six Months Ended June 30, 2008

We reported a net loss attributable to Harvest of $9.0 million, or $0.27 diluted earnings per share, for the six months ended June 30, 2009 compared with net income of $0.6 million, or $0.02 diluted earnings per share, for the six months ended June 30, 2008.

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


	Six Months Ended
	June 30,						Increase
	2009			2008			(Decrease)
Exploration expense	$	4.4		$	4.2		$	0.2
General and administrative		12.9			12.6			0.3
Taxes other than on income		0.6			0.5			0.1
Gain on financing transactions		—			(3.4	)		3.4
Investment earnings and other		(0.6	)		(1.9	)		1.3
Interest expense		—			1.7			(1.7	)
Income tax expense		1.0			0.1			0.9

Our accounting method for oil and gas properties is the successful efforts method. During the six months ended June 30, 2009, we incurred $2.8 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, and $1.6 million related to other general business development activities. During the six months ended June 30, 2008, we incurred $3.5 million of exploration costs related to the purchase and reprocessing of seismic data related to our U.S. operations and $0.7 million related to other general business development activities.

General and administrative costs were higher in the six months ended June 30, 2009 compared to the six months ended June 30, 2008 primarily due to employee related expenses. Taxes other than on income for the six months ended June 30, 2009 were higher than that of the six months ended June 30, 2008 primarily due to an increase in payroll related taxes.

We did not participate in any financing transactions in the six months ended June 30, 2009. During the six months ended June 30, 2008, we entered into an exchange transaction exchanging U.S. government securities for U.S. Dollar indexed debt issued by the Venezuelan government. This security exchange transaction resulted in a $3.4 million gain on financing transactions for the six months ended June 30, 2008.

Investment earnings and other decreased due to lower interest rates earned on lower average cash balances. Interest expense was lower for the six months ended June 30, 2009 compared to the six months ended June 30, 2008 due to the repayment of debt in 2008.

For the six months ended June 30, 2009, income tax expense was higher than that of the six months ended June 30, 2008 primarily due to additional income tax assessed in the Netherlands for 2007 and 2008 of $0.7 million as a result of financing activities, which was recorded in the first quarter of 2009, and additional current income tax in the Netherlands of $0.2 million due to interest income earned from loans to affiliates and on cash balances.

Effects of Changing Prices, Foreign Exchange Rates and Inflation

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

Venezuela has imposed currency exchange restrictions. This currency exchange restriction or adjustment in the exchange rate has not had a material impact on us at this time. Dividends from Petrodelta will be denominated in U.S. Dollars when paid. We have not encountered currency restrictions in other countries in which we operate or have offices. Local reporting and large transactions are denominated in U.S. Dollars. During the six months ended June 30, 2009 and 2008, our net foreign exchange gains attributable to our international operations were minimal. The U.S. Dollar and Bolivar exchange rates have not been adjusted since March 2005. However, 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.

Within the United States and the other countries in which we operate or have offices, except for Venezuela, inflation has had a minimal effect on us, but it is potentially an important factor with respect to Petrodelta’s results of operations.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk from adverse changes of the situation in Venezuela, our recently initiated exploration program and adverse changes in oil prices, interest rates, foreign exchange and political risk, as discussed in our Annual Report on Form 10-K for the year ended December 31, 2008. The information about market risk for the six months ended June 30, 2009 does not differ materially from that discussed in the Annual Report on Form 10-K for the year ended December 31, 2008.

Item 4. 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.

Based on their evaluation as of June 30, 2009, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) were effective.

Management’s Remediation Efforts.In our Annual Report on Form 10-K for the year ended December 31, 2008, management concluded that the Company did not maintain effective controls over the period-end financial reporting process as of December 31, 2008. Specifically, effective controls did not exist to ensure that the deferred tax adjustments to reconcile net income reported by Petrodelta under IFRS to that required by GAAP were completely and accurately identified and that the necessary adjustments were appropriately analyzed and recorded on a timely basis.

During 2009, management has enhanced the controls over its equity investment to ensure that the adequate information regarding Petrodelta’s temporary deferred tax differences is obtained and that a comprehensive analysis of such information is performed. Specifically, management has requested further information related to the nature of each temporary deferred tax difference which enables management to determine the impact on the deferred tax adjustment to reconcile net income reported by Petrodelta under IFRS to that required under GAAP. The enhanced controls have enabled management to ensure that the deferred tax adjustment to reconcile net income reported by Petrodelta under IFRS to that required under GAAP is identified and completely and accurately reconciled.

During the six months ended June 30, 2009, management further enhanced the controls necessary to ensure that all necessary adjustments are appropriately analyzed and recorded on a timely basis. These enhancements were in place and operating effectively as of June 30, 2009.

Changes in Internal Control over Financial Reporting.As described above under Management’s Remediation Efforts, there have been changes in our internal control over financial reporting during our most recent quarter ended June 30, 2009, that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

In June 2007, the SENIAT, the Venezuelan income tax authority, issued an assessment for taxes in the amount of $0.4 million for Harvest Vinccler’s failure to withhold VAT from vendors during 2005. Also, the SENIAT imposed penalties and interest in the amount of $1.3 million for Harvest Vinccler’s failure to withhold VAT. In July 2008, the SENIAT adjusted the assessment for penalties and interest to the change in tax units as mandated by the Venezuelan tax code and issued a new assessment for $2.3 million. The change in assessment resulted in an additional $1.0 million expense recorded in the year ended December 31, 2008. A tax court has ruled against the SENIAT stating that penalties and interest cannot be calculated on tax units. The case is currently pending a decision in the Venezuelan Supreme Court. The SENIAT has recognized a payment made by Harvest Vinccler in 2006 for the underwithheld VAT and has partially confirmed that some of the affected vendors have remitted the underwithheld VAT. Harvest Vinccler has received credit, less penalties and interest, from the SENIAT for the VAT remitted by the vendors. Harvest Vinccler has filed claims against the SENIAT for the portion of VAT not recognized by the SENIAT and believes it has a substantial basis for its position. In August 2008, Harvest Vinccler filed an appeal in the tax courts and presented a proposed settlement with the SENIAT. In October 2008, after consideration of our proposed settlement, the SENIAT offered a counter-proposal which Harvest Vinccler has tentatively accepted. In January 2009, the case was suspended while the tax court notified the Venezuelan General Attorney’s Office (“GAO”) of our intention to settle the case. The Venezuelan Tax Code establishes that once the taxpayer files a request to settle a case, the tax court will admit the request and suspend the filing for 60 consecutive court working days following the notification of the GAO. The 60 consecutive court working days are for the taxpayer and GAO to agree on the terms of settlement to be proposed to the tax court. In Harvest Vinccler’s case, the wording of the settlement is in the advanced stages, the amounts are already agreed upon and comments were received from the GAO on April 24, 2009. The suspension of the case expired June 30, 2009, but the GAO agreed to extend the suspension for another 40 court working days. With such extension, the Court case is still suspended while the GAO waits for confirmation from the Finance Ministry. The GAO will monitor the case to obtain authorization from the SENIAT before the extension expires. We are waiting for final confirmation from the SENIAT.

See our Annual Report on Form 10-K for the year ended December 31, 2008 for a description of certain other legal proceedings. There have been no material developments in such legal proceedings since the filing of such Annual Report.

Item 1A. Risk Factors

PDVSA has recently failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. In addition, PDVSA has recently failed to pay on a timely basis certain amounts owed to Petrodelta with which Petrodelta pays its contractors. Not making timely payments to contractors makes it more difficult for Petrodelta to obtain the services of contractors, which difficulty is having an adverse effect on Petrodelta’s business. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise

use to pay its contractors. As a result, Petrodelta has experienced, and may continue to experience, difficulty in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is having an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.

See our Annual Report on Form 10-K for the year ended December 31, 2008 underItem 1A Risk Factorsfor a description of other risk factors. There have been no other changes during the quarter ended June 30, 2009 to those risk factors.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

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

At our Annual Meeting of Stockholders held on May 21, 2009, the following items were voted on by the Stockholders:

1. To approve the Election of Directors:


	Votes in Favor		Votes Against/Withheld
Stephen D. Chesebro’		27,993,212		737,568
James A. Edmiston		28,069,211		661,569
Dr. Igor Effimoff		23,276,967		5,453,813
H. H. Hardee		23,102,836		5,627,944
Robert E. Irelan		23,196,513		5,534,267
Patrick M. Murray		27,646,412		1,084,368
J. Michael Stinson		23,318,623		5,412,157

2. To ratify the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm for the year ended December 31, 2009:


	Against/Withheld	Abstentions/Broker Non-
Votes in Favor	Votes	Votes
28,401,402	266,459	62,919

3. To approve an amendment that increases the number of shares of common stock available for issuance under our 2006 Long Term Incentive Plan by 700,000 shares and raises the limitation on grants of full value awards by no more than 350,000 of these 700,000 shares.


	Against/Withheld	Abstentions/Broker Non-
Votes in Favor	Votes	Votes
11,198,072	11,822,474	5,710,234


		Item 6. Exhibits

(a)

Exhibits

	3.1		Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1(i) to our Form 10-Q filed on August 13, 2002, File No. 1-10762.)

	3.2		Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on April 23, 2007, File No. 1-10762.)

	4.1		Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.1 to our Form 10-K filed on March 17, 2008, File No. 1-10762.)

	4.2		Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.)

	4.3		Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A filed on October 23, 2007, File No. 1-10762.)

	10.1		Form of Stock Appreciation Right Award Agreement.

	10.2		Form of Stock Unit Award Agreement.

	31.1		Certification of the principal executive officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2		Certification of the principal financial officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1		Certification accompanying Quarterly Report on Form 10-Q 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 Quarterly Report on Form 10-Q 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.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	HARVEST NATURAL RESOURCES, INC.
Dated: August 4, 2009	By:	/s/James A. Edmiston
		James A. Edmiston
		President and Chief Executive Officer


Dated: August 4, 2009	By:	/s/ Stephen C. Haynes
		Stephen C. Haynes
		Vice President - Finance, Chief Financial Officer and Treasurer

Exhibit Index


Exhibit
Number		Description

	3.1	Amended and Restated Certificate of Incorporation (Incorporated by reference to Exhibit 3.1(i) to our Form 10-Q filed on August 13, 2002, File No. 1-10762).

	3.2	Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on April 23, 2007, File No. 1-10762.)

	4.1	Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.1 to our Form 10-K filed on March 17, 2008. File No. 1-10762.)

	4.2	Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.)

	4.3	Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A filed on October 23, 2007, File No. 1-10762.)

	10.1	Form of Stock Appreciation Right Award Agreement.

	10.2	Form of Stock Unit Award Agreement.

	31.1	Certification of the principal executive officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification of the principal financial officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1	Certification accompanying Quarterly Report on Form 10-Q 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 Quarterly Report on Form 10-Q 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.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Avg

Large accelerated filero

Accelerated filerþ

Non-accelerated filero

Smaller reporting companyo

(Do not check if smaller reporting company)