e10vq

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 September 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.

Yes þ No o

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).

Yes o No o

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


Large Accelerated Filer o		Accelerated Filer þ		Non-Accelerated Filer o (Do not check if a smaller reporting company)		Smaller Reporting Company o

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

Yes o No þ

At October 28, 2009, 33,196,385 shares of the Registrant’s Common Stock were outstanding.

PART I. FINANCIAL INFORMATION


Item 1.		Financial Statements

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	September 30,			December 31,
	2009			2008
	(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	48,989		$	97,165
Accounts and notes receivable, net		11,574			11,570
Advances to equity affiliate		4,405			3,732
Prepaid expenses and other		2,765			3,964

TOTAL CURRENT ASSETS		67,733			116,431

OTHER ASSETS		3,512			3,316
INVESTMENT IN EQUITY AFFILIATES		220,008			218,982
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		48,010			22,328
Other administrative property		3,090			2,368

		51,100			24,696
Accumulated depreciation and amortization		(1,233	)		(1,159	)

		49,867			23,537

	$	341,120		$	362,266


LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable, trade and other	$	909		$	1,662
Advance from equity affiliate		—			20,750
Accrued expenses		12,133			12,241
Accrued interest		4,691			4,691
Income taxes payable		1,076			77

TOTAL CURRENT LIABILITIES		18,809			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 September 30, 2009 and December 31, 2008, respectively; issued 39,340 shares and 39,128 shares at September 30, 2009 and December 31, 2008, respectively		393			391
Additional paid-in capital		212,193			208,868
Retained earnings		121,169			129,351
Treasury stock, at cost, 6,448 shares and 6,444 shares at September 30, 2009 and December 31, 2008, respectively		(65,383	)		(65,368	)

TOTAL HARVEST STOCKHOLDERS’ EQUITY		268,372			273,242
NONCONTROLLING INTEREST		53,939			49,603

TOTAL EQUITY		322,311			322,845

	$	341,120		$	362,266

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands, except per share data)
OPERATING EXPENSES
Depreciation	$	125		$	49		$	282		$	141
Exploration expense		887			4,837			5,315			9,052
General and administrative		6,066			6,700			18,965			19,334
Taxes other than on income		208			(965	)		766			(507	)

		7,286			10,621			25,328			28,020


LOSS FROM OPERATIONS		(7,286	)		(10,621	)		(25,328	)		(28,020	)

OTHER NON-OPERATING INCOME (EXPENSE)
Gain on financing transactions		—			—			—			3,421
Investment earnings and other		224			1,122			851			3,004
Interest expense		—			(22	)		—			(1,741	)

		224			1,100			851			4,684


LOSS FROM CONSOLIDATED COMPANIES BEFORE INCOME TAXES		(7,062	)		(9,521	)		(24,477	)		(23,336	)

INCOME TAX EXPENSE (BENEFIT)		109			(20	)		1,145			81

LOSS FROM CONSOLIDATED COMPANIES		(7,171	)		(9,501	)		(25,622	)		(23,417	)

NET INCOME FROM UNCONSOLIDATED EQUITY AFFILIATES		9,890			5,309			21,776			23,527


NET INCOME (LOSS)		2,719			(4,192	)		(3,846	)		110

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		1,936			1,045			4,336			4,775


NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST	$	783		$	(5,237	)	$	(8,182	)	$	(4,665	)


NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST PER COMMON SHARE:
Basic	$	0.02		$	(0.16	)	$	(0.25	)	$	(0.14	)

Diluted	$	0.02		$	(0.16	)	$	(0.25	)	$	(0.14	)

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Nine Months Ended September 30,
	2009			2008
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(3,846	)	$	110
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation		282			141
Net income from unconsolidated equity affiliates		(21,776	)		(23,527	)
Non-cash compensation-related charges		3,105			4,061
Gain on financing transactions		—			(3,421	)
Dividends received from equity affiliate		—			72,530
Changes in operating assets and liabilities:
Accounts and notes receivable		(4	)		1,121
Advances to equity affiliate		(673	)		13,116
Prepaid expenses and other		(1,606	)		(2,979	)
Accounts payable		(753	)		(4,354	)
Accounts payable, related party		—			(10,093	)
Accrued expenses		496			(1,364	)
Accrued interest		—			(420	)
Income taxes payable		999			(326	)

NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(23,776	)		44,595


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions of property and equipment		(22,696	)		(17,239	)
Decrease in restricted cash		—			6,769
Investment costs		(372	)		(1,141	)

NET CASH USED IN INVESTING ACTIVITIES		(23,068	)		(11,611	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuances of common stock		222			1,345
Purchase of treasury stock		—			(28,393	)
Dividends paid to noncontrolling interest		—			(358	)
Financing costs		(1,554	)		(923	)
Payments of notes payable		—			(7,211	)

NET CASH USED IN FINANCING ACTIVITIES		(1,332	)		(35,540	)


NET DECREASE IN CASH AND CASH EQUIVALENTS		(48,176	)		(2,556	)

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

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	48,989		$	118,285

Supplemental Schedule of Noncash Investing and Financing Activities:

During the nine months ended September 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 3,757 shares being added to treasury stock at cost.

During the nine months ended September 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 Nine Months Ended September 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 September 30, 2009, and the results of operations for the three and nine months ended September 30, 2009 and 2008, and cash flows for the nine months ended September 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 in West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), and onshore in the Sultanate of Oman (“Oman”). See Note 6 — United States Operations, Note 7 — Indonesia, Note 8 — Gabon and Note 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.

Reporting and Functional Currency

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

Investment in Equity Affiliates

Investments in unconsolidated companies in which we have less than a 50 percent interest and have significant influence are accounted for under the equity method of accounting. Investment in equity affiliates is increased by additional investments and earnings and decreased by dividends and losses. We review our Investment in equity affiliates for impairment whenever events and circumstances indicate a decline in the recoverability of its carrying value.

Fair Value Measurements

We adopted the accounting standard for fair value measurements for financial assets as of January 1, 2008. We adopted this standard for non-financial assets and liabilities as of January 1, 2009. This standard provides guidance for using fair value to measure assets and liabilities. This standard also clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing the asset or liability. The standard establishes a fair value hierarchy, giving the highest priority to quoted prices in active markets and the lowest priority to unobservable data. The standard applies whenever other standards require assets or liabilities to be measured at fair value. The adoption of this standard had no impact on our consolidated financial position, results of operations or cash flows.

At September 30, 2009 and December 31, 2008, cash and cash equivalents include $42.2 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 the accounting standard for fair value measurements.

Property and Equipment

Our accounting method for oil and gas exploration and development activities is the successful efforts method. We have $48.0 million and $22.3 million in oil and gas properties as of September 30, 2009 and December 31, 2008, respectively, all of which is unproved property. During the three and nine months ended September 30, 2009, we incurred $0.3 million and $3.1 million, respectively, of exploration costs related to the processing and reprocessing of seismic data for our foreign operations, and $0.6 million and $2.2 million, respectively, related to other general business development activities. In addition, in the first quarter of 2009, we reclassified $2.8 million of lease bonus associated with our Antelope project from Prepaid expenses and other to Oil and gas properties, and in the second quarter of 2009, we reclassified $1.4 million of Oman acquisition costs from Other assets to Oil and gas properties. See Note 6 — United States Operations and Note 9 — Oman.

Noncontrolling Interests

We adopted the accounting standard for noncontrolling interests in consolidated financial statements as of January 1, 2009. This standard establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. This standard also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owner. The adoption of this standard 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 net income (loss) attributable to Harvest 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 33.2 million and 33.0 million for the three and nine months ended September 30, 2009, respectively, and 33.6 million and 34.5 million for the three and nine months ended September 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 33.5 million and 33.0 million for the three and nine months ended September 30, 2009, respectively, and 33.6 million and 34.5 million for the three and nine months ended September 30, 2008, respectively.

An aggregate of 3.2 million and 3.8 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 nine months ended September 30, 2009, respectively. An aggregate of 4.3 million and 4.1 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 nine months ended September 30, 2008, respectively.

Stock options to purchase 0.1 million shares of common stock were exercised in the nine months ended September 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 nine months ended September 30, 2008 resulting in cash proceeds of $1.3 million.

New Accounting Pronouncements

In September 2009, the Financial Accounting Standards Board (“FASB”) issued its proposed updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure requirements of Extractive Industries — Oil and Gas (Topic 932) with the requirements in the Securities and Exchange Commission’s (“SEC”) final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and is effective for the year ended December 31, 2009. The public comment period for the FASB’s proposed updates ended October 15, 2009; however, no final guidance has been issued by the FASB. We are evaluating the potential impact of any updates to the oil and gas accounting rules and will comply with any new accounting and disclosure requirements once they become effective.

Reclassifications

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

Note 2 — Commitments and Contingencies

Liquidity — Based on our cash balance of $49 million at September 30, 2009, we will be required to raise additional funds in order to fund our 2010 forecasted operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration projects and to a lesser extent general and administrative costs. Currently, our only source of cash is dividends from Petrodelta. However, there is no certainty that Petrodelta will pay dividends in 2009 or 2010. Our lack of cash flow and the unpredictability of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance adequate financing can be raised. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, exploration of our properties worldwide, and cost reductions. In addition, we could delay discretionary capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, if necessary. There can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.

Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-Vinccler, C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, Texas. This suit was brought in May 2003 by Excel alleging, among other things, breach of a consulting agreement between Excel and us, misappropriation of proprietary information and trade secrets, and fraud. Excel seeks actual and exemplary damages, injunctive relief and attorneys’ fees. In April 2007, the court set the case for trial. The trial date, reset for the first quarter of 2009, had been stayed indefinitely. On October 20, 2009, the stay was lifted although no trial date has been set. We dispute Excel’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.

Uracoa Municipality Tax Assessments. Our Venezuelan subsidiary, Harvest Vinccler, 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.

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 several extensions. With such extensions, the court case is still suspended while the GAO waits for confirmation from the Finance Ministry. In September 2009, the Finance Minister issued an opinion in favor of the settlement. In October 2009, the SENIAT confirmed their recommendation to settle the case based on the amounts already negotiated. Final negotiations are on-going.

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					Nine Months Ended
	September 30,					September 30,
	2009		2008			2009		2008
	(in thousands)
Franchise Taxes	$	42	$	(1,074	)	$	141	$	(991	)
Payroll and Other Taxes		166		109			625		484

	$	208	$	(965	)	$	766	$	(507	)

During the nine months ended September 30, 2008, we reversed a $1.1 million franchise tax provision that was no longer required.

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						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands)
Segment Income (Loss)
Venezuela	$	9,706		$	4,642		$	22,496		$	22,750
Indonesia		(1,129	)		(4,402	)		(3,921	)		(6,176	)
United States and other		(7,794	)		(5,477	)		(26,757	)		(21,239	)

Net income (loss) attributable to Harvest	$	783		$	(5,237	)	$	(8,182	)	$	(4,665	)


	September 30,			December 31,
	2009			2008
	(in thousands)
Operating Segment Assets
Venezuela	$	234,804		$	231,755
Indonesia		4,618			1,556
United States and other		140,305			152,184

		379,727			385,495
Intersegment eliminations		(38,607	)		(23,229	)

	$	341,120		$	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 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 operations or cash flows. However, the new reserve could have a negative impact on the amount of dividends received in the future.

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) in the fourth quarter of 2008 for contributions to LOCTI. The waiver to file the declaration on a consolidated basis has to be requested each year and granted each year. Since Petrodelta expects PDVSA to continue requesting and receiving waivers and to have sufficient contributions, Petrodelta has not accrued a liability to LOCTI for the nine months ended September 30, 2009. The potential exposure to LOCTI for the nine months ended September 30, 2009 is $7.1 million, $3.6 million net of tax ($1.1 million net to our 32 percent interest).

Petrodelta’s reporting and functional currency is the U.S. Dollar. Petrodelta’s financial information is prepared in accordance with International Financial Reporting Standards (“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 September 30, 2009 and December 31, 2008 and for the three and nine months ended September 30, 2009 and 2008 (in thousands, except per unit information):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Barrels of oil sold		1,938			1,496			5,670			3,943
Thousand cubic feet of gas sold		913			2,843			3,633			9,064
Total barrels of oil equivalent		2,090			1,970			6,276			5,454

Average price per barrel	$	63.33		$	85.21		$	52.89		$	82.66
Average price per thousand cubic feet	$	1.54		$	1.54		$	1.54		$	1.54

Revenues:
Oil sales	$	122,731		$	127,489		$	299,914		$	325,921
Gas sales		1,409			4,378			5,608			13,992
Royalty		(41,510	)		(55,765	)		(102,422	)		(132,888	)

		82,630			76,102			203,100			207,025

Expenses:
Operating expenses		9,054			20,076			41,579			53,270
Depletion, depreciation and amortization		7,002			5,423			23,715			17,475
General and administrative		2,347			2,693			11,561			6,427
Taxes other than on income		1,254			3,541			2,789			10,629

		19,657			31,733			79,644			87,801

Income from operations		62,973			44,369			123,456			119,224

Investment Earnings and Other		—			7,397			3			12,405


Income before Income Tax		62,973			51,766			123,459			131,629

Current income tax expense		36,251			29,600			68,451			60,211
Deferred income tax benefit		(16,153	)		(10,495	)		(39,520	)		(25,471	)

Net Income		42,875			32,661			94,528			96,889
Adjustment to reconcile to reported Net Income From Unconsolidated Equity Affiliate:
Deferred income tax benefit		16,011			8,561			32,098			24,991

Net Income Equity Affiliate		26,864			24,100			62,430			71,898
Equity interest in unconsolidated equity affiliate		40	%		40	%		40	%		40	%

Income before amortization of excess basis in equity affiliate		10,746			9,640			24,972			28,759
Amortization of excess basis in equity affiliate		(330	)		(313	)		(993	)		(865	)
Conform depletion expense to GAAP		28			(1,516	)		468			(1,774	)
Reserve for interest receivable (net of tax)		—			(2,428	)		—			(2,428	)

Net income from unconsolidated equity affiliate	$	10,444		$	5,383		$	24,447		$	23,692


	September 30,		December 31,
	2009		2008
Current assets	$	412,872	$	311,017
Property and equipment		258,766		211,760
Other assets		137,030		97,323
Current liabilities		333,662		260,234
Other liabilities		39,786		19,174
Net equity		435,220		340,692

Fusion Geophysical, LLC (“Fusion”)

We own a 49 percent 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 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 nine months ended September 30, 2009 and 2008, respectively. Summarized financial information for Fusion follows (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Operating Revenues	$	2,751		$	2,627		$	8,095		$	7,621

Net Income (Loss)	$	(210	)	$	200		$	(3,581	)	$	727
Equity interest in unconsolidated equity affiliate		49	%		45	%		49	%		45	%

Net income (loss) from unconsolidated equity affiliate		(103	)		90			(1,755	)		327
Amortization of fair value of intangibles		(451	)		(164	)		(916	)		(492	)

Net loss from unconsolidated equity affiliate	$	(554	)	$	(74	)	$	(2,671	)	$	(165	)


	September 30,		December 31,
	2009		2008
Current assets	$	3,155	$	7,864
Total assets		27,484		30,633
Current liabilities		7,218		7,294
Total liabilities		9,087		8,281

Approximately 12.7 percent and 31.1 percent of Fusion’s revenue for the three and nine months ended September 30, 2009, respectively, was earned from Harvest or equity affiliates. Approximately 35.9 percent and 20.9 percent of Fusion’s revenue for the three and nine months ended September 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. Services rendered have been applied against the prepayment, and as of September 30, 2009, the balance for prepaid services was approximately $1.4 million.

During the nine months ended September 30, 2009, we updated the review for impairment of our equity investment in Fusion. The initial review at June 30, 2009 and subsequent update as of September 30, 2009 was performed using the equity method of accounting for investments in common stock accounting standard. In preparing this update, future net cash flows prepared by Fusion based on different business opportunities that Fusion is currently pursuing were updated for current activities. These business opportunities were weighted with a probability of success. Based on this updated review, there was no impairment to the carrying value of $2.3 million to our equity investment in Fusion at September 30, 2009.

Note 6 — United States Operations

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 private third party is obligated to evaluate and present additional opportunities at their sole cost. As each prospect is accepted it will be covered by the AMI. Although several additional potential prospects 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 September 30, 2009. At June 30, 2009, we had met the $20 million funding obligation under the terms of the AMI. All costs incurred after June 30, 2009 are being shared by the parties in proportion to their working interests as defined in the AMI.

Gulf Coast AMI — West Bay Project

Interpretation of 3-D seismic data on the West Bay project was completed during the second quarter 2009 and resulted in the identification of a revised set of drilling leads and prospects for the West Bay project. On July 14, 2009, we, along with our partner in the AMI, acquired 880 acres of shallow water offshore bay leases representing two separate tracts from the State of Texas General Land Office at a state lease sale for a total gross cost of $0.5 million. Acquisition of these two tracts completes the planned land acquisition activities on the West Bay project.

The AMI participants are currently evaluating the leads and prospects and developing drilling plans for the West Bay project. Depending on the selected drilling prospects and locations, the drilling may or may not require permit(s) from the U.S. Army Corps of Engineers — Galveston District (“Corps of Engineers”). We expect to firm up plans for initial drilling on the West Bay project during the fourth quarter 2009, with the expectation of initial drilling on the project in 2010. The West Bay project represents $4.0 million and $3.7 million, respectively, of oil and gas properties on our September 30, 2009 and December 31, 2008 balance sheets.

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 Antelope project. The private third party is obligated to assemble the lease position on the Antelope project. The JEDA provides that we would earn our initial 50 percent working interest in the Antelope project by compensating the private third party for leases acquired in accordance with terms defined in the JEDA, and by drilling and completing one deep natural gas test well (the Bar F #1-20-3-2 [“Bar F”]) at our sole expense. In November 2008, we entered into a Letter Agreement/Amendment of the JEDA (the “Letter Agreement”) with the private third party. The Letter Agreement clarifies several open issues in the JEDA, such as classification of $2.7 million of prepaid land costs for the Antelope 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 Antelope project prior to the Bar F. Per the Letter Agreement, payment of the $2.7 million note receivable was due from the private third party on or by spud date of the Bar F. Since payment was not received prior to spud, our interest in the Antelope project was increased to 60 percent, with the incremental 10 percent working interest being earned by drilling and completing the Bar F. The note receivable remains outstanding and will be collected through sales revenues taken from a portion of the private third party’s net revenue from the Bar F provided the Bar F is commercial. As of September 30, 2009, we held approximately 61,232 gross undeveloped acres under lease (36,739 acres net to us) in the Antelope project. On October 26, 2009, we, along with our partner in the JEDA, acquired 1,304 gross acres (782 acres net to us) of leases representing eight separate tracts from the State of Utah at a state lease sale for a total gross cost of $0.3 million.

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 has been completed. The well reached total depth of 17,566 feet on October 8, 2009 and production casing has been run. Production testing of the well is expected to commence in November 2009 with the expectation that the testing program will be completed in early 2010. Operational activities on the Antelope project during the quarter primarily focused on drilling of the Bar F and pursuing additional leases. The Antelope project represents $28.5 million and $8.2 million, respectively, of oil and gas properties on our September 30, 2009 and December 31, 2008 balance sheets.

definitive Participation Agreement with a previously non-consenting third party industry partner to undertake a joint drilling project covering an area of 332 acres encompassing these eight wells. The industry partner will be the operator of the eight wells. Our average working interest in the eight wells will be approximately 43 percent. The Board of DOGM approved our request for forced pooling of the remaining non-consenting interests in the 332 acres at a hearing on October 28, 2009. On October 29, 2009, we received the drilling permits for all eight wells. 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 first two of the eight shallow oil wells in the fourth quarter 2009 with the remaining six wells expected to be drilled in late 2009 or early 2010.

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 two exploratory wells. After the commitment of each component is met, all subsequent costs will be shared by the parties in proportion to their ownership interests. The $6.5 million carry obligation for the 2-D seismic acquisition was met in December 2008. Prior to drilling the first exploration well, subject to the estimated cost of that well, our partner will have a one-time option to increase the level of the carried interest to $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, the work commitment included the acquisition of 300 kilometers of 2-D seismic and drilling two exploration wells. An acquisition program of 650 kilometers of 2-D seismic was completed in 2008. Processing and interpretation of the 2-D seismic data was completed in the second quarter 2009 and current activities include well planning. It is expected that the first of two exploration wells will spud in the fourth quarter of 2009. The Budong PSC represents $0.4 million and $0.2 million, respectively, of oil and gas properties on our September 30, 2009 and December 31, 2008 balance sheets.

Note 8 — Gabon

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

The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources (“Republic of Gabon”), entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. The second exploration phase comprises a three-year work commitment which includes the acquisition and processing of 500 kilometers of 2-D seismic, geology and geophysical interpretation, engineering studies and the drilling of a conditional well. In October 2008, the acquisition of 650 kilometers of 2-D seismic was completed, and during the first six months of 2009, this data was processed along with the reprocessing of approximately 640 kilometers of existing 2-D seismic data. Current activities include the interpretation 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 the 3-D seismic should be completed in the fourth 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 $6.8 million and $5.9 million, respectively, of oil and gas properties on our September 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 have a 100 percent working interest in Block 64 EPSA during the exploration phase. Oman Oil Company has the option to back-in to up to a 20 percent interest in Block 64 EPSA after the discovery of gas.

Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate which the Oman Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). PDO will continue to produce oil from several fields within Block 64 EPSA area. The 3,867 square kilometer (955,600 acres) block is located in the gas and condensate rich Ghaba Salt Basin in close proximity to the Barik, Saih Rawl and Saih Nihayda gas and condensate fields. We have an obligation to drill two wells over a three year period with a funding commitment of $22.0 million. Current activities include the compilation of existing data, preparation for 3-D pre-stack depth migration reprocessing and initiation of a baseline environmental survey. During the nine months ended September 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 $3.8 million of oil and gas properties on our September 30, 2009 balance sheet.

Note 10 — Subsequent Events

We have performed an evaluation of subsequent events through November 5, 2009, which is the date the financial statements were issued.

On October 26, 2009, we, along with our partner in the JEDA, acquired 1,304 gross acres (782 acres net to us) of leases representing eight separate tracts from the State of Utah at a state lease sale for a total gross cost of $0.3 million.

On October 29, 2009, we received drilling permits for eight shallow oil wells on the Antelope prospect from the State of Utah.

On November 4, 2009, we filed a universal shelf registration statement on Form S-3 with the SEC. The registration statement is subject to review by the SEC. The shelf registration will allow us the flexibility from time to time to offer up to $300 million of equity, debt or other types of securities described in the registration statement, or any combination of such securities. There is no guarantee that securities can or will be issued under this registrations statement.

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 holding a noncontrolling interest in a corporation, the permitting and the drilling of oil and natural gas wells, the availability of materials and supplies necessary to projects and operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, the Company’s ability to acquire oil and natural gas properties that meet its objectives, availability and cost of drilling rigs, 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 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 onshore in the Sultanate of Oman (“Oman”).

Venezuela

During the nine months ended September 30, 2009, Petrodelta drilled and completed 12 successful development wells and two appraisal wells, sold approximately 5.7 million barrels of oil and sold 3.6 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 20,771 barrels of oil per day during the nine months ended September 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 had to take actions to reduce both operating and capital expenditures. See Item 1A — Risk Factors in Part II of this Quarterly Report on Form 10-Q for additional information regarding Petroleos de Venezuela, S.A. (“PDVSA”). Due to the situation described in Item 1A — Risk Factors, Petrodelta’s working capital position continues to deteriorate.

Petrodelta’s 2009 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 El Salto field and presently non-producing Isleño field. However, Petrodelta had to reduce its rig count to one drilling rig for most of the second and all of the third quarter 2009 while rigs and drilling contracts are renegotiated. Petrodelta is expected to utilize only one rig during the fourth quarter of 2009 to drill both development wells and appraisal wells. Petrodelta’s management is reviewing options to hire an additional drilling rig and a workover rig for early 2010.

Petrodelta began the appraisal and testing of its large portfolio of undeveloped resources in the second quarter of 2009. During the second quarter 2009, Petrodelta drilled two successful appraisal wells in the El Salto field, and pilot production commenced from one of the appraisal wells through temporary facilities. The well commenced production on July 18, 2009 and has produced 243,000 barrels of oil through the end of October 2009. The second appraisal well is still waiting on permits from the Ministry of Energy and Petroleum (“MENPET”) for testing.

During the third quarter 2009, we commissioned an interim reserve report for Petrodelta to assess and secure the growth potential of the Temblador and El Salto fields. The reserve report reflects a 10 percent increase in proved reserves to 47.6 million barrels of oil equivalent (MMBOE) (net to our 32 percent interest) at August 31, 2009, as compared to year-end 2008. The increase was driven primarily by the drilling of the two appraisal wells in Petrodelta’s largely undeveloped El Salto field.

In our Annual Report on Form 10-K for the year ended December 31, 2008, we reported that Petrodelta had not received all information regarding production during the conversion period for the Temblador field in order to invoice all volumes produced in that field during that period. As Temblador production was handled in PDVSA system, PDVSA had allocated only partial, estimated production to Petrodelta. As a result, Petrodelta had not, and still has not, received full credit for the Temblador field production. Discussions are ongoing to settle figures. During the third quarter 2009, Petrodelta completed the facilities and pipelines to segregate approximately 80 percent of the Temblador field’s production out of PDVSA’s system.

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. Since Petrodelta expects PDVSA to continue requesting and receiving waivers, Petrodelta has not accrued a liability to LOCTI for the nine months ended September 30, 2009. The potential exposure to LOCTI for the nine months ended September 30, 2009 is $7.1 million, $3.6 million net of tax ($1.1 million net to our 32 percent interest).

Certain operating statistics for the three and nine months ended September 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				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
Oil production (million barrels)		1.9		1.5		5.7		3.9
Natural gas production (billion cubic feet)		0.9		2.8		3.6		9.1
Barrels of oil equivalent		2.1		2.0		6.3		5.5
Operating expense ($millions)		9.1		20.1		41.6		53.3
Capital expenditures ($millions)		20.6		9.1		69.6		18.5

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 $63.33 and $52.89 per barrel for the three and nine months ended September 30, 2009, respectively. Market prices for crude oil of the type produced in the fields operated by Petrodelta averaged approximately $85.21 and $82.66 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 nine months ended September 30, 2008, respectively. The Windfall Profits Tax takes effect when the average price of oil exceeds $70 per barrel. The price for natural gas is $1.54 per thousand cubic feet. The decrease in gas production is due to reservoir management. Petrodelta’s reporting and functional currency is the U.S. Dollar.

United States

Gulf Coast — West Bay

During the nine months ended September 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 West Bay project was completed in the second quarter 2009 and resulted in the identification of a revised set of drilling leads and prospects for the project. On July 14, 2009, we, along with our partner in the AMI, acquired 880 acres of shallow water offshore bay leases representing two separate tracts from the State of Texas General Land Office at a state lease sale for a total gross cost of $0.5 million. Acquisition of these two tracts completes the planned land acquisition activities on the project.

The AMI participants are currently evaluating the leads and prospects to determine priorities and drilling plans for the West Bay project. Depending on the selected drilling prospects and locations, the drilling may or may not require permit(s) from the U.S. Army Corps of Engineers — Galveston District (“Corps of Engineers”). We expect to firm up plans for initial drilling on the West Bay project during the fourth quarter 2009, with the expectation of initial drilling on the West Bay project in 2010. During the nine months ended September 30, 2009, we incurred $0.5 million for lease acquisition, surveying, permitting and site preparation and $1.4 million for seismic interpretation.

There is no expected remaining 2009 budget left for this project exclusive of the cost of preparations for drilling the initial well.

Western United States — Antelope

During the nine months ended September 30, 2009, operational activities in the Antelope prospect focused on continuing leasing activities on private, Allottee, and tribal land, and surveying, preliminary engineering, permitting preparations, and conducting drilling operations on a deep natural gas test well (the Bar F #1-20-3-2 [“Bar F”]) that commenced drilling on June 15, 2009. The Bar F is a tight hole and is permitted to 18,000 feet. Drilling has been completed. The well reached total depth of 17,566 feet on October 8, 2009 and production casing has been run. Production testing of the well is expected to commence in November 2009 with the expectation that the testing program will be completed in early 2010. During the nine months ended September 30, 2009, we

incurred $17.6 million for drilling, lease acquisition, surveying, permitting and site preparation and $0.3 million for seismic program planning. The expected remaining 2009 budget for the Antelope project is $7.0 million.

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 have signed a definitive Participation Agreement with a previously non-consenting third party industry partner to undertake a joint drilling project covering an area of 332 acres encompassing these eight wells. The industry partner will be the operator of the eight wells. Our average working interest in the eight wells will be approximately 43 percent. The Board of DOGM approved our request for forced pooling of the remaining non-consenting interests in the 332 acres at a hearing on October 28, 2009. On October 29, 2009, we received the drilling permits for all eight wells. 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 first two of the eight shallow oil wells in the fourth quarter 2009 with the remaining six wells expected to be drilled in late 2009 or early 2010.

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

The interpretation of 650 kilometers of 2-D seismic was completed in the third quarter 2009. Current activities include 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 nine months ended September 30, 2009, we incurred $0.1 million for surveying, permitting, engineering and well planning and $1.2 million for seismic processing and interpretation. 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 processing of 650 kilometers of 2-D seismic and the reprocessing of 680 kilometers of vintage 2-D seismic was completed in the third quarter 2009. Current activities include the interpretation 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 the 3-D seismic should be completed in the fourth quarter 2009. We expect the seismic to mature the prospect inventory to make a decision in 2009 for a well in 2010. During the nine months ended September 30, 2009, we incurred $0.9 million for seismic processing and reprocessing. The projected remaining 2009 project expenditures (net to our working interest) for exploration activities are $1.4 million.

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 have a 100 percent working interest in the Block 64 EPSA during the exploration phase. Oman Oil Company has the option to back-in to up to a 20 percent interest in the Block 64 EPSA after the discovery of gas.

Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate which the Oman Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). PDO will continue to produce oil from several fields within 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. Current activities include the compilation of existing data, preparation for 3-D pre-stack depth migration reprocessing and initiation of a baseline environmental survey. During the nine months ended September 30, 2009, we incurred $2.4 million for costs associated with signing the license, including signature bonus and data compilation and $0.1 million for seismic processing and reprocessing. There is no expected remaining 2009 budget left for this project. 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 $2.1 million during the nine months ended September 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. See Item 1A — Risk Factors and Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2008 and Item 1A — Risk Factors in Part II of this Quarterly Report on Form 10-Q for a more complete description of the situation in Venezuela and other matters.

Based on our cash balance of $49 million at September 30, 2009, we will be required to raise additional funds in order to fund our 2010 forecasted operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration projects and to a lesser extent general and administrative costs. Through September 30, 2009, our exploration expenditures outside of Venezuela have not resulted in new proved reserves. If we are not able to raise additional capital, there will be a need to reduce our projected expenditures which could limit our ability to operate our business. Currently, our only source of cash is dividends from Petrodelta, for which we recently announced an increase in proved reserves net to Harvest from 43.3 million barrels of oil equivalent (“MMBOE”) at December 31, 2008 to 47.6 MMBOE at August 31, 2009. This increase in Petrodelta proved reserves could potentially provide an increase in cash dividends to Harvest in future years. However, there is no certainty that Petrodelta will pay dividends in 2009 or 2010. Our lack of cash flow and the unpredictability of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance adequate financing can be raised. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, exploration of our properties worldwide, and cost reductions. In addition, we could delay discretionary capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, if necessary. There can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.

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:


	Nine Months Ended September 30,
	2009			2008
	(in thousands)
Net cash provided by (used in) operating activities	$	(23,776	)	$	44,595
Net cash used in investing activities		(23,068	)		(11,611	)
Net cash used in financing activities		(1,332	)		(35,540	)

Net decrease in cash	$	(48,176	)	$	(2,556	)

At September 30, 2009, we had current assets of $67.7 million and current liabilities of $18.8 million, resulting in working capital of $48.9 million and a current ratio of 3.6:1. 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 $28.1 million was primarily due to a reduction in cash and cash equivalents, primarily for capital expenditures and operating expenses.

Cash Flow from Operating Activities. During the nine months ended September 30, 2009, net cash used in operating activities was approximately $23.8 million. During the nine months ended September 30, 2008, net cash provided by operating activities was approximately $44.6 million. The $68.4 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 nine months ended September 30, 2009, we had cash capital expenditures of approximately $22.7 million. Of the 2009 expenditures, $17.6 million was attributable to activity on the Antelope project, $2.4 million to Block 64 EPSA, $0.1 million to Budong PSC, $0.5 million to the West Bay project and $2.1 million to other projects. During the nine months ended September 30, 2008, we had cash capital expenditures of approximately $17.2 million. Of the 2008 expenditures, $3.0 million was attributable to activity on the West Bay project, $6.1 million to the Dussafu PSC, $2.7 million to the Antelope project, $3.3 million to the Harvest Hunter #1 project, $1.1 million to the Stark project and $1.0 million was attributable to other projects.

During the nine months ended September 30, 2008, $6.8 million of restricted cash used as collateral for loans which were repaid was returned to us. During the nine months ended September 30, 2009 and 2008, we incurred $0.4 million and $1.1 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, future Petrodelta dividends, financing sources, accessing of equity markets or sale of assets, as necessary.

Cash Flow from Financing Activities. During the nine months ended September 30, 2009 and 2008, we incurred $1.6 million and $0.9 million, respectively, in legal fees associated with prospective financing. During the nine months ended September 30, 2008, Harvest Vinccler repaid 20 million Bolivars (approximately $9.3 million) of its Bolivar denominated debt, we paid a $0.4 million dividend to our noncontrolling interest, 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 nine months ended September 30, 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 nine months ended September 30, 2009 and 2008 and the financial condition as of September 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 September 30, 2009 Compared with Three Months Ended September 30, 2008

We reported net income attributable to Harvest of $0.8 million, or $0.02 diluted earnings per share, for the three months ended September 30, 2009 compared with a net loss attributable to Harvest of $5.2 million, or $0.16 diluted earnings per share, for the three months ended September 30, 2008.

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


	Three Months Ended
	September 30,						Increase
	2009			2008			(Decrease)
Exploration expense	$	0.9		$	4.8		$	(3.9	)
General and administrative		6.1			6.7			(0.6	)
Taxes other than on income		0.2			(1.0	)		1.2
Investment earnings and other		(0.2	)		(1.1	)		0.9
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 September 30, 2009, we incurred $0.3 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, and $0.6 million related to other general business development activities. During the three months ended September 30, 2008, we incurred $4.5 million of exploration costs related to the purchase and reprocessing of seismic data related to our U.S. operations and acquisition of seismic data related to our Indonesian operations, and $0.3 million related to other general business development activities.

General and administrative costs were lower in the three months ended September 30, 2009 compared to the three months ended September 30, 2008 primarily due to lower travel, corporate overhead, and other professional fees in 2009. Taxes other than on income were higher in the three months ended September 30, 2009 compared to the three months ended September 30, 2008 primarily due to the reversal in September 2008 of a $1.1 million franchise tax provision that was no longer required.

Investment earnings and other decreased due to lower interest rates earned on lower average cash balances.

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

Nine Months Ended September 30, 2009 Compared with Nine Months Ended September 30, 2008

We reported a net loss attributable to Harvest of $8.2 million, or $0.25 diluted earnings per share, for the nine months ended September 30, 2009 compared with a net loss attributable to Harvest of $4.7 million, or $0.14 diluted earnings per share, for the nine months ended September 30, 2008.

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


	Nine Months Ended
	September 30,						Increase
	2009			2008			(Decrease)
Exploration expense	$	5.3		$	9.1		$	(3.8	)
General and administrative		19.0			19.3			(0.3	)
Taxes other than on income		0.8			(0.5	)		1.3
Gain on financing transactions		—			(3.4	)		3.4
Investment earnings and other		(0.9	)		(3.0	)		2.1
Interest expense		—			1.7			(1.7	)
Income tax expense		1.1			0.1			1.0

Our accounting method for oil and gas properties is the successful efforts method. During the nine months ended September 30, 2009, we incurred $3.1 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, and $2.2 million related to other general business development activities. During the nine months ended September 30, 2008, we incurred $8.2 million of exploration costs related to the purchase and reprocessing of seismic data related to our U.S. operations and acquisition of seismic data related to our Indonesian operations, and $0.9 million related to other general business development activities.

General and administrative costs were lower in the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008 primarily due to payroll and payroll related expenses. Taxes other than on income for the nine months ended September 30, 2009 were higher than that of the nine months ended September 30, 2008 primarily due to the reversal in September 2008 of a $1.1 million franchise tax provision that was no longer required.

We did not participate in any security exchange transactions in the nine months ended September 30, 2009. During the nine months ended September 30, 2008, we entered into a security 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 nine months ended September 30, 2008.

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

For nine months ended September 30, 2009, income tax expense was higher than that of the nine months ended September 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 $0.3 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 nine months ended September 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 nine months ended September 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 September 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 nine months ended September 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 September 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 September 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 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 several extensions. With such extensions, the court case is still suspended while the GAO waits for confirmation from the Finance Ministry. In September 2009, the Finance Minister issued an opinion in favor of the settlement. In October 2009, the SENIAT confirmed their recommendation to settle the case based on the amounts already negotiated. Final negotiations are on-going.

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 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 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.

Our cash position and limited ability to access additional capital could impact our financial condition and liquidity and limit our growth opportunities. At September 30, 2009, we had $49 million of available cash and, until Petrodelta pays a dividend or other sources of revenue are captured, there will be no additional cash available from operations. Having a Petrodelta dividend as our sole source of cash flow limits our access to additional capital, and our concentration of political risk in Venezuela may limit our ability to leverage our assets. In addition, our future cash position depends upon the payment of dividends by Petrodelta or success with our exploration program. While we believe such dividends, if available, will be paid, there is no assurance this will be the case. These factors could have a material adverse effect on our financial condition and liquidity and may limit our ability to grow through the acquisition or exploration of additional oil and gas properties and projects.

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

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.)

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.

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.)

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.


	Page
PART I FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS
Unaudited Consolidated Balance Sheets at September 30, 2009 and December 31, 2008		3
Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2009 and 2008		4
Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 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 6. EXHIBITS		27

Signatures		28
EX-31.1
EX-31.2
EX-32.1
EX-32.2


	HARVEST NATURAL RESOURCES, INC.
Dated: November 5, 2009	By:	/s/ James A. Edmiston
		James A. Edmiston
		President and Chief Executive Officer


Dated: November 5, 2009	By:	/s/ Stephen C. Haynes
		Stephen C. Haynes
		Vice President - Finance, Chief Financial Officer and Treasurer

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