Harvest Natural Resources 10Q 2010 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


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

For the Quarterly Period Ended June 30, 2010


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


		for the transition period from to

Commission File No. 1-10762

Harvest Natural Resources, Inc.

(Exact Name of Registrant as Specified in Its Charter)


Delaware		77-0196707
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)

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

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

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

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

Yesþ Noo

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

Yeso Noo

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


Large Accelerated Filero	Accelerated Filerþ	Non-Accelerated Filero	Smaller Reporting Companyo
	(Do not check if a smaller reporting company)

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

Yeso Noþ

At July 31, 2010, 33,588,625 shares of the Registrant’s Common Stock were outstanding.

HARVEST NATURAL RESOURCES, INC.

FORM 10-Q

TABLE OF CONTENTS


		Page
PART I FINANCIAL INFORMATION

Item 1.	Financial Statements
	Unaudited Consolidated Balance Sheets at June 30, 2010 and December 31, 2009		3
	Unaudited Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009		4
	Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009		5
	Notes to Consolidated Financial Statements		6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		32

Item 4.	Controls and Procedures		32

PART II OTHER INFORMATION

Item 1.	Legal Proceedings		34

Item 1A.	Risk Factors		34

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		35

Item 6.	Exhibits		36

Signatures			37
EX-10.2
EX-10.3
EX-10.4
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,			December 31,
	2010			2009
	(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	31,509		$	32,317
Restricted cash		1,000			—
Accounts and notes receivable, net:
Oil and gas revenue receivable		1,788			166
Dividend receivable – equity affiliate		12,220			—
Joint interest and other		3,346			8,047
Note receivable		3,229			3,265
Advances to equity affiliate		2,197			4,927
Prepaid expenses and other		1,951			2,214

TOTAL CURRENT ASSETS		57,240			50,936
OTHER ASSETS		6,084			3,613
INVESTMENT IN EQUITY AFFILIATES		269,051			233,989
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		78,700			58,543
Other administrative property		3,193			3,085

		81,893			61,628
Accumulated depletion, depreciation and amortization		(3,210	)		(1,387	)

		78,683			60,241

	$	411,058		$	348,779


LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Joint interest and royalty payable	$	510		$	—
Accounts payable, trade and other		2,660			696
Accrued expenses		7,047			10,253
Accrued interest		968			4,691
Income taxes payable		737			1,090

TOTAL CURRENT LIABILITIES		11,922			16,730
LONG-TERM DEBT		32,000			—
ASSET RETIREMENT LIABILITY		79			50
COMMITMENTS AND CONTINGENCIES (See Note 4)		—			—

EQUITY
STOCKHOLDERS’ EQUITY:
Preferred stock, par value $0.01 a share; authorized 5,000 shares; outstanding, none		—			—
Common stock, par value $0.01 a share; authorized 80,000 shares at June 30, 2010 and December 31, 2009, respectively; issued 39,658 shares and 39,495 shares at June 30, 2010 and December 31, 2009, respectively		397			395
Additional paid-in capital		215,294			213,337
Retained earnings		150,538			126,244
Treasury stock, at cost, 6,475 shares and 6,448 shares at June 30, 2010 and December 31, 2009, respectively		(65,543	)		(65,383	)

TOTAL HARVEST STOCKHOLDERS’ EQUITY		300,686			274,593
NONCONTROLLING INTEREST		66,371			57,406

TOTAL EQUITY		367,057			331,999

	$	411,058		$	348,779

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(in thousands, except per share data)
REVENUES
Oil sales	$	2,695		$	—		$	5,514		$	—
Gas sales		219			—			524			—

		2,914			—			6,038			—


EXPENSES
Lease operating costs and production taxes		432			—			677			—
Depletion, depreciation and amortization		1,259			88			1,825			157
Exploration expense		1,491			3,456			2,737			4,428
General and administrative		6,391			6,432			11,807			12,899
Taxes other than on income		198			241			498			558

		9,771			10,217			17,544			18,042


LOSS FROM OPERATIONS		(6,857	)		(10,217	)		(11,506	)		(18,042	)

OTHER NON-OPERATING INCOME (EXPENSE)
Investment earnings and other		140			280			271			638
Interest expense		(688	)		—			(1,104	)		—
Gain (loss) on exchange rates		(24	)		16			(1,551	)		(11	)

		(572	)		296			(2,384	)		627

LOSS FROM CONSOLIDATED COMPANIES BEFORE INCOME TAXES		(7,429	)		(9,921	)		(13,890	)		(17,415	)

INCOME TAX EXPENSE		152			147			133			1,036

LOSS FROM CONSOLIDATED COMPANIES		(7,581	)		(10,068	)		(14,023	)		(18,451	)

NET INCOME FROM UNCONSOLIDATED EQUITY AFFILIATES		8,915			7,476			47,282			11,886


NET INCOME (LOSS)		1,334			(2,592	)		33,259			(6,565	)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		1,630			1,597			8,965			2,400


NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST	$	(296	)	$	(4,189	)	$	24,294		$	(8,965	)


NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST PER COMMON SHARE:
Basic	$	(0.01	)	$	(0.13	)	$	0.73		$	(0.27	)

Diluted	$	(0.01	)	$	(0.13	)	$	0.65		$	(0.27	)

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended June 30,
	2010			2009
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	33,259		$	(6,565	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		1,825			157
Amortization of debt financing costs		329			—
Net income from unconsolidated equity affiliate		(47,282	)		(11,886	)
Non-cash compensation-related charges		1,844			2,120
Changes in operating assets and liabilities:
Accounts and notes receivable		3,115			541
Advances to equity affiliate		2,730			(475	)
Prepaid expenses and other		263			(1,780	)
Joint interest and royalty payable		510			—
Accounts payable		1,964			(973	)
Accrued expenses		363			(1,963	)
Accrued interest		(3,723	)		—
Income taxes payable		(353	)		977

NET CASH USED IN OPERATING ACTIVITIES		(5,156	)		(19,847	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions of property and equipment		(23,913	)		(11,341	)
Increase in restricted cash		(1,000	)		—
Investment costs		(36	)		(310	)

NET CASH USED IN INVESTING ACTIVITIES		(24,949	)		(11,651	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuances of common stock		115			201
Proceeds from issuance of long-term debt		32,000			—
Financing costs		(2,818	)		(1,477	)

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		29,297			(1,276	)


NET DECREASE IN CASH AND CASH EQUIVALENTS		(808	)		(32,774	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		32,317			97,165

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	31,509		$	64,391

Supplemental Schedule of Noncash Investing and Financing Activities:

During the six months ended June 30, 2010, we issued 0.3 million shares of restricted stock valued at $1.8 million. Also, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis, which resulted in 26,260 shares being added to treasury stock at cost; and 1,000 shares held in treasury that had been reissued as restricted stock were forfeited and returned to treasury.

During the six months ended June 30, 2009, we issued 0.2 million shares of restricted stock valued at $0.7 million. Also, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis, which resulted in 2,937 shares being added to treasury stock at cost.

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2010 and 2009 (unaudited)

Note 1 — Organization

Interim Reporting

In our opinion, the accompanying unaudited consolidated financial statements contain all adjustments necessary for a fair statement of the financial position as of June 30, 2010, and the results of operations for the three and six months ended June 30, 2010 and 2009, and cash flows for the six months ended June 30, 2010 and 2009. 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, 2009, 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 net 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, mainly onshore in West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in the Sultanate of Oman (“Oman”), and offshore of the People’s Republic of China (“China”). We also have developed acreage in the Antelope project in the Western United States in the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”) and Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) where we have established production. SeeNote 8 – United States,Note 9 – Indonesia,Note 10 – GabonandNote 11 – Oman.

Note 2 — Summary of Significant Accounting Policies

Principles of Consolidation

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

Reporting and Functional Currency

The United States Dollar (“U.S. Dollar”) is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. Amounts denominated in non-U.S. Dollar currencies are re-measured 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.

currency, at the published exchange rate of 4.30 Bolivars per U.S. Dollar. During the six months ended June 30, 2010, Harvest Vinccler recorded a $1.6 million remeasurement loss on revaluation of assets and liabilities.

Per the Exchange Agreement, each exchange rate is applied to foreign currency sales and purchases conducted through the Foreign Currency Administration Commission (“CADIVI”), in the cases expressly provided in the Exchange Agreement. In this regard, the exchange rates established in the Agreement are: 2.60 Bolivars per U.S. Dollar and 4.30 Bolivars per U.S. Dollar. The 2.60 Bolivar exchange rate applies to the food, health, medical and technology sectors. The 4.30 Bolivar exchange rate applies to all other sectors not expressly established by the 2.60 Bolivar exchange rate. As an alternative to the use of the official exchange rate, an exemption under the Venezuelan Criminal Exchange Law for transactions in certain securities resulted in an indirect securities transaction market of foreign currency exchange, through which companies could obtain foreign currency legally without requesting it from CADIVI. Publicly available quotes did not exist for the securities transaction exchange rate but such rates could be obtained from brokers. Securities transaction markets were used to move financial securities into and out of Venezuela. In May 2010, the government of Venezuela effectively eliminated this indirect market of foreign currency exchange.

Revenue Recognition

We record revenue for our U.S. oil and natural gas operations when we deliver our production to the customer and collectability is reasonably assured. Revenues from the production of oil and natural gas on properties in which we have joint ownership are recorded under the sales method. Differences between these sales and our entitled share of production are not significant.

Cash and Cash Equivalents

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

Restricted Cash

Restricted cash is classified as current or non-current based on the terms of the agreement. Restricted cash at June 30, 2010 represents cash held in a U.S. bank used as collateral for a standby letter of credit issued in support of a bank guarantee required as a performance guarantee for a joint study.

Accounts and Notes Receivable

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

Each note is analyzed to determine if it is impaired pursuant to the accounting standard for accounting by creditors for impairment of a loan. A note is impaired if it is probable that we will not collect all principal and interest contractually due. We do not accrue interest when a note is considered impaired. All cash receipts on impaired notes are applied to reduce the accrued interest on the note until the interest is made current and, thereafter, applied to reduce the principal amount of such notes.

Deferred Financing Costs

Deferred financing costs relate to specific financing and are amortized over the life of the financing to which the costs relate. SeeNote 3 – Long-Term Debt and Liquidity.

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.

Property and Equipment

We use the successful efforts method of accounting for oil and gas properties. We adopted the successful efforts method of accounting in the fourth quarter of 2007 and all periods presented reflect application of the successful efforts method of accounting.

At June 30, 2010, oil and gas properties include $0.2 million of capitalized interest. Oil and gas properties did not include any capitalized interest at December 31, 2009.

Suspended Exploratory Drilling Costs.Our capitalized suspended exploratory drilling costs at June 30, 2010 were $16.5 million. We did not have any suspended exploratory drilling costs at December 31, 2009. The $16.5 million increase relates to drilling in the Mesaverde formation in the Bar F #1-20-3-2 (“Bar F”). SeeNote 8 – United States Operations, Western United States – Antelope, Mesaverde Gas Exploration and Appraisal Project. Management believes the Mesaverde formation exhibits sufficient quantities of hydrocarbons to justify potential development and is actively pursuing efforts to assess whether reserves can be attributed to this reservoir. If additional information becomes available that raises substantial doubt as to the economic or operational viability of this project, the associated costs will be expensed at that time.

Fair Value Measurements

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

At June 30, 2010 and December 31, 2009, cash and cash equivalents include $21.8 million and $26.8 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 (level 1 input) for identical assets. The estimated fair value of our senior convertible notes based on observable market information (level 2 input) as of June 30, 2010 was $50.7 million.

Our current assets and liabilities accounts include financial instruments, the most significant of which are accounts receivables and trade payables. We believe the carrying values of our current assets and liabilities approximate fair value, with the exception of the note receivable. Because this note receivable is not publicly-traded and not easily transferable, the estimated fair value of our notes receivable is based on the best information available to us which approximates the note receivable book value. The majority of inputs used in the fair value calculation of the note receivable are Level 3 inputs and are consistent with the information used in determining impairment of the note receivable.

Asset Retirement Liability

The accounting for asset retirement obligations standard requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. No wells were abandoned during the six months ended June 30, 2010 or the year ended December 31, 2009. Changes in asset retirement obligations during the six months ended June 30, 2010 and the year ended December 31, 2009 were as follows (in thousands):


	June 30,		December 31,
	2010		2009
Asset retirement obligations beginning of period	$	50	$	—
Liabilities recorded during the period		27		50
Liabilities settled during the period		—		—
Revisions in estimated cash flows		—		—
Accretion expense		2		—

Asset retirement obligations end of period	$	79	$	50

Noncontrolling Interests

We adopted the accounting standard for noncontrolling interests in consolidated financial statements as of January 1, 2009. This standard establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. This standard also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owner. The retrospective adoption of this standard impacted the presentation of our consolidated financial position, results of operations and cash flows. Changes in noncontrolling interest during the six months ended June 30, 2010 and 2009 were as follows (in thousands):


	June 30,		June 30,
	2010		2009
Balance at beginning of period	$	57,406	$	49,603
Net income attributable to noncontrolling interest		8,965		2,400

Balance at end of period	$	66,371	$	52,003

Earnings Per Share

Basic earnings per common share (“EPS”) are computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. The weighted average number of common shares outstanding for computing basic EPS was 33.4 million and 33.3 million for the three and six months ended June 30, 2010, respectively, and 33.0 million for the three and six months ended June 30, 2009, 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 33.4 million and 39.2 million for the three and six months ended June 30, 2010, respectively, and 33.0 million for the three and six months ended June 30, 2009, respectively.

An aggregate of 3.8 million and 3.2 million options were excluded from the diluted EPS calculations because their exercise price exceeded the average stock price for the three and six months ended June 30, 2010, respectively. An aggregate of 3.8 million options were excluded from the diluted EPS calculations because their exercise price exceeded the average stock price for the three and six months ended June 30, 2009, respectively.

Stock options of 0.1 million were exercised in the six months ended June 30, 2010 resulting in cash proceeds of $0.1 million. Stock options of 0.1 million were exercised in the six months ended June 30, 2009 resulting in cash proceeds of $0.2 million.

Stock-Based Compensation

At June 30, 2010, we had a number of stock-based employee compensation plans, which are more fully described in Note 5 in our Annual Report on Form 10-K for the year ended December 31, 2009. In May 2010, our shareholders approved the 2010 Long Term Incentive Plan (the “Plan”). The Plan provides for the issuance of up to 1,700,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”), restricted stock, restricted stock units (“RSUs”) and other stock-based awards to eligible participants including employees, non-employee directors and consultants of our Company or subsidiaries. Under the Plan, no more than 500,000 shares may be granted as restricted stock. No individual may be granted more than 1,000,000 options or

SARs. The exercise price of stock options granted under the plan must be no less than the fair market value of our common stock on the date of grant. All options granted to date will vest in the manner and subject to the conditions specified in the award agreement and expire five years from grant date. Restricted stock granted vest in the manner and subject to the conditions specified in the award agreement. The Plan also permits the granting of performance awards and other cash-based awards to eligible employees and consultants. Performance awards may be in the form of performance stock, performance units and other form of award established by the Board of Directors’ Human Resource Committee (the “Committee”) with vesting based on the accomplishment of a performance goal. No individual may be awarded performance related cash awards during a calendar year that could result n a cash payment of more than $5.0 million. In the event of a change in control, the Committee shall act to effect one or more of the following alternatives, which may vary among individual holders of awards granted under the Plan and which may vary among awards held by any individual holder of an award granted under the Plan: 1) accelerate vesting; 2) require mandatory surrender; 3) assume outstanding awards or have a new award of a similar nature substituted; 4) adjust the number and class of common stock covered by an award; and/or 5) make adjustments deemed appropriate to reflect the change of control.

In May 2010, stock options to purchase 0.5 million shares of common stock and 0.2 million shares of restricted stock were granted to employees and 0.1 million shares of restricted stock were granted to non-employee directors. The stock options vest ratably over a three year period from date of grant and expire five years from grant date. The restricted stock granted to employees is subject to a restriction period of not less than 36 months during which the stock will be deposited with Harvest and is subject to forfeiture under certain circumstances. Restricted stock granted to non-employee directors vests one year after the grant date provided that he is still a director on that date.

New Accounting Pronouncements

In May 2010, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-19, which is included in Accounting Standards Codification (“ASC”) under 830, “Foreign Currency” (“ASC 830”). This update addresses the multiple foreign currency exchange rates and the impact of highly inflationary accounting in Venezuela. Since the U.S. Dollar is the functional and reporting currency for all of our Venezuela entities, the adoption of this update did not have an impact on our consolidated financial position, results of operations or cash flows.

Note 3 — Long-Term Debt and Liquidity

Long-Term Debt

Long-term debt consists of the following (in thousands):


	June 30,		December 31,
	2010		2009
Note payable with interest at 8.25%	$	32,000	$	—

On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. Under the terms of the notes, interest is payable semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2010. The notes will mature on March 1, 2013, unless earlier redeemed, repurchased or converted. The notes are convertible into shares of our common stock at a conversion rate of 175.2234 shares of common stock per $1,000 principal amount of convertible notes, equivalent to a conversion price of approximately $5.71 per share of common stock. The notes are our general unsecured obligations, ranking equally with all of our other unsecured senior indebtedness, if any, and senior in right of payment to any of our subordinated indebtedness, if any. The notes are also redeemable in certain circumstances at our option and may be repurchased by us at the purchaser’s option in connection with occurrence of certain events. The net proceeds of the offering to us were approximately $30.0 million, after deducting underwriting discounts, commissions and estimated offering expenses. Financing costs of $2.3 million associated with this debt offering are being amortized over the life of the debt. These costs are capitalized in Other Assets at June 30, 2010.

We have incurred $2.9 million in costs related to ongoing negotiations for a future financing. If the financing is successful, these costs will be amortized over the life of the financial instrument. These costs are capitalized in Other Assets at June 30, 2010.

Liquidity– Based on our cash balance of $31.5 million at June 30, 2010, we will require additional funds in order to fund our future operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration, appraisal and development projects and to a lesser extent, general and administrative costs. Currently, our primary source of cash is dividends from Petrodelta and to a lesser extent, production from the Monument Butte Extension and Lower Green River/Upper Wasatch projects. In May 2010, Petrodelta declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). However, there is no certainty that Petrodelta will pay additional dividends in 2010 or 2011. Our lack of cash flow and the anticipated level 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, farm-out or otherwise monetize assets as necessary to maintain the liquidity required to run our operations, if necessary. There can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.

Note 4 — Commitments and Contingencies

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

Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-Vinccler, C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, Texas. This suit was brought in May 2003 by Excel alleging, among other things, breach of a consulting agreement between Excel and us, misappropriation of proprietary information and trade secrets and fraud. Excel seeks actual and exemplary damages, injunctive relief and attorneys’ fees. In April 2007, the court set the case for trial. The trial date, reset for the first quarter of 2009, had been stayed indefinitely. On October 20, 2009, the stay was lifted. A trial date of November 1, 2010 has been set. We dispute Excel’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.

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

	•		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 a 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 a 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.

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

Note 5 — Taxes Other Than on Income

The components of taxes other than on income were:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
	(in thousands)
Franchise Taxes	$	45	$	57	$	106	$	99
Payroll and Other Taxes		153		184		392		459

	$	198	$	241	$	498	$	558

Note 6 — Operating Segments

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(in thousands)
Segment Revenues
Oil and gas sales:
United States and other	$	2,914		$	—		$	6,038		$	—

Total oil and gas sales	$	2,914		$	—		$	6,038		$	—


Segment Income (Loss)
Venezuela	$	7,786		$	8,074		$	44,276		$	12,790
Indonesia		(1,514	)		(2,957	)		(2,793	)		(2,792	)
United States and other		(6,568	)		(9,306	)		(17,189	)		(18,963	)

Net income (loss) attributable to Harvest	$	(296	)	$	(4,189	)	$	24,294		$	(8,965	)


	June 30,			December 31,
	2010			2009
	(in thousands)
Operating Segment Assets
Venezuela	$	275,235		$	249,484
Indonesia		10,321			5,893
United States and other		151,303			113,555

		436,859			368,932
Intersegment eliminations		(25,801	)		(20,153	)

	$	411,058		$	348,779

Note 7 — Investment in Equity Affiliates

Petrodelta

Petrodelta has undertaken its operations in accordance with Petrodelta’s business plan as set forth in its conversion contract. Under its conversion contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. On February 4, 2010, Petrodelta’s board of directors endorsed a capital budget of $205 million for Petrodelta’s 2010 business plan. It is unlikely that Petrodelta will spend all of its 2010 budget during the remaining six months of 2010.

In May 2010, Petrodelta declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest), which represents 50 percent of Petrodelta’s net income as reported under International Financial Reporting Standards (“IFRS”) for the year ended December 31, 2009. The dividend is expected to be received during the third quarter of 2010. No dividends were declared or paid during the six months ended June 30, 2009.

In 2008, the Venezuelan government published in the Official Gazette the Law of Special Contribution to Extraordinary Prices at the Hydrocarbons International Market (“Windfall Profits Tax”). The Windfall Profits Tax is calculated on the Venezuelan Export Basket (“VEB”) of prices as published by the Ministry of the People’s Power for Energy and Petroleum (“MENPET”). As instructed by CVP, Petrodelta has applied the Windfall Profits Tax to gross oil production delivered to PDVSA. The Windfall Profits Tax established a special 50 percent tax to the Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar manner, the percentage is increased from 50 percent to 60 percent when the average price of the VEB exceeds $100 per barrel. The Windfall Profits Tax is reported as taxes other than on income on the income statement of Petrodelta and is deductible for Venezuelan tax purposes. Petrodelta recorded $1.7 million and $2.9 million of expense for the Windfall Profits Tax during the three and six months ended June 30, 2010, respectively. During the three and six months ended June 30, 2009, no expense was recorded for the Windfall Profits Tax.

The Science and Technology Law (referred to as “LOCTI” in Venezuela) requires major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law (“OHL”) to contribute two

percent of their gross revenue generated in Venezuela from activities specified in the OHL on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. The contribution is based on the previous year’s gross revenue and is due the following year. LOCTI requires that each company file a separate declaration stating how much has been contributed; however, waivers have been granted in the past to allow PDVSA to file a declaration on a consolidated basis covering all of its and its consolidating entities liabilities. Since Petrodelta expects PDVSA to continue requesting and receiving waivers, Petrodelta has not accrued a liability to LOCTI for the six months ended June 30, 2010. The potential exposure to LOCTI for the six months ended June 30, 2010 is $2.3 million, $1.1 million net of tax ($0.4 million net to our 32 percent interest).

On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement, which established new exchange rates for the Bolivar/U.S. Dollar currencies that entered into force on January 11, 2010. SeeNote 2 – Summary of Significant Accounting Policies, Reporting and Functional Currency. Petrodelta revalued the appropriate monetary accounts that were Bolivar-denominated to U.S. Dollars, Petrodelta’s functional and reporting currency, at the published exchange rate of 4.30 Bolivars per U.S. Dollar. In general, monetary assets based in Bolivars would be revalued to a lower U.S. Dollar balance on Petrodelta’s balance sheet resulting in a currency exchange rate loss on the income statement, and monetary liabilities based in Bolivars would revalue to a lower U.S. Dollar balance in Petrodelta’s balance sheet resulting in a gain on exchange rates in the income statement. The primary factor in Petrodelta’s gain on currency exchange rates is that Petrodelta had substantially higher Bolivar denominated liabilities than Bolivar denominated assets. During the three and six months ended June 30, 2010, Petrodelta recorded a $1.9 million and $120.7 million, before tax, ($0.6 million and $38.6 million, before tax, net to our 32 percent interest) remeasurement gain on revaluation of assets and liabilities, respectively.

Petrodelta’s current tax rate increased from 45 percent for the three months ended March 31, 2010 to 79 percent for the three months ended June 30, 2010 primarily as a result of changes to the 2010 tax projections for the taxability of the exchange gain and the projected recognition of certain tax deductions. The changes to the 2010 tax projection resulted in the recording of $17.1 million additional tax expense in the second quarter of 2010 related to income attributable to the first quarter of 2010. The Bolivar devaluation increased Petrodelta’s overall effective tax rate due to the effect of the devaluation on the deferred tax asset in the first quarter of 2010.

Petrodelta’s reporting and functional currency is the U.S. Dollar. HNR Finance owns a 40 percent interest in Petrodelta. Petrodelta’s financial information is prepared in accordance with IFRS, which we have adjusted to conform to GAAP. All amounts through Net Income represent 100 percent of Petrodelta. Summary financial information has been presented below at June 30, 2010 and December 31, 2009 and for the three and six months ended June 30, 2010 and 2009 (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenues:
Oil sales	$	135,964		$	107,154		$	277,466		$	177,183
Gas sales		1,022			2,016			2,040			4,199
Royalty		(45,835	)		(36,125	)		(93,262	)		(60,912	)

		91,151			73,045			186,244			120,470
Expenses:
Operating expenses		11,565			20,809			22,757			32,525
Depletion, depreciation and amortization		9,768			9,025			18,376			16,713
General and administrative		2,451			6,989			3,819			9,214
Windfall profits tax		1,664			—			2,915			—
Taxes other than on income		1,143			(1,536	)		3,496			1,535

		26,591			35,287			51,363			59,987

Income from operations		64,560			37,758			134,881			60,483

Gain on exchange rate		1,938			—			120,654			—
Investment earnings and other		(13	)		1			2,881			3


Income before income tax		66,485			37,759			258,416			60,486

Current income tax expense		52,656			22,414			138,076			32,200
Deferred income tax (benefit) expense		5,118			(19,284	)		47,582			(23,367	)

Net income		8,711			34,629			72,758			51,653
Adjustment to reconcile to reported net income From Unconsolidated equity affiliate:
Deferred income tax (benefit) expense		(14,499	)		11,086			(47,488	)		16,087

Net income equity affiliate		23,210			23,543			120,246			35,566
Equity interest in unconsolidated equity affiliate		40	%		40	%		40	%		40	%

Income before amortization of excess basis in equity affiliate		9,284			9,417			48,098			14,226
Amortization of excess basis in equity affiliate		(322	)		(352	)		(656	)		(663	)
Conform depletion expense to GAAP		(47	)		(263	)		(160	)		440

Net income from unconsolidated equity affiliate	$	8,915		$	8,802		$	47,282		$	14,003


	June 30,		December 31,
	2010		2009
Current assets	$	542,474	$	404,825
Property and equipment		268,921		265,442
Other assets		93,706		141,245
Current liabilities		368,495		345,812
Other liabilities		31,748		33,600
Net equity		504,858		432,100

Fusion Geophysical, LLC (“Fusion”)

Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering. The purchase of our equity investment in Fusion extends our technical ability and global reach to support a more organic growth and exploration strategy. Our minority 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 six months ended June 30, 2010 and 2009, respectively. Summarized financial information for Fusion follows (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Operating revenues	$	2,763		$	2,165		$	5,599		$	5,344

Net loss	$	(832	)	$	(2,306	)	$	(1,671	)	$	(3,371	)
Equity interest in unconsolidated equity affiliate		49	%		49	%		49	%		49	%

Net loss from unconsolidated equity affiliate		(408	)		(1,130	)		(819	)		(1,652	)
Amortization of fair value of intangibles		—			(196	)		—			(465	)

Net loss from unconsolidated equity affiliate	$	(408	)	$	(1,326	)	$	(819	)	$	(2,117	)


	June 30,		December 31,
	2010		2009
Current assets	$	2,466	$	2,726
Total assets		25,752		30,205
Current liabilities		7,593		8,024
Total liabilities		8,423		12,242

At December 31, 2009, we recorded a $1.6 million charge to fully impair the carrying value of our equity investment in Fusion. Accordingly, we no longer record losses that would cause our equity investment to go into a negative position. For the three and six months ended June 30, 2010, Fusion reported a net loss of $0.8 million and $1.7 million ($0.4 million and $0.8 million net to our 49 percent interest), respectively. This loss is not reported in the three and six months ended June 2010 net income from unconsolidated equity affiliates as reporting it would take our equity investment into a negative position.

Approximately 16.1 percent and 20.7 percent of Fusion’s revenue for the three and six months ended June 30, 2010, respectively, and approximately 47.9 percent and 40.7 percent of Fusion’s revenue for the three and six months ended June 30, 2009, respectively, was earned from Harvest or equity affiliates.

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 June 30, 2010, the balance for prepaid services was approximately $0.6 million.

Note 8 — United States Operations

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

Gulf Coast

In March 2008, we executed an Area of Mutual Intent (“AMI”) agreement with a private third party for an area in the upper Gulf Coast Region of the United States. In August 2009, the AMI became a three-party arrangement when the private third party restructured and assigned a portion of its interest to one of its affiliates. The AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana, including state waters. We are the operator and have an initial working interest of 50 percent in West Bay, the second prospect in the AMI. The first prospect in the AMI was abandoned in 2009 after a dry hole was drilled. The private third party contributed these two prospects, including 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 funding obligation was met during 2009, and all costs are now being shared by the parties in proportion to their working interests as defined in the AMI.

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. On January 28, 2010, we entered into an agreement with one of the private third parties in our AMI for an option to participate in a new project. We paid $1.5 million for the option to acquire up to a 50 percent interest in the new project. In March 2010, an additional party was admitted into the new project as operator with a 50 percent interest. As a result, our option allowed us to acquire up to a 25 percent non-operated interest in the project. The option to participate expired June 1, 2010. Because of the substantial changes made to the project after we acquired our option, we elected to not participate in the project, and the $1.5 million paid for the option will be refunded by September 30, 2010. The $1.5 million paid for the option is reported in Accounts Receivable Joint Interest and Other on the June 30, 2010 balance sheet.

West Bay Project

During the six months ended June 30, 2010, operational activities in the West Bay prospect focused on firming up plans for drilling on the identified initial drilling prospect and continuing to evaluate the other leads and prospects in the project. Land, regulatory and surface access preparations currently in progress are focused on taking the initial drilling prospect to drill-ready status. We finalized a 3-D seismic data trade with a third party that provides access to additional seismic data, which allows for more complete technical evaluation of the leads and prospects identified in the project. We are in the process of merging the newly acquired seismic data set with our existing seismic data, and interpreting the merged data set. The West Bay project represents $3.4 million and $3.1 million of unproved oil and gas properties as of June 30, 2010 and December 31, 2009, respectively.

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 prospect in the Western United States. We are the operator and have a working interest of 60 percent in the Antelope prospect. The private third party is obligated to assemble the lease position on the Antelope prospect. The JEDA provides that we will earn our 60 percent working interest in the Antelope prospect by compensating the private third party for leases acquired in accordance with terms defined in the JEDA, and by drilling and completing one well (the Bar F) at our sole expense. As of July 19, 2010, we have completed our earning obligation for the Antelope prospect.

In November 2008, land costs of $2.7 million previously advanced to the private third party were reclassified to a note receivable. Payment of the note receivable was due from the private third party on or by spud date of the Bar F. Since payment was not received prior to the Bar F spud date, payment will be collected through sales revenues taken from a portion of the private third party’s net revenue from the Bar F. Through June 30, 2010, $0.2 million of sales revenue has been applied against the note.

Operational activities during the six months ended June 30, 2010 on the Antelope prospect focused on continuing leasing activities on private, Allottee, and tribal land. The Antelope prospect represents $21.2 million and $19.4 million of unproved oil and gas properties as of June 30, 2010 and December 31, 2009, respectively.

Other activities on the Antelope prospect focused on drilling, completion and testing activities on three separate projects on the Antelope prospect in Duchesne and Uintah Counties, Utah.

Mesaverde Gas Exploration and Appraisal Project

The Mesaverde Gas Exploration and Appraisal Project (“Mesaverde”) is targeted to explore for and develop oil and natural gas from multiple reservoir intervals in the Mesaverde formation in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties. Operational activities during the three months ended March 31, 2010 included completion of the initial testing activities on the Mesaverde horizons in the deep natural gas test well (the Bar F) that commenced drilling on June 15, 2009. No operational activities occurred in the Mesaverde during the three months ended June 30, 2010. The Bar F was drilled to a total depth of 17,566 feet and an extended production test of the Mesaverde has been completed. Testing was focused on the evaluation of the natural gas potential of the Mesaverde tight gas reservoir over a prospective interval from 14,000 to 17,400 feet. Completion activities consisted of hydraulic fracturing of eight separate reservoir intervals in the Mesaverde and multiple extended flow tests of the individual fractured intervals, along with a flow test of the commingled eight intervals. While the results to date have not definitively determined the commerciality of a stand-alone development of the Mesaverde in the current gas price environment, we believe these results indicate progress toward that commerciality determination and that the Mesaverde reservoir remains potentially prospective over a portion of our

land position. Exploratory drilling costs for the Mesaverde have been suspended pending further evaluation. SeeNote 2 – Summary of Significant Accounting Policies, Property and Equipment. The Mesaverde project represents $16.5 million and $11.3 million of unproved oil and gas properties as of June 30, 2010 and December 31, 2009, respectively.

Lower Green River/Upper Wasatch Oil Delineation and Development Project

A second project has also been pursued in the Bar F exploration well. After completion of the initial testing program on the Mesaverde deep gas as described above, we moved uphole in the same well to test multiple oil bearing intervals at depths from 8,200 feet to 9,500 feet in the Lower Green River and Upper Wasatch formations. Operational activities during the six months ended June 30, 2010 included completion of testing of the Bar F, completion of the Bar F, including installation of an electric submersible pump, completion of production facilities for the Bar F, and routine production operations of the Bar F. Results of the testing have been positive, and we believe the results indicate that we have made a commercial oil discovery in the Lower Green River and Upper Wasatch formations. Extended flow testing of the well was conducted during the second quarter of 2010, and the well is on routine production as of June 30, 2010, with the produced oil being sold into the Salt Lake City, Utah market. We developed an estimate of reserves accessed by the Bar F well during second quarter of 2010, incorporating the results of the flow testing and initial phases of permanent production operation of the well into the reserves determination.

Our Board of Directors has authorized a five-well Lower Green River/Upper Wasatch delineation and development drilling program, which is planned to take place beginning in the third quarter of 2010. This five-well program would further delineate and appraise the extent of the Lower Green River/Upper Wasatch discovery made in the Bar F, and is also expected to establish additional production from the Lower Green River/Upper Wasatch reservoirs in at least some of the five appraisal wells. The Lower Green River/Upper Wasatch formations are productive in the Altamont/Bluebell oil field approximately six miles north of the Bar F well. Operational activities during the six months ended June 30, 2010 on the five well Lower Green River/Upper Wasatch delineation program included preparations and well planning for the drilling program to be implemented in the second half of 2010. The first well of the five-well delineation program, the Kettle #1-10-3-1 (“Kettle”), spud on July 14, 2010, and is drilling as of August 9, 2010. The five wells are planned to be drilled back-to-back.

The Lower Green River/Upper Wasatch represents $10.0 million of proved and $0.3 million of unproved oil and gas properties as of June 30, 2010 and $5.6 million of unproved oil and gas properties as of December 31, 2009.

Monument Butte Extension Appraisal and Development Project

The Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”) was initiated with an eight-well appraisal and development drilling program to produce oil and natural gas from the Green River formation on the southern portion of our Antelope land position. The Monument Butte Extension is non-operated, and we hold a 43 percent working interest in the initial eight wells. The parties participating in the wells formed a 320 acre AMI, which contained the initial eight drilling locations. Operational activities during the three months ended March 31, 2010 on the Monument Butte Extension focused on drilling and completion activities on the original eight-well program. As of March 31, 2010, all eight wells had been drilled and were on production. Operational activities on these eight wells during the three months ended June 30, 2010 consisted of routine production operations from the wells.

Our Board of Directors has authorized six additional Monument Butte Extension appraisal and development wells planned to be drilled beginning in the third quarter of 2010. The estimated gross drilling and completion cost per well is $0.9 million, and we will have an approximate 37 percent working interest in the six wells after the acquisition of the incremental 10 percent interest from our partner as described inNote 12 – Subsequent Events. This six-well expansion program is a follow up to the successful completion of the initial eight-well program that was drilled in late 2009 and early 2010. The expansion is planned to occur on acreage immediately adjacent to the initial eight-well program. The first well of the six-well delineation program spud on July 29, 2010 and was logged on August 1, 2010. The six wells are planned to be drilled back-to-back.

The Monument Butte Extension represents $3.5 million of proved and $0.2 million of unproved oil and gas properties as of June 30, 2010 and $1.6 million of proved and $0.3 million of unproved oil and gas properties as of December 31, 2009.

Note 9 — Indonesia

In 2008, we acquired a 47 percent interest in the Budong-Budong Production Sharing Contract (“Budong PSC”) by committing to fund the first phase of the exploration program including the acquisition of 2-D seismic and drilling of the first two exploration wells. This commitment is capped at $17.2 million. The commitment is comprised of $6.5 million for the acquisition of seismic and $10.7 million for the drilling of the first two exploratory wells. After the commitment of each component is met, all subsequent costs will be shared by the parties in proportion to their ownership interests. The $6.5 million carry obligation for the 2-D seismic acquisition was met in December 2008. Prior to drilling the first exploration well, subject to the estimated cost of that well, our partner will have a one-time option to increase the level of the carried interest to a maximum of $20.0 million, and as compensation for the increase, we will increase our participation to a maximum of 54.65 percent. This equates to a total carried cost for the farm-in of $9.1 million. Our partner intends to exercise their option to increase the level of the carried interest and is currently reviewing the amount of the increase. 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 covers 1.35 million acres and includes the Lariang and Karama sub-basins, which are the eastern onshore extension of the West Sulawesi foldbelt (“WSFB”). Exploration to date in the basin is immature due to previously difficult jungle terrain, which is now accessible with the development of palm oil plantations and their related infrastructure. Field work performed over the last 10 years, as outcrops have been more accessible, has given a new understanding to the presence of Eocene source and reservoir potential that had not previously been recognized. Recent seismic surveys have greatly improved the understanding of the geology and enhanced the prospectivity of the offshore WSFB and, by analogy, the sparsely explored onshore area. The Budong PSC includes a ten-year exploration period and a 20-year development phase. The second three-year exploration phase began in January 2010. Two drill sites were selected in 2009. After delays in acquiring permits to mobilize the drilling rig from its port location to the drilling pad, it is now expected that the first of the two exploratory wells will spud late in the third quarter of 2010. In accordance with the farm-in agreement, we expect to fund 100 percent of the well expenditures to earn our 47 percent working interest up to a cap of $10.7 million; thereafter, we will pay in proportion to our working interest. Operational activities during the six months ended June 30, 2010 include construction for the two test well sites, mobilization of rig and ancillary equipment to the first drill site, and purchase of drilling equipment. The Budong PSC represents $6.4 million and $2.0 million of unproved oil and gas properties as of June 30, 2010 and December 31, 2009, respectively.

Note 10 — Gabon

We are the operator of the Dussafu Marin Permit offshore Gabon in West Africa (“Dussafu PSC”) with a 66.667 percent interest in the Dussafu PSC. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC covers an area of 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. It has been agreed that the second three-year exploration phase will be extended until May 27, 2011, at which time the partners can elect to enter a third exploration phase. The second exploration phase comprises a work commitment which includes the acquisition and processing of 500 kilometers of 2-D seismic, geology and geophysical interpretation, engineering studies and the drilling of a conditional well. Operational activities during the six months ended June 30, 2010 include maturation of prospect inventory and well planning. Subject to drilling rig availability, we expect to drill an exploratory well in the second quarter of 2011. The Dussafu PSC represents $8.2 million and $6.9 million of unproved oil and gas properties as of June 30, 2010 and December 31, 2009, respectively.

Note 11 — Oman

In April 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 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. We have an obligation to drill two wells over a three-year period with a funding commitment of $22.0 million. Current activities include geological studies, baseline environmental and social study and 3-D pre-stack depth migration reprocessing of approximately 1,000 square kilometers of existing 3-D seismic data. The Block 64 EPSA represents $4.2 million and $3.8 million of unproved oil and gas properties as of June 30, 2010 and December 31, 2009, respectively.

Note 12 — Subsequent Events

We conducted our subsequent events review through the date of the issuance of this Quarterly report on Form 10-Q.

On July 28, 2010, our Board of Directors approved the acquisition of an incremental 10 percent interest in the Antelope Project from our partner through a farmout. This acquisition includes all leases, the Mesaverde Gas Exploration and Appraisal Project and the Lower Green River/Upper Wasatch Oil Delineation and Development Project. The acquisition excludes the initial eight wells previously drilled in the Monument Butte Extension Appraisal and Development Project. Total consideration for the incremental 10 percent interest is $20.0 million of which $3.0 million was paid on August 2, 2010 (closing date), $3.0 million to be paid by October 1, 2010 and a capped $14.0 million carry of a portion of our partner’s exploration and development cost obligations in the upcoming Lower Green River/Upper Wasatch and Monument Butte Extension drilling programs in the Antelope project. Based on current plans, we anticipate the full carry obligation will be met in the first half of 2011. This acquisition increases our ownership in the Antelope project to 70 percent.

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”, “expect”, “believes”, “goals”, “projects”, “plans”, “anticipates”, “estimates”, “should”, “could”, “assume” and similar expressions are intended to identify forward-looking statements. In accordance with the provisions of the Private Securities Litigation Reform Act of 1995, we caution you that important factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include our concentration of operations in Venezuela, the political and economic risks associated with international operations (particularly those in Venezuela), the anticipated future development costs for undeveloped reserves, drilling risks, the risk that actual results may vary considerably from reserve estimates, the dependence upon the abilities and continued participation of certain of our key employees, the risks normally incident to the exploration, operation and development of oil and natural gas properties, risks incumbent to being a noncontrolling interest shareholder in a corporation, the permitting and the drilling of oil and natural gas wells, the availability of materials and supplies necessary to projects and operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, the Company’s ability to acquire oil and natural gas properties that meet its objectives, availability and cost of drilling rigs, seismic crews, overall economic conditions, political stability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in governmental policy, availability of sufficient financing including the Company’s ability to obtain the Islamic (sukuk) financing described in Item 1A – Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2009, 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, 2009, 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 incorporated under Delaware law in 1989. Our focus is on acquiring exploration, development and producing properties in geological basins with proven active hydrocarbon systems. Our experienced technical, business development and operating staffs have identified low entry cost exploration opportunities in areas with large hydrocarbon resource potential. We operate from our Houston, Texas headquarters. We also have regional/technical offices in the United Kingdom and Singapore, and small field offices in Jakarta, Indonesia, Muscat, Sultanate of Oman (“Oman”) and Roosevelt, Utah to support field operations in those areas. We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”) through our 40 percent equity affiliate, Petrodelta, S. A. (“Petrodelta”), which operates a portfolio of properties in eastern Venezuela including large proven oil fields as well as properties with very substantial opportunities for both development and exploration. We have seconded key technical and managerial personnel into Petrodelta and participate on Petrodelta’s board of directors. Geophysical, geosciences and reservoir engineering support services are available to our in-house experts through our minority equity investment in Fusion Geophysical, LLC (“Fusion”). Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering headquartered in the Houston area. Through the pursuit of technically-based strategies guided by conservative investment philosophies, we are building a portfolio of exploration prospects to complement the low-risk production, development and exploration prospects we hold in Venezuela. Currently, we hold interests in Venezuela, exploration acreage in the Gulf Coast Region of the United States through an Area of Mutual Intent (“AMI”) agreement with two private third parties, the Antelope project in the Western United States through a Joint Exploration and Development Agreement (“JEDA”), mainly onshore West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in the Sultanate of Oman (“Oman”) and offshore of the People’s Republic of China (“China”). We also have developed acreage in the Antelope project in the Western United States in the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”) and Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) where we have established production.

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

Venezuela

During the six months ended June 30, 2010, Petrodelta drilled and completed nine successful development wells, produced approximately 3.9 million barrels of oil and sold 1.3 billion cubic feet (“BCF”) of natural gas. Petrodelta produced an average of 21,713 barrels of oil per day during the six months ended June 30, 2010.

The appraisal and development activity in the El Salto field continues to exceed expectations. During the second quarter of 2010 the ELS-32 was drilled in the El Salto field and completed with initial production of 2,400 BOPD, which confirms the potential of Upper Jobo reservoir in Block 5. Also in mid-July Petrodelta spud the ELS-33, a well whose plan includes the drilling of two pilot holes. The initial pilot hole was intended to test the downdip limits in Block 5. Logs indicate significant oil columns exist in the Lower Jobo and the Upper and Lower Morichal formations in an area not previously included in the Block’s mapped oil in place.

Petrodelta shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. On February 4, 2010, Petrodelta’s board of directors endorsed a capital budget of $205 million for Petrodelta’s 2010 business plan. The budget includes utilizing two rigs to drill both development and appraisal wells for both maintaining production capacity and appraising the substantial resource bases in the El Salto Field and presently non-producing Isleño field. Currently, Petrodelta is operating two drilling rigs; one rig is operating in the El Salto field and a second rig began operating in the Temblador field in mid-July. Also, Petrodelta is currently seeking a workover rig which it expects to have under contract during the third quarter of 2010. It is unlikely that Petrodelta will spend all of its 2010 budget during the remaining six months of 2010.

During the six months ended June 30, 2010, Petrodelta started the engineering work for expanded production facilities to handle the expected production from the development and appraisal wells projected to be drilled in 2010.

In 2008, the Venezuelan government published in the Official Gazette the Law of Special Contribution to Extraordinary Prices at the Hydrocarbons International Market (“Windfall Profits Tax”). The Windfall Profits Tax is to be calculated on the Venezuelan Export Basket (“VEB”) of prices as published by the Ministry of the People’s Power for Energy and Petroleum (“MENPET”). As instructed by CVP, Petrodelta has applied the Windfall Profits Tax to gross oil production delivered to Petroleos de Venezuela S.A. (“PDVSA”). The Windfall Profits Tax established a special 50 percent tax to the Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar manner, the percentage is increased from 50 percent to 60 percent when the average price of the VEB exceeds $100 per barrel. The Windfall Profits Tax is reported as expense on the income statement and is deductible for Venezuelan tax purposes. Petrodelta recorded $1.7 million and $2.9 million of expense for the Windfall Profits Tax during the three and six months ended June 30, 2010, respectively. During the three and six months ended June 30, 2009, no expense was recorded for the Windfall Profits Tax.

In 2005, Venezuela modified the Science and Technology Law (referred to as “LOCTI” in Venezuela) to require companies doing business in Venezuela to invest, contribute or spend a percentage of their gross revenue on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. LOCTI requires major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law (“OHL”) to contribute two percent of their gross revenue generated in Venezuela from activities specified in the OHL. The contribution is based on the previous year’s gross revenue and is due the following year. LOCTI requires that each company file a separate declaration stating how much has been contributed; however, waivers have been granted in the past to allow PDVSA to file a declaration on a consolidated basis covering all of its and its consolidating entities liabilities. Since Petrodelta expects PDVSA to continue requesting and receiving waivers, Petrodelta has not accrued a liability to LOCTI for the six months ended June 30, 2010. The potential exposure to LOCTI for the six months ended June 30, 2010 is $2.3 million, $1.1 million net of tax ($0.4 million net to our 32 percent interest).

entered into force on January 11, 2010. Each exchange rate is applied to foreign currency sales and purchases conducted through the Foreign Currency Administration Commission (“CADIVI”), in the cases expressly provided in the Exchange Agreement. In this regard, the exchange rates established in the Agreement are: 2.60 Bolivars per U.S. Dollar and 4.30 Bolivars per U.S. Dollar. The 2.60 Bolivar exchange rate applies to the food, health, medical and technology sectors. The 4.30 Bolivar exchange rate applies to all other sectors not expressly established by the 2.60 Bolivar exchange rate. Petrodelta revalued the appropriate monetary accounts that were Bolivar-denominated to U.S. Dollars, Petrodelta’s functional currency, at the published exchange rate of 4.30 Bolivars per U.S. Dollar. In general, monetary assets based in Bolivars would be revalued to a lower U.S. Dollar balance on Petrodelta’s balance sheet resulting in a currency exchange rate loss on the income statement, and monetary liabilities based in Bolivars would revalue to a lower U.S. Dollar balance in Petrodelta’s balance sheet resulting in a gain on exchange rates in the income statement. The primary factor in Petrodelta’s gain on currency exchange rates is that Petrodelta had substantially higher Bolivar denominated liabilities than Bolivar denominated assets. During the three and six months ended June 30, 2010, Petrodelta recorded a $1.9 million and $120.7 million, before tax, ($0.6 million and $38.6 million, before tax, net to our 32 percent interest) remeasurement gain on revaluation of assets and liabilities, respectively.

Certain operating statistics for the three and six months ended June 30, 2010 and 2009 for the Petrodelta fields operated by Petrodelta are set forth below. This information is provided at 100 percent. This information may not be representative of future results.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Thousand barrels of oil sold		1,955		2,007		3,923		3,732
Million cubic feet of gas sold		663		1,306		1,323		2,720
Total thousand barrels of oil equivalent		2,066		2,225		4,144		4,185
Average price per barrel	$	69.55	$	53.39	$	70.73	$	47.48
Average price per thousand cubic feet	$	1.54	$	1.54	$	1.54	$	1.54
Cash operating costs ($millions)	$	11.6	$	20.8	$	22.8	$	32.5
Capital expenditures ($millions)	$	19.4	$	18.9	$	25.5	$	48.6

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.

United States

Gulf Coast AMI

On January 28, 2010, we entered into an agreement with one of the private third parties in our AMI for an option to participate in a new project. We paid $1.5 million for the option to acquire up to a 50 percent interest in the new project. In March 2010, an additional party was admitted into the new project as operator with a 50 percent interest. As a result, our option now allows us to acquire up to a 25 percent non-operated interest in the project. If we had chosen to exercise our option to participate, we would have participated in this project with essentially the same terms as the other existing projects in the AMI with the exception that we would not be the operator. The option to participate expired June 1, 2010. Because of the substantial changes made to the project after we acquired our option, we elected to not participate in the project, and the $1.5 million paid for the option will be refunded by September 30, 2010.

West Bay

During the six months ended June 30, 2010, operational activities in the West Bay prospect focused on firming up plans for drilling on the identified initial drilling prospect and continuing to evaluate the other leads and prospects in the project. Land, regulatory and surface access preparations are currently in progress focused on taking the initial drilling prospect to drill-ready status. We finalized a 3-D seismic data trade with a third party that provides access to additional seismic data, which allows for more complete technical evaluation of the leads and prospects identified in the project. We are in the process of merging the newly acquired seismic data set with our

existing seismic data, and interpreting the merged data set. During the six months ended June 30, 2010, we incurred $0.3 million for leasing activities on the West Bay project. There is no remaining 2010 budget for this project.

Western United States – Antelope

During the six months ended June 30, 2010, we had cash capital expenditures of $1.8 million for leasing activities on the Antelope prospect. The remaining 2010 budget for leasing activities on the Antelope prospect is $8.3 million. Drilling, completion and testing activities are in progress on three separate projects on the Antelope prospect in Duchesne and Uintah Counties, Utah.

Mesaverde Gas Exploration and Appraisal Project

The Mesaverde Gas Exploration and Appraisal Project (“Mesaverde”) is targeted to explore for and develop oil and natural gas from multiple reservoir intervals in the Mesaverde formation in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties. Operational activities during the three months ended March 31, 2010 included completion of the initial testing activities on the Mesaverde horizons in the deep natural gas test well (Bar F #1-20-3-2 [“Bar F”]) that commenced drilling on June 15, 2009. No operational activities occurred in the Mesaverde during the three months ended June 30, 2010. The Bar F was drilled to a total depth of 17,566 feet and an extended production test of the Mesaverde has been completed. Testing was focused on the evaluation of the natural gas potential of the Mesaverde tight gas reservoir over a prospective interval from 14,000 to 17,400 feet. Completion activities consisted of hydraulic fracturing of eight separate reservoir intervals in the Mesaverde and multiple extended flow tests of the individual fractured intervals, along with a flow test of the commingled eight intervals. Gas was tested at flow rates of 1.5-2 million cubic feet per day (“MMCFD”) from selected intervals. While the results to date have not definitively determined the commerciality of a stand-alone development of the Mesaverde in the current gas price environment, we believe these results indicate progress toward that commerciality determination and that the Mesaverde reservoir remains potentially prospective over a portion of our land position. Exploratory drilling costs for the Mesaverde have been suspended pending further evaluation. See Note 2 –Summary of Significant Accounting Policies, Property and Equipment. During the six months ended June 30, 2010, we had cash capital expenditures of $5.1 million for drilling, completion and testing activities. A provision has been included in the 2010 budget for core and other analysis required to evaluate the results of the Bar F gas test well.

Lower Green River/Upper Wasatch Oil Delineation and Development Project

A second project has also been pursued in the Bar F exploration well. After completion of the initial testing program on the Mesaverde deep gas as described above, we moved uphole in the same well to test multiple oil bearing intervals at depths from 8,200 feet to 9,500 feet in the Lower Green River/Upper Wasatch formations. Operational activities during the six months ended June 30, 2010 included completion of testing of the Bar F, completion of the Bar F, including installation of an electric submersible pump, completion of production facilities for the Bar F, and routine production operations of the Bar F. Results of the testing have been positive, and we believe the results indicate that we have made a commercial oil discovery in the Lower Green River/Upper Wasatch formations. The well commenced flowing naturally on extended test on March 24, 2010 with initial rates of approximately 900 barrels of oil per day (“BOPD”) of 42 degree API oil. An electric submersible pump was installed in the well in May 2010. As of June 30, 2010, the well had produced in excess of 32,000 gross barrels of oil since the commencement of the flow test, with the oil being sold in the Salt Lake City, Utah market. During the second quarter 2010, we developed an estimate of reserves accessed by the Bar F well, incorporating the results of the flow testing and initial phases of permanent production operation of the well. During the six months ended June 30, 2010, we had cash capital expenditures of $5.2 million in drilling, completion and testing activities.

Our Board of Directors has authorized a five-well Lower Green River/Upper Wasatch delineation and development drilling program, which is planned to take place beginning in the third quarter of 2010 at a capital cost of $21.2 million (net to Harvest). This five-well program would further delineate and appraise the extent of the Lower Green River/Upper Wasatch discovery made in the Bar F, and is also expected to establish additional production from the Lower Green River/Upper Wasatch reservoirs in at least some of the five appraisal wells. The Lower Green River/Upper Wasatch formations are productive in the Altamont/Bluebell oil field approximately six miles north of the Bar F well. Operational activities during the six months ended June 30, 2010 on the five well Lower Green River/Upper Wasatch delineation program included preparations and well planning for the drilling program to be implemented in the second half of 2010. The first well of the five well delineation program, the Kettle #1-10-3-1 (“Kettle”), spud on July 14, 2010 and is drilling as of August 9, 2010. The five wells are planned to be drilled back-to-back. During the six months ended June 30, 2010, we had cash capital expenditures of $0.1 million in well planning. The remaining 2010 budget for the Lower Green River/Upper Wasatch delineation and development drilling program is $21.0 million.

Monument Butte Extension Appraisal and Development Project

Our Board of Directors has authorized six additional Monument Butte Extension appraisal and development wells planned to be drilled beginning in the third quarter of 2010. The estimated gross drilling and completion cost per well is $0.9 million, and we will have an approximate 37 percent working interest in the six wells after the acquisition of the incremental 10 percent interest from our partner. This six-well expansion program is a follow up to the successful completion of the initial eight-well program that was drilled in late 2009 and early 2010. The expansion is planned to occur on acreage immediately adjacent to the initial eight-well program. The first well of the six-well delineation program spud on July 29, 2010 and was logged on August 1, 2010. The six wells are planned to be drilled back-to-back. Our 2010 budget for this six-well program is $2.0 million.

Certain operating statistics for the three and six months ended June 30, 2010 for the U.S. operations are set forth below. This information is provided at our net ownership. As of June 30, 2010, our average net revenue interest is 33.24 percent in the eight producing wells in the Monument Butte Extension and 24.92 percent in the Lower Green/Upper Wasatch Project. Substantially all of the oil and gas production, cash operating expense and depletion expense listed below are associated with the Monument Butte Extension project. The cash capital expenditures listed below are associated with the Monument Butte Extension, the Lower Green River/Upper Wasatch project and Mesaverde project combined. This information may not be representative of future results.


	Three Months		Six Months
	Ended		Ended
	June 30, 2010		June 30, 2010
Barrels of oil sold		41,881		84,149
Cubic feet of gas sold		49,467		135,803
Total barrels of oil equivalent		50,125		106,783
Average price per barrel	$	64.35	$	65.53
Average price per thousand cubic feet	$	4.43	$	3.86
Cash operating costs ($millions)	$	0.5	$	0.6
Cash capital expenditures ($millions)	$	10.4	$	23.9
Depletion expense per barrel of oil equivalent	$	22.90	$	15.07

Crude oil delivered from the Monument Butte Extension is priced with reference to NYMEX CL1 – Light Sweet Crude Contract published prices. Natural gas delivered from the Monument Butte Extension is priced with reference to NYMEX Henry Hub published prices. Crude oil delivered from the Lower Green River/Upper Wasatch is priced with reference to Chevron Altamont Yellow Wax monthly average posting.

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

Two drill sites were selected in 2009. Operational activities during the six months ended June 30, 2010 focused on well planning, construction for the two test well sites, mobilization of rig and ancillary equipment to the first drill site and purchase of drilling equipment. After delays in acquiring permits to mobilize the drilling rig from its port location to the drilling pad, it is now expected that the first of two exploratory wells will spud late in the third quarter of 2010. In accordance with the farm-in agreement, we expect to fund 100 percent of the well expenditures to earn our 47 percent working interest up to a cap of $10.7 million; thereafter, we will pay in proportion to our working interest. Prior to drilling the first exploration well, subject to the estimated cost of that well, our partner will have a one-time option to increase the level of the carried interest to a maximum of $20.0 million, and as compensation for the increase, we will increase our participation to a maximum of 54.65 percent. This equates to a total carried cost for the farm-in of $9.1 million. Our partner intends to exercise their option to increase the level of the carried interest and is currently reviewing the amount of the increase. During the six months ended June 30, 2010, we had cash capital expenditures of $5.6 million for well planning, construction and drilling equipment and $1.3 million for seismic data processing and reprocessing. The remaining 2010 budget for the Budong PSC is $14.5 million.

Dussafu Project — Gabon (“Dussafu PSC”)

The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources, entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. It has been agreed that the second three-year exploration phase will be extended until May 27, 2011, at which time the partners can elect to enter a third exploration phase. Operational activities during the six months ended June 30, 2010 focused on maturation of prospect inventory and well planning. Subject to drilling rig availability, we expect to drill an exploratory well in the second quarter of 2011. During the six months ended June 30, 2010, we had cash capital expenditures of $1.6 million in well planning and $0.3 million for seismic data processing and reprocessing. The remaining 2010 budget for the Dussafu PSC is $3.7 million.

Oman (“Block 64 EPSA”)

Operational activities during the six months ended June 30, 2010 include the geological studies, baseline environmental and social study and 3-D pre-stack depth migration reprocessing of approximately 1,000 square kilometers of existing 3-D seismic data. During the six months ended June 30, 2010, we had cash capital expenditures of $0.4 million on geological, environmental and social studies and $0.5 million for seismic data processing and reprocessing. The remaining 2010 budget for the Block 64 EPSA is $1.6 million.

Other Exploration Projects

Relating to other projects, we had cash capital expenditures of $0.6 million during the six months ended June 30, 2010. Either one of the two exploratory wells to be drilled in 2010 on the Budong PSC or further results from the Bar F well in Utah can have a significant impact on our ability to obtain financing, record reserves and generate cash flow in 2010 and beyond.

Management Changes

In August 2007, Mr. Karl L. Nesselrode, Vice President, Engineering and Business Development of Harvest, accepted a long-term secondment to Petrodelta as its Operations and Technical Manager. In July 2010, Mr. Nesselrode’s secondment ended, and Mr. G. Michael Morgan, Vice President of Business Development of Harvest, will temporarily replace Mr. Nesselrode as Petrodelta’s Operations and Technical Manager. Under the terms of the conversion contract, HNR Finance has the right to nominate the Operations and Technical Manager. Mr. Morgan will remain an officer of Harvest.

Capital Resources and Liquidity

Working Capital.Our capital resources and liquidity are affected by the ability of Petrodelta to pay dividends. We expect to receive future dividends from Petrodelta; however, we expect the amount of any future dividends to be lower in the near term as Petrodelta reinvests most of its earnings into the company in support of its drilling and appraisal activities. At CVP’s instructions, Petrodelta has set up a reserve within the equity section of its 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. It is anticipated that all available cash during 2010 and 2011 will be used to meet current operating requirements and will not be available for dividends. SeeItem 1A – Risk FactorsandItem 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operationsin our Annual Report on Form 10-K for the year ended December 31, 2009 for a complete description of the situation in Venezuela and other matters.

Based on our cash balance of $31.5 million at June 30, 2010, we will require additional funds in order to fund our future operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration, appraisal and development projects and to a lesser extent, general and administrative costs. Currently, our primary source of cash is dividends from Petrodelta and to a lesser extent, production from the Monument Butte Extension and Lower Green River/Upper Wasatch projects. In May 2010, Petrodelta declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). However, there is no certainty that Petrodelta will pay additional dividends in 2010 or 2011. Our lack of cash flow and the anticipated level 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, and cost reductions. In addition, we could delay discretionary capital spending to future periods or sell, farm-out or otherwise monetize 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.

We continue to pursue one particular additional alternative source of financing through an Islamic (sukuk) financing, in which one of our subsidiaries would form and contribute certain assets to a partnership and subsequently sell a minority interest in the partnership to one or more third parties for approximately $250 million. Although the terms of this transaction have not been finalized, we anticipate that the terms would include our agreement to pay all or a substantial portion of the dividends paid by Petrodelta to which we are entitled over the next five or six years to reacquire all of the third-party partnership interests, including premiums thereon. While we may be able to consummate this financing transaction during the second half of 2010, there can be no assurances that this transaction will be consummated, and we may consider alternative forms of additional financing if we deem necessary or advisable with respect to our operations from time to time.

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


	Six Months Ended June 30,
	2010			2009
	(in thousands)
Net cash used in operating activities	$	(5,156	)	$	(19,847	)
Net cash used in investing activities		(24,949	)		(11,651	)
Net cash provided by (used in) financing activities		29,297			(1,276	)

Net decrease in cash	$	(808	)	$	(32,774	)

At June 30, 2010, we had current assets of $57.2 million and current liabilities of $11.9 million, resulting in working capital of $45.3 million and a current ratio of 4.8:1. This compares with a working capital of $34.2 million and a current ratio of 3.0:1 at December 31, 2009. The increase in working capital of $11.1 million was primarily due to the receivable for the $12.2 million dividend net to HNR Finance ($9.8 million net to our 32 percent interest) from our unconsolidated equity affiliate.

Cash Flow used in Operating Activities.During the six months ended June 30, 2010 and 2009, net cash used in operating activities was approximately $5.2 million and $19.8 million, respectively. The $14.6 million decrease was primarily due to increases in accounts and notes receivable and accounts payable offset by the payments of accrued interest and income taxes and a decrease in accrued expenses. The six months ended June 30, 2010, also included $6.0 million in oil and gas revenue from the Monument Butte Extension and Lower Green River/Upper Wasatch areas in Utah.

Cash Flow from Investing Activities.During the six months ended June 30, 2010, we had cash capital expenditures of approximately $23.9 million. Of the 2010 expenditures, $15.4 million was attributable to activity on the Antelope projects, $5.6 million was attributable to activity on the Budong PSC, $1.6 million was attributable to activity on the Dussafu PSC and $1.3 million was attributable to other projects. During the six months ended June 30, 2009, we had cash capital expenditures of approximately $11.3 million. Of the 2009 expenditures, $7.6 million was attributable to activity on the Antelope project, $2.2 million to Block 64 EPSA, $0.1 million to the Dussafu PSC and $1.4 million to other projects.

During the six months ended June 30, 2010, we deposited with a U.S. bank $1.0 million as collateral for a standby letter of credit issued in support of a bank guarantee required as a performance guarantee for a joint study. During the three months ended March 31, 2009, we deposited with a U.S. bank $1.7 million as collateral for two standby letters of credit issued in support of bank guarantees required as part of a project bidding process. During the three months ended June 30, 2009, both standby letters of credit were cancelled and the collateral returned to us.

During the three months ended March 31, 2010, we incurred $1.5 million for the option to acquire an interest in a new project. During the three months ended June 30, 2010, we elected to not participate in the new project and the $1.5 million paid for the option will be returned to us. The $1.5 million was reclassified to Accounts and Notes Receivable at June 30, 2010. During the six months ended June 30, 2009, we incurred $0.3 million of investigatory costs related to various international and domestic exploration studies.

Petrodelta’s capital commitments will be determined by its business plan. Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. Our budgeted capital expenditures for 2010 will be funded through our existing cash balances, the February 2010 8.25 percent convertible debt offering, other financing sources, accessing equity and debt markets, and cost reductions. In addition, we could delay discretionary capital spending to future periods or sell, farm-out or otherwise monetize assets as necessary to maintain the liquidity required to run our operations, as warranted.

Cash Flow from Financing Activities.During the six months ended June 30, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes, incurred $2.7 million in deferred financings costs related to the $32.0 million convertible debt offering that are being amortized over the life of the financial instrument and $0.1 million in legal fees associated with a prospective financing. During the six months ended June 30, 2009, we incurred $1.5 million in legal fees associated with a prospective financing.

Results of Operations

You should read the following discussion of the results of operations for the three and six months ended June 30, 2010 and 2009 and the financial condition as of June 30, 2010 and December 31, 2009 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, 2009.

Three Months Ended June 30, 2010 Compared with Three Months Ended June 30, 2009

We reported a net loss attributable to Harvest of $0.3 million, or $(0.01) diluted earnings per share, for the three months ended June 30, 2010, compared with a net loss attributable to Harvest of $4.2 million, or $(0.13) diluted earnings per share, for the three months ended June 30, 2009.

Revenues were higher in the three months ended June 30, 2010 compared with the three months ended June 30, 2009 due to the Monument Butte Extension wells coming on production in December 2009 and the Lower Green River/Upper Wasatch coming on production in March 2010. Production for the two areas for the three months ended June 30, 2010 was:


	Lower Green		Monument
	River/Upper		Butte
	Wasatch		Extension
Barrels of oil sold		11,625		30,256
Cubic feet of gas sold		—		49,467
Total barrels of oil equivalent		11,625		38,500
Average price per barrel	$	69.93	$	62.19
Average price per thousand cubic feet	$	—	$	4.43

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


	Three Months Ended
	June 30,						Increase
	2010			2009			(Decrease)
Lease operating costs and production taxes	$	0.4		$	—		$	0.4
Depletion, depreciation and amortization		1.3			0.1			1.2
Exploration expense		1.5			3.5			(2.0	)
General and administrative		6.4			6.4			—
Taxes other than on income		0.2			0.2			—
Investment earnings and other		(0.1	)		(0.3	)		0.2
Interest expense		0.7			—			0.7
Income tax expense		0.2			0.1			0.1

Lease operating costs were higher in the three months ended June 30, 2010 compared to the three months ended June 30, 2009 due to the inception of oil and natural gas operations in the U.S. beginning in late December 2009. Costs incurred were primarily for water disposal, gas gathering transportation and processing, fuel, and other routine oil production activities. Depletion expense, which was all attributable to U.S. production, was $1.1 million ($22.90 per equivalent barrel) for the three months ended June 30, 2010. During the second quarter 2010, we developed an estimate of reserves accessed by the Bar F well, incorporating the results of the flow testing and initial phases of permanent production operation of the well and updated the reserves for the Monument Butte wells. Proved reserves for the Bar F were 128,074 BOE. Proved reserves for Monument Butte were 484,443 BOE, a 50 percent increase from January 1, 2010 reserves.

During the three months ended June 30, 2010, we incurred $1.3 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations and $0.2 million related to other general business development activities. During the three months ended June 30, 2009, we incurred $2.4 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations and $1.1 million related to other general business development activities.

General and administrative costs for the three months ended June 30, 2010 were consistent with the three months ended June 30, 2009. Taxes other than on income for the three months ended June 30, 2010 were consistent with the three months ended June 30, 2009.

Investment earnings and other decreased in the three months ended June 30, 2010 compared to the three months ended June 30, 2009 due to lower interest rates earned on lower cash balances. Interest expense was higher for the three months ended June 30, 2010 compared to the three months ended June 30, 2009 due to the interest

associated with our $32 million convertible debt offering in February 2010 offset by interest capitalized to oil and gas properties of $0.2 million.

For the three months ended June 30, 2010, income tax expense was not materially different from that of the three months ended June 30, 2009.

Petrodelta’s reporting and functional currency is the U.S. Dollar. Net income from unconsolidated equity affiliates includes a $1.9 million, before tax, ($0.6 million, before tax, net to our 32 percent interest) remeasurement gain on revaluation of assets and liabilities recorded by Petrodelta due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. Petrodelta’s current tax rate increased from 59 percent for the three months ended June 30, 2009 to 79 percent for the three months ended June 30, 2010 primarily as a result of changes to the 2010 tax projections for the taxability of the exchange gain and reversing the projected recognition of certain tax deductions. The changes to the 2010 tax projection resulted in the recording of $17.1 million additional tax expense in the second quarter of 2010 related to income attributable to the first quarter of 2010. The Bolivar devaluation increased Petrodelta’s overall effective tax rate due to the effect of the devaluation on the deferred tax asset in the first quarter of 2010. The adjustment to reconcile to reported net income from unconsolidated affiliate for deferred income taxes increased due to the effect of the currency devaluation on the deferred tax asset associated with the non-monetary assets impacted by inflationary adjustments.

At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion. Accordingly, we no longer record losses that would cause our equity investment to go into a negative position. For the three months ended June 30, 2010, Fusion reported a net loss of $0.8 million ($0.4 million net to our 49 percent interest). This loss is not reported in the three months ended June 2010 net income from unconsolidated equity affiliates as reporting it would take our equity investment into a negative position.

Six Months Ended June 30, 2010 Compared with Six Months Ended June 30, 2009

We reported net income attributable to Harvest of $24.3 million, or $0.65 diluted earnings per share, for the six months ended June 30, 2010, compared with a net loss attributable to Harvest of $9.0 million, or $(0.27) diluted earnings per share, for the six months ended June 30, 2009.

Revenues were higher in the six months ended June 30, 2010 compared with the six months ended June 30, 2009 due to the Monument Butte Extension wells coming on production in December 2009 and the Lower Green River/Upper Wasatch coming on production in March 2010. Production for the two areas for the six months ended June 30, 2010 was:


	Lower Green		Monument
	River/Upper		Butte
	Wasatch		Extension
Barrels of oil sold		14,166		69,983
Cubic feet of gas sold		—		135,803
Total barrels of oil equivalent		14,166		92,617
Average price per barrel	$	70.29	$	64.56
Average price per thousand cubic feet	$	—	$	3.86

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


	Six Months Ended
	June 30,						Increase
	2010			2009			(Decrease)
Lease operating costs and production taxes	$	0.7		$	—		$	0.7
Depletion, depreciation and amortization		1.8			0.2			1.6
Exploration expense		2.7			4.4			(1.7	)
General and administrative		11.8			12.9			(1.1	)
Taxes other than on income		0.5			0.6			(0.1	)
Investment earnings and other		(0.3	)		(0.6	)		0.3
Interest expense		1.1			—			1.1
Loss on exchange rates		1.6			—			1.6
Income tax expense		0.1			1.0			(0.9	)

Lease operating costs and production taxes were higher in the six months ended June 30, 2010 compared to the six months ended June 30, 2009 due to the inception of oil and natural gas operations in the U.S. beginning in late December 2009. Costs incurred were primarily for water disposal, gas gathering transportation and processing, fuel, and other routine oil production activities. Depletion expense, which was all attributable to U.S. production, was $1.6 million ($15.07 per equivalent barrel) for the six months ended June 30, 2010. During the second quarter 2010, we developed an estimate of reserves accessed by the Bar F well, incorporating the results of the flow testing and initial phases of permanent production operation of the well and updated the reserves for the Monument Butte wells. Proved reserves for the Bar F were 128,074 BOE. Proved reserves for Monument Butte were 484,443 BOE, a 50 percent increase from January 1, 2010 reserves.

During the six months ended June 30, 2010, we incurred $2.2 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations and $0.5 million related to other general business development activities. During the six months ended June 30, 2009, we incurred $2.8 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations and $1.6 million related to other general business development activities.

General and administrative costs were lower in the six months ended June 30, 2010 compared to the six months ended June 30, 2009 primarily due to lower employee related costs and contract services. Taxes other than on income for the six months ended June 30, 2010 were consistent with the six months ended June 30, 2009.

Investment earnings and other decreased in the six months ended June 30, 2010 compared to the six months ended June 30, 2009 due to lower interest rates earned on lower cash balances. Interest expense was higher for the six months ended June 30, 2010 compared to the six months ended June 30, 2009 due to the interest associated with our $32 million convertible debt offering in February 2010 offset by interest capitalized to oil and gas properties of $0.2 million.

Loss on exchange rates is higher for the six months ended June 30, 2010 compared to the six months ended June 30, 2009 due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. Harvest Vinccler, S.C.A. (“Harvest Vinccler”) revalued the appropriate monetary accounts that were Bolivar-denominated to U.S. Dollars, Harvest Vinccler’s functional and reporting currency, at the published exchange rate of 4.30 Bolivars per U.S. Dollar. The primary factor in Harvest Vinccler’s loss on currency exchange rates is that Harvest Vinccler had substantially higher Bolivar denominated assets than Bolivar denominated liabilities. During the six months ended June 30, 2010, Harvest Vinccler recorded a $1.6 million remeasurement loss on revaluation of assets and liabilities.

For the six months ended June 30, 2010, income tax expense was lower than that of the six months ended June 30, 2009 due to income tax assessed in the Netherlands of $0.9 million as a result of financing activities, which was recorded in the first quarter of 2009.

Petrodelta’s reporting and functional currency is the U.S. Dollar. Net income from unconsolidated equity affiliates includes a $120.7 million, before tax, ($38.6 million, before tax, net to our 32 percent interest) remeasurement gain on revaluation of assets and liabilities recorded by Petrodelta due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. The Bolivar devaluation increased Petrodelta’s overall effective tax rate due to the effect of the devaluation on the deferred tax asset in the first quarter of 2010.

The adjustment to reconcile to reported net income from unconsolidated affiliate for deferred income taxes increased due to the effect of the currency devaluation on the deferred tax asset associated with the non-monetary assets impacted by inflationary adjustments.

At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion. Accordingly, we no longer record losses that would cause our equity investment to go into a negative position. For the six months ended June 30, 2010, Fusion reported a net loss of $1.7 million ($0.8 million net to our 49 percent interest). This loss is not reported in the six months ended June 2010 net income from unconsolidated equity affiliates as reporting it would take our equity investment into a negative position.

Effects of Changing Prices, Foreign Exchange Rates and Inflation

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

Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004, March 2005 and again in January 2010. The currency conversion restrictions or the adjustment in the exchange rate have not had a material impact on us at this time. Dividends from Petrodelta will be denominated in U.S. Dollars when paid. Within the United States and other countries in which we conduct business, inflation has had a minimal effect on us, but it is potentially an important factor with respect to results of operations in Venezuela.

Our net foreign exchange losses attributable to our international operations were $1.6 million for the six months ended June 30, 2010. The U.S. Dollar and Bolivar exchange rates had not been adjusted from March 2005 until January 2010. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our control. 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.

On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement, which established new exchange rates for the Venezuela Bolivar (“Bolivar”)/U.S. Dollar currencies that entered into force on January 11, 2010. Each exchange rate is applied to foreign currency sales and purchases conducted through the Foreign Currency Administration Commission (“CADIVI”), in the cases expressly provided in the Exchange Agreement. In this regard, the exchange rates established in the Agreement are: 2.60 Bolivars per U.S. Dollar and 4.30 Bolivars per U.S. Dollar. The 2.60 Bolivar exchange rate applies to the food, health, medical and technology sectors. The 4.30 Bolivar exchange rate applies to all other sectors not expressly established by the 2.60 Bolivar exchange rate. As an alternative to the use of the official exchange rate, an exemption under the Venezuelan Criminal Exchange Law for transactions in certain securities resulted in an indirect securities transaction market of foreign currency exchange, through which companies could obtain foreign currency legally without requesting it from CADIVI. Publicly available quotes did not exist for the securities transaction exchange rate but such rates could be obtained from brokers. Securities transaction markets were used to move financial securities into and out of Venezuela. In May 2010, the government of Venezuela effectively eliminated this indirect market of foreign currency exchange.

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, 2009. The information about market risk for the six months ended June 30, 2010 does not differ materially from that discussed in the Annual Report on Form 10-K for the year ended December 31, 2009.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.We have established disclosure controls and procedures that are designed to ensure the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management,

including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on their evaluation as of June 30, 2010, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) were effective.

Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the Internal Control Integrated Framework, our management concluded that our internal control over financial reporting was effective as of June 30, 2010.

Changes in Internal Control over Financial Reporting.There have been no changes in our internal control over financial reporting during our most recent quarter ended June 30, 2010, that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

See our Annual Report on Form 10-K for the year ended December 31, 2009 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

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.In addition, potential regulatory actions could increase our costs and reduce our liquidity, delay our operations or otherwise alter the way we conduct our business. Exploration and development and the production and sale of oil and gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

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

	•		Response to unexpected releases to the environment;

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

	•		The spacing of wells;

	•		Unitization and pooling of properties;

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

	•		Taxation.

Under these laws, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs, natural resource damages and other environmental damages. We also could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action orders. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition, results of operations or cash flows.

In addition, changes to existing regulations or the adoption of new regulations may unfavorably impact us, our suppliers or our customers. For example, governments around the world have become increasingly focused on climate change matters. In the United States, legislation that directly impacts our industry has been proposed covering areas such as emission reporting and reductions, hydraulic fracturing, the repeal of certain oil and gas tax incentives and tax deductions, and the regulation of over-the-counter commodity hedging activities. These and other potential regulations could increase our costs, reduce our liquidity, delay our operations or otherwise alter the way we

conduct our business, negatively impacting our financial condition, results of operations and cash flows.

Congress has been actively considering legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs. In June 2009, the U.S. House of Representatives passed a cap and trade bill known as the American Clean Energy and Security Act of 2009, which is now being considered by the U.S. Senate. In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases. Further, in April 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act. In April 2009, EPA responded to the Massachusetts, et al. v. EPA decision with a proposed finding that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from new motor vehicles and motor vehicle engines contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change. EPA published the final version of this finding on December 15, 2009, which allowed EPA to proceed with the rulemaking process to regulate greenhouse gases under the Clean Air Act. In anticipation of the finalization of EPA’s finding that greenhouse gases threaten public health and welfare, and that greenhouse gases from new motor vehicles contribute to climate change, EPA proposed a rule in September 2009 that would require a reduction in emissions of greenhouse gases from motor vehicles and would trigger applicability of Clean Air Act permitting requirements for certain stationary sources of greenhouse gas emissions. In response to this issue, EPA also proposed a tailoring rule that would, in general, only impose greenhouse gas permitting requirements on facilities that emit more than 25,000 tons per year of greenhouse gases. Moreover, in September 2009, EPA finalized a rule requiring nation-wide reporting of greenhouse gas emissions in 2011 for emissions occurring in 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent greenhouse gas emissions per year, and to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines.

In response to the recent oil spill in the Gulf of Mexico, the United States Congress is considering a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore that could result in significant additional laws or regulations governing our operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990.

Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Additional costs or operating restrictions associated with legislation or regulations could have a material adverse effect on our operating results and cash flows, in addition to the demand for the natural gas and other hydrocarbon products that we produce.

We may be subject to more expensive insurance coverage for our assets as a result of the recent rig explosion and oil spill in the Gulf of Mexico.The recent rig explosion and resulting oil spill in the Gulf of Mexico may make it increasingly difficult to obtain onshore and offshore property damage, well control, or related insurance coverage on economic terms, or at all.

See our Annual Report on Form 10-K for the year ended December 31, 2009 underItem 1A Risk Factorsfor a description of certain other risk factors. Except for the risk factor updates set forth above, there have been no material developments in such risk factors since the filing of such Annual Report.

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

During the three months ended June 30, 2010, we issued 0.3 million shares of restricted stock valued at $1.8 million to certain of our employees and non-employee directors under our 2010 Long Term Incentive Plan (the “Plan”). Because we had not yet filed our registration statement on Form S-8 with respect to the Plan, we issued the shares in reliance on an exemption from registration contained

in Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”), or the common law “no sale” exemption for non-contributory issuances to employees. Such shares have not been registered under the Securities Act, or any state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. This Quarterly Report on Form 10-Q does not constitute an offer to sell, or a solicitation of an offer to buy, any security and shall not constitute an offer, solicitation or sale in any jurisdiction in which such offering would be unlawful.

Item 6. Exhibits

(a) Exhibits

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

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

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

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

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

	10.1		2010 Long Term Incentive Plan. (Incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed with the Securities and Exchange Commission on April 9, 2010, file No. 1-10762.)

	10.2		Form of 2010 Long Term Incentive Plan Employee Restricted Stock Award Agreement.

	10.3		Form of 2010 Long Term Incentive Plan Stock Option Award Agreement.

	10.4		Form of 2010 Long Term Incentive Plan Director Restricted Stock Award Agreement.

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

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

	32.1		Certification accompanying Quarterly Report on Form 10-Q pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by James A. Edmiston, President and Chief Executive Officer.

	32.2		Certification accompanying Quarterly Report on Form 10-Q pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by Stephen C. Haynes, Vice President, Chief Financial Officer and Treasurer.

SIGNATURES

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


	HARVEST NATURAL RESOURCES, INC.
Dated: August 9, 2010	By:	/s/ James A. Edmiston
		James A. Edmiston
		President and Chief Executive Officer

Dated: August 9, 2010	By:	/s/ Stephen C. Haynes
		Stephen C. Haynes
		Vice President - Finance, Chief Financial Officer and Treasurer

Exhibit Index


Exhibit
Number		Description

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

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

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

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

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

10.1		2010 Long Term Incentive Plan. (Incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed with the Securities and Exchange Commission on April 9, 2010, file No. 1-10762.)

10.2		Form of 2010 Long Term Incentive Plan Employee Restricted Stock Award Agreement.

10.3		Form of 2010 Long Term Incentive Plan Stock Option Award Agreement.

10.4		Form of 2010 Long Term Incentive Plan Director Restricted Stock Award Agreement.

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

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

32.1		Certification accompanying Quarterly Report on Form 10-Q pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by James A. Edmiston, President and Chief Executive Officer.

32.2		Certification accompanying Quarterly Report on Form 10-Q pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by Stephen C. Haynes, Vice President, Chief Financial Officer and Treasurer.

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Harvest Natural Resources (HNR) 10-Q2010 Q2 Quarterly report

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