e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


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

For the Quarterly Period Ended March 31, 2010 or


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

for the transition period from to

Commission File No. 1-10762

Harvest Natural Resources, Inc.

(Exact Name of Registrant as Specified in Its Charter)


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


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

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

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

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

Yes þ No o

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

Yes o No o

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


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

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

Yes o No þ

At April 30, 2010, 33,260,554 shares of the Registrant’s Common Stock were outstanding.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	March 31,			December 31,
	2010			2009
	(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	44,115		$	32,317
Restricted cash		1,000			—
Accounts and notes receivable, net:
Oil and gas revenue receivable		2,459			166
Joint interest and other		1,099			8,047
Note receivable		3,304			3,265
Advances to equity affiliate		3,861			4,927
Prepaid expenses and other		1,864			2,214

TOTAL CURRENT ASSETS		57,702			50,936

OTHER ASSETS		7,746			3,613
INVESTMENT IN EQUITY AFFILIATES		272,356			233,989
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		70,535			58,543
Other administrative property		3,092			3,085

		73,627			61,628
Accumulated depreciation and amortization		(1,952	)		(1,387	)

		71,675			60,241

	$	409,479		$	348,779


LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Joint interest and royalty payable	$	134		$	—
Accounts payable, trade and other		2,101			696
Accrued expenses		9,591			10,253
Accrued interest		308			4,691
Income taxes payable		600			1,090

TOTAL CURRENT LIABILITIES		12,734			16,730
LONG-TERM DEBT		32,000			—
ASSET RETIREMENT LIABILITY		79			50
COMMITMENTS AND CONTINGENCIES (See Note 3)		—			—

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 March 31, 2010 and December 31, 2009, respectively; issued 39,542 shares and 39,495 shares at March 31, 2010 and December 31, 2009, respectively		395			395
Additional paid-in capital		214,190			213,337
Retained earnings		150,834			126,244
Treasury stock, at cost, 6,469 shares and 6,448 shares at March 31, 2010 and December 31, 2009, respectively		(65,494	)		(65,383	)

TOTAL HARVEST STOCKHOLDERS’ EQUITY		299,925			274,593
NONCONTROLLING INTEREST		64,741			57,406

TOTAL EQUITY		364,666			331,999

	$	409,479		$	348,779

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Three Months Ended March 31,
	2010			2009
	(in thousands, except per share data)
REVENUES
Oil sales	$	2,784		$	—
Gas sales		340			—

		3,124			—


EXPENSES
Lease operating costs		126			—
Production taxes		119			—
Depletion, depreciation and amortization		566			69
Exploration expense		1,246			972
General and administrative		5,416			6,467
Taxes other than on income		300			317

		7,773			7,825

LOSS FROM OPERATIONS		(4,649	)		(7,825	)

OTHER NON-OPERATING INCOME (EXPENSE)
Investment earnings and other		131			358
Interest expense		(416	)		—
Loss on exchange rates		(1,527	)		(27	)

		(1,812	)		331


LOSS FROM CONSOLIDATED COMPANIES BEFORE INCOME TAXES		(6,461	)		(7,494	)
INCOME TAX EXPENSE (BENEFIT)		(19	)		889

LOSS FROM CONSOLIDATED COMPANIES		(6,442	)		(8,383	)
NET INCOME FROM UNCONSOLIDATED EQUITY AFFILIATES		38,367			4,410

NET INCOME (LOSS)		31,925			(3,973	)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		7,335			803

NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST	$	24,590		$	(4,776	)


NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST PER COMMON SHARE:
Basic	$	0.74		$	(0.15	)

Diluted	$	0.64		$	(0.15	)

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Three Months Ended March 31,
	2010			2009
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	31,925		$	(3,973	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depletion, depreciation and amortization		566			69
Amortization of debt financing costs		108			—
Net income from unconsolidated equity affiliates		(38,367	)		(4,410	)
Non-cash compensation related charges		853			1,154
Changes in Operating Assets and Liabilities:
Accounts and notes receivable		4,616			162
Advances to equity affiliate		1,066			(180	)
Prepaid expenses and other		350			104
Revenue and royalty payable		134			—
Accounts payable		1,405			265
Accrued expenses		793			(2,779	)
Accrued interest		(4,383	)		—
Income taxes payable		(490	)		881

NET CASH USED IN OPERATING ACTIVITIES		(1,424	)		(8,707	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions of property and equipment		(13,495	)		(7,067	)
Increase in restricted cash		(1,000	)		(1,735	)
Investment costs		(1,656	)		(531	)

NET CASH USED IN INVESTING ACTIVITIES		(16,151	)		(9,333	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuances of common stock		—			69
Proceeds from issuance of long-term debt		32,000			—
Financing costs		(2,627	)		(785	)

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		29,373			(716	)


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		11,798			(18,756	)

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

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	44,115		$	78,409

Supplemental Schedule of Noncash Investing and Financing Activities:

During the three months ended March 31, 2010, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 20,831 shares being added to treasury stock at cost. During the three months ended March 31, 2009, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 2,117 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 Months Ended March 31, 2010 and 2009 (unaudited)

Note 1 — Organization and Summary of Significant Accounting Policies

Interim Reporting

In our opinion, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position as of March 31, 2010, and the results of operations and cash flows for the three months ended March 31, 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 exclusive of 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, mainly onshore in West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in the Sultanate of Oman (“Oman”), and offshore of the People’s Republic of China (“China”). See Note 7 – United States, Note 8 – Indonesia, Note 9 – Gabon and Note 10 – Oman.

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

The U.S. Dollar is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta.

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. 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. During the three months ended March 31, 2010, Harvest Vinccler recorded a $1.5 million remeasurement loss on revaluation of assets and liabilities.

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 March 31, 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. See Note 2 – 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.

Suspended Exploratory Drilling Costs. Our capitalized suspended exploratory drilling costs at March 31, 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 to the Mesaverde formation in the Bar F #1-20-3-2 (“Bar F”). See Note 7 – 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 March 31, 2010 and December 31, 2009, cash and cash equivalents include $36.3 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 March 31, 2010 was $47.8 million.

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 three months ended March 31, 2010 or the year ended December 31, 2009. Changes in asset retirement obligations during the three months ended March 31, 2010 and the year ended December 31, 2009 were as follows (in thousands):


	March 31,		December 31,
	2010		2009
Asset retirement obligations beginning of period	$	50	$	—
Liabilities recorded during the period		28		50
Liabilities settled during the period		—		—
Revisions in estimated cash flows		—		—
Accretion expense		1		—

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 three months ended March 31, 2010 and 2009 were as follows (in thousands):


	March 31,		March 31,
	2010		2009
Balance at beginning of period	$	57,406	$	49,603
Net income attributable to noncontrolling interest		7,335		803

Balance at end of period	$	64,741	$	50,406

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 33.3 million and 32.9 million for the three months ended March 31, 2010 and 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 39.1 million and 32.9 million for the three months ended March 31, 2010 and 2009, respectively.

An aggregate of 3.2 million and 3.3 million options were excluded from the earnings per share calculations because their exercise price exceeded the average stock price for the three months ended March 31, 2010 and 2009, respectively.

No stock options were exercised in the three months ended March 31, 2010. Stock options of 25,000 were exercised in the three months ended March 31, 2009 resulting in cash proceeds of $0.1 million.

New Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, which is included in the Accounting Standards Codification (“ASC”) under 820, “Fair Value Measurements and Disclosures” (“ASC 820”). This update requires the disclosure of transfers between the observable input categories and activity in the unobservable input category for fair value measurements. The guidance also requires disclosures about the inputs and valuation techniques used to measure fair value and became effective for our interim and annual reporting periods beginning January 1, 2010. The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows.

In February 2010, the FASB issued ASU No. 2010-09, which is included in the Codification under ASC 855, “Subsequent Events” (“ASC 855”). This update removes the requirement for an SEC filer to disclose the date through which subsequent events have been evaluated and became effective for our interim and annual reporting periods beginning January 1, 2010. The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows.

In March 2010, the FASB issued ASU No. 2010-11, which is included in the Codification under ASC 815, “Derivatives and Hedging” (“ASC 815”). This update clarifies the type of embedded credit derivative that is exempt from embedded derivative bifurcation requirements. Only an embedded credit derivative that is related to the subordination of one financial instrument to another qualifies for the exemption. This guidance became effective for our interim and annual reporting periods beginning January 1, 2010. The adoption of this guidance did not have a material impact on our consolidated financial position, results of operations or cash flows.

Note 2 — Long-Term Debt and Liquidity

Long-Term Debt

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


	March 31,		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 $2.5 million associated with this debt offering are being amortized over the life of the debt. These costs are capitalized in Other Assets at March 31, 2010.

We have incurred $2.8 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 March 31, 2010.

Liquidity – Based on our cash balance of $44.1 million at March 31, 2010, we will be required to raise additional funds in order to fund our future operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration projects and to a lesser extent general and administrative costs. Currently, our primary source of cash is dividends from Petrodelta and to a lesser extent, production from the Monument Butte Extension and Lower Green River/Upper Wasatch projects as drilling completes. However, there is no certainty that Petrodelta will pay 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 3 — 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 the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims.

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

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

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

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

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

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

	•		Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.

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

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

Note 4 — Taxes Other Than on Income

The components of taxes other than on income were:


	Three Months Ended March 31,
	2010		2009
	(in thousands)
Franchise Taxes	$	61	$	42
Payroll and Other Taxes		239		275

	$	300	$	317

Note 5 — 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 March 31,
	2010			2009
	(in thousands)
Segment Revenues
Oil and gas sales:
United States and other	$	3,124		$	—

Total oil and gas sales		3,124			—


Operating Segment Income (Loss)
Venezuela	$	36,490		$	4,716
Indonesia		(1,279	)		165
United States and other		(10,621	)		(9,657	)

Net income (loss)	$	24,590		$	(4,776	)


	March 31,			December 31,
	2010			2009
	(in thousands)
Operating Segment Assets
Venezuela	$	281,311		$	249,484
Indonesia		6,259			5,893
United States and other		143,638			113,555

		431,208			368,932
Intersegment eliminations		(21,729	)		(20,153	)

	$	409,479		$	348,779

Note 6 – 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.

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 $1.3 million of expense for the Windfall Profits Tax during the three months ended March 31, 2010. During the three months ended March 31, 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 three months ended March 31, 2010. The potential exposure to LOCTI for the three months ended March 31, 2010 is $1.1 million, $0.6 million net of tax ($0.2 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. See Note 1 – Organization and 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 months ended March 31, 2010, Petrodelta recorded a $118.7 million, before tax, ($38.0 million, before tax, net to our 32 percent interest) remeasurement gain on revaluation of assets and liabilities.

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 International Financial Reporting Standards (“IFRS”) which we have adjusted to conform to GAAP. No dividends were declared or paid during the three months ended March 31, 2010 or 2009. All amounts through Net Income Equity Affiliate represent 100 percent of Petrodelta. Summary financial information has been presented below at March 31, 2010 and December 31, 2009 and for the three months ended March 31, 2010 and 2009 (in thousands, except per unit information):


	Three Months			Three Months
	Ended			Ended
	March 31, 2010			March 31, 2009
Revenues:
Oil sales	$	141,502		$	70,029
Gas sales		1,018			2,183
Royalty		(47,427	)		(24,787	)

		95,093			47,425
Expenses:
Operating expenses		11,192			11,716
Depletion, depreciation and amortization		8,608			7,688
General and administrative		1,368			2,225
Taxes other than on income		3,604			3,071

		24,772			24,700


Income from operations		70,321			22,725

Gain on exchange rate		118,716			—
Investment Earnings and Other		2,894			2


Income before Income Tax		191,931			22,727
Current income tax expense		85,420			9,786
Deferred income tax expense (benefit)		42,464			(4,083	)

Net Income		64,047			17,024
Adjustment to reconcile to reported Net Income from Unconsolidated Equity Affiliate:
Deferred income tax expense (benefit)		(32,989	)		5,001

Net Income Equity Affiliate		97,036			12,023
Equity interest in unconsolidated equity affiliate		40	%		40	%

Income before amortization of excess basis in equity affiliate		38,814			4,809
Amortization of excess basis in equity affiliate		(334	)		(311	)
Conform depletion expense to GAAP		(113	)		703

Net income from unconsolidated equity affiliate	$	38,367		$	5,201


	March 31,		December 31,
	2010		2009
Current assets	$	489,596	$	404,825
Property and equipment		263,399		265,442
Other assets		98,823		141,245
Current liabilities		321,074		345,812
Other liabilities		34,597		33,600
Net equity		496,147		432,100

Fusion Geophysical, LLC (“Fusion”)

Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering. The purchase of Fusion extends our technical ability and global reach to support a more organic growth and exploration strategy. Our 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 three months ended March 31, 2010 and 2009, respectively. Summarized financial information for Fusion follows (in thousands, except per unit information):


	Three Months			Three Months
	Ended			Ended
	March 31, 2010			March 31, 2009
Operating Revenues	$	2,836		$	3,179


Net Loss	$	(839	)	$	(1,065	)

Equity interest in unconsolidated equity affiliate		49	%		49	%

Net loss from unconsolidated equity affiliate		(411	)		(522	)
Amortization of fair value of intangibles		—			(269	)

Net loss from unconsolidated equity affiliate	$	(411	)	$	(791	)


	March 31,		December 31,
	2010		2009
Current assets	$	2,417	$	2,726
Total assets		28,903		30,205
Current liabilities		8,002		8,024
Total liabilities		12,184		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. Under GAAP, we are not required to record losses that would cause our equity investment to go into a negative position. For the three months ended March 31, 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 March 2010 net income from unconsolidated equity affiliates as reporting it would take our equity investment into a negative position.

Approximately 25.0 percent and 35.7 percent of Fusion’s revenue for the three months ended March 31, 2010 and 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 March 31, 2010, the balance for prepaid services was approximately $0.9 million.

Note 7 – 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 now allows us to acquire up to a 25 percent non-operated interest in the project. If we exercise our option to participate, we will participate in this project with essentially the same terms as the other existing projects in the AMI with the exception that we will not be the operator. We are currently in the process of evaluating the project. The option to participate expires on June 1, 2010.

West Bay Project

During the three months ended March 31, 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 have recently finalized a 3-D seismic data trade that will provide access to additional seismic data which will allow for more complete technical evaluation of the leads and prospects identified in the project. The West Bay project represents $3.1 million of unproved oil and gas properties as of March 31, 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. 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.

Operational activities during the three months ended March 31, 2010 on the Antelope prospect focused on continuing leasing activities on private, Allottee, and tribal land. The Antelope prospect represents $20.6 million and $19.4 million of unproved oil and gas properties as of March 31, 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. 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. See

Note 1 – Organization and 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 March 31, 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 three months ended March 31, 2010 included preparing the well for the oil zone tests, hydraulic fracturing of six separate oil bearing intervals, and conducting flow testing of the fractured intervals. 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 is continuing as of April 30, 2010, and the produced test oil is being sold into the Salt Lake City, Utah market. Work is currently in progress to design and install permanent production facilities to enable the well to be placed on permanent production during the second quarter of 2010.

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 and Upper Wasatch formations are productive in the Altamont/Bluebell oil field approximately six miles north of the Bar F well. We plan to develop 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. The Lower Green River/Upper Wasatch represents $8.0 million of proved and $5.6 million of unproved oil and gas properties as of March 31, 2010 and December 31, 2010, respectively.

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 have been drilled. As of April 30, 2010, seven of the eight wells are on production. The remaining well is completed and production is pending expansion of the hydrocarbon handling capacity in the surface production system to accommodate the unexpectedly high hydorcarbon production volumes from the eight-well program.

Our Board of Directors has authorized five 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 32 percent working interest in the five wells. This five-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 Monument Butte Extension represents $3.4 million and $1.6 million of proved and $0.2 million and $0.3 million of unproved oil and gas properties as of March 31, 2010 and December 31, 2009, respectively.

Note 8 – Indonesia

In 2008, we acquired a 47 percent interest in the Budong-Budong Production Sharing Contract (“Budong PSC”) by committing to fund the first phase of the exploration program including the acquisition of 2-D seismic and drilling of the first two exploration wells. This commitment is capped at $17.2 million. The commitment is comprised of $6.5 million for the acquisition of seismic and $10.7 million for the drilling of the first two exploratory wells. After the commitment of each component is met, all subsequent costs will be shared by the

parties in proportion to their ownership interests. The $6.5 million carry obligation for the 2-D seismic acquisition was met in December 2008. Prior to drilling the first exploration well, subject to the estimated cost of that well, our partner will have a one-time option to increase the level of the carried interest to a maximum of $20.0 million, and as compensation for the increase, we will increase our participation to a maximum of 54.65 percent. This equates to a total carried cost for the farm-in of $9.1 million. Our partner will be the operator through the exploration phase as required by the terms of the Budong PSC. We will have control of major decisions and financing for the project 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. It is expected that the first of the two exploratory wells will spud late in the second quarter of 2010. In accordance with the farm-in agreement, we expect to fund 100 percent of the well expenditures to earn our 47 percent working interest up to a cap of $10.7 million; thereafter, we will pay in proportion to our working interest. Operational activities during the three months ended March 31, 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 $3.4 million and $2.0 million of unproved oil and gas properties as of March 31, 2010 and December 31, 2009, respectively.

Note 9 – Gabon

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

The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources (“Republic of Gabon”), entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. The second exploration phase comprises a three-year work commitment which includes the acquisition and processing of 500 kilometers of 2-D seismic, geology and geophysical interpretation, engineering studies and the drilling of a conditional well. Operational activities during the three months ended March 31, 2010 include maturation of prospect inventory and well planning. Subject to drilling rig availability, we expect to drill an exploratory well in the fourth quarter of 2010. The Dussafu PSC represents $7.1 million and $6.9 million of unproved oil and gas properties as of March 31, 2010 and December 31, 2009, respectively.

Note 10 – 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 3,867 square kilometer (955,600 acres) block is located in the gas and condensate rich Ghaba Salt Basin in close proximity to the Barik, Saih Rawl and Saih Nihayda gas and condensate fields. We have an obligation to drill two wells over a three year period with a funding commitment of $22.0 million. Current activities include the compilation of existing data, preparation for 3-D pre-stack depth migration reprocessing and initiation of

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 holding a noncontrolling interest in a corporation, the permitting and the drilling of oil and natural gas wells, the availability of materials and supplies necessary to projects and operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, the Company’s ability to acquire oil and natural gas properties that meet its objectives, availability and cost of drilling rigs, seismic crews, overall economic conditions, political stability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in governmental policy, availability of sufficient financing 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, 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”) exclusive of 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, and exploration acreage mainly onshore West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in Oman and offshore of the People’s Republic of China (“China”).

Venezuela

During the three months ended March 31, 2010, Petrodelta drilled and completed four successful development wells, produced approximately 2.0 million barrels of oil and sold 0.7 billion cubic feet (“BCF”) of natural gas. Petrodelta produced an average of 21,867 barrels of oil per day during the three months ended March 31, 2010.

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 has one drilling rig operating in the Temblador field. A second rig has been assigned to Petrodelta and is expected to arrive in the field on June 1, 2010. Also, Petrodelta is currently seeking a workover rig which it expects to have under contract during the second quarter of 2010.

During the three months ended March 31, 2010, Petrodelta started the engineering work for expanded production facilities to handle the expected production from the development and appraisal wells expected 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 taxes other than on income on the income statement and is deductible for Venezuelan tax purposes. Petrodelta recorded $1.3 million of expense for the Windfall Profits Tax during the three months ended March 31, 2010. During the three months ended March 31, 2009 no expense was recorded for the Windfall Profits Tax.

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. 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 months ended March 31, 2010, Petrodelta recorded a $118.7 million, before tax, ($38.0 million before tax, net to our 32 percent interest) remeasurement gain on revaluation of assets and liabilities.

Certain operating statistics for the three months ended March 31, 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		Three Months
	Ended		Ended
	March 31, 2010		March 31, 2009
Thousand barrels of oil sold		1,968		1,725
Million cubic feet of gas sold		660		1,414
Total thousand barrels of oil equivalent		2,078		1,961
Average price per barrel	$	71.90	$	40.60
Average price per thousand cubic feet	$	1.54	$	1.54
Cash operating costs ($millions)	$	11.2	$	11.7
Capital expenditures ($millions)	$	6.1	$	29.7

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 exercise our option to participate, we will participate in this project with essentially the same terms as the other existing projects in the AMI with the exception that we will not be the operator. We are currently in the process of evaluating the project. The option to participate expires on June 1, 2010.

West Bay

During the three months ended March 31, 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 have also recently finalized a 3-D seismic data trade that will provide access to additional seismic data which will allow for more complete technical evaluation of the leads and prospects identified in the project. The remaining 2010 budget for the West Bay project is $0.1 million.

Western United States – Antelope

During the three months ended March 31, 2010, we incurred $1.2 million for leasing activities on the Antelope prospect. 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

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 1 – Organization and Summary of Significant Accounting Policies, Property and Equipment. During the three months ended March 31, 2010, we incurred $5.1 million for drilling, completion and testing activities. There is no remaining 2010 budget for this program.

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 three months ended March 31, 2010 included preparing the well for the oil zone tests, hydraulic fracturing of six separate oil bearing intervals, and conducting flow testing of the fractured intervals. 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. The well has been flowing naturally on extended test since March 24, 2010 with initial rates of approximately 900 barrels of oil per day (“BOPD”) of 42 degree API oil. As of April 30, 2010, the well had produced in excess of 18,000 gross barrels of oil since the commencement of the flow test, with the oil being sold in the Salt Lake City, Utah market. Work is currently in progress to design and install permanent production facilities to enable the well to be placed on permanent production during the second quarter of 2010.

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 $13.5 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 and Upper Wasatch formations are productive in the Altamont/Bluebell oil field approximately six miles north of the Bar F well. During the three months ended March 31, 2010, we incurred $2.0 million in lease acquisition, drilling, completion and testing activities. We plan to develop 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.

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 have been drilled. As of April 30, 2010, seven of the eight wells are on production. The remaining well is completed and production is pending expansion of the hydrocarbon handling capacity in the surface production system to accommodate the unexpectedly high hydrocarbon production volumes from the eight-well program. As of April 30, 2010, the seven producing wells have produced 52,000 barrels of oil (net to Harvest). The seven wells combined are currently producing 400 BOPD (net to Harvest). During the three months ended March 31, 2010, we incurred $2.4 million in well costs. There is no remaining 2010 budget for the initial eight-well program.

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 2010 budget for this five well program is $4.5 million.

Certain operating statistics for the three months ended March 31, 2010 for the U.S. operations are set forth below. This information is provided at our net ownership. 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 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
	Ended
	March 31, 2010
Thousand barrels of oil sold		42,269
Thousand cubic feet of gas sold		86,336
Total thousand barrels of oil equivalent		56,658
Average price per barrel	$	65.86
Average price per thousand cubic feet	$	3.94
Cash operating costs ($millions)	$	0.2
Capital expenditures ($millions)	$	13.5
Depletion expense per barrel of oil equivalent	$	8.27

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 three months ended March 31, 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. It is expected that the first of two exploratory wells will spud late in the second quarter of 2010. In accordance with the farm-in agreement, we expect to fund 100 percent of the well expenditures to earn our 47 percent working interest up to a cap of $10.7 million; thereafter, we will pay in proportion to our working interest. During the three months ended March 31, 2010, we incurred $2.3 million for well planning, construction and drilling equipment, and $0.5 million for seismic data processing and reprocessing. The remaining 2010 budget for the Budong PSC is $12.1 million. Contingent on the successful results of the two exploratory test wells and availability of funds, this 2010 budget could be increased by an additional $13.1 million.

Dussafu Project — Gabon (“Dussafu PSC”)

Operational activities during the three months ended March 31, 2010 focused on maturation of prospect inventory and well planning Subject to drilling rig availability, we expect to drill an exploratory well in the fourth quarter of 2010. During the three months ended March 31, 2010, we incurred $0.4 million in well planning and $0.1 million for seismic data processing and reprocessing. The remaining 2010 budget for the Dussafu PSC is $1.7 million. Contingent on rig availability and successful results from the exploration well and availability of funds, this budget could be increased by an additional $17.9 million.

Oman (“Block 64 EPSA”)

Operational activities during the three months ended March 31, 2010 include the continued compilation of existing data over two prospect areas of approximately 1,000 square kilometers and geological studies to determine drillable prospects. Well planning is expected to commence in 2010 for exploration drilling in 2011. During the three months ended March 31, 2010, we incurred $0.3 million for seismic data processing and reprocessing. The

remaining 2010 budget for the Block 64 EPSA is $2.5 million. Contingent on the availability of funds, an additional $1.9 million is planned for this project.

Other Exploration Projects

Relating to other projects, we incurred $0.1 million during the three months ended March 31, 2010. The remaining 2010 budget for other projects is $0.2 million. Contingent upon successful test results in Utah and Indonesia and availability of funds, this budget may be increased by an additional $20.1 million.

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.

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. See Item 1A – Risk Factors and Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2009 for a complete description of the situation in Venezuela and other matters.

Based on our cash balance of $44.1 million at March 31, 2010, we will be required to raise additional funds in order to fund our future operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration projects and to a lesser extent general and administrative costs. Currently, our primary source of cash is dividends from Petrodelta and to a lesser extent, production from the Monument Butte Extension and Lower Green River/Upper Wasatch projects as drilling completes. However, there is no certainty that Petrodelta will pay 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.

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:


	Three Months Ended March 31,
	2010			2009
	(in thousands)
Net cash used in operating activities	$	(1,424	)	$	(8,707	)
Net cash used in investing activities		(16,151	)		(9,333	)
Net cash provided by (used in) financing activities		29,373			(716	)

Net increase (decrease) in cash	$	11,798		$	(18,756	)

At March 31, 2010, we had current assets of $57.7 million and current liabilities of $12.7 million, resulting in working capital of $45.0 million and a current ratio of 4.5:1. 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 $10.8 million was primarily due to proceeds received from the debt offering offset by an increase in capital expenditures, exploration costs and administrative expenses.

Cash Flow used in Operating Activities. During the three months ended March 31, 2010 and 2009, net cash used in operating activities was approximately $1.4 million and $8.7 million, respectively. The $7.3 million decrease was primarily due to decreases in accounts and notes receivable and advances to equity affiliates and increases in accounts payable and accrued expenses offset by the payments of accrued interest and income taxes. The three months ended March 31, 2010, also included $3.1 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 three months ended March 31, 2010, we had cash capital expenditures of approximately $13.5 million. Of the 2010 expenditures, $10.7 million was attributable to activity on the Antelope projects, $2.3 million was attributable to activity on the Budong PSC, $0.4 million was attributable to activity on the Dussafu PSC and $0.1 million was attributable to other projects. During the three months ended March 31, 2009, we had cash capital expenditures of approximately $7.1 million. Of the 2009 expenditures, $4.8 million was attributable to the Antelope projects and $2.3 million to other projects.

During the three months ended March 31, 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 binding process. During the three months ended March 31, 2010 and 2009, we incurred $1.7 million and $0.5 million, respectively, 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 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 three months ended March 31, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes, $2.5 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 three months ended March 31, 2009, we incurred $0.8 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 months ended March 31, 2010 and 2009 and the financial condition as of March 31, 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 March 31, 2010 Compared with Three Months Ended March 31, 2009

We reported net income attributable to Harvest of $24.6 million, or $0.64 diluted earnings per share, for the three months ended March 31, 2010, compared with a net loss attributable to Harvest of $4.8 million, or $(0.15) diluted earnings per share, for the three months ended March 31, 2009.

Revenues were higher in the three months ended March 31, 2010 compared with the three months ended March 31, 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 March 31, 2010 was:


	Lower Green		Monument
	River/Upper		Butte
	Wasatch		Extension
Thousand barrels of oil sold		2,541		39,728
Million cubic feet of gas sold		—		86,336
Total barrels of oil equivalent		2,541		54,117
Average price per barrel	$	71.89	$	65.46
Average price per thousand cubic feet	$	—	$	3.94
Total expenses and other non-operating (income) expense (in millions):


	Three Months Ended
	March 31,						Increase
	2010			2009			(Decrease)
Lease operating costs	$	0.1		$	—		$	0.1
Production taxes		0.1			—			0.1
Depletion, depreciation and amortization		0.6			0.1			0.5
Exploration expense		1.2			1.0			0.2
General and administrative		5.4			6.5			(1.1	)
Taxes other than on income		0.3			0.3			—
Investment earnings and other		(0.1	)		(0.4	)		0.3
Interest expense		0.4			—			0.4
Loss on exchange rates		1.5			—			1.5
Income tax expense		—			0.9			(0.9	)

Lease operating costs and production taxes were higher in the three months ended March 31, 2010 compared to the three months ended March 31, 2009 due to the inception of oil and natural gas operations in the U.S. beginning in late December 2009. Costs incurred were for supervision and pipeline and transportation costs. Depletion expense, which was all attributable to 2010 production in the Monument Butte Extension, was $0.5 million ($8.27 per equivalent barrel) for the three months ended March 31, 2010.

During the three months ended March 31, 2010, we incurred $0.9 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, and $0.3 million related to other general business development activities. During the three months ended March 31, 2009, we incurred $0.5 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.

General and administrative costs were lower in the three months ended March 31, 2010 compared to the three months ended March 31, 2009 primarily due to lower general corporate overhead costs and legal and other professional fees. Taxes other than on income for the three months ended March 31, 2010 were consistent with the three months ended March 31, 2009.

Investment earnings and other decreased in the three months ended March 31, 2010 compared to the three months ended March 31, 2009 due to lower interest rates earned on lower cash balances. Interest expense was higher for the three months ended March 31, 2010 compared to the three months ended March 31, 2009 due to the interest associated with our $32 million convertible debt offering in February 2010.

Loss on exchange rates is higher for the three months ended March 31, 2010 compared to the three months ended March 31, 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 three months ended March 31, 2010, Harvest Vinccler recorded a $1.5 million remeasurement loss on revaluation of assets and liabilities.

For the three months ended March 31, 2010, income tax expense was lower than that of the three months ended March 31, 2009 primarily 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 $118.7 million, before tax, ($38.0 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 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. Under accounting principals generally accepted in the United States of America (“GAAP”), we are not required to record losses that would cause our equity investment to go into a negative position. For the three months ended March 31, 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 March 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 $1.5 million for the three months ended March 31, 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.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk from adverse changes of the situation in Venezuela, our 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 three months ended March 31, 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 March 31, 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 March 31, 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 March 31, 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

See our Annual Report on Form 10-K for the year ended December 31, 2009 under Item 1A Risk Factors for a description of risk factors. 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

None.

Item 6. Exhibits

(a)

Exhibits

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

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

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

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

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

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

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

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

Exhibit Index


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

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

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

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

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

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

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

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

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


	Page
PART I FINANCIAL INFORMATION

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

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		20

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		28

Item 4. CONTROLS AND PROCEDURES		28

PART II OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS		30

Item 1A. RISK FACTORS		30

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		30

Item 6. EXHIBITS		30

Signatures		32
EX-31.1
EX-31.2
EX-32.1
EX-32.2


	HARVEST NATURAL RESOURCES, INC.
Dated: May 7, 2010	By:	/s/ James A. Edmiston
		James A. Edmiston
		President and Chief Executive Officer


Dated: May 7, 2010	By:	/s/ Stephen C. Haynes
		Stephen C. Haynes
		Vice President - Finance, Chief Financial Officer and Treasurer

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