e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


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

For the Quarterly Period Ended September 30, 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 (Address of Principal Executive Offices)		77077 (Zip Code)

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

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

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

Yes þ No o

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

Yes o No o

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


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

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

Yes o No þ

At November 2, 2010, 33,838,025 shares of the Registrant’s Common Stock were outstanding.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30,			December 31,
	2010			2009
	(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	13,310		$	32,317
Restricted cash		1,000			—
Accounts and notes receivable, net:
Oil and gas revenue receivable		1,176			166
Dividend receivable — equity affiliate		12,220			—
Joint interest and other		2,743			8,047
Note receivable		3,194			3,265
Advances to equity affiliate		1,975			4,927
Prepaid expenses and other		2,481			2,214

TOTAL CURRENT ASSETS		38,099			50,936
OTHER ASSETS		6,353			3,613
INVESTMENT IN EQUITY AFFILIATES		275,199			233,989
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		111,076			58,543
Other administrative property		3,244			3,085

		114,320			61,628
Accumulated depletion, depreciation and amortization		(3,908	)		(1,387	)

		110,412			60,241

	$	430,063		$	348,779


LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Joint interest and royalty payable	$	156		$	—
Accounts payable, trade and other		841			696
Accrued expenses		30,526			10,253
Accrued interest		220			4,691
Income taxes payable		877			1,090

TOTAL CURRENT LIABILITIES		32,620			16,730
LONG-TERM DEBT		32,000			—
ASSET RETIREMENT LIABILITY		616			50
COMMITMENTS AND CONTINGENCIES (See Note 4)		—			—

EQUITY
STOCKHOLDERS’ EQUITY:
Preferred stock, par value $0.01 a share; authorized 5,000 shares; outstanding, none		—			—
Common stock, par value $0.01 a share; authorized 80,000 shares at September 30, 2010 and December 31, 2009, respectively; issued 39,923 shares and 39,495 shares at September 30, 2010 and December 31, 2009, respectively		399			395
Additional paid-in capital		216,864			213,337
Retained earnings		145,547			126,244
Treasury stock, at cost, 6,475 shares and 6,448 shares at September 30, 2010 and December 31, 2009, respectively		(65,543	)		(65,383	)

TOTAL HARVEST STOCKHOLDERS’ EQUITY		297,267			274,593
NONCONTROLLING INTEREST		67,560			57,406

TOTAL EQUITY		364,827			331,999

	$	430,063		$	348,779

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
				(in thousands, except per share data)
REVENUES
Oil sales	$	1,702		$	—		$	7,216		$	—
Gas sales		217			—			741			—

		1,919			—			7,957			—


EXPENSES
Lease operating costs and production taxes		494			—			1,171			—
Depletion, depreciation and amortization		741			125			2,566			282
Exploration expense		2,592			887			5,329			5,315
General and administrative		7,033			6,066			18,840			18,965
Taxes other than on income		218			208			716			766

		11,078			7,286			28,622			25,328


LOSS FROM OPERATIONS		(9,159	)		(7,286	)		(20,665	)		(25,328	)

OTHER NON-OPERATING INCOME (EXPENSE)
Investment earnings and other		123			268			394			907
Interest expense		(217	)		—			(1,321	)		—
Gain (loss) on exchange rates		2			(44	)		(1,549	)		(56	)

		(92	)		224			(2,476	)		851

LOSS FROM CONSOLIDATED COMPANIES BEFORE INCOME TAXES		(9,251	)		(7,062	)		(23,141	)		(24,477	)

INCOME TAX EXPENSE		699			109			832			1,145

LOSS FROM CONSOLIDATED COMPANIES		(9,950	)		(7,171	)		(23,973	)		(25,622	)

NET INCOME FROM UNCONSOLIDATED EQUITY AFFILIATES		6,148			9,890			53,430			21,776


NET INCOME (LOSS)		(3,802	)		2,719			29,457			(3,846	)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		1,189			1,936			10,154			4,336


NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST	$	(4,991	)	$	783		$	19,303		$	(8,182	)


NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST PER COMMON SHARE:
Basic	$	(0.15	)	$	0.02		$	0.58		$	(0.25	)

Diluted	$	(0.15	)	$	0.02		$	0.53		$	(0.25	)

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
	2010			2009
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	29,457		$	(3,846	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		2,566			282
Amortization of debt financing costs		552			—
Net income from unconsolidated equity affiliate		(53,430	)		(21,776	)
Non-cash compensation-related charges		3,037			3,105
Changes in operating assets and liabilities:
Accounts and notes receivable		4,365			(4	)
Advances to equity affiliate		2,952			(673	)
Prepaid expenses and other		(267	)		(1,606	)
Joint interest and royalty payable		156			—
Accounts payable		145			(753	)
Accrued expenses		3,168			496
Accrued interest		(5,345	)		—
Income taxes payable		(213	)		999

NET CASH USED IN OPERATING ACTIVITIES		(12,857	)		(23,776	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions of property and equipment		(34,619	)		(22,696	)
Increase in restricted cash		(1,000	)		—
Investment costs		(203	)		(372	)

NET CASH USED IN INVESTING ACTIVITIES		(35,822	)		(23,068	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuances of common stock		494			222
Proceeds from issuance of long-term debt		32,000			—
Financing costs		(2,822	)		(1,554	)

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		29,672			(1,332	)


NET DECREASE IN CASH AND CASH EQUIVALENTS		(19,007	)		(48,176	)

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

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	13,310		$	48,989

Supplemental Schedule of Noncash Investing and Financing Activities:

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

During the nine months ended September 30, 2009, we issued 0.2 million shares of restricted stock valued at $0.7 million. Also, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis, which resulted in 3,757 shares being added to treasury stock at cost.

See accompanying notes to consolidated financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2010 and 2009 (unaudited)

Note 1 — Organization

Interim Reporting

In our opinion, the accompanying unaudited consolidated financial statements contain all adjustments necessary for a fair statement of the financial position as of September 30, 2010, and the results of operations for the three and nine months ended September 30, 2010 and 2009, and cash flows for the nine months ended September 30, 2010 and 2009. The unaudited consolidated financial statements are presented in accordance with the requirements of Form 10-Q and do not include all disclosures normally required by accounting principles generally accepted in the United States of America (“GAAP”). Reference should be made to our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2009, which include certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year.

Organization

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

We have significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through HNR Finance, B.V. (“HNR Finance”). We indirectly own 80 percent of HNR Finance and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining 20 percent interest in HNR Finance. HNR Finance owns 40 percent of Petrodelta, S.A. (“Petrodelta”). As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta (80 percent of 40 percent), and Vinccler indirectly owns eight percent (20 percent of 40 percent). Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petrodelta is governed by its own charter and bylaws and 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.

In addition to our interests in Venezuela, we have exploration acreage in the Gulf Coast Region of the United States, the Antelope project in the Western United States, mainly onshore in West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in the Sultanate of Oman (“Oman”), and offshore of the People’s Republic of China (“China”). We also have developed acreage in the Antelope project in the Western United States in the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”) and Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) where we have established production. See Note 8 – United States, Note 9 – Indonesia, Note 10 – Gabon and Note 11 – Oman.

Note 2 – Summary of Significant Accounting Policies

Principles of Consolidation

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

Reporting and Functional Currency

The United States Dollar (“U.S. Dollar”) is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. Amounts denominated in non-U.S. Dollar currencies are re-measured into U.S. Dollars, and all currency gains or losses are recorded in the consolidated statement of operations. We attempt to manage our

operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence.

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 went into effect on January 11, 2010. Per the Exchange Agreement, each exchange rate is applied to foreign currency sales and purchases conducted through the Foreign Currency Administration Commission (“CADIVI”), in the cases expressly provided in the Exchange Agreement. In this regard, the exchange rates established in the Agreement are: 2.60 Bolivars per U.S. Dollar and 4.30 Bolivars per U.S. Dollar. The 2.60 Bolivar exchange rate applies to the food, health, medical and technology sectors. The 4.30 Bolivar exchange rate applies to all other sectors not expressly established by the 2.60 Bolivar exchange rate. The 4.30 Bolivar exchange rate applies to the oil and gas sector.

As an alternative to the use of the official exchange rate, an exemption under the Venezuelan Criminal Exchange Law for transactions in certain securities resulted in an indirect securities transaction market of foreign currency exchange, through which companies could obtain foreign currency legally without requesting it from CADIVI. Publicly available quotes did not exist for the securities transaction exchange rate but such rates could be obtained from brokers. Securities transaction markets were used to move financial securities into and out of Venezuela. In May 2010, the government of Venezuela effectively eliminated this indirect market of foreign currency exchange and established the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) for exchanging Bolivars. SITME’s purpose is to assist companies and individuals requiring foreign currency (U.S. Dollars) for the import of goods and services into Venezuela. SITME may also be used for buying or selling of Venezuela’s bonds. The elimination of the indirect market for foreign currency exchange and the establishment of SITME has not had, is not expected to have, an impact on our business in Venezuela.

Harvest Vinccler, S.C.A. (“Harvest Vinccler”), a subsidiary of HNR Finance, and Petrodelta do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Harvest Vinccler and Petrodelta do not have, and have not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate.

At December 31, 2009, Harvest Vinccler remeasured the appropriate monetary assets and liabilities at the official exchange rate of 2.15 Bolivars per U.S. Dollar, Harvest Vinccler’s functional and reporting currency. On January 31, 2010, Harvest Vinccler remeasured the appropriate monetary assets and liabilities at the new official exchange rate of 4.30 Bolivars per U.S. Dollar. During the nine months ended September 30, 2010, Harvest Vinccler recorded a $1.5 million remeasurement loss on revaluation of monetary assets and liabilities. The remeasurement loss for Harvest Vinccler was calculated as the difference between the old official exchange rate of 2.15 Bolivars per U.S. Dollar and the new official 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 monetary assets than Bolivar denominated monetary liabilities. At September 30, 2010, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 2.9 million and BsF 3.4 million, respectively.

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 September 30, 2010 represents cash held in a U.S. bank used as collateral for a standby letter of credit issued in support of a bank guarantee required as a performance guarantee for a joint study.

Accounts and Note Receivable

Note receivable relates 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 note bears 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 note.

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.

At September 30, 2010, the note receivable was considered to be fully recoverable.

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 3 – Long-Term Debt and Liquidity.

Investment in Equity Affiliates

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

If an investment in an equity affiliate is deemed fully impaired, i.e. investment written down to zero, no additional losses are recorded to the equity investment account or reported in the financial statements if doing so would cause the equity investment to go into a negative position. If the equity investee begins to record income after the investment has been fully impaired, the income is not recorded to the equity investment account or reported in the financial statements until the accumulated losses have been recovered.

Property and Equipment

We use the successful efforts method of accounting for oil and gas properties.

At September 30, 2010, oil and gas properties include $0.9 million of capitalized interest. Oil and gas properties did not include any capitalized interest at December 31, 2009.

Suspended Exploratory Drilling Costs. At September 30, 2010, oil and gas properties included capitalized suspended exploratory drilling costs of $16.5 million. We did not have any suspended exploratory drilling costs at December 31, 2009. The $16.5 million of suspended exploratory drilling costs relates to drilling in the Mesaverde formation in the Bar F #1-20-3-2 (“Bar F”). The Mesaverde Gas Exploration and Appraisal Project (“Mesaverde”) targeted multiple reservoir intervals in the Mesaverde formation in the Uintah Basin of Utah. Testing 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. While the results to date have not definitively determined the commerciality of stand-alone development of the Mesaverde in the current gas price environment, 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 September 30, 2010 and December 31, 2009, cash and cash equivalents include $6.9 million and $26.8 million, respectively, in money market funds 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 September 30, 2010 was $60.5 million.

Our current assets and liabilities accounts include financial instruments, the most significant of which are accounts receivables and trade payables. We believe the carrying values of our current assets and liabilities approximate fair value, with the exception of the note receivable. Because this note receivable is not publicly-traded and not easily transferable, the estimated fair value of our notes receivable is based on the best information available to us which approximates the note receivable book value of $3.2 million. The majority of inputs used in the fair value calculation of the note receivable are Level 3 inputs and are consistent with the information used in determining impairment of the note receivable.

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 nine months ended September 30, 2010 or the year ended December 31, 2009. Changes in asset retirement obligations during the nine months ended September 30, 2010 and the year ended December 31, 2009 were as follows (in thousands):


	September 30,		December 31,
	2010		2009
Asset retirement obligations beginning of period	$	50	$	—
Liabilities recorded during the period		399		50
Liabilities settled during the period		—		—
Revisions in estimated cash flows		146		—
Accretion expense		21		—

Asset retirement obligations end of period	$	616	$	50

Noncontrolling Interests

We adopted the accounting standard for noncontrolling interests in consolidated financial statements as of January 1, 2009. Changes in noncontrolling interest during the nine months ended September 30, 2010 and 2009 were as follows (in thousands):


	September 30,		September 30,
	2010		2009
Balance at beginning of period	$	57,406	$	49,603
Net income attributable to noncontrolling interest		10,154		4,336

Balance at end of period	$	67,560	$	53,939

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 33.6 million and 33.4 million for the three and nine months ended September 30, 2010, respectively, and 33.2 million and 33.0 million for the three and nine months ended September 30, 2009, respectively. Diluted EPS reflects the potential dilution that would occur if securities or other contracts to issue common stock were exercised or converted into common stock. The weighted average number of common shares outstanding for computing diluted EPS, including dilutive stock options, was 33.6 million and 39.1 million for the three and nine months ended September 30, 2010, respectively, and 33.5 million and 33.0 million for the three and nine months ended September 30, 2009, respectively.

For the three and nine months ended September 30, 2010, an aggregate of 3.7 million and 3.0 million options, respectively, were excluded from the diluted EPS calculations because their exercise price exceeded the average stock price. For the three and nine months ended September 30, 2009, an aggregate of 3.2 million and 3.8 million options, respectively, were excluded from the diluted EPS calculations because their exercise price exceeded the average stock price.

Stock options of 0.3 million were exercised in the nine months ended September 30, 2010 resulting in cash proceeds of $0.5 million. Stock options of 0.1 million were exercised in the nine months ended September 30, 2009 resulting in cash proceeds of $0.2 million.

New Accounting Pronouncements

In July 2010, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-20 Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses (“ASU 2010-20”), which amends existing guidance by requiring more robust and disaggregated disclosures by an entity about the credit quality of its financing receivables and its allowance for credit losses. These disclosures will provide financial statement users with additional information about the nature of credit risks inherent in financing receivables, how credit risks are analyzed and assessed in determining allowance for credit losses, and reasons for any changes made in allowance for credit losses. This update is generally effective for interim and annual reporting periods ending on or after December 15, 2010; however, certain aspects of the update pertaining to activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. We do not expect ASU 2010-20 to have a material impact on our consolidated financial position, results of operations or cash flows.

Note 3 — Long-Term Debt and Liquidity

Long-Term Debt

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


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

On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. Under the terms of the notes, interest is payable semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2010. The senior convertible 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 senior convertible notes, equivalent to a conversion price of approximately $5.71 per share of common stock. The senior convertible 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 senior convertible 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 $2.1 million associated with this debt offering are being amortized over the remaining life of the debt. These costs are capitalized in Other Assets at September 30, 2010.

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

Liquidity – Based on our cash balance of $13.3 million at September 30, 2010, we will require additional funds in order to fund our future operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration, appraisal and development projects and to a lesser extent, general and administrative costs. Currently, our primary source of cash is dividends from Petrodelta and to a lesser extent, production from the Monument Butte Extension and Lower Green River/Upper Wasatch projects. In August 2010, Petrodelta declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received on October 22, 2010. However, there is no certainty that Petrodelta will pay additional dividends in 2010 or 2011. Our lack of cash flow and the anticipated level of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance adequate financing can

be raised. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing capital 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.

In September 2010, we announced the retention of Bank of America Merrill Lynch to provide advisory services to assist us in exploring a broad range of strategic alternatives for enhancing shareholder value. These alternatives could include, but are not limited to, certain extraordinary transactions, including, possibly, a sale of assets or a sale or merger of the Company.

On October 29, 2010, we announced the closing of a $60.0 million term loan facility with MSD Energy Investments Private II, LLC (“MSD Energy”), an affiliate of MSD Capital, L.P., as the sole Lender under the term loan facility. The net proceeds of the term loan facility are approximately $59.5 million, after deducting fees related to the transaction. See Note 12 – Subsequent Events.

Note 4 — Commitments and Contingencies

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

Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-Vinccler, C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, Texas. This suit was brought in May 2003 by Excel alleging, among other things, breach of a consulting agreement between Excel and us, misappropriation of proprietary information and trade secrets and fraud. Excel sought actual and exemplary damages, injunctive relief and attorneys’ fees. We filed counterclaims against Excel alleging breach of contract, fraud and theft of corporate assets. On November 3, 2010, judgment was entered dismissing Excel’s claims against Harvest and in favor of Harvest with respect to our counterclaim for breach of contract. We were awarded approximately $1.8 million in damages, legal fees and prejudgment interest. The judgment is subject to appeal. We can give no assurances that we can collect all or any portion of the judgment from Excel.

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

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

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

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

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

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

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

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

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

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

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

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

Note 5 — Taxes Other Than on Income

The components of taxes other than on income were:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(in thousands)
Franchise Taxes	$	45	$	42	$	151	$	141
Payroll and Other Taxes		173		166		565		625

	$	218	$	208	$	716	$	766

Note 6 — Operating Segments

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

reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the United States and other segment and are not allocated to other operating segments:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(in thousands)
Segment Revenues
Oil and gas sales:
United States and other	$	1,919		$	—		$	7,957		$	—

Total oil and gas sales	$	1,919		$	—		$	7,957		$	—


Segment Income (Loss)
Venezuela	$	5,654		$	9,706		$	49,930		$	22,496
Indonesia		(2,622	)		(1,129	)		(5,415	)		(3,921	)
United States and other		(8,023	)		(7,794	)		(25,212	)		(26,757	)

Net income (loss) attributable to Harvest	$	(4,991	)	$	783		$	19,303		$	(8,182	)


	September 30,			December 31,
	2010			2009
	(in thousands)
Operating Segment Assets
Venezuela	$	280,507		$	249,484
Indonesia		12,079			5,893
United States and other		166,142			113,555

		458,728			368,932
Intersegment eliminations		(28,665	)		(20,153	)

	$	430,063		$	348,779

Note 7 – Investment in Equity Affiliates

Petrodelta

Petrodelta has undertaken its operations in accordance with Petrodelta’s business plan as set forth in its conversion contract. Under its conversion contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. On February 4, 2010, Petrodelta’s board of directors endorsed a capital budget of $205 million for Petrodelta’s 2010 business plan. Due to delays in rig availability and El Salto facilities project execution, Petrodelta has spent $47 million of its 2010 budget through September 30, 2010. It is unlikely that Petrodelta will spend its entire 2010 budget during the remaining three months of 2010.

In August 2010, Petrodelta’s board of directors declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received on October 22, 2010. The dividend represents 50 percent of Petrodelta’s net income as reported under International Financial Reporting Standards (“IFRS”) for the year ended December 31, 2009. In April 2009, Petrodelta’s board of directors declared a dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest), which was received in the form of an advance dividend in October 2008. The dividend represents Petrodelta’s net income under IFRS for the six months ended June 30, 2008.

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. During the three months ended September 30, 2010, no expense was recorded for the Windfall Profits Tax. Petrodelta recorded $2.9 million of expense for the Windfall Profits Tax during the nine months ended September 30, 2010. During the three and nine months ended September 30, 2009, no expense was recorded for the Windfall Profits Tax.

The Science and Technology Law (referred to as “LOCTI” in Venezuela) requires major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law (“OHL”) to contribute two percent of their gross revenue generated in Venezuela from activities specified in the OHL on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. The contribution is based on the previous year’s gross revenue and is due the following year. LOCTI requires that each company file a separate declaration stating how much has been contributed; however, waivers have been granted in the past to allow PDVSA to file a declaration on a consolidated basis covering all of its and its consolidating entities liabilities. Since Petrodelta expects PDVSA to continue requesting and receiving waivers, Petrodelta has not accrued a liability to LOCTI for the nine months ended September 30, 2010. The potential exposure to LOCTI for the nine months ended September 30, 2010 is $3.4 million, $1.7 million net of tax ($0.5 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 2 – Summary of Significant Accounting Policies, Reporting and Functional Currency. At December 31, 2009, Petrodelta remeasured the appropriate monetary assets and liabilities at the official exchange rate of 2.15 Bolivars per U.S. Dollar, Petrodelta’s functional and reporting currency. On January 31, 2010, Petrodelta remeasured the appropriate monetary assets and liabilities at the new official exchange rate of 4.30 Bolivars per U.S. Dollar. Petrodelta recorded a $0.1 million remeasurement loss and a $120.5 million remeasurement gain, before tax, during the three and nine months ended September 30, 2010, respectively, on revaluation of monetary assets and liabilities. The remeasurement gain for Petrodelta was calculated as the difference between the old official exchange rate of 2.15 Bolivars per U.S. Dollar and the new official exchange rate of 4.30 Bolivars per U.S. dollar. The primary factor in Petrodelta’s gain on currency exchange rates is that Petrodelta had substantially higher Bolivar denominated monetary liabilities than Bolivar denominated monetary assets. At September 30, 2010, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 78.0 million and BsF 2,032.3 million, respectively.

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Revenues:
Oil sales	$	144,917		$	122,731		$	422,383		$	299,914
Gas sales		705			1,409			2,745			5,608
Royalty		(48,961	)		(41,510	)		(142,223	)		(102,422	)

		96,661			82,630			282,905			203,100

Expenses:
Operating expenses		8,009			8,902			30,766			41,427
Workovers		1,637			152			1,637			152
Depletion, depreciation and amortization		11,146			7,002			29,522			23,715
General and administrative		2,221			2,347			6,040			11,561
Taxes other than on income		968			1,254			7,379			2,789

		23,981			19,657			75,344			79,644

Income from operations		72,680			62,973			207,561			123,456

Gain (loss) on exchange rate		(136	)					120,518
Investment earnings and other		5			—			2,886			3


Income before income tax		72,549			62,973			330,965			123,459

Current income tax expense		56,660			36,251			194,736			68,451
Deferred income tax (benefit) expense		18,785			(16,153	)		66,367			(39,520	)

Net income (loss)		(2,896	)		42,875			69,862			94,528
Adjustment to reconcile to reported net income (loss) From Unconsolidated equity affiliate:
Deferred income tax (benefit) expense		(18,953	)		16,011			(66,441	)		32,098

Net income equity affiliate		16,057			26,864			136,303			62,430
Equity interest in unconsolidated equity affiliate		40	%		40	%		40	%		40	%

Income before amortization of excess basis in equity affiliate		6,423			10,746			54,521			24,972
Amortization of excess basis in equity affiliate		(364	)		(330	)		(1,020	)		(993	)
Conform depletion expense to GAAP		89			28			(71	)		468

Net income from unconsolidated equity affiliate	$	6,148		$	10,444		$	53,430		$	24,447


	September 30,		December 31,
	2010		2009
Current assets	$	660,253	$	404,825
Property and equipment (net)		277,949		265,442
Other assets		74,921		141,245
Current liabilities		508,926		345,812
Other liabilities		32,785		33,600
Net equity		471,412		432,100

Fusion Geophysical, LLC (“Fusion”)

Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering. The purchase of our equity investment in Fusion extends our technical ability and global reach to support a more organic growth and exploration strategy. Our minority equity investment in Fusion is accounted for using the equity method of accounting. Operating revenue and total assets represent 100 percent of Fusion. No dividends were declared or paid during the nine months ended September 30, 2010 and 2009, respectively. Summarized financial information for Fusion follows (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Operating revenues	$	2,464		$	2,751		$	8,063		$	8,095

Net loss	$	(651	)	$	(210	)	$	(2,322	)	$	(3,581	)
Equity interest in unconsolidated equity affiliate		49	%		49	%		49	%		49	%

Net loss from unconsolidated equity affiliate		(319	)		(103	)		(1,138	)		(1,755	)
Amortization of fair value of intangibles		—			(451	)		—			(916	)

Net loss from unconsolidated equity affiliate	$	(319	)	$	(554	)	$	(1,138	)	$	(2,671	)


	September 30,		December 31,
	2010		2009
Current assets	$	2,515	$	2,726
Total assets		25,271		30,205
Current liabilities		7,655		8,024
Total liabilities		8,861		12,242

At December 31, 2009, we recorded a $1.6 million charge to fully impair the carrying value of our equity investment in Fusion. Accordingly, we no longer record losses that would cause our equity investment to go into a negative position. For the three and nine months ended September 30, 2010, Fusion reported a net loss of $0.7 million and $2.3 million ($0.3 million and $1.1 million net to our 49 percent interest), respectively. This loss is not reported in the three and nine months ended September 2010 net income from unconsolidated equity affiliates as reporting it would take our equity investment into a negative position.

Approximately 11.7 percent and 18.0 percent of Fusion’s revenue for the three and nine months ended September 30, 2010, respectively, and approximately 12.7 percent and 31.1 percent of Fusion’s revenue for the three and nine months ended September 30, 2009, respectively, was earned from Harvest or Harvest subsidiaries.

On April 9, 2009, we entered into a service agreement with Fusion whereby we prepaid $1.5 million for certain services to be performed in connection with certain projects as defined in the service agreement. The services are to be performed in accordance with the existing consulting agreement. Upon written notice to Fusion, the projects and types of services can be amended. The unapplied portion of the prepayment advance bears interest at an annual rate of 12 percent, which will be added to the prepayment advance balance and used to offset future service invoices from Fusion. Services rendered have been applied against the prepayment, and as of September 30, 2010, the balance for prepaid services was approximately $0.6 million.

Note 8 – United States Operations

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

Gulf Coast

On January 28, 2010, we entered into an agreement with one of the private third parties in our AMI for an option to participate in a new project. We paid $1.5 million for the option to acquire up to a 50 percent interest in the new project. In March 2010, an additional party was admitted into the new project as operator with a 50 percent interest. As a result, our option allowed us to acquire up to a 25 percent non-operated interest in the project at that point in time. If we had chosen to exercise our option to participate, we would have participated in this project with essentially the same terms as the other existing projects in the Area of Mutual Intent (“AMI”) with the exception that we would not be the operator. The option to participate expired June 1, 2010. Because of the substantial changes made to the project after we acquired our option, we elected to not participate in the project, and the private third party agreed to refund our $1.5 million option payment. We received a refund of 50 percent of the $1.5 million option payment on September 24, 2010. We received the remaining 50 percent on October 1, 2010.

West Bay Project

During the nine months ended September 30, 2010, operational activities in the West Bay prospect focused on firming up plans for drilling on the identified initial drilling prospect and continuing to evaluate the other leads and prospects in the project. Land, regulatory and surface access preparations currently in progress are focused on taking the initial drilling prospect to drill-ready status. During the third quarter of 2010, we merged the 3-D seismic data set acquired during the second quarter of 2010 with our existing seismic data, and interpretation of the merged data set is in progress. The acquisition and merging of the additional 3-D seismic data allows for more complete technical evaluation of the leads and prospects identified in the project. The preliminary interpretation of the merged data set has resulted in the addition of a number of additional leads to the prospect inventory. The West Bay project represents $3.3 million and $3.1 million of unproved oil and gas properties as of September 30, 2010 and December 31, 2009, respectively.

Western United States — Antelope

In October 2007, we entered into a Joint Exploration and Development Agreement (“JEDA”) with a private third party to pursue a lease acquisition program and drilling program on the Antelope prospect in the Western United States. We are the operator and, from October 2007 until June 2009, we had a working interest of 50 percent. In June 2009, as compensation for reclassifying $2.7 million of prepaid land costs to a note receivable, our working interest increased to 60 percent in the Antelope prospect. The private third party was obligated to assemble the initial lease position on the Antelope prospect. The JEDA provides that we would earn our working interest in the Antelope prospect by compensating the private third party for leases acquired in accordance with terms defined in the JEDA, and by drilling and completing one well (the Bar F) at our sole expense. As of July 20, 2010, we completed our earning obligation for the Antelope prospect.

In July 2010, we executed a farm-out agreement with the private third party for the acquisition of an incremental 10 percent interest in the Antelope Project with an effective date of July 1, 2010. This acquisition includes all leases, the Mesaverde, the Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) and the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”). The acquisition excludes the initial eight wells previously drilled in the Monument Butte Extension. Total consideration for the incremental 10 percent interest is $20.0 million, of which (1) $3.0 million was paid on August 2, 2010 (the closing date of the acquisition); (2) $3.0 million to be used as a credit against future joint interest billings or if joint interest billings do not accumulate to $3.0 million by October 1, 2010, at the sole election of the private third party, the balance is to be paid by us within 15 days of receipt of written request from the private third party; and (3) a capped $14.0 million carry of a portion of our partner’s exploration and development cost obligations in the upcoming Lower Green River/Upper Wasatch and Monument Butte Extension drilling programs in the Antelope project. On October 1, 2010, the private third party elected to receive in cash the remaining balance of the joint interest billing credit of $2.4 million. At September 30, 2010, the outstanding balance on the $14.0 million exploration and development cost obligation carry is $12.7 million. Based on current plans, we anticipate the full carry obligation will be met in the first half of 2011. This acquisition increases our ownership in the Antelope project to 70 percent.

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 is being collected through sales revenues taken from a portion of the private third party’s net revenue from the Bar F. At September 30, 2010, the note receivable balance including interest was $3.2 million. At September 30, 2010, the note receivable was considered to be fully recoverable.

Operational activities during the nine months ended September 30, 2010 on the Antelope prospect included continuing leasing activities on private, Allottee, and tribal land. The Antelope prospect represents $42.1 million and $19.4 million of unproved oil and gas properties as of September 30, 2010 and December 31, 2009, respectively.

Other activities on the Antelope prospect during the nine months ended September 30, 2010, focused on drilling, completion and testing activities on two separate projects on the Antelope prospect in Duchesne and Uintah Counties, Utah.

Lower Green River/Upper Wasatch Oil Delineation and Development Project

In the first quarter of 2010, we completed the drilling and testing of the Bar F in the Mesaverde formation. See Note 2 — Summary of Significant Accounting Policies, Property and Equipment — Suspended Exploratory Drilling Costs. After completion of the initial testing program on the Mesaverde deep gas formation, 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 nine months ended September 30, 2010 included completion of testing of the Bar F, completion of the Bar F, including installation of an electric submersible pump, completion of production facilities for the Bar F, and routine production operations of the Bar F. Results of the testing have been positive, and we believe the results indicate that we have made a commercial oil discovery in the Lower Green River and Upper Wasatch formations. The well is currently on routine production with the produced oil being sold into the Salt Lake City, Utah market.

We began a five-well Lower Green River/Upper Wasatch delineation and development drilling program in the third quarter of 2010. This five-well program is planned to further delineate and appraise the extent of the Lower Green River/Upper Wasatch discovery made in the Bar F, and is also expected to establish additional production from the Lower Green River/Upper Wasatch reservoirs in at least some of the five appraisal wells. The Lower Green River/Upper Wasatch formations are productive in the Altamont/Bluebell oil field approximately six miles north of the Bar F well. Operational activities during the nine months ended September 30, 2010 on the five well Lower Green River/Upper Wasatch delineation program included preparations and well planning for the drilling program that is being implemented in the second half of 2010. The first well of the five-well delineation program, the Kettle #1-10-3-1 (“Kettle”), which spud on July 14, 2010, was drilled to a total depth of 12,000 feet and has been hydraulically fractured and completed. The second well, the ON Moon #1-27-3-2 (“ON Moon”) spud on August 19, 2010. As of September 30, 2010, the ON Moon had been drilled to a total depth of 4,380 feet. The third well in the program, the Dart #1-12-3-2 (“Dart”), has been permitted and was ready to be spud at September 30, 2010. Planning and permitting is underway for the next two wells. The five wells are planned to be drilled back-to-back.

The Lower Green River/Upper Wasatch represents $10.6 million of proved and $7.3 million of unproved oil and gas properties as of September 30, 2010 and $5.6 million of unproved oil and gas properties as of December 31, 2009.

Monument Butte Extension Appraisal and Development Project

Four additional wells in the Monument Butte Extension were drilled during the third quarter of 2010. These four wells are the first of a planned six well expansion program being conducted as a follow up to the successful completion of the initial eight-well program that was drilled in late 2009 and early 2010. The six-well expansion is being drilled on acreage immediately adjacent to the initial eight-well program. The estimated gross drilling and completion cost per well is $0.9 million, and we have an approximate 37 percent working interest in the six wells after the acquisition of the incremental 10 percent interest from the private third party through the farm-out agreement dated July 1, 2010. At September 30, 2010, four wells had been drilled and were on production.

The Monument Butte Extension represents $5.2 million of proved and $0.4 million of unproved oil and gas properties as of September 30, 2010 and $1.6 million of proved and $0.3 million of unproved oil and gas properties as of December 31, 2009.

Note 9 — Indonesia

In 2008, we acquired a 47 percent interest in the Budong-Budong Production Sharing Contract (“Budong PSC”) by committing to fund the first phase of the exploration program including the acquisition of 2-D seismic and drilling of the first two exploration wells. 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 commitment to fund the first phase of the exploration program 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. 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. On September 15, 2010, our partner exercised their option to increase the carry obligation by $2.7 million to a total of $19.9 million ($7.9 million for acquisition of seismic and $12.0 million for drilling). The additional carry increases our ownership by 7.4 percent to 54.4 percent. The change in ownership interest is subject to regulatory approval.

During the initial exploration period, the Budong PSC covered 1.35 million. The Budong PSC includes a ten-year exploration period and a 20-year development phase. Pursuant to the terms of the Budong PSC, at end of the first three-year exploration phase, 35 percent of the original area was relinquished to BP Migas. The second three-year exploration phase began in January 2010 covering 0.88 million acres.

Two drill sites were selected in 2009. After delays in acquiring permits to mobilize the drilling rig from its port location to the drilling pad, it is now expected that the first of the two exploratory wells will spud late in the fourth quarter of 2010. In accordance with the farm-in agreement, we expect to fund 100 percent of the well expenditures to earn our 54.4 percent working interest up to a cap of $12.0 million; thereafter, we will pay in proportion to our working interest. Operational activities during the nine months ended September 30, 2010 include construction for the two test well sites, preparations for mobilization of rig and ancillary equipment to the first drill site, and delivery of drilling equipment. The Budong PSC represents $7.2 million and $2.0 million of unproved oil and gas properties as of September 30, 2010 and December 31, 2009, respectively.

Note 10 — Gabon

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

The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources (“Republic of Gabon”), entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. It has been agreed that the second three-year exploration phase will be extended until May 27, 2011, at which time the partners can elect to enter a third exploration phase. The second exploration phase comprises a work commitment which includes the acquisition and processing of 500 kilometers of 2-D seismic, geology and geophysical interpretation, engineering studies and the drilling of a conditional well. Operational activities during the nine months ended September 30, 2010 include maturation of prospect inventory and well planning. Subject to drilling rig availability, we expect to drill an exploratory well in the second quarter of 2011. The Dussafu PSC represents $8.8 million and $6.9 million of unproved oil and gas properties as of September 30, 2010 and December 31, 2009, respectively.

Note 11 — Oman

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

Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate, which the Oman Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). PDO will continue to produce oil from several fields within Block 64 EPSA area. The 955,600 acre block is located in the gas and condensate rich Ghaba Salt Basin in close proximity to the Barik, Saih Rawl and Saih Nihayda gas and condensate fields. We have an obligation to drill two wells over a three-year period with a funding commitment of $22.0 million. We expect to drill the first of the two exploratory wells in the second half of 2011. Current activities include geological studies, baseline environmental and social study and 3-D pre-stack depth migration reprocessing of approximately 1,000 square kilometers of existing 3-D seismic data. The Block 64 EPSA represents $4.2 million and $3.8 million of unproved oil and gas properties as of September 30, 2010 and December 31, 2009, respectively.

Note 12 — Subsequent Events

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

On October 29, 2010, we announced the closing of a $60.0 million term loan facility with MSD Energy, an affiliate of MSD Capital, L.P., as the sole Lender under the term loan facility. The net proceeds of the term loan facility are approximately $59.5 million, after deducting fees related to the transaction. We intend to use the net proceeds of the term loan facility to fund capital expenditures and for working capital needs and general corporate purposes. The term loan facility is a general unsecured obligation, ranking equally with all of our other unsecured senior indebtedness and senior in right of payment to our subordinated indebtedness, if any. Under the terms of the term loan facility, interest is paid on a monthly basis at the initial rate of 10 percent and will mature on October 28, 2012. The initial rate of interest increases to 15 percent on July 28, 2011, the Bridge Date. The Bridge Date may be extended at our option for three months by paying a fee to MSD Energy in the amount of five percent of the initial principal amount of the term loan facility. MSD Energy Investments, L.P., an affiliate of MSD Capital, L.P., is currently a shareholder and a convertible note holder of Harvest.

In connection with the term loan, we issued to MSD Energy (1) 1.2 million warrants exercisable at any time on or after the closing date for a period of five years from the closing date on a cashless exercise basis at $15 per share until the Bridge Date, at which time the exercise price per share will equal the lower of $15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date; 2) 0.4 million warrants exercisable at any time on or after the closing date for a period of five years from the closing date on a cashless exercise basis at $20 per share until the Bridge Date, at which time the exercise price per share will equal the lower of $15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date; and 3) 4.4 million warrants exercisable at any time on or after the Bridge Date for a period of five years from the Bridge Date on a cashless exercise basis at the lower of $15 per share or 120 percent of the average closing price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date. The 4.4 million warrants may be redeemed by Harvest for $0.01 per share at any time prior to the Bridge Date in conjunction with the repayment of the loan prior to the Bridge Date.


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, as amended (the “PSLRA”) contained in this report or made by management of the Company involve risks and uncertainties and are subject to change based on various important factors. When used in this report, the words “budget”, “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 PSLRA, we caution you that important factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include our concentration of operations in Venezuela, the political and economic risks associated with international operations (particularly those in Venezuela), the anticipated future development costs for undeveloped reserves, drilling risks, the risk that actual results may vary considerably from reserve estimates, the dependence upon the abilities and continued participation of certain of our key employees, the risks normally incident to the exploration, operation and development of oil and natural gas properties, risks incumbent to being a noncontrolling interest shareholder in a corporation, the permitting and the drilling of oil and natural gas wells, the availability of materials and supplies necessary to projects and operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, the Company’s ability to acquire oil and natural gas properties that meet its objectives, availability and cost of drilling rigs, 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 personnel have identified low entry cost exploration opportunities in areas with large hydrocarbon resource potential. We operate from our Houston, Texas headquarters. We also have regional/technical offices in the United Kingdom and Singapore, and small field offices in Jakarta, Indonesia; Muscat, Sultanate of Oman (“Oman”); and Roosevelt, Utah to support field operations in those areas. 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.

We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through HNR Finance, B.V. (“HNR Finance”). We indirectly own 80 percent of HNR Finance and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining 20 percent interest of HNR Finance. HNR Finance owns 40 percent of Petrodelta, S.A. (“Petrodelta”). As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta (80 percent of 40 percent), and Vinccler indirectly owns eight percent (20 percent of 40 percent). Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petrodelta is governed by its own charter and bylaws and 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.

Through the pursuit of technically-based strategies guided by conservative investment philosophies, we are building a portfolio of exploration prospects to complement the low-risk production, development and exploration prospects we hold in Venezuela. In addition to our interests in Venezuela, we hold exploration acreage in the Gulf Coast Region of the United States through an Area of Mutual Intent (“AMI”) agreement with two private third parties, the Antelope project in the Western United States through a Joint Exploration and Development Agreement

(“JEDA”), mainly onshore West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in Oman and offshore of the People’s Republic of China (“China”). We also have developed acreage in the Antelope project in the Western United States in the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”) and Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) where we have established production.

From time to time we learn of possible third party interests in acquiring ownership in certain assets within our property portfolio. We evaluate these potential opportunities taking into consideration our overall property mix, our operational and liquidity requirements, our strategic focus and our commitment to long-term shareholder value. For example, we have recently received such expressions of interest in acquiring some of our international producing and exploration assets, and we are currently evaluating these potential opportunities. These considerations are at a very preliminary stage, and there can be no assurances that our discussions will continue or that any transaction may ultimately result from our discussions. In September 2010, we announced the retention of Bank of America Merrill Lynch to provide advisory services to assist us in exploring a broad range of strategic alternatives for enhancing shareholder value. These alternatives could include, but are not limited to, certain extraordinary transactions, including, possibly, a sale of assets or a sale or merger of the Company.

Venezuela

During the nine months ended September 30, 2010, Petrodelta drilled and completed 13 successful development wells, produced approximately 6.1 million barrels of oil and sold 1.8 billion cubic feet (“BCF”) of natural gas. Petrodelta produced an average of 22,501 barrels of oil per day during the nine months ended September 30, 2010.

Petrodelta shareholders intend that Petrodelta be self-funding and rely on internally-generated cash flow to fund operations. On February 4, 2010, Petrodelta’s board of directors endorsed a capital budget of $205 million for Petrodelta’s 2010 business plan. The budget includes utilizing two rigs to drill both development and appraisal wells for both maintaining production capacity and appraising the substantial resource bases in the El Salto Field and presently non-producing Isleño field. Currently, Petrodelta is operating two drilling rigs in the Temblador field. The second drilling rig started operations in mid-July. Also, Petrodelta has contracted a workover rig which was mobilized to the Temblador field on October 15, 2010. Due to delays in rig availability and El Salto facilities project execution, Petrodelta has spent $47 million of its 2010 budget through September 30, 2010. It is unlikely that Petrodelta will spend its entire 2010 capital budget during the remaining three months of 2010.

The appraisal and development activity in the El Salto field continues to exceed expectations. During the third quarter of 2010, the ELS-33 well was drilled and completed in the Lower Jobo sand and began producing on September 1, 2010. The ELS-33 has tested at rates of 1,800 barrels of oil per day (“BOPD”). The ELS-33 also drilled a pilot hole which encountered a full column of oil in a block that was previously unpenetrated and represents a significant expansion of Block 5 in El Salto field not included in the 2009 reserve report. The ELS-34 well was drilled and completed in the Lower Jobo sand of the newly identified Block 5 extension and began production on September 26, 2010. The ELS-34 has tested at rates of 700 BOPD with indicated potential of over 3,000 BOPD based on bottom-hole-pressures. The ELS-33 and ELS-34 wells are currently restricted in their production rate until additional oil transportation trucks are contracted by Petrodelta to service the expanded production capacity from El Salto.

During the third quarter 2010, we commissioned an interim reserve report for Petrodelta to assess and secure the growth potential of the El Salto field. The reserve report reflects a 10 percent increase net to our 32 percent interest in proved reserves to 50.4 million barrels of oil equivalent (MMBOE) and a 26 percent increase net to our 32 percent interest in proved and probable reserves to 103.0 MMBOE at September 30, 2010, as compared to year-end 2009. The increase was driven primarily by the drilling of the ELS-33 and ELS-34 wells in Block 5 of Petrodelta’s mostly undeveloped El Salto field. The interim reserve report only included the El Salto field. In our

opinion, there has been no material change to the reserves at the other five fields in 2010 except for 2010 production.

During the nine months ended September 30, 2010, Petrodelta started the pre-engineering work for production facilities to handle the expected early production from the development and appraisal wells projected to be drilled in 2010 and 2011. Petrodelta is presently pursuing the engineering work required for the full development of El Salto field.

In August 2010, Petrodelta declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received October 22, 2010. The dividend represents 50 percent of Petrodelta’s net income as reported under International Financial Reporting Standards (“IFRS”) for the year ended December 31, 2009.

In 2008, the Venezuelan government published in the Official Gazette the Law of Special Contribution to Extraordinary Prices at the Hydrocarbons International Market (“Windfall Profits Tax”). The Windfall Profits Tax is 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 Corporación Venezolana del Petroleo S.A. (“CVP”), Petrodelta has applied the Windfall Profits Tax to gross oil production delivered to Petroleos de Venezuela S.A. (“PDVSA”). The Windfall Profits Tax established a special 50 percent tax to the Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar manner, the percentage is increased from 50 percent to 60 percent when the average price of the VEB exceeds $100 per barrel. The Windfall Profits Tax is reported as expense on the income statement and is deductible for Venezuelan tax purposes. During the three months ended September 30, 2010, no expense was recorded for the Windfall Profits Tax. Petrodelta recorded $2.9 million of expense for the Windfall Profits Tax during the nine months ended September 30, 2010.

In 2005, Venezuela modified the Science and Technology Law (referred to as “LOCTI” in Venezuela) to require companies doing business in Venezuela to invest, contribute or spend a percentage of their gross revenue on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. LOCTI requires major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law (“OHL”) to contribute two percent of their gross revenue generated in Venezuela from activities specified in the OHL. The contribution is based on the previous year’s gross revenue and is due the following year. LOCTI requires that each company file a separate declaration stating how much has been contributed; however, waivers have been granted in the past to allow PDVSA to file a declaration on a consolidated basis covering all of its and its consolidating entities liabilities. Since Petrodelta expects PDVSA to continue requesting and receiving waivers, Petrodelta has not accrued a liability to LOCTI for the nine months ended September 30, 2010. The potential exposure to LOCTI for the nine months ended September 30, 2010 is $3.4 million, $1.7 million net of tax ($0.5 million net to our 32 percent interest).

At December 31, 2009, Harvest Vinccler and Petrodelta remeasured the appropriate monetary assets and liabilities at the official exchange rate of 2.15 Bolivars per U.S. Dollar, Harvest Vinccler’s and Petrodelta’s functional and reporting currency. On January 31, 2010, Harvest Vinccler and Petrodelta remeasured the appropriate monetary assets and liabilities at the new official exchange rate of 4.30 Bolivars per U.S. Dollar. During the nine months ended September 30, 2010, Harvest Vinccler recorded a $1.5 million remeasurement loss and Petrodelta recorded a $120.5 million remeasurement gain on revaluation of monetary assets and liabilities. The revaluation of Bolivars to U.S. Dollars was calculated as the difference between the old official exchange rate of 2.15 Bolivars per U.S. Dollar and the new official 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 monetary assets than Bolivar denominated monetary liabilities. The primary factor in Petrodelta’s gain on currency exchange rates is that Petrodelta had substantially higher Bolivar denominated monetary liabilities than Bolivar denominated monetary assets. At September 30, 2010, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 2.9 million and BsF 3.4 million, respectively. At September 30, 2010, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are BsF 78.0 million and BsF 2,032.3 million, respectively.

In Item 1A — Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2009, we disclosed that PDVSA’s failure to timely pay contractors, including Petrodelta, was having an adverse effect on Petrodelta. During the nine months ended September 30, 2010, PDVSA began making regular payments to Petrodelta to enable Petrodelta to reduce the outstanding debt to contractors. Some of the payments received from PDVSA were designated to be used to repay Harvest Vinccler (Advances to Equity Affiliates). During the nine months ended September 30, 2010, Petrodelta has paid $5.5 million to Harvest Vinccler for costs related to contractors and seconded employees.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
Thousand barrels of oil sold		2,219		1,938		6,142		5,670
Million cubic feet of gas sold		457		913		1,780		3,633
Total thousand barrels of oil equivalent		2,295		2,090		6,439		6,276
Average price per barrel	$	65.31	$	63.33	$	68.77	$	52.89
Average price per thousand cubic feet	$	1.54	$	1.54	$	1.54	$	1.54
Operating costs ($millions)	$	9.6	$	9.1	$	32.4	$	41.6
Capital expenditures ($millions)	$	21.4	$	20.6	$	46.9	$	69.6

Crude oil delivered from the Petrodelta fields to PDVSA is priced with reference to Merey 16 published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices are quoted and sold in U.S. Dollars. Natural gas delivered from the Petrodelta fields to PDVSA Petroleo S.A. (“PPSA”) is priced at $1.54 per thousand cubic feet. Since payments to Petrodelta for crude oil and natural gas deliveries are in U.S. Dollars as required under the Contract for Sale and Purchase of Hydrocarbons with PPSA, we do not expect the recent currency exchange developments in Venezuela to have a significant impact on our business in Venezuela.

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 allowed us to acquire up to a 25 percent non-operated interest in the project at that point in time. If we had chosen to exercise our option to participate, we would have participated in this project with essentially the same terms as the other existing projects in the AMI with the exception that we would not be the operator. The option to participate expired June 1, 2010. Because of the substantial changes made to the project after we acquired our option, we elected to not participate in the project, and the private third party agreed to refund our $1.5 million option payment. We received a refund of 50 percent of the $1.5 million option payment on September 24, 2010. We received the remaining 50 percent on October 1, 2010.

West Bay

During the nine months ended September 30, 2010, operational activities in the West Bay prospect focused on firming up plans for drilling on the identified initial drilling prospect and continuing to evaluate the other leads and prospects in the project. Land, regulatory and surface access preparations are currently in progress focused on taking the initial drilling prospect to drill-ready status. During the third quarter of 2010, we merged the 3-D seismic data set acquired during the second quarter of 2010 with our existing seismic data, and interpretation of the merged data set is in progress. The acquisition and merging of the additional 3-D seismic data allows for more complete technical evaluation of the leads and prospects identified in the project. The preliminary interpretation of the merged data set has resulted in the addition of a number of additional leads to the prospect inventory. During the nine months ended September 30, 2010, we had cash capital expenditures of $0.1 million for leasing activities and $0.1 million for seismic data processing on the West Bay project. The remaining 2010 forecast of expenditures for West Bay is $0.2 million.

Western United States — Antelope

In July 2010, we executed a farm-out agreement with the private third party in the JEDA for the acquisition of an incremental 10 percent interest in the Antelope Project with an effective date of July 1, 2010. This acquisition includes all leases, the Mesaverde, the Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) and the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”). The acquisition excludes the initial eight wells previously drilled in the Monument Butte Extension. Total consideration for the incremental 10 percent interest is $20.0 million, of which (1) $3.0 million was paid on August 2, 2010 (the closing date of the acquisition); (2) $3.0 million to be used as a credit against future joint interest billings or if joint interest billings do not accumulate to $3.0 million by October 1, 2010, at the sole election of the private third party, the balance is to be paid by us within 15 days of receipt of written request from the private third party; and (3) a capped $14.0 million carry of a portion of our partner’s exploration and development cost obligations in the upcoming Lower Green River/Upper Wasatch and Monument Butte Extension drilling programs in the Antelope project. On October 1, 2010, the private third party elected to receive in cash the remaining balance of the joint interest billing credit of $2.4 million. At September 30, 2010, the outstanding balance on the $14.0 million exploration and development cost obligation carry is $12.7 million. Based on current plans, we anticipate the full carry obligation will be met in the first half of 2011. This acquisition increases our ownership in the Antelope project to 70 percent.

During the nine months ended September 30, 2010, we had cash capital expenditure of $5.3 million for leasing activities on the Antelope prospect. We do not anticipate significant leasing activity in the remaining three months of 2010. Drilling, completion and testing activities are currently in progress on two separate projects on the Antelope prospect in Duchesne and Uintah Counties, Utah.

Lower Green River/Upper Wasatch Oil Delineation and Development Project

In the first quarter of 2010, we completed the drilling and testing of the Bar F #1-20-3-2 (“Bar F”) in the Mesaverde formation. After completion of the initial testing program on the Mesaverde deep gas formation, we moved uphole in the same well to test multiple oil bearing intervals at depths from 8,200 feet to 9,500 feet in the

Lower Green River/Upper Wasatch formations. Operational activities during the nine months ended September 30, 2010 included completion of testing of the Bar F, completion of the Bar F, including installation of an electric submersible pump, completion of production facilities for the Bar F and routine production operations of the Bar F. Results of the testing have been positive, and we believe the results indicate that we have made a commercial oil discovery in the Lower Green River/Upper Wasatch formations. The well is currently on routine production. As of October 18, 2010, the well had produced in excess of 46,000 gross barrels of oil since the commencement of the flow test, with the oil being sold in the Salt Lake City, Utah market. During the nine months ended September 30, 2010, we had cash capital expenditure of $6.8 million in drilling, completion and testing activities.

	•		The first well of the five-well delineation program, the Kettle #1-10-3-1 (“Kettle”), which spud on July 14, 2010, was drilled to a total depth of 12,000 feet and was hydraulically fractured with nine stages. The well flowed naturally a total of 4,440 barrels of oil and 17.6 million cubic feet of gas on a nine day flowback period up casing. The well has now been completed for production and installation of production facilities for the well is in progress.

	•		The second well, the ON Moon #1-27-3-2 (“ON Moon”), which spud on August 19, 2010, was drilled to a total depth of 10,169 feet and was hydraulically fractured with nine stages in the first week of November 2010.

	•		The third well in the program, the Dart 1-12-3-2 (“Dart”), which spud on October 8, 2010, was drilling at a depth of 9,100 feet as of November 2, 2010 with a planned total depth of 11,000 feet.

	•		The fourth well in the program, the Giles #1-19-3-2 (“Giles”) spud surface hole on October 15, 2010 using a small spud rig. As of October 25, 2010 the spud rig had reached total depth of 1,180 feet. The planned total depth of the Giles is 10,500 feet. The Giles is currently waiting arrival of the drilling rig to drill the production hole.

	•		Location construction is underway for the fifth well in the program, the Yergensen #1-9-3-1 (“Yergensen”).

During the nine months ended September 30, 2010, we had cash capital expenditure of $3.2 million in well planning and $0.1 million for engineering costs. The remaining 2010 forecast of expenditures for the Lower Green River/Upper Wasatch delineation and development drilling program is $17.0 million.

Monument Butte Extension Appraisal and Development Project

The 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 on these eight wells during the nine months ended September 30, 2010 consisted of routine production operations from the wells. As of September 30, 2010, the eight producing wells have produced approximately 86,000 barrels of oil (net to Harvest). The eight wells combined are currently producing slightly over 129 BOPD (net to Harvest). During the nine months ended September 30, 2010, we had cash capital expenditure of $3.3 million in well costs. There is no remaining 2010 forecast of expenditures for the initial eight-well program.

successful completion of the initial eight-well program that was drilled in late 2009 and early 2010. The six-well expansion is being drilled on acreage immediately adjacent to the initial eight-well program. The estimated gross drilling and completion cost per well is $0.9 million, and we have an approximate 37 percent working interest in the six wells after the acquisition of the incremental 10 percent interest from the private third party through the farm-out agreement dated July 1, 2010. At September 30, 2010, four wells had been drilled and were on production. As of September 30, 2010, the four expansion wells have produced approximately 5,000 barrels of oil (net to Harvest). The four wells are currently producing slightly over 92 BOPD (net to Harvest). During the nine months ended September 30, 2010, we had cash capital expenditures of $0.5 million in well costs and $0.1 million for geological and geophysical costs. The remaining 2010 forecast of expenditures for the six-well expansion program is $0.7 million which includes the planned drilling of the two remaining wells in the six-well expansion program.

Certain operating statistics for the three and nine months ended September 30, 2010 for the U.S. operations are set forth below. This information is provided at our net ownership. As of September 30, 2010, our average net revenue interest is 33 percent in the initial eight producing wells in the Monument Butte Extension, 29 percent in the six well expansion of Monument Butte Extension, and 55 percent in the Lower Green/Upper Wasatch Project. Substantially all of the oil and gas production, cash operating expense and depletion expense listed below are associated with the Monument Butte Extension project. The cash capital expenditures listed below are associated with the Monument Butte Extension, the Lower Green River/Upper Wasatch project and Mesaverde project combined. This information may not be representative of future results.


	Three Months		Nine Months
	Ended		Ended
	September 30,		September 30,
	2010		2010
Barrels of oil sold		27,181		111,330
Thousand cubic feet of gas sold		71,643		207,446
Total barrels of oil equivalent		39,122		145,905
Average price per barrel	$	62.63	$	64.82
Average price per thousand cubic feet	$	3.03	$	3.57
Lease operating costs and production taxes ($millions)	$	0.5	$	1.2
Cash capital expenditures ($millions)	$	8.8	$	24.2
Depletion expense per barrel of oil equivalent	$	15.54	$	15.20

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”)

Pursuant to the terms of the Budong PSC, at end of the first three-year exploration phase, 35 percent of the original area was relinquished to BP Migas. The second three-year exploration phase began in January 2010 covering 0.88 million acres.

In accordance with the Budong PSC farm-in agreement, we expect to fund 100 percent of the well expenditures to earn our working interest. Prior to drilling the first exploration well, subject to the estimated cost of that well, our partner will have a one-time option to increase the level of the carried interest to a maximum of $20.0 million. On September 15, 2010, our partner exercised their option to increase the carry obligation by $2.7 million to a total of $19.9 million. The additional carry increases our ownership by 7.4 percent to 54.4 percent. The change in ownership interest is subject to regulatory approval.

Two drill sites were selected in 2009. Operational activities during the nine months ended September 30, 2010 focused on well planning, construction for the two test well sites, preparations for mobilization of rig and ancillary equipment to the first drill site and delivery of drilling equipment. After delays in acquiring permits to mobilize the drilling rig from its port location to the drilling pad, it is now expected that the first of two exploratory wells will spud late in the fourth quarter of 2010. During the nine months ended September 30, 2010, we had cash capital expenditure of $6.4 million for well planning, construction and drilling equipment and $3.2 million for

seismic, geological and geophysical and exploration support costs. The remaining 2010 forecast of expenditures for the Budong PSC is $7.5 million.

Dussafu Project — Gabon (“Dussafu PSC”)

The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources, entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. It has been agreed that the second three-year exploration phase will be extended until May 27, 2011, at which time the partners can elect to enter a third exploration phase. Operational activities during the nine months ended September 30, 2010 focused on maturation of prospect inventory and well planning. Subject to drilling rig availability, we expect to drill an exploratory well in the second quarter of 2011. During the nine months ended September 30, 2010, we had cash capital expenditure of $2.2 million in well planning and $0.4 million for seismic, geological and geophysical and explorations support costs. The remaining 2010 forecast of expenditures for the Dussafu PSC is $1.2 million.

Oman (“Block 64 EPSA”)

Operational activities on the Al Ghubar / Qarn Alam license (“Block 64 EPSA”) during the nine months ended September 30, 2010 include the geological studies, baseline environmental and social study and 3-D pre-stack depth migration reprocessing of approximately 1,000 square kilometers of existing 3-D seismic data. We expect to drill the first of the two exploratory wells in the second half of 2011. During the nine months ended September 30, 2010, we had cash capital expenditure of $0.4 million on geological, environmental and social studies and $0.9 million for seismic, geological and geophysical and explorations support costs. The remaining 2010 expected cash expenditures for the Block 64 EPSA is $0.6 million.

Other Exploration Projects

Relating to other projects, we had cash capital expenditure of $1.3 million during the nine months ended September 30, 2010. Either the exploratory well to be drilled in 2010 on the Budong PSC or further results from the Lower Green River/Upper Wasatch delineation and development drilling program in Utah can have a significant impact on our ability to obtain financing, record reserves and generate cash flow in 2011 and beyond.

Management Changes

On September 1, 2010, Mr. Angel Urdaneta was hired by Harvest Vinccler and seconded to Petrodelta as its Operations and Technical Manager. Mr. Urdaneta replaced Mr. G. Michael Morgan, Vice President of Business Development of Harvest, who was temporarily performing the duties of Petrodelta’s Operations and Technical Manager. Under the terms of the conversion contract, HNR Finance has the right to nominate the Operations and Technical Manager.

Other Matters

On August 20, 2010, we received a comment letter from the Securities and Exchange Commission (“SEC”) pertaining to our Annual Report on Form 10-K for the year ended December 31, 2009, Definitive Proxy Statement on Schedule 14A relating to our annual stockholders’ meeting held May 20, 2010 and Quarterly Report on Form 10-Q for the period ended June 30, 2010. The SEC’s comments addressed various items, including recommended expanded disclosures. On September 14, 2010, we filed our response with the SEC. We have incorporated into this Quarterly Report on Form 10-Q for the period ended September 30, 2010 disclosures which we believe are responsive to the applicable comments in the SEC’s comment letter.

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 that in the near term Petrodelta will reinvest 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 operations or cash flows. However, the new reserve could have a negative impact on the amount of dividends received in the future. It was anticipated that all available cash generated during 2010, and is still

anticipated for 2011, would be used to meet Petrodelta’s current operating requirements and would not be available for dividends. However, in August 2010, Petrodelta declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received on October 22, 2010. There is no certainty that Petrodelta will pay additional dividends in 2010 or 2011. 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 $13.3 million at September 30, 2010, we will require additional funds in order to fund our future operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration, appraisal and development projects and to a lesser extent, general and administrative costs. Currently, our primary source of cash is dividends from Petrodelta and to a lesser extent, production from the Monument Butte Extension and Lower Green River/Upper Wasatch projects. 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 capital markets, and reducing costs. In addition, we could delay discretionary capital spending to future periods or sell, farm-out or otherwise monetize assets as necessary to maintain the liquidity required to run our operations, if necessary. There can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.

We continually assess our need for additional sources of financing based on our operational, working capital and other needs from time to time. In addition to the above, we are currently contemplating one particular additional source of financing through an Islamic (sukuk) financing. Sukuk financing is an Islamic financial certificate, similar to a bond in Western finance, that complies with Sharia, Islamic religious law. Trading debt is prohibited under Sharia. As such, financing under Sharia must only be raised for identifiable assets. The issuer of a sukuk buys an asset from an investor group, who then rents the asset from the issuer for a predetermined fee. Under the sukuk, one of our subsidiaries would form and contribute certain assets to a partnership and subsequently sell a minority interest in the partnership to the sukuk issuers for approximately $250 million. Although the terms of this transaction have not been finalized, we anticipate that the terms would include our agreement to pay all or a substantial portion of the future dividends paid by Petrodelta over the next five or six years to reacquire all of the sukuk issuers partnership interests, including premiums thereon. While we may be able to consummate this financing transaction in the near future, there can be no assurances that this transaction will be consummated at all, and we may consider alternative forms of additional financing if we deem necessary or advisable with respect to our operations from time to time.

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


	Nine Months Ended September 30,
	2010			2009
	(in thousands)
Net cash used in operating activities	$	(12,857	)	$	(23,776	)
Net cash used in investing activities		(35,822	)		(23,068	)
Net cash provided by (used in) financing activities		29,672			(1,332	)

Net decrease in cash	$	(19,007	)	$	(48,176	)

At September 30, 2010, we had current assets of $38.1 million and current liabilities of $32.6 million, resulting in working capital of $5.5 million and a current ratio of 1.2:1. This compares with a working capital of $34.2 million and a current ratio of 3.0:1 at December 31, 2009. The decrease in working capital of $28.7 million was due to increases in capital expenditures, exploration costs and administrative expenses offset by increases in accounts receivable and accrued expenses.

Cash Flow used in Operating Activities. During the nine months ended September 30, 2010 and 2009, net cash used in operating activities was approximately $12.9 million and $23.8 million, respectively. The $10.9 million decrease was due to increases in capital expenditures, exploration costs and administrative expenses offset by increases in accounts receivable and accrued expenses. The nine months ended September 30, 2010 also included $8.0 million in oil and gas revenue from the Monument Butte Extension and Lower Green River/Upper Wasatch areas in Utah.

Cash Flow from Investing Activities. During the nine months ended September 30, 2010, we had cash capital expenditures of approximately $34.6 million. Of the 2010 expenditures, $24.2 million was attributable to activity on the Antelope projects, $6.4 million was attributable to activity on the Budong PSC, $2.2 million was attributable to activity on the Dussafu PSC and $1.8 million was attributable to other projects. During the nine months ended September 30, 2009, we had cash capital expenditures of approximately $22.7 million. Of the 2009 expenditures, $17.6 million was attributable to activity on the Antelope projects, $2.4 million to Block 64 EPSA, $0.5 million to the West Bay project and $2.2 million to other projects.

During the nine months ended September 30, 2010, we deposited with a U.S. bank $1.0 million as collateral for a standby letter of credit issued in support of a bank guarantee required as a performance guarantee for a joint study. We incurred $0.2 million and $0.4 million of investigatory costs related to various international and domestic exploration studies during the nine months ended September 30, 2010 and 2009, respectively.

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, our February 2010 8.25 percent senior convertible notes, other financing sources, accessing equity and debt markets, and reducing costs. 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 nine months ended September 30, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes, incurred $2.7 million in deferred financings costs related to the $32.0 million convertible debt offering that are being amortized over the life of the financial instrument and $0.1 million in legal fees associated with a prospective financing. During the nine months ended September 30, 2009, we incurred $1.6 million in legal fees associated with a prospective financing.

Results of Operations

You should read the following discussion of the results of operations for the three and nine months ended September 30, 2010 and 2009 and the financial condition as of September 30, 2010 and December 31, 2009 in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2009.

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

We reported a net loss attributable to Harvest of $5.0 million, or $(0.15) diluted earnings per share, for the three months ended September 30, 2010, compared with net income attributable to Harvest of $0.8 million, or $0.02 diluted earnings per share, for the three months ended September 30, 2009.

Revenues were higher in the three months ended September 30, 2010 compared with the three months ended September 30, 2009 due to production from the Monument Butte Extension wells and the Lower Green River/Upper Wasatch well. We had no production in the three months ended September 30, 2009. Production for the two areas for the three months ended September 30, 2010 was:


	Lower Green		Monument
	River/Upper		Butte
	Wasatch		Extension
Barrels of oil sold		6,108		21,073
Thousand cubic feet of gas sold		3,700		67,943
Total barrels of oil equivalent		6,725		32,397
Average price per barrel	$	64.67	$	62.04
Average price per thousand cubic feet	$	3.81	$	2.98

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


	Three Months Ended
	September 30,						Increase
	2010			2009			(Decrease)
Lease operating costs and production taxes	$	0.5		$	—		$	0.5
Depletion, depreciation and amortization		0.7			0.1			0.6
Exploration expense		2.6			0.9			1.7
General and administrative		7.0			6.1			0.9
Taxes other than on income		0.2			0.2			—
Investment earnings and other		(0.1	)		(0.3	)		0.2
Interest expense		0.2			—			0.2
Income tax expense		0.7			0.1			0.6

Lease operating costs were higher in the three months ended September 30, 2010 compared to the three months ended September 30, 2009 due to the inception of oil and natural gas operations in the U.S. beginning in late December 2009. Costs incurred were primarily for water disposal, gas gathering transportation and processing, fuel and other routine oil production activities. Depletion expense, which was entirely attributable to U.S. production, was $0.6 million ($15.54 per equivalent barrel) for the three months ended September 30, 2010.

During the three months ended September 30, 2010, we incurred $2.6 million of exploration costs related to seismic, geological and geophysical, and exploration support costs. Included in the $2.6 million of exploration costs is the one-time charge of $1.2 million for acquisition of seismic data for the Budong PSC related to our partner in the Budong PSC exercising their option to increase the carry obligation. During the three months ended September 30, 2009, we incurred $0.3 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations and $0.6 million related to other general business development activities.

General and administrative costs for the three months ended September 30, 2010 were higher compared to the three months ended September 30, 2009, primarily due to higher employee related costs, contract services and travel costs. Taxes other than on income for the three months ended September 30, 2010 were consistent with the three months ended September 30, 2009.

Investment earnings and other decreased in the three months ended September 30, 2010 compared to the three months ended September 30, 2009 due to lower interest rates earned on lower cash balances. Interest expense was higher for the three months ended September 30, 2010 compared to the three months ended September 30, 2009 due to the interest associated with our $32 million senior convertible note offering in February 2010 offset by interest capitalized to oil and gas properties of $0.7 million.

Income tax expense was higher for the three months ended September 30, 2010 compared to the three months ended September 30, 2009, primarily due to $0.5 million of additional income taxes assessed to Harvest Vinccler in 2010 for the 2007 and 2008 tax years. The tax assessment was the result of a tax audit conducted by the SENIAT, the Venezuelan income tax authority.

Petrodelta’s reporting and functional currency is the U.S. Dollar. Net income from unconsolidated equity affiliates includes a $0.1 million, before tax, remeasurement loss on revaluation of assets and liabilities recorded by Petrodelta due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. Petrodelta’s current tax rate increased from 58 percent for the three months ended September 30, 2009 to 78 percent for the three months ended September 30, 2010 primarily as a result of changes to the 2010 tax projections for the deductibility of the exchange losses. The Bolivar devaluation increased Petrodelta’s overall effective tax rate due to the effect of the devaluation on the deferred tax asset. The adjustment to reconcile to reported net income from unconsolidated affiliate for deferred income taxes increased due to the effect of the currency devaluation on the deferred tax asset associated with the non-monetary assets impacted by inflationary adjustments.

At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion. Accordingly, we no longer record losses that would cause our equity investment to go into a negative position. For the three months ended September 30, 2010, Fusion reported a net loss of $0.7 million ($0.3 million net to our 49 percent interest). This loss is not reported in the three months ended September 30, 2010 net income from unconsolidated equity affiliates as reporting it would take our equity investment into a negative position.

Nine Months Ended September 30, 2010 Compared with Nine Months Ended September 30, 2009

We reported net income attributable to Harvest of $19.3 million, or $0.53 diluted earnings per share, for the nine months ended September 30, 2010, compared with a net loss attributable to Harvest of $8.2 million, or $(0.25) diluted earnings per share, for the nine months ended September 30, 2009.

Revenues were higher in the nine months ended September 30, 2010 compared with the nine months ended September 30, 2009 due to production from the Monument Butte Extension wells and the Lower Green River/Upper Wasatch well. We had no production in the nine months ended September 30, 2009. Production for the two areas for the nine months ended September 30, 2010 was:


	Lower Green		Monument
	River/Upper		Butte
	Wasatch		Extension
Barrels of oil sold		20,274		91,056
Thousand cubic feet of gas sold		3,700		203,746
Total barrels of oil equivalent		20,891		125,014
Average price per barrel	$	68.60	$	63.97
Average price per thousand cubic feet	$	3.81	$	3.57

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


	Nine Months Ended
	September 30,						Increase
	2010			2009			(Decrease)
Lease operating costs and production taxes	$	1.2		$	—		$	1.2
Depletion, depreciation and amortization		2.6			0.3			2.3
Exploration expense		5.3			5.3			—
General and administrative		18.8			19.0			(0.2	)
Taxes other than on income		0.7			0.8			(0.1	)
Investment earnings and other		(0.4	)		(0.9	)		0.5
Interest expense		1.3			—			1.3
Loss on exchange rates		1.5			0.1			1.4
Income tax expense		0.8			1.1			(0.3	)

Lease operating costs and production taxes were higher in the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 due to the inception of oil and natural gas operations in the U.S. beginning in late December 2009. Costs incurred were primarily for water disposal, gas gathering

transportation and processing, fuel and other routine oil production activities. Depletion expense, which was entirely attributable to U.S. production, was $2.2 million ($15.20 per equivalent barrel) for the nine months ended September 30, 2010.

During the nine months ended September 30, 2010, we incurred $4.8 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. Included in the $4.8 million of exploration costs is the one-time charge of $1.2 million for acquisition of seismic data for the Budong PSC related to our partner in the Budong PSC exercising their option to increase the carry obligation. During the nine months ended September 30, 2009, we incurred $3.1 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations and $2.2 million related to other general business development activities.

General and administrative costs were lower in the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 primarily due to lower contract services and travel costs offset by higher employee related costs and general operating costs. Taxes other than on income for the nine months ended September 30, 2010 were not materially different from the nine months ended September 30, 2009.

Investment earnings and other decreased in the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 due to lower interest rates earned on lower cash balances. Interest expense was higher for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 due to the interest associated with our $32 million senior convertible note offering in February 2010 offset by interest capitalized to oil and gas properties of $0.9 million.

Loss on exchange rates is higher for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced by the Venezuelan government on January 8, 2010. During the nine months ended September 30, 2010, Harvest Vinccler recorded a $1.5 million remeasurement loss on revaluation of assets and liabilities.

Income tax expense was lower for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 due to income tax assessed in the Netherlands recorded in the first quarter of 2009 of $0.9 million offset by $0.5 million of additional income taxes assessed to Harvest Vinccler in 2010 for the 2007 and 2008 tax years. The 2010 tax assessment was the result of a tax audit conducted by the SENIAT.

Petrodelta’s reporting and functional currency is the U.S. Dollar. Net income from unconsolidated equity affiliates includes a $120.5 million, before tax, ($38.6 million, before tax, net to our 32 percent interest) remeasurement gain on revaluation of assets and liabilities recorded by Petrodelta due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. The Bolivar devaluation increased Petrodelta’s overall effective tax rate due to the effect of the devaluation on the deferred tax asset in the first quarter of 2010. The adjustment to reconcile to reported net income from unconsolidated affiliate for deferred income taxes increased due to the effect of the currency devaluation on the deferred tax asset associated with the non-monetary assets impacted by inflationary adjustments.

At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion. Accordingly, we no longer record losses that would cause our equity investment to go into a negative position. For the nine months ended September 30, 2010, Fusion reported a net loss of $2.3 million ($1.1 million net to our 49 percent interest). This loss is not reported in the nine months ended September 30, 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 nine months ended September 30, 2010. The U.S. Dollar and Bolivar exchange rates had not been adjusted from March 2005 until January 2010. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our control. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.

Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Harvest Vinccler and Petrodelta do not have, and have not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate.


Item 3.		Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk from adverse changes of the situation in Venezuela, our recently initiated exploration program and adverse changes in oil prices, interest rates, foreign exchange and political risk, as discussed in our Annual Report on Form 10-K for the year ended December 31, 2009. The information about market risk for the nine months ended September 30, 2010 does not differ materially from that discussed in the Annual Report on Form 10-K for the year ended December 31, 2009.


Item 4.		Controls and Procedures

Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures that are designed to ensure the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s (“SEC”) rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

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

PART II. OTHER INFORMATION


Item 1.		Legal Proceedings

See our Annual Report on Form 10-K for the year ended December 31, 2009 for a description of certain other legal proceedings. There have been no material developments in such legal proceedings since the filing of such Annual Report.


Item 1A.		Risk Factors

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

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

	•		Response to unexpected releases to the environment;

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

	•		The spacing of wells;

	•		Unitization and pooling of properties;

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

	•		Taxation.

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

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

could increase our costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business, negatively impacting our financial condition, results of operations and cash flows.

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

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

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

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

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


Item 6.		Exhibits

(a) Exhibits

3.1

Amended and Restated Certificate of Incorporation.

	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.

	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.)

	4.4		Amendment to Third Amended and Restated Rights Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

	4.5		Warrant Purchase Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.2 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

	4.6		Common Stock Purchase Warrant No. W-1, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.3 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

	4.7		Common Stock Purchase Warrant No. W-2, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.4 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

	4.8		Common Stock Purchase Warrant No. W-3, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.5 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

	10.1		Credit Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 10.1 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

	10.2		Guaranty, dated as of October 28, 2010, by Harvest (US) Holdings, Inc., Harvest Natural Resources, Inc. (UK) and Harvest Offshore China Company in favor of MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 10.2 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

	10.3		Term Note, dated as of October 28, 2010, of Harvest Natural Resources, Inc. in favor of MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 10.3 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

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

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

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

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

Exhibit Index


Exhibit
Number		Description
3.1		Amended and Restated Certificate of Incorporation.

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.

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.)

4.4		Amendment to Third Amended and Restated Rights Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

4.5		Warrant Purchase Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.2 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

4.6		Common Stock Purchase Warrant No. W-1, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.3 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

4.7		Common Stock Purchase Warrant No. W-2, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.4 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

4.8		Common Stock Purchase Warrant No. W-3, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.5 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

10.1		Credit Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 10.1 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

10.2		Guaranty, dated as of October 28, 2010, by Harvest (US) Holdings, Inc., Harvest Natural Resources, Inc. (UK) and Harvest Offshore China Company in favor of MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 10.2 to our Form 8-K filed on October 29, 2010, File No. 1-10762.)

10.3		Term Note, dated as of October 28, 2010, of Harvest Natural Resources, Inc. in favor of MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 10.3 to our Form 8-K filed on October 29, 2010, 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.


	Page
PART I FINANCIAL INFORMATION

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk		34

Item 4. Controls and Procedures		34

PART II OTHER INFORMATION

Item 1. Legal Proceedings		36

Item 1A. Risk Factors		36

Item 6. Exhibits		37

Signatures		39
EX-3.1
EX-4.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2


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


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

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