exv99w3

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Harvest Natural Resources, Inc.:

In our opinion, the consolidated financial statements listed in the index appearing in Item 9.01 under Exhibit 99.3 present fairly, in all material respects, the financial position of Harvest Natural Resources, Inc. and its subsidiaries at December 31, 2008 and December 31, 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule (not presented herein) listed in the index appearing under Item 15(a)2 of Harvest Natural Resources, Inc.’s 2008 Annual Report on Form 10-K presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because a material weakness in internal control over financial reporting related to the period-end financial reporting process existed as of that date. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in Management’s Report on Internal Control Over Financial Reporting (not presented herein) appearing under Item 9A of Harvest Natural Resources, Inc.’s 2008 Annual Report on Form 10-K. We considered this material weakness in determining the nature, timing, and extent of audit tests applied in our audit of the 2008 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in management’s report referred to above. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 1 of the consolidated financial statements, the Company has restated its 2007 consolidated financial statements to correct an error.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for noncontrolling interests effective January 1, 2009.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

Houston, Texas

March 13, 2009, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of the change in accounting for noncontrolling interests discussed in Note 1 and the subsequent events disclosure about the Company’s liquidity and related ability to fund its operations in 2010 as discussed in Note 3, as to which the date is November 4, 2009.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS


	December 31,
	2008			2007*
				(restated)
	(in thousands, except per share data)
ASSETS
Current Assets:
Cash and cash equivalents	$	97,165		$	120,841
Restricted cash		—			6,769
Accounts and notes receivable, net		11,570			9,418
Advances to equity affiliate		3,732			16,352
Prepaid expenses and other		3,964			1,032

Total Current Assets		116,431			154,412
Other Assets		3,316			4,301
Investment in equity affiliates		218,982			254,775
Property and Equipment:
Oil and gas properties (successful efforts method)		22,328			3,163
Other administrative property		2,368			1,481

		24,696			4,644
Accumulated depreciation and amortization		(1,159	)		(1,061	)

Net Property and Equipment		23,537			3,583

	$	362,266		$	417,071


LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable, trade and other	$	1,662		$	5,949
Accounts payable, related party		—			10,093
Advance from equity affiliate		20,750			—
Accrued expenses		12,241			11,895
Accrued interest		4,691			5,136
Income taxes payable		77			503
Current portion of long-term debt		—			9,302

Total Current Liabilities		39,421			42,878
Commitments and Contingencies		—			—

EQUITY
Stockholders’ Equity:
Preferred stock, par value $0.01 a share; Authorized 5,000 shares; outstanding, none
Common stock, par value $0.01 a share; Authorized 80,000 shares at December 31, 2008 and 2007; issued 39,128 shares and 38,513 shares at December 31, 2008 and 2007, respectively		391			385
Additional paid-in capital		208,868			201,938
Retained earnings		129,351			150,815
Treasury stock, at cost, 6,444 shares at December 31, 2008 and 3,719 shares at December 31, 2007, respectively		(65,368	)		(36,491	)

Total Harvest Stockholders’ Equity		273,242			316,647
Noncontrolling Interest		49,603			57,546

Total Equity		322,845			374,193

	$	362,266		$	417,071


*		See Note 1 — Organization and Summary of Significant Accounting Policies — Restatement.

See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS


	Years Ended December 31,
				2007*
	2008			(restated)			2006
	*(in thousands, except per share data)*
Revenues
Oil sales (a)	$	—		$	11,217		$	54,858
Gas sales		—			—			4,648

		—			11,217			59,506


Expenses
Operating expenses		—			—			9,241
Depletion, depreciation and amortization		201			384			15,435
Exploration expense		16,402			850			—
Dry hole costs		10,828			—			—
General and administrative		27,215			29,096			26,421
Contribution to Science and Technology Fund		—			—			3,887
Taxes other than on income		(206	)		423			3,948

		54,440			30,753			58,932


Income (Loss) from Operations		(54,440	)		(19,536	)		574
Other Non-Operating Income (Expense)
Gain on Financing Transactions		3,421			49,623			—
Investment earnings and other		3,663			9,051			9,285
Interest expense		(1,730	)		(8,224	)		(23,156	)

		5,354			50,450			(13,871	)


Income (Loss) from Consolidated Companies Before Income Taxes		(49,086	)		30,914			(13,297	)
Income Tax Expense		25			6,312			60,917

Income (loss) from Consolidated Companies		(49,111	)		24,602			(74,214	)
Net Income from Unconsolidated Equity Affiliates		34,576			55,297			—

Net Income (Loss)		(14,535	)		79,899			(74,214	)
Less: Net Income Attributable to Noncontrolling Interest		6,929			19,781			(11,712	)

Net Income (Loss) Attributable to Harvest	$	(21,464	)	$	60,118		$	(62,502	)


Net Income (Loss) Attributable to Harvest Per Common Share:
Basic	$	(0.63	)	$	1.65		$	(1.68	)

Diluted	$	(0.63	)	$	1.59		$	(1.68	)


(a)		Recognition of deferred revenue — See Note 1 — Organization and Summary of Significant Accounting Policies — Revenue Recognition.

*		See Note 1 — Organization and Summary of Significant Accounting Policies — Restatement.

See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(in thousands)


	Common				Additional								Non-
	Shares		Common		Paid-in		Retained			Treasury			Controlling
	Issued		Stock		Capital		Earnings			Stock			Interests			Total
Balance at January 1, 2006		37,757	$	378	$	188,242	$	153,199		$	(3,844	)	$	49,477		$	387,452

Issuance of common shares:
Exercise of stock options		137		1		879		—			—			—			880
Employee stock-based compensation		80		1		5,055		—			—			—			5,056
Net Loss		—		—		—		(62,502	)		—			(11,712	)		(74,214	)


Balance at December 31, 2006		37,974		380		194,176		90,697			(3,844	)		37,765			319,174

Issuance of common shares:
Exercise of stock options		402		4		1,934		—			—			—			1,938
Employee stock-based compensation		137		1		5,828		—			—			—			5,829
Purchase of Treasury Shares		—		—		—		—			(32,647	)		—			(32,647	)
Net Income		—		—		—		57,237			—			19,060			76,297


Balance at December 31, 2007 as previously reported		38,513		385		201,938		147,934			(36,491	)		56,825			370,591
Restatement adjustment		—		—		—		2,881			—			721			3,602


Balance at December 31, 2007 as restated*		38,513		385		201,938		150,815			(36,491	)		57,546			374,193

Issuance of common shares:
Exercise of stock options		547		5		1,560		—			—			—			1,565
Employee stock-based compensation		68		1		5,370		—			—			—			5,371
Purchase of Treasury Shares		—		—		—		—			(28,877	)		(8	)		(28,885	)
Distribution to noncontrolling Interests		—		—		—		—			—			(14,864	)		(14,864	)
Net Income (Loss)				—		—		(21,464	)		—			6,929			(14,535	)


Balance at December 31, 2008		39,128	$	391	$	208,868	$	129,351		$	(65,368	)	$	49,603		$	273,242


*		See Note 1 — Organization and Summary of Significant Accounting Policies — Restatement.

See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)


	Years Ended December 31,
				2007*
	2008			(restated)			2006
				*(in thousands)*
Cash Flows From Operating Activities:
Net income (loss)	$	(14,535	)	$	79,899		$	(74,214	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		201			384			15,435
Dry hole costs		10,828			—			—
Gain on financing transactions		(3,421	)		(49,623	)		—
Net income from unconsolidated equity affiliates		(34,576	)		(55,297	)		—
Non-cash compensation related charges		6,061			6,108			5,056
Deferred income taxes		—			5,608			(2,556	)
Dividend received from equity affiliate		72,530			—			—
Changes in operating assets and liabilities:
Accounts and notes receivable		548			393			61,839
Advances to equity affiliate		12,620			2,794			(19,146	)
Prepaid expenses and other		(5,632	)		214			903
Accounts payable		(2,957	)		2,122			3,419
Accounts payable, related party		(10,093	)		456			434
Advance from equity affiliate		20,750			—			—
Accrued expenses		(1,073	)		(1,251	)		(5,445	)
Accrued interest		(445	)		(1,714	)		4,213
Deferred revenue		—			(11,217	)		4,489
Income taxes payable		(426	)		469			(18,875	)

Net Cash Provided By (Used In) Operating Activities		50,380			(20,655	)		(24,448	)

Cash Flows from Investing Activities:
Additions of property and equipment		(26,317	)		(647	)		(1,657	)
Investments in equity affiliates		(2,161	)		(7,388	)		(513	)
(Increase) decrease in restricted cash		6,769			82,120			(88,889	)
Investment costs		(1,346	)		(4,125	)		503

Net Cash Provided By (Used In) Investing Activities		(23,055	)		69,960			(90,556	)

Cash Flows from Financing Activities:
Net proceeds from issuances of common stock		1,565			1,938			880
Purchase of treasury stock		(29,416	)		(32,755	)		—
Proceeds from issuance of notes payable		—			—			118,953
Financing costs		(1,075	)		—			—
Payments of note payable		(7,211	)		(45,726	)		(19,769	)
Dividend paid to noncontrolling interest		(14,864	)		—			—

Net Cash Provided By (Used In) Financing Activities		(51,001	)		(76,543	)		100,064

Net Decrease in Cash and Cash Equivalents		(23,676	)		(27,238	)		(14,940	)
Cash and Cash Equivalents at Beginning of Year		120,841			148,079			163,019

Cash and Cash Equivalents at End of Year	$	97,165		$	120,841		$	148,079

Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for interest expense	$	768		$	7,972		$	23,171

Cash paid during the year for income taxes	$	456		$	201		$	62,505


*		See Note 1 — Organization and Summary of Significant Accounting Policies — Restatement.

See accompanying notes to consolidated financial statements.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements

Note 1 — Organization and Summary of Significant Accounting Policies

Harvest Natural Resources, Inc. (“Harvest”) is an independent energy company engaged in the acquisition, exploration, development, production and disposition of oil and natural gas properties since 1989, when it was incorporated under Delaware law. We have significant interests in the Bolivarian Republic of Venezuela (”Venezuela”) through our ownership in Petrodelta, S.A. (“Petrodelta”). HNR Finance B.V. (“HNR Finance”) has a 40 percent ownership interest in Petrodelta. As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta, and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining eight percent equity interest. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petrodelta is governed by its own charter and bylaws. In March 2008, we executed an Area of Mutual Intent (“AMI”) agreement with a private third party for an area of the Gulf Coast Region of the United States and entered into a Joint Exploration and Development Agreement (“JEDA”) in the Antelope project in the Western United States. We also have exploration acreage offshore of the People’s Republic of China (“China”), offshore of the Republic of Gabon (“Gabon”) and mainly onshore West Sulawesi in the Republic of Indonesia (“Indonesia”). See Note 9 – United States Operations, Note 10 – Indonesia and Note 11 – Gabon.

Restatement

We are restating our historical financial statements for the year ended December 31, 2007 and quarterly information for the quarters ended December 31, 2007, March 31, 2008, June 30, 2008 and September 30, 2008 (see Exhibits and Financial Statement Schedules, Quarterly Financial Data (unaudited)). The restatements relate to the correction of an error in the deferred tax adjustment to reconcile our share of Petrodelta’s net income reported under International Financial Reporting Standards (“IFRS”) to that required under accounting principles generally accepted in the United States of America (“GAAP”) and recorded within Net income from unconsolidated equity affiliates.

The adjustment to record our share of Petrodelta’s net income under GAAP should have been limited to deferred tax adjustments related to non-monetary temporary differences impacted by inflationary adjustments under Venezuela law. During the 2008 year end close process, we determined that restatements were necessary because since October 1, 2007 both the monetary and non-monetary temporary differences recorded in Petrodelta’s IFRS financial statements had been adjusted in arriving at our GAAP consolidated financial statements rather than only the non-monetary temporary differences impacted by inflationary adjustments. Accordingly, we had understated our Net income from unconsolidated equity affiliates and Investment in equity affiliates.

The following tables set forth the effect of the adjustments described above on the consolidated statement of operations for the year ended December 31, 2007 and the consolidated balance sheet as of December 31, 2007. There was no impact on net cash used in operating activities in the consolidated statements of cash flows.

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Consolidated Statements of Operations


	December 31, 2007
	As Previously				As
	Reported		Adjustment		Restated
	*(in thousands, except per share data)*
Income from Consolidated Companies Before Income Taxes	$	30,914	$	—	$	30,914
Income Tax Expense		6,312		—		6,312

Income from Consolidated Companies		24,602		—		24,602
Net Income from Unconsolidated Equity Affiliates		51,695		3,602		55,297

Net Income		76,297		3,602		79,899
Less: Net Income Attributable to Noncontrolling Interest		19,060		721		19,781

Net Income Attributable to Harvest	$	57,237	$	2,881	$	60,118


Net Income Attributable to Harvest Per Common Share:
Basic	$	1.57	$	0.08	$	1.65
Diluted	$	1.51	$	0.08	$	1.59

Consolidated Balance Sheets


	December 31, 2007
	As Previously				As
	Reported		Adjustment		Restated
			*( in thousands)*
Investment in Equity Affiliates	$	251,173	$	3,602	$	254,775
Total Assets		413,469		3,602		417,071
Retained Earnings		147,934		2,881		150,815
Total Harvest Shareholders’ Equity		313,766		2,881		316,647
Noncontrolling Interest		56,825		721		57,546
Total Equity		370,591		3,602		374,193
Total Liabilities and Equity		413,469		3,602		417,071

Principles of Consolidation

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

Investment in Equity Affiliates

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

We own a 49 percent noncontrolling equity interest in Fusion Geophysical, LLC (“Fusion”) and a 40 percent noncontrolling equity interest in Petrodelta through our 80 percent owned subsidiary HNR Finance. Petrodelta was formed in October 2007, and the net income from unconsolidated equity affiliates from April 1, 2006 to December 31, 2007 was reflected in the three months ended December 31, 2007 consolidated statements of operations. The year ended December 31, 2008 includes net income from unconsolidated equity affiliates for Petrodelta on a current basis. No dividends were declared or paid by Fusion in the years ended December 31, 2008 or 2007. In May 2008, Petrodelta declared and paid a dividend of $181 million, $72.5 million net to HNR Finance ($58.0 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for

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the period of April 1, 2006 through December 31, 2007. In October 2008, Petrodelta paid an advance dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the six months ended June 30, 2008. Until Petrodelta’s board of directors declares a dividend for the year ended December 31, 2008, there is a possibility that all or a portion of the advance dividend could be rescinded; therefore, the advance dividend is reflected as a current liability on the consolidated balance sheets at December 31, 2008.

Reporting and Functional Currency

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

Revenue Recognition

Oil and natural gas revenue under the Operating Service Agreement (“OSA”) was accrued monthly based on production and delivery. Until March 31, 2006, each quarter, Harvest Vinccler invoiced Petroleos de Venezuela S.A. (“PDVSA”), based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. Dollar contract service fees per barrel. The related OSA with PDVSA provided for Harvest Vinccler to receive an operating fee for each barrel of crude oil delivered and the right to receive a capital recovery fee for certain of its capital expenditures, provided that such operating fee and capital recovery fee could not exceed the maximum total fee per barrel set forth in the agreement. In August 2005, Harvest Vinccler and PDVSA executed a Transitory Agreement (the “Transitory Agreement”) which provided that the maximum total fee per barrel paid under the OSA could not exceed 66.67 percent of the total value of the crude oil as determined under an Annex to the Transitory Agreement. This limitation was applied retroactively to January 1, 2005 and approximated 47 percent of West Texas Intermediate (“WTI”). The operating fee was subject to quarterly adjustments to reflect changes in the special energy index of the U.S. Consumer Price Index. Until March 31, 2006, each quarter Harvest Vinccler also invoiced PDVSA for natural gas sales based on a fixed price of $1.03 per Mcf. In addition, Harvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the natural gas production (“Incremental Crude Oil”). A portion of the Incremental Crude Oil was invoiced to PDVSA quarterly at a fixed price of $7.00 per Bbl. The invoices were prepared and submitted to PDVSA by the end of the first month following the end of each calendar quarter, and payment was due from PDVSA by the end of the second month following the end of each calendar quarter. Harvest Vinccler invoiced PDVSA for the first quarter 2006 delivery of its crude oil and natural gas in accordance with the Transitory Agreement. With the formation of Petrodelta, Harvest Vinccler recognized deferred revenue of $11.2 million for 2005 and first quarter 2006 deliveries that had been deferred pending clarification on the calculation of crude prices under the Transitory Agreement.

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 represents cash and cash equivalents held in a U.S. bank used as collateral for Harvest Vinccler’s loan agreement, and is classified as current or non-current based on the terms of the agreement. See Note 2 — Long-Term Debt and Liquidity.

Fair Value Measurements

We adopted Statement of Financial Accounting Standard (“SFAS”) No. 157, “Fair Value Measurements,” (“SFAS No. 157”) effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”)

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No.157-2, which delayed the effective date of SFAS No.157 by one year for non-financial assets and liabilities. As defined in SFAS No.157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The adoption of SFAS No. 157 had no impact on our consolidated financial position, results of operations or cash flows.

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

Credit Risk and Operations

All of our total consolidated revenues in 2007 and 2006 related to operations in Venezuela. During the year ended December 31, 2006, our Venezuelan crude oil and natural gas production represented all of our total production from consolidated companies. Petrodelta’s sole source of revenues for its production is PDVSA Petroleo S.A. (“PPSA”), a 100 percent owned subsidiary of PDVSA, which maintains full ownership of all hydrocarbons in its fields. The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PPSA which was signed on January 17, 2008.

Accounts and Notes Receivable

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

Each note is analyzed to determine if it is impaired pursuant to FAS No. 114 – 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.

During the three months ended December 31, 2008, we reclassified $2.7 million of prepaid land costs for the Antelope project to notes receivable. The note is due in less than one year and bears interest at a rate of 12 percent.

Other Assets

Other assets consist of investigative costs associated with new business development projects. These costs are reclassified to oil and natural gas properties or expensed depending on management’s assessment of the likely outcome of the project. At December 31, 2008, $1.2 million was reclassified to exploration expense.

Property and Equipment

We have $22.3 million and $3.2 million in oil and gas properties as of December 31, 2008 and 2007, respectively, all of which is unproved property. In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method.

Properties and equipment are stated at cost less accumulated depreciation, depletion and amortization (“DD&A”). Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if appropriate, gains or losses are recognized in Investment Earnings and Other.

Exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling exploratory wells are capitalized pending

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determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense. Costs of drilling successful exploratory wells, all development wells, and related production equipment and facilities are capitalized and depleted or depreciated using the unit-of-production method as oil and gas is produced.

Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent associated with successful exploration activities. Costs of maintaining and retaining undeveloped leaseholds, as well as amortization and impairment of unsuccessful leases, are included in exploration expense. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties.

During the year ended December 31, 2008, we incurred $13.9 million of exploration costs related to the purchase and re-processing of seismic for our United States operations, acquisition of seismic for our Indonesia and Gabon operations, $2.5 million of other general business development activities and $10.8 million of dry hole exploratory well costs. During the year ended December 31, 2007, we incurred $0.9 million of exploration costs related to other general business development activities. During year ended December 31, 2008, we reclassified $3.8 million of lease investigatory costs associated with our United States operations from other assets to oil and gas properties. See Note 9 – United States Operations.

Proved oil and gas properties are reviewed for impairment for which identifiable cash flows are independent of cash flows of other assets when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are determined based on estimated future oil and gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these undiscounted estimated future net cash flows is less than the carrying amount of the property, an impairment loss is recognized for the excess, if any, of the property’s carrying amount over its estimated fair value, which is generally based on discounted future net cash flows.

Costs of drilling and equipping successful exploratory wells, development wells, asset retirement liabilities and costs to construct or acquire offshore platforms and other facilities, are depreciated using the unit-of-production method based on total estimated proved oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved leaseholds, are depleted using the unit-of-production method based on total estimated proved reserves. All other properties are stated at historical acquisition cost, net of allowance for impairment, and depreciated using the straight-line method over the useful lives of the assets.

Undeveloped property costs consist of $13.2 million for the Gulf Coast and Western United States operations, $3.0 million for WAB-21, $5.9 million for the Dussafu Marin exploration production sharing contract (“Dussafu PSC”) and $0.2 million for the Budong-Budong production sharing contract (“Budong PSC”). None of these costs are being amortized.

Depreciation of furniture and fixtures is computed using the straight-line method with depreciation rates based upon the estimated useful life of the property, generally 5 years. Leasehold improvements are depreciated over the life of the applicable lease. Depreciation expense was $0.2 million, $0.4 million and $0.6 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Income Taxes

Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carryforwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. With the formation of Petrodelta, Harvest Vinccler recognized the deferred tax related to the deferred revenue discussed above.

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Financial Instruments

Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. Cash and cash equivalents are placed with commercial banks with high credit ratings. This diversified investment policy limits our exposure both to credit risk and to concentrations of credit risk.

Noncontrolling Interests

We record a noncontrolling interest attributable to the noncontrolling shareholder of Petrodelta. The noncontrolling interest in net income and losses is subtracted or added to arrive at consolidated net income.

New Accounting Pronouncements

In December 2007, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 110 (“SAB 110”) which expresses the views of the staff regarding the use of a “simplified” method, as discussed in SAB No. 107, in developing an estimate of expected term of “plain vanilla” share options in accordance with FAS 123 (revised) – Share Based Payment. The staff will continue to accept, under certain circumstances, the use of the simplified method beyond December 31, 2007. SAB 110 was effective January 1, 2008. SAB 110 will not have a material effect on our consolidated financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (“SFAS Non 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, Business Combinations. SFAS No. 141(R) establishes principles and requirements for how the acquirer recognized and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. SFAS No. (141(R) also recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and determines what information to disclose in the financial statements. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted SFAS No. 141(R) effective January 1, 2009. The adoption of SFAS No. 141(R) did not impact our consolidated financial statements, but may have material impact on our financial statements for businesses we acquire post-adoption.

In December 2007, the FASB issued SFAS 160 – Noncontrolling Interest in Consolidated Financial Statements – an amendment of Accounting Research Bulletin (“ARB”) No. 51 (“SFAS 160”). This new standard requires all entities to report noncontrolling interest in subsidiaries as equity in the consolidated financial statements. SFAS 160 is effective beginning with our first quarter 2009 financial reporting. We adopted SFAS No. 160 effective January 1, 2009. The provisions of SFAS 160 were applied to all non-controlling interests prospectively except for the presentation and disclosure requirements which were applied retrospectively to all periods presented and have been disclosed as such in our consolidated financial statements contained herein. The adoption of SFAS 160 impacted the presentation of our consolidated financial position, results of operations and cash flows.

In March 2008, the Financial Accounting Standards Board (“FASB”) issued FAS 161 – Disclosures about Derivative Instruments and Hedging Activities (“FAS 161”) which changes the disclosure requirements for derivative instruments and hedging activities. FAS 161 is intended to enhance the current disclosure framework in FAS 133 – Accounting for Derivative Instruments and Hedging Activities. FAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. FAS 161 will not have a material effect on our consolidated financial position, results of operations or cash flows.

In May 2008, the Financial Accounting Standards Board (“FASB”) issued FAS 162 – The Hierarchy of Generally Accepted Accounting Principles (“FAS 162”) which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presenting in conformity with GAAP. FAS 162 is effective 60 days following the SEC approval of the Public Company Accounting Oversight Board (“PCAOB”) amendments to AU Section 411, The Meaning of “Present Fairly” in Conformity With Generally Accepted Accounting Principles. The adoption of FAS 162 will not have a material effect on our consolidated financial position, results of operation or cash flows.

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On December 31, 2008, the SEC issued its revised disclosure requirements for oil and gas reserves contained in its Regulation S-K and Regulation S-X under the Securities Act of 1933, the Securities Exchange Act of 1934 and Industry Guide 2. The final rule and interpretation was published in the Federal Register on January 14, 2009 and is effective January 1, 2010. Voluntary early compliance is not permitted. In short, the rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves. We are assessing the effect, if any, the rule will have in future years on our consolidated financial position, results of operation and cash flows. The SEC is discussing the rule with the FASB staff to align FASB accounting standards with the new SEC rules. These discussions may delay the required compliance date. Absent any change in the effective date, we will comply with the disclosure requirements in our Annual Report on Form 10-K for the year ended December 31, 2009.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserve volumes and future development costs. Actual results could differ from those estimates.

Reclassifications

Certain items in 2007 have been reclassified to conform to the 2008 financial statement presentation.

Note 2 — Long-Term Debt and Liquidity

All of our debt has been classified as current (in thousands):


	December 31,		December 31,
	2008		2007
Current portion of note payable with interest at 12.5%	$	—	$	9,302

On November 20, 2006, Harvest Vinccler entered into a three-year term loan with a Venezuelan bank for 120 million Venezuela Bolivars (“Bolivars”) (approximately $55.8 million). The first principal payment was due 180 days after the funding date in the amount of 20 million Bolivars (approximately $9.3 million), and 20 million Bolivars (approximately $9.3 million) every 180 days thereafter. The interest rate for the first 180 days was fixed at 10.0 percent and may be adjusted from time to time thereafter within the limits set forth by the Central Bank of Venezuela or in accordance with the conditions in the financial market. The interest rate was adjusted to 12.5 percent on October 1, 2007. The loan was collateralized by a $6.8 million deposit plus interest in a U.S. bank. The loan was used to meet the SENIAT, the Venezuelan income tax authority, income tax assessments and related interest, refinance a portion of a 105 million Bolivar loan and to fund operating requirements. On July 9, 2008, the loan was repaid in full and the cash collateral returned to us. See Note 13 – Gain on Financing Transactions. We have no other debt obligations.

We have incurred $1.3 million in costs related to negotiation for future financing. If successful, these costs will be amortized over the life of the financial instrument.

Note 3 — Commitments and Contingencies

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

In June 2009, CVP issued instructions to all mixed companies regarding the accounting for deferred tax assets. The mixed companies have been instructed to set up a reserve within the equity section of the balance sheet for deferred tax assets. The setting up of the reserve had no effect on Petrodelta’s financial position, results of operation or cash flows. However, the new reserve could have a negative impact on the amount of dividends received in the future.

We have employment contracts with six executive officers which provide for annual base salaries, eligibility for bonus compensation and various benefits. The contracts provide for a lump sum payment as a multiple of base salary in the event of termination of employment without cause. In addition, these contracts provide for payments as a multiple of base salary and bonus, excise tax reimbursement and a continuation of benefits in the event of termination without cause following a change in control. By providing one year notice, these agreements may be terminated by either party on or after May 31, 2009.

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In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month. In December 2008, we signed a five-year lease for additional office space in Houston, Texas, for approximately $15,000 per month. In November 2008, Harvest Vinccler extended its lease for office space in Caracas, Venezuela for two years for approximately $8,000 per month. In August 2008, we signed a two-year lease in Roosevelt, Utah for approximately $6,000 per month. In October 2008, we signed a two-year lease for office space in Singapore for approximately $18,000 per month.

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

Uracoa Municipality Tax Assessments. 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 PDVSA under the OSA. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims.

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

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

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

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

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

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

	•		Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay

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			taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.

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

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

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

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

Note 4 — Taxes

Taxes Other Than on Income

The components of taxes other than on income were (in thousands):


	2008			2007		2006
Venezuelan municipal taxes	$	—		$	—	$	3,191
Franchise taxes		(951	)		166		175
Payroll and other taxes		745			257		582

	$	(206	)	$	423	$	3,948

During the year ended December 31, 2008, we reversed a $1.1 million franchise tax provision that is no longer required.

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Contribution to Science and Technology Fund

In 2005, Venezuela modified the Science and Technology Law 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. In October 2006, the Executive Branch issued the Regulations for the Science and Technology Law which established the methodology for determining the required investment, contribution or expenditure for the 2005 calendar year financial results. Harvest Vinccler was unable to estimate the corresponding percentage of the gross revenue for 2005 or the first quarter of 2006 until the regulations were released as many aspects of the law were unclear. After release of the regulations, Harvest Vinccler accrued $3.9 million for the estimated liability for 2005 and the first quarter of 2006 based on its current understanding of the regulations. Harvest Vinccler did not have any gross revenue subject to this law after March 31, 2006. The regulation provides that the amount that is not invested, contributed or spent must be deposited with an official agency created to administrate the law which has yet to be formed. This liability was paid in the first quarter of 2008.

Taxes on Income

The tax effects of significant items comprising our net deferred income taxes as of December 31, 2008, are as follows (in thousands):


	2008
Deferred tax assets:
Operating loss carryforwards	$	7,547
Dry hole costs		4,060
Stock options		1,680
Valuation allowance		(7,841	)

Net deferred tax asset		5,446

Deferred tax liability:
Tax on undistributed earnings		(5,446	)

Net deferred tax asset (liability)	$	—

We currently have undistributed earnings from foreign affiliates of $40.0 million at our Netherlands Antilles subsidiary, HNR Energia B.V. Of that amount, $15.5 million would be subject to United States income tax if distributed to us. We have provided for income tax on the undistributed earnings; however, as a result of our deferred tax assets, the recording of the income tax did not have an impact on our earnings.

The valuation allowance increased by $7.8 million as a result of additional net operating losses and tax benefits that we do not expect to fully realize through future taxable income. Realization of deferred tax assets associated with net operating loss carryforwards is dependent upon generating sufficient taxable income prior to their expiration.

The components of income before income taxes are as follows (in thousands):


	2008			2007			2006
Income (loss) before income taxes
United States	$	(34,760	)	$	(17,786	)	$	(15,688	)
Foreign		(14,326	)		48,700			2,391

Total	$	(49,086	)	$	30,914		$	(13,297	)

The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):


	2008			2007		2006
Current:
United States	$	(128	)	$	400	$	—
Foreign		153			5,912		63,473

		25			6,312		63,473
Deferred:
Foreign		—			—		(2,556	)

	$	25		$	6,312	$	60,917

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A comparison of the income tax expense (benefit) at the federal statutory rate to our provision for income taxes is as follows (in thousands):


	2008			2007			2006
Computed tax expense (benefit) at the statutory rate	$	(17,180	)	$	10,820		$	(2,930	)
Effect of foreign source income and rate differentials on foreign income		5,167			(11,140	)		8,563
Change in valuation allowance		6,059			1,085			5,446
Tax on undistributed earnings		5,446			—			—
Deemed income inclusion under Subpart F		968			12,942			—
Venezuela tax settlement		—			—			49,793
Net operating loss utilization		—			(7,306	)		—
Foreign disregarded entities		(268	)		—			—
Return to accrual adjustment		(166	)		—			—
Other		(1	)		(89	)		45

Total income tax expense	$	25		$	6,312		$	60,917

Rate differentials for foreign income result from tax rates different from the U.S. tax rate being applied in foreign jurisdictions.

At December 31, 2008, we had, for federal income tax purposes, operating loss carryforwards of approximately $21.5 million, expiring in the years 2026 through 2028.

FIN 48 Disclosure

Effective January 1, 2007, we adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of SFAS 109, Accounting for Income Taxes (“FIN 48”), to create a single model to address accounting for uncertainty in tax positions. FIN 48 clarifies the accounting for income taxes, by prescribing a minimum recognition threshold a tax position is required to meet before being recognized in the financial statements.

We or one of our subsidiaries files income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2005. To date, the Internal Revenue Service (“IRS”) has not performed an examination of our U.S. income tax returns for 2005 through 2007.

The adoption of FIN 48 has not had a significant impact on our consolidated financial position, results of operations or cash flows. We do not have any unrecognized tax benefits.

Note 5 — Stock Option and Stock Purchase Plans

In May 2006, our shareholders approved the 2006 Long Term Incentive Plan (the “2006 Plan”). The 2006 Plan provides for the issuance of up to 1,825,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to eligible participants including employees, non-employee directors and consultants of our company or subsidiaries. Under the 2006 Plan, no more than 325,000 shares may be granted as restricted stock. No individual may be granted more than 900,000 options or SARs and no more than 175,000 shares of restricted stock during any period of three consecutive calendar years. The exercise price of stock options granted under the 2006 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted through December 31, 2006 vest ratably over a three to five year period from their dates of grant and expire seven to ten years from grant date. Restricted stock granted to employees or consultants to date is subject to a restriction period of not less than 36 months during which the stock will be deposited with Harvest and is subject to forfeiture under certain circumstances. Restricted stock granted to non-

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employee directors vests as to one-third of the shares on each anniversary of the date of grant of the award provided that he is still a director on that date. The 2006 Plan also permits the granting of performance awards to eligible employees and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time of at least one year. No employee or consultant shall be granted a performance award during a calendar year that could result in a cash payment of more than $5.0 million. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become exercisable.

In May 2004, our shareholders approved the 2004 Long Term Incentive Plan (the “2004 Plan”). The 2004 Plan provides for the issuance of up to 1,750,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to eligible participants including employees, non-employee directors and consultants of our company or subsidiaries. Under the 2004 Plan, no more than 438,000 shares may be granted as restricted stock, and no individual may be granted more than 110,000 shares of restricted stock or 438,000 in options over the life of the Plan. The exercise price of stock options granted under the 2004 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date. All restricted stock granted to date is subject to a restriction period of 36 months during which the stock will be deposited with Harvest and is subject to forfeiture under certain circumstances. The 2004 Plan also permits the granting of performance awards to eligible employees and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time of at least one year. Performance awards granted under the Plan may not exceed $5.0 million in a calendar year and may not exceed $2.5 million to any one individual in a calendar year. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become exercisable.

In July 2001, our shareholders approved the 2001 Long Term Stock Incentive Plan (the “2001 Plan”). The 2001 Plan provides for grants of options to purchase up to 1,697,000 shares of our common stock in the form of Incentive Stock Options and Non-Qualified Stock Options to eligible participants including employees of our company or subsidiaries, directors, consultants and other key persons. The exercise price of stock options granted under the 2001 Plan must be no less than the fair market value of our common stock on the date of grant. No officer may be granted more than 500,000 options during any one fiscal year, as adjusted for any changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date.

Since 1989 we have adopted several other stock option plans under which options to purchase shares of our common stock have been granted to employees, officers, directors, independent contractors and consultants. Options granted under these plans have been at prices equal to the fair market value of the stock on the grant dates. Options granted under the plans are generally exercisable in varying cumulative periodic installments after one year and cannot be exercised more than ten years after the grant dates. Following the adoption of the 2001 Plan, no options may be granted under any of these plans.

A summary of the status of our stock option plans as of December 31, 2008, 2007 and 2006 and changes during the years ending on those dates is presented below (shares in thousands):


	2008						2007						2006
	Weighted						Weighted						Weighted
	Average						Average						Average
	Exercise						Exercise						Exercise
	Price			Shares			Price			Shares			Price			Shares
Outstanding at beginning of the year:	$	7.80			4,172		$	7.70			4,123		$	8.61			4,070
Options granted		10.28			444			9.63			866			10.62			558
Options exercised		(2.86	)		(548	)		(4.73	)		(397	)		(5.69	)		(65	)
Options cancelled		(11.34	)		(285	)		(13.49	)		(420	)		(19.96	)		(440	)

Outstanding at end of the year		8.54			3,783			7.80			4,172			7.70			4,123

Exercisable at end of the year		7.23			2,147			5.87			2,372			5.91			2,719

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Significant option groups outstanding at December 31, 2008 and related weighted average price and life information follow (shares in thousands):


	Outstanding								Exercisable
			Weighted-
			Average		Weighted						Weighted-
Range of	Number		Remaining		Average		Aggregate		Number		Average		Aggregate
Exercise	Outstanding		Contractual		Exercise		Intrinsic		Exercisable		Exercise		Intrinsic
Prices	at 12/31/08		Life		Price		Value		at 12/31/08		Price		Value
$1.55 - $2.75		844		1.4	$	2.11	$	1,846		844	$	2.11	$	1,846
$4.86 - $7.10		176		3.7		5.74		—		176		5.74		—
$8.72 - $10.91		2,177		6.8		10.03		—		602		9.69		—
$12.50 - $13.90		586		5.9		13.13		—		525		13.12		—

		3,783					$	1,846		2,147			$	1,846

The aggregate intrinsic value in the preceding table represents the total pretax intrinsic value based on our closing stock price of $4.30 of December 31, 2008, which would have been received by the option holders had all option holders exercised their options as of that date. Of the number outstanding, 318,750 options are pledged to us to secure a repayment of debt.

The value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions:


For options granted during:	2008			2007			2006
Weighted average fair value	$	5.85		$	4.67		$	5.98
Weighted averaged expected life		7			7			7
Valuation assumptions:
Expected volatility		46.6-49.7	%		47.7-48.7	%		49.9%-53.3	%
Risk-free interest rate		3.0-3.9	%		4.5%-4.6	%		4.6%-5.2	%
Expected dividend yield		0	%		0	%		0	%
Expected annual forfeitures		3	%		3	%		3	%

The Black-Scholes option pricing model was developed for use in estimating the value of traded options that have no vesting restrictions and are fully transferable. In addition, option pricing models require the input of highly subjective assumptions, including the expected stock price volatility and expected life. The expected volatility is based on historical volatilities of our stock. Historical data is used to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options are expected to be outstanding. The risk-free rate for the periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant.

A summary of our nonvested options as of December 31, 2008, and changes during the year ended December 31, 2008, is presented below (shares in thousands):


				Weighted-Average
				Grant-Date
Nonvested Shares	Shares			Fair Value
Nonvested at January 1, 2008		1,850		$	5.83
Granted		754			5.85
Vested		(624	)		(5.87	)
Forfeited		(1	)		(5.62	)

Nonvested at December 31, 2008		1,979		$	5.80

As of December 31, 2008, there was $5.8 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under our plans. That cost is expected to be recognized

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over the next three to five years. The total fair value of shares vested during the years ended December 31, 2008, 2007 and 2006 was $4.0 million, $4.5 million and $4.1 million, respectively.

In addition to options issued pursuant to the plans, options have been issued to new hire employees as employment inducement grants under a New York Stock Exchange (“NYSE”) exception. These options were granted in 2007 and 2008 between $10.07 and $12.63 and vest over three years. At December 31, 2008, a total of 360,000 options issued outside of the plans were outstanding and 16,667 options were exercisable.

Stock options of 0.5 million were exercised in the year ended December 31, 2008 resulting in cash proceeds of $1.6 million. Stock options of 0.4 million were exercised in the year ended December 31, 2007, resulting in cash proceeds of $1.9 million.

Treasury Stock Buy-Back Program

In June 2007, we announced that our Board of Directors had authorized the purchase of up to $50 million of our common stock from time to time through open market transactions. This repurchase program was completed in June 2008. Under this program, we repurchased 4.6 million shares at an average cost of $10.93 per share, including commissions. In July 2008, our Board of Directors authorized the purchase of up to $20 million of our common stock from time to time through open market transactions. We continue to believe that Harvest stock remains undervalued and that the investment in the shares of our Company represents an attractive alternative to holding cash in excess of our needs. As of December 31, 2008, 1.2 million shares of stock have been purchased at an average cost of $10.17 per share for a total cost of $12.2 million of the $20 million authorization. Federal securities laws and the New York Stock Exchange (“NYSE”) regulate the use of public disclosure of corporate inside information. These laws, rules and regulations require that we ensure information about Harvest is not used unlawfully in connection with the purchase and sale of securities. Pursuant to these laws, we are prohibited from purchasing stock while in possession of material non-public information.

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. The results of operations and economic benefits of our noncontrolling equity investment in Petrodelta from April 1, 2006 through December 31, 2007 were recorded in the three months ended December 31, 2007 as Net Income from Unconsolidated Equity Affiliates. See Note 7 – Investment in Equity Affiliates, Petrodelta S.A. Oil and gas sales for 2007 is the recognition of the deferred revenue recorded by Harvest Vinccler for 2005 and first quarter 2006 deliveries pending clarification on the calculation of crude prices under the Transitory Agreement (see Note 1 – Organization and Summary of Significant Accounting Policies, Revenue Recognition). 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.


				2007
	2008			(restated)			2006
				(in thousands)
Segment Revenues
Oil and gas sales:
Venezuela	$	—		$	11,217		$	59,506

Total oil and gas sales		—			11,217			59,506

Segment Income (Loss)
Venezuela		33,020			79,878			(46,835	)
Indonesia		(8,966	)		(7	)		—
United States and other		(45,518	)		(19,753	)		(15,667	)

Net income (loss) attributable to Harvest	$	(21,464	)	$	60,118		$	(62,502	)

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				December 31,
	December 31,			2007
	2008			(restated)
	(in thousands)
Operating Segment Assets
Venezuela	$	231,755		$	306,644
Indonesia		1,556			26
United States and other		152,184			126,747

		385,495			433,417
Intersegment eliminations		(23,229	)		(16,346	)

	$	362,266		$	417,071

Note 7 — Investment in Equity Affiliates

Petrodelta, S.A.

On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract was published in the Official Gazette. Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from that date. Petrodelta has undertaken its operations in accordance with the Business Plan as set forth in the Conversion Contract (“Business Plan”). Under the Conversion Contract, work programs and annual budgets adopted by Petrodelta must be consistent with the Business Plan. The Business Plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. The 2009 budget for Petrodelta’s Business Plan has not yet been approved by its shareholders.

Petrodelta adopted policies and procedures governing its operations, including, among others, policies and procedures for safety, health and environment, contracting, maintenance of insurance, accounting, banking and treasury and human resources, following the guidelines established by CVP. To the extent possible, such policies and procedures are consistent with the policies and procedures of PDVSA and the ultimate parent company of HNR Finance.

Petrodelta is governed by a board of directors in accordance with the Charter and Bylaws of Petrodelta as set forth in the Conversion Contract (“Charter and Bylaws”). Under the Charter and Bylaws, matters requiring shareholder approval may be approved by a simple majority with the exception of certain specified matters which require the approval by the holders of at least 75 percent of the capital stock. These matters include: most changes to the Charter and Bylaws; changes in the capital stock of Petrodelta that would alter the percentage participation of HNR Finance or CVP; any liquidation or dissolution of Petrodelta; any merger, consolidation or business combination of Petrodelta; disposition of all or any substantial part of the assets of Petrodelta, except in the ordinary course of business; any financing agreement for an amount greater than $10 million; approval or modification of Petrodelta’s financial statements; creation of certain reserve funds; any distribution of dividends or return of paid-in surplus; changes to the policy regarding dividends and other distributions established by the Charter and Bylaws; changes to the Business Plan; changes to the Contract for Sale and Purchase of Hydrocarbons with PDVSA Petroleo S.A. (“PPSA”), a 100 percent owned subsidiary of PDVSA; contracts with shareholders or affiliates that are not at market price; any social investment in excess of the amount required by the Venezuelan government; any waiver of material rights or actions with respect to litigation involving more than $1 million; selection of external auditors; appointment of any judicial representative or general agent of Petrodelta; and designation of a liquidator in the event of the liquidation of Petrodelta.

Petrodelta’s board of directors consists of five directors, three of whom are appointed by CVP, including the President of the Board, and two of whom are appointed by HNR Finance. Decisions of the board of directors are taken by the favorable vote of at least three of its members, except in the case of any decision implementing a decision of the Shareholders’ Meeting relating to any of the matters where a qualified majority is required, in which case, a favorable vote of four members will be required. The board of directors has broad powers of administration and disposition expressly granted in the Charter and Bylaws. The powers include: proposing budget and work programs; presenting the annual report to the shareholders; appointing and dismissing personnel; making

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recommendations regarding financial reserves and utilization of surplus; making proposals on dividends consistent with the Charter and Bylaws; agreeing on contracts consistent with the work programs and budgets; opening and closing bank accounts; making, accepting, endorsing and guaranteeing bank drafts and other commercial instruments consistent with work programs and budgets; and implementing policies and procedures.

The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PPSA signed on January 17, 2008. The form of the agreement is set forth in the Conversion Contract. Crude oil delivered from the Petrodelta Fields to PPSA 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. Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make payment to Petrodelta of each invoice within 60 days of the end of the invoiced production month by wire transfer, in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered, and in Bolivars in the case of payment for natural gas delivered, in immediately available funds to the bank accounts designated by Petrodelta. Any dividend paid by Petrodelta will be made in U.S. Dollars.

The Conversion Contract and related documents state that Petrodelta will issue invoices monthly to PPSA for hydrocarbon sales, and payment is due from PPSA within 30 days of invoicing. Petrodelta invoiced PPSA for 2006 and 2007 hydrocarbon sales, but PPSA has not made payment against the invoices. The Conversion Contract and related documents also state that PDVSA is to submit invoices to Petrodelta for services and materials rendered to Petrodelta. PDVSA has not been issuing invoices. Since Petrodelta has not received payments from PPSA on the hydrocarbon sales invoices issued for 2006 and 2007, in April 2008, Petrodelta began accruing interest on late payment of invoices under the Conversion Contract provisions. PDVSA has been netting revenues and expenses and advancing funds to Petrodelta sufficient to pay Petrodelta’s operating expenses, capital expenditures and dividends distribution requirements according to financial statements. It is our understanding that PDVSA considers all 2006 and 2007 receivables and payables settled with the payment of the dividend in May 2008. On December 11, 2008, Petrodelta’s Board approved a resolution to settle the 2006 and 2007 hydrocarbon invoices against the account payable to PDVSA for 2006 and 2007 cash advances and the dividend received in May 2008. On January 22, 2009, CVP notified all mixed companies, including Petrodelta, that they must net the outstanding accounts payable balance with PDVSA and CVP against the revenues due from PPSA. The mixed companies were also notified that interest accrued on late payment of invoices would not be recognized or paid. Petrodelta’s December 31, 2008 balance sheet reflects the results of the netting of accounts receivable and accounts payable, and the interest income accrued on late payment of invoices for 2006, 2007 and 2008 has been reversed in its results of operations for the year ended December 31, 2008.

In May 2008, Petrodelta declared and paid a dividend of $181 million, $72.5 million net to HNR Finance ($58.0 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the period of April 1, 2006 through December 31, 2007. In October 2008, Petrodelta paid an advance dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the six months ended June 30, 2008. Until Petrodelta’s board of directors declares a dividend for the year ended December 31, 2008, there is a possibility that all or a portion of the advance dividend could be rescinded; therefore, the advance dividend is reflected as a current liability on the consolidated balance sheets at December 31, 2008.

On April 15, 2008, the Venezuelan government published in the Official Gazette the Law of Special Contribution to Extraordinary Prices at the Hydrocarbons International Market (“original Windfall Profits Tax”). The original Windfall Profits Tax was based on prices for Brent crude, and, as instructed by CVP, Petrodelta applied the original Windfall Profits Tax to net production after deduction for royalty barrels. On July 10, 2008, the Venezuelan government published an amendment to the Windfall Profits Tax (“amended Windfall Profits Tax”) 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”). The amended Windfall Profits Tax was made retroactive to April 15, 2008, the date of the original Windfall Profits Tax. As instructed by CVP, Petrodelta has applied the amended Windfall Profits Tax to gross oil production delivered to PDVSA since April 15, 2008 when the tax was enacted.

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The amended 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 amended Windfall Profits Tax is reported as expense on the income statement and is deductible for Venezuelan tax purposes. Petrodelta recorded for the year ended December 31, 2008 $56.4 million for the amended Windfall Profits Tax.

In 2005, Venezuela modified the Science and Technology Law (referred to as “LOCTI” in Venezuela) to require companies doing business in Venezuela to invest, contribute, or spend a percentage of their gross revenue on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. LOCTI requires major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law to contribute two percent of their gross revenue generated in Venezuela from activities specified in the Law. The contribution is based on the previous year’s gross revenue and is due the following year. Based on legal advice from CVP, Petrodelta management concluded that for 2006 Petrodelta was not a legal entity and therefore did not generate any gross revenue subject to LOCTI. Based on this opinion, Petrodelta did not accrue a liability in 2007 under LOCTI. During 2008, Petrodelta accrued $12.4 million, $6.2 million net of tax, ($2.0 million net to our 32 percent interest) for contributions to LOCTI. On January 22, 2009, CVP notified all mixed companies, including Petrodelta, that PDVSA would be filing a consolidated declaration to LOCTI on the position that PDVSA had incurred sufficient qualifying expenses to cover all of its and its consolidating entities liability. The mixed companies were instructed to reverse any accrued contributions for LOCTI based on PDVSA’s filing position. Based on this notice from CVP, in December 2008, Petrodelta reversed the $12.4 million accrual to LOCTI.

The notice from CVP was supported by communication from the LOCTI regulator dated March 2008 which provided a waiver to PDVSA to submit a consolidated return, comprising PDVSA and all its subsidiaries, for the 2007 contributions. Per this communication, however, the waiver was only applicable to companies that did not file separate tax returns. We have received confirmation from CVP that LOCTI has again issued a waiver to PDVSA to submit a consolidated return for the 2008 contributions. Based on past history, we believe that the likelihood is remote that PDVSA will have to pay LOCTI in excess of internally generated science and tax credits on Petrodelta’s behalf. However, since Petrodelta files a separate tax return, until the final communication from LOCTI is received for the 2008 contributions (which is expected in late March 2009), there is a risk that the waiver will not include Petrodelta, and LOCTI could issue a claim against Petrodelta for failure to remit its contribution.

Due to the recent precipitous drop in crude oil prices, our noncontrolling equity investment in Petrodelta was reviewed for impairment under APB 18. In performing this review, future net cash flows were determined based on estimated future oil and gas sales revenue less future expenditures necessary to develop and produce the reserves. Based on this review, there was no impairment to the carrying value of our noncontrolling equity investment in Petrodelta.

HNR Finance owns a 40 percent interest in Petrodelta and recorded its share of the earnings of Petrodelta from April 1, 2006 to December 31, 2007 in the three months ended December 31, 2007. The year ended December 31, 2008 includes net income from unconsolidated equity affiliates for Petrodelta on a current basis. Petrodelta’s financial information is prepared in accordance with IFRS which we have adjusted to conform to GAAP. All amounts through Net Income Equity Affiliate represent 100 percent of Petrodelta. Summary financial information has been presented below at December 31, 2008 and 2007, and for the years ended December 31, 2008 and 2007 (in thousands, except per unit information):

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				Year Ended			Nine Months
	Year Ended			December 31,			Ended
	December 31,			2007			December 31,
	2008			(restated)			2006
Barrels of oil sold		5,505			5,374			5,211
MCF of gas sold		10,700			13,456			11,519
Total Boe		7,288			7,616			7,131

Average price per barrel	$	83.22		$	58.61		$	50.98
Average price per mcf	$	1.54		$	1.54		$	1.54

Revenues:
Oil sales	$	458,113		$	314,928		$	265,625
Gas sales		16,506			20,789			17,796
Royalty		(168,790	)		(114,847	)		(96,790	)

		305,829			220,870			186,631

Expenses:
Operating expenses		52,946			21,352			22,729
Workovers		24,663			2,400			—
Depletion, depreciation and amortization		25,509			18,549			17,076
General and administrative		5,974			19,880			11,093
Windfall profits tax		56,377			—			—
Taxes other than on income		—			2,747			2,029

		165,469			64,928			52,927


Income from Operations		140,360			155,942			133,704
Interest expense		(2,329	)		—			—

Income before Income Tax		138,031			155,942			133,704

Current income tax expense		69,374			85,849			67,188
Deferred income tax benefit		(52,560	)		(21,348	)		(23,415	)

Net Income		121,217			91,441			89,931
Adjustment to reconcile to reported Net Income from Unconsolidated Equity Affiliate:
Deferred income tax benefit		34,827			12,343			23,415

Net Income Equity Affiliate		86,390			79,098			66,516
Equity interest in unconsolidated equity affiliate		40	%		40	%		40	%

Income before amortization of excess basis in equity affiliate		34,556			31,639			26,606
Amortization of excess basis in equity affiliate		(1,155	)		(2,530	)		—
Conform depletion expense to GAAP		2,533			—			—

Net income from unconsolidated equity affiliate	$	35,934		$	29,109		$	26,606


	December 31,		December 31,
	2008		2007
Current assets	$	311,017	$	464,904
Property and equipment		211,760		190,613
Other assets		97,323		38,738
Current liabilities		260,234		287,491
Other liabilities		19,174		5,964
Net equity		340,692		400,800

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Fusion Geophysical, LLC (“Fusion”)

Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering. The purchase of Fusion extends our technical ability and global reach to support a more organic growth and exploration strategy. Our 49 percent noncontrolling equity investment in Fusion is accounted for using the equity method of accounting. In October 2008, we increased our noncontrolling equity investment in Fusion from 45 percent to 49 percent for $2.2 million. Operating revenue and total assets represent 100 percent of Fusion. No dividends were declared or paid during the years ended December 31, 2008 and 2007, respectively. Summarized financial information for Fusion follows:


	Year Ended			Year Ended
	December 31,			December, 31
	2008			2007
	(in thousands)
Operating Revenues	$	13,063		$	7,392


Net Income (Loss)	$	(1,290	)	$	527
Equity interest in unconsolidated equity affiliate		49	%		45	%

Net income (loss) from unconsolidated equity affiliate		(632	)		237
Amortization of fair value of intangibles		(726	)		(656	)

Net loss from unconsolidated equity affiliate	$	(1,358	)	$	(419	)


	December 31,		December, 31
	2008		2007
Current assets	$	7,864	$	3,995
Total assets		30,633		14,846
Current liabilities		7,294		2,100
Total liabilities		8,281		2,100

Approximately 26 percent and seven percent of Fusion’s revenue for the years ended December 31, 2008 and 2007, respectively, was earned from Harvest or equity affiliates.

Note 8 — China Operations

In December 1996, we acquired Crestone Energy Corporation, subsequently renamed Benton Offshore China Company. Its principal asset is a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under certain circumstances, and lies within an area which is the subject of a border dispute between the People’s Republic of China (“China”) and Socialist Republic of Vietnam (“Vietnam”). Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The border dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the dispute. Due to the border dispute between China and Vietnam, we have been unable to pursue an exploration program during Phase One of the contract. As a result, we have obtained license extensions, with the current extension in effect until May 31, 2009. We are in the process of scheduling a meeting with CNOOC for March 2009 to discuss another extension for our license. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist. WAB-21 represents $3.0 million of oil and gas properties on our December 31, 2008 balance sheet.

Note 9 — United States Operations

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

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Gulf Coast

In March 2008, we executed an AMI agreement with a private third party for an area in the upper Gulf Coast Region of the United States. We are the operator and have an initial working interest of 55 percent in the AMI. The AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana, including state waters. The private third party contributed two prospects, including the leases and proprietary 3-D seismic data sets, and numerous leads generated over the last three decades of regional geological focus. We will fund the first $20 million of new lease acquisitions, geological and geophysical studies, seismic reprocessing and drilling costs. All subsequent costs will be shared pursuant to the terms of the AMI. The parties focused on two initial prospects for evaluation and completed essentially all leasing of each prospect area during 2008. The other party is obligated to evaluate and present additional opportunities at their sole cost. As each prospect is accepted it will be covered by the AMI. At year end 2008, we have met $16.4 million of the total $20 million funding obligation under the terms of the AMI. After the remainder of the $20 million funding obligation is met, all subsequent costs will be shared by the parties in proportion to their working interests as defined in the AMI agreement.

In July 2008, we and our partners in the AMI acquired 6,510 acres of state leases representing all or part of 12 separate tracts from the State of Texas General Land Office for $2.7 million. This lease acquisition completes planned lease acquisition in the area and covers the West Bay prospect, which is the second exploratory prospect in the AMI. During the year ended December 31, 2008, operational activities in the West Bay prospect included re-processing of 3-D seismic, site surveying, and preparation of preliminary engineering documents. On December 8, 2008, we submitted an Application to Install Structures to Drill and Produce Oil and Gas with the U. S. Army Corps of Engineers — Galveston District (“Corps of Engineers”). At December 31, 2008, the permit application was under review by the Corps of Engineers. Drilling is expected to commence upon receipt of the requisite permit from the Corps of Engineers, which we expect to obtain in late 2009 or early 2010. During the year ended December 31, 2008, we incurred $5.4 million for land acquisition seismic, surveying and permitting.

In September 2008, we spud an exploratory well on the Starks prospect, the first prospect in the Gulf Coast AMI, in Calcasieu Parish, Louisiana. The Harvest Hunter #1 well was drilled to a depth of 12,290 feet and three prospective reservoir horizons were tested. On January 9, 2009, the well was determined to not have commercial quantities of hydrocarbons and was plugged and abandoned. Through December 31, 2008, $10.8 million was expended for drilling of the well which was written off to dry hole costs as of December 31, 2008.

Western United States — Antelope

In October 2007, we entered into a JEDA with a private party to pursue a lease acquisition program and drilling program on the Antelope project in the Western United States. We are the operator and have a working interest of 50 percent in the project. The other party is obligated to assemble the lease position on the project. We will earn our 50 percent working interest in the project by compensating the other party for leases acquired in accordance with terms defined in the JEDA, and by drilling one deep natural gas test well at our sole expense. In November 2008, we entered into a Letter Agreement/Amendment of the JEDA (the “Letter Agreement”) with the private party. The Letter Agreement clarifies several open issues in the JEDA, such as classification of $2.7 million of prepaid land costs for the Antelope project as a note receivable, addition of a requirement for the private party to partially assign leases to us prior to meeting the lease earning obligation, and clarification of the parties’ cost obligations for any shallow wells to be drilled on the project prior to the initial deep test well.

The Antelope project is targeted to explore for and develop oil and natural gas from multiple reservoir horizons in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties. Leads and/or prospects have been identified in three prospective reservoir horizons in preparation for anticipated drilling of one or more prospects in 2009. Operational activities during 2008 on the Antelope project were focused primarily on leasing. Leases acquired during 2008 include fee leases from private landowners, as well as leases obtained from Allottees of the Ute Indian Tribe. The Allottee leases are administered by the Bureau of Indian Affairs Fort Duchesne, Utah office. In addition to leasing activities, other operational activities during 2008 were focused on preparations for anticipated drilling in 2009. We opened a small field office and hired two employees in Roosevelt, Utah in September 2008 to support field activities. Other activities included surveying, preliminary engineering, and preparations for permitting. In December 2008, we filed Applications for Permits to Drill eight shallow oil wells with the State of Utah Department of Natural Resources Division of Oil, Gas and Mining. The permit applications

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were still being processed as of February 25, 2009. The cost of the eight shallow oil wells will be borne 50 percent by us and 50 percent by the other party participating in the project. Drilling of the shallow oil wells will not materially contribute to meeting our lease earning obligation under the JEDA. Through December 31, 2008, we incurred $8.4 million for lease acquisition and permitting.

Note 10 — Indonesia

In February 2008, Indonesia’s oil and gas regulatory authority, BP Migas, approved the assignment to us of a 47 percent interest in the Budong-Budong production sharing contract (“Budong PSC”) located mainly onshore West Sulawesi, Indonesia. Final government approval from the Ministry of Energy and Mineral Resources, Migas, was received in April 2008. We acquired our 47 percent interest in the Budong PSC by committing to fund the first phase of the exploration program including the acquisition of 2-D seismic and drilling of the first two exploration wells. This commitment is capped at $17.2 million. Prior to drilling the first exploration well, subject to the estimated cost of that well, our partner will have a one-time option to increase the level of the carried interest to $20.0 million, and as compensation for the increase, we will increase our participation to a maximum of 54.65 percent. This equates to a total carried cost for the farm-in of $9.1 million. Our partner will be the operator through the exploration phase as required by the terms of the Budong PSC. We will have control of major decisions and financing for the project with an option to become operator if approved by BP Migas in the subsequent development and production phase.

The Budong PSC includes a ten-year exploration period and a 20-year development phase. During the initial three-year exploration phase, which began January 2007, we plan to acquire, process and interpret 2-D seismic and drill two exploration wells. In November 2008, we opened a small field office in Jakarta, Indonesia and hired four employees to support field activities. In December 2008, the acquisition program of 650 kilometers of 2-D seismic was completed. The data is currently being processed. Interpretation of the data and well planning will take place in the first quarter of 2009. It is expected that the first of two exploration wells will spud in the second half of 2009. During the year ended December 31, 2008, we incurred $7.7 million including the carry obligation for the 2-D seismic acquisition and other costs.

Note 11 — Gabon

In April 2008, we completed the purchase of a 50 percent interest in the production sharing contract related to the Dussafu Marin Permit offshore Gabon in West Africa (“Dussafu PSC’) for $4.5 million. In September 2008, we completed the purchase of an additional 16.667 percent interest in the Dussafu PSC for $1.5 million. This acquisition brings our total interest in the Dussafu PSC to 66.667 percent. We are the operator of the Dussafu PSC. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC contains 680,000 acres with water depths up to 1,000 feet. The Dussafu PSC has two small oil discoveries in the Gamba and Dentale reservoirs and a small natural gas discovery. Production and infrastructure exists in the blocks contiguous to the Dussafu PSC.

The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources (“Republic of Gabon”), entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. The second exploration phase comprises a three-year work commitment which includes the acquisition and processing of 500 kilometers of 2-D seismic, geology and geophysical interpretation, engineering studies and the drilling of a conditional well. In October 2008, the acquisition of 650 kilometers of 2-D seismic was completed which is now being processed to define the syn-rift potential similar to the Lucina and M’Baya fields. In addition, during the three months ended December 31, 2008, we commenced the reprocessing of 1,076 square kilometers of existing 3-D seismic to define the sub-salt structure to unlock the potential of the Gamba play that is producing in the Etame field to the north. We expect the seismic to mature the prospect inventory to make a decision in 2009 for a well in 2010. During the year ended December 31, 2008, we incurred $8.8 million for acreage acquisition and exploration activity.

Note 12 — Earnings Per Share

Basic earnings per common share (“EPS”) are computed by dividing net income attributable to Harvest by the weighted-average number of common shares outstanding for the period. The weighted average number of

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common shares outstanding for computing basic EPS was 34.1 million, 36.5 million and 37.2 million for the years ended December 31, 2008, 2007 and 2006, respectively. Diluted EPS reflects the potential dilution that could 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 34.1 million, 37.9 million and 37.2 million for the years ended December 31, 2008, 2007 and 2006, respectively.

An aggregate of 1.7 million options were excluded from the earnings per share calculations because their exercise price exceeded the average price for the year ended December 31, 2008. For the years ended December 31, 2007 and 2006, 1.1 million and 1.5 million options, respectively, were excluded from the earnings per share calculations because their exercise price exceeded the average price.

Note 13 — Gain on Financing Transaction

During the years ended December 31, 2008 and 2007, Harvest Vinccler entered into security exchange transactions to effectively convert U.S. Dollars to Bolivars as Harvest Vinccler has no source for Bolivars. In these exchange transactions, one of Harvest’s affiliates purchased U.S. government securities and exchanged them for U.S. Dollar indexed debt issued by the Venezuelan government. The U.S. Dollar indexed Venezuelan government securities can only be traded in Venezuela for Bolivars (“Southern Bonds” or “TICC’s”). The exchanges were transacted through an intermediary at the securities transaction rate of Bolivars to U.S. Dollars. Harvest Vinccler at the same time purchased a like amount of U.S. government securities and exchanged those securities with the intermediary for the TICCs. Harvest Vinccler converted the TICCs to Bolivars at a local bank at the official exchange rate of 2.15 Bolivars to one U.S. Dollar and used the Bolivars for operating expenses and to settle 10 million Bolivars (approximately $4.6 million) of its Bolivar denominated debt. During the year ended December 31, 2008, these security exchanges resulted in a gain on financing transactions of $3.4 million. During the year ended December 31, 2007, these security exchanges resulted in a gain on financing transactions of $49.6 million.

Note 14 — Related Party Transactions

In August 1997, we entered into a consulting agreement with Oil & Gas Technology Consultants Inc. (“OGTC”) to provide operational and technical assistance in Venezuela. OGTC is an affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A., which indirectly owns 20 percent of Petrodelta. The consulting agreement was cancelled January 1, 2004. On July 18, 2008, the account payable, related party was repaid in full.

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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

Quarterly Financial Data (unaudited)

Summarized quarterly financial data is as follows:


	Quarter Ended
	March 31			June 30			September 30
	(restated)			(restated)			(restated)			December 31
	(amounts in thousands, except per share data)
Year ended December 31, 2008
Expenses	$	(7,869	)	$	(9,530	)	$	(10,621	)	$	(26,420	)
Non-operating income		2,002			1,582			1,100			670

Loss before income taxes		(5,867	)		(7,948	)		(9,521	)		(25,750	)
Income tax expense (benefit)		64			37			(20	)		(56	)

Loss from consolidated companies		(5,931	)		(7,985	)		(9,501	)		(25,694	)
Net income from unconsolidated equity affiliates		8,809			9,409			5,309			11,049

Net income (loss)		2,878			1,424			(4,192	)		(14,645	)
Less: Net income attributable to noncontrolling interest		1,673			2,057			1,045			2,154

Net income (loss) attributable to Harvest	$	1,205		$	(633	)	$	(5,237	)	$	(16,799	)


Net income (loss) attributable to Harvest per common share:
Basic	$	0.03		$	(0.02	)	$	(0.16	)	$	(0.51	)

Diluted	$	0.03		$	(0.02	)	$	(0.16	)	$	(0.51	)


	Quarter Ended
										December 31
	March 31			June 30			September 30			(restated)
	(amounts in thousands, except per share data)
Year ended December 31, 2007
Revenues	$	—		$	—		$	—		$	11,217
Expenses		(6,951	)		(7,798	)		(6,069	)		(9,935	)
Non-operating income (expense)		(38	)		353			15,076			35,059

Income (loss) before income taxes		(6,989	)		(7,445	)		9,007			36,341
Income tax expense		114			52			863			5,283

Income (loss) from consolidated companies		(7,103	)		(7,497	)		8,144			31,058
Net income (loss) from unconsolidated equity affiliates		(39	)		(137	)		(235	)		55,708

Net income (loss)		(7,142	)		(7,634	)		7,909			86,766
Less: Net income attributable to noncontrolling interest		(637	)		(736	)		2,524			18,630

Net income (loss) attributable to Harvest	$	(6,505	)	$	(6,898	)	$	5,385		$	68,136


Net income (loss) attributable to Harvest per common share:
Basic	$	(0.17	)	$	(0.18	)	$	0.15		$	1.95

Diluted	$	(0.17	)	$	(0.18	)	$	0.14		$	1.86

Restatement

As discussed in Note 1 — Organization and Summary of Significant Accounting Policies, we are restating our historical financial statements for the year ended December 31, 2007 and quarterly information for the quarters ended December 31, 2007, March 31, 2008, June 30, 2008 and September 30, 2008. The restatements relate to the correction of an error in the deferred tax adjustment to reconcile our share of Petrodelta’s net income reported under International Financial Reporting Standards (“IFRS”) to that required under accounting principles generally accepted in the United States of America (“GAAP”) and recorded within Net income from unconsolidated equity affiliates.

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The following tables set forth the effect of the adjustments described above for the quarterly periods from the fourth quarter of 2007 to the third quarter of 2008.

Increase (Decrease) in Quarterly Net Income (Loss)


	Quarter Ended
	December		March		June 30,			September
*(in thousands)*	31, 2007		31, 2008		2008			30, 2008
Net income from unconsolidated equity affiliates as previously reported	$	52,106	$	7,558	$	11,243		$	4,534
Total adjustment		3,602		1,251		(1,834	)		775

Net income from unconsolidated equity affiliates as restated	$	55,708	$	8,809	$	9,409		$	5,309


Net income (loss) attributable to Harvest as previously reported	$	65,255	$	204	$	834		$	(5,857	)
Total adjustment		2,881		1,001		(1,467	)		620

Net income (loss) attributable to Harvest as restated	$	68,136	$	1,205	$	(633	)	$	(5,237	)

Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)

The following tables summarize our proved reserves, drilling and production activity, and financial operating data at the end of each year. The Venezuelan reserves are attributable to our consolidated activities prior to the conversion to an equity investment in Petrodelta. Historical costs in Tables I through III provide information prior to the effective date of the conversion to Petrodelta on April 1, 2006.

In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS 69”), this section provides supplemental information on our oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

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TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):


							United States
	China		Gabon		Indonesia		and Other		Total
Year Ended December 31, 2008
Acquisition costs	$	87	$	5,792	$	71	$	13,215	$	19,165
Exploration costs		41		3,016		7,647		13,979		24,683

	$	128	$	8,808	$	7,718	$	27,194	$	43,848


Year Ended December 31, 2007
Acquisition costs	$	160	$	136	$	168	$	—	$	464
Exploration costs		204		—		—		—		204

	$	364	$	136	$	168	$	—	$	668


Year Ended December 31, 2006
Acquisition costs	$	35	$	—	$	—	$	—	$	35
Development costs		—		—		—		501		501

	$	35	$	—	$	—	$	501	$	536

TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):


								United States
	China*			Gabon		Indonesia		and Other		Total
Year Ended December 31, 2008
Costs excluded from amortization	$	2,947		$	5,927	$	239	$	13,215	$	22,328


Year Ended December 31, 2007
Costs excluded from amortization	$	2,859		$	136	$	168	$	—	$	3,163


Year Ended December 31, 2006
Proved property costs	$	13,532		$	—	$	—	$	—	$	13,532
Costs excluded from amortization		2,900			—		—		—		2,900
Oilfield inventories		—			—		—		—		—
Less accumulated depletion and impairment		(13,532	)		—		—		—		(13,532	)

	$	2,900		$	—	$	—	$	—	$	2,900


*		See Note 8 — China Operations.

TABLE III — Results of operations for oil and natural gas producing activities (in thousands):


	Venezuela
Year ended December 31, 2006^(a)
Oil and natural gas revenues	$	59,506
Expenses:
Operating, selling and distribution expenses and taxes other than on income		9,451
Depletion		9,904
Income tax expense		20,076

Total expenses^(b)		39,431

Results of operations from oil and natural gas producing activities	$	20,075


(a)		Reflects oil and natural gas deliveries through March 31, 2006.

(b)		Excludes taxes of $50.3 million recorded in 2006 due to the settlement of the SENIAT tax assessments.

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TABLE IV — Quantities of Oil and Natural Gas Reserves

Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. All Venezuelan reserves are attributable to the OSA between Harvest Vinccler and PDVSA, under which mineral rights are owned by the government of Venezuela. The Venezuelan government unilaterally terminated the OSA in April 2006.

The SEC requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data, economic changes and other relevant developments. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.

Proved developed reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well.

Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves are proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates.

Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for proved undeveloped reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir.

Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.

The evaluation of the oil and natural gas reserves were prepared by Ryder Scott Company L.P., independent petroleum engineers.

The evaluations of the oil and natural gas reserves as of December 31, 2006 were prepared by Ryder Scott Company L.P., independent petroleum engineers. The 2006 reserve information shown below has been reduced to exclude reserves formerly classified as proved undeveloped. Under SEC standards for the reporting of oil and natural gas reserves, proved reserves are estimated quantities of crude oil and natural gas “which geological data and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.” (Emphasis added). Our quantities of proved reserves were

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reduced to remove undeveloped reserves because the actions taken by the Venezuelan government beginning in 2005 under our OSA have created uncertainty as to whether those reserves will be recovered under the economic and operating conditions which currently exist in Venezuela. For ease of reference, the reclassified reserves are hereafter referred to as “Contractually Restricted Reserves”. In April 2006, the OSA was unilaterally terminated by the Venezuelan government. Reserves for Petrodelta are reflected in the following section Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela Equity Affiliate as of December 31, 2007 and 2006, TABLE IV — Quantities of Oil and Natural Gas Reserves.

The tables shown below represent our interests in Venezuela in each of the years.


				Noncontrolling
				Interest in
	Venezuela			Venezuela			Net Total
				(in thousands)
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls)

Year ended December 31, 2006
Proved Reserves at beginning of the year		35,311			(7,062	)		28,249
Revisions of previous estimates^(a)		(33,417	)		6,683			(26,734	)
Production		(1,894	)		379			(1,515	)

Proved Reserves at end of the year		—			—			—


(a)		All reserves have been removed due to the conversion to Petrodelta effective April 1, 2006.


Proved Reserves-Natural gas (MMcf)

Year ended December 31, 2006
Proved Reserves beginning of the year	58,918		(11,784	)	47,134
Revisions of previous estimates^(a)	(54,412	)	10,883		(43,529	)
Production	(4,506	)	901		(3,605	)

Proved Reserves end of the year	—		—		—


(a)		All reserves have been removed due to the conversion to Petrodelta effective April 1, 2006.

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TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities

The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.

Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.

The tables shown below represent our net interest in Petrodelta. We report the results of Ryder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan reserves.

TABLE VI — Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves


	Net Venezuela
	2006^(a)
	(in thousands)
Standardized Measure at January 1	$	329,438
Sales of oil and natural gas, net of related costs		(40,361	)
Revisions to estimates of proved reserves
Net changes in prices, development and production costs		—
Quantities		—
Extensions, discoveries and improved recovery, net of future costs		—
Accretion of discount		—
Net change in income taxes		—
Development costs incurred		501
Changes in timing and other		(289,578	)

Standardized Measure at December 31	$	—


(a)		All reserves have been removed due to the conversion to Petrodelta effective April 1, 2006.

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Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Petrodelta S.A. as of December 31, 2008, 2007 and 2006

Petrodelta (32 percent ownership) is accounted for under the equity method, and has been included at its ownership interest in the consolidated financial statements and the following Tables based on a year ending December 31 and, accordingly, results of operations for oil and natural gas producing activities in Venezuela reflect the year ended December 31, 2008, 2007 and 2006.

TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):


	Petrodelta
Year Ended December 31, 2008
Development costs	$	7,791
Exploration costs		—

	$	7,791


Year Ended December 31, 2007
Development costs	$	972
Exploration costs		—

	$	972


Year Ended December 31, 2006
Development costs	$	217
Exploration costs		—

	$	217

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TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):


	Petrodelta
December 31, 2008
Proved property costs	$	72,205
Unproved property costs		2,653
Oilfield inventories		5,974
Less accumulated depletion and impairment		(18,992	)

	$	61,840


December 31, 2007
Proved property costs	$	59,821
Unproved property costs		7,247
Oilfield inventories		4,426
Less accumulated depletion and impairment		(11,063	)

	$	60,431


December 31, 2006
Proved property costs	$	58,849
Unproved property costs		7,247
Oilfield inventories		2,650
Less accumulated depletion and impairment		(5,317	)

	$	63,429

TABLE III — Results of operations for oil and natural gas producing activities (in thousands):


	Petrodelta
Year ended December 31, 2008
Oil and natural gas revenues	$	151,878
Royalty		(53,003	)

		98,875

Expenses:
Operating, selling and distribution expenses and taxes other than on income		43,885
Depletion		7,929
Income tax expense		23,530

Total expenses		75,344

Results of operations from oil and natural gas producing activities	$	23,531


Year ended December 31, 2007
Oil and natural gas revenues	$	107,429
Royalty		(35,035	)

		72,394

Expenses:
Operating, selling and distribution expenses and taxes other than on income		14,993
Depletion		5,746
Income tax expense		25,828

Total expenses		46,567

Results of operations from oil and natural gas producing activities	$	25,827

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	Petrodelta
Year ended December 31, 2006
Oil and natural gas revenues	$	90,695
Royalty		(30,973	)

		59,722

Expenses:
Operating, selling and distribution expenses and taxes other than on income		7,273
Depletion		5,317
Income tax expense		23,566

Total expenses		36,156

Results of operations from oil and natural gas producing activities	$	23,566

TABLE IV — Quantities of Oil and Natural Gas Reserves

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Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.

The evaluation of the oil and natural gas reserves as of December 31, 2008 and 2007 was prepared by Ryder Scott Company L.P., independent petroleum engineers.

The tables shown below represents HNR Finance’s interest, net of a 33.33 percent royalty, in Venezuela in each of the years.


				Noncontrolling
				Interest in			32%
	HNR Finance			Venezuela			Net Total
				(in thousands)
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls)

Year ended December 31, 2008
Proved Reserves at January 1, 2008		47,261			(9,452	)		37,809
Revisions/Additions		(2,984	)		597			(2,387	)
Production		(1,468	)		294			(1,174	)

Proved Reserves at end of the year		42,809			(8,561	)		34,248


Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at:
December 31, 2008		13,415			(2,683	)		10,732

Year ended December 31, 2007
Proved Reserves at January 1, 2007		—			—			—
Additions^(a)		50,085			(10,017	)		40,068
Production		(2,824	)		565			(2,259	)

Proved Reserves at end of the year		47,261			(9,452	)		37,809


(a) Petrodelta was formed in 2007

Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at:
December 31, 2007		14,779			(2,956	)		11,823

Proved Reserves-Natural gas (MMcf)

Year ended December 31, 2008
Proved Reserves at January 1, 2008		43,084			(8,617	)		34,467
Additions		27,574			(5,515	)		22,059
Production		(2,854	)		571			(2,283	)

Proved Reserves at end of the year		67,804			(13,561	)		54,243


Proved Developed Reserves-Natural gas (MMcf) at:
December 31, 2008		30,168			(6,034	)		24,135

Year ended December 31, 2007
Proved Reserves at January 1, 2007		—			—			—
Additions^(a)		50,019			(10,004	)		40,015
Production		(6,935	)		1,387			(5,548	)

Proved Reserves at end of the year		43,084			(8,617	)		34,467


(a)		Petrodelta was formed in 2007


Proved Developed Reserves-Natural gas (MMcf) at:
December 31, 2007	7,755	(1,551	)	6,204

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TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities

The table shown below represents HNR Finance’s net interest in Petrodelta. We report the results of Ryder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan reserves.


				Noncontrolling
				Interest in
	HNR Finance			Venezuela			Net Total
				(in thousands)
December 31, 2008
Future cash inflows from sales of oil and gas	$	1,576,312		$	(315,262	)	$	1,261,050
Future production costs		(557,043	)		111,409			(445,634	)
Future development costs		(306,500	)		61,300			(245,200	)
Future income tax expenses		(355,746	)		71,149			(284,597	)

Future net cash flows		357,023			(71,404	)		285,619
Effect of discounting net cash flows at 10%		(217,822	)		43,564			(174,258	)

Standardized measure of discounted future net cash flows	$	139,201		$	(27,840	)	$	111,361


December 31, 2007
Future cash inflows from sales of oil and gas	$	3,650,110		$	(730,022	)	$	2,920,088
Future production costs		(685,368	)		137,074			(548,294	)
Future development costs		(358,759	)		71,752			(287,007	)
Future income tax expenses		(1,274,005	)		254,801			(1,019,204	)

Future net cash flows		1,331,978			(266,395	)		1,065,583
Effect of discounting net cash flows at 10%		(677,756	)		135,551			(542,205	)

Standardized measure of discounted future net cash flows	$	654,222		$	(130,844	)	$	523,378

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	Page
Index to Financial Statements:
Report of Independent Registered Public Accounting Firm		S-1
Consolidated Balance Sheets at December 31, 2008 and 2007		S-2
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006		S-3
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2008, 2007 and 2006		S-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006		S-5
Notes to Consolidated Financial Statements		S-7