FORM 10-Q/A

Large Accelerated Filer

Accelerated Filer

Non-Accelerated Filer

Smaller Reporting Company

10-Q/A 1 d518655d10qa.htm FORM 10-Q/A FORM 10-Q/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q/A

AMENDMENT NO. 1

(Mark One)

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

For the Quarterly Period Ended June 30, 2012

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

for the transition period from to

Commission File No. 1-10762

Harvest Natural Resources, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware

77-0196707

(State or Other Jurisdiction of

Incorporation or Organization)

(IRS Employer

Identification No.)

1177 Enclave Parkway, Suite 300

Houston, Texas

77077

(Address of Principal Executive Offices)

(Zip Code)

(281) 899-5700

(Registrant’s Telephone Number, Including Area Code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

At July 27, 2012, 37,528,852 shares of the Registrant’s Common Stock were outstanding.

Restatement

Overview

Harvest Natural Resources, Inc. (“Harvest” or the “Company”) is filing this Amendment on Form 10-Q/A (“Form 10-Q/A”) to amend its Quarterly Report on Form 10-Q for the three and six months ended June 30, 2012, filed with the Securities and Exchange Commission (“SEC”) on August 9, 2012 (“Original Form 10-Q”). Accordingly, pursuant to Rule 12b-15 under the Securities Exchange Act of 1934, as amended (“Exchange Act”), the Form 10-Q/A contains complete text of Items 1, 2 and 4 of Part 1, and Item 6 of Part II as amended as well as certain currently dated certifications.

The Form 10-Q/A is being filed to amend and restate the Company’s previously issued consolidated condensed financial statements due to errors in previously filed financial statements. In the course of our review, management determined (a) certain warrants issued in 2010 in connection with our $60 million term loan facility (the “Warrants”) were improperly valued at inception and improperly classified as equity instruments rather than liability instruments. As a result of the improper classification of the Warrants, (b) the debt discount and associated interest expense related to the amortization of the debt discount was understated for all periods in which the associated debt was outstanding, and (c) the consolidated condensed statement of operations and comprehensive income (loss) for each reporting period was misstated by the omission of the changes in fair value of the Warrants as a liability instrument. Additionally, (d) certain exploration overhead was incorrectly capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed, and (e) certain leasehold maintenance and other costs were improperly capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed. Finally, (f) advances to equity affiliate were improperly classified as an operating activity rather than an investing activity and (g) certain costs were improperly classified as an investing activity rather than an operating activity on the consolidated condensed statement of cash flows. Such errors impacted the annual period ended December 31, 2011 and quarterly periods ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, and June 30, 2012.

As a result of the errors related to the Warrants described above, loss on extinguishment of debt was understated for the year ended December 31, 2011 and the quarters ended June 30, 2011, September 30, 2011 and December 31, 2011.

Additionally, an error was identified in the calculation of earnings (loss) per diluted share for the year ended December 31, 2011 and the three and six months ended June 30, 2011, and an additional error was identified related to the improper expensing of costs associated with debt conversions that should have been recorded to equity in the six months ended June 30, 2012.

We have restated our segment footnote information to reflect the applicable errors stated above and eliminate intrasegment receivables erroneously reported gross of related intrasegment payable. Such errors impacted the annual period ended December 31, 2011 and quarterly periods ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, and June 30, 2012.

In assessing the severity of the errors, management determined that the errors were material to the consolidated condensed financial statements for the year ended December 31, 2011 and quarterly information for all quarters in 2011 and the first and second quarters of 2012. In addition to the errors described above, we made corrections for previously identified immaterial errors and errors affecting classification within the consolidated condensed statement of operations and comprehensive income (loss) related to impairment of oil and gas properties and income taxes and the consolidated condensed balance sheets related to income taxes.

For information relating to the effect of the restatements, see the following items:

Part I:

Item 1 – Financial Statements

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

Item 4 – Controls and Procedures

Part II:

Item 6 – Exhibits

Aside from the forgoing items, no other items are amended or modified in this Form 10-Q/A.

Other than the restatement, this Form 10-Q/A does not reflect events occurring after the date of the Original Form 10-Q or modify or update those disclosures as affected by subsequent events. Such events include, among others, the events described in the Company’s Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. This Form 10-Q/A should be read in conjunction with our other reports filed with the SEC subsequent to December 31, 2012 pursuant to the Exchange Act.

HARVEST NATURAL RESOURCES, INC.

FORM 10-Q

TABLE OF CONTENTS


		Page
PART I FINANCIAL INFORMATION

Item 1.	Financial Statements
	Unaudited Consolidated Condensed Balance Sheets at June 30, 2012 and December 31, 2011		4
	Unaudited Consolidated Condensed Statements of Operations and Comprehensive Income for the Three and Six Months Ended June 30, 2012 and 2011		5
	Unaudited Consolidated Condensed Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011		6
	Notes to Consolidated Condensed Financial Statements		8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		37

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		59

Item 4.	Controls and Procedures		59

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings		63

Item 1A.	Risk Factors		64

Item 6.	Exhibits		66

Signatures			68

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)


	June 30, 2012			December 31, 2011
	(in thousands)
	(RESTATED*)			(RESTATED*)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	28,746		$	58,946
Restricted cash		—			1,200
Receivables, net:
Dividend receivable – equity affiliate		12,200			12,200
Joint interest and other		6,315			14,342
Note receivable		—			3,335
Advances to equity affiliate		2,538			2,388
Prepaid expenses and other		1,692			728

TOTAL CURRENT ASSETS		51,491			93,139
OTHER ASSETS		5,555			5,427
INVESTMENT IN EQUITY AFFILIATE		384,779			345,054
PROPERTY AND EQUIPMENT:
Oil and gas properties		66,017			62,455
Other administrative property, net		934			1,128

TOTAL PROPERTY AND EQUIPMENT, NET		66,951			63,583

TOTAL ASSETS	$	508,776		$	507,203


LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable, trade and other	$	1,044		$	7,381
Accounts payable, carry obligation		—			3,596
Accrued expenses		8,896			15,247
Accrued interest		612			976
Other current liabilities		2,632			2,632
Income taxes payable		1,221			689
Current portion – long-term debt		15,551			—

TOTAL CURRENT LIABILITIES		29,956			30,521
OTHER LONG-TERM LIABILITIES		956			908
WARRANT DERIVATIVE LIABILITY		6,079			4,870
LONG-TERM DEBT		—			31,535
COMMITMENTS AND CONTINGENCIES (See Note 6)

EQUITY
STOCKHOLDERS’ EQUITY:
Preferred stock, par value $0.01 a share; authorized 5,000 shares; outstanding, none		—			—
Common stock, par value $0.01 a share; authorized 80,000 shares at June 30, 2012 (December 31, 2011: 80,000 shares); issued 43,864 shares at June 30, 2012 (December 31, 2011: 40,625 shares)		438			406
Additional paid-in capital		247,178			227,800
Retained earnings		198,774			193,589
Treasury stock, at cost 6,527 shares at June 30, 2012 (December 31, 2011: 6,521 shares)		(66,145	)		(66,104	)

TOTAL HARVEST STOCKHOLDERS’ EQUITY		380,245			355,691
NONCONTROLLING INTEREST		91,540			83,678

TOTAL EQUITY		471,785			439,369

TOTAL LIABILITIES AND EQUITY	$	508,776		$	507,203

*	See Note 2 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements.

See accompanying notes to consolidated condensed financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands, except per share data)
	(RESTATED*)			(RESTATED*)			(RESTATED*)			(RESTATED*)
EXPENSES
Depreciation and amortization	$	105		$	119		$	210		$	243
Exploration expense		1,712			1,440			3,647			2,739
Impairment of oil and gas properties		—			3,335			—			3,335
Dry hole costs		71			—			5,617			—
General and administrative		6,524			7,049			12,366			13,724

		8,412			11,943			21,840			20,041


LOSS FROM OPERATIONS		(8,412	)		(11,943	)		(21,840	)		(20,041	)

OTHER NON-OPERATING INCOME (EXPENSE)
Investment earnings and other		80			240			149			385
Unrealized gain (loss) on warrant derivatives		(1,641	)		7,060			(1,209	)		4,544
Interest expense		(34	)		(2,186	)		(126	)		(5,739	)
Debt conversion expense		20			—			(2,402	)		—
Loss on extinguishment of debt		—			(13,132	)		—			(13,132	)
Other non-operating expenses		(1,467	)		(244	)		(1,723	)		(675	)
Foreign currency transaction loss		(48	)		(32	)		(70	)		(43	)

		(3,090	)		(8,294	)		(5,381	)		(14,660	)

LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(11,502	)		(20,237	)		(27,221	)		(34,701	)

INCOME TAX EXPENSE (BENEFIT)		(1,022	)		260			(2,242	)		719

LOSS FROM CONTINUING OPERATIONS		(10,480	)		(20,497	)		(24,979	)		(35,420	)

NET INCOME FROM EQUITY AFFILIATES		22,829			18,284			39,725			36,740


NET INCOME (LOSS) FROM CONTINUING OPERATIONS		12,349			(2,213	)		14,746			1,320

DISCONTINUED OPERATIONS:
Income (Loss) from discontinued operations		(1,584	)		480			(1,699	)		(2,786	)
Gain on sale of oil and gas properties		—			103,933			—			103,933
Income tax expense		—			(5,748	)		—			(5,748	)

Income (Loss) from discontinued operations		(1,584	)		98,665			(1,699	)		95,399


NET INCOME		10,765			96,452			13,047			96,719

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		4,540			3,639			7,862			7,058


NET INCOME ATTRIBUTABLE TO HARVEST	$	6,225		$	92,813		$	5,185		$	89,661


NET INCOME ATTRIBUTABLE TO HARVEST PER COMMON SHARE: (See Note 2 – Summary of Significant Accounting Policies, Earnings Per Share):
Basic	$	0.17		$	2.73		$	0.14		$	2.64

Diluted	$	0.15		$	2.73		$	0.14		$	2.64


COMPREHENSIVE INCOME	$	6,225		$	92,813		$	5,185		$	89,661

*	See Note 2 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements.

See accompanying notes to consolidated condensed financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
	2012			2011
	(in thousands)
	(RESTATED*)			(RESTATED*)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	13,047		$	96,719
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization		210			1,053
Impairment of long-lived assets		—			1,440
Impairment of oil and gas properties costs		—			3,335
Dry hole costs		5,617			—
Amortization of debt financing costs		287			530
Amortization of discount on debt		—			2,876
Gain on sale of assets		—			(103,933	)
Loss on early extinguishment of debt		—			10,983
Debt conversion expense		1,939			—
Allowance for account and note receivable		5,180			—
Write-off of accounts payable, carry obligation		(3,596	)		—
Net income from equity affiliate		(39,725	)		(36,740	)
Share-based compensation-related charges		2,124			2,673
Unrealized (gain) loss on warrant derivative		1,209			(4,544	)
Other current liabilities		—			425
Changes in operating assets and liabilities:
Receivables		6,182			(2,887	)
Prepaid expenses and other		(950	)		3,061
Other assets		(829	)		(62	)
Accounts payable		(6,337	)		8,168
Accrued expenses		(2,177	)		(2,469	)
Accrued interest		(971	)		(814	)
Other long-term liabilities		48			(701	)
Income taxes payable		532			6,032

NET CASH USED IN OPERATING ACTIVITIES		(18,210	)		(14,855	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets		—			217,833
Additions of property and equipment		(13,146	)		(27,900	)
Additions to assets held for sale		—			(31,742	)
Proceeds from sale of equity affiliate		—			1,385
Advances to equity affiliate		(150	)		(296	)
(Increase) decrease in restricted cash		1,200			(7,323	)

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(12,096	)		151,957


CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuances of common stock		273			416
Proceeds from long term debt		—			(60,000	)
Financing costs		(167	)		(189	)

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		106			(59,773	)


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(30,200	)		77,329

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		58,946			58,703

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	28,746		$	136,032

*	See Note 2 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements.

See accompanying notes to consolidated condensed financial statements.

Supplemental Schedule of Noncash Investing and Financing Activities:

During the six months ended June 30, 2012, we settled 70,994 restricted stock units with Harvest common stock valued at $0.4 million. Also, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 7,789 shares being added to treasury stock at cost.

During the six months ended June 30, 2011, we issued 0.2 million shares of restricted stock valued at $2.0 million. Also, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 30,373 shares being added to treasury stock at cost.

See accompanying notes to consolidated condensed financial statements.

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2012 and 2011 (unaudited)

Note 1 – Organization

Interim Reporting

In our opinion, the accompanying unaudited consolidated condensed financial statements contain all adjustments necessary to present fairly the financial position as of June 30, 2012, and the results of operations and cash flows for the three and six months ended June 30, 2012 and 2011. The unaudited consolidated condensed financial statements are presented in accordance with the requirements of Form 10-Q and do not include all disclosures normally required by accounting principles generally accepted in the United States of America (“USGAAP”). Reference should be made to our consolidated financial statements and notes thereto included in our Annual Reports on Form 10-K for the years ended December 31, 2012 and 2011 which include certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year.

Organization

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

We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through Harvest-Vinccler Dutch Holding, B.V., a Dutch private company with limited liability (“Harvest Holding”). Our ownership of Harvest Holding is through HNR Energia, B.V. (“HNR Energia”) in which we have a direct controlling interest. Through HNR Energia, we indirectly own 80 percent of Harvest Holding and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining 20 percent interest of Harvest Holding. Harvest Holding owns, indirectly through wholly owned subsidiaries, a 40 percent of Petrodelta, S.A. (“Petrodelta”). As we indirectly own 80 percent of Harvest Holding, we indirectly own a net 32 percent interest in Petrodelta, and Vinccler indirectly owns eight percent. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petroleos de Venezuela S.A. (“PDVSA”) owns 100 percent of CVP. Harvest Holding has a direct controlling interest in Harvest Vinccler S.C.A. (“Harvest Vinccler”). Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with PDVSA. We do not have a business relationship with Vinccler outside of Venezuela.

In addition to our interests in Venezuela, we hold exploration acreage in four projects:

•

Mainly onshore in West Sulawesi in the Republic of Indonesia (“Indonesia”) through a Production Sharing Contract (“Budong PSC”) (see Note 11 – Indonesia),

•

Offshore of the Republic of Gabon (“Gabon”) through the Dussafu Marin Permit (“Dussafu PSC”) (see Note 12 – Gabon),

•

Onshore in the Sultanate of Oman (“Oman”) through the Oman Exploration and Production Sharing Agreement Al Ghubar / Qarn Alam license (“Block 64 EPSA”) (see Note 13 – Oman), and

•

Offshore of the People’s Republic of China (“China”) through a Petroleum Contract.

Note 2 – Summary of Significant Accounting Policies

Restatement of Prior Period Financial Statements

than liability instruments. As a result of the improper classification of the Warrants, (b) the debt discount and associated interest expense related to the amortization of the debt discount was understated for all periods in which the associated debt was outstanding, and (c) the consolidated condensed statement of operations and comprehensive income (loss) for each reporting period was misstated by the omission of the changes in fair value of the Warrants as a liability instrument. Additionally, (d) certain exploration overhead was incorrectly capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed, and (e) certain leasehold maintenance and other costs were improperly capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed. Finally, (f) advances to equity affiliate were improperly classified as an operating activity rather than an investing activity and (g) certain costs were improperly classified as an investing activity rather than an operating activity on the consolidated condensed statement of cash flows. Such errors impacted annual period ended December 31, 2011 and quarterly periods ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, and June 30, 2012.

We have restated our segment footnote information to reflect the applicable errors stated above and eliminate intrasegment receivables erroneously reported gross of related intrasegment payable. Such errors impacted annual period ended December 31, 2011 and quarterly periods ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, and June 30, 2012.

The following tables set forth the effect of the adjustments described above on the consolidated condensed statements of operations and comprehensive income for the three and six months ended June 30, 2012 and 2011, the consolidated condensed statements of cash flows for the six months ended June 30, 2012 and 2011, and the consolidated condensed balance sheets as of June 30, 2012 and December 31, 2011.

Consolidated Condensed Statements of Operations and Comprehensive Income (Loss)


	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	As Previously Reported			Adjustment			As RESTATED			As Previously Reported			Adjustment			As RESTATED
	*(in thousands)*
Expenses
Depreciation and amortization	$	105		$	—		$	105		$	119		$	—		$	119
Exploration expense^(a)		1,282			430			1,712			4,650			(3,210	)		1,440
Impairment of oil and gas properties^(b)		—			—			—			—			3,335			3,335
Dry hole costs		71			—			71			—			—			—
General and administrative		6,524			—			6,524			7,049			—			7,049

Total expenses		7,982			430			8,412			11,818			125			11,943

Loss from operations		(7,982	)		(430	)		(8,412	)		(11,818	)		(125	)		(11,943	)
Other non-operating income (expense)
Investment earnings and other		80			—			80			240			—			240
Unrealized gain (loss) on warrant derivatives^(c)		—			(1,641	)		(1,641	)		—			7,060			7,060
Interest expense^(d)		(34	)		—			(34	)		(1,704	)		(482	)		(2,186	)
Debt conversion expense		20			—			20			—			—			—
Loss on early extinguishment of debt^(e)		—			—			—			(9,682	)		(3,450	)		(13,132	)
Other non-operating expense		(1,467	)		—			(1,467	)		(244	)		—			(244	)
Foreign currency transaction loss		(48	)		—			(48	)		(32	)		—			(32	)

		(1,449	)		(1,641	)		(3,090	)		(11,422	)		3,128			(8,294	)

Income (Loss) from Continuing Operations Before Income taxes		(9,431	)		(2,071	)		(11,502	)		(23,240	)		3,003			(20,237	)
Income tax expense (benefit)^(f)		(426	)		(596	)		(1,022	)		260			—			260

Income (Loss) from Continuing Operations		(9,005	)		(1,475	)		(10,480	)		(23,500	)		3,003			(20,497	)
Net Income from Equity Affiliate^(g)		22,661			168			22,829			18,246			38			18,284

Net Income (Loss) from Continuing Operations		13,656			(1,307	)		12,349			(5,254	)		3,041			(2,213	)
Discontinued Operations
Income (Loss) from Discontinued Operations		(1,584	)		—			(1,584	)		480			—			480
Gain on sale of oil and gas properties		—			—			—			103,933			—			103,933
Income tax (expense) benefit		595			(595	)		—			(5,748	)		—			(5,748	)

Income (Loss) from Discontinued Operations^(h)		(989	)		(595	)		(1,584	)		98,665			—			98,665

Net Income (Loss)		12,667			(1,902	)		10,765			93,411			3,041			96,452
Less: Net Income Attributable to Noncontrolling Interest^(g)		4,507			33			4,540			3,631			8			3,639

Net Income (Loss) Attributable To Harvest	$	8,160		$	(1,935	)	$	6,225		$	89,780		$	3,033		$	92,813


Net Income (Loss) Attributable to Harvest Per Common Share:
Basic	$	0.22		$	(0.05	)	$	0.17		$	2.64		$	0.09		$	2.73

Diluted⁽ⁱ⁾	$	0.20		$	(0.05	)	$	0.15		$	2.23		$	0.50		$	2.73


Comprehensive income (loss)	$	8,160		$	(1,935	)	$	6,225		$	89,780		$	3,033		$	92,813

(a)

For 2012, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense. For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense. For the three months ended June 30, 2011, this amount was offset by a reclassification from exploration expense to impairment of oil and gas properties of $3,335 thousand in the three months ended June 30, 2011 for amounts that were erroneously classified as exploration expense.

(b)	For 2011, represents the reclassification from exploration expense to impairment of oil and gas properties for amounts that were erroneously classified as exploration expense.

(c)	For 2012 and 2011, represents changes in fair value of the Warrants for the period. Such Warrants were previously classified as equity and were, therefore, not marked to market at the end of each reporting period.

(d)	For 2011, as a result of the change in fair value of the Warrants, the original discount allocated to the debt was understated; therefore, the additional amortization of the discount on debt, which is a component of interest expense, was understated for each period the debt was outstanding.

(e)	For 2011, the correction in the fair value of the Warrants and its classification as a liability resulted in an increase discount on debt which also impacted the resulting loss on extinguishment of debt originally recorded in May 2011 when the debt was retired.

(f)	For 2012, represents income tax effect of adjustments.

(g)	For 2012 and 2011, represents a previously identified immaterial error.

(h)	For 2012, represents a previously identified classification error between income tax on discontinued operations and income tax on continuing operations.

(i)

For 2011, in addition to the impact on EPS related to the adjustments described in (a) through (e) and (g) above, diluted EPS has been adjusted to reflect an error in the calculation of the weighted average common shares outstanding for dilutive EPS for the three months ended June 30, 2011. The weighted average common shares utilized for the calculation of diluted EPS was erroneously 40,260 thousand rather than 34,039 thousand.

Consolidated Condensed Statements of Operations and Comprehensive Income (Loss)


	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	As Previously Reported			Adjustment			As RESTATED			As Previously Reported			Adjustment			As RESTATED
	*(in thousands)*
Expenses
Depreciation and amortization	$	210		$	—		$	210		$	243		$	—		$	243
Exploration expense^(a)		2,725			922			3,647			5,839			(3,100	)		2,739
Impairment of oil and gas properties^(b)		—			—			—			—			3,335			3,335
Dry hole costs		5,617			—			5,617			—			—			—
General and administrative		12,366			—			12,366			13,724			—			13,724

Total expenses		20,918			922			21,840			19,806			235			20,041

Loss from operations		(20,918	)		(922	)		(21,840	)		(19,806	)		(235	)		(20,041	)
Other non-operating income (expense)
Investment earnings and other		149			—			149			385			—			385
Unrealized gain (loss) on warrant derivatives^(c)		—			(1,209	)		(1,209	)		—			4,544			4,544
Interest expense^(d)		(428	)		302			(126	)		(3,916	)		(1,823	)		(5,739	)
Debt conversion expense		(2,402	)		—			(2,402	)		—			—			—
Loss on extinguishment of debt^(e)		—			—			—			(9,682	)		(3,450	)		(13,132	)
Other non-operating expense		(1,723	)		—			(1,723	)		(675	)		—			(675	)
Foreign currency transaction loss		(70	)		—			(70	)		(43	)		—			(43	)

		(4,474	)		(907	)		(5,381	)		(13,931	)		(729	)		(14,660	)

Loss from Continuing Operations Before Income taxes		(25,392	)		(1,829	)		(27,221	)		(33,737	)		(964	)		(34,701	)
Income tax expense (benefit)^(f)		(1,646	)		(596	)		(2,242	)		482			237			719

Loss from Continuing Operations		(23,746	)		(1,233	)		(24,979	)		(34,219	)		(1,201	)		(35,420	)
Net Income from Equity Affiliate^(g)		39,419			306			39,725			36,740			—			36,740

Net Income (Loss) from Continuing Operations		15,673			(927	)		14,746			2,521			(1,201	)		1,320
Discontinued Operations
Income (Loss) from Discontinued Operations		(1,699	)		—			(1,699	)		(2,786	)		—			(2,786	)
Gain on sale of oil and gas properties		—			—			—			103,933			—			103,933
Income tax (expense) benefit		595			(595	)		—			(5,748	)		—			(5,748	)

Income (Loss) from Discontinued Operations^(h)		(1,104	)		(595	)		(1,699	)		95,399			—			95,399

Net Income (Loss)		14,569			(1,522	)		13,047			97,920			(1,201	)		96,719
Less: Net Income Attributable to Noncontrolling Interest^(g)		7,801			61			7,862			7,058			—			7,058

Net Income (Loss) Attributable To Harvest	$	6,768		$	(1,583	)	$	5,185		$	90,862		$	(1,201	)	$	89,661


Net Income (Loss) Attributable to Harvest Per Common Share:
Basic	$	0.19		$	(0.05	)	$	0.14		$	2.67		$	(0.03	)	$	2.64

Diluted⁽ⁱ⁾	$	0.18		$	(0.04	)	$	0.14		$	2.27		$	0.37		$	2.64


Comprehensive income (loss)	$	6,768		$	(1,583	)	$	5,185		$	90,862		$	(1,201	)	$	89,661

(a)

For 2012, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense. For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense. For the six months ended June 30, 2011, this amount was offset by a reclassification from exploration expense to impairment of oil and gas properties of $3,335 thousand in the six months ended June 30, 2011 for amounts that were erroneously classified as exploration expense.

(b)	For 2011, represents the reclassification from exploration expense to impairment of oil and gas properties for amounts that were erroneously classified as exploration expense.

(c)	Represents changes in fair value of Warrants for the period. Such Warrants were previously classified as equity and were, therefore, not marked to market at the end of each reporting period.

(d)

For 2012, relates to the improper expensing of accrued interest associated with debt conversions. For 2011, as a result of the change in fair value of the Warrants, the original discount allocated to the debt was understated; therefore, the additional amortization of the discount on debt, which is a component of interest expense, was understated for each period the debt was outstanding and income taxes improperly classified as interest expense.

(e)	The correction in the fair value of the Warrants and its classification as a liability resulted in an increase discount on debt which also impacted the resulting loss on extinguishment of debt originally recorded in May 2011 when the debt was retired.

(f)	For 2012, represents income tax effect of adjustments. For 2011, relates to income tax expense improperly classified as interest expense.

(g)	Represents a previously identified immaterial error.

(h)	Represents a previously identified classification error between income tax on discontinued operations and income tax on continuing operations.

(i)

For 2011, in addition to the impact on EPS related to the adjustments described in (a) through (e) and (g) above, diluted EPS has been adjusted to reflect an error in the calculation of the weighted average common shares, diluted outstanding for the six months ended June 30, 2011. The weighted average common shares utilized for the calculation of diluted EPS was erroneously 40,027 thousand rather than 33,992 thousand.

Consolidated Condensed Balance Sheets


	June 30, 2012
	As Previously Reported		Adjustment			As RESTATED
	*(in thousands)*

Deferred income tax^(a)	$	2,628	$	(2,628	)	$	—
Investment in equity affiliate^(b)		384,473		306			384,779
Oil and gas properties^(c)		70,292		(4,275	)		66,017
Total assets^(d)		515,373		(6,597	)		508,776
Accrued interest payable^(e)		1,008		(396	)		612
Other current liabilities^(a)		4,835		(2,203	)		2,632
Income taxes payable^(f)		1,251		(30	)		1,221
Warrant derivative liability^(g)		—		6,079			6,079
Total liabilities^(h)		33,541		3,450			36,991
Additional paid in capital⁽ⁱ⁾		256,009		(8,831	)		247,178
Retained earnings^(j)		200,051		(1,277	)		198,774
Total Harvest shareholders’ equity^(k)		390,353		(10,108	)		380,245
Noncontrolling interest^(b)		91,479		61			91,540
Total equity		481,832		(10,047	)		471,785

(a)	Relates to a deferred tax asset that was erroneously reported gross of the related liability.

(b)	Represents a previously identified immaterial error.

(c)	Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense.

(d)	Relates to (a) through (c) above.

(e)	Represents other current liabilities that were improperly classified as interest payable and income taxes payable.

(f)	Income tax effect of the adjustments and income taxes improperly classified as interest payable in 2011.

(g)	Represents the fair value of the Warrants at the reporting date.

(h)	Relates to (a) and (e) through (g) above.

(i)

Relates to (a) the reclassification of the Warrants from equity to warrant derivative liability of $11,122 thousand offset by an error recorded in 2011 for $2,730 thousand for the reversal of the original fair value of certain Warrants that did not qualify for equity classification and (b) deferred financing costs of $439 thousand that were erroneously expensed rather than capitalized to additional paid-in capital.

(j)

Relates to (a) net increase in expense in 2010, 2011, and six months ended June 30, 2012 related to exploration expense of $3,445 thousand, (b) net increase in unrealized gain on warrant derivatives of $8,921 thousand for cumulative 2010, 2011 and six months ended June 30, 2012, (c) net increase in interest expense of $2,619 thousand cumulative for 2010, 2011 and six months ended June 30, 2012, (d) net increase in loss on extinguishment of debt of $3,450 thousand for 2011, (e) net increase in income from equity affiliate of $306 thousand less noncontrolling interest of $61 thousand due a previously identified immaterial error, (f) net increase in income tax expense of $236 thousand for income taxes improperly classified as interest expense, offset by a reduction to retained earnings of $693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than expensed prior to January 1, 2010.

(k)	Relates to reclassification of the Warrants as described in (i) above plus the impact of retained earnings described in (j) above.

Consolidated Condensed Balance Sheets


	December 31, 2011
	As Previously Reported		Adjustment			As RESTATED
	*(in thousands)*

Deferred income taxes^(a)	$	2,628	$	(2,628	)	$	—
Oil and gas properties^(b)		65,671		(3,216	)		62,455
Total assets^(c)		513,047		(5,844	)		507,203
Accrued interest payable^(d)		1,372		(396	)		976
Other current liabilities^(e)		4,835		(2,203	)		2,632
Income taxes payable^(d)		718		(29	)		689
Warrant derivative liability^(f)		—		4,870			4,870
Total liabilities^(g)		65,592		2,242			67,834
Additional paid in capital^(h)		236,192		(8,392	)		227,800
Retained earnings⁽ⁱ⁾		193,283		306			193,589
Total Harvest shareholders’ equity^(j)		363,777		(8,086	)		355,691
Total equity		447,455		(8,086	)		439,369

(a)	Relates to a deferred tax asset that was erroneously reported gross of the related liability.

(b)	Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense.

(c)	Relates to (a) and (b) above.

(d)	Represents other current liabilities that were improperly classified as interest payable and income taxes payable.

(e)	Relates to a deferred tax asset that was erroneously reported gross of the related liability and other current liabilities that were improperly classified as interest payable and income taxes payable.

(f)

Relates to the reclassification of the Warrants out of additional paid in capital to warrant derivative liabilities. The fair value of the Warrants was not appropriately determined at inception because certain features of the Warrants were not originally considered in the fair value calculation. Thus, the correction of the error to record the Warrants as a liability does not agree to the correction of the error removing the Warrants from equity. Additionally, the Warrants were not properly marked to market at the end of each period. The warrant derivative liability was valued at $15,000 thousand at inception with subsequent reductions in fair value of $344 thousand in 2010 and $9,786 thousand in 2011.

(g)	Relates to (d) through (f) above.

(h)

Relates to the reversal of the amount recorded to equity at inception for the Warrants of $11,122 thousand and the reversal of the amount removed from additional paid in capital of $2,730 thousand when a portion of the Warrants were redeemed by the Company. In May 2011, additional paid in capital was debited for $2,730 thousand for the reversal of the original fair value of such warrants which was an error as they did not qualify for equity classification.

(i)

Relates to (a) net increase in expense in 2010 and 2011 related to exploration expense of $2,523 thousand (inclusive of the reclassification of exploration expense to impairment of oil and gas properties of $3,335 thousand), (b) net increase in unrealized gain on warrant derivatives of $10,130 thousand for cumulative 2010 and 2011, (c) net increase in interest expense of $2,921 thousand cumulative for 2010 and 2011, (d) net increase in loss on extinguishment of debt of $3,450 thousand for 2011, (e) net increase in income tax expense of $237 thousand for income taxes improperly classified as interest expense, offset by a reduction to retained earnings of $693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than expensed prior to January 1, 2010.

(j)	Relates to reclassification of the Warrants as described in (h) above plus the impact of retained earnings described in (i) above.

Consolidated Condensed Statements of Cash Flows


	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	As Previously Reported			Adjustment			As RESTATED			As Previously Reported			Adjustment			As RESTATED
	*(in thousands)*
Net cash used in operating activities^(a)(b)	$	(16,472	)	$	(1,738	)	$	(18,210	)	$	(14,922	)	$	67		$	(14,855	)
Net cash provided by (used in) investing activities^(a)(b)		(13,834	)		1,738			(12,096	)		152,024			(67	)		151,957
Net cash provided by (used in) financing activities		106			—			106			(59,773	)		—			(59,773	)

Net increase (decrease) in cash and cash equivalents		(30,200	)		—			(30,200	)		77,329			—			77,329
Cash and cash equivalents at beginning of year		58,946			—			58,946			58,703			—			58,703

Cash and cash equivalents at end of year	$	28,746		$	—		$	28,746		$	136,032		$	—		$	136,032

(a)

For 2012, relates to the $1,059 thousand of lease maintenance costs, exploration overhead and $829 thousand of certain investment costs that were improperly classified as an investing activity rather than an operating activity. In addition, Advances to Equity Affiliates of $(150) thousand were previously erroneously classified as an operating activity rather than an investing activity.

(b)

For 2011, relates to the $167 thousand of lease maintenance costs, exploration overhead and $62 thousand of certain investment costs that were improperly classified as an investing activity rather than an operating activity. In addition, Advances to Equity Affiliates of $(296) thousand were previously erroneously classified as an operating activity rather than an investing activity.

In addition to the above, we have restated our segment footnote information to reflect the applicable errors stated above and eliminate intrasegment receivables erroneously reported gross of related intrasegment payable.


	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	As Previously Reported			Adjustments			As RESTATED			As Previously Reported			Adjustments			As RESTATED
Segment Income (Loss) Attributable to Harvest
Venezuela^(a)	$	17,733		$	4		$	17,737		$	14,115		$	(74	)	$	14,041
Indonesia^(b)		(1,225	)		(353	)		(1,578	)		(1,596	)		—			(1,596	)
Gabon^(b)		(1,670	)		(52	)		(1,722	)		(717	)		(125	)		(842	)
Oman		(923	)		—			(923	)		(489	)		—			(489	)
United States^(c)		(4,766	)		(939	)		(5,705	)		(20,198	)		3,232			(16,966	)

Net income (loss) from continuing operations		9,149			(1,340	)		7,809			(8,885	)		3,033			(5,852	)
Discontinued operations (Antelope Project)^(d)		(989	)		(595	)		(1,584	)		98,665			—			98,665

Net income (loss) attributable to Harvest	$	8,160		$	(1,935	)	$	6,225		$	89,780		$	3,033		$	92,813

(a)	Represents a previously identified immaterial error.

(b)	Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense.

(c)

For 2012, represents change in the fair value of the Warrants for the reporting period and improper expensing of debt conversion costs and lease maintenance costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense. For 2011, represents (a) change in fair value of the Warrants for the reporting period, (b) understatement of interest expense and debt discount which resulted from the improper classification of the Warrants, (c) lease maintenance costs erroneously capitalized as oil and gas properties rather than expensed to exploration expense, and (d) for the period ended June 30, 2011, changes in the loss on extinguishment of debt due to the correction in discount on debt related to the improper classification of the Warrants.

(d)	Represents a previously identified classification error between income tax on discontinued operations and income tax on continuing operations.


	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	As Previously Reported			Adjustments			As RESTATED			As Previously Reported			Adjustments			As RESTATED
Segment Income (Loss) Attributable to Harvest
Venezuela^(a)	$	30,448		$	245		$	30,693		$	27,329		$	—		$	27,329
Indonesia^(b)		(3,701	)		(733	)		(4,434	)		(3,014	)		—			(3,014	)
Gabon^(b)		(2,985	)		(162	)		(3,147	)		(1,059	)		(235	)		(1,294	)
Oman		(6,531	)		—			(6,531	)		(1,045	)		—			(1,045	)
United States^(c)		(9,359	)		(338	)		(9,697	)		(26,748	)		(966	)		(27,714	)

Net income (loss) from continuing operations		7,872			(988	)		6,884			(4,537	)		(1,201	)		(5,738	)
Discontinued operations (Antelope Project)^(d)		(1,104	)		(595	)		(1,699	)		95,399			—			95,399

Net income (loss) attributable to Harvest	$	6,768		$	(1,583	)	$	5,185		$	90,862		$	(1,201	)	$	89,661

(a)	Represents a previously identified immaterial error.

(b)	Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense.

(c)

(d)	Represents a previously identified classification error between income tax on discontinued operations and income tax on continuing operations.


	June 30, 2012									December 31, 2011
	As Previously Reported			Adjustments			As RESTATED			As Previously Reported			Adjustments			As RESTATED
Operating Segment Assets
Venezuela^(a)	$	388,311		$	306		$	388,617		$	348,802		$	—		$	348,802
Indonesia^(b)		12,862			(2,240	)		10,622			65,165			(50,572	)		14,593
Gabon^(b)		56,211			(1,719	)		54,492			119,273			(63,768	)		55,505
Oman^(b)		6,535			—			6,535			20,980			(13,828	)		7,152
United States^(c)		253,594			(2,944	)		250,650			137,531			122,325			259,856

		717,513			(6,597	)		710,916			691,751			(5,843	)		685,908
Intersegment eliminations		(202,140	)		—			(202,140	)		(178,704	)		(1	)		(178,705	)

Total Assets	$	515,373		$	(6,597	)	$	508,776		$	513,047		$	(5,844	)	$	507,203

(a)	Represents a previously identified immaterial error.

(b)	Relates to the elimination of intrasegment receivables erroneously reported gross of related intrasegment payable.

(c)	Relates to the elimination of intrasegment receivables erroneously reported gross of related intrasegment payable and a deferred tax asset that was erroneously reported gross of the related liability.

Principles of Consolidation

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

Presentation of Comprehensive Income

In June 2011, the Financial Accounting Standards Board’s (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-05 (ASU 2011-05), which is included in Accounting Standards Codification (“ASC”) 220, “Comprehensive Income” (“ASC 220”). This update requires that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. We adopted ASU 2011-05 effective January 1, 2012 and have elected to utilize the “single continuous statement” for presentation.

Reporting and Functional Currency

The United States Dollar (“U.S. Dollar”) is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. Amounts denominated in non-U.S. Dollar currencies are re-measured into U.S. Dollars, and all currency gains or losses are recorded in the consolidated condensed statement of operations and comprehensive income (loss). There are many factors that affect foreign exchange rates and the resulting exchange gains and losses, many of which are beyond our influence.

See Note 9 – Venezuela for a discussion of currency exchange risk on Harvest Vinccler’s and Petrodelta’s businesses.

Cash and Cash Equivalents

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

Restricted Cash

Restricted cash is classified as current or non-current based on the terms of the agreement. Restricted cash at December 31, 2011 represents cash held in a U.S. bank used as collateral for a standby letter of credit issued as a payment guarantee for electric wireline services to be provided during the drilling of the two exploratory wells on the Block 64 EPSA (see Note 13 – Oman). Drilling of the wells was completed in the first quarter of 2012 and the restricted cash returned to us on April 18, 2012.

Financial Instruments

Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents, accounts receivable and notes payable. 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.

Current portion of long-term debt at June 30, 2012 consisted of $15.6 million of fixed-rate unsecured senior convertible notes maturing on March 1, 2013 unless earlier redeemed, purchased or converted. Total long-term debt at December 31, 2011 consisted of $31.5 million of fixed-rate unsecured senior convertible notes maturing on March 1, 2013 unless earlier redeemed, purchased or converted. See Note 5 – Long-Term Debt.

Notes Receivable

Notes receivable 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 ASU 2010-20, which is included in ASC 310, “Receivables”. 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.

Our note receivable relates to a prospect leasing cost financing arrangement. The note receivable plus accrued interest was approximately $3.3 million at December 31, 2011, and was secured by a portion of the production from the Bar F #1-20-3-2 in Utah. See Note 6 – Commitments and Contingencies for a discussion of the settlement of the note receivable.

Other Assets

Other assets consist of investigative costs associated with new business development projects, deferred financing costs and a long-term receivable for value added tax (“VAT”) credits related to the Budong PSC. Investigative costs are reclassified to oil and gas properties or expensed depending on management’s assessment of the likely outcome of the project. Deferred financing costs relate to specific financing and are amortized over the life of the financing to which the costs relate. See Note 5 – Long-Term Debt. The VAT receivable is reimbursed through the sale of hydrocarbons (see Note 11 – Indonesia for development plans for the Budong PSC).

At June 30, 2012, other assets consisted of $0.9 million of investigative costs, $0.3 million of deferred financing costs and $3.7 million of long-term VAT receivable. At December 31, 2011, other assets consisted of $0.4 million of investigative costs, $1.0 million of deferred financing costs and $3.3 million of long-term VAT receivable. During the six months ended June 30, 2012, $0.3 million of investigative costs were reclassified to expense.

Other Assets at June 30, 2012 also includes a blocked payment of $0.7 million (December 31, 2011: $0.7 million) net to our 66.667 percent interest related to our drilling operations in Gabon in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”). See Note 6 – Commitments and Contingencies.

Investment in Equity Affiliates

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

There are many factors to consider when evaluating an equity investment for possible impairment. Currency devaluations, inflationary economies, slow pay of dividends and cash flow analysis are some of the factors we consider in our evaluation for possible impairment. At June 30, 2012, there were no events that would indicate that our equity investment in Petrodelta had sustained a loss in value that is other than temporary.

Property and Equipment

We use the successful efforts method of accounting for oil and gas properties. The major components of property and equipment are as follows:


	June 30, 2012			December 31, 2011
	(in thousands)
	(RESTATED*)			(RESTATED*)

Unproved property costs	$	62,915		$	59,626
Oilfield inventories		3,102			2,829
Other administrative property		3,192			3,176

		69,209			65,631
Accumulated depreciation and amortization		(2,258	)		(2,048	)

	$	66,951		$	63,583

*	See Note 2 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements.

Capitalized Interest

We capitalize interest costs for qualifying oil and gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation. During the three and six months ended June 30, 2012, we capitalized interest costs of $0.5 million and $1.2 million, respectively, for qualifying oil and gas property additions. During the three and six months ended June 30, 2011, we capitalized interest costs of $0.1 million and $1.0 million, respectively, for qualifying oil and gas property.

Derivative Financial Instruments

Under ASC 480 “Distinguishing Liabilities From Equity”, certain of our financial instruments with anti-dilution protection features do not meet the conditions to obtain equity classification, as there are conditions which may require settlement by transferring assets, and are required to be carried as derivative liabilities, at fair value, with changes in fair value reflected in our consolidated condensed statements of operations and comprehensive income (loss). See Note 16 – Warrant Derivative Liabilities for additional disclosures. In the occurrence of a fundamental change, we are required to repurchase the Warrants at the higher of (1) the fair market value of the warrant and (2) a valuation based on a computation of the option value of the Warrant using the Black-Scholes calculation method using the assumptions described in the Warrant Agreement. A fundamental change is defined as “the occurrence of one of the following events: a) a person or group becomes the direct or indirect owner of more than 50% of the voting power of the outstanding common stock, b) a merger event or similar transaction in which the majority owners before the transaction fail to own a majority of the voting power of the Company after the transaction, and c) approval of a plan of liquidation or dissolution of the Company or sale of all or substantially all of the Company’s assets.”

Fair Value Measurements

We measure and disclose our fair values in accordance with the provisions of ASC 820 “Fair Value Measurements and Disclosures” (“ASC 820”). ASC 820 defines fair value as 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). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable.

Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument with related changes in internal and external market factors. In addition, option-based techniques (such the Monte Carlo model) are highly volatile and sensitive to changes in the trading market price of our common stock. Since derivative financial instruments are initially and subsequently carried at fair value, our (income) loss will reflect the volatility in these estimate and assumption changes.

Inherent in the Monte Carlo valuation model are assumptions related to expected stock price volatility, expected life, risk-free interest rate and dividend yield. We estimate the volatility of our common stock based on historical volatility that matched the expected remaining life of the warrants. The risk-free interest rate is based on the U.S. Treasury yield curve as of the valuation dates for a maturity similar to the expected remaining life of the warrants. The expected life of the warrants is assumed to be equivalent to their remaining contractual term. The dividend rate is based on the historical rate, which we anticipate to remain at zero.

As part of our overall valuation process, management employs processes to evaluate and validate the methodologies, techniques and inputs, including review and approval of valuation judgments, methods, models, process controls, and results. These processes are designed to help ensure that the fair value measurements and disclosures are appropriate, consistently applied, and reliable.

The Monte Carlo model is used on the warrants to appropriately value the potential future exercise price adjustments triggered by the anti-dilution provisions. See Note 16 – Warrant Derivative Liability. This requires Level 3 inputs which are based on our estimates of the probability and timing of potential future financings and fundamental transactions. The assumptions we used are summarized in the following tables for warrants that were outstanding as of any of the balance sheet dates presented on our consolidated condensed balance sheets:


		June 30, 2012			December 31, 2011
Significant assumptions (or ranges):
Trading market values	Level 1 input	$	8.55		$	7.38
Term (years)			3.33			3.83
Volatility	Level 2 input		75	%		70	%
Risk-free rate	Level 1 input		0.46	%		0.55	%
Dividend yield	Level 2 input		0.0	%		0.0	%
Scenario probability debt/equity raise	Level 3 input		80% / 20	%		80% / 20	%

*	See Note 2 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements.

The following tables set forth by level within the fair value hierarchy our financial liabilities that were accounted for at fair value as of June 30, 2012 and December 31, 2011. As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.


	June 30, 2012
	Level 1		Level 2		Level 3		Total
	(in thousands)
Liabilities
Warrant derivative liabilities	$	—	$	—	$	6,079	$	6,079

Total liabilities	$	—	$	—	$	6,079	$	6,079


	December 31, 2011
	Level 1		Level 2		Level 3		Total
	(in thousands)
Liabilities
Warrant derivative liabilities	$	—	$	—	$	4,870	$	4,870

Total liabilities	$	—	$	—	$	4,870	$	4,870

*	See Note 2 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements.

We record the net change in the fair value of the derivative positions listed above in unrealized gain (loss) on warrant derivative liabilities in our consolidated condensed statements of operations and comprehensive income (loss). During the three months ended June 30, 2012, an unrealized loss of $1.6 million was recorded to reflect the change in fair value of the warrants (three months ended June 30, 2011: $7.1 million unrealized gain). During the six months ended June 30, 2012, an unrealized loss of $1.2 million was recorded to reflect the change in fair value of the warrants (six months ended June 30, 2011: $4.5 million unrealized gain).

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The following table presents the estimated fair values of our fixed interest rate, long-term debt instrument (Level 2) as of June 30, 2012.


	June 30, 2012
	Carrying Value		Fair Value
	(in thousands)

8.25% senior unsecured convertible notes (Level 2)	$	15,551	$	22,100

The fair value of our fixed interest debt instruments (Level 2) is based on the most recent market trades of the debt and weighted by the size of the trades.

Changes in Level 3 Instruments Measured at Fair Value on a Recurring Basis

The following table provides a reconciliation of financial liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3).


	June 30, 2012		December 31, 2011
	(in thousands)
Financial liabilities:
Beginning balance	$	4,870	$	14,656
Unrealized change in fair value		1,209		(9,786	)

Ending balance	$	6,079	$	4,870

*	See Note 2 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements.

During the six months ended June 30, 2012, there were no transfers between Level 1, Level 2 and Level 3 liabilities.

Noncontrolling Interests

Changes in noncontrolling interest were as follows:


	Six Months Ended June 30,
	2012		2011
	(in thousands)
	(RESTATED*)

Balance at beginning of period	$	83,678	$	69,501
Net income attributable to noncontrolling interest		7,862		7,058

Balance at end of period	$	91,540	$	76,559

*	See Note 2 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements.

Earnings Per Share

Basic earnings per common share (“EPS”) are computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that would occur if securities or other contracts to issue common stock were exercised or converted into common stock.


	Three Months Ended June 30,
	2012			2011
	(in thousands, except per share data)
	(RESTATED*)			(RESTATED*)

Income (loss) from continuing operations^(a)	$	7,809		$	(5,852	)
Discontinued operations		(1,584	)		98,665

Net income attributable to Harvest	$	6,225		$	92,813


Weighted average common shares outstanding		37,375			34,039
Effect of dilutive securities		3,424			—

Weighted average common shares, diluted		40,799			34,039


Basic Earnings (Loss) Per Share:
Income (loss) from continuing operations	$	0.21		$	(0.17	)
Income (loss) from discontinued operations		(0.04	)		2.90

Basic earnings per share	$	0.17		$	2.73


Diluted Earnings (Loss) Per Share:
Income (loss) from continuing operations	$	0.19		$	(0.17	)
Income (loss) from discontinued operations		(0.04	)		2.90

Diluted earnings per share	$	0.15		$	2.73


	Six Months Ended June 30,
	2012			2011
	(in thousands, except per share data)
	(RESTATED*)			(RESTATED*)

Income (loss) from continuing operations^(a)	$	6,884		$	(5,738	)
Discontinued operations		(1,699	)		95,399

Net income attributable to Harvest	$	5,185		$	89,661


Weighted average common shares outstanding		36,130			33,992
Effect of dilutive securities		1,469			—

Weighted average common shares, diluted		37,599			33,992


Basic Earnings (Loss) Per Share:
Income (loss) from continuing operations	$	0.19		$	(0.16	)
Income (loss) from discontinued operations		(0.05	)		2.80

Basic earnings per share	$	0.14		$	2.64


Diluted Earnings (Loss) Per Share:
Income (loss) from continuing operations	$	0.18		$	(0.16	)
Income (loss) from discontinued operations		(0.04	)		2.80

Diluted earnings per share	$	0.14		$	2.64

^(a)	Net of income attributable to noncontrolling interest.

*	See Note 2 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements.

The three months ended June 30, 2012 per share calculations above exclude 3.7 million options and 1.7 million warrants because they were anti-dilutive. The three months ended June 30, 2011 per share calculations above exclude 3.8 million options and 1.6 million warrants because they were anti-dilutive.

The six months ended June 30, 2012 per share calculations above exclude 3.7 million options and 1.7 million warrants because they were anti-dilutive. The six months ended June 30, 2011 per share calculations above exclude 3.7 million options and 1.6 million warrants because they were anti-dilutive.

Note 3 – Risks, Uncertainties, Capital Resources and Liquidity

The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. There are a number of variables and risks related to our exploration projects that could significantly utilize our cash balances, and affect our capital resources and liquidity.

The environments in which we operate are often difficult and the ability to operate successfully depends on a number of factors including our ability to control the pace of development, our ability to apply “best practices” in drilling and development, and the fostering of productive and transparent relationships with local partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, often the legal systems of certain countries are not mature and their reliability can be uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and natural gas projects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy depends on our ability to have significant influence over operations and financial control.

Our operations are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and governmental royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts or tribunals, renegotiation of contracts with governmental entities, changes in laws and policies, including taxes, governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign policy, foreign trade, taxation and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States.

There are also a number of variables and risks related to our minority equity investment in Petrodelta that could significantly utilize our cash balances, and affect our capital resources and liquidity. Petrodelta’s capital commitments are determined by its business plan, and Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. The total capital required to develop the fields in Venezuela may exceed Petrodelta’s available cash and financing capabilities, and there may be operational or contractual consequences due to this inability. Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Due to PDVSA’s liquidity constraints, PDVSA has not been providing the necessary monetary and contractual support required by Petrodelta. If we are called upon to fund our share of Petrodelta’s operations, our failure to do so could be considered a default under the Conversion Contract and cause the forfeiture of some or all our shares in Petrodelta.

Petrodelta also has a material impact on our results of operations for any quarterly or annual reporting period. See Note 10 – Investment in Equity Affiliate – Petrodelta. Petrodelta operates under a business plan, the success of which relies heavily on the market price of oil. To the extent that market prices of oil decline, the business plan, and thus our equity investment and/or operations and/or profitability, could be adversely affected.

Operations in Venezuela are subject to various risks inherent in foreign operations. It is possible the legal or fiscal framework for Petrodelta could change and the Venezuela government may not honor its commitments. Our ability to implement or influence Petrodelta’s business plan, assure quality control and set the timing and pace of development could also be adversely impacted. No assurance can be provided that events beyond our control will not adversely affect the value of our minority investment in Petrodelta.

On June 21, 2012, we and our wholly owned subsidiary HNR Energia entered into a share purchase agreement (the “SPA”) with PT Pertamina (Persero), a state-owned limited liability company existing under the laws of Indonesia (“Buyer”) for the sale of our interest in Venezuela for a cash purchase price of $725.0 million. See Note 9 – Venezuela, Share Purchase Agreement. We cannot assure you that the SPA will be consummated. The consummation of the SPA is subject to the satisfaction or waiver of a number of conditions, including, among others, the requirement that approvals are received from the Government of the Bolivarian Republic of Venezuela, the Government of the Republic of Indonesia, and the majority of our stockholders; requirements with respect to the accuracy of the representations and warranties of the parties to the SPA; and requirements with respect to the satisfaction or waiver of the covenants and obligations of the parties to the SPA. In addition, the SPA may be terminated in certain circumstances under the terms of the SPA. We cannot guarantee that the parties to the SPA will be able to meet all of the closing conditions of the SPA. If we are unable to meet all of the closing conditions, the Buyer would not be obligated to close the SPA. We also cannot be sure that circumstances, such as a material

adverse effect, will not arise that would also allow the Buyer to terminate the SPA prior to closing. If the SPA does not close, our Board of Directors will be forced to evaluate other alternatives, which may be less favorable to us than the SPA. There can be no assurances as to whether this transaction will close or whether we will receive any cash proceeds related to the SPA.

Our cash is being used to fund oil and gas exploration projects, debt, interest, and to a lesser extent general and administrative costs. We require capital principally to fund the exploration and development of new oil and gas properties. As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. We do not have any remaining work commitments for the current exploration phases of the Budong PSC or Block 64 EPSA. We entered the third exploration phase of the Dussafu PSC on May 28, 2012. The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period (see Note 12 – Gabon). This work commitment is non-discretionary; however, we do have the ability to control the pace of expenditures. On July 17, 2012, we signed a contract for a semi-submersible drilling rig to drill an exploration well on the Gabon PSC. In the event that we elect to terminate the contract prior to the rig’s arrival on-site, we are obligated to compensate the drilling company $5.0 million ($3.3 million net to our 66.667 percent interest) for liquidated damages (see Note 16 – Subsequent Events).

Historically, our primary ongoing source of cash has been dividends from Petrodelta and the sale of oil and gas properties. On May 17, 2011, we closed the transaction to sell the Antelope Project. The transaction had an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflected increases to the purchase price for customary adjustments and deductions for transaction related costs (see Note 4 – Dispositions).

Between Petrodelta’s formation in October 2007 and June 2010, Petrodelta declared and paid dividends of $105.5 million to HNR Finance, B.V. (“HNR Finance”), a wholly owned subsidiary of Harvest Holding ($84.4 million net to our 32 percent interest). In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, this dividend has not yet been received, although it is due and payable. There is uncertainty of the timing of receipt of the dividend receivable from Petrodelta and whether Petrodelta will declare or pay additional dividends in 2012 or 2013. See Note 14 – Related Party Transactions for a discussion of our obligations to our non-controlling interest holder, Vinccler, for any dividend received from Petrodelta. Also, any receipt of dividends while the SPA is active would become a purchase price adjustment under the SPA. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable not be collected timely, or facts and circumstances surrounding our investment change, our results of operations and our investment in Petrodelta could be adversely impacted. If facts and circumstances change, it is possible we could conclude our investment in Petrodelta should be accounted for using the cost method of accounting rather than the equity method of accounting. If that were to occur, the operations of Petrodelta would no longer be included in our results of operations.

Currently, our source of cash is expected to be generated by accessing the debt and/or equity markets. On March 30, 2012, we announced that we had entered into an equity distribution agreement (the “Agreement”) with Knight Capital America, L.P. (“KCA”), a subsidiary of Knight Capital Group, Inc. relating to an “at-the-market” (“ATM”) offering of shares of our common stock having an aggregate sales price of up to $75.0 million. Under the terms of the Agreement, we may offer and sell shares of our common stock by means of transactions on the New York Stock Exchange (“NYSE”) or otherwise at market prices prevailing at the time of sale, at prices related to the prevailing market price or at negotiated rates. We are unable to access the ATM during blackout periods or when we are in possession of material information which has not been made public. As of June 30, 2012, we have not accessed the ATM.

We incurred debt during 2010 which has imposed restrictions on us and increased our vulnerability to adverse economic and industry conditions. Our senior convertible notes impose restrictions on us that limit our ability to obtain additional financing. Our ability to meet these covenants is primarily dependent on meeting customary affirmative covenant clauses. Our inability to satisfy the covenants contained in our senior convertible notes would constitute an event of default, if not waived. An uncured default could result in the senior convertible notes becoming immediately due and payable. If this were to occur, we may not be able to obtain waivers or secure alternative financing to satisfy our obligations, either of which would have a material adverse impact on our business. As of June 30, 2012, we were in compliance with all of our long term debt covenants.

Our senior convertible notes are due March 1, 2013. As of June 30, 2012, $16.5 million of the senior convertible notes had been converted into, or exchanged for, shares of our common stock. If the remaining debt is not converted or is only partially converted, we will be required to refinance the debt. Due to our current liquidity position, any debt instrument available to us is likely to have a substantial interest rate and/or provide for additional dilution to shareholders. There can be no assurances we will be able to refinance the debt on terms that are acceptable to us. If we are unable to obtain additional debt and/or equity sources, convert or exchange the senior convertible notes, or receive the Petrodelta dividend or our cash sources and requirements are different than expected, it will have a material adverse effect on our operations.

In order to increase our liquidity to levels sufficient to meet our commitments, we continue to seek to secure additional capital to fund operations, to meet future expenditure requirements necessary to retain our rights under our PSCs and to pay remaining amounts due under our senior convertible notes to the extent the convertible notes are not subsequently exchanged for shares prior to their maturity date. We plan to secure capital by obtaining debt or project financing or refinancing or extending existing debt, or, if acceptable debt or project financing or refinancing is unavailable, by obtaining equity related financing, or exploring potential strategic relationships or transactions involving one or more of our PSCs, such as a joint venture, farmout, merger, or sale of some or all of our assets. While we will continue to seek to secure capital, there can be no assurance that we will be able to enter any strategic relationship or transaction or that we will be successful in obtaining funds through debt, project finance or equity related financing or refinancing, or extending existing debt. Under certain circumstances, the structure of a strategic transfer of our rights under any PSC will require the approval of the governments of the countries in which we operate. In addition, the terms and conditions of any potential strategic relationship or transaction or of any debt or equity related financing is uncertain. Raising additional funds by issuing shares or other types of equity securities would further dilute our existing stockholders. We cannot predict the timing, structure or other terms and conditions of any such arrangements or the consideration that may be paid with respect to any transaction and whether the consideration will meet or exceed our offering price. Our lack of revenues, cash inflows and the unpredictability of cash dividends from Petrodelta could make it difficult to obtain financing and, accordingly, there is no assurance adequate financing can be raised and/or on terms acceptable to us.

Our ability to continue as a going concern depends upon the success of our planned exploration and development activities and the ability to secure additional financing to secure our current operations. There can be no guarantee of future capital acquisition, fundraising or explorations success or that we will realize the value of our unevaluated exploratory well costs. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty. We believe that we will continue to be successful in securing any funds necessary to continue as a going concern. However, our current cash position and our ability to access additional capital may limit our available opportunities or not provide sufficient cash for operations.

Note 4 – Dispositions

Discontinued Operations

On May 17, 2011, we closed the transaction to sell the Antelope Project. The sale had an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale was reported in discontinued operations in the second quarter of 2011.

During the six months ended June 30, 2012, we incurred $0.1 million of expense related to settlement of royalty payments to the Mineral Management Services, write-offs of $5.2 million of accounts and note receivable and $3.6 million of accounts payable and carry obligation related to the settlement of all outstanding claims with a private third party on the Antelope Project (see Note 2 – Summary of Significant Accounting Policies, Notes Receivable and Note 6 – Commitments and Contingencies).

Revenue and net loss on the disposition of the Antelope Project are shown in the table below:


	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
	(in thousands)
	(RESTATED*)					(RESTATED*)

Revenue applicable to discontinued operations	$	—		$	2,368	$	—		$	6,488
Net income (loss) from discontinued operations	$	(1,584	)	$	98,665	$	(1,699	)	$	95,399

*	See Note 2 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements.

Note 5 – Long-Term Debt

Long-Term Debt

Long-term debt consists of the following:


	June 30, 2012		December 31, 2011
	(in thousands)
Senior convertible notes, unsecured, with interest at 8.25%
See description below	$	15,551	$	31,535
Less current portion		15,551		—

Long term portion	$	—	$	31,535

On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. Under the terms of the notes, interest is payable semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2010. The senior convertible notes mature on March 1, 2013, unless earlier redeemed, repurchased or converted. The notes are convertible into shares of our common stock at a conversion rate of 175.2234 shares of common stock per $1,000 principal amount of senior convertible notes, equivalent to a conversion price of approximately $5.71 per share of common stock. The notes are general unsecured obligations, ranking equally with all of our other unsecured senior indebtedness, if any, and senior in right of payment to any of our subordinated indebtedness, if any. The notes are also redeemable in certain circumstances at our option and may be repurchased by us at the purchaser’s option in connection with occurrence of certain events.

On October 12, 2011, $0.5 million of the senior convertible notes were converted into 0.1 million shares of common stock at a conversion rate of $5.71 per share. On March 14, 2012, $16.0 million of the senior convertible notes were exchanged for 2.9 million shares of common stock at an effective exchange price of $5.56 per share. In addition, the exchanging holders were issued 0.2 million shares of common stock at $8.16 per share in exchange for foregoing a one-year interest make-whole of $1.3 million.

Financing costs associated with the senior convertible notes offering are being amortized over the remaining life of the notes and are recorded in other assets. The balance for financing costs was $0.3 million at June 30, 2012 (December 31, 2011: $1.0 million).

Note 6 – Commitments and Contingencies

In June 2012, the operator of the Budong PSC received notice of a claim related to the ownership of part of the land comprising the Karama-1 (“KD-1”) drilling site. The claim asserts that the land on which the drill site is located is partly owned by the claimant. The operator purchased the site from local landowners in January 2010, and the purchase was approved by BPMIGAS. The claimant is seeking compensation of 16 billion Indonesia Rupiah (approximately $1.7 million, $1.1 million net to our 64.51 percent cost sharing interest) for land that was purchased at a cost of $4,100 in January 2010. A formal mediation hearing to assess the conflicting claims of ownership is scheduled for August 9, 2012. We and the Budong PSC operator dispute the landowner’s claim and plan to vigorously defend against it.

locations constructed by Harvest were built on, within, or otherwise impact or potentially impact wetlands and other water bodies. The notice asserts that to the extent of potential penalties or other obligations that might result from potential violations that Harvest US indemnifies Newfield pursuant to the PSA. In June 2012, we provided Newfield with notice pursuant to the PSA (1) denying that Newfield has any right to indemnification from us, (2) alleging that any potential environmental claim related to Newfield’s notice would be an assumed liability under the PSA and (3) asserting that Newfield indemnify us pursuant to the PSA. We dispute Newfield’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.

In October 2007, we entered into a Joint Exploration and Development Agreement (“JEDA”) with a private third party with respect to the Antelope Project. On January 11, 2011, in connection with the sale of each party’s interests in the Antelope Project (see Note 4 – Dispositions), we entered into a letter agreement with the private third party wherein the private third party agreed to reimburse us for certain expenses related to the sale of the two parties’ interests in the Antelope Project. The private third party disputes our calculation of the amount owed to us pursuant to the January 11, 2011 letter agreement. On March 11, 2011, we entered into a letter agreement with the private third party regarding certain obligations between the parties related to the JEDA. The private third party disputes our calculation of the amount due pursuant to one of the items in the March 11, 2011 letter agreement. At March 31, 2012, we had a note receivable outstanding from the private third party of $3.3 million (see Note 2 – Summary of Significant Accounting Policies, Notes Receivable), an account receivable from the private third party of $2.7 million, and an account payable outstanding to the private third party of $3.6 million related to the purchase in July 2010 of an incremental 10 percent interest in the Antelope Project. On June 13, 2012, the parties agreed to settle all outstanding claims for $0.8 million net account receivable to Harvest, which resulted in a $1.6 million loss recorded in discontinued operations.

On May 31, 2011, the United Kingdom branch of our subsidiary, Harvest Natural Resources, Inc. (UK), initiated a wire transfer of approximately $1.1 million ($0.7 million net to our 66.667 percent interest) intending to pay Libya Oil Gabon S.A. (“LOGSA”) for fuel that LOGSA supplied to our subsidiary in the Netherlands, Harvest Dussafu, B.V., for the company’s drilling operations in Gabon. On June 1, 2011, our bank notified us that it had been required to block the payment in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by OFAC, because the payee, LOGSA, may be a blocked party under the sanctions. The bank further advised us that it could not release the funds to the payee or return the funds to us unless we obtain authorization from OFAC. On October 26, 2011, we filed an application with OFAC for return of the blocked funds to us. Unless that application is approved, the funds will remain in the blocked account, and we can give no assurance when, or if, OFAC will permit the funds to be released. As of August 3, 2012, our October 26, 2011 application for the return of the blocked funds remains pending with OFAC.

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

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

•

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

•

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

•

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

•

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

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

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

•

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

•

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

•

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

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

On May 4, 2012, Harvest Vinccler learned that the Political Administrative Chamber of the Supreme Court of Justice has issued a decision dismissing one of Harvest Vinccler’s claims against the Libertador Municipality. Harvest Vinccler continues to believe that it has sufficient arguments to maintain its position in accordance to the Venezuelan Constitution. Harvest Vinccler plans to present a request of Constitutional Revision to the Constitutional Chamber of the Supreme Court of Justice once it is notified officially of the decision. As of August 3, 2012, Harvest Vinccler has not received official notification of the decision. Harvest Vinccler is unable to predict the impact of this decision on the remaining outstanding municipality claims and assessments.

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 7 – Taxes

Taxes on Income

We have recorded a tax benefit in the second quarter of 2012 as a result of the projected U.S. tax loss from operations for the year 2012. The amount of benefit is limited to the amount of the loss that is expected to be

utilized. Although we have not yet filed our 2011 U.S. corporate income tax return, we are anticipating taxable income for that year of approximately $10.3 million. Therefore, the loss carryback benefit is $3.6 million, utilizing the U.S. tax rate of 35 percent. On a worldwide basis, this resulted in an overall tax benefit of $2.2 million.

Our effective tax rate is low compared to the U.S. statutory rate due to the lower statutory tax rates in the foreign jurisdictions where we are doing business and incurring income tax expense. The effective tax rate is further diluted when the overall tax benefit resulting from the U.S. tax loss is compared to our worldwide loss.

Note 8 – Operating Segments

We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Operations included under the heading “United States” 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 segment and are not allocated to other operating segments:


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
	(RESTATED*)			(RESTATED*)			(RESTATED*)			(RESTATED*)
Segment Income (Loss) Attributable to Harvest
Venezuela	$	17,737		$	14,041		$	30,693		$	27,329
Indonesia		(1,578	)		(1,596	)		(4,434	)		(3,014	)
Gabon		(1,722	)		(842	)		(3,147	)		(1,294	)
Oman		(923	)		(489	)		(6,531	)		(1,045	)
United States		(5,705	)		(16,966	)		(9,697	)		(27,714	)

Net income (loss from continuing operations		7,809			(5,852	)		6,884			(5,738	)
Discontinued operations (Antelope Project)		(1,584	)		98,665			(1,699	)		95,399

Net income attributable to Harvest	$	6,225		$	92,813		$	5,185		$	89,661


	June 30, 2012			December 31, 2011
	(in thousands)
	(RESTATED*)			(RESTATED*)
Operating Segment Assets
Venezuela	$	388,617		$	348,802
Indonesia		10,622			14,593
Gabon		54,492			55,505
Oman		6,535			7,152
United States		250,650			259,856

		710,916			685,908
Intersegment eliminations		(202,140	)		(178,705	)

Total Assets	$	508,776		$	507,203

*	See Note 2 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements.

Note 9 – Venezuela

Share Purchase Agreement (“SPA”)

On June 21, 2012, we and our wholly owned subsidiary HNR Energia entered into a share purchase agreement (the “SPA”) with PT Pertamina (Persero), a state-owned limited liability company existing under the laws of Indonesia (“Buyer”). HNR Energia is a private company with limited liability under the laws of Curacao. HNR Energia owns 80 percent of the equity interest of Harvest Holding, which owns 40 percent of the equity interest of Petrodelta. Vinccler, who owns the other 20 percent equity interest of Harvest Holding, is not a party to the transaction.

Under the SPA, HNR Energia will sell all of its 80 percent interest in Harvest Holding to Buyer or a newly formed wholly owned subsidiary of Buyer for a cash purchase price of $725.0 million, subject to adjustment as described in the SPA. The sale of Harvest Holding, including its direct and indirect subsidiaries, will constitute the sale of all of our interest in Venezuela, which consists of our indirect 32 percent interest in Petrodelta and our indirect 80 percent interest in Harvest Vinccler. The effective date of the transaction is January 1, 2012. We have also executed a guarantee in Buyer’s favor by which we guarantee HNR Energia’s obligations under the SPA.

The closing of the transaction is subject to receipt of three approvals, in addition to satisfaction of other conditions standard in transactions of this type: (a) approval by the Ministerio del Poder Popular de Petroleo y Mineria representing the Government of the Bolivarian Republic of Venezuela (which indirectly owns the other 60 percent interest in Petrodelta); (b) approval by the Government of the Republic of Indonesia in its capacity as Buyer’s sole shareholder; and (c) approval by the holders of a majority of Harvest’s common stock. If the approval of Buyer’s shareholder is not obtained within five months after the date of the SPA, we may terminate the SPA. If the approval of Harvest’s stockholders is not obtained within 90 days after approval of Buyer’s shareholder is obtained, Buyer may terminate the SPA.

Contemporaneously with signing the SPA, Buyer deposited $108.8 million, or 15 percent of the $725.0 million purchase price, in escrow. The deposit constitutes liquidated damages, and if Buyer defaults, our sole remedy is to retain the deposit and any earned interest. The deposit and any earned interest will be returned to Buyer if the SPA is terminated for any other reason, including if the approval by our stockholders, Buyer’s shareholder or the Government of Venezuela is not obtained. The purchase deposit was received by the escrow agent on June 22, 2012.

We have agreed not to solicit other offers to acquire Harvest as a whole or the Petrodelta assets while the SPA is in effect. If we receive an unsolicited superior proposal before our stockholders have approved the transaction, we may enter into discussions with the potential purchaser. We have the right to terminate the SPA and accept a superior proposal if we first offer Buyer the opportunity to modify the transaction so that the competing offer is no longer superior and pay Buyer a break-up fee equal to $21.8 million, or three percent of the purchase price.

Under the SPA, the parties will meet during the week of September 5, 2012, to assess progress toward obtaining the required governmental approvals and satisfaction of other conditions to closing. At that time, HNR Energia or Buyer may terminate the SPA without surrender of Buyer’s deposit or payment of any break-up fee.

The SPA includes representations and warranties, tax provisions and indemnification provisions typical in transactions of this type. Reference should be made to the SPA regarding those provisions and all other provisions pertinent to a complete understanding of the transaction.

Operations

Harvest Vinccler’s and Petrodelta’s functional and reporting currency is the U.S. Dollar. They do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”) (4.30 Bolivars per U.S. Dollar). However, during the three months ended June 30, 2012, Harvest Vinccler exchanged approximately $0.4 million (three months ended June 30, 2011: $0.1 million) through the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) and received an average exchange rate of 5.10 Bolivars (three months ended June 30, 2011: 5.21 Bolivars) per U.S. Dollar. During the six months ended June 30, 2012, Harvest Vinccler exchanged approximately $0.6 million (six months ended June 30, 2011: $0.4 million) through SITME and received an average exchange rate of 5.13 Bolivars (six months ended June 30, 2011: 5.19 Bolivars) per U.S. Dollar. Harvest Vinccler currently does not have any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. Petrodelta does not have, and has not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate.

The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals

and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. At June 30, 2012, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 5.0 million Bolivars and 7.2 million Bolivars, respectively. At June 30, 2012, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 227.8 million Bolivars and 2,696.5 million Bolivars, respectively.

On May 7, 2012, the Organic Law on Employment, Male and Female Workers (“Labor Law”) was published in the Official Gazette, the official government publication where laws, decrees, resolutions, instructions, and other regulations of general interest issued by the central government of Venezuela are published in order to make those acts valid and official. The Labor Law has 554 Articles divided into ten Titles and heavily favors employees over employers. After much analysis, Harvest Vinccler estimates that there will be little if any financial impact on its business from the Labor Law, and Petrodelta has estimated the financial impact of the Labor Law on its business to be approximately $0.2 million ($0.1 million net to our 32 percent interest).

Note 10 – Investment in Equity Affiliate – Petrodelta

As discussed in previous filings, PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors, including Harvest Vinccler. As a result, Petrodelta has experienced, and is continuing to experience, difficulty in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is having an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.

Harvest Vinccler has advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, operations, seismic interpretation, and employee salaries and related benefits for Harvest Vinccler employees seconded into Petrodelta. Currently, we have three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. Harvest Vinccler is considered a contractor to Petrodelta, and as such, Harvest Vinccler is also experiencing the slow payment of invoices. During the six months ended June 30, 2012, Harvest Vinccler advanced to Petrodelta $0.2 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advance. Advances to equity affiliate have increased slightly to a balance of $2.5 million as of June 30, 2012. During the year ended December 31, 2011, we advanced Petrodelta $0.8 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advances. Although payment is slow and the balance is increasing, payments continue to be received.

In April 2011, the Venezuelan government published in the Official Gazette the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (“Windfall Profits Tax”). Windfall Profits Tax is deductible for Venezuelan income tax purposes. During the three months ended June 30, 2012, Petrodelta recorded $74.7 million for Windfall Profits Tax (three months ended June 30, 2011: $65.3 million). During the six months ended June 30, 2012, Petrodelta recorded $159.4 million for Windfall Profits Tax (six months ended June 30, 2011: $92.5 million).

One section of the Windfall Profits Tax states that royalties paid to Venezuela are capped at $70 per barrel, but the cap on royalties has not been defined as being applicable to in-cash, in-kind, or both. In October 2011, Petrodelta received instructions from PDVSA that royalties, whether paid in-cash or in-kind, should be reported at $70 per barrel (royalty barrels x $70). The difference between the $70 royalty cap and the current oil price is to be reflected on the income statement as a reduction in oil sales. For the three months ended June 30, 2012 and 2011, the reduction to oil sales due to the $70 cap applied to all royalty barrels was $28.9 million and $29.4 million ($9.2 million and $9.4 million net to our 32 percent interest), respectively. For the six months ended June 30, 2012 and 2011, the reduction to oil sales due to the $70 cap applied to all royalty barrels was $67.4 million and $44.7 million ($21.6 million and $14.3 million net to our 32 percent interest), respectively.

percent royalty paid in cash and the current oil sales price to the 30 percent royalty paid in-kind for the three and six months ended June 30, 2012 and 2011. With assistance from Petrodelta, we have recalculated Petrodelta’s oil sales and royalties to apply the current oil price to its total barrels produced and to the 30 percent royalty paid in-kind and applied the $70 cap to the 3.33 percent royalty paid in cash for the three and six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012 and 2011, net oil sales (oil sales less royalties) are slightly higher, $2.9 million and $2.9 million ($0.9 million and $0.9 million net to our 32 percent interest), respectively, and for the six months ended June 30, 2012 and 2011, net oil sales (oil sales less royalties) are slightly higher, $6.7 million and $4.5 million ($2.1 million and $1.4 million net to our 32 percent interest), respectively, under this method than the method advised by PDVSA and the method of applying the current oil price to total barrels produced and to total royalty barrels.

In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, as of August 3, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain.

The sale of oil and gas by Petrodelta to PDVSA is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PDVSA Petroleo S.A. (“PPSA”) (the “Sales Contract”). When the Sales Contract was executed, Petrodelta was producing only one type of crude, Merey 16. Therefore, the Sales Contract provides for only one crude pricing formula. This formula has been approved by the Ministry of the People’s Power for Energy and Petroleum (“MENPET”). The production deliveries and factors to include in the pricing formula are certified and acknowledged by MENPET.

Beginning in October 2011, MENPET determined that certain of the crude deliveries were a heavier type of crude, Boscan. The Boscan gravity and sulphur correction factors and crude pricing formula are not included in the Sales Contract. However, under the Sales Contract, PDVSA is obligated to receive all of Petrodelta’s production. All production deliveries for all of Petrodelta fields have been certified by MENPET and acknowledged by PDVSA.

The pricing factors for the Boscan crude have been provided and certified by MENPET to Petrodelta. The crude pricing formula used by Petrodelta to record the revenue from the Boscan deliveries is based on the actual Boscan pricing formula published in the Official Gazette on January 11, 2007. Because the Boscan crude pricing formula is not in the Sales Contract, Petrodelta has not yet invoiced PDVSA for the El Salto production. Contract amendment discussions are underway between Petrodelta, PPSA and CVP. PDVSA will be invoiced for the El Salto production as soon as the Sales Contract is amended. At June 30, 2012, El Salto production, net of royalties, covering the production months of October 2011 through June 2012 totaled approximately 2.0 million barrels of oil (“MBls”) (0.6 MBls net to our 32 percent interest). The Boscan pricing formula based upon the production deliveries and factors certified by MENPET, results in a price for this production of $193.8 million ($62.0 million net to our 32 percent interest).

The Organic Law on Sports, Physical Activity and Physical Education (“Sports Law”) was published in the Official Gazette on August 23, 2011 and is effective beginning January 1, 2012. The purpose of the Sports Law is to establish the public service nature of physical education and the promotion, organization and administration of sports and physical activity. Funding of the Sports Law is by contributions made by companies or other public or private organizations that perform economic activities for profit in Venezuela. The contribution is one percent of annual net or accounting profit and is not deductible for income tax purposes. Per the Sports Law, contributions are to be calculated on an after-tax basis. However, CVP has instructed Petrodelta to calculate the contribution on a before-tax basis contrary to the Sports Law. For the three and six months ended June 30, 2012, this method of calculation overstates the liability for the Sports Law contribution by $0.4 million and $0.8 million ($0.1 million and $0.2 million net to our 32 percent interest), respectively. We have adjusted for the over - accrual of the Sports Law in the three and six months ended June 30, 2012 Net Income from Equity Affiliate. See Note 2 – Summary of Significant Accounting Policies, Restatement of Prior Period Financial Statements.

Petrodelta’s reporting and functional currency is the U.S. Dollar. HNR Finance owns a 40 percent interest in Petrodelta. Petrodelta’s financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”) which we have adjusted to conform to USGAAP. The two major differences between IFRS and USGAAP, for which we adjust, are deferred taxes and depletion expense.

•

Deferred tax. IFRS allows the inclusion of monetary temporary differences impacted by inflationary adjustments. USGAAP does not. Net Income Equity Affiliate has been reduced by the deferred tax benefit created by the monetary temporary differences impacted by inflationary adjustments.

•

Depletion expense. Oil and gas reserves used by Petrodelta in calculating depletion expense under IFRS are provided by MENPET. MENPET reserves are not prepared using the guidance on extractive activities for oil and gas (ASC 932). At least annually, we prepare reserve reports for Petrodelta using ASC 932. Petrodelta depletion is recalculated using the USGAAP compliant reserves.

All amounts through Net Income Equity Affiliate represent 100 percent of Petrodelta. Summary financial information for Petrodelta has been presented below at June 30, 2012 and December 31, 2011 and for the three and six months ended June 30, 2012 and 2011:


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Revenues:
Oil sales	$	318,474		$	282,975		$	642,971		$	509,588
Gas sales		762			679			1,734			1,405
Royalty		(106,097	)		(96,214	)		(213,436	)		(173,529	)

		213,139			187,440			431,269			337,464

Expenses:
Operating expenses		20,063			18,684			41,644			32,966
Workovers		3,149			7,021			9,057			13,496
Depletion, depreciation and amortization		21,718			13,231			39,640			25,718
General and administrative		4,944			3,782			9,927			2,852
Windfall profits tax		74,687			65,345			159,425			92,471

		124,561			108,063			259,693			167,503

Income from operations		88,578			79,377			171,576			169,961

Investment earnings and other		1			185			2			352
Interest expense		(2,690	)		(3,146	)		(4,603	)		(4,418	)


Income before income tax		85,889			76,416			166,975			165,895

Current income tax expense		31,268			31,618			73,338			84,961
Deferred income tax benefit		(17,394	)		(2,513	)		(30,884	)		(28,275	)

Net income		72,015			47,311			124,521			109,209
Adjustment to reconcile to reported net income from unconsolidated equity affiliate (RESTATED*):
Deferred income tax expense		16,258			26			28,299			17,897
Unrealized gain on fair value of VAT		—			(95	)		—			—
Sports law over accrual		(420	)		—			(765	)		—

Net income equity affiliate		56,177			47,380			96,987			91,312
Equity interest in unconsolidated equity affiliate		40	%		40	%		40	%		40	%

Income before amortization of excess basis in equity affiliate		22,471			18,952			38,795			36,525
Conform depletion expense to USGAAP		896			(452	)		1,957			(873	)
Amortization of excess basis in equity affiliate		(538	)		(216	)		(1,027	)		(297	)

Net income from unconsolidated equity affiliate	$	22,829		$	18,284		$	39,725		$	35,355

*	See Note 2 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements.


	June 30, 2012		December 31, 2011
	(in thousands)
Current assets	$	1,158,365	$	979,868
Property and equipment		433,137		409,941
Other assets		175,656		146,499
Current liabilities		910,079		808,955
Other liabilities		58,278		53,073
Net equity		798,801		674,280

Note 11 – Indonesia

Operational activities during the six months ended June 30, 2012 included rigging down operations of the drilling rig on the KD-1 location and review of geological and geophysical data obtained from the drilling of the Lariang-1 (“LG-1”) and KD-1 wells. Based on the multiple oil and gas shows encountered in both LG-1 and KD-1, we are working on an exploration program targeting the Pliocene and Miocene sands encountered in the previous two wells. We have completed remapping of both the Lariang and Karama Basins with eight prospects in the Lariang Basin and five prospects in the Karama Basin having been identified in the Pliocene, Middle-Late Miocene and Eocene sands. The initial exploration term of the Budong PSC expires on January 16, 2013. We will be requesting a four year extension of the initial exploration period to enable us to complete exploration activities on the Budong PSC.

Drilling costs for the KD-1well incurred through December 31, 2011 of $26.0 million were expensed to dry hole costs as of December 31, 2011. The remaining costs to plug and abandon the KD-1 and KD-1ST, the first sidetrack to the KD-1, of $0.7 million have been expensed to dry hole costs as of June 30, 2012.

The remaining work commitment for the current exploration phase on the Budong PSC is for geological and geophysical work to be completed during 2012 at a minimum of $0.5 million ($0.3 million net to our 64.51 percent cost sharing interest). However, per the Budong PSC, excessive work done during any period can be offset against another period, so although there is a work commitment in the Budong PSC to perform the geological and geophysical work, we have exceeded this requirement. BPMIGAS has stated that that we have satisfied all work commitments for the current exploration phase of the Budong PSC.

The Budong PSC represents $5.4 million of unproved oil and gas properties on our June 30, 2012 balance sheet (RESTATED) (December 31, 2011: $5.3 million).

Note 12 – Gabon

The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources, entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. In order to complete drilling activities of the Dussafu Ruche Marin-A (“DRM-1”) exploratory well, in March 2011, the Direction Generale Des Hydrocarbures (“DGH”) approved a one year extension to May 27, 2012 of the second exploration phase. We do not have any remaining work commitments for the second exploration phase. On April 27, 2012, we submitted notification to the DGH of our intent to enter the third exploration phase of the Dussafu PSC with an effective date of May 28, 2012. The DGH has agreed to lengthen the third exploration phase to four years until May 27, 2016. The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period. We paid a $1.0 million bonus ($0.7 million net to our 66.667 percent interest) to enter the third exploration phase.

Operational activities during the six months ended June 30, 2012 included processing of the 545 square kilometers of seismic which was acquired in the fourth quarter of 2011. The 3-D Pre-Stack Time Migration (“PSTM”) was completed in July 2012. Well planning is in progress to drill an exploration well in the fourth quarter of 2012 on the Tortue prospect. See Note 16 – Subsequent Events.

The Dussafu PSC represents $51.6 million of unproved oil and gas properties on our June 30, 2012 balance sheet (RESTATED) (December 31, 2011: $48.9 million).

Note 13 – Oman

In 2009, we signed an EPSA with Oman for the Block 64 EPSA. The Block 64 EPSA has a minimum work obligation to reprocess seismic and drill two exploration wells. The parties to the Block 64 EPSA acknowledged that $22.0 million was indicative of the costs needed to complete the work program during the three-year initial period which expires in May 2013. As of February 29, 2012, we had expended more than $22.0 million and completed the minimum work obligations. We do not have any remaining work commitments for the current exploration phase of the Block 64 EPSA.

Operational activities during the six months ended June 30, 2012 include completion of the drilling of the Al Ghubar North-1 (“AGN-1”), the second exploratory well on the Block 64 EPSA which spud December 21, 2011. On February 6, 2012, the AGN-1 was plugged and abandoned with gas shows in the Permian Khuff Formation. Drilling costs incurred through December 31, 2011 of $2.8 million were expensed to dry hole costs as of December 31, 2011. The remaining costs to plug and abandon the AGN-1 of $4.9 million have been expensed to dry hole costs as of June 30, 2012. Work continues on Block 64 EPSA to determine if other drilling opportunities exist.

The Block 64 EPSA represents $6.1 million of unproved oil and gas properties on our June 30, 2012 balance sheet (December 31, 2011: $5.3 million).

Note 14 – Related Party Transactions

Dividends declared and paid by Petrodelta are paid to HNR Finance. HNR Finance must declare a dividend in order for the partners, Harvest and Vinccler, to receive their respective shares of Petrodelta’s dividend. Petrodelta has declared two dividends, totaling $33.0 million, which have been received by HNR Finance and one dividend, totaling $12.2 million, which has not yet been received by HNR Finance. HNR Finance has not distributed these dividends to the partners. At June 30, 2012, Vinccler’s share of the undistributed dividends is $9.0 million.

Note 15 – Stock-Based Compensation

Stock options for 46,900 shares were exercised in the six months ended June 30, 2012 resulting in cash proceeds of $0.3 million. Stock options for 41,666 shares were exercised in the six months ended June 30, 2011 resulting in cash proceeds of $0.4 million.

On March 30, 2012, we announced that we had entered into the Agreement with KCA relating to an ATM offering of shares of our common stock having an aggregate sales price of up to $75.0 million. Under the terms of the Agreement, we may offer and sell shares of our common stock by means of transactions on the NYSE or otherwise at market prices prevailing at the time of sale, at prices related to the prevailing market price or at negotiated rates. We are unable to access the ATM during blackout periods or when we are in possession of material information which has not been made public. No shares were sold under the ATM during the six months ended June 30, 2012.

Stock Appreciation Rights (“SARs”)

On May 18, 2012, we issued 0.7 million SARs to employees of Harvest at $5.12 and vest ratably over three years. The vesting of the SARs is dependent upon the employee’s continued service to Harvest.

Restricted Stock Units (“RSUs”)

On May 18, 2012, we issued 0.3 million RSUs to employees of Harvest. The RSUs vest after three years. The vesting of the RSUs is dependent upon the employee’s continued service to Harvest.

On May 18, 2012, we issued 0.1 million RSUs to outside directors of Harvest. The RSUs vest after one year. The vesting of the RSUs is dependent upon the director’s continued service to Harvest.

Common Stock Warrants

In connection with a $60 million term loan facility issued in November 2010, we issued (1) 1.2 million warrants exercisable at any time on or after the closing date of the term loan facility for a period of five years from

the closing date on a cashless exercise basis at $15 per share until July 28, 2011, the Bridge Date, at which time the exercise price per share would be repriced to equal the lower of $15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date (“Tranche A”); (2) 0.4 million warrants exercisable at any time on or after the closing date of the term loan facility for a period of five years from the closing date on a cashless exercise basis at $20 per share until the Bridge Date, at which time the exercise price per share would be repriced to equal the lower of $15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date (“Tranche B”); and (3) 4.4 million warrants exercisable at any time on or after the Bridge Date for a period of five years from the Bridge Date on a cashless exercise basis at the lower of $15 per share or 120 percent of the average closing price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date (“Tranche C”) (“collectively “the Warrants”). Tranche C was redeemable by Harvest for $0.01 per share at any time prior to the Bridge Date in conjunction with the repayment of the loan prior to the Bridge Date.

On May 17, 2011, in connection with the payment of the term loan facility, we redeemed all of Tranche C at $0.01 per share. The cost to redeem Tranche C ($44,000) was expensed to loss on extinguishment of debt in the six months ended June 30, 2011.

On July 28, 2011, the Bridge Date, Tranche A and Tranche B were repriced to $14.78 per warrant which is the lower of $15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date.

The Warrants include anti-dilution provisions which adjust the number of warrants and the exercise price per warrant based on the issuance of additional shares. The induced conversions related to the $32 million senior convertible notes triggered the anti-dilution provision which resulted in the issuance of 72,830 additional warrants in the three and six months ended June 30, 2012 (December 31, 2011: 2,007 additional warrants). In addition, the exercise price per share for all Warrants was repriced to $14.12 per warrant. The Warrants are classified as a liability on our consolidated condensed balance sheets and marked to market. See Note 2 – Summary of Significant Accounting Policies, Restatement of Prior Period Financial Statements.

In the occurrence of a fundamental change, we are required to repurchase the Warrants at the higher of (1) the fair market value of the warrant and (2) a valuation based on a computation of the option value of the Warrant using the Black-Scholes calculation method using the assumptions described in the Warrant Agreement. A fundamental change is defined as “the occurrence of one of the following events: a) a person or group becomes the direct or indirect owner of more than 50% of the voting power of the outstanding common stock, b) a merger event or similar transaction in which the majority owners before the transaction fail to own a majority of the voting power of the Company after the transaction, and c) approval of a plan of liquidation or dissolution of the Company or sale of all or substantially all of the Company’s assets.”

The dates the warrants were issued, the expiration dates, the exercise prices and the number of warrants issued and outstanding at June 30, 2012 were:


				Warrants
Date Issued	Expiration Date	Exercise Price		Issued		Outstanding
				(warrants in thousands)
November 2010	November 2015	$	14.12		1,600		1,600
October 2011	November 2015		14.12		2		2
March 2012	November 2015		14.12		73		73

					1,675		1,675

Note 16 – Warrant Derivative Liabilities

As of June 30, 2012, derivative financial instruments consisted of 1,674,837 warrants (December 31, 2011: 1,602,007 warrants) issued under the warrant agreements dated November 2010 in connection with a $60 million term loan. The fair value of the warrants as of June 30, 2012 was $3.63 per warrant (December 31, 2011: $3.04 per warrant).

These warrant agreements include provisions wherein we may be required to settle the warrant agreement by transferring assets. Consequently, these warrants must be treated as a derivative liability, bifurcated from the host instrument, and recorded at fair value at each reporting date. In the occurrence of a fundamental change, we

are required to repurchase the Warrants at the higher of (1) the fair market value of the warrant and (2) a valuation based on a computation of the option value of the Warrant using the Black-Scholes calculation method using the assumptions described in the Warrant Agreement. A fundamental change is defined as “the occurrence of one of the following events: a) a person or group becomes the direct or indirect owner of more than 50% of the voting power of the outstanding common stock, b) a merger event or similar transaction in which the majority owners before the transaction fail to own a majority of the voting power of the Company after the transaction, and c) approval of a plan of liquidation or dissolution of the Company or sale of all or substantially all of the Company’s assets.”

All our warrant derivative contracts are recorded at fair value and are located in the balance sheet as warrant derivative liability. The following table summarizes the effect on our income (loss) associated with changes in the fair values of our derivative financial instruments:


	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
	(in thousands)

Unrealized gain (loss) on warrant derivatives	$	(1,641	)	$	7,060	$	(1,209	)	$	4,544

Note 17 – Subsequent Event

On July 17, 2012, we signed a contract for the Scarabeo 3 semi-submersible drilling rig. Mobilization of the drilling rig to the well site in Gabon is scheduled to commence the beginning of October 2012. In the event that we elect to terminate the contract prior to the rig’s arrival on-site, we are obligated to compensate the drilling company $5.0 million ($3.3 million net to our 66.667 percent interest) for liquidated damages.

We conducted our subsequent events review up through the date of the issuance of the original Quarterly Report on Form 10-Q.

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Harvest Natural Resources, Inc. (“Harvest” or the “Company”) cautions that any forward-looking statements as such term is defined in the Private Securities Litigation Reform Act of 1995, as amended (the “PSLRA”) contained in this report or made by management of the Company involve risks and uncertainties and are subject to change based on various important factors. When used in this report, the words “budget”, “forecast”, “expect”, “believes”, “goals”, “projects”, “plans”, “anticipates”, “estimates”, “should”, “could”, “assume” and similar expressions are intended to identify forward-looking statements. In accordance with the provisions of the PSLRA, we caution you that important factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include our concentration of operations in Venezuela, the political and economic risks associated with international operations (particularly those in Venezuela), the anticipated future development costs for undeveloped reserves, drilling risks, the risk that actual results may vary considerably from reserve estimates, the dependence upon the abilities and continued participation of certain of our key employees, the risks normally incident to the exploration, operation and development of oil and natural gas properties, risks incumbent to being a noncontrolling interest shareholder in a corporation, the permitting and the drilling of oil and natural gas wells, the availability of materials and supplies necessary to projects and operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, the Company’s ability to acquire oil and natural gas properties that meet its objectives, availability and cost of drilling rigs and seismic crews, overall economic conditions, political stability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in governmental policy, lack of liquidity, availability of sufficient financing, estimates of amounts and timing of sales of securities, closing of the Share Purchase Agreement, changes in weather conditions, and ability to hire, retain and train management and personnel. A discussion of these factors is included in our Annual Report on Form 10-K for the year ended December 31, 2011, which includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q.

Executive Summary

Harvest Natural Resources, Inc. is a petroleum exploration and production company incorporated under Delaware law in 1989. Our focus is on acquiring exploration, development and producing properties in geological basins with proven active hydrocarbon systems. Our experienced technical, business development and operating personnel have identified low entry cost exploration opportunities in areas with large hydrocarbon resource potential. We operate from our Houston, Texas headquarters. We also have regional/technical offices in the United Kingdom and Singapore, and small field offices in Jakarta, Republic of Indonesia (“Indonesia”); Muscat, Sultanate of Oman (“Oman”); and Port Gentil, Republic of Gabon (“Gabon”) to support field operations in those areas.

We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through Harvest-Vinccler Dutch Holding, B.V., a Dutch private company with limited liability (“Harvest Holding”). Our ownership of Harvest Holding is through HNR Energia, B.V. (“HNR Energia”) in which we have a direct controlling interest. Through HNR Energia, we indirectly own 80 percent of Harvest Holding and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining 20 percent interest of Harvest Holding. Harvest Holding owns, indirectly through wholly owned subsidiaries, a 40 percent of Petrodelta, S.A. (“Petrodelta”). As we indirectly own 80 percent of Harvest Holding, we indirectly own a net 32 percent interest in Petrodelta, and Vinccler indirectly owns eight percent. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Harvest Holding has a direct controlling interest in Harvest Vinccler S.C.A. (“Harvest Vinccler”). Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with Petroleos de Venezuela S.A. (“PDVSA”). We do not have a business relationship with Vinccler outside of Venezuela.

Through the pursuit of technically-based strategies, we are building a portfolio of exploration prospects to complement the production, development and exploration prospects we hold in Venezuela. In addition to our interests in Venezuela, we hold exploration acreage mainly onshore West Sulawesi in Indonesia; offshore of Gabon; onshore in Oman; and offshore of the People’s Republic of China (“China”).

From time to time we learn of possible third party interests in acquiring ownership in certain assets within our property portfolio. We evaluate these potential opportunities taking into consideration our overall property mix, our operational and liquidity requirements, our strategic focus and our commitment to long-term shareholder value.

During the last two years, we have been exploring a broad range of strategic alternatives for enhancing stockholder value. On September 24, 2010, we retained Merrill Lynch, Pierce, Fenner & Smith (“Merrill Lynch”) to provide advisory services to assist us in exploring those strategic alternatives, including, among others, a sale of assets. Since that time, we have received several indications of interest from third parties, provided due diligence materials to third parties under confidentiality agreements and had preliminary discussions with third parties regarding a sale of our interests in Venezuela, but had not determined that any of the transactions discussed were in our best interests.

On March 6, 2012, we announced that we had commenced exclusive negotiations with a third party for the possible sale of our 32 percent interest in Petrodelta.

Operations

Restatement of Prior Period Financial Statements

In connection with the preparation of our Annual Report on Form 10-K for the year ended December 31, 2012, we concluded that there were errors in previously filed financial statements. In the course of our review, management determined that (a) certain warrants issued in 2010 in connection with our $60 million term loan facility (the “Warrants”) were improperly valued at inception and improperly classified as equity instruments rather than liability instruments. As a result of the improper classification of the Warrants, (b) the debt discount and associated interest expense related to the amortization of the debt discount was understated for all periods in which the associated debt was outstanding, and (c) the consolidated condensed statement of operations and comprehensive income (loss) for each reporting period was misstated by the omission of the changes in fair value of the Warrants as a liability instrument. Additionally, (d) certain exploration overhead was incorrectly capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed, and (e) certain leasehold maintenance and other costs were improperly capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed. Finally, (f) advances to equity affiliate were improperly classified as an operating activity rather than an investing activity and (g) certain costs were improperly classified as an investing activity rather than an operating activity on the consolidated condensed statement of cash flows. Such errors impacted annual period ended December 31, 2011 and quarterly periods ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, and June 30, 2012.

We have restated our segment footnote information to reflect the applicable errors stated above and eliminate intrasegment receivables erroneously reported gross of related intrasegment payable. Such errors impacted annual period ended December 31, 2011 and quarterly periods ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, and June 30, 2012.

Consolidated Condensed Statements of Operations and Comprehensive Income (Loss)


	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	As Previously Reported			Adjustment			As RESTATED			As Previously Reported			Adjustment			As RESTATED
	*(in thousands)*
Expenses
Depreciation and amortization	$	105		$	—		$	105		$	119		$	—		$	119
Exploration expense^(a)		1,282			430			1,712			4,650			(3,210	)		1,440
Impairment of oil and gas properties^(b)		—			—			—			—			3,335			3,335
Dry hole costs		71			—			71			—			—			—
General and administrative		6,524			—			6,524			7,049			—			7,049

Total expenses		7,982			430			8,412			11,818			125			11,943

Loss from operations		(7,982	)		(430	)		(8,412	)		(11,818	)		(125	)		(11,943	)
Other non-operating income (expense)
Investment earnings and other		80			—			80			240			—			240
Unrealized gain (loss) on warrant derivatives^(c)		—			(1,641	)		(1,641	)		—			7,060			7,060
Interest expense^(d)		(34	)		—			(34	)		(1,704	)		(482	)		(2,186	)
Debt conversion expense		20			—			20			—			—			—
Loss on early extinguishment of debt^(e)		—			—			—			(9,682	)		(3,450	)		(13,132	)
Other non-operating expense		(1,467	)		—			(1,467	)		(244	)		—			(244	)
Foreign currency transaction loss		(48	)		—			(48	)		(32	)		—			(32	)

		(1,449	)		(1,641	)		(3,090	)		(11,422	)		3,128			(8,294	)

Income (Loss) from Continuing Operations Before Income taxes		(9,431	)		(2,071	)		(11,502	)		(23,240	)		3,003			(20,237	)
Income tax expense (benefit)^(f)		(426	)		(596	)		(1,022	)		260			—			260

Income (Loss) from Continuing Operations		(9,005	)		(1,475	)		(10,480	)		(23,500	)		3,003			(20,497	)
Net Income from Equity Affiliate^(g)		22,661			168			22,829			18,246			38			18,284

Net Income (Loss) from Continuing Operations		13,656			(1,307	)		12,349			(5,254	)		3,041			(2,213	)
Discontinued Operations
Income (Loss) from Discontinued Operations		(1,584	)		—			(1,584	)		480			—			480
Gain on sale of oil and gas properties		—			—			—			103,933			—			103,933
Income tax (expense) benefit		595			(595	)		—			(5,748	)		—			(5,748	)

Income (Loss) from Discontinued Operations^(h)		(989	)		(595	)		(1,584	)		98,665			—			98,665

Net Income (Loss)		12,667			(1,902	)		10,765			93,411			3,041			96,452
Less: Net Income Attributable to Noncontrolling Interest^(g)		4,507			33			4,540			3,631			8			3,639

Net Income (Loss) Attributable To Harvest	$	8,160		$	(1,935	)	$	6,225		$	89,780		$	3,033		$	92,813


Net Income (Loss) Attributable to Harvest Per Common Share:
Basic	$	0.22		$	(0.05	)	$	0.17		$	2.64		$	0.09		$	2.73

Diluted⁽ⁱ⁾	$	0.20		$	(0.05	)	$	0.15		$	2.23		$	0.50		$	2.73


Comprehensive income (loss)	$	8,160		$	(1,935	)	$	6,225		$	89,780		$	3,033		$	92,813

(a)

(b)	For 2011, represents the reclassification from exploration expense to impairment of oil and gas properties for amounts that were erroneously classified as exploration expense.

(c)	For 2012 and 2011, represents changes in fair value of the Warrants for the period. Such Warrants were previously classified as equity and were, therefore, not marked to market at the end of each reporting period.

(d)	For 2011, as a result of the change in fair value of the Warrants, the original discount allocated to the debt was understated; therefore, the additional amortization of the discount on debt, which is a component of interest expense, was understated for each period the debt was outstanding.

(e)	For 2011, the correction in the fair value of the Warrants and its classification as a liability resulted in an increase discount on debt which also impacted the resulting loss on extinguishment of debt originally recorded in May 2011 when the debt was retired.

(f)	For 2012, represents income tax effect of adjustments.

(g)	For 2012 and 2011, represents a previously identified immaterial error.

(h)	For 2012, represents a previously identified classification error between income tax on discontinued operations and income tax on continuing operations.

(i)

Consolidated Condensed Statements of Operations and Comprehensive Income (Loss)


	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	As Previously Reported			Adjustment			As RESTATED			As Previously Reported			Adjustment			As RESTATED
	*(in thousands)*
Expenses
Depreciation and amortization	$	210		$	—		$	210		$	243		$	—		$	243
Exploration expense^(a)		2,725			922			3,647			5,839			(3,100	)		2,739
Impairment of oil and gas properties^(b)		—			—			—			—			3,335			3,335
Dry hole costs		5,617			—			5,617			—			—			—
General and administrative		12,366			—			12,366			13,724			—			13,724

Total expenses		20,918			922			21,840			19,806			235			20,041

Loss from operations		(20,918	)		(922	)		(21,840	)		(19,806	)		(235	)		(20,041	)
Other non-operating income (expense)
Investment earnings and other		149			—			149			385			—			385
Unrealized gain (loss) on warrant derivatives^(c)		—			(1,209	)		(1,209	)		—			4,544			4,544
Interest expense^(d)		(428	)		302			(126	)		(3,916	)		(1,823	)		(5,739	)
Debt conversion expense		(2,402	)		—			(2,402	)		—			—			—
Loss on extinguishment of debt^(e)		—			—			—			(9,682	)		(3,450	)		(13,132	)
Other non-operating expense		(1,723	)		—			(1,723	)		(675	)		—			(675	)
Foreign currency transaction loss		(70	)		—			(70	)		(43	)		—			(43	)

		(4,474	)		(907	)		(5,381	)		(13,931	)		(729	)		(14,660	)

Loss from Continuing Operations Before Income taxes		(25,392	)		(1,829	)		(27,221	)		(33,737	)		(964	)		(34,701	)
Income tax expense (benefit)^(f)		(1,646	)		(596	)		(2,242	)		482			237			719

Loss from Continuing Operations		(23,746	)		(1,233	)		(24,979	)		(34,219	)		(1,201	)		(35,420	)
Net Income from Equity Affiliate^(g)		39,419			306			39,725			36,740			—			36,740

Net Income (Loss) from Continuing Operations		15,673			(927	)		14,746			2,521			(1,201	)		1,320
Discontinued Operations
Income (Loss) from Discontinued Operations		(1,699	)		—			(1,699	)		(2,786	)		—			(2,786	)
Gain on sale of oil and gas properties		—			—			—			103,933			—			103,933
Income tax (expense) benefit		595			(595	)		—			(5,748	)		—			(5,748	)

Income (Loss) from Discontinued Operations^(h)		(1,104	)		(595	)		(1,699	)		95,399			—			95,399

Net Income (Loss)		14,569			(1,522	)		13,047			97,920			(1,201	)		96,719
Less: Net Income Attributable to Noncontrolling Interest^(g)		7,801			61			7,862			7,058			—			7,058

Net Income (Loss) Attributable To Harvest	$	6,768		$	(1,583	)	$	5,185		$	90,862		$	(1,201	)	$	89,661


Net Income (Loss) Attributable to Harvest Per Common Share:
Basic	$	0.19		$	(0.05	)	$	0.14		$	2.67		$	(0.03	)	$	2.64

Diluted⁽ⁱ⁾	$	0.18		$	(0.04	)	$	0.14		$	2.27		$	0.37		$	2.64


Comprehensive income (loss)	$	6,768		$	(1,583	)	$	5,185		$	90,862		$	(1,201	)	$	89,661

(a)

For 2012, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense. For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense. For the six months ended June 30, 2011, this amount was offset by a reclassification from exploration expense to impairment of oil and gas properties of $3,335 thousand in the six months ended June 30, 2011 for amounts that were erroneously classified as exploration expense.

(b)	For 2011, represents the reclassification from exploration expense to impairment of oil and gas properties for amounts that were erroneously classified as exploration expense.

(c)	Represents changes in fair value of Warrants for the period. Such Warrants were previously classified as equity and were, therefore, not marked to market at the end of each reporting period.

(d)

(e)	The correction in the fair value of the Warrants and its classification as a liability resulted in an increase discount on debt which also impacted the resulting loss on extinguishment of debt originally recorded in May 2011 when the debt was retired.

(f)	For 2012, represents income tax effect of adjustments. For 2011, relates to income tax expense improperly classified as interest expense.

(g)	Represents a previously identified immaterial error.

(h)	Represents a previously identified classification error between income tax on discontinued operations and income tax on continuing operations.

(i)

For 2011, in addition to the impact on EPS related to the adjustments described in (a) through (e) and (g) above, diluted EPS has been adjusted to reflect an error in the calculation of the weighted average common shares, diluted outstanding for the six months ended June 30, 2011. The weighted average common shares utilized for the calculation of diluted EPS was erroneously 40,027 thousand rather than 33,992 thousand.

Consolidated Condensed Balance Sheets


	June 30, 2012
	As Previously Reported		Adjustment			As RESTATED
	*(in thousands)*

Deferred income tax^(a)	$	2,628	$	(2,628	)	$	—
Investment in equity affiliate^(b)		384,473		306			384,779
Oil and gas properties^(c)		70,292		(4,275	)		66,017
Total assets^(d)		515,373		(6,597	)		508,776
Accrued interest payable^(e)		1,008		(396	)		612
Other current liabilities^(a)		4,835		(2,203	)		2,632
Income taxes payable^(f)		1,251		(30	)		1,221
Warrant derivative liability^(g)		—		6,079			6,079
Total liabilities^(h)		33,541		3,450			36,991
Additional paid in capital⁽ⁱ⁾		256,009		(8,831	)		247,178
Retained earnings^(j)		200,051		(1,277	)		198,774
Total Harvest shareholders’ equity^(k)		390,353		(10,108	)		380,245
Noncontrolling interest^(b)		91,479		61			91,540
Total equity		481,832		(10,047	)		471,785

(a)	Relates to a deferred tax asset that was erroneously reported gross of the related liability.

(b)	Represents a previously identified immaterial error.

(c)	Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense.

(d)	Relates to (a) through (c) above.

(e)	Represents other current liabilities that were improperly classified as interest payable and income taxes payable.

(f)	Income tax effect of the adjustments and income taxes improperly classified as interest payable in 2011.

(g)	Represents the fair value of the Warrants at the reporting date.

(h)	Relates to (a) and (e) through (g) above.

(i)

(j)

Relates to (a) net increase in expense in 2010, 2011, and six months ended June 30, 2012 related to exploration expense of $3,445 thousand, (b) net increase in unrealized gain on warrant derivatives of $8,921 thousand for cumulative 2010, 2011 and six months ended June 30, 2012, (c) net increase in interest expense of $2,619 thousand cumulative for 2010, 2011 and six months ended June 30, 2012, (d) net increase in loss on extinguishment of debt of $3,450 thousand for 2011, (e) net increase in income from equity affiliate of $306 thousand less noncontrolling interest of $61 thousand due to a previously identified immaterial error, (f) net increase in income tax expense of $236 thousand for income taxes improperly classified as interest expense, offset by a reduction to retained earnings of $693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than expensed prior to January 1, 2010.

(k)	Relates to reclassification of the Warrants as described in (i) above plus the impact of retained earnings described in (j) above.

Consolidated Condensed Balance Sheets


	December 31, 2011
	As Previously Reported		Adjustment			As RESTATED
	*(in thousands)*

Deferred income taxes^(a)	$	2,628	$	(2,628	)	$	—
Oil and gas properties^(b)		65,671		(3,216	)		62,455
Total assets^(c)		513,047		(5,844	)		507,203
Accrued interest payable^(d)		1,372		(396	)		976
Other current liabilities^(e)		4,835		(2,203	)		2,632
Income taxes payable^(d)		718		(29	)		689
Warrant derivative liability^(f)		—		4,870			4,870
Total liabilities^(g)		65,592		2,242			67,834
Additional paid in capital^(h)		236,192		(8,392	)		227,800
Retained earnings⁽ⁱ⁾		193,283		306			193,589
Total Harvest shareholders’ equity^(j)		363,777		(8,086	)		355,691
Total equity		447,455		(8,086	)		439,369

(a)	Relates to a deferred tax asset that was erroneously reported gross of the related liability.

(b)	Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense.

(c)	Relates to (a) and (b) above.

(d)	Represents other current liabilities that were improperly classified as interest payable and income taxes payable.

(e)	Relates to a deferred tax asset that was erroneously reported gross of the related liability and other current liabilities that were improperly classified as interest payable and income taxes payable.

(f)

(g)	Relates to (d) through (f) above.

(h)

(i)

(j)	Relates to reclassification of the Warrants as described in (h) above plus the impact of retained earnings described in (i) above.

Consolidated Condensed Statements of Cash Flows


	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	As Previously Reported			Adjustment			As RESTATED			As Previously Reported			Adjustment			As RESTATED
	*(in thousands)*
Net cash used in operating activities^(a)(b)	$	(16,472	)	$	(1,738	)	$	(18,210	)	$	(14,922	)	$	67		$	(14,855	)
Net cash provided by (used in) investing activities^(a)(b)		(13,834	)		1,738			(12,096	)		152,024			(67	)		151,957
Net cash provided by (used in) financing activities		106			—			106			(59,773	)		—			(59,773	)

Net increase (decrease) in cash and cash equivalents		(30,200	)		—			(30,200	)		77,329			—			77,329
Cash and cash equivalents at beginning of year		58,946			—			58,946			58,703			—			58,703

Cash and cash equivalents at end of year	$	28,746		$	—		$	28,746		$	136,032		$	—		$	136,032

(a)

(b)


	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	As Previously Reported			Adjustments			As RESTATED			As Previously Reported			Adjustments			As RESTATED
Segment Income (Loss) Attributable to Harvest
Venezuela^(a)	$	17,733		$	4		$	17,737		$	14,115		$	(74	)	$	14,041
Indonesia^(b)		(1,225	)		(353	)		(1,578	)		(1,596	)		—			(1,596	)
Gabon^(b)		(1,670	)		(52	)		(1,722	)		(717	)		(125	)		(842	)
Oman		(923	)		—			(923	)		(489	)		—			(489	)
United States^(c)		(4,766	)		(939	)		(5,705	)		(20,198	)		3,232			(16,966	)

Net income (loss) from continuing operations		9,149			(1,340	)		7,809			(8,885	)		3,033			(5,852	)
Discontinued operations (Antelope Project)^(d)		(989	)		(595	)		(1,584	)		98,665			—			98,665

Net income (loss) attributable to Harvest	$	8,160		$	(1,935	)	$	6,225		$	89,780		$	3,033		$	92,813

(a)	Represents a previously identified immaterial error.

(b)	Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense.

(c)

(d)	Represents a previously identified classification error between income tax on discontinued operations and income tax on continuing operations.


	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	As Previously Reported			Adjustments			As RESTATED			As Previously Reported			Adjustments			As RESTATED
Segment Income (Loss) Attributable to Harvest
Venezuela^(a)	$	30,448		$	245		$	30,693		$	27,329		$	—		$	27,329
Indonesia^(b)		(3,701	)		(733	)		(4,434	)		(3,014	)		—			(3,014	)
Gabon^(b)		(2,985	)		(162	)		(3,147	)		(1,059	)		(235	)		(1,294	)
Oman		(6,531	)		—			(6,531	)		(1,045	)		—			(1,045	)
United States^(c)		(9,359	)		(338	)		(9,697	)		(26,748	)		(966	)		(27,714	)

Net income (loss) from continuing operations		7,872			(988	)		6,884			(4,537	)		(1,201	)		(5,738	)
Discontinued operations (Antelope Project)^(d)		(1,104	)		(595	)		(1,699	)		95,399			—			95,399

Net income (loss) attributable to Harvest	$	6,768		$	(1,583	)	$	5,185		$	90,862		$	(1,201	)	$	89,661

(a)	Represents a previously identified immaterial error.

(b)	Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense.

(c)

(d)	Represents a previously identified classification error between income tax on discontinued operations and income tax on continuing operations.


	June 30, 2012									December 31, 2011
	As Previously Reported			Adjustments			As RESTATED			As Previously Reported			Adjustments			As RESTATED
Operating Segment Assets
Venezuela^(a)	$	388,311		$	306		$	388,617		$	348,802		$	—		$	348,802
Indonesia^(b)		12,862			(2,240	)		10,622			65,165			(50,572	)		14,593
Gabon^(b)		56,211			(1,719	)		54,492			119,273			(63,768	)		55,505
Oman^(b)		6,535			—			6,535			20,980			(13,828	)		7,152
United States^(c)		253,594			(2,944	)		250,650			137,531			122,325			259,856

		717,513			(6,597	)		710,916			691,751			(5,843	)		685,908
Intersegment eliminations		(202,140	)		—			(202,140	)		(178,704	)		(1	)		(178,705	)

Total Assets	$	515,373		$	(6,597	)	$	508,776		$	513,047		$	(5,844	)	$	507,203

(a)	Represents a previously identified immaterial error.

(b)	Relates to the elimination of intrasegment receivables erroneously reported gross of related intrasegment payable.

(c)	Relates to the elimination of intrasegment receivables erroneously reported gross of related intrasegment payable and a deferred tax asset that was erroneously reported gross of the related liability.

Share Purchase Agreement (“SPA”)

On June 21, 2012, we and our wholly owned subsidiary HNR Energia entered into a share purchase agreement (the “SPA”) with PT Pertamina (Persero), a state-owned limited liability company existing under the laws of Indonesia (“Buyer”). HNR Energia is a private company with limited liability under the laws of Curacao. HNR Energia owns 80 percent of the equity interest of Harvest Holding, which owns 40 percent of the equity interest of Petrodelta. Vinccler, who owns the other 20 percent equity interest of Harvest Holding, is not a party to the transaction.

described in the SPA. The sale of Harvest Holding, including its direct and indirect subsidiaries, will constitute the sale of all of our interest in Venezuela, which consists of our indirect 32 percent interest in Petrodelta and our indirect 80 percent interest in Harvest Vinccler. The effective date of the transaction is January 1, 2012. We have also executed a guarantee in Buyer’s favor by which we guarantee HNR Energia’s obligations under the SPA.

Venezuela

Harvest Vinccler’s and Petrodelta’s functional and reporting currency is the United States Dollar (“U.S. Dollar”). They do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”) (4.30 Bolivars per U.S. Dollar). However, during the three months ended June 30, 2012, Harvest Vinccler exchanged approximately $0.4 million (three months ended June 30, 2011: $0.1 million) through the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) and received an average exchange rate of 5.10 Bolivars (three months ended June 30, 2011: 5.21 Bolivars) per U.S. Dollar. During the six months ended June 30, 2012, Harvest Vinccler exchanged approximately $0.6 million (six months ended June 30, 2011: $0.4 million) through SITME and received an average exchange rate of 5.13 Bolivars (six months ended June 30, 2011: 5.19 Bolivars) per U.S. Dollar. Harvest Vinccler currently does not have any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. Petrodelta does not have, and has not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate.

The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. At June 30, 2012, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 5.0 million Bolivars and 7.2 million Bolivars, respectively. At June 30, 2012, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 227.8 million Bolivars and 2,696.5 million Bolivars, respectively.

Petrodelta

Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Petrodelta’s 2012 capital budget, which has yet to be endorsed by Petrodelta’s board, is expected to be approximately $300 million with a significant portion of that total related to infrastructure costs to support the further development of the Temblador and El Salto fields.

Petrodelta began 2012 with three drilling rigs, but PDVSA relocated one rig to another operation. Currently, Petrodelta is operating two drilling rigs and one workover rig and is continuing with infrastructure enhancement projects in the El Salto and Temblador fields. Plans are underway to build a pipeline connection between the Isleño field and the main production facility at Uracoa as Isleño production is currently being trucked to Uracoa. Petrodelta has been informed by PDVSA that a new drilling rig will be arriving in the third quarter of 2012, to replace the rig that was relocated. The rig is currently rigging up in the Isleño field. It is expected that the drilling rig will be operational in August 2012. On May 1, 2012, Petrodelta was notified that it could be receiving two additional new rigs during the third quarter of 2012 which would result in an expected five working rigs by year end 2012.

During the six months ended June 30, 2012, Petrodelta drilled and completed six development wells, delivered approximately 6.3 million barrels (“MBls”) of oil and 1.1 billion cubic feet (“Bcf”) of natural gas, averaging 35,633 barrels of oil equivalent (“BOE”) per day. During the six months ended June 30, 2011, Petrodelta drilled and completed eight development wells, one successful appraisal well and one water injector well, delivered approximately 5.4 MBls of oil and 0.9 Bcf of natural gas, averaging 30,481 per day.

Certain operating statistics for the three and six months ended June 30, 2012 and 2011 for the Petrodelta fields operated by Petrodelta are set forth below. This information is provided at 100 percent. This information may not be representative of future results.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011

Thousand barrels of oil sold		3,314		2,782		6,298		5,365
Million cubic feet of gas sold		494		440		1,124		910
Total thousand barrels of oil equivalent		3,396		2,855		6,485		5,517
Average price per barrel	$	96.10	$	101.72	$	102.09	$	94.98
Average price per thousand cubic feet	$	1.54	$	1.54	$	1.54	$	1.54
Cash operating costs ($millions)	$	20.1	$	18.7	$	41.6	$	33.0
Capital expenditures ($ millions)	$	44.5	$	32.1	$	70.6	$	66.5

Under Petrodelta’s Contract for Sale and Purchase of Hydrocarbons with PDVSA Petroleo S.A. (“PPSA”), a wholly owned subsidiary of PDVSA, (the “Sales Contract”), crude oil delivered from the Petrodelta fields to PDVSA is priced with reference to Merey 16 published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices are quoted and sold in U.S. Dollars. Natural gas delivered from the Petrodelta Fields to PDVSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make payment to Petrodelta in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered. Natural gas deliveries are paid in Bolivars, but the pricing for natural gas is referenced to the U.S. Dollar.

The official price formula applied to the Merey 16 by the Ministry of the People’s Power for Energy and Petroleum (“MENPET”) is used for the sales of Petrodelta crude oil with quality close to 16 degrees API to represent actual quality delivered.

As disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011, production from the Petrodelta fields, except the El Salto field, flows through Petrodelta’s pipelines into PDVSA’s EPT-1 storage facility. Prior to October 2011, El Salto production was trucked to the EPT-1 storage facility and combined with the other Petrodelta fields’ production. Beginning October 2011, production from the El Salto field flows through PDVSA’s EPM-1 transfer point at PDVSA Morichal. Currently, the El Salto production flows through COMOR transfer point, a new transfer point for Petrodelta, at PDVSA Morichal.

When the Sales Contract was executed, Petrodelta was producing only one type of crude, Merey 16. Therefore, the Sales Contract provides for only one crude pricing formula. This formula has been approved by MENPET. The production deliveries and factors to include in the pricing formula are certified and acknowledged by MENPET.

Beginning in October 2011, MENPET determined that Petrodelta’s production flowing through the COMOR transfer point was a heavier type of crude, Boscan. The Boscan gravity and sulphur correction factors and crude pricing formula are not included in the Sales Contract. However, under the Sales Contract, PDVSA is obligated to receive all of Petrodelta’s production. All production deliveries for all of Petrodelta fields have been certified by MENPET and acknowledged by PDVSA.

Due to PDVSA’s liquidity constraints, PDVSA has not been providing the necessary monetary and contractual support required by Petrodelta. Continued underinvestment in the development plan may lead to continued under-performance. As discussed in previous filings, PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors, including Harvest Vinccler. As a result, Petrodelta has experienced, and is continuing to experience, difficulty in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is having an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.

Per our interpretation of the amended Windfall Profits Tax, the $70 cap on royalty barrels should only be applied to the 3.33 percent royalty which Petrodelta pays in cash. We have applied the $70 cap to only the 3.33 percent royalty paid in cash and the current oil sales price to the 30 percent royalty paid in-kind for the three and six months ended June 30, 2012 and 2011. With assistance from Petrodelta, we have recalculated Petrodelta’s oil sales and royalties to apply the current oil price to its total barrels produced and to the 30 percent royalty paid in-kind and applied the $70 cap to the 3.33 percent royalty paid in cash for the three and six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012 and 2011, net oil sales (oil sales less royalties) are slightly higher, $2.9 million and $2.9 million ($0.9 million and $0.9 million net to our 32 percent interest), respectively, and for the six months ended June 30, 2012 and 2011, net oil sales (oil sales less royalties) are slightly higher, $6.7 million and $4.5 million ($2.1 million and $1.4 million net to our 32 percent interest), respectively, under this method than the method advised by PDVSA and the method of applying the current oil price to total barrels produced and to total royalty barrels.

In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance, B.V. (“HNR Finance”), a wholly owned subsidiary of Harvest Holding, ($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, as of August 3, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain.

The Organic Law on Sports, Physical Activity and Physical Education (“Sports Law”) was published in the Official Gazette on August 23, 2011 and is effective beginning January 1, 2012. The purpose of the Sports Law is to establish the public service nature of physical education and the promotion, organization and administration of sports and physical activity. Funding of the Sports Law is by contributions made by companies or other public or private organizations that perform economic activities for profit in Venezuela. The contribution is one percent of annual net or accounting profit and is not deductible for income tax purposes. Per the Sports Law, contributions are to be calculated on an after-tax basis. However, CVP has instructed Petrodelta to calculate the contribution on a before-tax basis contrary to the Sports Law. For the three and six months ended June 30, 2012, this method of calculation overstates the liability for the Sports Law contribution by $0.4 million and $0.8 million ($0.1 million and $0.2 million net to our 32 percent interest), respectively. We have adjusted for the over accrual of the Sports Law in the three and six months ended June 30, 2012 net income from Equity affiliate. See Operations – Restatement of Prior Period Financial Statements above.

Budong-Budong Project, Indonesia

Operational activities during the six months ended June 30, 2012 included rigging down operations of the drilling rig on the Karama-1 (“KD-1”) location and review of geological and geophysical data obtained from the drilling of the Lariang-1 (“LG-1”) and KD-1 wells. Based on the multiple oil and gas shows encountered in both LG-1 and KD-1, we are working on an exploration program targeting the Pliocene and Miocene sands encountered in the previous two wells. We have completed remapping of both the Lariang and Karama Basins with eight prospects in the Lariang Basin and five prospects in the Karama Basin having been identified in the Pliocene, Middle-Late Miocene and Eocene sands. The initial exploration term of the Budong-Budong Production Sharing Contract (“Budong PSC”) expires on January 16, 2013. We will be requesting a four year extension of the initial exploration period to enable us to complete exploration activities on the Budong PSC.

The remaining work commitment for the current exploration phase on the Budong PSC is for geological and geophysical work to be completed during 2012 at a minimum of $0.5 million ($0.3 million net to our 64.51 percent cost sharing interest). However, per the Budong PSC, excessive work done during any period can be offset against another period, so although there is a work commitment in the Budong PSC to perform the geological and geophysical work, we have exceeded this requirement. BPMIGAS, Indonesia’s oil and gas regulatory authority, has stated that we have satisfied all work commitments for the current exploration phase of the Budong PSC.

During the six months ended June 30, 2012, we had cash capital expenditures of $5.9 million (RESTATED) for plugging and abandonment costs.

Dussafu Project – Gabon

The Dussafu Marin Permit (“Dussafu PSC”) partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources, entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. In order to complete drilling activities of the Dussafu Ruche Marin-A (“DRM-1”) exploratory well, in March 2011, the Direction Generale Des Hydrocarbures (“DGH”) approved a one year extension to May 27, 2012 of the second exploration phase. We do not have any remaining work commitments for the second exploration phase. On April 27, 2012, we submitted notification to the DGH of our intent to enter the third exploration phase of the Dussafu PSC with an effective date of May 28, 2012. The DGH has agreed to lengthen the third exploration phase to four years until May 27, 2016. The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period. We paid a $1.0 million bonus ($0.7 million net to our 66.667 percent interest) to enter the third exploration phase.

Operational activities during the six months ended June 30, 2012 included processing of the 545 square kilometers of seismic which was acquired in the fourth quarter of 2011 and well planning. The 3-D Pre-Stack Time Migration (“PSTM”) was completed in July 2012. Pre-Stack Depth processing and reprocessing of the 2005 Inboard 3-D seismic of approximately 1,300 square kilometers commenced in June 2012. Well planning is in progress to drill an exploration well in the fourth quarter of 2012 on the Tortue prospect to target stacked pre-salt Gamba and Dentale reservoirs as well as a secondary post-salt Madiela clastic reservoir. On July 17, 2012, we signed a contract for the Scarabeo 3 semi-submersible drilling rig. Mobilization of the drilling rig to the well site in Gabon is scheduled to commence the beginning of October 2012. In the event that we elect to terminate the contract prior to the rig’s arrival on-site, we are obligated to compensate the drilling company $5.0 million ($3.3 million net to our 66.667 percent interest) for liquidated damages.

During the six months ended June 30, 2012, we had cash capital expenditures of $1.4 million (RESTATED) for seismic processing.

Block 64 EPSA Project – Oman

All work commitments on the Al Ghubar/Qarn Alam License (“Block 64 EPSA”) have been completed and post well studies are being conducted. A one year extension for the Block 64 EPSA was granted until May 2013, at which time we must decide whether to commit to the Second Phase of the Block 64 EPSA. The Second Phase exploration phase of the Block 64 EPSA has an $11.0 million work commitment over a three year period.

During the six months ended June 30, 2012, we incurred $5.8 million for drilling and plugging and abandonment costs.

Risks, Uncertainties, Capital Resources and Liquidity

Petrodelta also has a material impact on our results of operations for any quarterly or annual reporting period. See Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 10 – Investment in Equity Affiliate – Petrodelta. Petrodelta operates under a business plan, the success of which relies heavily on the market price of oil. To the extent that market prices of oil decline, the business plan, and thus our equity investment and/or operations and/or profitability, could be adversely affected.

On June 21, 2012, we and our wholly owned subsidiary HNR Energia entered into a share purchase agreement (the “SPA”) with PT Pertamina (Persero), a state-owned limited liability company existing under the laws of Indonesia (“Buyer”) for the sale of our interest in Venezuela for a cash purchase price of $725.0 million. See Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 9 – Venezuela, Share Purchase Agreement. We cannot assure you that the SPA will be consummated. The consummation of the SPA is subject to the satisfaction or waiver of a number of conditions, including, among others, the requirement that approvals are received from the Government of the Bolivarian Republic of Venezuela, the Government of the Republic of Indonesia, and the majority of our stockholders; requirements with respect to the accuracy of the representations and warranties of the parties to the SPA; and requirements with respect to the satisfaction or waiver of the covenants and obligations of the parties to the SPA. In addition, the SPA may be terminated in certain circumstances under the terms of the SPA. We cannot guarantee that the parties to the SPA will be able to meet all of the closing conditions of the SPA. If we are unable to meet all of the closing conditions, the

Buyer would not be obligated to close the SPA. We also cannot be sure that circumstances, such as a material adverse effect, will not arise that would also allow the Buyer to terminate the SPA prior to closing. If the SPA does not close, our Board of Directors will be forced to evaluate other alternatives, which may be less favorable to us than the SPA. There can be no assurances as to whether this transaction will close or whether we will receive any cash proceeds related to the SPA.

Our cash is being used to fund oil and gas exploration projects, debt, interest, and to a lesser extent general and administrative costs. We require capital principally to fund the exploration and development of new oil and gas properties. As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. We do not have any remaining work commitments for the current exploration phases of the Budong PSC or Block 64 EPSA. We entered the third exploration phase of the Dussafu PSC on May 28, 2012. The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period (see Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 12 – Gabon). This work commitment is non-discretionary; however, we do have the ability to control the pace of expenditures. On July 17, 2012, we signed a contract for a semi-submersible drilling rig to drill an exploration well on the Gabon PSC. In the event that we elect to terminate the contract prior to the rig’s arrival on-site, we are obligated to compensate the drilling company $5.0 million ($3.3 million net to our 66.667 percent interest) for liquidated damages (see Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 16 – Subsequent Events).

Between Petrodelta’s formation in October 2007 and June 2010, Petrodelta declared and paid dividends of $105.5 million to HNR Finance, B.V. (“HNR Finance”), a wholly owned subsidiary of Harvest Holding ($84.4 million net to our 32 percent interest). In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, this dividend has not yet been received, although it is due and payable. There is uncertainty of the timing of receipt of the dividend receivable from Petrodelta and whether Petrodelta will declare or pay additional dividends in 2012 or 2013. See Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 14 – Related Party Transactions for a discussion of our obligations to our non-controlling interest holder, Vinccler, for any dividend received from Petrodelta. Also, any receipt of dividends while the SPA is active would become a purchase price adjustment under the SPA. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable not be collected timely, or facts and circumstances surrounding our investment change, our results of operations and our investment in Petrodelta could be adversely impacted. If facts and circumstances change, it is possible we could conclude our investment in Petrodelta should be accounted for using the cost method of accounting rather than the equity method of accounting. If that were to occur, the operations of Petrodelta would no longer be included in our results of operations.

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


	Six Months Ended June 30,
	2012			2011
	(in thousands)
	(RESTATED*)			(RESTATED*)

Net cash used in operating activities	$	(18,210	)	$	(14,855	)
Net cash provided by (used in) investing activities		(12,096	)		151,957
Net cash provided by (used in) financing activities		106			(59,773	)

Net increase (decrease) in cash and cash equivalents	$	(30,200	)	$	77,329

*	See Operations – Restatement of Prior Period Financial Statements above.

At June 30, 2012, we had current assets of $51.5 million and current liabilities of $30.0 million, resulting in working capital of $21.5 million and a current ratio of 1.7:1. This compares with a working capital of $62.6 million and a current ratio of 3.1:1 at December 31, 2011. The decrease in working capital of $41.1 million was primarily due to decreases in receivables and increases in cash payments for capital expenditures.

Cash Flow used in Operating Activities. During the six months ended June 30, 2012 and 2011, net cash used in operating activities was approximately $18.2 million and $14.9 million, respectively. The $3.3 million increase was primarily due to decreases in accounts payable and accrued expenses offset by decreases in receivables.

Cash Flow from Investing Activities. Our cash capital expenditures for property and equipment are summarized in the following table:


	June 30,
	2012		2011
	(in millions)
	(RESTATED*)		(RESTATED*)

Budong PSC	$	5.9	$	13.1
Dussafu PSC		1.4		13.7
Block 64 EPSA		5.8		0.7
Other projects		—		0.4

Total additions of property and equipment –continuing operations		13.1		27.9
Assets Held for Sale – Antelope Project⁽¹⁾		—		31.7

Total additions of property and equipment	$	13.1	$	59.6

⁽¹⁾	See Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 4 – Dispositions.

*	See Operations – Restatement of Prior Period Financial Statements above.

During the six months ended June 30, 2012, we:

•

Had $1.2 million of restricted cash returned to us; and

•

Advanced $0.3 million to Petrodelta for continuing operations costs, and Petrodelta repaid $0.1 million.

During the six months ended June 30, 2011, we:

•

Received $217.8 million for the sale of our Antelope Project (see Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 4 – Dispositions);

•

Received $1.4 million from the sale of our equity investment in Fusion;

•

Deposited $7.3 million as collateral for two standby letters of credit issued in support of the drilling activities on the Gabon PSC; and

•

Advanced $0.4 million to Petrodelta for continuing operations costs, and Petrodelta repaid $0.1 million.

Petrodelta’s capital commitments will be determined by its business plan. Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. Our budgeted capital expenditures of $25.5 million for 2012 for Indonesia, Gabon and Oman operations will be funded through our existing cash balances, accessing equity and debt markets, and cost reductions. In addition, we could delay the discretionary portion of our capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, as warranted.

Cash Flow from Financing Activities. During the six months ended June 30, 2012 we:

•

Incurred $0.2 million in legal fees associated with financings.

During the six months ended June 30, 2011, we:

•

Repaid $60.0 million of our term loan facility; and

•

Incurred $0.2 million in legal fees associated with financings.

Contractual Obligations


	Payments (in thousands) Due by Period
Contractual Obligation	Total		Less than 1 Year		1-2 Years		3-4 Years		After 4 Years
Debt:
8.25% Senior Convertible Note Due 2013	$	15,551	$	15,551	$	—	$	—	$	—

Total Debt		15,551		15,551		—		—		—


Other obligations:
Interest payments		855		855		—		—		—
Oil and gas activities		8,000		8,000		—		—		—
Office leases		1,681		865		645		148		23

Total other obligations		10,536		9,720		645		148		23


Total contractual obligations	$	26,087	$	25,271	$	645	$	148	$	23

We do not have any remaining work commitments for the current exploration phases of the Budong PSC or Block 64 EPSA.

As of May 28, 2012, the Dussafu PSC entered the third exploration phase. The third exploration phase has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period.

On July 17, 2012, we signed a contract for a semi-submersible drilling rig to drill an exploration well on the Gabon PSC. In the event that we elect to terminate the contract prior to the rig’s arrival on-site, we are obligated to compensate the drilling company $5.0 million ($3.3 million net to our 66.667 percent interest) for liquidated damages.

Results of Operations

You should read the following discussion of the results of operations for the three and six months ended June 30, 2012 and 2011 and the financial condition as of June 30, 2012 and December 31, 2011 in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2011.

Three Months Ended June 30, 2012 (RESTATED) Compared with Three Months Ended June 30, 2011 (RESTATED)

We reported net income attributable to Harvest of $6.2 million, or $0.15 diluted earnings per share, for the three months ended June 30, 2012, compared with net income attributable to Harvest of $92.8 million, or $2.73 diluted earnings per share, for the three months ended June 30, 2011.

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


	Three Months Ended June 30,						Increase (Decrease)
	2012			2011			Increase (Decrease)
	(RESTATED*)			(RESTATED*)
Depreciation and amortization		0.1		$	0.1		$	—
Exploration expense		1.7			1.4			0.3
Impairment of oil and gas properties		—			3.3			(3.3	)
Dry hole costs		0.1			—			0.1
General and administrative		6.5			7.0			(0.5	)
Investment earnings and other		(0.1	)		(0.2	)		0.1
Unrealized (gain) loss on warrant derivative		1.6			(7.1	)		8.7
Interest expense		—			2.2			(2.2	)
Loss on extinguishment of debt		—			13.1			(13.1	)
Other non-operating expenses		1.5			0.2			1.3
Income tax expense (benefit)		(1.0	)		0.3			(1.3	)

*	See Operations – Restatement of Prior Period Financial Statements above.

During the three months ended June 30, 2012, we incurred $1.2 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, $0.4 million of lease maintenance costs, and $0.1 million related to other general business development activities. During the three months ended June 30, 2011, we incurred $1.3 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations and $0.1 million related to other general business development activities.

During the three months ended June 30, 2012, we did not impair any oil and gas properties. During the three months ended June 30, 2011, we impaired $3.3 million related to the carrying value of West Bay.

During the three months ended June 30, 2012, we expensed to dry hole costs $0.1 million related to the drilling of the AGN-1 on the Block 64 EPSA (see Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Budong-Budong Project, Indonesia and Block 64 EPSA Project – Oman). We did not record any dry hole costs in the three months ended June 30, 2011.

The decrease in general and administrative costs in the three months ended June 30, 2012 from the three months ended June 30, 2011 was primarily due to lower general office expense and overhead ($1.2 million) offset by higher employee related costs ($0.5 million) and contract services ($0.2 million).

The decrease in investment earnings and other in the three months ended June 30, 2012 from the three months ended June 30, 2011 was due to the receipt during the three months ended June 30, 2011 of payment for transition services provided on the Antelope Project after closing of the sale.

The increase in unrealized loss on warrant derivatives in the three months ended June 30, 2012 from the three months ended June 30, 2011 was due to the change in fair value for our warrant derivative liabilities: $3.63 per warrant at June 30, 2012 and $6.32 per warrant at June 30, 2011.

The decrease in interest expense in the three months ended June 30, 2012 from the three months ended June 30, 2011 was due to the repayment in May 2011 of our $60 million term loan facility and interest capitalized to oil and gas properties of $0.5 million.

During the three months ended June 30, 2011, we incurred a loss on extinguishment of debt related to the early payment of our $60 million term loan facility. The loss on extinguishment of debt includes the write off of the discount on debt ($10.7 million), a prepayment premium of 3.5 percent of the amount outstanding ($2.1 million), expensing of financing costs related to the term loan facility ($0.3 million), and the cost to repurchase 4.4 million unvested warrants issued in connection with the term loan facility.

The increase in other non-operating expense in the three months ended June 30, 2012 from the three months ended June 30, 2011 was due to costs incurred related to our strategic alternative process and evaluation which resulted in the SPA for the sale of our 32 percent interest in Petrodelta.

The decrease in income tax expense in the three months ended June 30, 2012 from the three months ended June 30, 2011 is due to $1.4 million of projected U.S. income tax benefits associated with the carryback to the 2011 income tax year of net operating losses projected to be incurred in the 2012 income tax year offset by a reclassification from income tax expense on continuing operations to income tax expense on discontinued operations.

Equity in Earnings from Unconsolidated Equity Affiliates

For the three months ended June 30, 2012, net income from unconsolidated equity affiliates reflects an increase in Petrodelta’s revenue from oil sales due to higher sales volumes ($51.2 million) offset by lower prices ($15.6 million). Royalties, which is a function of revenue, increased $9.9 million due to the increase in revenue (net increase in revenue of $35.6 million at 30 percent royalty). Windfall Profits Tax, which is a function of volume and price per barrel, increased $9.3 million due to an increase in volumes (2012: 3.3 MBls vs. 2011: 2.8 MBls) offset by the decrease in price received per barrel (2012: $96.10 per barrel vs. 2011: $101.72 per barrel). The increase in operating expense in the three months ended June 30, 2012 from the three months ended June 30, 2011 was due to increased oil production. The decrease in workover expense in the three months ended June 30, 2012 from the three months ended June 30, 2011 was due to fewer workovers being performed. Petrodelta’s effective tax rate (inclusive of the adjustments to reconcile to reported net income from unconsolidated equity affiliate) for the three months ended June 30, 2012 was consistent with the effective tax rate for the three months ended June 30, 2011.

Discontinued Operations

During the three months ended June 30, 2012, we incurred write-offs of $5.2 million of accounts and note receivable and $3.6 million of accounts payable, carry obligation related to the settlement of all outstanding claims with a private third party on the Antelope Project (see Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 2 – Summary of Significant Accounting Policies, Notes Receivable and Note 6 – Commitments and Contingencies).

Revenue and net loss on the disposition of the Antelope Project are shown in the table below:


	Three Months Ended June 30,
	2012			2011
	(in thousands)
	(RESTATED*)
Revenues applicable to discontinued operations	$	—		$	2,368
Net income (loss) from discontinued operations		(1,584	)		98,665

*	See Operations – Restatement of Prior Period Financial Statements above.

Six Months Ended June 30, 2012 (RESTATED) Compared with Six Months Ended June 30, 2011 (RESTATED)

We reported net income attributable to Harvest of $5.2 million, or $0.14 diluted earnings per share, for the six months ended June 30, 2012, compared with net income attributable to Harvest of $89.7 million, or $2.64 diluted earnings per share, for the six months ended June 30, 2011.

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


	Six Months Ended June 30,						Increase (Decrease)
	2012			2011
	(RESTATED*)			(RESTATED*)
Depreciation and amortization	$	0.2		$	0.2		$	—
Exploration expense		3.6			2.7			0.9
Impairment of oil and gas properties		—			3.3			(3.3	)
Dry hole costs		5.6			—			5.6
General and administrative		12.4			13.7			(1.3	)
Investment earnings and other		(0.1	)		(0.4	)		0.3
Unrealized (gain) loss on warrant derivative		1.2			(4.5	)		5.7
Interest expense		0.1			5.7			(5.6	)
Debt conversion expense		2.4			—			2.4
Loss on extinguishment of debt		—			13.1			(13.1	)
Other non-operating expenses		1.7			0.7			1.0
Income tax expense (benefit)		(2.2	)		0.7			(2.9	)

*	See Operations – Restatement of Prior Period Financial Statements above.

During the six months ended June 30, 2012, we incurred $2.4 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, $0.9 million of lease maintenance costs, and $0.3 million related to other general business development activities. During the six months ended June 30, 2011, we incurred $2.3 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations, $0.2 million of lease maintenance costs, and $0.2 million related to other general business development activities,

During the six months ended June 30, 2012, we did not impair any oil and gas properties. During the six months ended June 30, 2011, we impaired $3.3 million related to the carrying value of West Bay.

During the six months ended June 30, 2012, we expensed to dry hole costs $0.7 million related to the drilling of the KD-1 well on the Budong PSC and $4.9 million related to the drilling of the AGN-1 on the Block 64 EPSA (see Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Budong-Budong Project, Indonesia and Block 64 EPSA Project – Oman). We did not record any dry hole costs in the six months ended June 30, 2011.

The decrease in general and administrative costs in the six months ended June 30, 2012 from the six months ended June 30, 2011 was primarily due to lower general office expense and overhead ($1.6 million) and employee related costs ($0.3 million) offset by higher contract services ($0.6 million).

The decrease in investment earnings and other in the six months ended June 30, 2012 from the six months ended June 30, 2011 was due to the receipt during the six months ended June 30, 2011 of payment for transition services provided on the Antelope Project after closing of the sale.

The decrease in interest expense in the six months ended June 30, 2012 from the six months ended June 30, 2011 was due to the repayment in May 2011 of our $60 million term loan facility, conversion of $16 million of our 8.25 percent senior convertible notes on March 14, 2012, and interest capitalized to oil and gas properties of $1.2 million.

The increase in unrealized loss on warrant derivatives in the six months ended June 30, 2012 from the six months ended June 30, 2011 was due to the change in fair value for our warrant derivative liabilities: $3.63 per warrant at June 30, 2012 and $6.32 per warrant at June 30, 2011.

During the six months ended June 30, 2012, we incurred debt conversion expense related to the issuance of 0.2 million shares of our common stock in exchange for certain holders of our senior convertible notes foregoing a one-year interest make-whole of $1.3 million. The debt conversion expense consists of bond conversion expenses ($0.6 million), interest expense make-whole provision satisfied by the issuance of 0.2 million common shares ($1.3 million) and legal and other professional fees ($0.5 million).

During the six months ended June 30, 2011, we incurred a loss on extinguishment of debt related to the early payment of our $60 million term loan facility. The loss on extinguishment of debt includes the write off of the discount on debt ($10.7 million), a prepayment premium of 3.5 percent of the amount outstanding ($2.1 million), expensing of financing costs related to the term loan facility ($0.3 million), and the cost to repurchase 4.4 million unvested warrants issued in connection with the term loan facility.

The increase in other non-operating expense in the six months ended June 30, 2012 from the six months ended June 30, 2011 was due to costs incurred related to our strategic alternative process and evaluation which resulted in the SPA for the sale of our 32 percent interest in Petrodelta.

The decrease in income tax expense in the six months ended June 30, 2012 from the six months ended June 30, 2011 is due to $3.0 million of projected U.S. income tax benefits associated with the carryback to the 2011 income tax year of net operating losses projected to be incurred in the 2012 income tax year offset by income tax expense incurred during the six months ended June 30, 2011.

Equity in Earnings from Unconsolidated Equity Affiliates

For the six months ended June 30, 2012, net income from unconsolidated equity affiliates reflects an increase in Petrodelta’s revenue from oil sales due to higher sales volumes ($95.6 million) and prices ($38.1 million). Royalties, which is a function of revenue, increased $39.9 million due to the increase in revenue (net increase in revenue of $133.7 million at 30 percent royalty). Windfall Profits Tax, which is a function of volume and price received per barrel, increased $67.0 million due to an increase in volumes (2012: 6.3 MBls vs. 2011: 5.4 MBls) and price received per barrel (2012: $102.09 per barrel vs. 2011: $94.98 per barrel). The increase in operating expense in the six months ended June 30, 2012 from the six months ended June 30, 2011 was due to increased oil production. The decrease in workover expense in the six months ended June 30, 2012 from the six months ended June 30, 2011 was due to fewer workovers being performed. Petrodelta’s effective tax rate (inclusive of the adjustments to reconcile to reported net income from unconsolidated equity affiliate) for the six months ended June 30, 2012 was consistent with the effective tax rate for the six months ended June 30, 2011.

Discontinued Operations

During the six months ended June 30, 2012, we incurred $0.1 million of expense related to settlement of royalty payments to the Mineral Management Services and write-offs of $5.2 million of accounts and note receivable and $3.6 million of accounts payable, carry obligation related to the settlement of all outstanding claims with a private third party on the Antelope Project (see Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 2 – Summary of Significant Accounting Policies, Notes Receivable and Note 6 – Commitments and Contingencies).

Revenue and net loss on the disposition of the Antelope Project are shown in the table below:


	Six Months Ended June 30,
	2012			2011
	(in thousands)
	(RESTATED*)
Revenues applicable to discontinued operations	$	—		$	6,488
Net income (loss) from discontinued operations		(1,699	)		95,399

*	See Operations – Restatement of Prior Period Financial Statements above.

Effects of Changing Prices, Foreign Exchange Rates and Inflation

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

Our net foreign exchange losses attributable to our international operations were minimal for the six months ended June 30, 2012 and 2011. There are many factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our control. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.

Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004, March 2005, January 2010 and again in January 2011. On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate with an effective date of January 1, 2011.

Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). However, during the six months ended June 30, 2012, Harvest Vinccler exchanged approximately $0.6 million through SITME and received an average exchange rate of 5.13 Bolivars per U.S. Dollar. The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Petrodelta does not have, and has not had, any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate. Harvest Vinccler currently does not have any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate.

See Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Venezuela for a more complete discussion of the exchange agreements and their effects on our Venezuelan operations.

Within the United States and other countries in which we conduct business, inflation has had a minimal effect on us, but it is potentially an important factor with respect to results of operations in Venezuela.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk from adverse changes of the situation in Venezuela, our exploration program and adverse changes in oil prices, interest rates, foreign exchange and political risk, as discussed in our Annual Report on Form 10-K for the year ended December 31, 2011. The information about market risk for the six months ended June 30, 2012 does not differ materially from that discussed in the Annual Report on Form 10-K for the year ended December 31, 2011.

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures. In our Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 filed on August 9, 2012, our management, including our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2012. In connection with the restatement of the unaudited consolidated condensed financial statements for the three and six months ended June 30, 2012 as discussed in Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 2 – Summary of Significant Accounting Policies, Restatement of Prior Period Financial Statements, a reevaluation was carried out under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Exchange Act Rule 13a-15(e), as amended, (the “Exchange Act”) as of June 30, 2012. Based on that evaluation and in light of the material weaknesses described below, our Chief Executive Officer and Chief Financial Officer concluded that as of June 30, 2012, our disclosure controls and procedures were not effective to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in rules and forms of the SEC, and is accumulated and communicated to our management as appropriate to allow timely decisions regarding required disclosure.

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 company’s annual or interim financial statements will not be prevented or detected on a timely basis.

Sufficient Complement of Accounting and Financial Reporting Resources

In certain areas, we did not maintain a sufficient complement of resources with an appropriate level of accounting knowledge, experience and training commensurate with our financial reporting requirements. This limited our ability, in certain areas, to ensure the necessary consistent communication, reinforcement, and application of accounting policies to make appropriate accounting and disclosure decisions. This material weakness contributed to the material weaknesses set forth below.

Accounting for Certain Transactions for Oil and Gas Properties

We did not maintain effective internal control over the accuracy, valuation and application of USGAAP related to capitalization, classification, and impairment of certain costs related to oil and gas properties. Specifically, effective controls were not designed or effectively operating to review the nature and classification of costs to be capitalized to oil and gas properties which impacts the accurate calculation of oil and gas property impairments. This control deficiency resulted in the misstatement of oil and gas properties, exploration expense, and related financial statement disclosures.

Accounting for Income Taxes

We did not maintain effective controls over the completeness, accuracy, presentation and disclosure of our accounting for income taxes, including income tax expense and income tax assets and liabilities. Specifically, we did not maintain effective controls to (1) document our analysis, considerations and evaluation of relevant facts related to our accounting judgments for income taxes, (2) account for uncertain tax positions, and (3) ensure appropriate recording and presentation of our net operating losses and associated valuation allowance and related footnote disclosures. This control deficiency resulted in the misstatement of income tax expense, deferred tax assets, our valuation allowance, and related financial statement disclosures.

Financial Reporting Process

We did not maintain effective internal control over certain of our financial close and reporting processes because of the following material weaknesses:

(a)

We did not maintain effective controls over segregation of duties related to certain system access rights and the recording and review of journal entries for validity, accuracy, and completeness for substantially all significant accounts. Specifically, certain individuals have incompatible access rights within key IT systems and certain accounting personnel have the ability to prepare and post journal entries without an independent review that is designed with sufficient rigor and precision to prevent or detect an error.

(b)

We did not maintain effective controls over the preparation and review of certain classification and disclosure matters impacting the financial statements and related notes. Specifically, controls are not designed and operating effectively to accumulate and review all information required to ensure complete, accurate, and proper presentation of the statement of cash flows and financial statement disclosures. This control deficiency resulted in the misstatement of cash provided by or used in investing and operating activities and related financial statement disclosures and the misstatement of segment information.

(c)

We did not maintain effective controls over significant and complex debt and equity transactions. Specifically, controls were not designed and operating effectively to ensure completeness and accuracy over the identification, evaluation, analysis and recording of significant and complex debt and equity transactions and the associated financial statement impact. This control deficiency resulted in the misstatement of additional paid-in capital, interest expense, unrealized gain (loss) on warrant derivatives, loss on extinguishment of debt and related financial statement disclosures.

Additionally, each of the control deficiencies described above could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements and financial statement schedule that would not be prevented or detected. Certain of these material weaknesses resulted in errors which required the restatement of our unaudited interim consolidated condensed financial statements for the three and six months ended June 30, 2012 and 2011.

Remediation Plan. In response to the identified material weaknesses, our management, with oversight from our Audit Committee will dedicate appropriate resources to remediate the material weaknesses described above. Until the remediation steps set forth below are fully implemented, the material weaknesses described above will continue to exist.

Management is taking the following actions to remediate the material weakness related to oil and gas unproved properties described above:

•

Formalize policies and procedures for the appropriate recording of oil and gas property transactions.

•

Train the accounting staff on the above policies and procedures.

•

Establish timely independent review and approval of oil and gas property transactions and schedules.

•

Redesign the controls for the evaluation, analysis, recording and review of oil and gas property transactions.

Management is taking the following actions to remediate the material weakness related to income tax accounting described above:

•

Formalize the policies and procedures for appropriate recording of income taxes.

•

Maintain and update memorandum to reflect the current status of income tax accounting positions and the relevant analysis, considerations and conclusions.

•

Redesign the controls for income taxes to ensure the level of precision and operating effectiveness required by management.

•

Redesign the controls for income taxes to ensure appropriate presentation and disclosure of the associated footnotes and financial statement schedule.

•

Supplement existing resources with additional personnel and additional training.

Management is taking the following actions to remediate the material weaknesses related to our Financial Reporting Process and complement of accounting and financial reporting resources:

•

Implement a sufficiently-designed control that is intended to ensure functions are appropriately segregated and that all journal entries are reviewed by an appropriate person.

•

Modify the system access of individuals with incompatible responsibilities and/or design compensating controls that operate at the appropriate level of precision to address the associated conflict.

•

Redesign the controls for the preparation, execution and review of the cash flow statement and financial statement disclosures.

•

Redesign certain entity-level monitoring controls and certain transaction level controls in order to achieve the level of precision and operating effectiveness required by management.

•

Redesign the controls over significant and complex debt and equity transactions to ensure appropriate identification, evaluation, analysis and recording of such transactions.

•

Supplement our accounting department with additional personnel and provide additional training to our personnel regarding the application of USGAAP.

Inherent Limitations of Internal Controls. Internal control over financial reporting has inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements will not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

Changes in Internal Control over Financial Reporting. There have been no changes in internal control over financial reporting during the quarter ended June 30, 2012 that have materially affected or are reasonably likely to materially affect that Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

In June 2012, the operator of the Budong PSC received notice of a claim related to the ownership of part of the land comprising the KD-1 drilling site. The claim asserts that the land upon which the drill site is located is partly owned by the claimant. The operator purchased the site from local landowners in January 2010, and the purchase was approved by BPMIGAS. The claimant is seeking compensation of 16 billion Indonesia Rupiah (approximately $1.7 million, $1.1 million net to our 64.51 percent cost sharing interest) for land that was purchased at a cost of $4,100 in January 2010. A formal mediation hearing to assess the conflicting claims of ownership is scheduled for August 9, 2012. The operator disputes the landowner’s claim and plans to vigorously defend against it.

In May 2012, Newfield Production Company (“Newfield”) filed notice pursuant to the Purchase and Sale Agreement between Harvest (US) Holdings, Inc. (“Harvest US”) and Newfield dated March 21, 2011 (the “PSA”) of a potential environmental claim involving certain wells drilled on the Antelope Project. The claim asserts that locations constructed by Harvest were built on, within, or otherwise impact or potentially impact wetlands and other water bodies. The notice asserts that to the extent of potential penalties or other obligations that might result from potential violations that Harvest US indemnifies Newfield pursuant to the PSA. In June 2012, we provided Newfield with notice pursuant to the PSA (1) denying that Newfield has any right to indemnification from us, (2) alleging that any potential environmental claim related to Newfield’s notice would be an assumed liability under the PSA and (3) asserting that Newfield indemnify us pursuant to the PSA. We dispute Newfield’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.

In October 2007, we entered into a Joint Exploration and Development Agreement (“JEDA”) with a private third party with respect to the Antelope Project. On January 11, 2011, in connection with the sale of each party’s interests in the Antelope Project (see Notes to Consolidated Financial Statements – Note 4 – Dispositions), we entered into a letter agreement with the private third party wherein the private third party agreed to reimburse us for certain expenses related to the sale of the two parties’ interests in the Antelope Project. The private third party disputes our calculation of the amount owed to us pursuant to the January 11, 2011 letter agreement. On March 11, 2011, we entered into a letter agreement with the private third party regarding certain obligations between the parties related to the JEDA. The private third party disputes our calculation of the amount due pursuant to one of the items in the March 11, 2011 letter agreement. At March 31, 2012, we had a note receivable outstanding from the private third party of $3.3 million (see Notes to Consolidated Financial Statements – Note 2 – Summary of Significant Accounting Policies, Notes Receivable), an account receivable from the private third party of $2.7 million, and an account payable outstanding to the private third party of $3.6 million related to the purchase in July 2010 of an incremental 10 percent interest in the Antelope Project. On June 13, 2012, the parties agreed to settle all outstanding claims for $0.8 million net payable to Harvest.

See our Annual Report on Form 10-K for the year ended December 31, 2011 for a description of certain other legal proceedings. There have been no material developments in such legal proceedings since the filing of such Annual Report.

Item 1A.

Risk Factors

We operate in many different jurisdictions and we could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar worldwide anti-corruption laws. The U.S. Foreign Corrupt Practices Act (“FCPA”) and similar worldwide anti-corruption laws, including the U.K. Bribery Act 2010, which is broader in scope than the FCPA, generally prohibit companies and their intermediaries from making improper payments to government and other officials for the purpose of obtaining or retaining business. Our internal policies mandate compliance with these anti-corruption laws. Despite our training and compliance programs, we cannot be assured that our internal control policies and procedures will always protect us from acts of corruption committed by our employees or agents. Our continued expansion outside the U.S., including in developing countries, could increase the risk of such violations in the future. Violations of these laws, or allegations of such violations, could disrupt our business and result in a material adverse effect on our financial condition, results of operations and cash flows.

There is no assurance that the SPA will be completed, and our inability to consummate the SPA could harm the market price of our common stock and our business, results of operations and financial condition. If our stockholders fail to approve the proposed Transaction, or if the proposed Transaction is not completed for any other reason, the market price of our common stock may decline. In addition, failure to complete the proposed Transaction will result in a reduction in the amount of cash otherwise available to us and may substantially limit our ability to implement our business strategy.

We cannot assure you that the SPA will be consummated. The consummation of the SPA is subject to the satisfaction or waiver of a number of conditions, including, among others, the requirement that we obtain stockholder approval of the SPA, requirements with respect to the accuracy of the representations and warranties of the parties to the SPA and requirements with respect to the satisfaction or waiver of the covenants and obligations of the parties to the SPA. In addition, the SPA may be terminated in certain circumstances under the terms of the SPA.

We cannot guarantee that the parties to the SPA will be able to meet all of the closing conditions of the SPA.

If we are unable to meet all of the closing conditions, the Buyer would not be obligated to close the SPA. We also cannot be sure that circumstances, such as a material adverse effect, will not arise that would also allow the Buyer to terminate the SPA prior to closing. If the SPA is not approved by our stockholders or does not close, our Board of Directors will be forced to evaluate other alternatives, which may be less favorable to us than the SPA.

In addition, if the SPA is not consummated, our directors, executive officers and other employees will have expended extensive time and effort and will have experienced significant distractions from their work during the pendency of the transaction and we will have incurred significant transaction costs, in each case, without any commensurate benefit.

While the SPA is pending, it creates uncertainty about our future which could have a material and adverse effect on our business, financial condition and results of operations. While the SPA is pending, it creates uncertainty about our future. As a result of this uncertainty, our current or potential business partners may decide to delay, defer or cancel entering into new business arrangements with us pending completion or termination of the SPA. In addition, while the SPA is pending, we are subject to a number of risks, including:

•

the diversion of management and employee attention from our day-to-day business;

•

the potential disruption to business partners and other service providers; and

•

the possible inability to respond effectively to competitive pressures, industry developments and future opportunities.

The occurrence of any of these events individually or in combination could have a material adverse effect on our business, financial condition and results of operation.

The SPA restricts our ability to manage the operations of Harvest Holding and its subsidiaries. The SPA contains provisions that obligate us to cause Harvest Holding and its subsidiaries to conduct their business in the ordinary course of business, and prohibit us from causing or permitting Harvest Holding and its subsidiaries from undertaking or entering into certain actions and transactions. These provisions restrict our ability to cause or permit Harvest Holding and its subsidiaries, other than Petrodelta, from, among other things, amending its governing documents, issuing securities, incurring indebtedness, and acquiring or selling assets. The SPA also prohibits us from causing or permitting Petrodelta from amending its governing document in certain respects. These prohibitions restrict us from causing or permitting Harvest Holding and its subsidiaries from taking certain actions or entering into certain transactions that we might otherwise deem to be in the best interest of those companies.

The SPA limits our ability to pursue alternatives to the SPA. The SPA contains provisions that make it more difficult for us to sell our interests in Venezuela to a party other than the Buyer or to enter into other transactions relating to our company as a whole. These provisions include a non-solicitation provision (including certain matching rights), a provision requiring that we submit the SPA to our stockholders for approval unless the SPA has been terminated in accordance with its terms, and provisions obligating us to pay the Buyer a termination fee of three percent of the purchase price under certain circumstances. These provisions could discourage a third party that might have an interest in acquiring all of or a significant part of our interests in Venezuela or our assets or company as a whole from considering or proposing such an acquisition, even if that party were prepared to pay consideration with a higher value than the consideration to be paid by the Buyer.

If the SPA is not completed, there may not be any other offers from potential acquirers. If the SPA is not completed, we may seek another purchaser for our interests in Venezuela. There can be no assurances that we would be able to enter into meaningful discussions or to otherwise complete any transaction with any other party who may have an interest in purchasing our Venezuelan interests on terms acceptable to us.

The SPA may expose us to contingent liabilities. Under the SPA, we have agreed to indemnify the Buyer for a breach or inaccuracy of any representation, warranty or covenant made by us in the SPA, subject to certain limitations. Significant indemnification claims by the Buyer could have a material adverse effect on our financial condition.

We are not permitted to terminate the SPA except in limited circumstances, and we may be required to pay a substantial termination fee to the Buyer if the SPA is terminated. The SPA does not generally allow us to terminate it, except in certain limited circumstances. If the SPA is terminated because our Board of Directors determines to accept a superior proposal (as defined in the SPA), we would be obligated to pay the Buyer a termination fee of $21.8 million, or three percent of the purchase price. In addition, if the SPA is terminated because our stockholders fail to approve the transaction at a time when we have an outstanding acquisition proposal and we enter into an alternative acquisition agreement with the person making such acquisition proposal within 12 months following the date of such termination, we would be obligated to pay the Buyer a termination fee of $21.8 million, or three percent of the purchase price. Any payment of the termination fee would substantially increase the cost of completing any alternative transaction involving our interests in Venezuela and would effectively reduce any net proceeds available to us resulting from the consummation of such an alternative transaction. If the SPA is terminated for other reasons under its terms, we would not be required to pay the termination fee, but those circumstances are narrowly defined in the SPA.

See our Annual Report on Form 10-K for the year ended December 31, 2011 under Item 1A Risk Factors for a description of other risk factors. There have been no other material developments in such risk factors since the filing of such Annual Report.

Item 6.

Exhibits

(a)

Exhibits


3.1		Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.)

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

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

4.2		Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.2 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.)

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

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

10.1		Form of Stock Appreciation Right Award Agreement. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on August 4, 2009, File No. 1-10762.)

10.2		Form of Stock Unit Award Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 4, 2009, File No. 1-10762.)

10.3		Form of Director Stock Unit Award Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 4, 2009, File No. 1-10762.)

10.4		Form of Employee Stock Unit Award Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 4, 2009, File No. 1-10762.)

10.5		Form of Employee Stock Appreciation Right Award Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 4, 2009, File No. 1-10762.)

10.6		Share Purchase Agreement dated June 21, 2012, by and among HNR Energia BV, Harvest Natural Resources, Inc. and PT Pertamina (Persero). (Incorporated by reference to Exhibit 2.1 to our Form 8-K filed on June 21, 2012, file No. 1-10762.)

10.7		Guarantee of Harvest Natural Resources, Inc. dated June 21, 2012. (Incorporated by reference to Exhibit 2.2 to our Form 8-K filed on June 21, 2012, file No. 1-10762.)

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

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

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

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

101.INS		XBRL Instance Document


101.SCH		XBRL Schema Document

101.CAL		XBRL Calculation Linkbase Document

101.DEF		XBRL Definition Linkbase Document

101.LAB		XBRL Label Linkbase Document

101.PRE		XBRL Presentation Linkbase Document

SIGNATURES

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


	HARVEST NATURAL RESOURCES, INC.

Dated: May 13, 2013	By:	/s/ James A. Edmiston
		James A. Edmiston
		President and Chief Executive Officer

Dated: May 13, 2013	By:	/s/ Stephen C. Haynes
		Stephen C. Haynes
		Vice President – Finance, Chief Financial Officer and Treasurer

Exhibit Index


Exhibit Number		Description

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

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

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

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

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

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

10.1		Form of Stock Appreciation Right Award Agreement. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on August 4, 2009, File No. 1-10762.)

10.2		Form of Stock Unit Award Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 4, 2009, File No. 1-10762.)

10.3		Form of Director Stock Unit Award Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 4, 2009, File No. 1-10762.)

10.4		Form of Employee Stock Unit Award Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 4, 2009, File No. 1-10762.)

10.5		Form of Employee Stock Appreciation Right Award Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 4, 2009, File No. 1-10762.)

10.6		Share Purchase Agreement dated June 21, 2012, by and among HNR Energia BV, Harvest Natural Resources, Inc. and PT Pertamina (Persero). (Incorporated by reference to Exhibit 2.1 to our Form 8-K filed on June 21, 2012, file No. 1-10762.)

10.7		Guarantee of Harvest Natural Resources, Inc. dated June 21, 2012. (Incorporated by reference to Exhibit 2.2 to our Form 8-K filed on June 21, 2012, file No. 1-10762.)

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

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

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

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

101.INS		XBRL Instance Document

101.SCH		XBRL Schema Document

101.CAL		XBRL Calculation Linkbase Document

101.DEF		XBRL Definition Linkbase Document

101.LAB		XBRL Label Linkbase Document

101.PRE		XBRL Presentation Linkbase Document