Form 10-Q

Large Accelerated Filer

Accelerated Filer

Non-Accelerated Filer

Smaller Reporting Company

(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 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 August 5, 2013, the Registrant had 39,520,611 shares of its Common Stock outstanding.

During the six months ended June 30, 2013, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 23,668 shares being added to treasury stock at cost. During the six months ended June 30, 2013, capital expenditures of $(14.5) million were financed through current liabilities.

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 9,789 shares being added to treasury stock at cost. During the six months ended June 30, 2012, capital expenditures of $(4.6) million were financed through current liabilities.

In our opinion, the accompanying unaudited consolidated condensed financial statements contain all adjustments, which are of a normal recurring nature, necessary to present fairly the financial position as of June 30, 2013, the results of operations for the three and six months ended June 30, 2013 and 2012, and the cash flows for the six months ended June 30, 2013 and 2012. 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 Report on Form 10-K for the year ended December 31, 2012 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.

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. We do not have a business relationship with Vinccler outside of Venezuela. Harvest Holding owns, indirectly through wholly owned subsidiaries, 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 an indirect 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.

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

Historically, our primary ongoing source of cash has been dividends from Petrodelta and the sale of oil and gas properties. However, due to the lack of receipt of dividends from Petrodelta discussed below, our current source of cash is expected to be generated by accessing debt and/or equity markets, asset sales, and/or farm-downs.

Our primary ongoing use of cash has been to fund oil and gas exploration projects, debt, interest, and 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. See Note 12 – Indonesia and Note 13 – Gabon for our contractual commitments.

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 the U.S. Foreign Corrupt Practices Act and similar worldwide anti-corruption laws, 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 support and contractual adherence required by Petrodelta. If we were to be called upon to fund our share of Petrodelta’s operations, our failure to do so could be considered a default under the Contract of Conversion and cause the forfeiture of some or all our shares in Petrodelta.

Petrodelta currently represents our only source of earnings. Petrodelta also has a material impact on our results of operations for any quarter or annual reporting period. See Note 11 – Investment in Equity Affiliate – Petrodelta, S.A. 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.

Between Petrodelta’s formation in October 2007 and June 2010, Petrodelta declared and paid dividends of $105.5 million to HNR Finance, B.V., a wholly owned subsidiary of Harvest Holding (“HNR Finance”) ($84.4 million net to our indirect 80 percent interest in HNR Finance). See Note 16 – Related Party Transactions for a discussion of our obligations to our non-controlling interest holder, Vinccler, for any dividend received from Petrodelta. Petrodelta has consistently earned a profit from 2007 through June 30, 2013; however, dividends of profits since 2010 have not been declared. As discussed below, on November 12, 2010, Petrodelta’s board of directors declared a dividend which has not yet been received. There is uncertainty with respect to the timing of the receipt of the dividend declared in November 2010 or whether future dividends will be declared and/or paid. We have and will continue to monitor our investment in Petrodelta. If the dividend receivable is deemed to not be collectible, or facts and circumstances surrounding our investment change, our results of operations and our investment in Petrodelta could be adversely impacted.

We have incurred losses from continuing operations since 2007 and negative cash flows from operating activities since 2009 and have utilized the proceeds from the sale of property and debt to fund our operations. For

the six months ended June 30, 2013, we generated net income attributable to Harvest of approximately $31.6 million and negative cash flows from operations of approximately $24.4 million. At June 30, 2013, we had retained earnings of approximately $213.0 million and working capital of approximately $2.6 million. We currently do not have any revenue or operating cash inflow and, as indicated above, historically our main source of cash from operations has been dividends from Petrodelta. On November 12, 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). The dividend was ratified by Petrodelta’s shareholders on March 14, 2011. Petrodelta had working capital of $378.9 million as of June 30, 2013; however, due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, as of August 9, 2013, this dividend has not been received, although it is due and payable, and dividends for subsequent periods have not been declared and/or paid.

We expect that for 2013 we will not generate revenue, will continue to generate losses from operations, and our cash flows will not be sufficient to cover our operating expenses and capital expenditures; therefore, expected continued losses from operations and use of cash will require additional capital. To meet our capital needs, we are considering multiple alternatives, including, but not limited to, additional debt and/or equity financing, farm-downs, delay of the discretionary portion of our capital spending to future periods and/or operating cost reductions. Our ability to continue as a going concern also depends upon the success of our planned exploration and development activities. There can be no guarantee of future capital acquisition, fundraising or exploration success or that we will realize the value of our unevaluated exploratory well costs. 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.

Failure to generate sufficient cash flow, raise additional capital through debt and/or equity financings, farm-downs, and/or further reduce operating costs could have a material adverse effect on our ability to meet our short- and long-term liquidity needs and achieve our intended long-term business objectives.

While we believe the issuance of additional equity securities, short- or long-term debt financing, farm-downs, delay of the discretionary portion of our capital spending to future periods and/or operating cost reductions could be put into place which would not jeopardize our operations and future growth plans, these circumstances raise substantial doubt about our ability to continue to operate as a going concern.

Our financial statements have been prepared under the assumption that we will continue as a going concern, which contemplates that we will continue in operation for the foreseeable future and will be able to realize assets and settle liabilities and commitments in the normal course of business. The accompanying consolidated condensed financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or amounts and classification of liabilities that could result should we be unable to continue as a going concern.

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. Third-party interests in our majority-owned subsidiaries are presented as noncontrolling interests.

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 statements 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 10 – Venezuela for a discussion of currency exchange rates and currency exchange risk on Harvest Vinccler’s and Petrodelta’s businesses.

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

Restricted cash is classified as current or non-current based on the terms of the agreement. Restricted cash at June 30, 2013 represents cash held in a U.S. bank used as collateral for a standby letter of credit issued in support of a performance bond for a joint study ($1.0 million) and cash held in a foreign bank used as collateral for a bank guarantee issued in support of customs clearances ($0.2 million). Restricted cash at December 31, 2012 represents cash held in a U.S. bank used as collateral for a standby letter of credit issued in support of a performance bond for a joint study.

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) and establishes a three-level hierarchy, which encourages an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The three levels of the hierarchy are defined as follows:

Financial instruments, which potentially subject us to concentrations of credit risk, are primarily cash and cash equivalents, accounts receivable, advances to equity affiliate, dividend receivable, long-term debt and warrant derivative liability. We maintain cash and cash equivalents in bank deposit accounts with commercial banks with high credit ratings, which, at times may exceed the federally insured limits. We have not experienced any losses from such investments. Concentrations of credit risk with respect to accounts receivable are limited due to the nature of our receivables. In the normal course of business, collateral is not required for financial instruments with credit risk.

The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature (Level 1). The estimated fair value of advances to equity affiliate and dividend receivable approximates their carrying value as it is the estimated amount we would receive from a third party to assume the receivables (Level 2). 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 following table presents the estimated fair values of our fixed interest rate, long-term debt instrument (Level 3) as of June 30, 2013.

The fair value of our fixed interest debt instruments (Level 3) was calculated using a pricing model which incorporates transaction details such as contractual terms, maturity and, in certain instances, timing and amount of future cash flows, as well as assumptions related to liquidity and credit valuation adjustments of marketplace participants.

See Note 8 – Warrant Derivative Liability for a description and discussion of our warrant derivative liability.

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, 2013 and December 31, 2012. 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 liabilities and their placement within the fair value hierarchy levels. See Note 8 – Warrant Derivative Liability for a description of the valuation model and inputs used to calculate the fair value of the warrant derivative liability.

We record the net change in the fair value of the derivative position listed above as an unrealized gain (loss) on warrant derivative in our consolidated condensed statements of operations and comprehensive income (loss). During the six months ended June 30, 2013, an unrealized gain of $3.8 million was recorded to reflect the change in fair value of the warrants. The change in fair value of the warrants was de minimus for the three months ended June 30, 2013. During the three and six months ended June 30, 2012, an unrealized loss of $1.6 million and $1.2 million, respectively, was recorded to reflect the change in fair value of the warrants.

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

During the six months ended June 30, 2013, there were no transfers between Level 1, Level 2 and Level 3 liabilities.

Other assets consist of business development costs associated with new business development projects, deferred financing costs, a long-term receivable for value added tax (“VAT”) credits related to the Budong PSC, and prepaid expenses which are expected to be realized in the next 12 to 24 months. Business development costs are reclassified to oil and gas properties or expensed depending on management’s assessment of the project under ASC 932-360-35-19 “Sufficient Progress Assessment”. Deferred financing costs relate to specific financing and are amortized over the life of the financing to which the costs relate using the interest rate method. The VAT receivable is reimbursed through the sale of hydrocarbons. Other assets also includes

a blocked payment 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 – Long-Term Debt, Note 7 – Commitments and Contingencies, and Note 12 – Indonesia.

We evaluate our investments in unconsolidated companies under ASC 323, “Investments – Equity Method and Joint Ventures.” Investments in which we have significant influence are accounted for under the equity method of accounting. Under the equity method, Investment in Equity Affiliates is increased by additional investments and earnings and decreased by dividends and losses.

There are many factors to consider when evaluating an equity investment for possible impairment. Currency devaluations, inflationary economies, and cash flow analysis are some of the factors we consider in our evaluation for possible impairment. At June 30, 2013, there were no events that would indicate that our equity investment in Petrodelta had sustained a loss in value that is other than temporary.

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

Furniture, fixtures and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to five years. Leasehold improvements are recorded at cost and amortized using the straight-line method over the life of the applicable lease. For the three and six months ended June 30, 2013, depreciation expense was $0.1 million and $0.2 million, respectively. For the three and six months ended June 30, 2012, depreciation expense was $0.1 million and $0.2 million, respectively.

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 since we incurred debt are used in the interest capitalization calculation. During the three and six months ended June 30, 2013, we capitalized interest costs of $2.1 million and $4.1 million, respectively for qualifying oil and gas property additions. 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.

Stock based compensation costs are measured at fair value on date of grant and recognition of compensation over the service period for awards expected to vest. We determine the fair value of stock options and stock appreciation rights (“SARs”) awards using the Black-Scholes valuation model. Restricted stock and restricted stock units (“RSUs”) are measured at their intrinsic values. During the six months ended June 30, 2013, we did not issue any awards that qualify as stock based compensation.

On July 18, 2013, we issued stock based compensation awards to certain employees and directors as follows: 1,019,000 stock options to purchase common shares at an exercise price of $4.80 per share, vesting over three years from date of grant; 115,000 SARs at an exercise price of $4.80 per share, vesting over three years from date of grant; and 190,002 shares of restricted stock vesting at three years from date of grant.

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

During the three and six months ended June 30, 2013, we recognized a tax benefit of $1.4 million as a result of the favorable resolution of uncertain tax positions.

We classify interest related to income tax liabilities, and penalties as applicable, as interest expense.

We do not provide deferred income taxes on undistributed earnings of our foreign subsidiaries for possible future remittances as all such earnings are permanently reinvested, or otherwise can be negotiated in a tax free manner, as part of our ongoing business.

We measure and disclose our noncontrolling interests in accordance with the provisions of ASC 810 “Consolidation”. Our noncontrolling interest relates to Vinccler’s indirectly owned 20 percent interest in Harvest Holding (see Note 1 – Organization). Changes in noncontrolling interest were as follows:

See Note 16 – Related Party Transactions for a discussion of our obligations to our non-controlling interest holder, Vinccler, for any dividend received from Petrodelta.

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.

The three months ended June 30, 2013 per share calculations above exclude 3.9 million options and 2.4 million warrants because they were anti-dilutive. 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 six months ended June 30, 2013 per share calculations above exclude 3.4 million options and 2.4 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 total intrinsic value of stock options exercised during the six months ended June 30, 2013 was $0.1 million. The total intrinsic value of stock options exercised during the six months ended June 30, 2012 was $0.3 million.

As a result of the decision to not request an extension of the First Phase or enter the Second Phase of the Exploration and Production Sharing Agreement (“EPSA”) Al Ghubar / Qarn Alam license (“Block 64 EPSA”), Block 64 was relinquished effective May 23, 2013. The carrying value of Block 64 EPSA of $6.4 million was written off to impairment expense at December 31, 2012. Operations in Oman were terminated and the field office was closed May 31, 2013.

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.

Oman operations and the Antelope Project have been classified as discontinued operations. Net loss on the dispositions is shown in the table below:

On October 11, 2012, we closed the sale of $79.8 million aggregate principal amount of 11 percent senior unsecured notes due October 11, 2014. Under the terms of the notes, interest is payable quarterly in arrears on January 1, April 1, July 1 and October 1, beginning January 1, 2013. The 11 percent senior unsecured notes are general unsecured obligations, ranking equally in right of payment with all our future senior unsecured indebtedness. The senior unsecured notes are structurally subordinated to indebtedness and other liabilities of our subsidiaries.

The 11 percent senior unsecured notes were issued at a price of 96 percent of principal amount. The original issue discount (“OID”) is recorded as a Discount on Debt. Warrants to purchase up to 0.7 million shares of our common stock with an exercise price of $10.00 per share were issued in connection with the 11 percent senior unsecured notes. The fair value of the warrants is recorded as Discount on Debt. The OID and Discount on Debt are being amortized over the life of the debt.

In the event that a sale of assets (farm-outs are not included in the definition of a sale of assets in the indenture) for more than $5.0 million in the aggregate occurs, we are required to offer to all noteholders of our 11 percent senior unsecured notes within 30 days of when sales proceeds exceed $5.0 million to purchase the maximum principal amount of our 11 percent senior unsecured notes that may be purchased out of the sales proceeds at an offer price in cash in an amount equal to 105.5 percent of the principal amount plus accrued and unpaid interest, if any. In the event of a change in control or a sale of Petrodelta, the noteholders of our 11 percent senior unsecured notes have the right to require us to repurchase all or any part of the 11 percent senior unsecured notes at a repurchase price equal to 101 percent in the case of a change in control or 105.5 percent in the case of a sale of Petrodelta plus accrued interest. We assessed the prepayment requirements and concluded that this feature met the criteria to be considered an embedded derivative. We considered the probabilities of these events occurring and determined that the derivative had a de minimus value at June 30, 2013 and December 31, 2012.

Financing costs associated with the 11 percent senior unsecured notes are recorded in other assets and are amortized over the life of the notes. The balance for financing costs was $2.0 million at June 30, 2013 (December 31, 2012: $3.2 million).

Kensho Sone, et al. v. Harvest Natural Resources, Inc., in the United States District Court, Southern District of Texas, Houston Division. On July 24, 2013, 70 individuals, all alleged to be citizens of Taiwan, filed an original complaint and application for injunctive relief relating to the Company’s interest in the WAB-21 area of the South China Sea. The complaint alleges that the area belongs to the people of Taiwan and seeks damages in excess of $2.9 million and preliminary and permanent injunctions to prevent the Company from exploring, developing plans to extract hydrocarbons from, conducting future operations in, and extracting hydrocarbons from, the WAB-21 area. The Company intends to vigorously defend these allegations.

The following related class action lawsuits were filed on the dates specified in the United States District Court, Southern District of Texas: John Phillips v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (March 22, 2013) (“Phillips case”); Sang Kim v. Harvest Natural Resources, Inc., James A. Edmiston, Stephen C. Haynes, Stephen D. Chesebro’, Igor Effimoff, H. H. Hardee, Robert E. Irelan, Patrick M. Murray and J. Michael Stinson (April 3, 2013); Chris Kean v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 11, 2013); Prastitis v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 17, 2013); Alan Myers v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 22, 2013); and Edward W. Walbridge and the Edward W. Walbridge Trust v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 26, 2013). The complaints allege that the Company made certain false or misleading public statements and demand that the defendants pay unspecified damages to the class action plaintiffs based on stock price declines. All of these actions have been consolidated into the Phillips case. The Company and the other named defendants have filed a motion to dismiss and intend to vigorously defend the consolidated lawsuits.

On March 25, 2013, the Securities and Exchange Commission notified the Company that it is conducting an inquiry related to certain matters disclosed in the Company’s Form 12b-25 announcing that it would be unable to file on a timely basis its Annual Report on Form 10-K for the year ended December 31, 2012, including certain errors in the Company’s prior years’ financial statements and material weaknesses in the Company’s internal controls. The Company is engaged in discussions with the Commission concerning these matters.

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, Indonesia’s oil and gas regulatory authority. The claimant is seeking compensation of 16 billion Indonesia Rupiah (approximately $1.6 million, $1.2 million net to our 71.61 percent cost sharing interest) for land that was purchased at a cost of $4,100 in January 2010. On March 8, 2013, the court ruled the lawsuit incorrect on the basis that the claim should have been made against other parties, in addition to the operator. On March 19, 2013, the claimant filed an appeal against the judgment. We dispute the claim and plan 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”), a wholly owned subsidiary of Harvest, 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 US 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.

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 8, 2013, 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:

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:

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 with 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 8, 2013, 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.

Our warrants, which have anti-dilution protection features, do not meet the conditions to obtain equity classification under ASC 480 “Distinguishing Liabilities From Equity” as there are conditions which may require settlement by transferring assets. These warrants are required to be carried as derivative liabilities, at fair value, with current changes in fair value reflected in our consolidated condensed statements of operations and comprehensive income (loss).

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 percent 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.

As of June 30, 2013 and December 31, 2012, warrant derivative financial instruments consisted of 1,720,334 warrants issued under the warrant agreements dated November 2010 in connection with a $60 million term loan facility (the “Warrants”). The fair value of the Warrants as of June 30, 2013 was $0.94 per warrant (December 31, 2012: $3.18 per warrant).

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.

The Monte Carlo model is used on the Warrants to reasonably value the potential future exercise price adjustments triggered by the anti-dilution provisions. This requires Level 3 inputs (see Note 3 – Summary of Significant Accounting Policies, Financial Instruments and Fair Value Measurements) which are based on our estimates of the probability and timing of potential future financings and fundamental transactions. The assumptions summarized in the following table were used to calculate the fair value of the warrant derivative liability that was outstanding as of any of the balance sheet dates presented on our consolidated condensed balance sheets:

Inherent in the Monte Carlo valuation model are assumptions related to expected stock price volatility, expected life, risk-free interest rate and dividend yield. 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. We estimate the volatility of our common stock based on historical volatility that matches 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.

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

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:

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”) (6.30 Bolivars per U.S. Dollar). However, during the three and six months ended June 30, 2013, Harvest Vinccler exchanged approximately $0.5 million and $0.9 million, respectively, through the Central Bank and received an average exchange rate of 6.28 Bolivars per U.S. Dollar and 6.08 Bolivars per U.S. Dollar, respectively. During the three and six months ended June 30, 2012, Harvest Vinccler exchanged approximately $0.4 million and $0.6 million, respectively, through the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) and received an average exchange rate of 5.10 Bolivars per U.S. Dollar and 5.13 Bolivars per U.S. Dollar, respectively. Harvest Vinccler currently does not have any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the Central Bank 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 Central Bank exchange rate.

The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. At June 30, 2013, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 8.4 million Bolivars and 8.1 million Bolivars, respectively. At June 30, 2013, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 1,432.1 million Bolivars and 5,424.0 million Bolivars, respectively.

The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PDVSA Petroleo S.A. (“PPSA”) signed on January 17, 2008. The form of the agreement is set forth in the Conversion Contract. Crude oil delivered from the Petrodelta Fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets, and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices are quoted and sold in U.S. Dollars. Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. Natural gas deliveries are paid in Bolivars, but the pricing for natural gas is referenced to the U.S. Dollar. PPSA is obligated to make payment to Petrodelta of each invoice within 60 days of the end of the invoiced production month by wire transfer, in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered, and in Bolivars in the case of payment for natural gas delivered, in immediately available funds to the bank accounts designated by Petrodelta. Major contracts for capital expenditures and lease operating expenditures are denominated in U.S. Dollars. Any dividend paid by Petrodelta will be made in U.S. Dollars.

When the Sales Contract was executed, Petrodelta was producing only one type of crude, Merey 16. Beginning in October 2011, the Ministry of the People’s Power for Petroleum and Mining (“MENPET”) determined that Petrodelta’s production flowing through the COMOR transfer point was a heavier type of crude, Boscan. Since Petrodelta was producing only Merey 16 when the Sales Contract was executed, the Boscan gravity and sulphur correction factors and crude pricing formula are not included in the Sales Contract. However, under the Sales Contract, PPSA is obligated to receive all of Petrodelta’s production. All production deliveries for all of Petrodelta’s fields have been certified by MENPET and acknowledged by PPSA. All pricing factors to be used in the Merey 16 and Boscan pricing formulas have been provided by and certified by MENPET to Petrodelta.

Since the Sales Contract provides for only one crude pricing formula, the Sales Contract had to be amended to include the Boscan pricing formula to allow Petrodelta to invoice PPSA for El Salto crude oil deliveries. From October 1, 2011 through June 30, 2012, Petrodelta used the Boscan pricing formula as published in the Official Gazette on January 11, 2007 to record revenue from El Salto deliveries. Petrodelta subsequently received from PDVSA Trade and Supply a draft amendment to the Sales Contract. The pricing formula in the draft amendment was used to record revenue for El Salto field deliveries from July 1, 2012 through June 30, 2013, and revenue for El Salto deliveries for October 1, 2011 through June 30, 2012 was revised to reflect the pricing formula in the draft amendment. The only item included in the draft amendment is the Boscan pricing formula to be used in invoicing El Salto crude oil deliveries. All other terms and conditions of the Sales Contract remain in force. On January 31, 2013, Petrodelta’s board of directors endorsed the amendment to the Sales Contract. The amendment has been approved by CVP’s board of directors. HNR Finance, as shareholder, has agreed to the contract amendment.

CVP’s board of directors reviewed the amendment on April 30, 2013. A certificate of CVP’s final board resolution approving the amendment dated April 30, 2013 was received by Petrodelta on May 23, 2013. The remaining steps for the contract amendment are to (1) inform MENPET of the approval, (2) receive approval from Petrodelta’s shareholders to amend the Sales Contract including the Boscan formula, and (3) sign the contract amendment with PDVSA Trade and Supply. Once the Sales Contract is executed, PPSA will be invoiced for the deliveries.

At June 30, 2013, El Salto deliveries, net of royalties, covering the delivery months of October 2011 through June 2013 totaled approximately 6.2 million barrels (“MBls”) (2.0 MBls net to our 32 percent interest). The amendment to the Sales Contract pricing formula for Boscan based upon the deliveries and factors certified by MENPET, results in revenue for these deliveries of $541.8 million ($173.4 million net to our 32 percent interest). As of June 30, 2013, these deliveries for El Salto remain uninvoiced to PPSA.

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, through PPSA, 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, 2013, Harvest Vinccler advanced to Petrodelta $0.2 million for continuing operations costs and recorded a $0.4 million loss on revaluation of the accounts receivable with Petrodelta. Petrodelta and Petrodelta’s board have neither indicated that the advances are not payable, nor that they will not be paid. As of June 30, 2013, Advance to Equity Affiliate of $2.1 million (December 31, 2012: $2.1 million) had been classified as long-term receivable due to slow payment and age of the advances although we expect the full amount to be collected. During the year ended December 31, 2012, Harvest Vinccler advanced to Petrodelta $0.5 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advance. 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”). In February 2013, the Venezuelan government published in the Official Gazette an amendment to the Windfall Profits Tax. The amended Windfall Profits Tax establishes new levels for contribution of extraordinary and exorbitant prices to the Venezuelan government. Extraordinary prices are considered to be equal to or lower than $80 per barrel, and exorbitant prices are considered to be over $80 per barrel. The amended Windfall Profits tax also sets a new royalty cap per barrel of $80. Contributions for extraordinary prices are 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $55 per barrel for 2013) and $80 per barrel. Contributions for exorbitant prices are (1) 80 percent when the average price of the Venezuela Export Basket (“VEB”) exceeds $80 per barrel but is less than $100 per barrel; (2) 90 percent when the average price of the VEB equals or exceeds $100 per barrel but is less than $110 per barrel; and (3) 95 percent when the average price of the VEB equals or exceeds $110 per barrel. Windfall Profits Tax is deductible for Venezuelan income tax purposes. During the three and six months ended June 30, 2013, Petrodelta recorded $51.9 million and $118.0 million, respectively, for Windfall Profits Tax. During the three and six months ended June 30, 2012, Petrodelta recorded $74.7 million and $159.4 million, respectively, for Windfall Profits Tax

The amended Windfall Profits Tax states that royalties paid to Venezuela are capped at $80 per barrel (in 2012, $70 per barrel under the original Windfall Profits Tax), but the cap on royalties has not been defined as being applicable to in-cash, in-kind, or both. Per instructions received from PDVSA, Petrodelta reports royalties, whether paid in-cash or in-kind, at $80 per barrel (royalty barrels x $80). The difference between the $80 royalty cap and the current oil price is to be reflected on the income statement as a reduction in oil sales. For the three and six months ended June 30, 2013, the reduction to oil sales due to the $80 cap applied to all royalty barrels was $23.6 million and $50.9 million, respectively, ($7.6 million and $16.3 million, respectively, net to our 32 percent interest). For the three and six months ended June 30, 2012, the reduction to oil sales due to the $80 cap applied to all royalty barrels was $28.9 million and $67.4 million, respectively, ($9.2 million and $21.6 million, respectively, net to our 32 percent interest).

Per our interpretation of the Windfall Profits Tax, the $80 cap on royalty barrels should only be applied to the 3.33 percent royalty which Petrodelta pays in cash. We have applied the $80 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 months ended March 31, 2013. 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 $80 cap to the 3.33 percent royalty paid in cash for the three and six months ended June 30, 2013. For the three and six months ended June 30, 2013, net oil sales (oil sales less royalties) are slightly higher, $2.4 million and $5.1 million, respectively, ($0.8 million and $1.6 million, respectively, net to our 32 percent interest) 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. For the three and six months ended June 30, 2012, net oil sales are slightly higher, $2.9 million and $6.7 million, respectively, ($0.9 million and $2.1 million, respectively, net to our 32 percent interest) under this method. We have reported revenues and royalties for Petrodelta under this method.

2013 did not modify the fundamentals of this section from the April 2011 Windfall Profits Tax law. Since the enactment of the April 2011 Windfall Profits Tax, we have believed that several of the fields operated by Petrodelta should qualify for exemption from the Windfall Profits Tax, and we have been waiting for MENPET to establish, through resolution, the definition of incremental production and grass roots developments, as well as guidance on the process of applying for, and the calculation of, the exemption.

In March 2013, PDVSA requested an exemption from MENPET for the Windfall Profits Tax under the provision in the April 2011 Windfall Profits Tax law. The exemption was applied to several oil development projects, including Petrodelta. The exemption is allowable under the April 2011 Windfall Profits Tax law; however, MENPET has neither defined the projects qualifying for exemption, nor the guidance to be used in calculating the exemption. PDVSA issued to Petrodelta its share of the exemption credit, $55.2 million ($36.4 million net of tax) ($17.7 million net to our 32 percent interest, $11.6 million net of tax net to our 32 percent interest) based on PDVSA’s calculation and projects PDVSA deemed to qualify for the exemption. Neither Petrodelta nor us have been provided with supporting documentation indicating the properties have been appropriately qualified by MENPET, the specific details for the exemption credit, such as which fields, production period or production, or the supporting calculations. Until MENPET either issues guidance on the exemption provision in the April 2011 Windfall Profits Tax law or issues payment forms including the exemption credit, or written approval from MENPET for this exemption credit is received by Petrodelta or us, we have and will continue to exclude the exemption credit from our equity earnings in Petrodelta.

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 six months ended June 30, 2013, this method of calculation overstates the liability for the Sports Law contribution by $0.2 million ($0.1 million net to our 32 percent interest). The liability for the Sports Law contribution for the three months ended June 30, 2013 was understated by $1.5 million ($0.5 million net to our 32 percent interest) due to adjustments from the devaluation of the Bolivar. 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, respectively ($0.1 million and $0.2 million, respectively, net to our 32 percent interest). We have adjusted for the over-accrual of the Sports Law in the three and six months ended June 30, 2013 and 2012 Net Income from Equity Affiliate.

On November 12, 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. Petrodelta had working capital of $378.9 million as of June 30, 2013; however, due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, as of August 8, 2013, this dividend has not been received, although it is due and payable, and dividends for subsequent periods have not been declared and/or paid. Petrodelta’s board of directors declared this dividend and has neither indicated that the dividend is not payable, nor that it will not be paid. The dividend receivable is classified as a long-term receivable at June 30, 2013 due to the uncertainty in the timing of payment. Petrodelta has consistently earned a profit from 2007 through June 30, 2013; however, dividends of profits since 2010 have not been declared. There is uncertainty with respect to the timing of the receipt of the dividend declared in November 2010 or whether future dividends will be declared and/or paid. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable not be collected or facts and circumstances surrounding our investment change, our results of operations and investment in Petrodelta could be adversely impacted.

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.

The excess basis in equity affiliate is being amortized using the unit-of-production method based on risk adjusted total current estimated reserves.

In preparing the interim period financial statements, management is required to use estimates which are subject to a high level of judgment in order to calculate the provision for income taxes. Petrodelta’s income tax expense for the three months ended June 30, 2013 includes approximately $19.5 million ($6.3 million net to our 32 percent interest) of additional expense associated with revisions to the interim tax provision primarily related to the treatment of items arising from the February 2013 currency devaluation.

All amounts through Net Income Equity Affiliate represent 100 percent of Petrodelta. Summary financial information has been presented below at June 30, 2013 and December 31, 2012, and for the three and six months ended June 30, 2013 and 2012:

In January 2013, the Budong PSC partners were granted a four year extension of the initial six year exploration term of the Budong PSC to January 15, 2016. The extension of the initial exploration term includes an exploration well, which if not drilled by January 2016, results in the obligation of the Joint Venture to return the entire Budong PSC to the Government of Indonesia. Also, if this exploration well is not drilled within 18 months of the date of approval from the Government of Indonesia of this transaction (October 9, 2014), we will be required to pay our partner in the Budong PSC $3.2 million.

Operational activities during the three months ended June 30, 2013 included continued work on an exploration program targeting the Pliocene and Miocene targets encountered in the previous two wells. Land access and acquisition; environmental studies; construction and upgrades to access roads, bridges, and well site; permitting; and tender prequalification and procurement are on-going.

The Budong PSC represents $5.3 million of oil and gas properties on our June 30, 2013 consolidated condensed balance sheet (December 31, 2012: $5.3 million).

We have met all funding commitments for the third exploration phase of the Dussafu PSC.

Operational activities during the three months ended June 30, 2013 included commencement of planning for a cluster field development. Geoscience, reservoir engineering and economic studies have been progressed. A project team has been assembled; field development options evaluated; key and long lead equipment have been identified; and a field development plan is being prepared.

Dussafu Ruche Marin-1 (“DRM-1”) and sidetracks, which were drilled in 2011, Dussafu Tortue Marin-1 (“DTM-1”) and sidetrack, which were drilled in 2013, are suspended pending future appraisal and development activities. During the second quarter 2013, our estimate of contingent resources was updated.

The Dussafu PSC represents $98.6 million of oil and gas properties on our June 30, 2013 consolidated condensed balance sheet (December 31, 2012: $76.4 million).

In March 2013, China National Offshore Oil Corporation (“CNOOC”) granted us an extension of Phase One of the Exploration Period for the WAB-21 contract area from May 2013 to May 2015. The contract extension was signed June 4, 2013.

We entered into two agreements to acquire operating interests in certain onshore exploration blocks outside the United States. Pursuant to these agreements, we incurred approximately $1.5 million in the second quarter of 2013. For competitive reasons, we have chosen not to disclose the details of these agreements.

This international project represents $1.2 million of oil and gas properties on our June 30, 2013 consolidated condensed balance sheet (December 31, 2012: none).

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, 2013, Vinccler’s share of the undistributed dividends is $9.0 million.

Harvest Natural Resources, Inc. (“Harvest” or the “Company”) cautions that any forward-looking statements as such term is defined in Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) 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 Securities Act and the Exchange Act, 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, 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, 2012, 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.

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”) 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, 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 an indirect 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.

Through the pursuit of technically-based strategies, we are building a portfolio of exploration prospects to complement the low-risk production, development and exploration prospects we hold in Venezuela. In addition to our interests in Venezuela, we hold exploration acreage mainly onshore West Sulawesi in Indonesia, offshore of Gabon, 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. During the last three 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. We evaluate these potential opportunities taking into consideration our overall property mix, our operational and liquidity requirements, our strategic focus and our commitment to long-term shareholder value. For example, we have received such expressions of interest in acquiring some of our international exploration assets, and we are currently evaluating these potential opportunities. There can be no assurances that our discussions will continue or that any transaction may ultimately result from our discussions.

During the six months ended June 30, 2013, Petrodelta drilled and completed six development wells, delivered approximately 6.8 million barrels (“MBls”) of oil and 1.4 billion cubic feet (“Bcf”) of natural gas, averaging 39,046 barrels of oil equivalent (“BOE”) per day. During the six months ended June 30, 2012, Petrodelta drilled and completed six development wells, delivered approximately 6.3 MBls of oil and 1.1 Bcf of natural gas, averaging 35,633 BOE per day.

Currently, Petrodelta is operating five drilling rigs and two workover rigs. A sixth drilling rig is rigging up. Infrastructure enhancement projects in the El Salto and Temblador fields continue. A pipeline between the Isleño field and the main production facility at Uracoa has been completed and is in service.

Certain operating statistics for the six months ended June 30, 2013 and 2012 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.

ended June 30, 2013, net oil sales (oil sales less royalties) are slightly higher, $2.4 million and $5.1 million, respectively, ($0.8 million and $1.6 million, respectively, net to our 32 percent interest) 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. For the three and six months ended June 30, 2012, net oil sales are slightly higher, $2.9 million and $6.7 million, respectively, ($0.9 million and $2.1 million, respectively, net to our 32 percent interest) under this method. We have reported revenues and royalties for Petrodelta under this method.

The April 2011 Windfall Profits Tax included a provision wherein it considered that an exemption of the Windfall Profits Tax could be granted for the incremental production of projects and grass root developments until the specific investments are recovered. The projects deemed to qualify for the exemption has to be considered and approved in a case by case basis by MENPET. The subsequent amendment to the Windfall Profits tax in February 2013 did not modify the fundamentals of this section from the April 2011 Windfall Profits Tax law. Since the enactment of the April 2011 Windfall Profits Tax, we have believed that several of the fields operated by Petrodelta should qualify for exemption from the Windfall Profits Tax, and we have been waiting for MENPET to establish, through resolution, the definition of incremental production and grass roots developments, as well as guidance on the process of applying for, and the calculation of, the exemption.

On November 12, 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. Petrodelta had working capital of $378.9 million as of June 30, 2013; however, due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, as of August 8, 2013, this dividend has not been received, although it is due and payable, and dividends for subsequent periods have not been declared and/or paid. Petrodelta’s board of directors declared this dividend and has neither indicated that the dividend is not payable, nor that it will not be paid. The dividend receivable is classified as a long-term receivable at June 30, 2013 due to the uncertainty in the timing of payment. Petrodelta has consistently earned a profit from 2007 through June 30, 3013; however, dividends of profits since 2010 have not been declared. There is uncertainty with respect to the timing of the receipt of the dividend declared in November 2010 or whether future dividends will be declared and/or paid. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable not be collected or facts and circumstances surrounding our investment change, our results of operations and investment in Petrodelta could be adversely impacted.

During the six months ended June 30, 2013, we had cash capital expenditures of $0.1 million for environment studies and well planning.

We have met all funding commitments for the third exploration phase of the Dussafu PSC.

During the six months ended June 30, 2013, we had cash capital expenditures of $36.6 million for well planning and drilling.

We entered into two agreements to acquire operating interests in certain onshore exploration blocks outside the United States. For competitive reasons, we have chosen not to disclose the details of these agreements.

During the six months ended June 30, 2013, we had cash capital expenditures of $1.2 million for lease acquisition costs.

Our financial statements for the six months ended June 30, 2013 have been prepared under the assumption that we will continue as a going concern.

Our current capital resources may not be sufficient to support our liquidity requirements through 2013. However, we believe certain cost reduction measures could be put into place which would not jeopardize our operations and future growth plans. In addition, we could delay the discretionary portion of our capital spending to future periods and farm-down or sell assets as necessary to maintain the liquidity required to run our operations, as warranted. There are no assurances that we will be successful in farming-down or selling our assets, and Petrodelta’s nonpayment of dividends since 2010 continues to be a contributing factor to our liquidity constraints.

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 as needed to fund our current operations. There can be no guarantee of future capital acquisition, fundraising or exploration success or that we will realize the value of our unevaluated exploratory well costs. 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.

We may be able to meet future liquidity needs through the issuance of additional equity securities and/or short or long-term debt financing, although there can be no assurance that such financing will be available to us or on terms that are acceptable to us. We may also farm-down assets or possibly sell assets.

The long-term continuation of our business plan through 2013 and beyond is dependent upon the generation of sufficient cash flow to offset expenses. We will be required to obtain additional funding through public or private financing, farm-downs, further reduce operating costs, and/or possible sales of assets. Failure to generate sufficient cash flow by raising additional capital through debt or equity financings, reducing operating costs, or by farm-downs and/or possible selling of assets further could have a material adverse effect on our ability to meet our short- and long-term liquidity needs and achieve our intended long-term business objectives.

The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. In our Annual Report on Form 10-K for the year ended December 31, 2012, Item 1A. Risk Factors, we discuss a number of variables and risks related to our exploration projects and our minority equity investment in Petrodelta that could significantly utilize our cash balances, affect our capital resources and liquidity.

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 support and contractual adherence 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 currently represents our only source of earnings. Petrodelta also has a material impact on our results of operations for any quarter or annual reporting period. See Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 11 – Investment in Equity Affiliate – Petrodelta, S.A. Petrodelta operates under a business plan, the success of which relies heavily on the market price of oil and PDVSA’a adherence to the contract. 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.

Historically, our primary ongoing source of cash has been dividends from Petrodelta and the sale of oil and gas properties. Currently, our source of cash is expected to be generated by accessing debt and/or equity markets, farm-downs or possible sale of assets.

In the event that a sale of assets (farm-outs are not included in the definition of a sale of assets in the indenture) for more than $5.0 million in the aggregate occurs, we are required to offer to all noteholders of our 11 percent senior unsecured notes within 30 days of when sales proceeds exceed $5.0 million to purchase the maximum principal amount of our 11 percent senior unsecured notes that may be purchased out of the sales proceeds at an offer price in cash in an amount equal to 105.5 percent of the principal amount plus accrued and unpaid interest, if any. In the event of a change in control or a sale of Petrodelta, the noteholders of our 11 percent senior unsecured notes have the right to require us to repurchase all or any part of the 11 percent senior unsecured notes at a repurchase price equal to 101 percent in the case of a change in control or 105.5 percent in the case of a sale of Petrodelta plus accrued interest. We assessed the prepayment requirements and concluded that this feature met the criteria to be considered an embedded derivative. We considered the probabilities of these events occurring and determined that the derivative had an immaterial value at June 30, 2013 and December 31, 2012.

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 80 percent interest in HNR Finance). On November 12, 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). The dividend was ratified by Petrodelta’s shareholders on March 14, 2011. Petrodelta had working capital of $378.9 million as of June 30, 2013; however, due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, this dividend has not yet been received, although it is due and payable, and dividends for subsequent periods have not been declared and/or paid. Petrodelta’s board of directors declared this dividend and has neither indicated that the dividend is not payable, nor that it will not be paid. The dividend receivable is classified as a long-term receivable at June 30, 2013 and December 31, 2012 due to the uncertainty in the timing of payment. Petrodelta has consistently earned a profit from 2007 through June 30, 3013; however, dividends of profits since 2010 have not been declared. There is uncertainty whether Petrodelta will declare and/or pay additional dividends in the future. See Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 16 – Related Party Transactions for a discussion of our obligations to our non-controlling interest holder, Vinccler, for any dividend received from Petrodelta. We have and will continue to monitor our investment in Petrodelta. If the dividend receivable is deemed to not be collectible, or facts and circumstances surrounding our investment change, our results of operations and our investment in Petrodelta could be adversely impacted.

Our cash is being used to fund oil and gas exploration projects, debt, interest, and 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 have met all funding commitments for the third exploration phase of the Dussafu PSC. In January 2013, the Budong PSC partners were granted a four year extension of the initial six year exploration term of the Budong PSC to January 15, 2016. The extension of the initial exploration term includes an exploration well, which if not drilled by January 2016, results in the termination of the Budong PSC. Also, if this exploration well is not drilled within 18 months of the date of approval from the Government of Indonesia of this transaction, we will be required to pay our partner in the Budong PSC $3.2 million. See Part I. Financial Statements, Notes to Consolidated Condensed Financial Statements, Note 12 – Indonesia. The Budong PSC work commitments are discretionary, and we have the ability to control the pace of expenditures.

Warrant Derivative Liability. At June 30, 2013, our warrant derivative liability represents all of our financial instruments measured at fair value. The warrant derivative liability is measured at fair value using significant unobservable inputs and is directly connected to the price of our common stock. The value of the warrant derivative liability during the six months ended June 30, 2013 was consistent with that for the three months ended March 31, 2013. The impact of the valuation of the warrant derivative liability is disclosed in our consolidated condensed statements of operations and comprehensive income (loss) and has no effect on our liquidity or capital resources.

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:

At June 30, 2013, we had current assets of $16.7 million and current liabilities of $14.1 million, resulting in working capital of $2.6 million and current ratio of 1.2:1. This compares with working capital of $40.5 million and current ratio of 2.0:1 at December 31, 2012. The decrease in working capital of $37.9 million was primarily due to decreases in receivables, increases in cash payments for capital expenditures and accrued expenses and accounts payable.

Cash Flow used in Operating Activities. During the six months ended June 30, 2013 and 2012, net cash used in operating activities was approximately $24.4 million and $18.2 million, respectively. The $6.2 million increase was primarily due to decreases in accounts receivable.

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

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 $31.8 million for 2013 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, 2013 we:

You should read the following discussion of the results of operations for the three and six months ended June 30, 2013 and 2012 and the financial condition as of June 30, 2013 and December 31, 2012 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, 2012.

Three Months Ended June 30, 2013 Compared with Three Months Ended June 30, 2012

We reported a net loss attributable to Harvest of $4.5 million, or $(0.12) diluted earnings per share, for the three months ended June 30, 2013, compared with net income attributable to Harvest of $6.2 million, or $0.15 diluted earnings per share, for the three months ended June 30, 2012.

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

During the three months ended June 30, 2013, we incurred $2.1 million of exploration costs related to the processing and reprocessing of seismic data and lease maintenance costs related to ongoing operations and $0.5 million related to other general business development activities. During the three months ended June 30, 2012, we incurred $1.4 million of exploration costs related to the processing and reprocessing of seismic data and lease maintenance costs related to ongoing operations, and $0.1 million related to other general business development activities.

The increase in general and administrative costs in the three months ended June 30, 2013 from the three months ended June 30, 2012 was primarily due to higher employee related costs ($0.4 million), contract services ($0.6 million) and restructuring costs ($0.7 million), offset by lower general office and overhead costs ($0.2 million).

Investment earnings and other in the three months ended June 30, 2013 was consistent with the three months ended June 30, 2012.

The decrease in unrealized loss on warrant derivatives in the three months ended June 30, 2013 from the three months ended June 30, 2012 was due to the change in fair value for our warrant derivative liabilities: $0.94 per warrant at June 30, 2013 and $3.63 per warrant at June 30, 2012.

The increase in interest expense in the three months ended June 30, 2013 from the three months ended June 30, 2012 was due to higher principal balance (2013: $79.8 million, 2012: $15.6 million) and interest rate (2013: 11 percent, 2012: 8.25 percent) on the debt outstanding at June 30, 2013 than the debt outstanding at June 30, 2012 offset by interest capitalized to oil and gas properties in the three months ended June 30, 2013 of $2.1 million (three months ended June 30, 2012: $0.5 million).

The decrease in other non-operating expense in the three months ended June 30, 2013 from the three months ended June 30, 2012 was due to costs incurred related to our strategic alternative process and evaluation.

The increase in loss on exchange rates in the three months ended June 30, 2013 from the three months ended June 30, 2012 was due to the difference in exchange rates used to accrue income tax refunds from the Netherlands for 2008 and 2009 and the exchange rate in effect at the time of receipt of the refunds.

The increase in income tax benefit in the three months ended June 30, 2013 from the three months ended June 30, 2012 is due to the favorable resolution of certain tax contingencies in the three months ended June 30, 2013.

Revenues were lower in the three months ended June 30, 2013 compared to the three months ended June 30, 2012 due to lower world crude oil prices offset by increases in sales volumes resulting from running a five drilling rig program.

Total expenses and other non-operating (income) expense, inclusive of all adjustments necessary to reconcile Net Income from Petrodelta to Net Income from Equity Affiliate:

For the three months ended June 30, 2013 compared to the three months ended June 30, 2012, royalties, which is a function of revenue, decreased due to the decrease in revenue (net decrease in revenue of $4.3 million at 30 percent royalty). The increase in operating expense is due to increased oil production. The increase in workover expense is due to running two workover rigs beginning in the quarter ended June 30, 2013 versus one workover rig in the quarter ended June 30, 2012. Windfall Profits Tax, which is a function of volume and price received per barrel, decreased in part due to an increase in volumes offset by lower price received per barrel, but also due to the change in the Windfall Profits Tax law (see Operations – Petrodelta, S.A. above). The foreign currency transaction loss is due to the Bolivar devaluation in February 2013 from 4.30 Bolivars/U.S. Dollar to 6.30 Bolivars/U.S. Dollar.

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 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.

Oman operations and the Antelope Project have been classified as discontinued operations. Net loss on the dispositions is shown in the table below:

During the three months ended June 30, 2012, we expensed to dry hole costs $0.1 million related to the drilling of the Al Ghubar North-1 (“AGN-1”) on the Block 64 EPSA.

We reported net income attributable to Harvest of $31.6 million, or $0.80 diluted earnings per share, for the six months ended June 30, 2013, compared with net income attributable to Harvest of $5.2 million, or $0.14 diluted earnings per share, for the six months ended June 30, 2012.

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

During the six months ended June 30, 2013, we incurred $3.5 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations and $0.9 million related to other general business development activities. During the six months ended June 30, 2012, we incurred $3.1 million of exploration costs related to the processing and reprocessing of seismic data related to ongoing operations and $0.3 million related to other general business development activities.

During the six months ended June 30, 2013, we did not record any dry hole costs. During the six months ended June 30, 2012, we expensed to dry hole costs $0.8 million related to the drilling of the Karama-1 well on the Budong PSC.

The decrease in general and administrative costs in the six months ended June 30, 2013 from the six months ended June 30, 2012 was primarily due to lower general office expense and overhead ($0.9 million) and employee related costs ($1.7 million), offset by higher contract services ($1.3 million) and restructuring costs ($0.7 million).

Investment earnings and other in the six months ended June 30, 2013 was consistent with the six months ended June 30, 2012.

The increase in unrealized gain on warrant derivatives in the six months ended June 30, 2013 from the six months ended June 30, 2012 was due to the change in fair value for our warrant derivative liabilities: $0.94 per warrant at June 30, 2013 and $3.63 per warrant at June 30, 2012.

The increase in interest expense in the six months ended June 30, 2013 from the six months ended June 30, 2012 was due to higher principal balance (2013: $79.8 million, 2012: $15.6 million) and interest rate (2013: 11 percent, 2012: 8.25 percent) on the debt outstanding at June 30, 2013 than the debt outstanding at June 30, 2012 offset by interest capitalized to oil and gas properties in the six months ended June 30, 2013 of $4.1 million (six months ended June 30, 2012: $1.2 million).

The decrease in other non-operating expense in the six months ended June 30, 2013 from the six months ended June 30, 2012 was due to costs incurred in 2012 related to our strategic alternative process and evaluation.

The loss on exchange rates in the six months ended June 30, 2013 was consistent with the six months ended June 30, 2012.

The decrease in income tax benefit in the six months ended June 30, 2013 from the six months ended June 30, 2012 is due to the benefit in the prior period of net operating loss; whereas, the current period includes the benefit from the favorable resolution of certain tax contingencies.

Revenues were lower in the six months ended June 30, 2013 compared to the six months ended June 30, 2012 due to lower world crude oil prices offset by increases in sales volumes resulting from running a five drilling rig program.

Total expenses and other non-operating (income) expense, inclusive of all adjustments necessary to reconcile Net Income from Petrodelta to Net Income from Equity Affiliate:

For the six months ended June 30, 2013 compared to the six months ended June 30, 2012, royalties, which is a function of revenue, decreased due to the decrease in revenue (net decrease in revenue of $11.2 million at 30 percent royalty). The increase in operating expense is due to increased oil production. Workover expense is lower for the six months ended June 30, 2013 than the six months ended June 30, 2013 due to fewer workovers being performed in 2013 prior to getting a second workover rig during the second quarter 2013. Windfall Profits Tax, which is a function of volume and price received per barrel, decreased in part due to an increase in volumes offset by lower price received per barrel, but also due to the change in the Windfall Profits Tax law (see Operations – Petrodelta, S.A. above). The foreign currency transaction gain is due to the Bolivar devaluation in February 2013 from 4.30 Bolivars/U.S. Dollar to 6.30 Bolivars/U.S. Dollar and Petrodelta having more Bolivar denominated liabilities than Bolivar denominated assets. 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, 2013 was higher than the effective tax rate for the six months ended June 30, 2012 primarily due to the foreign currency transaction gain.

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 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.

Oman operations and the Antelope Project have been classified as discontinued operations. Net loss on the dispositions is shown in the table below:

During the six months ended June 30, 2012, we expensed to dry hole costs $4.9 million related to the drilling of the AGN-1 on the Block 64 EPSA.

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 currency transaction loss attributable to our international operations was $0.1 million for the six months ended June 30, 2013 (six months ended June 30, 2012: $0.1 million). 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, January 2011 and February 2013.

See, 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. The inflation rate in Venezuela was 25.0 percent for the six months ended June 30, 2013 (six months ended June 30, 2012: 7.0 percent).

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, 2012. The information about market risk for the six months ended June 30, 2013 does not differ materially from that discussed in the Annual Report on Form 10-K for the year ended December 31, 2012.

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

Management of the Company, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures. Based on their evaluation as of June 30, 2013, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) were not effective because of the material weaknesses in our internal control over financial reporting.

We disclosed in Item 9A. Controls and Procedures of our Annual Report on Form 10-K for the year ended December 31, 2012, that we had identified material weaknesses in our internal control over financial reporting with respect to the following (1) sufficient complement of accounting and financial reporting resources, (2) accounting for certain transactions for oil and gas properties, (3) accounting for income taxes, (4) segregation of duties related to certain system access rights and the recording and review of journal entries; (5) preparation and review of certain classification and disclosure matters impacting the financial statements and related notes; and (6) accounting for significant and complex debt and equity transactions.

Management, with the participation of the principal executive officer and principal financial officer, has made significant progress in implementing the plan to remediate the material weaknesses described above and as disclosed in Item 9A. Controls and Procedures of our Annual Report on Form 10-K for the year ended December 31, 2012. However, due to our delayed filing of such Form 10-K, the implementation of such steps is not complete as of June 30, 2013.

There have been no changes in internal control over financial reporting during the quarter ended June 30, 2013 that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

See Notes to Consolidated Condensed Financial Statements, Note 7 – Commitments and Contingencies, our Quarterly Report on Form 10-Q for the period ended March 31, 2013 and our Annual Report on Form 10-K for the year ended December 31, 2012 for a description of certain other legal proceedings. There have been no material developments in such legal proceedings since the filing of such Quarterly and Annual Reports.


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.)

4.5		Second Amendment to Third Amended and Restated Rights Agreement, dated as of February 1, 2013, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A., as Rights Agent. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on February 4, 2013, File No. 1-10762.)

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

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

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

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

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

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.


		Page

PART I FINANCIAL INFORMATION

Item 1.	Financial Statements
	Unaudited Consolidated Condensed Balance Sheets at June 30, 2013 and December 31, 2012		3
	Unaudited Consolidated Condensed Statements of Operations and Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2013 and 2012		4
	Unaudited Consolidated Condensed Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012		5
	Notes to Consolidated Condensed Financial Statements		7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		41

Item 4.	Controls and Procedures		42

PART II OTHER INFORMATION

Item 1.	Legal Proceedings		43

Item 6.	Exhibits		43

Signatures			44


	June 30, 2013			December 31, 2012
	(Unaudited)
	(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9,767		$	72,627
Restricted cash		1,212			1,000
Accounts receivable, net		3,329			2,955
Advances to and receivables from equity affiliate		490			656
Deferred income taxes		821			821
Prepaid expenses and other		1,105			1,460

TOTAL CURRENT ASSETS		16,724			79,519
OTHER ASSETS		6,491			7,613
LONG-TERM RECEIVABLE – EQUITY AFFILIATE		14,324			14,346
INVESTMENT IN EQUITY AFFILIATE		469,896			412,823
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		105,156			81,792
Other administrative property, net		568			744

TOTAL PROPERTY AND EQUIPMENT, NET		105,724			82,536

TOTAL ASSETS	$	613,159		$	596,837


LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable, trade and other	$	2,691		$	3,970
Accrued expenses		8,938			30,748
Accrued interest		371			624
Other current liabilities		1,978			3,538
Income taxes payable		99			102

TOTAL CURRENT LIABILITIES		14,077			38,982
OTHER LONG-TERM LIABILITIES		403			1,108
WARRANT DERIVATIVE LIABILITY		1,685			5,470
LONG-TERM DEBT		76,124			74,839
COMMITMENTS AND CONTINGENCIES (See Note 7)

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, 2013 (December 31, 2012: 80,000 shares); issued 45,943 shares at June 30, 2013 (December 31, 2012: 45,882 shares)		459			458
Additional paid-in capital		265,035			263,646
Retained earnings		213,009			181,378
Treasury stock, at cost 6,550 shares at June 30, 2013 (December 31, 2012: 6,527 shares)		(66,217	)		(66,145	)

TOTAL HARVEST STOCKHOLDERS’ EQUITY		412,286			379,337
NONCONTROLLING INTEREST		108,584			97,101

TOTAL EQUITY		520,870			476,438

TOTAL LIABILITIES AND EQUITY	$	613,159		$	596,837


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands, except per share data)
EXPENSES
Depreciation and amortization	$	87		$	97		$	174		$	194
Exploration expense		2,603			1,541			4,404			3,374
Dry hole costs		—			—			—			767
General and administrative		7,654			6,208			11,081			11,652

		10,344			7,846			15,659			15,987


LOSS FROM OPERATIONS		(10,344	)		(7,846	)		(15,659	)		(15,987	)

OTHER NON-OPERATING INCOME (EXPENSE)
Investment earnings and other		118			80			164			149
Unrealized gain (loss) on warrant derivative		—			(1,641	)		3,785			(1,209	)
Interest expense		(1,067	)		(34	)		(2,265	)		(126	)
Debt conversion expense		—			20			—			(2,402	)
Other non-operating expenses		(141	)		(1,467	)		(613	)		(1,723	)
Foreign currency transaction loss		(183	)		(43	)		(91	)		(53	)

		(1,273	)		(3,085	)		980			(5,364	)

LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(11,617	)		(10,931	)		(14,679	)		(21,351	)

INCOME TAX BENEFIT		(1,415	)		(1,022	)		(1,376	)		(2,242	)

LOSS FROM CONTINUING OPERATIONS BEFORE NET INCOME FROM EQUITY AFFILIATE		(10,202	)		(9,909	)		(13,303	)		(19,109	)

NET INCOME FROM EQUITY AFFILIATE		7,602			22,829			57,073			39,725


NET INCOME (LOSS) FROM CONTINUING OPERATIONS		(2,600	)		12,920			43,770			20,616

DISCONTINUED OPERATIONS		(315	)		(2,155	)		(656	)		(7,569	)


NET INCOME (LOSS)		(2,915	)		10,765			43,114			13,047

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		1,551			4,540			11,483			7,862


NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST	$	(4,466	)	$	6,225		$	31,631		$	5,185


NET INCOME (LOSS) ATTRIBUTABLE TO HARVEST PER COMMON SHARE: (See Note 4 – Earnings Per Share):
Basic	$	(0.12	)	$	0.17		$	0.81		$	0.14

Diluted	$	(0.12	)	$	0.15		$	0.80		$	0.14


COMPREHENSIVE INCOME (LOSS)	$	(4,466	)	$	6,225		$	31,631		$	5,185


	Six Months Ended June 30,
	2013			2012
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	43,114		$	13,047
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization		188			210
Dry hole costs		—			5,617
Amortization of debt financing costs		724			287
Amortization of discount on debt		1,285			—
Foreign currency transaction loss on revaluation		436			—
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		(57,073	)		(39,725	)
Share-based compensation-related charges		1,269			2,124
Unrealized (gain) loss on warrant derivative		(3,785	)		1,209
Other current liabilities		(1,560	)		—
Changes in operating assets and liabilities:
Accounts receivable		(374	)		6,182
Prepaid expenses and other		355			(950	)
Other assets		397			(829	)
Accounts payable		(1,279	)		(6,337	)
Accrued expenses		(7,175	)		(2,177	)
Accrued interest		(253	)		(971	)
Other long-term liabilities		(705	)		48
Income taxes payable		(3	)		532

NET CASH USED IN OPERATING ACTIVITIES		(24,439	)		(18,210	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions of property and equipment		(37,888	)		(13,146	)
Advances to equity affiliate		(248	)		(150	)
Restricted cash		(212	)		1,200

NET CASH USED IN INVESTING ACTIVITIES		(38,348	)		(12,096	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuances of common stock		122			273
Financing costs		(195	)		(167	)

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(73	)		106


NET DECREASE IN CASH AND CASH EQUIVALENTS		(62,860	)		(30,200	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		72,627			58,946

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	9,767		$	28,746


	June 30, 2013
	Carrying Value		Fair Value
	(in thousands)

11% senior unsecured notes (Level 3)	$	76,124	$	78,111


	June 30, 2013
	Level 1		Level 2		Level 3		Total
	(in thousands)
Liabilities:
Warrant derivative liabilities	$	—	$	—	$	1,685	$	1,685

Total liabilities	$	—	$	—	$	1,685	$	1,685


	December 31, 2012
	Level 1		Level 2		Level 3		Total
	(in thousands)
Liabilities:
Warrant derivative liabilities	$	—	$	—	$	5,470	$	5,470

Total liabilities	$	—	$	—	$	5,470	$	5,470


	June 30, 2013		December 31, 2012
	(in millions)
Deferred financing costs	$	2.0	$	3.2
Long-term VAT receivable		3.5		3.5
Long-term prepaid expenses		0.3		0.2
Gabon PSC – blocked payment (net to our 66.667% interest)		0.7		0.7

	$	6.5	$	7.6


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)
Oman operations	$	(315	)	$	(571	)	$	(656	)	$	(5,870	)
Antelope Project		—			(1,584	)		—			(1,699	)

Net loss from discontinued operations	$	(315	)	$	(2,155	)	$	(656	)	$	(7,569	)


		June 30, 2013			December 31, 2012
Significant assumptions (or ranges):
Stock price	Level 1 input	$	3.10		$	9.07
Term (years)			2.33			2.83
Volatility	Level 2 input		90	%		70	%
Risk-free rate	Level 1 input		0.46	%		0.33	%
Dividend yield	Level 2 input		0.0	%		0.0	%
Scenario probability debt/equity raise	Level 3 input		80% / 20	%		80% / 20	%


	Six Months Ended June 30,
	2013			2012
	(in thousands)

Net cash used in operating activities	$	(24,439	)	$	(18,210	)
Net cash used in investing activities		(38,348	)		(12,096	)
Net cash provided by (used in) financing activities		(73	)		106

Net decrease in cash and cash equivalents	$	(62,860	)	$	(30,200	)


	Three Months Ended June 30,						Increase
	2013			2012			(Decrease)

Depreciation and amortization	$	0.1		$	0.1		$	—
Exploration expense		2.6			1.5			1.1
General and administrative		7.7			6.2			1.5
Investment earnings and other		(0.1	)		(0.1	)		—
Unrealized loss on warrant derivative		—			1.6			(1.6	)
Interest expense		1.1			—			1.1
Other non-operating expenses		0.1			1.5			(1.4	)
Loss on exchange rates		0.2			0.1			0.1
Income tax benefit		(1.4	)		(1.0	)		(0.4	)


	Three Months Ended							%
	June 30,				Increase			Increase			Increase
	2013		2012		(Decrease)			(Decrease)			(Decrease)
	(in millions, except volumes)
Revenues
Crude oil	$	314.1	$	318.5	$	(4.4	)		(1	)%
Natural gas		0.9		0.8		0.1			13	%

Total Revenues	$	315.0	$	319.3	$	(4.3	)		(1	)%


Price and Volume Variances
Crude oil price Variance (per Bbl)	$	90.33	$	96.10	$	(5.77	)		(6	)%	$	(19.1	)
Volume Variances
Crude oil volumes (MBbls)		3,477		3,314		163			5	%		14.7
Natural gas volumes (MMcf)		597		494		103			21	%		0.1

Total variance											$	(4.3	)


	Six Months Ended
	June 30,						Increase
	2013			2012			(Decrease)

Depreciation and amortization	$	0.2		$	0.2		$	—
Exploration expense		4.4			3.4			1.0
Dry hole costs		—			0.8			(0.8	)
General and administrative		11.1			11.7			(0.6	)
Investment earnings and other		(0.2	)		(0.1	)		(0.1	)
Unrealized (gain) loss on warrant derivative		(3.8	)		1.2			(5.0	)
Interest expense		2.3			0.1			2.2
Debt conversion expense		—			2.4			(2.4	)
Other non-operating expenses		0.6			1.7			(1.1	)
Foreign currency transaction loss		0.1			0.1			—
Income tax benefit		(1.4	)		(2.2	)		0.8


	HARVEST NATURAL RESOURCES, INC.

Dated: August 9, 2013	By:	/s/ James A. Edmiston
		James A. Edmiston
		President and Chief Executive Officer

Dated: August 9, 2013	By:	/s/ Stephen C. Haynes
		Stephen C. Haynes
		Vice President - Finance, Chief Financial Officer and Treasurer


	June 30, 2013			December 31, 2012
	(in thousands)
Operating Segment Assets
Venezuela	$	473,452		$	416,792
Indonesia		10,436			10,979
Gabon		105,706			80,908
United States		291,435			307,683
Other projects		1,206			—
Discontinued operations		107			313

		882,342			816,675
Intersegment eliminations		(269,183	)		(219,838	)

Total Assets	$	613,159		$	596,837


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.)

4.5		Second Amendment to Third Amended and Restated Rights Agreement, dated as of February 1, 2013, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A., as Rights Agent. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on February 4, 2013, File No. 1-10762.)

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

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

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

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

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