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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2013

or

Commission File No.: 1-10762

HARVEST NATURAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (281) 899-5700

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: Preferred Share Purchase Rights

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

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 website, 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

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 definitions 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

The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 28, 2013 was: $122,116,759.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practical date. Class: Common Stock, par value $0.01 per share, on March 7, 2014, shares outstanding: 42,104,038.

DOCUMENTS INCORPORATED BY REFERENCE

An amendment to this Annual Report on Form 10-K to be filed with the Securities and Exchange Commission not later than 120 days after the close of the Registrant’s fiscal year, is incorporated by reference under Part III of this Form 10-K.

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HARVEST NATURAL RESOURCES, INC.

FORM 10-K

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PART I

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 any forward-looking statements. These factors include our concentration of operations in Venezuela; political and economic risks associated with international operations (particularly those in Venezuela); anticipated future development costs for undeveloped reserves; drilling risks; risk that actual results may vary considerably from reserve estimates; the dependence on the abilities and continued participation of our key employees; 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; permitting and drilling of oil and natural gas wells; availability of materials and supplies necessary to projects and operations; prices for oil and natural gas and related financial derivatives; changes in interest rates; our ability to acquire oil and natural gas properties that meet our 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. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Executive Summary

Harvest Natural Resources, Inc. is a petroleum exploration and production company incorporated under Delaware law in 1989. Our focus is on acquiring exploration, development and producing properties in geological basins with proven active hydrocarbon systems. Our experienced technical, business development and operating personnel have identified low entry cost exploration opportunities in areas with large hydrocarbon resource potential. We acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). In addition to our interests in Venezuela, we hold exploration acreage mainly offshore of Gabon, onshore West Sulawesi in Indonesia and offshore of the People’s Republic of China (“China”). We operate from our Houston, Texas headquarters. We also have regional/technical offices in Singapore and field offices in Port Gentil, Republic of Gabon (“Gabon”) and Jakarta, Republic of Indonesia (“Indonesia”) to support field operations in those areas.

During the last several years, we have been exploring a broad range of strategic alternatives for enhancing and realizing stockholder value. In September 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 received several indications of interest from third parties, provided due diligence materials to third parties under confidentiality agreements and had preliminary discussions with third parties regarding a sale of our interests in Venezuela.

In June 2012 we entered into an agreement with PT Pertamina (Persero), a state-owned limited liability company existing under the laws of the Republic of Indonesia (“Pertamina”), to sell all of our interests in Venezuela for a cash consideration of $725 million, subject to certain price adjustments. The sale to Pertamina was conditioned on, among other things, the approval of the Ministerio del Poder Popular de Petroleo y Mineria, representing the Government of Venezuela (which indirectly owns 60 percent of Petrodelta) and the approval of

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Pertamina’s shareholder, the Government of the Republic of Indonesia. After receiving notice from Pertamina in February 2013 that Pertamina’s shareholder had decided not to approve the transaction, we exercised our right to terminate the agreement in accordance with its terms.

After the termination of the Pertamina transaction, we continued to consider our strategic alternatives. We received several indications of interest from third parties, provided due diligence materials to third parties under confidentiality agreements and had preliminary discussions with third parties regarding a sale of our interests in Venezuela. As discussed below, on December 16, 2013, we entered into an agreement to sell all of our interests in Venezuela to Petroandina Resources Corporation N.V. (“Petroandina”, a wholly owned subsidiary of Pluspetrol Resources Corporation B.V. (“Pluspetrol”)) in two closings for an aggregate cash purchase price of $400 million.

Our Venezuelan interests are owned through Harvest-Vinccler Dutch Holding, B.V., a Dutch private company with limited liability (“Harvest Holding”). Harvest Holding owns 100 percent of HNR Finance, B.V. (“HNR Finance”), and HNR Finance owns a 40 percent interest in Petrodelta, S.A. (“Petrodelta”).

Our ownership of Harvest Holding is through HNR Energia, B.V. (“HNR Energia”) in which we have a direct controlling interest. Prior to December 16, 2013, we indirectly owned 80 percent of Harvest Holding, and we had one partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., (“Vinccler”, a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A.), which owned the remaining noncontrolling interest in Harvest Holding of 20 percent. We do not have a business relationship with Vinccler outside of Venezuela. On December 16, 2013, Harvest and HNR Energia entered into a Share Purchase Agreement (“Share Purchase Agreement”) with Petroandina and Pluspetrol to sell all of our 80 percent equity interest in Harvest Holding to Petroandina in two closings for an aggregate cash purchase price of $400 million. The first closing occurred on December 16, 2013 contemporaneously with the signing of the Share Purchase Agreement, when we sold a 29 percent equity interest in Harvest Holding for $125 million. This first transaction resulted in a loss on the sale of the interest in Harvest Holding of $23.0 million in the year ended December 31, 2013. The second closing, for a cash purchase price of $275 million, will be subject to, among other things, authorization by the holders of a majority of the Company’s outstanding common stock and approval by the Ministerio del Poder Popular de Petroleo y Mineria representing the Government of Venezuela (which indirectly owns the other 60% interest in Petrodelta). As a result of this first sale, we indirectly own 51 percent of Harvest Holding beginning December 16, 2013 and the noncontrolling interest owners hold the remaining 49 percent with Petroandina having a 29 percent interest and Vinccler continuing to own a 20 percent interest. See Share Purchase Agreement below for further information on this transaction.

Corporación Venezolana del Petroleo S.A. (“CVP”) and PDVSA Social S.A. own the remaining 56 percent and 4%, respectively, of Petrodelta. Petroleos de Venezuela S.A. (“PDVSA”) owns 100 percent of CVP and PDVSA Social S.A. Through our indirect 51 percent in Harvest Holding, we indirectly own a net 20.4 percent interest in Petrodelta for the period from December 16, 2013 to date. Prior to December 16, 2013 we indirectly owned a 32 percent interest in Petrodelta through our indirect 80 percent interest in Harvest Holding during this period. In addition to its 40 percent interest in Petrodelta, Harvest Holding also indirectly owns 100 percent of 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.

As of December 31, 2013, we had total assets of $734.9 million, unrestricted cash of $120.9 million and debt of $83.6 million. For the year ended December 31, 2013, we had no revenues from continuing operations and net cash used in operating activities of $37.1 million. As of December 31, 2012, we had total assets of $596.8 million, unrestricted cash of $72.6 million and long-term debt of $74.8 million. For the year ended December 31, 2012, we had no revenues from continuing operations and net cash used in operating activities of $26.4 million.

At December 31, 2013, Petrodelta’s reserves net to our 20.4 percent interest are: Proved reserves 20.7 million barrels of oil equivalent (“MMBOE”), Probable reserves 41.5 MMBOE, and Possible reserves 62.9 MMBOE. Proved plus Probable reserves at 62.2 MMBOE, after accounting for the reduction in our interest from 32.0 percent to 20.4 percent, are virtually

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unchanged from last year. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies – Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve estimates. Barrels of oil equivalent is determined using the approximate heat content ratio of one barrel of crude oil or condensate to six thousand cubic feet (“Mcf”) of natural gas, which ratio does not necessarily reflect price equivalency.

Share Purchase Agreement

On December 16, 2013, Harvest and HNR Energia entered into the Share Purchase Agreement with Petroandina and Pluspetrol, its parent, to sell all of our Venezuelan interests through the sale of our equity interests in Harvest Holding to Petroandina in two closings for an aggregate cash purchase price of $400 million. The first closing occurred contemporaneously with the signing of the Share Purchase Agreement. At that time, HNR Energia sold to Petroandina, for a cash price of $125.0 million, a 29 percent equity interest in Harvest Holding (which we refer to as the “first closing”), which represents an indirect 11.6 percent equity interest in Petrodelta. This first transaction resulted in a loss on the sale of the interest in Harvest Holding of $23.0 million in the year ended December 31, 2013. As a result of this first sale, we indirectly own 51 percent of Harvest Holding beginning December 16, 2013 and the noncontrolling interest owners hold the remaining 49 percent with Petroandina having a 29 percent interest and Vinccler continuing to own a 20 percent interest. We will continue to consolidate Harvest Holding’s results until the sale of the remaining 51 percent interest has been completed. The second closing will be for the sale of HNR Energia’s remaining 51 percent equity interest in Harvest Holding, which represents an indirect 20.4 percent equity interest in Petrodelta, for a cash purchase price of $275 million payable at closing (which we refer to as the “second closing”). The second closing will be subject to, among other things, authorization by the holders of a majority of our outstanding common stock and approval by the Government of the Bolivarian Republic Venezuela (which indirectly owns the other 60 percent interest in Petrodelta).

HNR Energia and Petroandina also entered into a Shareholders’ Agreement (the “Shareholders’ Agreement”) on December 16, 2013, regarding the shares of Harvest Holding. The Shareholders’ Agreement becomes effective upon any termination of the Share Purchase Agreement before the second closing of the sale of the remaining shares of Harvest Holding.

If the Share Purchase Agreement is terminated because of the failure to obtain authorization by our stockholders, we will be required to pay Petroandina a fee of $3.0 million, and Petroandina will have the right to sell back to HNR Energia the shares of Harvest Holding purchased at the first closing (the “First Closing Shares”).

We have agreed not to solicit other offers to acquire our Petrodelta assets or the Company as a whole while the Share Purchase Agreement is in effect. If we receive an unsolicited acquisition proposal (as defined in the Share Purchase Agreement) before our stockholders have approved the sale of our remaining Venezuelan interests, we may enter into discussions with the potential purchaser if our Board of Directors determines, in good faith, after consultation with our outside legal counsel and financial advisors, that such acquisition proposal is reasonably likely to result in a superior proposal (as hereinafter defined). We have the right to terminate the Share Purchase Agreement and accept a superior proposal if we first offer Petroandina the opportunity to modify the terms of the Share Purchase Agreement so that the competing offer is no longer superior and, concurrently with such termination, we pay Petroandina a break-up fee equal to $9.6 million and enter into an alternative acquisition agreement with respect to such superior proposal.

If the Share Purchase Agreement is terminated because we or HNR Energia accept a superior proposal, Petroandina has the right to sell back to HNR Energia, and HNR Energia has the right to cause Petroandina to sell back to HNR Energia, the First Closing Shares, and we will be required to pay Petroandina a breakup fee of $9.6 million.

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Certain conditions must be satisfied before consummation of the proposed sale of our remaining Venezuelan interests, including authorization of the sale by the holders of a majority of the outstanding shares of our common stock entitled to vote at the special meeting and approval of the sale from the Ministerio del Poder Popular de Petroleo y Mineria representing the Government of Venezuela.

The Share Purchase Agreement may, by written notice given before or at the second closing, be terminated, among other reasons, if our stock holders do not authorize the proposed sale, if we or Petroandina breach certain representations, warranties or covenants, if we accept a superior proposal and pay a breakup fee or if any other closing condition is not satisfied or waived.

We must pay a termination fee of $9.625 million, or 3.5 percent of the $275 million purchase price payable at the second closing, in cash to Petroandina if the Share Purchase Agreement is terminated in certain circumstances, including our acceptance of a superior proposal. If the Share Purchase Agreement is terminated as a result of the failure of our stockholders to approve the proposed sale, we must pay a fee of $3 million in cash to Petroandina. We must also pay the reasonable out-of-pocket expenses of Petroandina incurred in connection with the Share Purchase Agreement, up to $4 million, if the Share Purchase Agreement is terminated as a result of our breach of a representation or warranty upon execution of the Share Purchase Agreement or our breach of a covenant.

Petroandina has the right and option to sell to HNR Energia, and to cause HNR Energia to purchase, the First Closing Shares, on termination of the Share Purchase Agreement in certain circumstances. HNR Energia has the right and option to purchase from Petroandina, and to cause Petroandina to sell, the First Closing Shares, on termination of the Share Purchase Agreement in certain other circumstances.

We have agreed to indemnify Petroandina and its affiliates from and against losses arising out of our and HNR Energia’s breaches of representations and warranties (deemed made without any qualification as to materiality or material adverse effect) or failure to perform or comply with covenants in the Share Purchase Agreement, subject to certain limitations.

We guaranteed HNR Energia’s obligations under the Share Purchase Agreement and the Shareholders’ Agreement.

During the term of the Share Purchase Agreement, Harvest Holding may not pay any dividends to HNR Energia, and therefore would not benefit from any dividends paid by Petrodelta during this period.

Approval of the second closing will be submitted to the Company’s stockholders for their consideration, and the Company will file a definitive proxy statement to be used to solicit stockholder approval of the second closing with the Securities and Exchange Commission (“SEC”). The Company’s stockholders are urged to read the proxy statement regarding the transaction when it becomes available and any other relevant documents filed with the SEC, as well as any amendments or supplements to those documents, because they will contain important information. A free copy of the proxy statement, as well as other filings with the SEC containing information about the Company and the transaction may be obtained, when available, at the SEC’s website at www.sec.gov. Copies of the proxy statement may also be obtained, when available, without charge, by directing a request to Harvest Natural Resources, Inc., Investor Relations, 1177 Enclave Parkway, Suite 300, Houston, Texas 77077 or at the Company’s Investor Relations page on its corporate website at www.harvestnr.com. The Company, its directors and executive officers and Morrow & Co., LLC may be deemed to be participants in the solicitation of proxies from the Company’s stockholders in connection with the approval of the second closing.

Recent Events

In January 2013, we announced that we had encountered oil in Dussafu Tortue Marin-1 (“DTM-1”) in Gabon. In February 2013, we announced that we had drilled a sidetrack well (“DTM-1ST1”) to test the lateral extent of the reservoirs encountered. See “Item 1. Business, Operations, Dussafu Marin, Offshore Gabon – Drilling and Development Activity”.

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In January 2013, we acquired an additional 7.1 percent participating interest in the Budong-Budong Production Sharing Contract (“Budong PSC”) and became operator of the Budong PSC in March 2013. If we do not drill an exploration well before October 2014, our partner has the right to give us notice that the consideration for the additional 7.1 percent participating interest must be paid in cash for $3.2 million. See “Item 1. Business, Operations, Budong-Budong, Onshore Indonesia – General.”

In February 2013, we signed farm-out agreements on Block VSM14 and Block VSM15 in Colombia. We have received notices of default from our partners for failing to comply with certain terms of the farmout agreements for Block VSM 14 and Block VSM 15, followed by notices of termination on November 27, 2013. As discussed further in “Item 3. Legal Proceedings”, our partners have filed for arbitration of claims related to these agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests, and we recorded an impairment charge of $3.2 million during the year ended December 31, 2013. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations. See “Item 1. Business – Operations, Colombia”.

In February 2013, we announced that the agreement between Pertamina and HNR Energia entered into in June 2012 for the purchase of Harvest’s interests in Venezuela had been terminated as a result of the Government of Indonesia, in its capacity as sole shareholder of Pertamina, voting not to approve the transaction.

In March 2013, we elected to not request an extension of the first phase or enter the second phase of Block 64 EPSA in Oman, and Block 64 was relinquished effective May 23, 2013. The carrying value of Block 64 EPSA of $6.4 million was considered to be impaired and a related impairment expense was recorded during the year ended December 31, 2012. During the first half of 2013, we terminated operations in Oman and closed the field office. Our activities in Oman have been reflected as discontinued operations in our financial statements.

On September 30, 2013, we entered into a subscription agreement under which we agreed to sell to three purchasers an aggregate of 390,000 shares of our common stock for an aggregate purchase price of $2,000,700. The transaction closed on October 1, 2013.

On October 2, 2013, we entered into subscription agreements under which we agreed to sell to three purchasers an aggregate of 400,000 shares of our common stock for an aggregate purchase price of $1,928,000. The transactions closed on October 4, 2013.

In November 2013, we entered into subscription agreements under which we agreed to sell to 12 purchasers an aggregate of 1,704,800 shares of common stock for an aggregate purchase price of $5,370,120. The purchasers included six Harvest officers and directors, who purchased an aggregate of 246,000 shares of common stock for an aggregate purchase price of $774,900. The transactions closed on November 27, 2013.

As discussed above, on December 16, 2013, we and HNR Energia entered into the Share Purchase Agreement with Petroandina and Pluspetrol to sell all of our Venezuelan interests through the sale of our equity interests in Harvest Holding.

On January 11, 2014, we used a portion of the $125 million in proceeds from the first closing sale to Petroandina to redeem all of our 11% Senior Notes due 2014. The notes were redeemed for $80.0 million, including principal and accrued and unpaid interest. As a result of the redemption, we recorded a loss on extinguishment of debt of approximately $3.6 million in January 2014. This loss primarily includes the write off of the discount on debt ($2.3 million) and the expensing of the related financing costs ($1.3 million).

See Item 1. Business, Operations, Item 1A. Risk Factors, and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a more detailed description of these and other events during 2013 and through the date of filing this Annual Report on Form 10-K.

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Business Strategy

In Operations, Petrodelta below, Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, we discuss the situation in Venezuela and how the actions of the Venezuelan government have and continue to adversely affect our operations. The expectation that dividends from Petrodelta will be minimal over the next few years restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere. As discussed above, on December 16, 2013, Harvest and HNR Energia entered into the Share Purchase Agreement with Petroandina and Pluspetrol to sell all of our 80 percent equity interest in Harvest Holding to Petroandina in two closings for an aggregate cash purchase price of $400 million. The first closing occurred on December 16, 2013 contemporaneously with the signing of the Share Purchase Agreement. The second closing will be subject to, among other things, approval by the holders of a majority of our common stock and approval by the Ministerio del Poder Popular de Petroleo y Mineria representing the Government of Venezuela (which indirectly owns the other 60 percent interest in Petrodelta). See Share Purchase Agreement above.

As discussed above, on January 11, 2014, we used $80.0 million of the $125 million in proceeds from the first closing that we received on December 16, 2013, to redeem all of our 11% Senior Notes due 2014. The remaining $45.0 million of the proceeds from the first closing have been or will be used to pay costs associated with the sale of our Venezuelan interests, to pay severance costs, to make capital expenditures, to pay taxes related to the sale and for general operating expenses. Those remaining proceeds will also be used to repurchase certain outstanding warrants if our stockholders approve the sale of our remaining Venezuelan interests, and if a “Fundamental Change” is consummated under the terms of those warrants.

We are currently marketing our non-Venezuelan assets and talking to potential buyers, and we intend to continue our consideration of a possible sale for some or all of our non-Venezuelan assets if we are able to negotiate a sale or sales in transactions that our Board of Directors believes are in the best interests of the Company and its stockholders. In the meantime, we intend to operate our business in the ordinary course and may ultimately decide to keep our non-Venezuelan assets and acquire additional assets.

If the proposed sale of our remaining Venezuelan interests is completed, a significant portion of our assets will be cash from the proceeds of such transaction. Sales of other non-Venezuelan assets would further increase the portion of our assets that is in cash from the proceeds of such sales. The timing of the second closing is beyond the control of the Company. Operating and capital requirements related to the portfolio of retained assets at the time of the sales will influence the determination by our Board of Directors of the size of any cash distribution to the stockholders from the proceeds of such sales. For clarity, the possible sale of non-Venezuelan assets before the second closing sale would diminish the need for the Company to retain proceeds from the second closing. Depending on the timing of these events, we anticipate using a portion of the proceeds from the second closing to pay for expenses and other costs related to the transaction, which we estimate will be approximately $4 million and to pay taxes related to the transaction, which we estimate will be approximately $51.1 million. In addition, if we do not sell our non-Venezuelan assets before the second closing, then we estimate that we will need to retain approximately $30 million to fund projected general operating expenses and capital expenditures through December 31, 2014 (to the extent that those general operating expenses are not already reserved from any possible sale of our non-Venezuelan assets). Some of these costs will be paid from funds remaining from the proceeds of the first closing. If we sell our non-Venezuelan assets before the second closing, then we estimate that we will need to retain approximately $20 million to fund projected general operating expenses and capital expenditures through December 31, 2014 (to the extent that those general operating expenses are not already reserved from any possible sale of our non-Venezuelan assets). Some of these costs will be paid from funds remaining from the proceeds of the first closing. We will also use these funds to pay any severance or other costs during 2014 associated with the possible severance of some of our personnel in connection with a downsizing of the Company both related to the sale of our Venezuelan interests and related to any sale of our non-Venezuelan assets, if our Board of Directors determines that a downsizing would be in the best interest of the Company and its shareholders. We estimate these costs to be approximately $20 million.

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We will use the remainder of the proceeds as our Board of Directors, in its discretion, determines, based on its determination of what is in the best interests of the Company and its stockholders at the time a decision is made. In addition to the possibility that our Board of Directors may use part of the proceeds to pay a dividend to our stockholders, it is also possible that our Board of Directors may use part of the proceeds to continue the Company’s business. Before making any decisions with respect to paying a dividend to Harvest’s stockholders, our Board of Directors will also need to consider the possible need to provide for retention of funds for contingent obligations relating to any lawsuits or other claims that may exist at the time that the Board of Directors considers these matters. For a description of our non-Venezuelan assets and operations, see “Operations – Dussafu Marin, Offshore Gabon,” “Operations – Budong-Budong, Onshore Indonesia” and “Operations – WAB-21, South China Sea.”

Although we are currently marketing our non-Venezuelan assets and talking to potential buyers, we will continue to operate our business in the ordinary course and may ultimately decide to keep our non-Venezuelan assets and acquire additional assets. Since we no longer have any obligations under the 11% Senior Notes due 2014, and given that we do not currently have any operating cash flow, we may also decide to access additional capital through equity or debt sales. After the sale, we would continue to be a reporting company under SEC regulations and would continue to file reports required by those regulations, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. Through these reports and other public announcements, we will update our strategy and plans for use of the proceeds from the sale of our remaining Venezuelan interests. We also currently expect that our common stock will continue to be traded on the New York Stock Exchange or another appropriate exchange as long as we meet applicable listing requirements.

Available Information

We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934 (“Exchange Act”). The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street NE, Washington, DC 20549-0213. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.

We also make available, free of charge on or through our Internet website (http://www.harvestnr.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Exchange Act are also available on our website. In addition, we have adopted a Code of Business Conduct and Ethics that applies to all of our employees, including our chief executive officer, principal financial officer and principal accounting officer. The text of the Code of Business Conduct and Ethics has been posted on the Corporate Governance section of our website. We post on our website any amendments to, or waivers from, our Code of Business Conduct and Ethics applicable to our senior officers. Additionally, the Code of Business Conduct and Ethics is available in print to any person who requests the information. Individuals wishing to obtain this printed material should submit a request to Harvest Natural Resources, Inc., 1177 Enclave Parkway, Suite 300, Houston, Texas 77077, Attention: Investor Relations.

Reserves

We measure and disclose our oil and gas reserves in accordance with the provisions of the SEC’s Modernization of Oil and Gas Reporting and ASC 932, “Extractive Activities – Oil and Gas” (“ASC 932”). See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies – Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve estimates.

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The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided, management reviews and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Arts in Engineering Science, a Master of Science in Petroleum Engineering, more than 33 years of experience in reservoir engineering, and is a member of the Society of Petroleum Engineers.

All reserve information in this report is based on estimates prepared by Ryder Scott Company L.P. (“Ryder Scott”), independent petroleum engineers. The technical personnel responsible for preparing the reserve estimates at Ryder Scott meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

In Venezuela during 2013, Petrodelta drilled and completed 13 production wells. Eleven of the wells were previously identified as Proved Undeveloped (“PUD”) locations and two wells were previously classified as probable, possible or undefined locations. In 2013, an additional ten PUD locations were identified through drilling activity, however ten PUD locations which are scheduled to be drilled five years after the wells were originally identified have been reclassified as Probable reserves. At December 31, 2013, Petrodelta has 133 identified PUD locations.

Petrodelta’s 2013 business plan, as proposed by Petrodelta, contemplates sustained drilling activities through the year 2023 to fully develop the El Salto, Isleño and Temblador fields. As a noncontrolling interest shareholder in Petrodelta, HNR Finance, a wholly owned subsidiary of Harvest Holding, has limited ability to control the development plans that are periodically prepared and/or approved by the Venezuelan government. The PUD locations which are now scheduled to be drilled five years after they were originally identified have been reclassified as Probable reserves.

Proved undeveloped reserves of 10.6 MMBOE from 133 gross PUD locations are scheduled to be drilled within the period from 2014 to 2017 and within five years from when these locations were first identified. All above MMBOE represent our net 20.4 percent interest, net of a 33.33 percent royalty.

Probable undeveloped reserves of 41.5 MMBOE include 14.0 MMBOE from 108 gross undeveloped locations that would otherwise meet the definition of proved undeveloped reserves, except that they are scheduled to be drilled at least five years after the date that they were originally identified. All of these 108 locations are scheduled to be drilled within five years from 2014 to 2019.

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The following table shows, by country and in the aggregate, a summary of our proved, probable and possible oil and gas reserves as of December 31, 2013.

Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves as of December 31, 2013, 2012 and 2011 and changes in proved reserves during the last three years are contained in Item 15. Supplemental Information on Oil and Natural Gas Producing Activities (unaudited). See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation, Critical Accounting Policies – Reserves for additional information on our reserves.

Operations

As of December 31, 2013, our operations include:

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Petrodelta

General

On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract was published in the Official Gazette, the official government publication where laws, decrees, resolutions, instructions, and other regulations of general interest issued by the central government of Venezuela are published in order to make those acts valid and official. Petrodelta is to undertake the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from that date. Petrodelta is governed by its own charter and bylaws. Petrodelta’s portfolio of properties in eastern Venezuela includes large proven oil fields as well as properties with very substantial opportunities for both development and exploration. We have seconded key technical and managerial personnel into Petrodelta and participate on Petrodelta’s board of directors.

Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Under its conversion contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. Petrodelta’s approved capital budget for 2013 was $210 million and included a drilling program to use five drilling rigs for both development and appraisal wells to maintain production capacity. Petrodelta’s actual capital expenditures for 2013 were $269.2 million, and exceeded the budget as a result of cost overruns and inefficiencies.

PDVSA, as administrator of certain operating contracts for several mixed companies in Venezuela, has failed to pay on a timely basis certain amounts owed to contractors doing work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures. 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 Holding. 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 has an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.

Crude oil delivered from Uracoa, Bombal, Tucupita, Isleño and Temblador fields of Petrodelta to PDVSA Petroleo S.A. (“PPSA”), a wholly owned subsidiary of PDVSA, is priced with reference to Merey 16 published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices are quoted and sold in U.S. Dollars. The crude oil produced and delivered from El Salto field is priced with reference to Boscan, a heavier 10 degree API crude oil, published prices, also weighted for different markets and quality adjusted as described above. Boscan published prices are also quoted and sold in U.S. Dollars. An amendment to Petrodelta’s Contract for Sale and Purchase of Hydrocarbons with PPSA (the “Sales Contract”) has been approved by Petrodelta’s shareholders and is awaiting execution. See

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Petrodelta for additional information on Petrodelta’s Contract for Sale and Purchase of Hydrocarbons with PPSA. Natural gas delivered from the Petrodelta fields to PPSA is priced at $1.54 per Mcf. PPSA is obligated to make payment to Petrodelta in U.S. Dollars for crude oil and natural gas liquids delivered. Natural gas deliveries are paid in Venezuelan Bolivars (“Bolivars”), but the pricing for natural gas is referenced to the U.S. Dollar.

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 (the “amended Windfall Profits Tax”). See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Venezuela – Petrodelta for a discussion of the effects of the amended Windfall Profits Tax on Petrodelta’s business.

On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance. Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, as of the date of this proxy statement, this dividend has not been received, although it is due and payable. Petrodelta’s board of directors declared this dividend and has never indicated that the dividend is not payable, or that it will not be paid. The dividend receivable is classified as a long-term receivable at December 31, 2013 due to the uncertainty in the timing of payment. There is uncertainty with respect to the timing of the receipt of this dividend and whether future dividends will be declared or paid. We 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 affected.

Petroandina has the right to any dividends paid by Harvest Holding after December 16, 2013, that would attach with respect to their current 29 percent interest and, after the second closing any dividends that would attach to the shares of Harvest Holding sold in that closing, regardless of whether the dividends are paid in connection with dividends paid by Petrodelta that are declared before, on or after the date of the Share Purchase Agreement and regardless of the record date therefor. During the term of the Share Purchase Agreement, Harvest Holding may not pay any dividends to HNR Energia, and therefore would not benefit from any dividends paid by Petrodelta during this period.

Petrodelta 2014 Capital Budget

The CVP proposed 2014 budget for Petrodelta is for $518.8 million in capital expenditures. This is nearly double the amount spent in 2013, and we expect the actual expenditures in 2014 will be well below the budgeted amount for several reasons. The engineering processes which are required to execute the plan have not been completed. In addition, the plan requires the procurement of materials and long lead equipment as well as negotiation of contracts with suppliers and this has not progressed to a stage which allow achievement of the plan. Since Petrodelta has had insufficient monetary support and contractual adherence by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2014 budget. Should PDVSA continue in insufficient monetary support and contractual adherence of Petrodelta, underinvestment in the development plan may lead to continued under-performance. This budget proposal has not been reviewed by Petrodelta’s board yet.

Location and Geology

Uracoa Field

At December 31, 2013, there were 76 (compared to 86 at December 31, 2012) oil and natural gas producing wells and seven (compared to seven at December 31, 2012) water injection wells in the field. The current production facility has capacity to handle 30 thousand barrels (“MBbls”) of oil per day, 130 MBbls of water per day, and storage of up to 75 MBbls of crude oil. The oil produced from Uracoa is blended with the oil produced

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from Tucupita, Bombal and Isleño fields then transported through a 25-mile oil pipeline from the Uracoa plant facilities UM-2 to PDVSA’s EPT-1 storage and fiscalization facility. Substantially all natural gas currently being delivered by Petrodelta is produced from the Uracoa field and is delivered to PDVSA through a 64-mile pipeline to Mamo gas station and PDVSA Gas network.

Tucupita Field

At December 31, 2013, there were 19 (compared to 15 at December 31, 2012) oil producing wells and five (compared to four at December 31, 2012) water injection wells in the field. The Tucupita production facility has a capacity to process 30 MBbls of oil per day, 125 MBbls of water per day and storage for up to 60 MBbls of crude oil. The oil is transported through a 31-mile, 20-MBbls-of-oil-per-day pipeline from the Tucupita field to the Uracoa plant facilities UM-2. See “Uracoa Field” above.

Bombal Field

At December 31, 2013, there were three (compared to four at December 31, 2012) oil producing wells. The oil is transported through a five-mile, ten MBbls of oil per day pipeline from the Bombal field to the Uracoa plant facilities UM-2. See “Uracoa Field” above.

Isleño Field

The Isleño field was discovered in 1953. Seven oil appraisal wells were drilled by PDVSA prior to the field being contributed to Petrodelta. At December 31, 2013, there were three (compared to two at December 31, 2012) oil producing wells in the field. The oil is transported through a pipeline to the Uracoa plant facilities UM-2. See “Uracoa Field” above. A 16-inch, 6.2-mile, 20-MBbls-per-day transfer line capacity was completed and is operational from the Isleño field to Uracoa to transport the fluids produced.

Temblador Field

At December 31, 2013, there were 28 (compared to 28 at December 31, 2012) oil producing wells in the field. The oil is transported through two pipelines: a 5.6-mile, 40-MBbls-of-oil-per-day trunkline from the TY-8 flow station (east end of the field) to the TY-23 flow station; and a 4.3-mile, 20 MBbls-of-oil-per-day gathering system from the west end of the field to the TY-23 flow station. The total crude oil is then delivered from the TY-23 flow station into PDVSA’s EPT-1 storage facility.

El Salto Field

At December 31, 2013, there were 23 (compared to 17 at December 31, 2012) oil producing wells and one (compared to one at December 31, 2012) water injection well in the El Salto field. The oil is transported through an 18.1-mile, 40-MBbls-of-oil-per-day pipeline to PDVSA’s EPM-1 storage facility.

Infrastructure and Facilities

Petrodelta has a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA’s EPT-1 storage facility, the custody transfer point. The pipeline has a nominal capacity of 30 MBls of oil per day and a design capacity of 60 MBls of oil per day.

Petrodelta has a 64-mile pipeline from Uracoa to the Mamo gas station and the PDVSA gas network with a nominal capacity of 70 million cubic feet (“MMcf”) of natural gas per day and a design capacity of 90 MMcf of natural gas per day.

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Petrodelta has two main gathering systems at Temblador Field, one in the east side of the field, a 5.6-mile trunkline from the TY-8 flow station to the TY-23 flow station, which is next to PDVSA’s EPT-1 storage facility. The trunkline has an operational capacity of 40 MBls of fluid per day and a design capacity of 60 MBls of oil per day. The second one, on the west side of the field, is a 4.3-mile, 20-MBbls-of-total-fluid-per-day gathering system from the end of the field to the TY-23 flow station. The total crude oil, on specification, is then delivered from the TY-23 flow station into PDVSA’s EPT-1 storage facility (the custody transfer point).

Petrodelta has an 18.1-mile pipeline from El Salto to PDVSA’s COMOR EPM-1 storage facility, the custody transfer point. The pipeline has a nominal capacity of 30 MBls of oil per day and a design capacity of 40 MBls of oil per day. Petrodelta is executing additional infrastructure enhancement projects in El Salto and Temblador.

Petrodelta has long term agreements in place with the PDVSA gas affiliate for purchase of power for electrical needs, leasing of compression, and operation and maintenance of the gas treatment and compression facilities at the Uracoa and Tucupita fields.

Drilling and Development Activity

During the year ended December 31, 2013, Petrodelta drilled and completed 13 development wells. Petrodelta delivered approximately 14.5 MBls of oil and 2.6 billion cubic feet (“Bcf”) of natural gas, averaging 41,014 BOE per day during the year ended December 31, 2013.

During the year ended December 31, 2012, Petrodelta drilled and completed 12 development wells. Petrodelta delivered approximately 13.2 MBls of oil and 2.2 Bcf of natural gas, averaging 36,979 BOE per day during the year ended December 31, 2012. During the year ended December 31, 2011, Petrodelta drilled and completed 15 development wells, one successful appraisal well and two water injector wells. Petrodelta delivered approximately 11.4 MBls of oil and 2.3 Bcf of natural gas, averaging 32,240 BOE per day during the year ended December 31, 2011.

Currently, Petrodelta is operating six drilling rigs and one workover rig and is continuing with infrastructure enhancement projects in the El Salto and Temblador fields. A pipeline was completed in March 2013, and it is operational between the Isleño field and the main production facility at Uracoa.

Risk Factors

We face significant risks in holding a minority equity investment in Petrodelta. These risks and other risk factors are discussed in Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Dussafu Marin, Offshore Gabon

General

In 2008, we acquired a 66.667 percent ownership interest in the Dussafu PSC through two separate acquisitions. We are the operator.

The Dussafu PSC partners and Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources, entered into the third exploration phase of the Dussafu PSC with an effective date of May 28, 2012. The Direction Generale Des Hydrocarbures agreed to lengthen the third exploration phase to four years, until May 27, 2016.

Location and Geology

The Dussafu PSC contract area is located offshore Gabon, adjacent to the border with the Republic of Congo. It contains 680,000 acres with water depths to 1,650 feet. Production and infrastructure exists in the blocks contiguous to the Dussafu PSC.

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Drilling and Development Activity

During 2011, we drilled our first exploratory well, Dussafu Ruche Marin-1 (“DRM-1”), and two appraisal sidetracks. DRM-1 and sidetracks discovered oil of approximately 149 feet of pay within the Gamba and Middle Dentale Formations. DRM-1 and sidetracks are currently suspended pending further exploration and development activities.

Operational activities during 2012 included completion of the time processing of 545 square kilometers of seismic, which was acquired in the fourth quarter of 2011, and well planning. The 3-D Pre-Stack Time Migration was completed in July 2012. Pre-Stack Depth processing and reprocessing of the 2005 Inboard 3-D seismic of approximately 1,300 square kilometers commenced in June 2012 with the time reprocessing and merging of the various 3-D surveys completed in September 2012. The Pre-Stack Depth processing project was completed in September 2013.

During the fourth quarter of 2012, our second exploration well on the Tortue prospect to target stacked pre-salt Gamba and Dentale reservoirs commenced. DTM-1 was spud on November 19, 2012 in a water depth of 380 feet. On January 4, 2013, we announced that DTM-1 had reached a vertical depth of 11,260 feet within the Dentale Formation. Log evaluation and pressure data indicate that we have an oil discovery of approximately 42 feet of pay in a 72-foot column within the Gamba Formation and 123 feet of pay in stacked reservoirs within the Dentale Formation.

The first appraisal sidetrack of DTM-1 (“DTM-1ST1”) was spud in January 12, 2013. DTM-1ST1 was drilled to a total depth of 11,385 feet in the Dentale Formation, approximately 1,800 feet from DTM-1 wellbore and found 65 feet of pay in the primary Dentale reservoir. Several other stacked sands with oil shows were encountered; however, due to a stuck downhole tool, logging operations were terminated before pressure data could be collected to confirm connectivity. The well can be re-entered, and the downhole tool has since been retrieved. Work on DTM-1 and DTM-1ST1 was suspended pending future appraisal and development activities.

Geoscience, reservoir engineering and economic studies have progressed and a field development plan is being prepared for a cluster field development of both the Ruche and Tortue discoveries along with existing pre-salt discoveries at Walt Whitman and Moubenga.

Following the success in both the pre-salt Gamba and Dentale reservoirs in the two Harvest exploration wells a new 1,130 square kilometer 3D seismic survey commenced in October and completed in mid-November 2013. This is first 3D coverage over the outboard area of the Dussafu license, where significant pre-salt prospectivity has been already recognized on 2D seismic data. Pre-Stack Depth processing commenced in December 2013 with the first high quality seismic products expected to be available during the second quarter of 2014. The pre-salt reservoirs are currently the focus of deep water exploration activity offshore Gabon. The new 3D seismic data was extended to be acquired over the two Harvest discoveries and should also enhance the placement of future development wells in the Ruche and Tortue development program. We continue to evaluate our prospects, but we have not drilled any additional wells.

Budong-Budong, Onshore Indonesia

General

In 2007, we entered into a farmout agreement to acquire a 47 percent interest in the Budong PSC located mostly onshore West Sulawesi, Indonesia. In April 2008, Indonesia approved this assignment. Our partner is the operator through the exploration phase as required by the terms of the Budong PSC, and we have an option to become operator, if approved by Indonesia and SKK Migas, the Special Task force for the oil and gas sector, in any subsequent development and production phase.

We acquired our 47 percent interest in the Budong PSC by committing to fund the first phase of the exploration program up to a maximum of $17.2 million, including the acquisition of 2-D seismic information and drilling of the first two exploration wells. Before we drilled the first exploration well, our partner had a one-time

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option to increase the level of the carried interest to a maximum of $20.0 million. On September 15, 2010, our partner exercised its option to increase its carried interest by $2.7 million to a total of $19.9 million. The additional carried interest increased our ownership by 7.4 percent to 54.4 percent. On March 3, 2011, Indonesia approved this change in ownership interest.

On January 14, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator to a third party, which allowed us to acquire an additional 10 percent ownership interest in the Budong PSC at a cost of $3.7 million payable ten business days after completion of the first exploration well. The $3.7 million was paid on April 18, 2011. Closing of this acquisition increased our participating ownership interest in the Budong PSC to 64.4 percent with our cost-sharing interest becoming 64.51 percent until first commercial production. On August 11, 2011, Indonesia approved this change in ownership interest.

The initial exploration term of the Budong PSC was due to expire on January 15, 2013. In September 2012, the operator of the Budong PSC, on behalf of us and our partner, submitted a request to BPMIGAS, Indonesia’s oil and gas regulatory authority, under the terms of the Budong PSC for a four-year extension of the initial six-year exploration term of the Budong PSC. In January 2013, we received written approval from SKK Migas of the four-year extension of the initial six-year exploration term to January 15, 2017.

In November 2012, the Indonesia constitutional court declared BPMIGAS to be unconstitutional. In January 2013, SKK Migas was formed to replace BPMIGAS. SKK Migas supervises all oil and gas industry activities in Indonesia.

In December 2012, we signed a farmout agreement with the operator of the Budong PSC to acquire an additional 7.1 percent participating interest and to become operator of the Budong PSC. We assumed the role of operator effective March 25, 2013. Closing of this acquisition on April 22, 2013 increased our participating ownership interest in the Budong PSC to 71.5 percent with our cost-sharing interest becoming 72 percent until first commercial production. The consideration for this transaction is that we will fund 100 percent of the costs of the first exploration well of the four-year extension to the Budong PSC. If we do not drill an exploration well before October 2014, our partner has the right to give us notice that the consideration for the additional 7.1 percent participating interest must be paid in cash for $3.2 million.

We have satisfied all work commitments for the current exploration phase of the Budong PSC. However, 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. We are actively discussing the sale of our interests in Budong, and based on indications of interest received in December 2013, we determined that is it was appropriate to recognize and impairment expense of $0.6 million and a charge included in general and administrative expenses related to a valuation allowance on VAT that we do not expect to recover of $2.8 million.

Location and Geology

During the initial exploration period, the Budong PSC covered 1.35 million acres. The Budong PSC includes a ten-year exploration period and a 20-year development phase. Pursuant to the terms of the Budong PSC, at the end of the first three-year exploration phase, 45 percent of the original area was to be relinquished to BPMIGAS. In January 2010, 35 percent of the original area was relinquished and 10 percent of the required relinquishment was deferred until 2011. In January 2011, the deferred 10 percent of the original total contract area was relinquished. The Budong PSC currently covers 0.75 million acres. However, pursuant to the request for extension of the initial exploration term, the contract area held by the Budong PSC at the beginning of the extension period should be reduced, according to the terms of the Budong PSC, from the current 55 percent to 20 percent of the original contract area. In January 2014, we submitted a relinquishment deferral proposal of 5 percent to SKK Migas. The retained area will contain all the areas of geological interest to the Budong PSC partners.

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The Budong PSC includes the Lariang and Karama sub-basins, which are the eastern onshore extension of the West Sulawesi foldbelt (“WSFB”). Field work performed has confirmed the presence of Eocene source and reservoir potential. Offshore seismic surveys have greatly improved the understanding of the geology and enhanced the prospectivity of the offshore WSFB and, by analogy, the sparsely explored onshore area.

Drilling and Development Activity

In 2011, two exploratory wells were drilled, Lariang-1 (“LG-1”) and Karama-1 (“KD-1”). Both wells were plugged and abandoned in 2011 and early 2012.

Operational activities during 2012 focused on a review of geological and geophysical data obtained from the drilling of LG-1 and KD-1 wells to upgrade the prospectivity of the block and to define a prospect for potential drilling in 2013. We have completed remapping of both the Lariang and Karama Basins with eight leads in the Lariang Basin and five leads in the Karama Basin having been identified. The identification of these leads is the basis for the four-year extension request of the first six-year exploration term. We continue to evaluate our prospects, but we have not drilled any additional wells.

WAB-21, South China Sea

General

In 1996, we acquired a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. The WAB-21 petroleum contract area lies within an area that is the subject of a border dispute between China and Socialist Republic of Vietnam (“Vietnam”). Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The border dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the dispute. Although it is uncertain when or how this dispute will be resolved and under what terms the various countries and parties to the agreements may participate in the resolution, there has been a small increase in exploration activity in the area starting in 2009.

Location and Geology

The WAB-21 contract area covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under certain circumstances, and is located in the West Wan’ an Bei Basin (Nam Con Son) of the South China Sea. Its western edge lies approximately 20 miles to the east of significant producing natural gas fields, Lan Tay and Lan Do, which are reported to contain two trillion cubic feet (“Tcf”) of natural gas and commenced production in November 2002. Also located to the west of WAB-21 are the Dua and Chim Sao discoveries that commenced oil production in 2011 and the oil and gas discovery in 2009 of Ca’ Rong Doh. The WAB-21 contract area covers a large unexplored area of the Wan’ an Bei Basin where the same successful Lower Miocene through to Upper Miocene plays to the west are present. Exploration success by other operators outside the WAB-21 contract area in the basin to date has resulted in discoveries estimated to total in excess of 500 MBls of oil and 7.5 Tcf of natural gas. Several similar structural trends and geological formations, each with significant potential for hydrocarbon reserves in traps with multiple pay zones similar to the known fields and discoveries to the west are present within WAB-21.

Drilling and Development Activity

Due to the border dispute between China and Vietnam, we have been unable to pursue an exploration program during phase one of the contract. The Joint Management Committee has approved an extension of the license until May 31, 2015. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist.

Even though there continues to be increasing activity on the Vietnamese blocks, which we believe confirms our view of WAB-21’s prospectivity, we impaired the carrying value of WAB-21 at December 31, 2012 due to our continued inability to pursue an exploration program. However, we continue to seek permission to acquire regional 2-D seismic and localized 3-D seismic.

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Colombia-Discontinued Operations

In February 2013, we signed farmout agreements on Block VSM14 and Block VSM15 in Colombia. Under the terms of the farm-out agreements, we had a 75 percent beneficial working interest and our partners had a 25 percent carried interest for the minimum exploratory work commitments on each block. We requested the legal assignment of the interest by the Agencia Nacional de Hidrocarburos (“ANH”), Colombia’s oil and gas regulatory authority, and approval of us as operator.

For both blocks, phase one of the contract began on December 15, 2012 and expires on December 15, 2015. The minimum work commitments for phase one of VSM14 include three exploration wells and the acquisition of 70 kilometers of 2D seismic information. The minimum work commitment for phase one of VSM15 includes one exploration well, the acquisition of 65 kilometers of 2D seismic information, reprocessing of 70 kilometers of 2D seismic information and the acquisition of 91 square kilometers of 3D seismic information.

VSM14 covers 137,061 acres and VSM15 covers 105,721 acres. Both blocks are located in the Upper Magdalena Valley in Colombia. The blocks are considered to be prospective for conventional oil and gas fields in multiple reservoirs in Tertiary and Cretaceous rocks, as well as for unconventional oil and gas fields in the Cretaceous La Luna and Villeta formations.

To date, there have been two exploration wells drilled on block VSM 14, both of which were plugged and abandoned. There have been no wells drilled on block VSM 15.

We have received notices of default from our partners for failing to comply with certain terms of the farmout agreements for Block VSM 14 and Block VSM 15, followed by notices of termination on November 27, 2013. As discussed further in “Item 3. Legal Proceedings”, our partners have filed for arbitration of claims related to these agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests, and we recorded an impairment charge of $3.2 million during the year ended December 31, 2013. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations.

Block 64 EPSA, Oman-Discontinued Operations

In 2009, we signed an EPSA with Oman for Block 64 EPSA. We had an 80 percent working interest and our partner, Oman Oil Company, had a 20 percent carried interest in Block 64 EPSA during the initial period.

The First Phase of Block 64 EPSA had a minimum work obligation of $22 million to reprocess 375 square kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup. In 2011, two exploratory wells were drilled, Mafraq South-1 (“MFS-1”) and Al Ghubar North-1 (“AGN-1”). Both wells were plugged and abandoned in the fourth quarter of 2011 and first quarter of 2012. Operational activities during 2012 included post-well evaluation and review of geological and geophysical data obtained from the drilling of the MFS-1 and AGN-1 wells.

On March 12, 2013, we elected to not request an extension of the first phase or enter the second phase of Block 64 EPSA, and Block 64 was relinquished effective May 23, 2013. The carrying value of Block 64 EPSA of $6.4 million was considered to be impaired and a related impairment expense was recorded at December 31, 2012. During the first half of 2013, we terminated operations and closed the field office. Our activities in Oman have been reflected as discontinued operations in our financial statements.

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Production, Prices and Lifting Cost Summary

In the following table we have set forth, by country, our net production, average sales prices and average operating expenses for the years ended December 31, 2013, 2012 and 2011. The presentation for Venezuela is presented at our net ownership interest in Petrodelta which was 32 percent through December 15, 2013 and 20.4 percent thereafter. The United States is presented at our ownership interest.

Drilling and Undeveloped Acreage

For acquisitions of leases, development and exploratory drilling, we spent approximately (excluding our share of capital expenditures incurred by equity affiliates) $43.9 million in 2013 ($23.6 million in 2012, $106.1 million in 2011). These numbers do not include any costs for the development of proved undeveloped reserves in 2013, 2012 or 2011.

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We have participated in the drilling of wells as follows:

In Gabon, following the success in both the pre-salt Gamba and Dentale reservoirs in the two Harvest exploration wells, a new seismic survey commenced in October and we expect the first high quality seismic products expected to be available during the second quarter of 2014. The new 3D seismic data was extended to be acquired over the two Harvest discoveries and should also enhance the placement of future development wells in the Ruche and Tortue development program. We continue to evaluate our prospects, but we have not drilled any additional wells.

All of our drilling activities are conducted on a contract basis with independent drilling contractors. We do not directly operate any drilling equipment.

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Acreage

The following table summarizes the developed and undeveloped acreage that we own, lease or hold under concession as of December 31, 2013:

Regulation

General

Our operations and our ability to finance and fund our growth strategy are affected by political developments and laws and regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are affected by:

In any country in which we may do business, the oil and natural gas industry legislation and agency regulation are periodically changed, sometimes retroactively, for a variety of political, economic, environmental and other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and our potential for economic loss.

Environmental Regulations

Our operations are subject to various federal, state, local and international laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The cost of compliance could be significant. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial and damage payment obligations, or the issuance of injunctive relief (including orders to cease operations). Environmental laws and regulations are complex and have tended to become more stringent over time. We also are subject to various environmental permit requirements. Some environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior

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operators or third parties. To the extent laws are enacted or other governmental action is taken that prohibits or restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected.

Competition

We encounter substantial competition from major, national and independent oil and natural gas companies in acquiring properties and leases for the exploration and development of crude oil and natural gas. The principal competitive factors in the acquisition of oil and natural gas properties include staff and data necessary to identify, investigate and purchase properties, the financial resources necessary to acquire and develop properties, and access to local partners and governmental entities. Many of our competitors have influence, financial resources, staffs, data resources and facilities substantially greater than ours.

Employees

At December 31, 2013, full-time employees in our various offices were: Houston – 17; Caracas – 12; London – 3; Singapore – 2; and Jakarta –12. We augment our employees from time to time with independent consultants, as required.

In addition to other information set forth elsewhere in this Annual Report on Form 10-K, the following factors should be carefully considered when evaluating us.

Risks Related to Our Business

Our cash position and limited ability to access additional capital may limit our growth opportunities. We have no recurring cash flows, and our available cash may not be sufficient to meet capital and operational commitments for the next twelve months. Our future cash position depends primarily upon the successful completion of the second closing sale, but is also impacted by farm-out, or possible sale or otherwise monetization of assets as necessary to maintain the liquidity required to run our operations and capital spending requirements. There is no assurance that the second closing sale will be completed, and under certain circumstances we may be required to repurchase the First Closing Shares at the greater of $125 million or fair value. These factors could have a material adverse effect on our financial condition and liquidity and may limit our ability to grow through the acquisition or exploration of additional oil and gas properties and projects.

Our business may be sensitive to market prices for oil and gas. We have made significant investments in our oil and gas properties. As we seek to sell the assets in our portfolio, to the extent market values of oil and gas decline, the valuation of the investments in these projects may be adversely affected.

Global market and economic conditions, including those related to the credit markets, could have a material adverse effect on our business, financial condition and results of operations. A general slowdown in economic activity could adversely affect our business by impacting our ability to access additional capital as well as the need to preserve adequate development capital in the interim.

We may not be able to meet certain contractual funding requirements. We have added a significant global exploration component to diversify our overall portfolio. In many locations, we may be required to post performance bonds in support of a work program or the work program may include minimum funding requirements to keep the contract. We may not have the funds available to meet the minimum funding requirements when they come due and be required to forfeit the contracts.

Our portfolio of hydrocarbon assets in known hydrocarbon basins globally are exposed to greater deal execution, operating, financial, legal and political risks. The environments in which we operate are often difficult and the ability to operate successfully will depend on a number of factors, including our ability to

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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 these countries are not mature and their reliability is 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 business depends on our ability to have significant influence over operations and financial control.

We do not directly manage operations of Petrodelta. PDVSA, through CVP, exercises substantial control over Petrodelta’s operations, making Petrodelta subject to some internal policies and procedures of PDVSA as well as being subject to constraints in skilled personnel available to Petrodelta. These issues may have an adverse effect on the efficiency and effectiveness of Petrodelta’s operations.

We hold a minority equity investment in Petrodelta. Even though we are able to exercise significant influence as a minority equity investor in Petrodelta, our control of Petrodelta is limited to our rights under the Conversion Contract and its annexes and Petrodelta’s charter and bylaws. As a result, our ability to implement or influence Petrodelta’s business plan, assure quality control, and set the timing and pace of development may be adversely affected. In addition, the majority partner, CVP, has initiated and undertaken numerous unilateral decisions that can impact our minority equity investment.

Petrodelta’s business plan will be sensitive to market prices for oil. Petrodelta operates under a business plan, the success of which will rely heavily on the market price of oil. To the extent that market values of oil decline, the business plan of Petrodelta may be adversely affected.

A decline in the market price of crude oil could uniquely affect the financial condition of Petrodelta. Under the terms of the Conversion Contract and other governmental documents, Petrodelta is subject to a special advantage tax (“ventajas especiales”) which requires that if in any year the aggregate amount of royalties, taxes and certain other contributions is less than 50 percent of the value of the hydrocarbons produced, Petrodelta must pay the government of Venezuela the difference. In the event of a significant decline in crude prices, the ventajas especiales could force Petrodelta to operate at a loss. Moreover, our ability to control those losses by modifying Petrodelta’s business plan or restricting the budget is limited under the Conversion Contract.

An increase in oil prices could result in increased tax liability in Venezuela affecting Petrodelta’s operations and profitability, which in turn could affect our dividends and profitability. Prices for oil fluctuate widely. In April 2011, the Venezuelan government published the amended Windfall Profits Tax which establishes a special contribution for extraordinary prices to the Venezuelan government of 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. The amended Windfall Profits Tax also establishes a special contribution for exorbitant prices to the Venezuelan government of (1) 80 percent when the average price of the Venezuelan Export Basket (“VEB”) exceeds $80 per barrel but is less than $100 per barrel; (2) 90 percent when the average price of the VEB exceeds $100 per barrel but is less that $110 per barrel; and (3) 95 percent when the average price of the VEB exceeds $110 per barrel. Any increase in the taxes payable by Petrodelta, including the Windfall Profits Tax, as a result of increased oil prices will reduce cash available for dividends to us and our partner, CVP.

Oil price declines and volatility could adversely affect Petrodelta’s operations and profitability, which in turn could affect our dividends and profitability. Prices for oil also affect the amount of cash flow available for capital expenditures and dividends from Petrodelta. Lower prices may also reduce the amount of oil that we can produce economically and lower oil production could affect the amount of natural gas we can produce. We cannot predict future oil prices. Factors that can cause fluctuations in oil prices include:

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The total capital required for development of Petrodelta’s assets may exceed the ability of Petrodelta to finance such developments. Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Petrodelta’s future capital requirements for the development of its assets may exceed the cash available from existing cash flow. Petrodelta’s ability to secure financing is currently limited and uncertain, and has been, and may be, affected by numerous factors beyond its control, including the risks associated with operating in Venezuela. Because of this financial risk, Petrodelta may not be able to secure either the equity or debt financing necessary to meet its future cash needs for investment, which may limit its ability to fully develop the properties, cause delays with their development or require early divestment of all or a portion of those projects. This could negatively impact our minority equity investment. 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. In addition, CVP may be unable or unwilling to fund its share of capital requirements and our ability to require them to do so is limited. Should PDVSA continue in insufficient monetary support and contractual adherence of Petrodelta, underinvestment in the development plan may lead to continued under-performance.

The legal or fiscal framework for Petrodelta may change and the Venezuelan government may not honor its commitments. While we believe that the Conversion Contract and Petrodelta provide a basis for a more durable arrangement in Venezuela, the value of the investment necessarily depends upon Venezuela’s maintenance of legal, tax, royalty and contractual stability. Our experiences in Venezuela demonstrate that such stability cannot be assured. While we have and will continue to take measures to mitigate our risks, no assurance can be provided that we will be successful in doing so or that events beyond our control will not adversely affect the value of our minority equity investment in Petrodelta.

PDVSA’s failure to timely pay contractors could have an adverse effect on Petrodelta. PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors, including Harvest Vinccler. As a result, Petrodelta 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 continuing to have an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.

Risks Related to Our Industry

Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This Annual Report on Form 10-K contains estimates of our oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

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The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth. Actual production, revenue, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used, and these variances may be material.

You should not assume that the present value of future net revenues referred to in Item 15. Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Petrodelta S.A., TABLE V – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on the unweighted average price of the first day of the month during the 12-month period before the ending date of the period covered by the reserve report and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in demand, changes in our ability to produce or changes in governmental regulations, policies or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from estimated proved reserves and their present value. In addition, the 10 percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with the oil and natural gas industry in general will affect the accuracy of the 10 percent discount factor.

We may not be able to replace production with new reserves. In general, production rates and remaining reserves from oil and natural gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive and uncertain. We may be unable to make the necessary capital investment to maintain or expand our oil and natural gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot give any assurance that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.

Our future operations and our investments in equity affiliates are subject to numerous risks of oil and natural gas drilling and production activities. Oil and natural gas exploration and development drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is often uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

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The prevailing price of oil also affects the cost of and availability for drilling rigs, production equipment and related services. We cannot give any assurance that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs.

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

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

Our oil and natural gas operations are subject to various governmental regulations that materially affect our operations. Our oil and natural gas operations are subject to various governmental regulations. These regulations may be changed in response to economic or political conditions. Matters regulated may include permits for discharges of wastewaters and other substances generated in connection with drilling operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on oil and natural gas production. In order to conserve or limit supplies of oil and natural gas, these agencies have restricted the rates of the flow of oil and natural gas wells below actual production capacity. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Exploration and development and the production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

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

The oil and gas business involves many operating risks that can cause substantial losses, and insurance may not protect us against all of these risks. We are not insured against all risks. Our oil and gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the risk of:

If any of these events occur, we could incur substantial losses as a result of:

If we experience any of these problems, our ability to conduct operations could be adversely affected.

We maintain insurance against some, but not all, of these potential risks and losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not insurable.

Competition within the industry may adversely affect our operations. We operate in a highly competitive environment. We compete with major, national and independent oil and natural gas companies for

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the acquisition of desirable oil and natural gas properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours.

The loss of key personnel could adversely affect our ability to successfully execute our strategy. We are a small organization and depend on the skills and experience of a few individuals in key management and operating positions to execute our business strategy. Loss of one or more key individuals in the organization could hamper or delay achieving our strategy.

Tax claims by municipalities in Venezuela may adversely affect Harvest Vinccler’s financial condition. The municipalities of Uracoa and Libertador have asserted numerous tax claims against Harvest Vinccler which we believe are without merit. However, the reliability of Venezuela’s judicial system is a source of concern and it can be subject to local and political influences.

Potential regulations regarding climate change could alter the way we conduct our business. Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that requires reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of oil, gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change and the Kyoto Protocol address greenhouse gas emissions, and several countries including the European Union have established greenhouse gas regulatory systems. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and gas that we produce and as a result, negatively impact our financial condition, results of operations and cash flows.

Our business is dependent upon the proper functioning of our internal business processes and information systems and modification or interruption of such systems may disrupt our business, processes and internal controls. The proper functioning of our internal business processes and information systems is critical to the efficient operation and management of our business. If these information technology systems fail or are interrupted, our operations may be adversely affected and operating results could be harmed. Our business processes and information systems need to be sufficiently scalable to support the future growth of our business and may require modifications or upgrades that expose us to a number of operational risks. Our information technology systems, and those of third party providers, may also be vulnerable to damage or disruption caused by circumstances beyond our control. These include catastrophic events, power anomalies or outages, natural disasters, computer system or network failures, viruses or malware, physical or electronic break-ins, unauthorized access and cyber attacks. Any material disruption, malfunction or similar challenges with our business processes or information systems, or disruptions or challenges relating to the transition to new processes, systems or providers, could have a material adverse effect on our financial condition, results of operations and cash flows.

Risks Related to the Sale of Our Venezuelan Interests

There is no assurance that the sale of our remaining Venezuelan interests under the Share Purchase Agreement will be completed, and our inability to consummate the proposed sale could harm the market price of our common stock and our business, results of operations and financial condition. If our stockholders fail to authorize the proposed sale of our remaining Venezuelan interests, or if the proposed sale is not completed for any other reason, the market price of our common stock may decline. In addition, failure to complete the proposed sale will result in a reduction in the amount of cash otherwise available to us and, given that we do not currently have any operating cash flow, may substantially limit our ability to implement our business strategy.

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We cannot assure you that the proposed sale of our remaining Venezuelan interests will be consummated. The consummation of the proposed sale is subject to the satisfaction or waiver of a number of conditions, including, among others, the requirement that we obtain stockholder approval of the proposed sale, the requirement that we obtain approval of the proposed sale from the Government of Venezuela, requirements with respect to the accuracy of the representations and warranties of the parties to the Share Purchase Agreement and requirements with respect to the satisfaction or waiver of the covenants and obligations of the parties to the Share Purchase Agreement. In addition, the Share Purchase Agreement may be terminated in certain circumstances under the terms of the Share Purchase Agreement.

We cannot guarantee that the parties to the Share Purchase Agreement will be able to meet all of the second closing conditions. If we are unable to meet all of the second closing conditions, Petroandina would not be obligated to close the proposed sale of our remaining Venezuelan interests. We also cannot be sure that circumstances, such as a material adverse effect, will not arise that would also allow Petroandina to terminate the Share Purchase Agreement before the second closing. If the proposed sale is not approved by our stockholders or does not close for another reason, our Board of Directors will be forced to evaluate other alternatives, which may be less favorable to us than the current proposed sale.

If the Share Purchase Agreement is terminated:

In any case where we would be required to repurchase the Petroandina’s 29 percent interest in Harvest Holding, we would not necessarily have sufficient funds to pay for the shares that we are required to repurchase,

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and, given that we do not currently have any operating cash flow, we may need additional funds for the sole purpose of purchasing Petroandina’s 29 percent interest in Harvest Holding which would require us to raise additional capital through equity or debt sales.

In addition, if the proposed sale of our remaining Venezuelan interests is not consummated, our directors, executive officers and other employees will have expended extensive time and effort during the pendency of the sale and we will have incurred significant transaction costs, in each case, without any commensurate benefit.

We are required to obtain the approval of the sale of our Venezuelan interests from the Ministerio del Poder Popular de Petroleo y Mineria representing the Government of Venezuela. There can be no assurances that we will be able to obtain this approval, or that we will be able to obtain this approval on terms reasonably satisfactory to us and Pluspetrol. If this approval is not obtained, then the Share Purchase Agreement may be terminated.

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

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

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

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

There is no guarantee that you will receive any of the net cash proceeds from the proposed sale of our remaining Venezuelan interests in the form of dividends, and we could spend or invest the net cash proceeds from the proposed sale in ways in which our stockholders may not agree. The purchase price for the sale of our interests in Venezuela will be paid directly to us. After the payment of expenses related to the proposed sale (including taxes) and reservation of some of the proceeds for operating costs and contingent liabilities, any use of the remaining proceeds will be at the discretion of our Board of Directors and based on its determination of what is in the best interests of the Company and its stockholders at the time of determination. Our Board of Directors could decide that we should use all or a significant portion of the net cash proceeds from the sale for purposes other than paying dividends, including continuing the Company’s business.

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None.

We have regional office in Singapore and field offices in Jakarta, Indonesia and Port Gentil, Gabon to support field operations in those areas. At December 31, 2013, we had the following lease commitments for office space:

See Item 1. Business, Operations for a description of our oil and gas properties.

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 has filed a motion to dismiss and 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.

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 $1.4 million, $1.0 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 to dismiss the claim because the claim had not been filed against the proper parties to the claim. On March 19, 2013, the claimant filed an appeal against the judgment. We dispute the claim and plan to vigorously defend against it.

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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, Harvest US must indemnify 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.

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. Until that application is approved, the funds will remain in the blocked account, and we can give no assurance when OFAC will permit the funds to be released. 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. On October 29, 2013, we learned that the court administratively closed the case. The case was recently reopened as a result of the Circuit Court of Appeals’ ruling against Plaintiffs’ discovery request. We dispute Plaintiffs’ claims and plan to vigorously defend against them.

Uracoa Municipality Tax Assessments. Harvest Vinccler S.C.A., a subsidiary of Harvest Holding (“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:

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Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions based on the interpretation of the tax code by SENIAT (the Venezuelan income tax authority), as it applies to operating service agreements, Harvest Holding 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. 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 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. Harvest Vinccler has not received official notification of the decision. Harvest Vinccler is unable to predict the effect of this decision on the remaining outstanding municipality claims and assessments.

On February 21, 2014, Tecnica Vial and Flamingo, our partners in Colombia on Blocks VSM14 and VSM15, respectively, filed for arbitration of claims related to the farmout agreements for each block. We had received notices of default from our partners for failing to comply with certain terms of the farmout agreements, followed by notices of termination on November 27, 2013. We determined that it was appropriate to fully impair the costs associated with these interests, and we recorded an impairment charge of $3.2 million during the year ended December 31, 2013 which includes an accrual of $2 million related to this matter. We intend to vigorously defend the arbitration.

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

Not applicable.

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PART II

Price Range of Common Stock and Dividend Policy

Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HNR”. As of December 31, 2013, there were 42,114,346 shares of common stock outstanding, with approximately 424 stockholders of record. The following table sets forth the high and low sales prices for our Common Stock reported by the NYSE.

On March 7, 2014, the last sales price for the common stock as reported by the NYSE was $4.18 per share.

Historically, our policy has been to retain earnings to support the growth of our business, and accordingly, our Board of Directors has never declared a cash dividend on our common stock. However, should the sale of our remaining interests in Venezuela be completed, a substantial portion of our assets would be cash proceeds from such sale, and our Board of Directors would evaluate alternative uses of the cash proceeds, including a possible distribution to the Company’s stockholders. See Part 1. Item 1. Business, Business Strategy for further discussion.

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Stock Performance Graph

The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2013, assuming an investment of $100 on December 31, 2008 in each of Harvest’s common stock, the Dow Jones U.S. Exploration & Production Index and the S&P Composite 500 Stock Index.

This graph assumes that the value of the investment in Harvest stock and each index was $100 at December 31, 2008 and that all dividends were reinvested.

PLOT POINTS

(December 31 of each year)

Total Return Data provided by S&P’s Institutional Market Services, Dow Jones & Company, Inc. is composed of companies that are classified as domestic oil companies under Standard Industrial Classification codes (1300-1399, 2900-2949, 5170-5179 and 5980-5989). The Dow Jones US Exploration & Production Index is accessible at http://www.djindexes.com/mdsidx/index.cfm?event=showTotalMarket.

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SELECTED CONSOLIDATED FINANCIAL DATA

The following tables set forth our selected consolidated financial data for each of the years in the five-year period ended December 31, 2013.

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Operations

We had a net loss attributable to Harvest of $(89.1) million, or $(2.25) per diluted share, for the year ended December 31, 2013 compared to a net loss attributable to Harvest of $(12.2) million, or $(0.33) per diluted share, for the year ended December 31, 2012. Net loss attributable to Harvest for the year ended December 31, 2013 includes $15.2 million of exploration expense, $0.6 million of impairment expense, $3.5 million of unrealized gain on warrant derivatives, $23.0 million of loss on sale of interest in affiliate, $73.1 of income tax expense (including $89.9 million of accrued income tax expense related to previously unrecognized income tax on undistributed earnings for foreign subsidiaries), net equity income from Petrodelta’s operations of $72.6 million and a loss from discontinued operations of $(5.2) million. Net loss attributable to Harvest for the year ended December 31, 2012 includes $8.8 million of exploration expense, $2.9 million of impairment expense, $0.7 million of dry hole costs, net equity income from Petrodelta’s operations of $67.8 million and a loss from discontinued operations of $(14.4) million.

Petrodelta

See Item 1. Business, Share Purchase Agreement and Operations, Petrodelta.

Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Petrodelta’s 2013 approved capital budget was $210 million and included a drilling program to use five drilling rigs for both development and appraisal wells to maintain production capacity. Actual capital expenditures were $269.2 million in 2013 or 28 percent over the approved budget due to cost overruns and inefficiencies.

Petrodelta began 2013 with three drilling rigs and two workover rigs and projects in progress to enhance the infrastructure in the El Salto and Temblador fields and to construct a pipeline between the Isleño field and the main production facility at Uracoa. Currently, Petrodelta is operating six drilling rigs and one workover rig and is continuing the construction on the infrastructure enhancements in the El Salto and Temblador fields. Construction of the pipeline between the Isleño field and the main production facility at Uracoa was completed in March 2013.

During the year ended December 31, 2013, Petrodelta drilled and completed 13 development wells compared to 12 development wells in the year ended December 31, 2012. Petrodelta delivered approximately 14.5 MBls of oil and 2.6 Bcf of natural gas, averaging 41,014 BOE per day during the year ended December 31, 2013 compared to deliveries of 13.2 MBls of oil and 2.2 Bcf of natural gas, averaging 36,979 BOE per day during the year ended December 31, 2012.

Petrodelta’s Proved reserves, net to our 20.4 percent interest, are 20.7 MMBOE at December 31, 2013. Petrodelta’s Probable reserves, net to our 20.4 percent interest, are 41.5 MMBOE at December 31, 2013. Petrodelta’s Possible reserves, net to our 20.4 percent interest, are 62.9 MMBOE. Proved plus Probable reserves at 62.2 MMBOE, after accounting for the reduction in our interest from 32.0 percent to 20.4 percent, are virtually unchanged from last year. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies – Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve estimates.

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Certain operating statistics for the years ended December 31, 2013, 2012 and 2011 for the Petrodelta fields operated by Petrodelta are set forth below. This information is provided at 100 percent.

Sales Contract

Under Petrodelta’s Sales 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 PDVSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make payment to Petrodelta in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered. Natural gas deliveries are paid in Bolivars, but the pricing for natural gas is referenced to the U.S. Dollar.

Beginning in October 2011, MENPET determined that Petrodelta’s production flowing through the COMOR transfer point which comes from the El Salto field was a heavier type of crude, Boscan. The official pricing formula applied to Boscan by MENPET is used for the sales of Petrodelta crude oil with quality close to 10 degrees API to represent actual quality delivered. PPSA and Petrodelta are in the process of amending the contract to provide pricing under both the Merey 16 and Boscan pricing formulas. Once the Sales Contract is executed, PPSA will be invoiced for the deliveries. As of December 31, 2013, $756.7 million ($352.7 million in 2012) for El Salto remain uninvoiced to PPSA pending execution of the amendment.

Payments to Contractors

In Item 1A. Risk Factors, we disclosed that PDVSA’s failure to timely pay contractors, including Petrodelta, was having an adverse effect on Petrodelta. We have advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, operations and seismic interpretation, and employee salaries and related benefits for Harvest employees seconded into Petrodelta. Currently, we have three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. We are considered a contractor to Petrodelta, and as such, we are also experiencing the slow payment of invoices. As of December 31, 2013, we had $2.9 million outstanding for unpaid advances to Petrodelta for continuing operations costs. Although payment is slow, payments continue to be received. Petrodelta and Petrodelta’s board have not indicated that the advances are not payable, nor that they will not be paid. At December 31, 2013, has reflected all of the $2.9 million of the Advances to Affiliate as a long-term receivable due to slow payment and age of the advances.

We are unable to provide an indication of when PDVSA will become and remain current in its payment obligations. However, we believe that PDVSA’s debt will not disappear completely in the short term, but the risk of contractor work stoppage is minimal due to PDVSA guaranteeing payments as publicly stated by top officials. Increased costs due to PDVSA’s debt financing are already imbedded in current contractor’s rates.

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In the past, there has been insufficient monetary support and contractual adherence by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2014 budget. Should PDVSA continue in insufficient monetary support and contractual adherence of Petrodelta, underinvestment in the development plan may lead to continued under-performance. The 2014 budget proposal has not been reviewed by Petrodelta’s board yet.

Windfall Profits Tax

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 which established new levels for contribution 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. See Item 15. Exhibits and Financial Statement Schedules, Notes to the Consolidated Financial Statements (“Notes to Consolidated Financial Statements”), Note 6 – Investment in Equity Affiliates for further discussion of the Windfall Profits Tax rates. Windfall Profits Tax is deductible for Venezuelan income tax purposes.

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 have to be considered and approved on a case by case basis by MENPET. 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. PDVSA issued to Petrodelta its share of the exemption credit for 2012 of $55.2 million ($36.4 million net of tax) ($11.3 million net to our 20.4 percent interest, $7.4 million net of tax net to our 20.4 percent interest) based on PDVSA’s calculation and projects PDVSA deemed to qualify for the exemption. Petrodelta has not 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.

Royalty Cap

Royalties are paid at 33.33 percent with the 30 percent royalty paid in-kind and the 3.33 percent royalty paid in cash. The amended Windfall Profits Tax states that royalties paid to Venezuela are capped at $80 per barrel ($70 per barrel in 2012). The law does not specify whether the cap on royalties is 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). Per our interpretation of the Windfall Profits Tax law and as required under U.S. GAAP, the $80 cap on royalty barrels should only be applied to the 3.33 percent royalty which Petrodelta pays in cash. The revenues and royalties in Results of Operations, Earnings from Equity Affiliates, have been adjusted to report royalties paid in-kind at the oil price applicable for the period. While both methods of reporting result in the same amount being reported for net sales, our method results in prices per barrel of oil which are consistent with the prices expected under the Sales Contract. See Notes to Consolidated Financial Statements, Note 6 – Investment in Equity Affiliates for further discussion of the amounts reported for royalties.

Sports Law

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. Per the Sports Law,

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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 resulting in an overstatement of the liability. We have adjusted for the over-accrual of the Sports Law in the years ended December 31, 2013 and 2012 Earnings from Equity Affiliate. As of December 31, 2013, the cumulative amount of this adjustment is $1.3 million ($0.3 million net to our 20.4 percent interest).

Functional Currency

Petrodelta’s functional and reporting currency is the U.S. Dollar. It has currency exchange risk from fluctuations of the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”). 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, current and deferred income tax and other tax obligations and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. The official prevailing currency exchange rate was increased from 4.3 Bolivars per U.S. Dollar to 6.3 Bolivars per U.S. Dollar in February 2013. Petrodelta reflected a gain of approximately $169.6 million on revaluation of its non-income tax related assets and liabilities during the year ended December 31, 2013 primarily related to the February 2013 devaluation.

As a result of legislation enacted in December 2013 and January and February of 2014, Venezuela now has a multiple exchange rate system. Most of Petrodelta’s transactions are subject to a fixed official exchange rate of 6.3. In addition, there is a variable official exchange rate system in which the exchange rate is determined through auctions (11.3 rate as of December 31, 2013). The third system is not yet available as the government has not yet specified the scope of application and mechanics. The financial information is prepared using the official fixed exchange rate (6.3 from February 2013 through December 2013). At December 31, 2013, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 1,011 million Bolivars and 6,683 million Bolivars, respectively.

Petrodelta’s results were also impacted by PDVSA changing its policy with respect to invoicing for disbursements made in Bolivars on behalf of Petrodelta to require that such invoices be denominated in U.S. dollars rather than Bolivars. This change was implemented in the fourth quarter of 2013 with retroactive application to certain transactions occurring in 2011 and thereafter. As a result of this change, Petrodelta recorded a $14.2 million foreign currency loss in the three months ended December 31, 2013.

Collective Labor Agreement

On February 11, 2014, the Collective Labor Agreement for the period from October 1, 2013 thru October 1, 2015, between the employees of the oil industry represented by the Venezuelan Unitary Federation of workers of the oil, gas, and derivatives (FUTPV) and PDVSA was signed. The Collective Labor Agreement establishes a salary raise and payroll and retirement benefits which has a significant impact on Petrodelta’s payroll cost. The most significant impact is a step increase of salary around 90%, where 59% is to be retroactive from October 1, 2013, then a 23% raise from May 1, 2014 and finally the remaining portion to be adjusted on January 1, 2015.

Dividends

On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance. Petrodelta shareholder approval of the dividend was received on March 14, 2011. Petrodelta had working capital of $253.8 million as of December 31, 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. Petrodelta has consistently earned a profit from 2007 through September 30, 2013; however, dividends of profits since 2010 have not been declared. There is uncertainty with

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respect to the timing of the receipt of the dividend declared in November 2010 or whether future dividends will be declared and/or paid. During the term of the Share Purchase Agreement, Harvest Holding may not pay any dividends to HNR Energia, and therefore would not benefit from any dividends paid by Petrodelta during this period. Should this receivable be paid and subsequently distributed to Harvest Holding’s shareholders prior to the second closing sale to Petroandina, we would not receive any portion of the dividend.

Petrodelta’s results and operating information is more fully described in Notes to the Consolidated Financial Statements, Note 6 – Investment in Equity Affiliates.

Dussafu Project – Gabon

We have a 66.667 percent ownership interest in the Dussafu PSC through two separate acquisitions, and we are the operator. The Dussafu PSC partners and Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources, is in the third exploration phase of the Dussafu PSC which has been extended to May 27, 2016.

During 2011, we drilled our first exploratory well, Dussafu Ruche Marin-1 (“DRM-1”), and two appraisal sidetracks. DRM-1 and sidetracks discovered oil of approximately 149 feet of pay within the Gamba and Middle Dentale Formations. DRM-1 and sidetracks are currently suspended pending further exploration and development activities.

During the fourth quarter of 2012, our second exploration well on the Tortue prospect to target stacked pre-salt Gamba and Dentale reservoirs commenced. DTM-1 was spud on November 19, 2012 in a water depth of 380 feet. On January 4, 2013, we announced that DTM-1 had reached a vertical depth of 11,260 feet within the Dentale Formation. Log evaluation and pressure data indicate that we have an oil discovery of approximately 42 feet of pay in a 72-foot column within the Gamba Formation and 123 feet of pay in stacked reservoirs within the Dentale Formation. The first appraisal sidetrack of DTM-1 (“DTM-1ST1”) was spud in January 12, 2013. DTM-1ST1 was drilled to a total depth of 11,385 feet in the Dentale Formation, approximately 1,800 feet from DTM-1 wellbore and found 65 feet of pay in the primary Dentale reservoir. Work on DTM-1 and DTM-1ST1 was suspended pending future appraisal and development activities.

Geoscience, reservoir engineering and economic studies have progressed and a field development plan is being prepared for a cluster field development of both the Ruche and Tortue discoveries along with existing pre-salt discoveries at Walt Whitman and Moubenga. Following the success in both the pre-salt Gamba and Dentale reservoirs in the two Harvest exploration wells a new 1,130 square kilometer 3D seismic survey commenced in October with the first high quality seismic products expected to be available during the second quarter of 2014. The new 3D seismic data was extended to be acquired over the two Harvest discoveries and should also enhance the placement of future development wells in the Ruche and Tortue development program. We continue to evaluate our prospects, but we have not drilled any additional wells.

During the year ended December 31, 2013, we had cash capital expenditures of $42.5 million for well costs ($11.7 million for well costs during the year ended December 31, 2012). The 2014 budget for the Dussafu PSC is $7.4 million. See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon for further information on the Dussafu Project.

Budong-Budong Project, Indonesia

See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia.

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, 2017. 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.

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In December 2012, we signed a farmout agreement with the operator of the Budong PSC to acquire an additional 7.1 percent participating interest and to become operator of the Budong PSC. We assumed the role of interim operator effective January 16, 2013. Closing of this acquisition will increase our participating ownership interest in the Budong PSC to 71.5 percent with our cost sharing interest becoming 72 percent until first commercial production. The consideration for this transaction is that we will fund 100 percent of the costs of the first exploration well of the four-year extension to the Budong PSC. If we do not drill an exploration well before October 2014, our partner has the right to give us notice that the consideration for the additional 7.1 percent participating interest must be paid in cash for $3.2 million.

Operational activities during the year ended December 31, 2013 included continued work on an exploration program targeting the Pliocene and Miocene targets encountered in the two exploratory wells drilled in 2011. 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.

We are actively discussing the sale of our interests in Budong, and based on indications of interest received in December 2013, we determined that is it was appropriate to recognize and impairment expense of $0.6 million and a charge included in general and administrative expenses related to a valuation allowance on VAT we do not expect to recover of $2.8 million.

During the year ended December 31, 2013, we had cash capital expenditures of $0.2 million ($5.8 million during the year ended December 31, 2012) for deepening and plugging and abandonment costs. The 2014 budget for the Budong PSC is $1.0 million.

WAB-21 Project – China

In March 2011, CNOOC granted us an extension to May 2013 of Phase One of the Exploration Period for the WAB-21 contract area. The Joint Management Committee has approved an extension of the license until May 31, 2015. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes with Vietnam persist. Even though there continues to be increasing activity on the Vietnamese blocks which we believe confirms our view of WAB-21’s prospectivity, we impaired the carrying value of WAB-21 of $2.9 million at December 31, 2012 due to our continued inability to pursue an exploration program. However, we continue to seek permission to acquire regional 2-D seismic and localized 3-D seismic.

Operational activities during 2013 include costs related to maintenance of the license. The 2014 budget for WAB 21 is minimal, consisting of costs required to maintain the license. See Item 1. Business, Operations, WAB-21, South China Sea for further information on the WAB-21 Project.

Colombia – Discontinued Operations

In February 2013, we signed farmout agreements on Block VSM14 and Block VSM15 in Colombia. Under the terms of the farm-out agreements, we had a 75 percent beneficial working interest and our partners had a 25 percent carried interest for the minimum exploratory work commitments on each block. We requested the legal assignment of the interest by the Agencia Nacional de Hidrocarburos (“ANH”), Colombia’s oil and gas regulatory authority, and approval of us as operator.

For both blocks, phase one of the contract began on December 15, 2012 and expires on December 15, 2015. We have received notices of default from our partners for failing to comply with certain terms of the farmout agreements for Block VSM 14 and Block VSM 15, followed by notices of termination on November 27, 2013. As discussed further in “Item 3. Legal Proceedings”, our partners have filed for arbitration of claims related to these agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests, and we recorded an impairment charge of $3.2 million during the year ended December 31, 2013. As we no longer have any interests in Colombia, we have reflected the results in

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discontinued operations. During the year ended December 31, 2013 we had capital expenditures of $1.2 million for leasehold acquisition costs. See Item 1. Business, Operations, Colombia for further information on this project.

Block 64 EPSA Project – Oman – Discontinued Operations

On March 12, 2013, we elected to not request an extension of the First Phase or enter the Second Phase of Block 64 EPSA. The carrying value of Block 64 EPSA of $6.4 million was considered to be impaired and a related impairment expense was recorded during the year ended December 31, 2012. During the first half of 2013, Block 64 was relinquished effective May 23, 2013 and we terminated our operations and closed the field office. Our activities in Oman have been reflected as discontinued operations in our financial statements. See Item 1. Business, Operations, Block 64 EPSA, Oman for further information on the Block 64 EPSA Project.

Business Strategy

In Item 1. Business and Item 1A. Risk Factors, we discuss the situation in Venezuela and how the actions of the Venezuelan government have and continue to adversely affect our operations. The expectation that dividends from Petrodelta will be minimal over the next few years has restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere. Upon consideration of these and other factors, on December 16, 2013, Harvest and HNR Energia entered into the Share Purchase Agreement with Petroandina and Pluspetrol to sell all of our 80 percent equity interest in Harvest Holding to Petroandina in two closings for an aggregate cash purchase price of $400 million. The first closing occurred on December 16, 2013 contemporaneously with the signing of the Share Purchase Agreement, when we sold a 29 percent equity interest in Harvest Holding for $125 million. The second closing, for the sale of a 51 percent equity interest in Harvest Holding for a cash purchase price of $275 million, will be subject to, among other things, approval by the holders of a majority of our common stock and approval by the Ministerio del Poder Popular de Petroleo y Mineria representing the Government of Venezuela (which indirectly owns the other 60 percent interest in Petrodelta). See Item 1. Business, Share Purchase Agreement.

We are currently marketing our non-Venezuelan assets and talking to potential buyers, and we intend to continue our consideration of a possible sale for some or all of our non-Venezuelan assets if we are able to negotiate a sale or sales in transactions that our Board of Directors believes are in the best interests of the Company and its stockholders. In the meantime, we intend to operate our business in the ordinary course and may ultimately decide to keep our non-Venezuelan assets and acquire additional assets. See Item 1. Business,Business Strategy for further discussion on how we plan to operate the business in the near term.

Results of Operations

The following discussion on results of operations for each of the years in the three-year period ended December 31, 2013 should be read in conjunction with our consolidated financial statements and related notes thereto.

Years Ended December 31, 2013 and 2012

We reported a net loss attributable to Harvest of $(89.1) million, or $(2.25) diluted earnings per share, for the year ended December 31, 2013, compared with a net loss attributable to Harvest of $(12.2) million, or $(0.33) diluted earnings per share, for the year ended December 31, 2012.

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Loss From Continuing Operations

Expenses and other non-operating (income) expense from continuing operations (in thousands) were:

Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2013, we incurred $13.7 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations and $1.5 million related to other general business development activities. During the year ended December 31, 2012, we incurred $4.5 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations, $2.5 million related to other general business development activities, and $1.8 million related to lease maintenance.

During the year ended December 31, 2013, we impaired $0.6 million related to our Budong project in Indonesia. During the year ended December 31, 2012, we impaired $2.9 million related to the carrying value of WAB-21.

During the year ended December 31, 2013, we did not record any dry hole costs. During the year ended December 31, 2012, we expensed to dry hole costs $0.7 million related to the drilling of the KD-1 well on the Budong PSC.

The increase in general and administrative costs in the year ended December 31, 2013 from the year ended December 31, 2012, was primarily due to higher professional fees and contract services ($1.2 million), general operations and overhead $2.5 million and restructuring costs ($3.0 million), offset by lower employee related costs ($3.3 million).

The unrealized gain on derivatives in the year ended December 31, 2013 as compared to an unrealized loss for the year ended December 31, 2012 was due to a reduction in the estimated fair value for our warrant derivative liability. As discussed further in Notes to Consolidated Financial Statements, Note 8 – Warrant Derivative Liabilities, the decrease in value reflects the impact of the increased likelihood of an event which would trigger certain early settlement provisions.

The increase in interest expense in the year ended December 31, 2013 from the year ended December 31, 2012 was due to higher average principal balance outstanding during the period ($79.8 million during 2013 and $24.6 million during 2012) and higher interest rate on the debt outstanding during the year ended December 31, 2013 (11 percent) than the year ended December 31, 2012 (8.25 percent through mid-October 2012 and 11 percent thereafter) offset by interest capitalized to oil and gas properties in the year ended December 31, 2013 of $8.3 million (year ended December 31, 2012: $3.0 million).

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During the year ended December 31, 2012, we incurred debt conversion expense of $2.9 million related to the issuance of 0.4 million common shares issued as an inducement for completing the exchange and legal and other professional fees ($0.7 million).

During the year ended December 31, 2012, we incurred a loss on extinguishment of debt of $5.4 million related to the early conversion of our 8.25 percent senior convertible notes. The loss on extinguishment of debt includes the difference between the carrying value of the 8.25 percent senior convertible notes and the amount received for the 11 percent senior unsecured notes ($5.0 million), expensing of deferred financing costs related to the 8.25 percent senior convertible notes ($0.1 million) and issuance of 30,000 shares of Harvest common stock issued in exchange for a waiver agreement ($0.3 million).

The $0.8 million loss on exchange rates for the year ended December 31, 2013 was primarily related to revaluation of the VAT receivable as compared to the nominal loss on exchange rates of $0.1 million for the year ended December 31, 2012.

The decrease in other non-operating expense in the year ended December 31, 2013 from the year ended December 31, 2012 was due to higher costs incurred in 2012 related to our strategic alternative process and evaluation.

We had income tax expense in the year ended December 31, 2013 of $73.1 million as compared to an income tax benefit of $(0.6) million in the year ended December 31, 2012. The income tax expense in 2013 included $89.9 million of accrued income tax related to previously unrecognized income tax on undistributed earnings for foreign subsidiaries (which were considered permanently invested in previous periods), $2.1 million of expense related to the sale of the interest in Harvest Holding offset by the benefit of $(8.8) million from the reversal of valuation allowances, the benefit from current year losses and a benefit of $(2.2) million from the favorable resolution of certain tax contingencies. The income tax benefit in the year ended December 31, 2012 is attributable to the benefit from net operating losses.

Earnings from Equity Affiliates

Revenues were higher in the year ended December 31, 2013 compared to the year ended December 31, 2012 due to increases in sales volumes resulting from running a six drilling rig program offset by lower world crude oil prices.

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

For the year ended December 31, 2013 compared to the year ended December 31, 2012, royalties, which is a function of revenue, increased due to the increase in revenues discussed above (net increase in revenue of $63.5 million at 30 percent royalty). The increase in operating expense is due to increased oil production as well as operating inefficiencies. Workover expense is higher for the year ended December 31, 2013 than the year ended December 31, 2012 due to running between one and two workovers rigs in 2013 versus one workover rig in 2012. Windfall Profits Tax, which is a function of volume and price received per barrel as well as pricing levels set for determining Windfall Profits Tax, decreased due to an increase in the pricing levels under 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 earnings from unconsolidated equity affiliate) for the year ended December 31, 2013 was higher than the effective tax rate for the year ended December 31, 2012 primarily because the foreign currency transaction gain is not included in taxable income.

Net Income Attributable to Noncontrolling Interests

Net income attributable to noncontrolling interests is attributable to Vinccler’s 20 percent equity interest in Harvest Holding. Beginning December 16, 2013 it is also attributable to Petroandina’s 29 percent equity interest in Harvest Holding. Earnings for Harvest Holding are primarily attributable to Petrodelta, and the decrease in net income attributable to noncontrolling interests from $13.4 million for the year ended December 31, 2012 to $11.6 million for the year ended December 31, 2013 is primarily a result of lower earnings from Petrodelta during the period in which the noncontrolling interest increased from 20 percent to 49 percent.

Discontinued Operations

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”) A1 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. We have no continuing involvement in Oman. The loss from discontinued operations for Oman of $(0.7) million for the year ended December 31, 2013 included $0.5 million of general and administrative expenses. The loss from discontinued operations for Oman of $(12.7) million for the year ended December 31, 2012 included $6.4 million related impairment expense, $4.9 million related to dry hole costs and $1.1 million of general and administrative expenses.

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We have received notices of default from our partners for failing to comply with certain terms of the farmout agreements for Block VSM 14 and Block VSM 15 in Colombia, followed by notices of termination on November 27, 2013. As discussed further in “Item 3. Legal Proceedings”, our partners have filed for arbitration of claims related to these agreements. We have accrued $2.0 million as of December 31, 2013 related to obligations under the farmout agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests, and we recorded an impairment charge of $3.2 million during the year ended December 31, 2013. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations.

On May 17, 2011, we closed the transaction to sell the Antelope Project. The sale had an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale was reported in discontinued operations in the second quarter of 2011. During the year ended December 31, 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 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. There were no revenues applicable to discontinued operations during the years ended December 31, 2013 and 2012. Income (loss) from discontinued operations was:

Years Ended December 31, 2012 and 2011

We reported a net loss attributable to Harvest of $(12.2) million, or $(0.33) diluted earnings per share, for the year ended December 31, 2012, compared with net income attributable to Harvest of $56.0 million, or $1.64 diluted earnings per share, for the year ended December 31, 2011.

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Loss from Continuing Operations

Expenses and other non-operating (income) expense from continuing operations (in thousands) were:

Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2012, we incurred $4.5 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations, $2.5 million related to other general business development activities, and $1.8 million related to lease maintenance. During the year ended December 31, 2011, we incurred $9.5 million of exploration costs for the acquisition, processing and reprocessing of seismic data related to ongoing operations, $0.3 million related to other general business development activities, and $2.2 million related to lease maintenance.

During the year ended December 31, 2012, we impaired $2.9 million related to the carrying value of WAB-21. During the year ended December 31, 2011, we impaired $3.3 million related to the carrying value of West Bay.

During the year ended December 31, 2012, we expensed to dry hole costs $0.7 million related to the drilling of the KD-1 well on the Budong. During the year ended December 31, 2011, we expensed to dry hole costs $14.0 million related to the drilling of the LG-1 on Budong PSC and $26.0 million related to the drilling of the KD-1 and KD-1ST on the Budong PSC. See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia –Drilling and Development Activity.

The increase in general and administrative costs in the year ended December 31, 2012 from the year ended December 31, 2011, was primarily due to increases in employee related costs ($3.3 million, of which $2.2 million was non-cash related to equity compensation), public relations ($0.1 million) and audit fees ($2.0 million) offset by a decrease in general office expense and overhead ($0.4 million), contract services ($0.4 million) and travel costs ($0.2 million).

The decrease in investment earnings and other in the year ended December 31, 2012 from the year ended December 31, 2011 was due to the receipt during the year ended December 31, 2011 of payment for transition services provided on the Antelope Project after closing of the sale.

The decrease in unrealized gain (loss) on derivatives in the year ended December 31, 2012 from the year ended December 31, 2011 was due to the change in fair value for our warrant derivative liabilities: $3.18 per warrant at December 31, 2012 and $3.04 per warrant at December 31, 2011.

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The decrease in interest expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to the conversion of $31.5 million of our 8.25 percent senior convertible notes in the year ended December 31, 2012, offset by our $79.8 million senior unsecure note offering in October 2012, repayment in May 2011 of our $60 million term loan facility, and interest capitalized to oil and gas properties of $3.0 million.

As discussed under Years Ended December 31, 2013 and 2012 above, during the year ended December 31, 2012, we incurred debt conversion expense of $2.9 million related to the issuance of 0.4 million common shares issued as an inducement for completing the exchange and legal and other professional fees ($0.7 million), and we incurred a loss on extinguishment of debt of $5.4 million related to the early conversion of our 8.25 percent senior convertible notes. During the year ended December 31, 2011, we incurred a loss on extinguishment of debt related to early payment of our $60 million term loan facility. The loss on extinguishment of debt includes the write off of the discount on debt ($10.6 million), prepayment premium of 3.5 percent of the amount outstanding ($2.1 million), expensing of financing costs related to the term loan facility ($0.4 million), and the cost to redeem 4.4 million unvested warrants issued in connection with the term loan facility.

The foreign currency transaction losses for the year ended December 31, 2012 were consistent with the year ended December 31, 2011.

The increase in other non-operating expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to costs incurred related to our strategic alternative process and evaluation.

The change in income tax expense in the year ended December 31, 2012 from the year ended December 31, 2011 is due to a net operating loss incurred in 2012 while we had taxable income in 2011 as a result of the sale of interest in the Antelope Project.

Earnings from Equity Affiliates

For the year ended December 31, 2012, revenue from oil sales due to higher sales volumes ($170.9 million) offset by lower prices ($29.8 million).

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

Royalties, which is a function of revenue, increased $48.9 million due to the increase in revenue (net increase in revenue of $141.2 million at 30 percent royalty). Windfall Profits Tax, which is a function of volume and price received per barrel, increased $53.7 million due to an increase in volumes (13.2 MBls in 2012 vs. 11.4 MBls in 2011) offset by lower price received per barrel ($95.91 per barrel in 2012 vs. $98.52 per barrel in 2011). The increase in operating expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to increased oil production and also includes $3.8 million of additional expense related to the labor law which was recorded in December 2012. The decrease in workover expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to fewer workovers being performed. Petrodelta’s effective tax rate (inclusive of the adjustments to reconcile to reported earnings from equity affiliate) for the year ended December 31, 2012 was not materially different with the effective tax rate for the year ended December 31, 2011.

Net Income Attributable to Noncontrolling Interests

The decrease in net income attributable to noncontrolling interests from $14.2 million for the year ended December 31, 2011 to $13.4 million for the year ended December 31, 2012 is primarily a result of the decrease in earnings from Petrodelta between the years.

Discontinued Operations

As discussed under Years Ended December 31, 2013 and 2012, Discontinued Operations above, the Oman operations and the Antelope Project have been classified as discontinued operations. Years Ended December 31, 2013 and 2012, Discontinued Operations above also discusses the losses from our Oman operations and Antelope Project for the year ended December 31, 2012. The loss from discontinued operations for Oman of $(11.4) million for the year ended December 31, 2011 included $9.7 million of dry hole costs and $1.0 million of general and administrative expenses. Income from discontinued operations for the Antelope Project for the year ended December 31, 2011 included $106.0 million gain on the sale of our Antelope Project, $3.8 million for employee severance and special accomplishment bonuses, and $5.7 million of U.S. income tax related to the sale of our Antelope Project. Severance costs for key employees include 58,000 stock appreciation rights (“SAR”) granted at an exercise price of $4.595 per SAR. These SARs are exercisable by the key employee for up to one year after termination.

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Revenues and income (loss) from discontinued operations were:

Risks, Uncertainties, Capital Resources and Liquidity

The following discussion on risks, uncertainties, capital resources and liquidity should be read in conjunction with our consolidated financial statements and related notes thereto.

Liquidity

In the Consolidated Financial Statements and other disclosures in our Annual Report on Form 10-K for 2012 (“2012 Form 10-K”), we discussed certain doubts about our ability to continue as a going concern. At the time we filed our 2012 Form 10-K, we expected that in 2013 we would not generate revenues, we would continue to generate losses from operations, and that our cash flows would not be sufficient to cover our operating expenses. While we believed that we would be able to raise additional capital through issuances of debt and/or equity or through sales of assets, our circumstances at such time raised substantial doubt about our ability to continue to operate as a going concern, and this was disclosed in the notes to the consolidated financial statements and in other disclosures in the 2012 Form 10-K.

As discussed above under Share Purchase Agreement, on December 16, 2013, Harvest and HNR Energia entered into the Share Purchase Agreement with Petroandina and Pluspetrol, its parent, to sell all of our 80 percent equity interest in Harvest Holding to Petroandina in two closings for an aggregate cash purchase price of $400 million. The first closing occurred on December 16, 2013 contemporaneously with the signing of the Share Purchase Agreement, when we sold a 29 percent equity interest in Harvest Holding for $125 million. Proceeds from the December 2013 sale of the 29 percent equity interest in Harvest Holding are expected to be adequate to meet our short-term liquidity requirements. We used a portion of the proceeds to redeem all of our 11% Senior Notes due 2014. The notes were redeemed on January 11, 2014, for $80.0 million, including principal and accrued and unpaid interest. The remaining $45.0 million of the proceeds from the sale have been or will be used to pay costs associated with the sale of our Venezuelan interests, to pay severance costs, to make capital expenditures, to pay taxes related to the sale and for general operating expenses. Those remaining proceeds will also be used to repurchase certain outstanding warrants if our stockholders approve the sale of our remaining Venezuelan interests, and if a “Fundamental Change” is consummated under the terms of those warrants.

We expect that during 2014, our capital needs will be met either from the completion of the sale of our remaining Venezuelan interests, the sale of other non-Venezuelan assets or borrowings available under the Share Purchase Agreement during the period until the second closing. The timing of the second closing, however, is beyond the control of the Company. In addition, depending on the timing of these events, we anticipate using a portion of the proceeds from the second closing to pay for expenses and other costs related to the transaction, which we estimate will be approximately $4 million; to pay taxes related to the transaction, which we estimate will be approximately $51.1 million; and if we do not sell our non-Venezuelan assets before the second closing,

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then we estimate that we will need to retain approximately $30 million to fund projected general operating expenses and capital expenditures from April 1, 2014 through December 31, 2014 (to the extent that those general operating expenses are not already reserved from any possible sale of our non-Venezuelan assets).

In addition, 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, farm-downs or possible sales of assets.

The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. In 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.

Accumulated Undistributed Earnings of Foreign Subsidiaries

As of December 31, 2013, the book-tax outside basis difference in our foreign subsidiary resulting from unremitted earnings was approximately $334.8 million. Prior to 2013, no U.S. taxes had been recorded on these earnings as it was our practice and intention to reinvest the earnings of our non-U.S. subsidiaries in those operations.

Under ASC 740-30-25-17, no deferred tax liability must be recorded if sufficient evidence shows that the subsidiary has invested or will invest the undistributed earnings or that the earnings will be remitted in a tax-free manner. Management must consider numerous factors in determining timing and amounts of possible future distribution of these earnings to the parent company and whether a U.S. deferred tax liability should be recorded for these earnings. These factors include the future operating and capital requirements of both the parent company and the subsidiaries, remittance restrictions imposed by foreign governments or financial agreements and tax consequences of the remittance, including possible application of U.S. foreign tax credits and limitations on foreign tax credits that may be imposed by the Internal Revenue Code and regulations.

During the fourth quarter of 2013, management evaluated numerous factors related to the timing and amounts of possible future distribution of these earnings to the parent company, with consideration of the pending sale of the remaining equity interest in Harvest Holding as well as possible sales of other non-U.S. assets. While we will continue to invest the undistributed earnings to the extent possible and operate the Company’s business in the normal course, management is also considering distributions to the Company’s shareholders which could include the distribution of proceeds from the sales of assets by the Company’s foreign subsidiaries to the U.S. parent company resulting in U.S. taxable income. Because management is pursuing various alternatives, a determination was made that it was appropriate to record a deferred tax liability associated with the unremitted earnings of our foreign subsidiaries of $89.9 million in the fourth quarter of 2013. This liability includes $51.1 million which could become payable currently upon the sale of the remaining interest in Harvest Holding and is therefore reflected as a current deferred tax liability.

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Working Capital and Cash Flows

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:

Working Capital

The decrease in working capital of $72.2 million between December 31, 2012 and December 31, 2013 was primarily due to increases in the current portion of long-term debt of $77.5 million and current deferred tax liability of $43.2 million, cash used to fund the loss from operations and interest payments as well as cash payments for capital expenditures offset by net proceeds of $124.0 million from the first closing sale to Petroandina. The current deferred tax liability of $43.2 million and the long-term deferred tax liability of $29.8 million are primarily related to the accrued income tax on undistributed earnings of foreign subsidiaries.

The decrease in working capital of $22.1 million at December 31, 2012 from December 31, 2011 was primarily due to decreases in receivables, increases in cash payments for capital expenditures and accrued expenses and decreases in accounts payable.

Cash Flow from Operating Activities

During the year ended December 31, 2013, net cash used in operating activities was approximately $37.1 million ($26.4 million during the year ended December 31, 2012). The $10.7 million increase in use of cash was primarily due to an increase in exploration expenses, general and administrative costs and interest expense.

Cash Flow from Investing Activities

Our cash capital expenditures for property and equipment are summarized in the following table:

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In addition to cash capital expenditures, during the year ended December 31, 2013, we:

In addition to cash capital expenditures, during the year ended December 31, 2012, we:

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 $8.7 million for 2014, of which $2.2 million is non-discretionary, for U.S., Gabon and Indonesia 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 year ended December 31, 2013, we:

During the year ended December 31, 2012, we:

Contractual Obligations

At December 31, 2013, we had the following lease commitments for office space in Houston, Texas, regional/technical offices in Singapore and field offices in Port Gentil, Gabon and Jakarta, Indonesia that support field operations in those areas.

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