10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

or

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No.: 1-10762

HARVEST NATURAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware	77-0196707
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)
1177 Enclave Parkway, Suite 300 Houston, Texas	77077
(Address of principal executive offices)	(Zip Code)

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

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

Title of each class	Name of each exchange on which registered
Common Stock, $.01 Par Value	NYSE

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   ☒

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  ☒

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  ☒    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  ☒    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.  ☒

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.

Large Accelerated Filer	☐	Accelerated Filer	☒
Non-Accelerated Filer	☐	Smaller Reporting Company	☐

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

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 30, 2015 was: $72,142,875.  

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 23, 2016, shares outstanding:51,415,164.  

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement relating to its 2016 annual meeting of shareholders, or information to be included in an amendment to the Form 10-K, in either case which the Registrant intends will be filed with the Securities and Exchange Commission not later than 120 days after the end of the Registrant’s fiscal year, are incorporated by reference under Part III of this Form 10-K where indicated.  

1

HARVEST NATURAL RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS

		Page
Part I
Item 1.	Business	3
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	20
Item 2.	Properties	20
Item 3.	Legal Proceedings	20
Item 4.	Mine Safety Disclosures	23
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
Item 6.	Selected Financial Data	26
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 8.	Financial Statements and Supplementary Data	44
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	44
Item 9A.	Controls and Procedures	44
Item 9B.	Other Information	45
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	46
Item 11.	Executive Compensation	46
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	46
Item 13.	Certain Relationships and Related Transactions, and Director Independence	46
Item 14.	Principal Accountant Fees and Services	46
Part IV
Item 15.	Exhibits and Financial Statement Schedules	47
Financial Statements			S-4
Signatures		S-59

PART I

Cautionary Notice Regarding Forward-Looking Statements

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; our ability to hire, retain and train management and personnel; and our ability to continue as a going concern. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

2

Item 1.Business

Executive Summary

Harvest Natural Resources, Inc. is a petroleum exploration and production company incorporated under Delaware law in 1988. 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 explorationacreage offshore of the Republic of Gabon (“Gabon”). We operate from our Houston, Texas headquarters. We also have  a regional office in Caracas, Venezuela and a field office in Port-Gentil, Gabon to support operations in those areas.

Our Venezuelan interests are owned through our 51 percent ownership interest in Harvest-Vinccler Dutch Holding B.V., a Dutch private company with limited liability (“Harvest Holding”).  The remaining 49 percent ownership interest of Harvest Holding is owned by Oil & Gas Technology Consultants (Netherlands) Cooperatie U.A. (20 percent) and Petroandina Resources Corporation N.V. ("Petroandina") (29 percent). 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”).  Corporación Venezolana del Petroleo S.A. (“CVP”) and PDVSA Social S.A. owns the remaining 56 percent and 4 percent, respectively, of Petrodelta. Petroleos de Venezuela S.A., the Venezuelan national oil company (“PDVSA”), owns 100 percent of CVP and PDVSA Social S.A.  Thus, we own an indirect 20.4 percent of Petrodelta (51 percent of 40 percent). 

Petrodelta, a Venezuelan mixed company formed in 2007, is our cost investment in eastern Venezuela responsible for the exploration, development, production, gathering, transportation and storage of hydrocarbons in six oil fields.  Petrodelta has 247,113 gross acres (50,411 net acres to our interest) under concessions.  Approximately 88% of the acreage is undeveloped which we believe provides us with substantial opportunities for multi-year development upside through our concession period of October 24, 2027.  Petrodelta is governed by its own charter and bylaws and its shareholders intend that the company be self-funding and rely on internally-generated cash flows. 

For the past several years, we have pursued strategic alternatives regarding our investment in Petrodelta to enhance and realize stockholder value. In 2010, we began searching for possible purchasers of our Petrodelta interest or parties that may wish to enter into strategic transactions with us as a continuing enterprise. In the course of doing this, we reviewed various proposals and engaged in discussions to determine whether any such transaction could be achieved on terms that we believed would be beneficial to our stockholders.  As part of this effort, we negotiated and entered into a transaction agreement with PT Pertamina (Persero) in June 2012 to sell our Venezuelan assets. This agreement was subsequently terminated in February 2013. In December 2013, we entered into a share purchase agreement (the “SPA”) with Petroandina to sell our Venezuelan assets in two stages. We completed the first stage, which consisted of the sale of a 29% interest in Harvest Holding. However, the second stage of the transaction, consisting of the planned sale of our remaining 51% interest in Harvest Holding to Petroandina, was not completed because the Government of Venezuela did not approve the transaction.We subsequently terminated the SPA. We believe that the proposed transaction with PT Pertamina (Persero) and proposed second stage transaction with Petroandina did not succeed because the level of financial support the prospective purchasers offered to Petrodelta to carry on future Petrodelta operations was not sufficient to obtain the approval of the Government of Venezuela.  When the SPA was terminated, a shareholders' agreement (the “Shareholders’ Agreement”) between the Company and Petroandina regarding their ownership shares in Harvest Holding became effective.

On June 19, 2015, after considering several strategic alternatives, the Company and certain of its domestic subsidiaries entered into a securities purchase agreement (the “Purchase Agreement”) with CT Energy Holding SRL (“CT Energy”), a Venezuelan-Italian consortium organized as a Barbados Society with Restricted Liability. Under the Purchase Agreement, CT Energy purchased certain securities of the Company and acquired certain governance rights.  Harvest immediately received gross proceeds of $32.2 million from the sale of the securities, as described below.   Key terms of the transaction include:

· CT Energy acquired a $25.2 million, five year, 15.0% non-convertible senior secured promissory note (“15% Note”).

· CT Energy acquired a $7.0 million, five year, 9.0% convertible senior secured note (the “9% Note”). The 9% Note and accrued interest was converted into 8,667,597 shares of Harvest common stock at a conversion price of $0.82 per share on September 15, 2015.  Immediately after the conversion, CT Energy owned approximately 16.6% of Harvest’s common stock.

· CT Energy acquired a warrant to purchase up to 34,070,820 shares of Harvest's common stock at an initial exercise price of $1.25 per share (the “CT Warrant”). The CT Warrant will become exercisable only after the 30-day volume weighted average price of Harvest's common stock equals or exceeds $2.50 per share (the “Stock Appreciation Date”).

· CT Energy acquired a five-year 15.0% non-convertible senior secured note (the “Additional Draw Note”), under which CT Energy may elect to provide $2.0 million of additional funds to the Company per month for up to six months following the one-year anniversary of the closing date of the transaction (up to $12.0 million in aggregate). The maturity date of the Additional Draw Note will be extended, and the interest rate adjusted, under certain circumstances.

3

· CT Energy was granted certain governance rights in the transaction, including the right to appoint specified directors.  Also, the Company and CT Energia Holding Ltd. (“CT Energia”), a Malta corporation, entered into a Management Agreement (the “Management Agreement”), under which CT Energia and its representatives will manage the day-to-day operations of the Company’s business as it relates to Petrodelta and Venezuela generally.

· Harvest’s stockholders approved all aspects of the transaction subject to stockholder approval at our 2015 annual shareholder meeting, which occurred on September 9, 2015.

See Part IV – Item 15 – Exhibits and Financial Statements Schedules, Note 1 – Organization for further information on the CT Energy transaction.

Through December 31, 2014, we included the results of Petrodelta in our consolidated financial statements using the equity method of accounting. We ceased recording earnings from Petrodelta in the second quarter of 2014 due to the expected sales price in the second closing under the SPA approximating the recorded value of our investment in Petrodelta.  Due to our failed sales attempts, lack of management influence, and actions and inactions by the majority owner, PDVSA, we believe we no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.

We performed animpairment analysis of the carrying value of our investment of Petrodelta as of December 31, 2014.  The estimated fair value of our investment was determined based on the estimated fair value of Petrodelta’s oil and natural gas properties and other net assets as of December 31, 2014, discounted by a factor for economic instability, foreign currency risks and lack of marketability.  Based on this analysis, we recorded a pre-tax impairment charge against the carrying value of our investment in Petrodelta of $355.7 million as of December 31, 2014. 

We also performed an impairment analysis of the carrying value of our investment of Petrodelta as of December 31, 2015 due to the continued decline in world oil prices and deteriorating economic conditions in Venezuela, which have significantly impacted Petrodelta’s operations.  During 2015, Petrodelta’s operating costs exceeded the price realized from the sale of its production due to the significant rate of inflation in Venezuela and the restrictive foreign currency exchange system which Petrodelta is required to operate under.  While we believe that our relationship with CT Energy may allow us to restructure our relationship with PDVSA and Petrodelta and allow us to access the alternative foreign currency systems available to companies in Venezuela, there can be no assurances that we will be successful in these negotiations.  Based on the existing economic environment in which Petrodelta is required to operate, we have concluded that the estimated fair value of our investment in Petrodelta is nil and have recorded a pre-tax impairment charge of $164.7 million to fully impair our investment in Petrodelta as of December 31, 2015. The estimated fair value of our investment was determined based on the estimated fair value of Petrodelta’s oil and natural gas properties and other net liabilities as of December 31, 2015, which exceeded the estimated fair value of the oil and natural gas properties.

We have a 66.667 percent ownership interest in the Dussafu Production Sharing Contract (“Dussafu PSC”) and we are the operator.  The Dussafu PSC, which is located offshore Gabon, covers an area of 680,000 acres with water depths up to 1,650 feet.In December 2014, the Company recorded a $50.3 million impairment related to the unproved costs of the Dussafu PSC based on a qualitative analysis which considered our current liquidity needs, our inability to attract additional capital and the decrease in oil and natural gas prices.  In December 2015, the Company reassessed the carrying value of the unproved costs related to the Dussafu PSC and recorded an additional impairment of $23.2 million based on its analysis of the value of the unproved costs which considered the value of the contingent and exploration resources and the ability of the Company to develop the project given its current liquidity situation and the depressed price of crude oilWe also impaired the oilfield inventory related to our property in Gabon by $1.0 million, leaving $3.0 million related to this inventory. We recorded the oilfield inventory impairment based on the decrease in demand for such inventory due to continued decreases in oil prices.  Operational activities during the year ended December 31, 2015, included continued evaluation of development plans, based on the 3D seismic data acquired in late 2013 and processed during 2014.  

As of December 31, 2015, we had total assets of $47.8 million, unrestricted cash of $7.8 million and debt of $0.2 million. For the year ended December 31, 2015, we had no revenues from continuing operations and net cash used in operating activities of $23.9 million. As of December 31, 2014, we had total assets of $228.0 million, unrestricted cash of $6.6 million and note payable to controlling interest owner of $13.7 million. For the year ended December 31, 2014, we had no revenues from continuing operations and net cash used in operating activities of $39.2 million.

We expect that in 2016 we will not generate revenues and will continue to generate losses from operations and that our operating cash flows will not be sufficient to cover our operating expenses.  While we believe that we may be able to raise additional capital through issuance of debt or equity or through sales of assets, our circumstances at such time raises substantial doubt about our ability to continue as a going concern.

4

Recent Events

On January 1, 2015, we terminated the SPA to sell our remaining 51 percent interest in Harvest Holding, which owns our investment in Petrodelta.

On January 15, 2015, HNR Finance and Harvest Vinccler S.C.A. (“Harvest Vinccler”) submitted a Request for Arbitration against the Government of Venezuela before the International Centre for Settlement of Investment Disputes (“ICSID”) regarding HNR Finance's interest in Petrodelta.  The Request for Arbitration set forth numerous claims, as further described in Part IV – Item 15 – Exhibits and Financial Statement Schedules, Note 13 – Commitments and Contingencies.

On January 26, 2015, Petroandina filed a complaint for breach of contract against the Company and its subsidiary HNR Energia B.V. (“HNR Energia”) in Court of Chancery of the State of Delaware (“Court of Chancery”).  The complaint states that HNR Energia breached provisions of the Shareholders Agreement between Petroandina and HNR Energia, which provisions require HNR Energia to provide advance notice, and deposit $5 million into an escrow account, before bringing any claim against the Venezuelan government. Under those provisions, if Petroandina so requests, an appraisal of Petroandina's 29 percent interest in Harvest Holdings must be performed, and Petroandina has the right to require HNR Energia to purchase that 29 percent interest at the appraised value.  Petroandina's claim requests relief as further described in Part IV – Item 15 – Exhibits and Financial Statements Schedules,Note 13 – Commitments and Contingencies.  On January 28, 2015, the Court of Chancery issued an injunction ordering the Company and HNR Energia to withdraw the Request for Arbitration and not take any action to pursue its claims against Venezuela until Harvest and HNR Energia have complied with the provisions of the Shareholders’ Agreement or otherwise reached an agreement with Petroandina.  Accordingly, on January 28, 2015, HNR Finance B.V. and Harvest Vinccler withdrew without prejudice the Request for Arbitration.

On February 5, 2015, the Company entered into a Share Purchase Agreement to transfer shares of Harvest Budong-Budong B.V. to Stockbridge Capital Limited.  The transfer of shares was completed on May 4, 2015.

On March 9, 2015, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., (“Vinccler”) forgave a note payable by HNR Energia and accrued interest totaling $6.2 million.  This was reflected as a contribution to stockholders’ equity.

On March 31, 2015, the Company closed its Singapore office.

On May 11, 2015, the Company borrowed $1.3 million to fund certain corporate expenses.  The Company issued a note payable to the lender bearing an interest rate of 15.0% per annum, with a maturity date of January 1, 2016.  On June 19, 2015, the Company repaid the note payable and accrued interest.

On June 19, 2015, Dr. Igor Effimoff, Mr. H. H. Hardee and Mr. J. Michael Stinson resigned as directors of the Company in connection with the CT Energy transaction.  CT Energy appointed Oswaldo Cisneros, Francisco D'Agostino and Edgard Leal as directors of the Company.

As of December 31, 2014, HNR Energia had a note payable to Petroandina of $7.6 million. Principal was due by January 1, 2016.  On June 23, 2015 the Company repaid the note payable of $7.6 million plus accrued interest of $0.4 million.

On July 14, 2015, HNR Finance entered into a non-binding term sheet with CVP and PDVSA.  The term sets forth a framework for definitive agreements that would govern the restructuring of the management and operations of Petrodelta.  Because the term sheet is non-binding and subject to several conditions precedent, we cannot guarantee that HNR Finance will be able to consummate the transactions contemplated by the term sheet. 

On September 9, 2015, our stockholders approved all proposals related to the transaction with CT Energy.

On September 15, 2015, the 9% Note and associated accrued interest were converted into 8,667,597 shares of Harvest common stock. The Company recognized a $1.9 million loss on debt conversion.  Immediately after the conversion, CT Energy owned approximately 16.6% of Harvest’s common stock.

On December 2, 2015, the Company received notification from the NYSE that the Company was not in compliance with the NYSE's continued listing standards, which require a minimum average closing price of $1.00 per share over 30 consecutive trading days.  Under the NYSE's rules, Harvest has a period of six months from the date of the NYSE notice to bring its share price and 30 trading-day average share price back above $1.00.  During this period, the Company’s common stock will continue to be traded on the NYSE under the symbol “HNR”, subject to the Company’s compliance with other NYSE continued listing requirements, but will be assigned the notation .BC after the listing symbol to signify that the Company is not currently in compliance with the NYSE’s continued listing standards.  As required by the NYSE, in order to maintain its listing, Harvest has notified the NYSE that it intends to cure the price deficiency.

On January 4, 2016, Harvest amended the 15% Note and made a loan, via one of its subsidiaries, to a third party. The parties involved in the transactions are HNR Energia, Harvest Holding, HNR Finance, CT Energy and CT Energia, which is the service provider under the June 19, 2015 management agreement with Harvest and HNR Finance.  Harvest and CT Energy executed a first amendment to the 15% Note. The amendment is effective as of December 31, 2015, and increases the principal amount of the 15%

5

Note to $26.1 million to reflect a loan back to Harvest equal to the amount of interest that otherwise would have been due to CT Energy on January 1, 2016, less applicable withholding tax.

On January 4, 2016, HNR Finance made a loan to CT Energia in the amount of $5.2 million under an 11.0% promissory note due 2019 (the “CT Energia Note”), dated January 4, 2016, executed by CT Energia. The purpose of the loan is to provide CT Energia with collateral to obtain funds for one or more loans to Petrodelta. The loans to Petrodelta are to assist Petrodelta in satisfying its working capital needs and discharging its obligations. Interest on the CT Energia Note is due and payable on the first of each January and July, commencing July 1, 2016. The full amount outstanding, including any unpaid accrued interest, is due on January 4, 2019; however, HNR Finance’s sole recourse for payment of the principal amount of the loan is the payments of principal and interest from loans that CT Energia has made to Petrodelta. If and when CT Energia receives any payments of principal or interest from loans it has made to Petrodelta, then those proceeds must be used to prepay unpaid interest and principal under the CT Energia Note.  The source of funds for HNR Finance’s $5.2 million loan to CT Energia was a capital contribution from Harvest Holding, which, in return, received the same aggregate amount of capital contributions from its shareholders, pro rata according to their equity interests in Harvest Holding. Of that aggregate amount of capital contributions, HNR Energia contributed $2.6 million, which it had received as a capital contribution from Harvest.

On February 19, 2016, the Company filed a Certificate of Elimination with the Delaware Secretary of State, which eliminated all matters set forth in the Certificate of Designations of Preferred Stock, Series C of Harvest Natural Resources, Inc. from the Company’s Amended and Restated Certificate of Incorporation and returned all shares of the Company’s Series C Preferred Stock, par value $0.01 per share (the “Series C Preferred Stock”), to the status of authorized but unissued shares of preferred stock of the Company.  The Company had issued 69.75 shares of Series C Preferred Stock to CT Energy on June 19, 2015 together with the 9% Note.  All outstanding shares of Series C Preferred Stock were redeemed in connection with the September 15, 2015 conversion of the 9% Note.

Business Strategy

We are currently negotiating the management and structure of our investment in Petrodelta.  In July 2015, HNR Finance entered into a non-binding term sheet with CVP and PDVSA.  The term sets forth a framework for definitive agreements that would govern the restructuring of the management and operations of Petrodelta.  Because the term sheet is non-binding and subject to several conditions precedent, we cannot guarantee that HNR Finance will be able to consummate the transactions contemplated by the term sheet.  Given the concentration of our assets in Petrodelta, our results of operations and financial conditions could be adversely affected if we are unable to consummate the restructuring of the management and operations of Petrodelta, as contemplated by the term sheet.

The Company is considering options to develop, sell or farm-down its interest in the Dussafu PSC in order to obtain the maximum value from the asset, while maintaining the required liquidity to continue our current operations.

Our financial statements have been prepared under the assumption that we will continue as a going concern, which contemplates that we will continue in operation for the foreseeable future and will be able to realize assets and settle liabilities and commitments in the normal course of business.

For additional information regarding our business strategy, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part IV – Item 15 – Exhibits and Financial Statements Schedules, Note 16 – Operating Segments.

Available Information

We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934, as amended (“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 and principal financial and 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

6

should submit a request to Harvest Natural Resources, Inc., 1177 Enclave Parkway, Suite 300, Houston, Texas 77077, Attention: Investor Relations.

Operations

As of December 31, 2015, our operations include:

· Venezuela. Operations are through our investment in affiliate Petrodelta which is governed by the Contract of Conversion (“Conversion Contract”) signed on September 11, 2007. Our ownership of Petrodelta is through Harvest Holding which indirectly, through wholly owned subsidiaries, owns 40 percent of Petrodelta. As we indirectly own 51 percent of Harvest Holding, we indirectly own a net 20.4 percent interest in Petrodelta.  Our investment in affiliate Petrodelta is accounted for under the cost method of accounting. 

· Gabon. Operations are offshore of Gabon through the Dussafu Production Sharing Contract (“Dussafu PSC”). We have a 66.667 percent interest in the Dussafu PSC. We are the operator.

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. Under the decree, 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 the 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.

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 USD. 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 USD. 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 was executed during the first quarter 2015. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Petrodelta for additional information on the sales contract. 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 USD 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.

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. The Venezuelan government modified the currency exchange system whereby the official exchange rate of 6.3 Bolivars per USD would only apply to certain economic sectors related to purchases of “essential goods and services” while other sectors of the economy would be subject to a new exchange rate, SICAD I, determined by an auction process conducted by Venezuela's Complimentary System of Foreign Currency Administration. Participation in the SICAD I mechanism is controlled by the Venezuelan government and is limited to certain companies that operate in designated economic sectors.  In March 2014, an additional currency exchange mechanism was established by the Venezuelan government that allows companies within other economic sectors to participate in an additional auction process (“SICAD II”).  The financial information for Petrodelta is prepared using the official fixed exchange rate (6.3 from February 2013 through December 2014).

7

On February 10, 2015, the Ministry of Economy, Finance, and Public Banking, and the Central Bank of Venezuela (BCV) published in the Extraordinary Official Gazette No.6.171 Exchange Agreement No.33 with two Official Notices.  The first notice being that the SICAD II exchange rate would be no longer permitted.  Secondly, a new exchange rate called the Foreign Exchange Marginal System (“SIMADI”) has been created.  The SIMADI rate published on December 31, 2015 is 198.70 Bolivars per USD. The SIMADI’s marginal system is available in limited quantities for individuals and companies to purchase and sell foreign currency via banks and exchange houses.

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 “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 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 report, the 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 was classified as a long-term receivable at December 31, 2014 due to the uncertainty in the timing of payment.  During the year ended December 31, 2014 we recorded an allowance of $12.2 million to fully reserve the dividend receivable due from Petrodelta.  As of December 31, 2015, this dividend has not been paid. 

Petroandina has the right to any dividends paid by Harvest Holding after December 16, 2013 that would attach with respect to its current 29 percent interest 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 SPA dated December 16, 2013 and regardless of the record date therefor.  Petrodelta did not declare or pay any dividends during this period.

Due to our failed sales attempts, lack of management influence, and actions and inactions by the majority owner, PDVSA, we believe we no longer exercise significant influence in Petrodelta and, in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we account for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.  Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends as income in the period they are received.

Location and Geology

Uracoa Field

At December 31, 2015, there were 52 (compared to 66 at December 31, 2014) oil and natural gas producing wells and six (compared to seven at December 31, 2014) 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 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 natural gas station and PDVSA’snatural gas network.

Tucupita Field

At December 31, 2015, there were 15 (compared to 17 at December 31, 2014) oil producing wells and five (compared to five at December 31, 2014) 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, 2015, there were four (compared to four at December 31, 2014) 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, 2015, there were nine (compared to eight at December 31, 2014) 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 oil produced.

8

Temblador Field

At December 31, 2015, there were 31 (compared to 31 at December 31, 2014) oil producing wells in the field, and eight (compared to eight at December 31, 2014) water injection 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, 2015, there were 31 (compared to 23 at December 31, 2014) oil producing wells and one (compared to one at December 31, 2014) 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 natural gas station and the PDVSA natural 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.

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 natural gas affiliate for purchase of power for electrical needs, leasing of compression, and operation and maintenance of the natural gas treatment and compression facilities at the Uracoa and Tucupita fields.

Drilling and Development Activity

During the year ended December 31, 2015, Petrodelta drilled and completed 18 development wells. Petrodelta delivered approximately 14.8 MBls of oil and 3.9 billion cubic feet (“Bcf”) of natural gas, averaging 42,237 barrels of oil equivalent (“BOE”) per day during the year ended December 31, 2015.

During the year ended December 31, 2014, Petrodelta drilled and completed 13 development wells. Petrodelta delivered approximately 15.6 MBls of oil and 3.0 Bcf of natural gas, averaging 43,994 BOE per day during the year ended December 31, 2014. During the year ended December 31, 2013, Petrodelta drilled and completed 13 development wells, 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.

Currently, Petrodelta is operating five drilling rigs and one workover rig and is continuing with infrastructure enhancement projects in the El Salto and Temblador fields.

Risk Factors

We face significant risks in holding a minority 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. As of December 31, 2014, the Company changed its accounting for its investment in Petrodelta from the equity interest method to the cost method.

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 Ministry of Mines, Energy,

9

Petroleum and Hydraulic Resources agreed to lengthen the third exploration phase to four years, until May 27, 2016.  The Company is currently assessing extension possibilities for the exploration phase.

On March 26, 2014, the joint venture partners approved a resolution that the discovered fields are commercial to exploit.  On June 4, 2014, a Declaration of Commerciality (“DOC”) was signed with Gabon pertaining to four discoveries on the Dussafu Project offshore Gabon.  Furthermore, on July 17, 2014, the Direction Generale Des Hydrocarbures (“DGH”) awarded an Exclusive Exploitation Authorization (“EEA”) for the development and exploitation of certain oil discoveries on the Dussafu Project and on October 10, 2014, the field development plan was approved. The Company has four years from the date of the EEA approval to begin production.

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.

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 the 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. 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 downhole tool was retrieved and the DTM-1 and DTM-1ST1 were suspended for future re-entry.

We have met all funding commitments for the third exploration phase of the Dussafu PSC.  See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation, Contractual Obligations.

Operational activities during the year ended December 31, 2015, included continued evaluation of development plans based on the 3D seismic data acquired in late 2013 and processed during 2014. 

Central/Inboard 3D seismic data acquired in 2011 has been processed and interpreted to evaluate prospectivity. We have also completed processing data from the 1,260 sq. km 3D seismic survey acquired during the fourth quarter of 2013. This survey provides 3D coverage over the outboard portion of the block and has confirmed significant pre-salt prospectivity which had been inferred from 2D seismic data. The new 3D seismic data also covers the Ruche, Tortue and Moubenga discoveries and we expect will facilitate the effective placement of future development wells in the Ruche and Tortue development program, as well as allowing improved assessment of the numerous undrilled structures already identified on older 3D seismic surveys.

Since approval of the Field Development Plan (“FDP”) in October 2014, Harvest has continued to move toward development of the Ruche Exclusive Exploitation Area. A tender for all the subsea equipment was concluded in January 2015 where prices exceeded the costs employed in the FDP. Efforts continue to negotiate with the lowest priced vendors and to revise the development scheme to bring the projected cost back to the FDP levels. The depth volume from the 2013 3D seismic acquisition over the discovered fields and the outboard area of the license has been received and interpreted.

This new data was incorporated into our reservoir models and optimization of well trajectories to maximize oil recovery is ongoing. Results from an ongoing seismic inversion study, aimed at recognizing reservoir ‘sweet spots’, will be incorporated when available. In addition, the prospect inventory was updated and several prospects have been high graded for drilling.

Harvest and its joint venture partner engaged a contractor to undertake a fixed-price, geophysical site survey over multiple potential well locations in the Dussafu block in August 2015.  The survey is a pre-requisite for siting mobile drilling units and other installations required for continuing exploration and development activities over the license.  The survey will provide information about the seabed and shallow geological conditions, essential for the safe siting and operation of these installations.  A tender for a jackup drilling rig was completed in November 2015 and a tender for well testing and other services were concluded in January 2016. 

The Company is considering options to develop, sell or farm-down its interest in the Dussafu PSC in order to obtain the maximum value from the asset, while maintaining the required liquidity to continue our current operations.

10

Budong-Budong, Onshore Indonesia

We fully impaired our investment in the Budong Production Sharing Contract (“Budong PSC”) in Indonesia as of March 31, 2014.  In June 2014, Harvest and our partner adopted a resolution to terminate the Budong PSC.  Harvest advised the Indonesian government of this decision and submitted a request to terminate the Budong PSC.  On February 5, 2015, the Company entered into a Share Purchase Agreement to transfer shares of Harvest Budong-Budong B.V. to Stockbridge Capital Limited for a nominal amount.  On February 17, 2015, a withdrawal request of the earlier termination request was made to the Indonesian government and the withdrawal request was accepted on April 15, 2015.  The transfer of shares to Stockbridge Capital Limited was completed on May 4, 2015.

Colombia-Discontinued Operations

We received notices of default from our partners for failing to comply with certain terms of the farm-down agreements for Block VSM14 and Block VSM15, followed by notices of termination on November 27, 2013.  Our partners 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, which included an accrual of $2.0 million related to this matter.  On December 14, 2014 we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed. We are in the process of closing and exiting our Colombia venture. As we no longer have any interests in Colombia, we reflected the results in discontinued operations. 

Production, Prices and Lifting Cost Summary

In the following table we have set forth, for Venezuela, our net production, average sales prices and average operating expenses for the years ended December 31, 2015,2014 and 2013. The presentation for Venezuela shows our net ownership interest in Petrodelta which was 32 percent through December 15, 2013 and 20.4 percent thereafter.  

	Year Ended December 31,
	2015		2014		2013
Venezuela (Petrodelta)
Crude Oil Production (MBbls) (b)		2,008		2,116		3,052
Natural Gas Production (MMcf) (a)(c)		535		405		547
Average Crude Oil Sales Price ($ per Bbl) (e)	$	36.92	$	86.33	$	91.22
Average Natural Gas Sales Price ($ per Mcf)	$	1.54	$	1.54	$	1.54
Average Operating Expenses and Workovers ($ per BOE) (d)		(f)	$	19.79	$	11.41

(a) Royalty-in-kind paid on natural gas used as fuel by Petrodelta net to our ownership interest (32 percent through December 15, 2013 and 20.4 percent thereafter) was 2,516 MMcf for 2015 (3,416 MMcf for 2014 and6,412 MMcf for 2013).

(b) Crude oil sales net to our ownership interest (32% through December 15, 2013 and 20.4% thereafter) after deduction of royalty. Crude oil sales for Petrodelta at 100 percent were 14,761 MBbls for 2015 (15,561 MBbls for 2014 and14,538 MBbls for 2013).

(c) Natural gas sales net to our ownership interest (32% through December 15, 2013 and 20.4% thereafter) after deduction of royalty. Natural gas sales for Petrodelta at 100 percent were 3,934 MMcf for 2015 (2,981 MMcf for 2014 and2,593 MMcf for 2013).

(d) Petrodelta is not subject to ad valorem or severance taxes. Average operating expenses per BOE net of royalties and workovers were $27.04 per BOE for 2014 and $14.19 per BOE for 2013. 

(e) Includes additional pricing adjustments related to the approved El Salto contract of $60.4 million for previous years that were invoiced in 2014.  Excluding these pricing adjustments, the average crude oil sales price for 2014 was $82.45.

(f) Due to the change in accounting method from equity method to cost method of accounting for our investment in Petrodelta, certain operating statistics for 2015 have been excluded.

Drilling and Undeveloped Acreage

For acquisitions of leases, development and exploratory drilling, we spent approximately (excluding our share of capital expenditures incurred by investmentin affiliate) $0.9 million in 2015 ($4.4 million in 2014,  $43.9 million in 2013). These numbers do not include any costs for the development of proved undeveloped reserves in 2015,  2014 or 2013.  Our net ownership interest was 32 percent through December 15, 2013 and 20.4 percent thereafter.

11

We have participated in the drilling of wells as follows:

	Year Ended December 31,
	2015		2014		2013
	Gross	Net	Gross	Net	Gross	Net
Wells Drilled Productive:
Venezuela (Petrodelta)
Development	18	3.7	13	2.7	13	2.7
Gabon
Exploration	—	—	—	—	1	0.7
Producing Wells (1):
Venezuela (Petrodelta)
Crude Oil	142	29.0	170	34.7	173	35.0

(1) The information related to producing wells reflects wells we drilled, wells we participated in drilling and producing wells we acquired.

	Year Ended December 31,
	2015	2014	2013
Average Depth of Wells (Feet) Drilled
Venezuela (Petrodelta)
Crude Oil	8,618	6,881	7,979
Gabon
Crude Oil	—	—	11,260

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 2013 and we received the first high quality seismic products during the second quarter of 2014 and interpretation was completed in early 2015. The new 3D seismic data was extended 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.

Acreage

The following table summarizes the developed and undeveloped acreage that we own, lease or hold under concession as of December 31, 2015:

	Developed		Undeveloped
	Gross	Net	Gross	Net
Venezuela – Petrodelta	29,900	6,100	217,213	44,311
Gabon	—	—	685,470	456,982
Total	29,900	6,100	902,683	501,293

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:

· change in governments;

· civil unrest;

· price and currency controls;

· limitations on oil and natural gas production;

· tax, environmental, safety and other laws relating to the petroleum industry;

· changes in laws relating to the petroleum industry;

· changes in administrative regulations and the interpretation and application of administrative rules and regulations; and

12

· changes in contract interpretation and policies of contract adherence.

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 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 natural 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, 2015, we employed 27full-time employees. We augment our employees from time to time with independent consultants, as required.

Item 1A.  Risk Factors

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

General Risks Related to Our Business

Our financial condition raises substantial doubt as to our ability to continue as a going concern. The Company has not generated revenue and has incurred recurring losses as well as negative cash flow from operations that give rise to this concern. Our financial statements have been prepared assuming we will continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.  If we become unable to continue as a going concern, we may have to liquidate our assets and the values we receive for our assets in liquidation or dissolution could be significantly lower than the values reflected in our financial statements.  Our financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Our cash position and limited ability to access additional capital may limit our growth and development 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. To maintain the liquidity required to run our operations and capital spending requirement, we may attempt to improve our future cash position by effectuating a farm-down, selling or monetizing assets, or accessing debt or equity markets. 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 natural gas properties and projects.

Our common stock may not remain listed for trading on the NYSE.  The NYSE has established certain quantitative and qualitative standards that companies must meet in order to remain listed for trading.  We may not be able to maintain necessary requirements for listing, in which case our common stock may not remain listed for trading on the NYSE or any similar market.  On December 2, 2015, we received notification from the NYSE that we had fallen below the NYSE's continued listing standards, which require a minimum average closing price of $1.00 per share over 30 consecutive trading days.  Under the NYSE's rules, we have a period of six months from the date of the NYSE notice to bring our share price and 30 trading-day average share price back above

13

$1.00.  During this period, our common stock will continue to be traded on the NYSE, subject to our compliance with other NYSE continued listing requirements.  As required by the NYSE, in order to maintain our listing, we have notified the NYSE that we intend to cure the price deficiency.  If we are unable to cure the deficiency, the NYSE could delist our common stock and we may seek to be listed on an alternative exchange.While we have not yet received any notification from the NYSE, as of the date of this Report, we believe we may be in noncompliance with a second NYSE continued listing standard, which states that a company will be in noncompliance if its average global market capitalization over a consecutive 30 trading-day period is less than $50.0 million at a time when its stockholders’ equity is less than $50.0 million.  We believe the NYSE will give us an opportunity to cure this deficiency, but there can be no assurance that we will be able to cure or will be given such opportunity before the NYSE commences delisting procedures.

Our business may be sensitive to market prices for oil and natural gas. We have made significant investments in our oil and natural gas properties. If we seek to sell the assets in our portfolio, to the extent market values of oil and natural 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 may not have the funds available to meet the minimum funding requirements of our existing contracts when they come due and be required to forfeit the contracts.

Our portfolio of hydrocarbon assets in known hydrocarbon basins globally is 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 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.

Risks Related to Gabon Project

We impaired our offshore project in Gabon and we may need to record additional impairments in the future.  Due to our liquidity situation we have not been able to commit to the development of our property in Gabon.  If oil prices do not improve, we may not be able to obtain the necessary capital to develop Gabon and we may be required to record additional impairments relating to this asset.  Currently the Company is considering alternatives with this property such as a farm-down or sale.

The capital required to develop our Gabon asset currently exceeds the Company’s ability to finance such development and we may have to farm-down or consider an outright sale of the asset.   Our ability to secure financing is currently limited and there may be factors beyond our control, which might hinder the marketability of this asset.

Risks Related to Petrodelta

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 investment in Petrodelta. We are not able to exercise significant influence as a minority investor in Petrodelta and 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 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

14

by modifying Petrodelta’s business plan or restricting the budget is limited under the Conversion Contract.  In 2015, Petrodelta was subject to the ventajas especiales and it may continue to be subject to this tax.

Oil price declines and volatility could adversely affect Petrodelta’s operations and profitability, which in turn could affect cash available for 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. Prices have declined from June 30, 2014 through December 31, 2015 from approximately $86 to approximately $37 per barrel based on the Venezuelan export basket.  Subsequent to December 31, 2015, oil price changes have been volatile. Factors that can causefluctuations in oil prices include:

· relatively minor changes in the global supply and demand for oil;

· export quotas;

· market uncertainty;

· the level of consumer product demand;

· weather conditions;

· domestic and foreign governmental regulations and policies;

· the price and availability of alternative fuels;

· political and economic conditions in oil-producing and oil consuming countries; and

· overall economic conditions.

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 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 $60 per barrel for 2015) and $80 per barrel. The 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 greater than or equal to $100 per barrel but is less than $110 per barrel; and (3) 95 percent when the average price of the VEB is greater than or equal to $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.

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 continue to 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 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 of 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 the Venezuelan government’s maintenance of legal, currency, 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 investment in Petrodelta.

15

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.

The operating environment in Venezuela is challenging, with high inflation, increased risk of political and economic instability increased government restrictions, exchange rate restrictions and increased risks of enforcement actions by the United States Department of Justice.  Going forward, additional government actions, political and labor unrest, or other economic headwinds, including the Venezuelan government's inability to fulfill its fiscal obligations and additional foreign currency devaluations, could have further adverse impacts on our business in Venezuela and our ability to fully realize the potential of our investment in Petrodelta.Additionally, the U.S. Department of Justice (“U.S. DOJ”) has increasingly focused on investigating criminal matters involving Venezuela, typically involving allegations of corruption, money laundering, drug trafficking and other crimes by Venezuelan government officials.  Specifically, late in 2015, the U.S. DOJ brought a case against United States companies for bribing procurement officials at PDVSA, the Venezuelan national oil company and the indirect 60% parent company of Petrodelta.  The increased scrutiny by the U.S. DOJ and ongoing investigation into PDVSA, combined with the weakened Venezuelan government and unstable economic climate, could negatively impact our results of operations and financial condition.

Risks Related to Our Strategic Relationship with CT Energy

Our transaction with CT Energy may significantly dilute our existing stockholders.  CT Energy may choose to fully convert the CT Warrant that we issued to CT Energy on June 19, 2015. CT Energy would own approximately 49.9% of our outstanding common stock following full exercise and the holdings of our other stockholders would be diluted.  However, the CT Warrant will not be exercisable until the volume weighted average price of our common stock over any 30-day period equals or exceeds $2.50 per share, which means that stockholders other than CT Energy will have experienced significant share price appreciation prior to such exercise when compared to the $0.69 price per share of our common stock on May 8, 2015, the last trading date before we entered into the term sheet with representatives of CT Energy.

As a significant stockholder and debtholder of Harvest, CT Energy has significant influence over our actions and its presence may affect the ability of a third party to acquire control of us.  CT Energy currently owns approximately 16.6% of our outstanding common stock.  For so long as CT Energy is a significant stockholder and debtholder, CT Energy and its affiliates may exercise significant influence or control over our management and affairs, including influence or control beyond what is expressly permitted under the CT Energy transaction documents.  CT Energy and its affiliates also will be able to strongly influence all matters requiring stockholder approval.  In any of these matters, the interests of CT Energy and its affiliates may differ or conflict with those of other stockholders.  Further, the high concentration of stock ownership in one stockholder may directly or indirectly deter hostile takeovers, delay or prevent changes in control or changes in management, or limit the ability of our other stockholders to approve transactions that they may deem to be in our best interests.  The trading price of our common stock may be adversely affected to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder and debtholder.

Anti-dilution provisions in the securities we issued to CT Energy may make it more difficult and expensive for us to raise additional capital in the future and may result in further dilution to our stockholders.  The CT Warrant that we issued to CT Energy on June 19, 2015 contains customary full ratchet anti-dilution provisions.  If triggered, these anti-dilution provisions will have the effect of lowering the price at which shares of our common stock are issued upon exercise of the CT Warrant, thereby increasing the number of shares received upon exercise.  Accordingly, if we are unable to raise additional capital at an effective price per share that is higher than the exercise price of the CT Warrant, the anti-dilution provisions will make it more difficult and expensive to raise additional capital in the future.  If triggered, these anti-dilution provisions also would result in further dilution to our stockholders. 

Changes in the fair value of financial instruments, particularly the securities we issued to CT Energy, may result in significant volatility in our reported operating results.  We recorded an embedded derivative asset related to the 15% Note and a derivative liability related to the CT Warrant that we issued to CT Energy on June 19, 2015.  Please see Part IV – Item 15 – Exhibits and Financial Statement Schedule, Note 11 – Debt and Financing and Note 12 – Warrant Derivative Liabilities for further information.  These financial instruments require us to “mark to market” (i.e., record the derivatives at fair value) as of the end of each reporting period as assets or liabilities, as applicable, on our balance sheet and to record the change in fair value during each period as a non-cash adjustment to our current period results of operations and in our income statement.  These accounting classifications could significantly increase the volatility of our reported operating results, and the negative reporting implications may make it more difficult for us to raise capital in the future. 

We may be unable to consummate the restructuring of Petrodelta as contemplated by the term sheet between HNR Finance and CVP and PDVSA.  On July 14, 2015, HNR Finance, our majority-owned subsidiary, entered into a non-binding term

16

sheet with CVP and PDVSA.  The term sets forth a framework for definitive agreements that would govern the restructuring of the management and operations of Petrodelta.  Because the term sheet is non-binding and subject to several conditions precedent, we cannot guarantee that HNR Finance will be able to consummate the transactions contemplated by the term sheet.  Given the concentration of our assets in Petrodelta, our results of operations and financial conditions could be adversely affected if we are unable to consummate the restructuring of the management and operations of Petrodelta, as contemplated by the term sheet. 

Risks Related to Our Industry

Estimates of oil and natural gas reserves are uncertain and inherently imprecise. 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.

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. 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 as of December 2014 and 2013 referred to in Part IV– 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 from our investment in Petrodelta.  In 2015, we accounted for Petrodelta as a cost investment and did not provide this information.  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 did not have any proved oil and natural gas reserves in 2015, 2014 or 2013 except for our share of the reserves in Petrodelta.

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 investment in Petrodelta, and our future operations and our development, sale or farm-down in Gabon, 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:

· shortages or delays in the delivery of equipment;

· shortages in experienced labor;

· pressure or irregularities in formations;

· unexpected drilling conditions;

· equipment or facilities failures or accidents;

· remediation and other costs resulting from oil spills or releases of hazardous materials;

· government actions or changes in regulations;

· delays in receiving necessary governmental permits;

17

· delays in receiving partner approvals; and

· weather conditions.

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 international 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 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. Any additional 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:

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

· response to unexpected releases to the environment;

· reports and permits concerning exploration, drilling, production and other operations; and

· taxation.

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

18

The oil and natural 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 natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and naturalgas, including the risk of:

· fires and explosions;

· blow-outs;

· uncontrollable or unknown flows of oil, natural gas, formation water or drilling fluids;

· adverse weather conditions or natural disasters;

· pipe or cement failures and casing collapses;

· pipeline ruptures;

· discharges of toxic gases;

· buildup of naturally occurring radioactive materials; and

· vandalism.

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

· injury or loss of life;

· severe damage or destruction of property and equipment, and oil and natural gas reservoirs;

· pollution and other environmental damage;

· investigatory and clean-up responsibilities;

· regulatory investigation and penalties;

· suspension of our operations; and

· repairs to resume operations.

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 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 natural gas that we produce and as a result, negatively impact our financial condition, results of operations and cash flows.

19

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.

Item 1B.  Unresolved Staff Comments

None.

Item 2.  Properties

We have a regional office in Caracas, Venezuela that provides oversight of our investment in Petrodelta.   Our corporate headquarters are in Houston, Texas.  At December 31, 2015, we had the following lease commitments for office space: 

Location	Date Lease Signed	Term		Annual Expense
Houston, Texas	December 2014	1.8 years	$	81,100
Caracas, Venezuela	December 2015	1.0 years	$	83,100

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

Item 3.  Legal Proceedings

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 alleged that the area belonged to the people of Taiwan and sought 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, and the WAB-21 area.  The Company filed a motion to dismiss the suit, which was granted by the district court in August 2014.  The plaintiffs appealed the dismissal.  The Fifth Circuit Court of Appeals heard oral arguments on June 3, 2015 and affirmed the district court’s dismissal on June 4, 2015.  The plaintiffs filed a petition for writ of certiorari with the Supreme Court of the United States. On October 13, 2015, the Supreme Court denied the petition.

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. We are currently unable to estimate the amount or range of any possible loss.

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.  We are currently unable to estimate the amount or range of any possible loss.

20

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. On April 23, 2014, we received a notice that OFAC had denied our October 26, 2011 application for the return of the blocked funds.  During the year ended December 31, 2015, primarily due to the passage of time, we recorded a $0.7 million allowance for doubtful accounts to general and administrative costs associated with the blocked payment and  a $0.4 million receivable from our joint venture partner.   On October 13, 2015, we filed a request that OFAC reconsider its decision and on March 8, 2016, OFAC denied our October 13, 2015 request for the return of blocked funds; however, the Company will continue attempts to recover the funds from 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. The court administratively closed the case in 2013. The case was reopened in 2014 as a result of a Circuit Court of Appeals’ ruling.  On November 3, 2015, the court granted a stipulated motion to dismiss with prejudice and the lawsuit was dismissed.

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

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

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

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

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

Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions 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:

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

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

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

21

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 January 15, 2015, HNR Finance and Harvest Vinccler S.C.A submitted a Request for Arbitration against the Government of Venezuela before the International Centre for Settlement of Investment Disputes ("ICSID") regarding HNR Finance's interest in Petrodelta.  The Request for Arbitration set forth numerous claims, including (a) the failure of the Venezuelan government to approve the Company’s negotiated sale of its 51 percent interest in Harvest Holding to Petroandina on any reasonable grounds in 2013-2014, resulting in the termination of the SPA (b) the failure of the Venezuelan government to approve the Company’s previously negotiated sale of its interest in Petrodelta to PT Pertamina (Persero) on any reasonable grounds in 2012-2013, resulting in the termination of a purchase agreement entered into between HNR Energia and PT Pertamina (Persero); (c) the failure of the Venezuelan government to allow Petrodelta to pay approved and declared dividends for 2009; (d) the failure of the Venezuelan government to allow Petrodelta to approve and declare dividends since 2010, in violation of Petrodelta’s bylaws and despite Petrodelta’s positive financial results between 2010 and 2013; (e) the denial of Petrodelta’s right to fully explore the reserves within its designated areas; (f) the failure of the Venezuelan government to pay Petrodelta for all hydrocarbons sales since Petrodelta’s incorporation, recording them instead as an ongoing balance in the accounts of PDVSA, the Venezuelan government-owned oil company that controls Venezuela’s 60 percent interest in Petrodelta, and as a result disregarding Petrodelta’s managerial and financial autonomy; (g) the failure of the Venezuelan government to pay Petrodelta in US dollars for the hydrocarbons sold to PDVSA, as required under the mixed company contract; (h) interference with Petrodelta’s operations, including PDVSA’s insistence that PDVSA and its affiliates act as a supplier of materials and equipment and provider of services to Petrodelta; (i) interference with Petrodelta’s financial management, including the use of low exchange rates Bolivars/US dollars to the detriment of the Company and to the benefit of the Venezuelan government, PDVSA and its affiliates; and (j) the forced migration of the Company’s investment in Venezuela from an operating services agreement to a mixed company structure in 2007.

On January 26, 2015, Petroandina filed a complaint for breach of contract against the Company and its subsidiary HNR Energia in Court of Chancery of the State of Delaware (“Court of Chancery”).  The complaint states that HNR Energia breached provisions of the Shareholders Agreement between Petroandina and HNR Energia, which provisions require HNR Energia to provide advance notice of, and deposit $5.0 million into an escrow account, before bringing any claim against the Venezuelan government. Under those provisions, if Petroandina so requests, an appraisal of Petroandina's 29 percent interest in Harvest Holdings must be performed, and Petroandina has the right to require HNR Energia to purchase that 29 percent interest at the appraised value.  Petroandina's claim requests that, among other things, the court (a) declare that HNR Energia has breached the Shareholders' Agreement by submitting the Request for Arbitration against the Venezuelan government on January 15, 2015 (which Request for Arbitration was subsequently withdrawn without prejudice); (b) declare that the Company has breached its guaranty of HNR Energia's obligations under the Shareholders' Agreement; (c) direct the Company and HNR Energia to refrain from prosecuting any legal proceeding against the Venezuelan government (including the previously filed Request for Arbitration) until such time as they have complied with the relevant provisions of the Shareholders' Agreement; (d) award Petroandina costs and fees related to the lawsuit; and (e) award Petroandina such other relief as the court deems just and proper.  On January 28, 2015, the Court of Chancery issued an injunction ordering the Company and HNR Energia to withdraw the Request for Arbitration and not take any action to pursue its claims against Venezuela until Harvest and HNR Energia have complied with the provisions of the Shareholders’ Agreement or otherwise reached an agreement with Petroandina.  Accordingly, on January 28, 2015, HNR Finance B.V. and Harvest Vinccler S.C.A. withdrew without prejudice the Request for Arbitration. In the Delaware proceeding, the Company and HNR Energia have until May 23, 2016 to respond to Petroandina’s complaint.  We are currently unable to estimate the amount or range of any possible loss.

On February 27, 2015, Harvest (US) Holdings, Inc. (“Harvest US”), a wholly owned subsidiary of Harvest, Branta, LLC and Branta Exploration & Production Company, LLC (together, “Branta,” and together with Harvest US, “Plaintiffs”) filed a complaint against Newfield Production Company (“Newfield”) in the United States District Court for the District of Colorado.  Plaintiffs previously sold oil and natural gas assets located in Utah’s Uinta Basin to Newfield pursuant to two Purchase and Sale Agreements, each dated March 21, 2011.  In the complaint, Plaintiffs allege that, prior to the sale, Newfield breached separate confidentiality agreements with Harvest US and Branta by discussing the auction of the assets with a potential bidder for the assets, which caused the potential bidder not to participate in the auction and resulted in a depressed sales price for the assets.  The complaint seeks damages and fees for breach of contract, violation of the Colorado Antitrust Act, violation of the Sherman Antitrust Act and tortious interference with a prospective business advantage.  In September 2015, Plaintiffs amended their complaint to add Ute Energy, LLC and Crescent Point Energy Corporation as defendants.

22

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

Item  4.  Mine Safety Disclosures

Not applicable.

23

PART II

Item  5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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, 2015, there were 51,415,164 shares of common stock outstanding, with approximately 390 stockholders of record. The following table sets forth the high and low sales prices for our common stock reported by the NYSE.

Year	Quarter	High	Low
2014	First quarter	4.80	3.75
	Second quarter	5.30	3.51
	Third quarter	5.01	3.67
	Fourth quarter	3.97	1.68
2015	First quarter	1.09	0.44
	Second quarter	2.08	0.44
	Third quarter	1.65	0.83
	Fourth quarter	1.50	0.43

On March 23, 2015, the last sales price for the common stock as reported by the NYSE was $0.59 a 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.

On December 2, 2015, the Company received notification from the NYSE that the Company had fallen below the NYSE's continued listing standards, which require a minimum average closing price of $1.00 per share over 30 consecutive trading days.  Under the NYSE's rules, Harvest has a period of six months from the date of the NYSE notice to bring its share price and 30 trading-day average share price back above $1.00.  During this period, the Company’s common stock will continue to be traded on the NYSE under the symbol "HNR", subject to the Company’s compliance with other NYSE continued listing requirements, but will be assigned the notation .BC after the listing symbol to signify that the Company is not currently in compliance with the NYSE’s continued listing standards.  As required by the NYSE, in order to maintain its listing, Harvest has notified the NYSE that it intends to cure the price deficiency.  However, there can be no assurance that the Company will be able to do so.While we have not yet received any notification from the NYSE, as of the date of this Report, we believe we may be in noncompliance with a second NYSE continued listing standard, which states that a company will be in noncompliance if its average global market capitalization over a consecutive 30 trading-day period is less than $50.0 million at a time when its stockholders’ equity is less than $50.0 million.  We believe the NYSE will give us an opportunity to cure this deficiency, but there can be no assurance that we will be able to cure or will be given such opportunity before the NYSE commences delisting procedures.

24

Stock Performance Graph

The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2015, assuming an investment of $100 on December 31, 2010 in each of Harvest’s common stock, the Dow Jones U.S. Select Oil 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, 2010 and all dividends were reinvested.

PLOT POINTS

(December 31 of each year)

	2010	2011	2012	2013	2014	2015
Harvest Natural Resources	$          100	$            61	$            75	$            37	$            15	$              4
Dow Jones US E&P Index	$          100	$            97	$          102	$          134	$          118	$            89
S&P 500 Index	$          100	$          102	$          118	$          157	$          178	$          181

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 Select Oil Exploration & Production Index data is accessible for download at http://us.ishares.com/tools/index_tracker.htm under the Sector/Industry selection.

25

Item 6.  Selected Financial Data

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, 2015.

	Year Ended December 31,
	2015		2014		2013		2012		2011
	(in thousands, except per share data)
Operating loss	$	(211,896)	$	(449,605)	$	(45,436)	$	(38,826)	$	(77,155)
Earnings from Investment in Affiliates		—		34,949		72,578		67,769		73,451
Income (loss) from continuing operations (1)		(98,570)		(192,936)		(83,946)		2,199		(30,285)
Net income (loss)  attributable to Harvest		(98,570)		(193,490)		(89,096)		(12,211)		55,960
Net income (loss) from continuing operations attributable to Harvest per common share:
Basic (1)	$	(2.18)	$	(4.59)	$	(2.12)	$	0.06	$	(0.89)
Diluted (1)	$	(2.18)	$	(4.59)	$	(2.12)	$	0.06	$	(0.89)
Weighted average common shares outstanding
Basic		45,288		42,039		39,579		37,424		34,117
Diluted		45,288		42,039		39,579		37,591		34,117
(1) Net of net income attributable to noncontrolling interest owners.
	As of December 31,
	2015		2014		2013		2012		2011
	(in thousands)
Balance Sheet Data:
Total assets	$	47,781	$	228,046	$	734,880	$	596,837	$	507,203
Long-term debt (3)		214		—		—		74,839		31,535
Total Harvest stockholders’ equity (1) (2)		36,759		113,726		302,630		379,337		355,691

(1) No cash dividends were declared or paid during the periods presented.

(2) Net of noncontrolling interest owners.

(3) The carrying value of the long-term debt with related party at December 31, 2015 is $0.2 million, net of discount of $25.0 million.

26

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

Operations

We had a net loss attributable to Harvest of $98.6 million, or $2.18 per diluted share, for the year ended December 31, 2015 compared to a net loss attributable to Harvest of $193.5 million, or $4.60 per diluted share, for the year ended December 31, 2014. Net loss attributable to Harvest for the year ended December 31, 2015 includes $3.9 million of exploration expense, $24.2 million of impairment expense – unproved property costs and oilfield inventories,  $164.7 million of impairment expense – investment in affiliate, $34.5 million gain on change in fair value of warrant liabilities, $4.8 million gain on change in fair value of derivative assets and liabilities, $1.9 million loss on debt conversion, $20.4 million loss on issuance of debt and $16.4 million of income tax benefit. The net loss attributable to Harvest for the year ended December 31, 2014 includes $6.3 million of exploration expense, $58.0 million of impairment expense – unproved property costs, impairment expense – investment in affiliate $355.7 million, $1.6 million of loss on sale of interest in affiliate, $2.9 million of gain on sale of oil and natural gas properties, $2.0 million gain on change in fair value of derivative assets and liabilities, $4.7 million loss on extinguishment of debt, $58.3 million of income tax benefit, net equity income from Petrodelta’s operations of $34.9 million and a loss from discontinued operations of $0.6 million.

Petrodelta

Our 40 percent investment in Petrodelta is owned through our subsidiary, Harvest Vinccler-Dutch Holding B.V. (“Harvest Holding”), a Dutch private company with limited liability.   Up until December 16, 2013 we had an 80 percent interest in Harvest Holding.  On December 16, 2013, Harvest entered into a share purchase agreement (“SPA”) with Petroandina Resources Corporation to sell our 80 percent equity interest in Harvest Holding in two closings for an aggregate cash purchase price of $400.0 million.  The first closing occurred on December 16, 2013 when we sold a 29 percent equity interest in Harvest Holding for $125.0 million.  As a result of the first sale, we own 51 percent of Harvest Holding beginning December 16, 2013 and the non-controlling interest owners hold the remaining 49 percent.

The Company was not able to obtain approval from the government of Venezuela during 2014, which was required to complete the second closing for our remaining 51 percent interest in Petrodelta and on January 1, 2015 we terminated the SPA. Due to our failed sales attempts, lack of management influence, and actions and inactions by the majority owner, PDVSA, we believe we no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.  Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.

We performed an impairment analysis of the carrying value of our investment of Petrodelta as of December 31, 2014.  The estimated fair value of our investment was determined based on the estimated fair value of Petrodelta’s oil and natural gas properties and other net assets as of December 31, 2014, discounted by a factor for economic instability, foreign currency risks and lack of marketability.  Based on this analysis, we recorded a pre-tax impairment charge against the carrying value of our investment in Petrodelta of $355.7 million as of December 31, 2014. 

We also performed an impairment analysis of the carrying value of our investment of Petrodelta as of December 31, 2015 due to the continued decline in world oil prices and deteriorating economic conditions in Venezuela, which have significantly impacted Petrodelta’s operations.  During 2015, Petrodelta’s operating costs exceeded the price realized from the sale of its production due to the significant rate of inflation in Venezuela and the restrictive foreign currency exchange system which Petrodelta is required to operate under.  While we believe that our relationship with CT Energy may allow us to restructure our relationship with PDVSA and Petrodelta and allow us to access the alternative foreign currency systems available to companies in Venezuela, there can be no assurances that we will be successful in these negotiations.  Based on the existing economic environment in which Petrodelta is required to operate, we have concluded that the estimated fair value of our investment in Petrodelta is nil and have recorded a pre-tax impairment charge of $164.7 million to fully impair our investment in Petrodelta as of December 31, 2015. The estimated fair value of our investment was determined based on the estimated fair value of Petrodelta’s oil and natural gas properties and other net liabilities as of December 31, 2015, which exceeded the estimated fair value of the oil and natural gas properties.

27

Certain operating statistics for the years ended December 31, 2015,2014 and 2013 for the fields operated by Petrodelta are set forth below. This information is provided at 100 percent. 

	Year Ended December 31,
	2015		2014		2013
Thousand barrels of oil sold		14,761		15,561		14,538
Million cubic feet of natural gas sold		3,934		2,981		2,593
Total thousand BOE		15,417		16,058		14,970
Average BOE per day		42,237		43,994		41,014
Average price per barrel (b)	$	36.92	$	86.33	$	91.22
Average price per thousand cubic feet	$	1.54	$	1.54	$	1.54
Operating costs  (inclusive of U.S. GAAP adjustment)  (thousands) (a)		(c)	$	289,521	$	141,627
Capital expenditures (thousands)		(c)	$	430,629	$	269,239

(a) See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations, Years Ended December 31, 2014 and 2013, Equity in Earnings from Investment in Affiliate

(b) Includes additional pricing adjustments related to the approved El Salto contract of $60.4 million for previous years that were invoiced in 2014.  Excluding these pricing adjustments, the average crude oil sales price for 2014 was $82.45.

(c) Due to the change in accounting method from equity method to cost method of accounting for our investment in Petrodelta as of December 31, 2014 certain operating statistics for 2015 have been excluded.

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 was extended to May 27, 2016.  The Company is currently assessing extension possibilities for the exploration phase.

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 the 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. 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 downhole tool was retrieved and the DTM-1 well was suspended for future re-entry.  We have met all funding commitments for the third exploration phase of the Dussafu PSC.

Central/inboard 3D seismic data acquired in 2011 has been processed and interpreted to review prospectivity. We have begun processing data from the 1,260 Sq Km of 3D seismic survey performed during the fourth quarter of 2013. This survey provides 3D coverage over the outboard portion of the block where significant pre-salt prospectivity has been recognized on 2D seismic data. The new 3D seismic data also covers the Ruche, Tortue and Moubenga discoveries and is expected to enhance the placement of future development wells in the Ruche and Tortue development program as well as provide improved assessment of the numerous undrilled structures already identified on older 2D seismic surveys.

On March 26, 2014, the joint venture partners approved a resolution that the discovered fields are commercial to exploit.  On June 4, 2014, a Declaration of Commerciality (“DOC”) was signed with Gabon pertaining to the four discoveries on the Dussafu Project offshore Gabon.  Furthermore, on July 17, 2014, the Direction Generale Des Hydrocarbures (“DGH”) awarded an Exclusive Exploitation Authorization (“EEA”) for the development and exploitation of certain oil discoveries on the Dussafu Project and on October 10, 2014, the field development plan was approved.The Company has four years from the date of the EEA approval to begin production.

Since approval of the Field Development Plan (“FDP”) in October 2014, Harvest has continued to move toward development of the Ruche Exclusive Exploitation Area. A tender for all the subsea equipment was concluded in January 2015 where prices exceeded the costs employed in the FDP. Efforts continue to negotiate with the lowest priced vendors and to revise the development scheme to

28

bring the projected cost back to the FDP levels. The depth volume from the 2013 3D seismic acquisition over the discovered fields and the outboard area of the license has been received and interpreted. This new data was incorporated into our reservoir models and optimization of well trajectories to maximize oil recovery is ongoing. In addition, the prospect inventory was updated and several prospects have been high graded for drilling in the first half of 2016. To accommodate the drilling schedule, a site survey, including bathymetry and geophysical data gathering with respect to prospects A/B, 6/7 and 8/9, was completed in August 2015. A tender for a drilling rig for the planned well was completed in November 2015 and a tender for well testing and other services were concluded in January 2016.

Harvest and its joint venture partner engaged a contractor to undertake a fixed-price, geophysical site survey over multiple potential well locations in the Dussafu block in August 2015.  The survey is a pre-requisite for siting mobile drilling units and other installations required for continuing exploration and development activities over the license.  The survey will provide information about the seabed and shallow geological conditions, essential for the safe siting and operation of these installations.

During the year ended December 31, 2015, we had cash capital expenditures of $0.9 million for site survey  ($1.2 million for well costs during the year ended December 31, 2014). The 2016 budget for the Dussafu PSC is $3.6  million. See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon for further information on the Dussafu Project.

The Company is considering options to develop, sell or farm-down its interest in the Dussafu Project in order to obtain the maximum value from the asset, while maintaining the required liquidity to continue our current operations. 

In December 2014, the Company recorded a $50.3 million impairment related to the unproved costs of the Dussafu PSC based on a qualitative analysis which considered our current liquidity needs, our inability to attract additional capital and the decrease in oil and natural gas prices.  In December 2015, the Company reassessed the carrying value of the unproved costs related to the Dussafu PSC and recorded an additional impairment of $23.2 million based on its analysis of the value of the unproved costs which considered the value of the contingent and exploration resources and the ability of the Company to develop the project given its current liquidity situation and the depressed price of crude oil.

We reviewed the value of our oilfield inventories that are in the country of Gabon, of which the majority is steel conductor and casing.  We impaired the value of this inventory by approximately $1.0 million, leaving $3.0 million related to this inventory as of December 31, 2015.

Colombia – Discontinued Operations

In February 2013, we signed farm-down agreements on Block VSM14 and Block VSM15 in Colombia. Under the terms of the farm-down 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 natural gas regulatory authority, and approval of us as operator.

For both blocks, phase one of the contract began on December 15, 2012 and expired on December 15, 2015. We have received notices of default from our partners for failing to comply with certain terms of the farm-down agreements for Block VSM14 and Block VSM15, followed by notices of termination on November 27, 2013. Our partners 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 which included an accrual of $2.0 million related to this matter.  On December 14, 2014 we paid our partners $2.0 million to settle the arbitration. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations. We are in the process of closing and exiting our Colombia venture. 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 – Discontinued Operations for further information on this project.

Results of Operations

The following discussion on results of operations for each of the years in the three-year period ended December 31, 2015 should be read in conjunction with our consolidated financial statements and related notes thereto.

Years Ended December 31, 2015 and 2014

We reported a net loss attributable to Harvest of $98.6 million, or $2.18 diluted earnings per share, for the year ended December 31, 2015, compared with a net loss attributable to Harvest of $193.5 million, or $4.60 diluted earnings per share, for the year ended December 31, 2014.

29

Loss From Continuing Operations

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

	Year Ended December 31,				Increase
	2015		2014		(Decrease)
	(in thousands)
Depreciation and amortization	$	108	$	198	$	(90)
Exploration expense		3,900		6,267		(2,367)
Impairment expense - unproved property costs and oilfield inventories		24,178		57,994		(33,816)
Impairment expense - investment in affiliate		164,700		355,650		(190,950)
General and administrative		19,010		29,496		(10,486)
Loss on sale of interest in Harvest Holding		—		1,574		(1,574)
Gain on sale of oil and gas properties		—		(2,865)		2,865
Change in fair value of warrant liabilities		(34,510)		(1,953)		(32,557)
Change in fair value of derivative assets and liabilities		(4,813)		—		(4,813)
Interest expense		2,959		11		2,948
Loss on issuance of debt		20,402		—		20,402
Loss on debt conversion		1,890		—		1,890
Loss on extinguishment of long-term debt		—		4,749		(4,749)
Foreign currency transaction (gains) losses		(261)		219		(480)
Other non-operating (income) expense		(483)		58		(541)
Income tax benefit		(16,423)		(58,290)		41,867
Earnings from investment in affiliate		—		(34,949)		34,949
Loss from continuing operations	$	180,657	$	358,159	$	(177,502)

Our accounting method for oil and natural gas properties is the successful efforts method. During the year ended December 31, 2015, we incurred $3.5 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations and $0.4 million related to other general business development activities. During the year ended December 31, 2014, we incurred $5.7 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations and $0.6 million related to other general business development activities.

During the years ended December 31, 2015 and 2014, we recorded impairment expense, related to our Dussafu Project in Gabon, of $24.2 million (including $1.0 million relating to oilfield inventories) and $50.3 million, respectively, which reflect management’s estimate of the decreased value of the project given our current liquidity situation and the decline in global crude oil prices.  During 2014, we also recognized impairments related to our Budong Project in Indonesia of $7.7 million.

We recorded pre-tax impairment charges against the carrying value of our investment in Petrodelta of $164.7 million and $355.7 million at December 31, 2015 and 2014, respectively. 

The decrease in general and administrative costs in the year ended December 31, 2015 from the year ended December 31, 2014, was primarily due to lower employee related costs ($0.1 million), general operations and overhead ($11.4 million),  taxes other than income ($0.6 million) and travel ($0.1 million) offset by higher professional fees and contract services ($1.7 million).  General operations and overhead is lower primarily due to recording an allowance on doubtful accounts for dividend and accounts receivables from investment in affiliate of $13.8 million in 2014 and lower billings to our joint venture partners offset byrecording an allowance on doubtful accounts for $0.7 million blocked payment related to our drilling operations in Gabon in 2015.  See Part IV – Item 15 – Exhibits and Financial Statements Schedules, Note 3 – Summary of Significant Accounting Policies, Other Assets.  Professional fees are higher due to higher litigation and consulting costs offset by lower audit fees in 2015 compared to 2014.

The $1.6 million loss on the sale of interest in Harvest Holding in the year ended December 31, 2014 relates to costs incurred during the period in connection to the failed second closing of our remaining 51 percent in Harvest Holding.

The $2.9 million gain on sale of oil and natural gas properties during the year ended December 31, 2014 relates to the sale of our rights under a petroleum contract with China National Offshore Oil Corporation.  The Company fully impaired this property in 2012. 

The change in fair value of the warrant liability of $34.5 million during the year ended December 31, 2015 was related to the decrease in fair value of the CT Warrant issued to CT Energy on June 19, 2015.  The fair value decreased due to a decrease in our closing stock price.The change in the fair value of the derivative assets and liabilities of $2.0 million during year ended December 31, 2014 was related to the change in fair value of 1,846,088 warrants issued as inducements under the warrant agreements dated October 2010 in connection with the $60.0 million term loan facility that was repaid in May 2011.  On October 28, 2015, the

30

1,846,088 warrants expired.  See Part IV – Item 15 – Exhibits and Financial Statements Schedules, Note 11 – Debt and Financing and Note 12 – Warrant Derivative Liabilities for further information.

The change in the fair value of the derivative assets and liabilities of $4.8 million during year ended December 31, 2015 was related to the increase in the fair value of the embedded derivative asset of $1.0 million and the decrease in fair value of the derivative liability related to the 9% Note which was converted on September 15, 2015.

The increase in interest expense in the year ended  December 31, 2015 from the year ended December 31, 2014 was primarily due to higher outstanding debt balances and higher rates of interest during the year ended December 31, 2015.

On June 19, 2015, we issued the CT Warrant, 9% and 15% Notes, Additional Draw Note and Series C preferred stock in connection with the Purchase Agreement with CT Energy and received proceeds of $30.6 million, net of financing fees of $1.6 million.  We identified embedded derivative assets and liabilities in the notes and determined that the CT Warrant did not meet the required conditions to qualify for equity classification and is required to be classified as a warrant liability (See Part IV – Item 15 – Exhibits and Financial Statement Schedules, Note 11 – Warrant Derivative Liabilities).  The estimated fair value, at issuance, of the embedded derivative asset was $2.5 million, the embedded derivative liability was $13.5 million and the CT Warrant was $40.0 million.  In accordance with ASC 815, the fair value of the financial instruments was first allocated to the embedded derivatives and warrants, which resulted in no value being attributable to the Series C preferred stock, the 9% and 15% Notes and theAdditional Draw Note. As a result of the allocation we recognized a loss on the issuance of these securities of $20.4 million during the year ended December 31, 2015.

On September 15, 2015, the 9% Note, the associated accrued interest and related derivative liability were converted into 8,667,597 shares of the Company’s common stock.  The Company recognized a $1.9 million loss on debt conversion.   The $1.9 million loss on debt conversion was the result of the difference between the September 14, 2015 carrying value of the 9% Note, including accrued interest and unamortized debt discount ($0.2 million) and the fair value of therelated derivative liability  ($11.1 million) less the fair value of the 8,667,597 shares issued upon conversion  ($13.2 million) at September 15, 2015.

During the year ended December 31, 2014, we incurred a loss on extinguishment of debt of $4.7 million in connection with the repayment of the 11% senior unsecured notes due in 2014 (“11% Senior Notes”).

We recognized a gain on foreign currency transactions for the year ended  December 31, 2015 of $0.3 million as compared to $0.2 million loss on foreign currency transactions for the year ended December 31, 2014.  The gain in 2015 was primarily associated with a favorable change in the Bolivar denominated liabilities.  The loss in 2014 is primarily related to converting USD to Bolivars from participating in the SICAD II auctions and USD to Euros.

The non-operating income of $0.5 million for the year ended December 31, 2015 was primarily related to the reduction of estimated final settlement costs associated with prior financings compared to non-operating expense of $0.1 million for the year ended December 31, 2014 for costs related to our strategic alternative process and evaluation.

We had an income tax benefit in the year ended December 31, 2015 of $16.4 million as compared to an income tax benefit of $58.3 million in the year ended December 31, 2014.  The benefit for the year ended December 31, 2015 was primarily attributable to a reduction in the valuation allowance against the Company’s deferred tax assets for a claim for refund of 2013 taxes and a decrease in the deferred tax liability associated with the Company’s undistributed earnings from its foreign subsidiaries.  In the fourth quarter of 2014, we reinstated a valuation allowance against the Company’s U.S. deferred tax assets as we determined that we would not have sufficient taxable income in the U.S. after the termination of the sale of the remaining equity interest in Harvest Holding.  We have not recognized a tax benefit on the Company’s losses arising during the year ended December 31, 2015; although the valuation allowance was reduced by an expected refund of alternative minimum tax from the carryback of 2014 losses to 2013.

Earnings from Investment in Affiliate

Our 40 percent investment in Petrodelta’s financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”) which we have adjusted to conform to U.S. GAAP. See Part IV –  Item 15 –  Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Investment in Affiliate. 

Through December 31, 2014, we included the results of Petrodelta in our financial statements under the equity method.  We ceased recording earnings from Petrodelta in the second quarter due to the expected sales price of the second tranche purchase agreement approximating the recorded value of our investment in Petrodelta.  During the year ended December 31, 2014 we recognized $34.9 million of equity in earnings from our investment in Petrodelta.  Accordingly we do not summarize revenue and operational results associated with our investment in affiliate for 2015 or provide analysis of the reported variancesof the revenues and operational expenses for Petrodelta.  As previously discussed in Item 1. Business, Executive Summary, we believe we no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 325 – Investments – Other”, we began reporting the results of our Venezuelan operations using the cost method of accounting effective December 31, 2014.

31

Net Loss Attributable to Noncontrolling Interest Owners

Net loss attributable to noncontrolling interest owners  was $82.1 million for year ended December 31, 2015 compared to net loss attributable to noncontrolling interest owners of $165.2 million year ended December 31, 2014.  The net loss attributable to noncontrolling interest owners in 2015 was related to the impairment of our investment in Petrodelta as well as to our ongoing operations at Harvest Vinccler as they continue oversight of our investment in Petrodelta.  The net loss attributable to noncontrolling interest owners in 2014 was related to the impairment of our investment in Petrodelta and our decision to cease recording earnings from Petrodelta in the second quarter due to the expected sales price of the second tranche purchase agreement approximating the recorded value of our investment in Petrodelta. 

Discontinued Operations

Oman

As a result of the decision to not request an extension of the first phase or enter the second phase of the 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 nominal loss from discontinued operations for Oman for the year ended  December 31, 2014 included general and administrative expenses for legal and other professional fees.

Colombia

We received notices of default from our partners for failing to comply with certain terms of the farm-down agreements for Block VSM14 and Block VSM15 in Colombia, followed by notices of termination on November 27, 2013. As discussed further in Item 3. Legal Proceedings, our partners filed for arbitration of claims related to these agreements. We accrued $2.0 million as of December 31, 2013 related to obligations under the farm-down agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests.  On December 14, 2014 we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations. We are in the process of closing and exiting our Colombia venture. The loss from discontinued operations included $0.5 million in general and administrative expenses during the year ended December 31, 2014. 

Oman and Colombia operations have been classified as discontinued operations. There were no revenues applicable to discontinued operations during the years ended December 31, 2015 and 2014. Losses from discontinued operations were:

	Year Ended December 31,
	2015		2014
	(in thousands)
Oman	$	—	$	(27)
Colombia		—		(527)
Net loss from discontinued operations	$	—	$	(554)

Years Ended December 31, 2014 and 2013

We reported a net loss attributable to Harvest of $193.5 million, or $4.60 diluted earnings per share, for the year ended December 31, 2014, compared with a net loss attributable to Harvest of $89.1 million, or $2.25 diluted earnings per share, for the year ended December 31, 2013.

32

Loss From Continuing Operations

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

	Year Ended December 31,				Increase
	2014		2013		(Decrease)
	(in thousands)
Depreciation and amortization	$	198	$	341	$	(143)
Exploration expense		6,267		15,155		(8,888)
Impairment expense - unproved property costs and oilfield inventories		57,994		575		57,419
Impairment expense - investment in affiliate		355,650		—		355,650
General and administrative		29,496		29,365		131
Loss on sale of interest in Harvest Holding		1,574		22,994		(21,420)
Gain on sale of oil and natural gas properties		(2,865)		—		(2,865)
Change in fair value of warrant liabilities		(1,953)		(3,517)		1,564
Interest expense		11		4,495		(4,484)
Loss on extinguishment of long-term debt		4,749		—		4,749
Foreign currency transaction losses		219		820		(601)
Other non-operating expense		58		1,569		(1,511)
Income tax expense (benefit)		(58,290)		73,087		(131,377)
Earnings from investment in affiliate		(34,949)		(72,578)		37,629
Loss from continuing operations	$	358,159	$	72,306	$	285,853

Our accounting method for oil and natural gas properties is the successful efforts method. During the year ended December 31, 2014, we incurred $5.7 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations and $0.6 million related to other general business development activities. 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, 2014, we impaired $7.7 million related to our Budong Project in Indonesia and $50.3 million related to the Dussafu Project in Gabon.  During the year ended December 31, 2013, we impaired $0.6 million related to our Budong Project in Indonesia.

We performed an impairment analysis of the carrying value of our investment in Petrodelta.  The estimated fair value of our interest in Petrodelta was less than its carrying value.  Based on this assessment we recorded a pre-tax impairment charge of $355.7 million against the carrying value of our investment during the year ended December 31, 2014.

General and administrative costs were consistent between the years ended December 31, 2014 and 2013.

The $1.6 million loss on sale of interest in Harvest Holding in the year ended December 31, 2014 relates to costs incurred during the period in connection to the failed second closing of our remaining 51 percent in Harvest Holding.  The $23.0 million loss on the sale of interest in Harvest Holding during the year ended December 31, 2013 relates to the sale of our 29 percent equity interest in Harvest Holding to Petroandina, which occurred on December 16, 2013.

The $2.9 million gain on sale of oil and natural gas properties during the year ended December 31, 2014 relates to the sale of our rights under a petroleum contract with China National Offshore Oil Corporation.  The Company fully impaired this property in 2012. 

The decrease in change in fair value of the warrant in the year ended December 31, 2014 from the year ended December 31, 2013 was due to a decrease in the estimated fair value for the MSD warrant derivative liability from $1.07 per warrant to zero.  The valuation for the MSD warrants is based primarily on our closing stock price of $1.81 at December 31, 2014, their remaining life of 0.83 years and their strike price of $12.81 at December 31, 2014.

The decrease in interest expense in the year ended December 31, 2014 from the year ended December 31, 2013 was due to the repayment of the 11% Senior Notes on January 11, 2014.

During the year ended December 31, 2014, we incurred a loss on extinguishment of debt of $4.7 million in connection with the repayment of the 11% Senior Notes.

We recognized a loss on foreign currency transactions for the year ended December 31, 2014 of $0.2 million as compared to $0.8 million loss on foreign currency transactions for the year ended December 31, 2013.  The loss in 2014 was primarily related to converting USD to Bolivars from participating in the SICAD II auctions and USD to Euros, while the loss in 2013 is primarily related to converting USD to Euros offset by a gain from converting USD to Bolivars from exchanging currency through the Central Bank of Venezuela (BCV). 

33

The decrease in other non-operating expense in the year ended December 31, 2014 from the year ended December 31, 2013 was due to higher costs incurred in 2013 related to our strategic alternative process and evaluation.

We had an income tax benefit in the year ended December 31, 2014 of $58.3 million as compared to an income tax expense of $73.1 million in the year ended December 31, 2013.  The income tax benefit in 2014 is primarily due to a decrease in the deferred tax liability related to the unremitted earnings of our foreign subsidiary as a result of the impairment of our investment in Petrodelta partially offset by the reinstatement of a valuation allowance against Harvest’s U.S. deferred tax assets.  The income tax expense in 2013 included $89.9 million of deferred income tax related to previously unrecognized income tax on undistributed earnings of 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 losses in 2012 and a benefit of $2.2 million from the favorable resolution of certain tax contingencies.

Earnings from Investment in Affiliate

Our 40 percent investment in Petrodelta’s financial information is prepared in accordance with IFRS which we have adjusted to conform to U.S. GAAP. SeePart IV –  Item 15 –  Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Investment in Affiliate.  

Through December 31, 2014, Petrodelta was considered an equity investment.  We ceased recording earnings from Petrodelta in the second quarter of 2014 due to the expected sales price of the second tranche purchase agreement approximating the recorded value of our investment in Petrodelta.  Due to this limitation during the year ended December 31, 2014, we recognized $34.9 million of equity in earnings from our investment in Petrodelta compared to $72.6 million in 2013.  We began reporting the results of our operations for Petrodelta using the cost method of accounting effective December 31, 2014.

The following tables summarize revenue and operational results associated with our investment in affiliate for the presented years and provide analysis of the reported variances:

							%
	Year Ended December 31,				Increase		Increase		Increase
	2014		2013		(Decrease)		(Decrease)		(Decrease)
	(dollars in thousands, except prices)
Revenues:
Crude oil	$	1,343,452	$	1,326,093	$	17,359	1	%
Natural gas		4,590		4,000		590	15	%
Total revenues	$	1,348,042	$	1,330,093	$	17,949	1	%
Price and Volume Variances:
Crude oil price variance (per Bbl)	$	86.33	$	91.22	$	(4.89)	(5.36)			$       (70,965)
Natural gas sales prices Variance (per Mcf)		1.54		1.54		—	—			—
Volume variances:
Crude oil volumes (MBbls)		15,561		14,538		1,023	7	%		88,316
Natural gas volumes (MMcf)		2,981		2,593		388	15	%		598
Total variance									$	17,949

Revenues were higher in the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to an increase in sales volumes resulting from running a six drilling rig program as well as an additional pricing adjustments related to the approved El Salto contract, $38.2 million for 2014 and $60.4 million for previous years that were invoiced in 2014 offset by a decrease in crude oil prices.  The decrease in price primarily reflects an overall decrease in market oil prices, but also resulted from increased El Salto field production, which is sold at the lower Boscan price. 

34

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

	Year Ended December 31,				Increase
	2014		2013		(Decrease)
	(in thousands)
Royalties	$	437,281	$	440,963	$	(3,682)
Operating expenses (inclusive of U.S. GAAP adjustment)		289,521		141,627		147,894
Workovers		28,239		29,168		(929)
Depletion, depreciation and amortization (inclusive of U.S. GAAP adjustment)		141,846		107,556		34,290
General and administrative		45,623		37,778		7,845
Windfall profits tax (inclusive of U.S. GAAP adjustment)		140,816		234,453		(93,637)
(Gain) loss on exchange rate		260		(169,582)		169,842
Investment earnings and other		(7,752)		(1,414)		(6,338)
Interest expense (inclusive of U.S. GAAP adjustment)		51,256		21,728		29,528
Income tax expense (inclusive of U.S. GAAP adjustment)		73,843		298,475		(224,632)
Adjustment stated at our 40% interest related to amortization of excess basis		4,428		3,684		744

For the year ended December 31, 2014 compared to the year ended December 31, 2013, royalties, which is a function of revenue, decreased due to the decrease in crude oil prices offset by an increase in sales volumes discussed above (net increase in revenue of $17.9 million at 30 percent royalty). The increase in operating expense is due to higher personnel costs as a result of new labor contract, higher maintenance costs and increased chemical costs. Workover expense is lower for the year ended December 31, 2014 than the year ended December 31, 2013 due to running one workover rig in 2014 versus between one and two workovers rigs in 2013.  Depletion, depreciation and amortization increased as a result of higher capitalized costs, including wells and infrastructure placed in service during 2014. Windfall profits tax expense decreased from declining Venezuela crude basket prices in line with declining world oil prices in 2014.  The foreign currency transaction gain in 2013 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.  Interest expense is due to increase in adjustments to the fair value of VAT credits ($47.7 million) offset by decrease accretion expense ($18.2 million).  Income tax expense decreased between the years primarily due to a revision to inflation adjustments to fixed assets and by the decrease in pre-tax income.

Net Income Attributable to Noncontrolling Interests Owners

Net loss attributable to noncontrolling interest owners was $165.2 million for the year ended December 31, 2014 compared to net income attributable to noncontrolling interest owners of $11.6 million for year ended December 31, 2013.  The net loss attributable to noncontrolling interest owners in 2014 was related to the impairment of our investment in Petrodelta and our decision to cease recording earnings from Petrodelta in the second quarter due to the expected sales price of the second tranche purchase agreement approximating the recorded value of our investment in Petrodelta.  During 2013 the net income attributable to noncontrolling interest owners was impacted by the sale of a portion of our interest in Harvest Holding which occurred in December.

Discontinued Operations

Oman

As a result of the decision to not request an extension of the first phase or enter the second phase of the 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 nominal loss from discontinued operations for Oman for the year ended December 31, 2014 included general and administrative expenses for legal and other professional fees. The loss from discontinued operations for Oman of $0.7 million for the year ended December 31, 2013 included $0.2 million of exploration expense and $0.5 million of general and administrative expenses and other expenses.

Colombia

We received notices of default from our partners for failing to comply with certain terms of the farm-down agreements for Block VSM14 and Block VSM15 in Colombia, followed by notices of termination on November 27, 2013. Our partners filed for arbitration of claims related to these agreements. We accrued $2.0 million as of December 31, 2013 related to obligations under the farm-down agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests.  On December 14, 2014 we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations. We are in the process of closing and exiting our Colombia venture. The loss from discontinued operations included $0.5 million in general and administrative expenses for primarily contract service during the year ended December 31, 2014.  The loss from

35

discontinued operations included $3.2 million in impairment expense, $0.7 million of exploration expense and $0.6 million in general and administrative expenses for contract services and travel during the year ended December 31, 2013.

Oman and Colombia operations have been classified as discontinued operations. There were no revenues applicable to discontinued operations during the years ended December 31, 2014 and 2013. Losses from discontinued operations were:

	Year Ended December 31,
	2014		2013
	(in thousands)
Oman	$	(27)	$	(674)
Colombia		(527)		(4,476)
Net loss from discontinued operations	$	(554)	$	(5,150)

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

Our financial statements for the year ended December 31, 2015 have been prepared under the assumption that we will continue as a going concern. We expect that in 2016 we will not generate revenues, we will continue to generate losses from operations, and that our operating cash flows will not be sufficient to cover our operating expenses. While we believe that we may be able to raise additional capital through issuances of debt or equity or through sales of assets, our circumstances at such time raise substantial doubt about our ability to continue to operate as a going concern. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Our current capital resources may not be sufficient to support our liquidity requirements through 2016.  However, we believe certain cost reduction measures could be put into place which would not jeopardize our operations and future growth plans.  In addition, we could delay the discretionary portion of our capital spending to future periods or sell or farm-down our interest in our Gabon asset as necessary to maintain the liquidity required to run our operations, as warranted.  There are no assurances that we will be successful in selling or farming-down this asset.

Our ability to continue as a going concern depends upon the success of our planned exploration and development activities and the ability to secure additional financing as needed to fund our current operations.  There can be no guarantee of future capital acquisition, fundraising or exploration success or that we will realize the value of our unevaluated exploratory well costs.  We believe that we will continue to be successful in securing any funds necessary to continue as a going concern.  However, our current cash position and our inability to access additional capital may limit our available opportunities or not provide sufficient cash for operations.

The long-term continuation of our business plan through 2016 and beyond is dependent upon the generation of sufficient cash flow to offset expenses.  We will be required to obtain additional funding through public or private financing, farm-downs, further reduce operating costs, or possible sales of assets.  Failure to generate sufficient cash flow by raising additional capital through debt or equity financings, reducing operating costs, or by farm-downs or selling of assets further could have a material adverse effect on our ability to meet our short- and long-term liquidity needs and achieve our intended long-term business objectives.

Historically, prior to the transaction pursuant to the Purchase Agreement with CT Energy, our primary ongoing source of cash had been dividends from Petrodelta, issuance of debt and the sale of oil and natural gas properties. Our primary use of cash has been to fund oil and natural gas exploration projects, principal payments on debt, interest, and general and administrative costs. We require capital principally to fund the exploration and development of new oil and natural gas properties. As is common in the oil and natural gas industry, we have various contractual commitments pertaining to exploration, development and production activities.  

The Company is assessing alternativesto farm-down or sell our interest in the Dussafu Project, while weighing the liquidity requirements necessary to maintain ongoing Company operations.  The development of, or a transaction regarding, the Dussafu project and the success of negotiations between PDVSA, CT Energy, and HNR Finance for the management of Petrodelta will directly impact our future earnings, cash flows, and balance sheet.  Without these transactions or additional financings or other sources of cash, we may not have sufficient liquidity for operations or capital requirements.  There can be no guarantee of realizing the value of our exploration and exploitation acreage or suspended wells in the Dussafu project or our investment in Petrodelta or that we can obtain further financings or sources of cash.

On June 19, 2015, CT Energy purchased from the Company 9% and 15% Notes and the CT Warrant. The Company immediately received gross proceeds of $32.2 million from the sale of the securities.  The Company used $9.7 million of these

36

proceeds to repay its existing debt plus accrued interest and certain financing fees. The remaining proceeds will be used to position the Company for long-term growth, both in Venezuela and Gabon as well as to fund general and administrative costs.  On September 15, 2015, the 9% Note and associated accrued interest was converted into 8,667,597 shares of Harvest common stock.  See Part IV – Item 15 – Exhibit and Financial Statement Schedules, Note 1 – Organization for further information. 

As of December 31, 2014, HNR Energia had a note payable to Petroandina of $7.6 million. Principal was due by January 1, 2016.  Interest payments were to be paid quarterly beginning on December 31, 2014.  On June 23, 2015 the Company repaid the note payable of $7.6 million plus accrued interest of $0.4 million.

At December 31, 2014, HNR Energia had a note payable to Vinccler of $6.1 million. Principal and interest were payable upon the maturity date of December 31, 2015.  On March 6, 2015, Vinccler forgave the note payable and accrued interest of $6.2 million.  This was reflected as a contribution to stockholders’ equity.

Accumulated Undistributed Earnings of Foreign Subsidiaries

Under ASC 740-30-25-17, no deferred tax liability must be recorded if sufficient evidence shows that a foreign subsidiary has invested or will invest its 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.

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 into our foreign operations.  During the fourth quarter of 2013, management evaluated numerous factors related to the timing and amounts of possible future distribution of foreign earnings to the parent company, with consideration of the sale of non-U.S. assets. Because management was pursuing various alternatives with respect to the Company’s future operations and disposition of any sale proceeds, 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. However, due primarily to the $355.7 million pre-tax impairment of Petrodelta, this balance decreased by $75.2 million to $14.7 million at December 31, 2014.

As of December 31, 2015, the book-tax outside basis difference in our foreign subsidiary resulting from unremitted earnings was reduced to zero due to a pre-tax impairment of the Company’s remaining investment in Petrodelta of $164.7 million.  Consequently, the deferred tax liability associated with the foreign earnings was reduced to zero. The entire net deferred tax liability as of December 31, 2014 has been reflected as a long-term liability, a characterization consistent with the Company’s adoption of Accounting Standards Update (“ASU”) No. 2015-17.  See New Accounting Pronouncements for further information.

Working Capital and Cash Flows

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

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Net cash used in operating activities	$	(23,892)	$	(39,210)	$	(37,077)
Net cash provided by (used in) investing activities		(1,270)		(5,031)		80,460
Net cash provided by (used in) financing activities		26,338		(70,071)		4,887
Net increase (decrease) in cash	$	1,176	$	(114,312)	$	48,270

37

	As of December 31,
	2015		2014		2013
	(in thousands, except ratios)
Working capital	$	6,232	$	(12,951)	$	88,894
Current ratio		2.3		0.4		3.5
Total cash, including restricted cash	$	7,761	$	6,610	$	121,045
Total debt (net of discount)	$	214	$	13,709	$	83,589

Working Capital

The increase in working capital of $19.2 million between December 31, 2014 and December 31, 2015  was primarily due to cash proceeds from issuance of debt and the CT Warrant in the CT Energy transaction offset by cash used to fund our loss from operations, capital expenditures and interest payments on notes payable and the 9% and 15% Notes.

The decrease in working capital of $101.8 million between December 31, 2013 and December 31, 2014 was primarily due to cash used to fund our loss from operations, interest payments as well as the extinguishment of certain debt in January 2014. 

Cash Flow from Operating Activities

During the year ended December 31, 2015, net cash used in operating activities was approximately $23.9 million ($39.2 million during the year ended December 31, 2014). The $15.3 million decreasein use of cash from operations was primarily from the decreased use of working capital in 2015 due to our decreased activity levels.

Cash Flow from Investing Activities

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

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Budong PSC	$	—	$	3,152	$	175
Dussafu PSC		947		1,194		42,536
Other		323		36		—
Total additions of property and equipment – continuing operations		1,270		4,382		42,711
Colombia-discontinued operations (1)		—		—		1,195
Total additions of property and equipment	$	1,270	$	4,382	$	43,906

(1) See Part IV –  Item 15 – Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 5 – Dispositions, Discontinued Operations.

Our only investing activities in during the year ended December 31, 2015 were cash capital expenditures. 

In addition to cash capital expenditures, during the year ended December 31, 2014 we:

· Paid $3.7 million in transaction costs associated with the failed sale of Harvest Holding;

· Received $2.9 million net of associated costs related to the sale of leasehold WAB-21 area;

· Received payments from Petrodelta to offset against advances to Petrodelta for continuing operations of $0.1 million;

· Had $0.1 million in restricted cash returned to us related to the Dussafu PSC.

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

· Received $124.0 million in net proceeds from the first Petroandina closing;

· Advanced $0.5 million to Petrodelta for continuing operations costs;

· Had $1.0 million in restricted cash returned to us and deposited with a U.S. bank $0.1 million for a customs bond related to the Dussafu PSC.

Our budgeted capital expenditures of $4.0  million for 2016 for U.S. and Gabon 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.

38

Cash Flow from Financing Activities

During the year ended December 31, 2015, we:

· Repaid $7.6 million of our note payable to Petroandina and repaid a bridge loan of  $1.3 million of our note payable to CT Energy;

· Received $33.5 million in proceeds from issuance of debt;

· Received $3.4 million in contributions from noncontrolling interest owners;

· Incurred $1.6 million in legal and other fees associated with the CT Energy financing.

During the year ended December 31, 2014, we:

· Repaid $79.8 million of our 11% Senior Notes;

· Incurred $0.8 million in debt extinguishment costs;

· Received $7.6 million from issuance of note payable from noncontrolling interest owner;

· Received $2.0 million in net proceeds from issuance of 653,832 shares of common stock from the “at-the-market” offerings;

· Received $1.2 million in contributions from controlling interest owners;

· Incurred $0.1 million in treasury stock purchases;

· Incurred $0.3 million in legal fees associated with financings.

During the year ended December 31, 2013, we:

· Sold 2,494,800 shares of our common stock in private placements for $9.4 million;

· Incurred $0.1 million in treasury stock purchases;

· Made a payment of $4.3 million on our note payable to O&G Technology Consultants, a noncontrolling interest owner;

· Incurred $0.2 million in legal fees associated with financings.

Contractual Obligations

At December 31, 2015, we had the following lease commitments for office space in Houston, Texas and regional office in Caracas, Venezuela.

Location	Date Lease Signed	Term	Annual Expense
Houston, Texas	December 2014	1.8 years	81,100
Caracas, Venezuela	December 2015	1.0 years	83,100

39

At December 31, 2015, we had the following contractual obligations:

	Payments Due by Period
			Less than
	Total		1 Year		1 - 2 Years		3-4 Years		After 4 Years
	(in thousands)
Debt:
15% Note with related party (1)	$	25,225	$	—	$	—	$	—	$	25,225
Total debt		25,225		—		—		—		25,225
Other obligations:
Interest payments		17,494		3,923		3,913		3,913		5,745
Oil and natural gas activities (2)		4,520		1,130		1,130		1,130		1,130
Office leases		171		157		14		—		—
Total other obligations		22,185		5,210		5,057		5,043		6,875
Total contractual obligations	$	47,410	$	5,210	$	5,057	$	5,043	$	32,100

1) The carrying value of the 15% Note at December 31, 2015 was $0.2 million, net of $25.0 million of unamortized discount On January 4, 2016, the outstanding principal amount of the 15% Note increased to $26.1 million as a result of the capitalization of accrued interest of $0.8 million.

2) “Oil and natural gas activities” in the table above includes various contractual commitments pertaining to leasehold, training and development costs.

15% Non-Convertible Senior Secured Note due June 19, 2020

On June 19, 2015, in connection with the transaction with CT Energy described in Part IV – Item 15 – Exhibits and Financial Statements Schedules Note 1 – Organization, we issued the five-year, 15% Note in the aggregate principal amount of $25.2 million with interest that is compounded quarterly at a rate of 15.0% per annum and is payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2015.  If by June 19, 2016, the volume weighted average price of the Company’s common stock over any consecutive 30-day period has not equaled or exceeded $2.50 per share, the maturity date of the 15% Note will be extended by two years and the interest rates on the 15% Note will adjust to 8.0% (the “15% Note Reset Feature”).  During an event of default, the outstanding principal amount bears additional interest at a rate of 2.0% per annum higher than the rate otherwise applicable.   See Part IV – Item 15 – Exhibits and Financial Statements Schedules, Note 11 – Debt and Financing. 

Effects of Changing Prices, Foreign Exchange Rates and Inflation

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

Our net foreign exchange gain attributable to our international operations was $0.3 million for the year ended December 31, 2015 compared to $0.2 million loss on foreign currency transactions for the year ended December 31, 2014.  The gains in 2015 are primarily associated with favorable changes in the Bolivar denominated liabilities. The loss in 2014 is primarily related to converting USD to Bolivars from participating in the SICAD II auctions and USD to Euros.  There are many factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our control.Petrodelta, our investment in affiliate, is required to follow the foreign exchange controls placed on PDVSA which requires them to use a 6.3 Bolivars per USD exchange rate.  Harvest Vinccler is able to bring money into the country using the SIMADI foreign exchange system which is at  a 200 Bolivars per USD exchange rate.  The foreign exchange gains and losses referred to here are generated from activity of Harvest Vinccler and not Petrodelta. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.

On March 9, 2016, Venezuela Vice President for Economic Area announced a new exchange agreement No.35 (the “Exchange Agreement No.35”).  Exchange Agreement No. 35 was published in Venezuela’s Official Gazette No. 40865 dated March 9, 2016, and became effective on March 10, 2016.  Exchange Agreement No. 35 will have a dual exchange rate for a controlled rate (named DIPRO) fixed at 10 USD/Bolivars for priority goods and services and a complimentary rate (named DICOM) starting at 206.92 USD/Bolivars for travel and other non-essential goods.  We are evaluating the impact Exchange Agreement No. 35 has on Harvest Vinccler and Petrodelta.

40

Harvest Vinccler’s functional and reporting currency is the USD. They do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”) (198.70 Bolivars per USD).

Within the United States and other countries in which we conduct business, inflation has had a minimal effect on us, but it is an important factor with respect to certain aspects of the results of operations in Venezuela. The 2015annual inflation rate in Venezuela provided by the Central Bank of Venezuela (BCV) through December 2015 was 180.9 percent.

Critical Accounting Policies

Reporting and Functional Currency

USD is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. Amounts denominated in non-USD currencies are re-measured into USD, and all currency gains or losses are recorded in the consolidated statements of operations and comprehensive loss. There are many factors that affect foreign exchange rates and the resulting exchange gains and losses, many of which are beyond our influence.

Investment in Affiliate

We evaluate our investments in unconsolidated companies under “ASC 323 – Investments – Equity Method and Joint Ventures” and “ASC 325 – Investments – Other”.In accordance with ASC 323, investments in which we have significant influence were accounted for under the equity method of accounting. Under the equity method, our Investment in Affiliate was increased by additional investments and earnings and decreased by dividends and losses. We review our Investment in Affiliate for impairment whenever events and circumstances indicate a loss in investment value is other than a temporary decline.  Once an event is identified that is other than temporary, a loss is recognized and the Investment in Affiliate is reduced to fair value.

Investments where we do not have significant influence are accounted for in accordance with ASC 325.  Under this method we will not recognize any equity in earnings from our investments in our results of operations, but will recognize any cash dividends in the period they are received.  We review our Investment in Affiliate for impairment whenever events and circumstances indicate a loss in investment value is other than a temporary decline.  Once an event is identified that is other than temporary, a loss is recognized and the Investment in Affiliate is reduced to fair value.

Through December 31, 2014, we included the results of Petrodelta in our financial statements under the equity method.  We ceased recording earnings from Petrodelta in the second quarter 2014 due to the expected sales price of the second closing purchase agreement approximating the recorded value of our investment in Petrodelta.  The Company was not able to obtain approval from the government of Venezuela during 2014 and on January 1, 2015 we terminated the SPA.  Due to our failed sales attempts, lack of management influence, and actions and inactions by the majority owner, PDVSA, we believe we no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.  Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.  

Capitalized Interest

We capitalize interest costs for qualifying oil and natural gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation.

Property and Equipment

We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. We assess our unproved property costs for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of the projects.  The estimated value of our unproved projects is determined using quantitative and qualitative assessments and the carrying value of the projects is adjusted if the carrying value exceeds the assessed value of the projects. 

During the years ended December 31, 2015 and 2014, we recorded impairment expense, related to our Dussafu Project in Gabon, of $24.2 million (including $1.0 million relating to oilfield inventories) and $50.3 million, respectively, which reflect management’s estimate of the decreased value of the project given our current liquidity situation and the decline in global crude oil prices.  During 2014, we recognized impairments related to our Budong Project in Indonesia of $7.7 million and in 2013, we also recognized impairments of $0.6 and $3.2 million related to projects in Indonesia and Colombia that we elected to abandon and which is reflected in discontinued operations.

41

If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and natural gas properties. Lease rentals are expensed as incurred. Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered proved reserves. Exploratory drilling costs are capitalized when drilling is completed if it is determined that there is economic producibility supported by either actual production, conclusive formation tests or by certain technical data. If proved reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development wells and related equipment used in production of crude oil and natural gas, are capitalized.

Depletion, depreciation, and amortization (“DD&A”) of the cost of proved oil and natural gas properties are calculated using the unit of production method. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is proved reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base is proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.

Assets are grouped based upon a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

Amortization rates are updated to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions or property dispositions and 4) impairments.

We account for impairments of proved properties under the provisions of ASC 360, “Property, Plant, and Equipment”. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field level to the amortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the amortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

Income Taxes

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

Since December 31, 2013, we  have provided deferred income taxes on undistributed earnings of our foreign subsidiaries where we are not able to assert that such earnings were permanently reinvested, or otherwise could be repatriated in a tax free manner, as part of our ongoing business.  As of December 31, 2015, the deferred tax liability provided on such earnings has been reduced to zero due to the impairment of the underlying book investment in Petrodelta.

As the conversion feature of the 9% Note was reasonably expected to be exercised at the time of the note’s issuance due to the conversion price being in-the-money, the interest on the 9% Note paid upon its conversion is non-deductible to the Company under Internal Revenue Code (“IRC”) Section 163(l).  The 15% Note was issued, for income tax purposes, with original issue discount (“OID”).  OID generally is deductible for income tax purposes.  However, if the debt instrument constitutes an “applicable high-yield discount obligation” (“AHYDO”) within the meaning of IRC Section 163(i)(1), then a portion of the OID likely would be non-deductible pursuant to IRC Section 163(e)(5).  Our analysis of the 15% Note is that the note may be an AHYDO; consequently, a portion or all of the OID likely may be non-deductible for income tax purposes.

New Accounting Pronouncements

In April 2015, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs”. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update.  In June 2015 the FASB issued ASU No. 2015-15 as an amendment to this guidance to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements.  The SEC staff stated that they would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement.  The guidance is effective for interim periods and annual period beginning after December 15, 2015; however early adoption is permitted. We do not believe the adoption of this guidance will have a material impact on our financial position and will not have an impact on our results of operations or cash flows.

In August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern”.   ASU No. 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide

42

related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU No. 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.

In April 2014, FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers” which is included in ASC 606, a new topic under the same name. The guidance in this update affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). The guidance supersedes the previous revenue recognition requirements and most industry-specific guidance. Additionally, the update supersedes some cost guidance related to construction type and production-type contracts.  In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in this update.

The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps:  (1) identify the contract(s) with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation.

The new guidance also provides for additional qualitative and quantitative disclosures related to: (1) contracts with customers, including revenue and impairments recognized, disaggregation of revenue, and information about contract balances and performance obligations (including the transaction price allocated to the remaining performance obligations); (2) significant judgments and changes in judgments which impact the determination of the timing of satisfaction of performance obligations (over time or at a point in time), the transaction price and amounts allocated to performance obligations; and (3) assets recognized from the costs to obtain or fulfill a contract.

In July 2015, the FASB issued a decision to delay related to ASU No. 2014-09 for the effective date by one year.  The new guidance is effective for annual and interim periods beginning after December 15, 2017.An entity should apply the amendments either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of initial application. We are currently evaluating the impact of this guidance.

In November 2015, the FASB issued ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes”.  ASU No. 2015-17 simplifies the balance sheet presentation of deferred income taxes by requiring all deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The standard is effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted.  The standard may be applied either prospectively or retrospectively to all periods presented.  The Company has decided to adopt the accounting change in its current financial statements and has adopted the change retrospectively.

In February 2016, the FASB issued ASU No. 2016-02, “Leases”.  It is expected to be effective for periods beginning after December 15, 2018 for public entities, and for periods beginning after December 15, 2019 for nonpublic entities.  Early application is permitted.  Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less.  All other leases will fall into one of two categories: (1) Financing leases, similar to capital leases, will require the recognition of an asset and liability, measured at the present value of the lease payments.  Interest on the liability will be recognized separately from amortization of the asset.  Principal repayments will be classified as financing outflows and payments of interest as operating outflows on the statement of cash flows.  (2) Operating leases will also require the recognition of an asset and liability measured at the present value of the lease payments.  A single lease cost, consisting of interest on the obligation and amortization of the asset, calculated such that the amortization of the asset will increase as the interest amount decreases resulting in a straight-line recognition of lease expense.  All cash outflows will be classified as operating on the statement of cash flows.  We do not believe the adoption of this guidance will have a material impact on our financial position, results of operations or cash flows.

In March 2016, the FASB issued ASU No. 2016-07, “Investments —Equity Method and Joint Ventures (Topic 323)”. This amendment simplifies the accounting for equity method investments; the amendment in the update eliminates the requirement in Topic 323 that an entity retroactively adopt the equity method of accounting if an investment qualifies for use of the equity method as a result of an increase in the level of ownership or degree of influence. The amendment requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt equity method of accounting as of the date the investment becomes qualified for equity method accounting. The amendment in this update is effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. The amendment should be applied prospectively upon the effective date to increases in the level of ownership interest or degree of influence that result in the adoption of the equity method. Earlier application is permitted.We are currently evaluating the impact of this guidance.

43

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Item  7A.  Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk from adverse changes in oil and natural gas prices and foreign exchange risk and are not able to quantify this risk, as discussed below.

Oil Prices

Oil and natural gas prices historically have been volatile, and this volatility is expected to continue. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control. Being primarily a crude oil producer, we are more significantly impacted by changes in crude oil prices than by changes in natural gas prices. As an independent oil producer, our revenue, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas.  We did not have any revenues for the years ended December 31, 2015, 2014 or 2013.

We and our investment in affiliate currently do not have any oil production that is hedged. While hedging limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements.

Interest Rates

The $25.2 million face value of our debt at December 31, 2015 consisted of a 15.0% Note with interest that compounds quarterly at a rate of 15.0% per annum and is payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2015.  On January 4, 2016, the outstanding principal amount of the 15% Note increased to $26.1 million. See Part IV – Item 15 – Exhibits and Financial Statements Schedules, Note 10 – Debt and Financing.  

Foreign Exchange

The Bolivar is not readily convertible into the U.S. Dollar. We have not utilized currency hedging programs to mitigate any risks associated with operations in Venezuela, and, therefore, our financial results are subject to favorable or unfavorable fluctuations in exchange rates and inflation in that country. Venezuela has imposed currency exchange controls. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Effects of Changing Prices, Foreign Exchange Rates and Inflation above.

Item  8.  Financial Statements and Supplementary Data

The information required by this item is included herein and begins on page S-1.

Item  9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item  9A.  Controls and Procedures

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

Management of the Company, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures. Based on their evaluation as of December 31, 2015, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) were effective.

Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the 2013 Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of The Treadway Commission. Based on our evaluation under the 2013 Internal Control Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2015. The effectiveness of our internal control over financial reporting as of December 31,

44

2015, has been audited by BDO USA, LLP, an independent registered public accounting firm, as stated in their report which appears herein in Part IV – Item 15 – Exhibits and Financial Statement Schedules, Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting.

Changes in Internal Control over Financial Reporting. There have been no changes in internal control over financial reporting during the quarter ended December 31, 2015 that have materially affected or are reasonably likely to materially affect that Company’s internal control over financial reporting.

Item  9B.  Other Information

None.

45

PART III

Item  10.  Directors, Executive Officers and Corporate Governance

The information required by this item is, or the Company intends that the information required by this item will be, set forth in the definitive proxy statement relating to the 2016 Annual Meeting of Stockholders of Harvest Natural Resources, Inc. (the Proxy Statement”) or an amendment to this report.  Such information is incorporated by reference into this item pursuant to General Instruction G(3) to Form 10-K.

Item 11.  Executive Compensation

The information required by this item is, or the Company intends that the information required by this item will be, set forth in the Proxy Statement or in an amendment to this report. Such information is incorporated by reference pursuant to General Instruction G(3) to Form 10-K.

Item  12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this item is, or the Company intends that the information required by this item will be, set forth in the Proxy Statement or in an amendment to this report. Such information is incorporated by reference pursuant to General Instruction G(3) to Form 10-K.

Item  13.  Certain Relationships and Related Transactions, and Director Independence

The information required by this item is, or the Company intends that the information required by this item will be, set forth in the Proxy Statement or in an amendment to this report. Such information is incorporated by reference pursuant to General Instruction G(3) to Form 10-K.

Item  14.  Principal Accountant Fees and Services

The information required by this item is, or the Company intends that the information required by this item will be, set forth in the Proxy Statement or in an amendment to this report. Such information is incorporated by reference pursuant to General Instruction G(3) to Form 10-K.

46

PART IV

Item  15.  Exhibits and Financial Statement Schedules

			Page
(a)	1.	Index to Financial Statements:
		Reports of Independent Registered Public Accounting Firms	S-1
		Consolidated Balance Sheets at December 31, 2015 and 2014	S-4
		Consolidated Statements of Operations and Comprehensive Loss for the Years Ended December 31, 2015, 2014 and 2013	S-5
		Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2015, 2014and 2013	S-6
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013	S-7
		Notes to Consolidated Financial Statements	S-9
	2.	Consolidated Financial Statement Schedules and Other:

All schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto.

(b)3. Exhibits:

2.1	Securities Purchase Agreement, dated as of June 19, 2015, between the Company, Harvest (US) Holding, Inc., Harvest Natural Resources, Inc. (UK), Harvest Offshore China Company, and CT Energy Holding SRL (incorporated by reference to our Form 8-K filed on June 22, 2015).
3.1	Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q filed on November 9, 2010).
3.1.1	Certificate of Amendment of Amended and Restated Certificate of Incorporation (incorporated by reference to our Registration Statement on Form S-3 filed on September 29, 2015).
3.1.2	Certificate of Elimination of Preferred Stock, Series C of Harvest Natural Resources, Inc. dated February 19, 2016 (Incorporated by reference to our form 8-K filed on February 19, 2016.
3.2	Restated Bylaws as of May 15, 2015 (incorporated by reference to our Form 8-K filed on May 15, 2015).
3.3	Certificate of Designations of Series C Preferred Stock of the Company filed on June 19, 2015 (incorporated by reference to our Form 8-K filed on June 22, 2015).
4.1	Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to our Form 10-K filed on March 17, 2008).
4.2	Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between the Company and Wells Fargo Bank, N.A. (incorporated by reference to Exhibit 99.3 to our Form 8-A12G filed on October 23, 2007).
4.2.1	Amendment to Third Amended and Restated Rights Agreement, dated as of October 28, 2010, between the Company and Wells Fargo Bank, N.A. (incorporated by reference to Exhibit 4.1 to our Form 8-K filed on October 29, 2010).
4.2.2	Second Amendment to Third Amended and Restated Rights Agreement, dated as of February 1, 2013, between the Company and Wells Fargo Bank, N.A., as Rights Agent (incorporated by reference to Exhibit 4.1 to our Form 8-K filed on February 4, 2013).
4.2.3	Third Amendment to Third Amended and Restated Rights Agreement, dated as of April 24, 2015, between the Company and Wells Fargo Bank, N.A. (incorporated by reference to the Company’s Form 8-K filed with the SEC on April 24, 2015).
4.2.4	Fourth Amendment to Third Amended and Restated Rights Agreement, dated as of June 19, 2015, between the Company and Wells Fargo Bank, N.A., as rights agent (incorporated by reference to the Company’s Current Report on Form 8-K filed on June 22, 2015).
4.3	Warrant Purchase Agreement, dated as of October 28, 2010, between the Company and MSD Energy Investments Private II, LLC (incorporated by reference to Exhibit 4.2 to our Form 8-K filed on October 29, 2010).
4.4	Common Stock Purchase Warrant No. W-1, dated as of October 28, 2010, between the Company and MSD Energy Investments Private II, LLC (incorporated by reference to Exhibit 4.3 to our Form 8-K filed on October 29, 2010).
4.5	Common Stock Purchase Warrant No. W-2, dated as of October 28, 2010, between the Company and MSD Energy Investments Private II, LLC (incorporated by reference to Exhibit 4.4 to our Form 8-K filed on October 29, 2010).
4.6	Indenture (including Form of Note), dated as of October 11, 2012, between the Company and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to our Form 8-K filed on October 15, 2012).
4.7	Warrant Agreement (including Form of Warrant), dated as of October 11, 2012, between the Company and U.S. Bank National Association, as Warrant Agent (incorporated by reference to Exhibit 4.3 to our Form 8-K filed on October 15, 2012).

47

4.8	15% Non-Convertible Senior Secured Promissory Note Due 2020, dated June 19, 2015, between the Company and CT Energy Holding SRL (incorporated by reference to the Company’s Form 8-K filed with the SEC on June 22, 2015).
4.8.1	First Amendment to 15% Non-Convertible Senior Secured Promissory Note Due 2020, effective as of December 31, 2015, between the Company and CT Energy Holding SRL (incorporated by reference to the Company’s Form 8-K filed with the SEC on January 7, 2016).
4.9	9% Convertible Senior Secured Note Due 2020, dated June 19, 2015, between the Company and CT Energy Holding SRL (incorporated by reference to the Company’s Form 8-K filed with the SEC on June 22, 2015).
4.10	15% Additional Draw Senior Secured Note Due 2020, dated June 19, 2015, between the Company and CT Energy Holding SRL (incorporated by reference to the Company’s Form 8-K filed with the SEC on June 22, 2015).
4.11	Common Stock Purchase Warrant, dated as of June 19, 2015, issued to CT Energy Holding SRL (incorporated by reference to the Company’s Form 8-K filed with the SEC on June 22, 2015).
10.1†	2001 Long Term Stock Incentive Plan (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-8 filed on April 9, 2002 (Registration Statement No. 333- 85900)).
10.2†	Harvest Natural Resources 2004 Long Term Incentive Plan (incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841)).
10.3†	Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement (incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005).
10.4†	Form of Indemnification Agreement between the Company and each Director and Executive Officer of the Company (incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005).
10.5†	Harvest Natural Resources 2006 Long Term Incentive Plan (incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on June 1, 2006 Registration Statement No. 333-134630).
10.5.1†	Amendment to Harvest Natural Resources 2006 Long Term Incentive Plan adopted July 19, 2006 (incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on May 3, 2007).
10.6†	Form of 2006 Long Term Incentive Plan Stock Option Agreement (incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2006).
10.7†	Form of 2006 Long Term Incentive Plan Stock Option Agreement – Five Year Vesting, Seven Year Term (incorporated by reference to Exhibit 10.33 to our Form 10-K filed on March 13, 2007).
10.8†	Stock Unit Award Agreement dated March 2, 2006 between the Company and James A. Edmiston (incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 9, 2006).
10.9	Contract for Conversion to a Mixed Company between Corporación Venezolana del Petróleo, S.A., Harvest-Vinccler, S.C.A. and HNR Finance B.V (incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on November 1, 2007).
10.10†	2010 Long Term Incentive Plan (incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed with the SEC on April 9, 2010).
10.10.1†	2010 Long Term Incentive Plan, as amended and Restated,  adopted June 27, 2013  (incorporated by reference to Exhibit 10.1 to our form 10-Q filed on November 12, 2013)
10.10.2†	Amendment to the 2010 Long Term Incentive Plan, adopted September 9, 2015 (incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on November 9 , 2015).
10.11†	Form of 2010 Long Term Incentive Plan Employee Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2010).
10.12†	Form of 2010 Long Term Incentive Plan Stock Option Award Agreement (incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2010).
10.13†	Form of 2010 Long Term Incentive Plan Director Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.30 to our Form 10-K filed on March 15, 2012).
10.14†	Employment Agreement dated January 1, 2009 between the Company and Karl L. Nesselrode (incorporated by reference to Exhibit 10.30 to our Form 10-K filed on March 15, 2012).
10.15†	Employment Agreement dated January 1, 2009 between the Company and Keith L. Head (incorporated by reference to Exhibit 10.32 to our Form 10-K filed on March 15, 2012).
10.16†	Employment Agreement dated January 1, 2009 between the Company and Stephen C. Haynes (incorporated by reference to Exhibit 10.33 to our Form 10-K filed on March 15, 2012).
10.17†	Employment Agreement dated May 31, 2008 between the Company and Robert Speirs (incorporated by reference to Exhibit 10.34 to our Form 10-K filed on March 15, 2012).
10.18†	Form of Stock Appreciation Right Award Agreement (incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on August 4, 2009).
10.19†	Form of Director Stock Unit Award Agreement (incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2012).

48

10.20†	Form of Employee Stock Unit Award Agreement (incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2012).
10.21†	Form of Employee Stock Appreciation Right Award Agreement (incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on August 9, 2012).
10.22	Shareholders’ Agreement dated as of December 16, 2013, by and among HNR Energia B.V. and Petroandina Resources Corporation N.V (incorporated by reference to Exhibit 10.42 to our Form 10-K filed on March 17, 2014).
10.23	Loan agreement, dated as of September 11, 2014, between the Company, HNR Energia, BV. and Petroandina Resources Corporation N.V. (incorporated by reference to the Company’s 10-Q/A filed with the SEC on June 26, 2014).
10.24	Promissory Note dated June 3, 2015 between the Company and James A. Edmiston (incorporated by reference to the Company’s Form 8-K filed with the SEC on June 8, 2015).
10.25	Registration Rights Agreement, dated June 19, 2015, between the Company and CT Energy Holding SRL (incorporated by reference to the Company’s Form 8-K filed with the SEC on June 22, 2015).
10.26	Management Agreement, dated June 19, 2015, between the Company, HNR Finance B.V., and CT Energia Holding Ltd. (incorporated by reference to the Company’s Form 8-K filed with the SEC on June 22, 2015).
10.27	Investor Voting Agreement, dated June 19, 2015, between the Company and CT Energy Holding SRL (incorporated by reference to the Company’s Form 8-K filed with the SEC on June 22, 2015).
10.28	Security Agreement, dated June 19, 2015, by and among the Company, Harvest (US) Holding, Inc., Harvest Natural Resources, Inc. (UK) and Harvest Offshore China Company in favor of CT Energy Holding SRL (incorporated by reference to the Company’s Form 10-Q filed with the SEC on August 7, 2015).
10.29	Guaranty Agreement, dated June 19, 2015, by and among the Company, Harvest (US) Holding, Inc., Harvest Natural Resources, Inc. (UK) and Harvest Offshore China Company in favor of CT Energy Holding SRL (incorporated by reference to the Company’s Form 10-Q filed with the SEC on August 7, 2015).
10.30	11.0% Senior Unsecured Promissory Note Due 2019, dated January 4, 2016, executed by CT Energia Holding Ltd. and payable to HNR Finance B.V. (incorporated by reference to the Company’s Form 8-K filed with the SEC on January 7, 2016).
16.1	Letter from UHY LLP, dated December 4, 2014, addressed to the SEC (incorporated by reference to Exhibit 16.1 to our Form 8-K filed on December 5, 2014).
21.1	List of subsidiaries (incorporated by reference to Exhibit 21.1 to our Form 10-K filed on March 17, 2014).
23.1*	Consent of UHY LLP
23.2*	Consent of BDO USA, LLP
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1^	Certification of Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350
32.2^	Certification of Chief Financial Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document

*   Filed herewith.

^   Furnished herewith.

†  Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15(a) and (b) of Form 10-K.

49

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

To the Board of Directors and

Stockholders of Harvest Natural Resources, Inc.

Houston, Texas

We have audited Harvest Natural Resources, Inc. and subsidiaries (the “Company”) internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A., Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

In our opinion, Harvest Natural Resources, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Harvest Natural Resources, Inc. and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations and comprehensive loss, stockholders’ equity and cash flows for the years then ended and our report dated March 29, 2016 expressed an unqualified opinion thereon and contains explanatory paragraphs referring to the Company’s change in the method of accounting for the classification of deferred taxes and the Company’s ability to continue as a going concern.

/s/ BDO USA, LLP

Houston, Texas

March 29, 2016

S-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Stockholders of Harvest Natural Resources, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Harvest Natural Resources, Inc. and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations and comprehensive loss, stockholders’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Harvest Natural Resources, Inc. and subsidiaries at December 31, 2015 and 2014, and the consolidated results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, the Company has changed its method of accounting for the classification of deferred taxes in the consolidated balance sheets as of December 31, 2015 and 2014 due to the retrospective adoption of Financial Accounting Standards Board, Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern.  As described in Note 2 to the consolidated financial statements, the Company has not generated revenues and has suffered recurring losses and negative cash flows from operations that raise substantial doubt about its ability to continue as a going concern.  Management's plans in regard to these matters are also described in Note 2.  The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Harvest Natural Resources, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 29, 2016 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, Texas

March 29, 2016

S-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Stockholders of Harvest Natural Resources, Inc.

We have audited the accompanying consolidated statements of operations and comprehensive loss, stockholders’ equity and cash flows of Harvest Natural Resources, Inc. and subsidiaries (the “Company”) for the year ended December 31, 2013. The Company’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the Company’s consolidated results of operations and cash flows for the year ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

March 17, 2014

S-3

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except per share data)

	December 31,
	2015		2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7,761	$	6,585
Restricted cash		—		25
Accounts receivable		2,461		339
Prepaid expenses and other		826		353
TOTAL CURRENT ASSETS		11,048		7,302
INVESTMENT IN AFFILIATE		—		164,700
PROPERTY AND EQUIPMENT:
Oil and natural gas properties (successful efforts method)		31,006		54,290
Other administrative property, net		455		217
TOTAL PROPERTY AND EQUIPMENT, net		31,461		54,507
EMBEDDED DERIVATIVE ASSET		5,010		—
LONG-TERM DEFERRED INCOME TAX ASSETS		120		53
OTHER ASSETS, net of allowance for $0.7 million and $0.0 million at December 31, 2015 and 2014, respectively.		142		1,484
TOTAL ASSETS	$	47,781	$	228,046
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable, trade and other	$	370	$	1,697
Accrued expenses		3,327		4,617
Accrued interest		954		97
Notes payable to noncontrolling interest owners		—		13,709
Other current liabilities		165		133
TOTAL CURRENT LIABILITIES		4,816		20,253
LONG-TERM DEBT DUE TO RELATED PARTY, net of discount		214		—
LONG-TERM DEFERRED TAX LIABILITIES, net		—		14,700
WARRANT DERIVATIVE LIABILITY WITH RELATED PARTY		5,503		—
OTHER LONG-TERM LIABILITIES		42		215
TOTAL LIABILITIES		10,575		35,168
COMMITMENTS AND CONTINGENCIES (Note 13)
STOCKHOLDERS’ EQUITY:
Preferred stock, par value $0.01 per share; authorized 5,000 shares; issued and outstanding, none		—		—
Common stock, par value $0.01 per share; shares authorized 150,000 (2015) and 80,000 (2014); shares  issued (2015 - 57,987;  2014 - 49,320); shares outstanding  (2015 - 51,415; 2014 - 42,748)		580		493
Additional paid-in capital		302,273		280,757
Accumulated deficit		(199,778)		(101,208)
Treasury stock, at cost, 6,572 shares (2015 and  2014)		(66,316)		(66,316)
TOTAL HARVEST STOCKHOLDERS’ EQUITY		36,759		113,726
NONCONTROLLING INTEREST OWNERS		447		79,152
TOTAL EQUITY		37,206		192,878
TOTAL LIABILITIES AND EQUITY	$	47,781	$	228,046

See accompanying notes to consolidated financial statements.

S-4

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

(in thousands, except per share data)

	Year Ended December 31,
	2015		2014		2013
EXPENSES:
Depreciation and amortization	$	108	$	198	$	341
Exploration expense		3,900		6,267		15,155
Impairment expense - unproved property costs and oilfield inventories		24,178		57,994		575
Impairment expense - investment in affiliate		164,700		355,650		—
General and administrative		19,010		29,496		29,365
		211,896		449,605		45,436
LOSS FROM OPERATIONS		(211,896)		(449,605)		(45,436)
OTHER NON-OPERATING INCOME (EXPENSE):
Loss on the sale of interest in Harvest Holding		—		(1,574)		(22,994)
Gain on sale of oil and natural gas properties		—		2,865		—
Change in fair value of warrant liabilities		34,510		1,953		3,517
Change in fair value of derivative assets and liabilities		4,813		—		—
Interest expense		(2,959)		(11)		(4,495)
Loss on debt conversion		(1,890)		—		—
Loss on issuance of debt and warrants		(20,402)		—		—
Loss on extinguishment of  long-term debt		—		(4,749)		—
Foreign currency transaction gains (losses), net		261		(219)		(820)
Other non-operating income (expense), net		483		(58)		(1,569)
		14,816		(1,793)		(26,361)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND EARNINGS  FROM INVESTMENT IN AFFILIATE		(197,080)		(451,398)		(71,797)
INCOME TAX EXPENSE (BENEFIT)		(16,423)		(58,290)		73,087
LOSS FROM CONTINUING OPERATIONS BEFORE EARNINGS FROM INVESTMENT IN AFFILIATE		(180,657)		(393,108)		(144,884)
EARNINGS FROM INVESTMENT IN AFFILIATE		—		34,949		72,578
LOSS FROM CONTINUING OPERATIONS		(180,657)		(358,159)		(72,306)
DISCONTINUED OPERATIONS		—		(554)		(5,150)
NET LOSS		(180,657)		(358,713)		(77,456)
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST OWNERS		(82,087)		(165,223)		11,640
NET LOSS AND COMPREHENSIVE LOSS ATTRIBUTABLE TO HARVEST	$	(98,570)	$	(193,490)	$	(89,096)
BASIC LOSS PER SHARE:
Loss from continuing operations	$	(2.18)	$	(4.59)	$	(2.12)
Discontinued operations		—		(0.01)		(0.13)
Basic loss per share	$	(2.18)	$	(4.60)	$	(2.25)
DILUTED LOSS PER SHARE:
Loss from continuing operations	$	(2.18)	$	(4.59)	$	(2.12)
Discontinued operations		—		(0.01)		(0.13)
Diluted loss per share	$	(2.18)	$	(4.60)	$	(2.25)

See accompanying notes to consolidated financial statements.

S-5

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands)

	Common Shares Issued	Common Stock		Additional Paid-in Capital		Retained Earnings (Loss)		Treasury Stock		Non- Controlling Interests		Total Equity
Balance at January 1, 2013	45,882	$	458	$	263,646	$	181,378	$	(66,145)	$	97,101	$	476,438
Issuance of common shares:
Exercise of stock options	20		—		122		—		—		—		122
Sales of common shares	2,495		25		9,273		—		—		—		9,298
Employee stock-based compensation	269		4		3,042		—		—		—		3,046
Purchase of treasury shares	—		—		—		—		(77)		—		(77)
Increase in equity held by noncontrolling interests due to sale of interest in affiliate	—		—		—		—		—		144,796		144,796
Dividend to noncontrolling interest owner	—		—		—		—		—		(10,370)		(10,370)
Net income (loss)	—		—		—		(89,096)		—		11,640		(77,456)
Balance at December 31, 2013	48,666	$	487	$	276,083	$	92,282	$	(66,222)	$	243,167	$	545,797
Issuance of common shares:
Sales of common shares	654		6		2,022		—		—		—		2,028
Employee stock-based compensation	—		—		2,652		—		—		—		2,652
Purchase of treasury shares	—		—		—		—		(94)		—		(94)
Contributions from noncontrolling interest owners	—		—		—		—		—		1,208		1,208
Net loss	—		—		—		(193,490)		—		(165,223)		(358,713)
Balance at December 31, 2014	49,320	$	493	$	280,757	$	(101,208)	$	(66,316)	$	79,152	$	192,878
Issuance of common shares:
Employee stock-based compensation	—		—		2,271		—		—		—		2,271
Conversion of 9% Note	8,667		87		13,088		—		—		—		13,175
Contribution from noncontrolling owner of note payable and accrued interest payable	—		—		6,157		—		—		—		6,157
Contributions from noncontrolling interest owners	—		—		—		—		—		3,382		3,382
Net loss	—		—		—		(98,570)		—		(82,087)		(180,657)
Balance at December 31, 2015	57,987	$	580	$	302,273	$	(199,778)	$	(66,316)	$	447	$	37,206

See accompanying notes to consolidated financial statements.

S-6

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2015		2014		2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(180,657)	$	(358,713)	$	(77,456)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization		108		198		354
Impairment expense - unproved property costs and oilfield inventories		24,178		57,994		3,770
Impairment expense - investment in affiliate		164,700		355,650		—
Amortization of debt financing costs		283		28		1,489
Accretion of discount on debt		225		—		2,641
Allowance for long-term receivable		734		13,753		—
Loss on the sale of interest in Harvest Holding		—		1,574		22,994
Gain on sale of oil and natural gas properties		—		(2,865)		—
Loss on debt issuance		20,402		—		—
Loss on debt conversion		1,890		—		—
Foreign currency transaction loss		—		1,239		436
Loss on extinguishment of  long-term debt		—		4,749		—
Earnings from investment in affiliate		—		(34,949)		(72,578)
Share-based compensation-related charges		2,271		2,652		3,046
Deferred income tax expense (benefit)		(14,767)		(58,221)		73,689
Change in fair value of warrant liabilities		(34,510)		(1,953)		(3,517)
Change in fair value of derivative assets and liabilities		(4,813)		—		—
Changes in operating assets and liabilities:
Accounts receivable		(2,122)		1,623		993
Prepaid expenses and other		(473)		339		710
Other assets		350		(328)		3,971
Accounts payable		(1,327)		(2,701)		428
Accrued expenses		(1,259)		(16,112)		3,790
Accrued interest		1,036		(360)		(244)
Other current liabilities		32		(2,464)		(1,043)
Other long-term liabilities		(173)		(343)		(550)
NET CASH USED IN OPERATING ACTIVITIES		(23,892)		(39,210)		(37,077)
CASH FLOWS FROM INVESTING ACTIVITIES:
Transaction costs from the sale of interest in Harvest Holding		—		(3,742)		—
Net proceeds from sale of oil and natural gas properties		—		2,865		—
Net proceeds from sale of interest in investment in affiliate		—		—		124,045
Additions of property and equipment, net		(1,270)		(4,382)		(43,906)
Payment from (advances to) investment in affiliate, net		—		105		(531)
Decrease in restricted cash		—		123		852
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(1,270)		(5,031)		80,460
CASH FLOWS FROM FINANCING ACTIVITIES:
Debt repayment		(8,900)		(79,750)		—
Debt extinguishment costs		—		(760)		—
Gross proceeds from issuance of debt and warrant		33,500		—		—
Proceeds from issuance of note payable to noncontrolling interest owner		—		7,600		—
Proceeds from issuance of common stock		—		2,036		9,420
Contributions from noncontrolling interest owners		3,382		1,208		—
Treasury stock purchases		—		(94)		(77)
Payments on note payable to noncontrolling interest owner		—		—		(4,260)
Financing costs		(1,644)		(311)		(196)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		26,338		(70,071)		4,887
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1,176		(114,312)		48,270
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		6,585		120,897		72,627
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	7,761	$	6,585	$	120,897

See accompanying notes to consolidated financial statements.

S-7

Supplemental Schedule of Noncash Investing and Financing Activities:

	Year Ended December 31,
	2015		2014		2013
Supplemental Cash Flow Information:	(in thousands)
Cash paid during the period for interest expense	$	1,547	$	—	$	487
Cash paid during the period  for income taxes		6		1,128		495
Supplemental Schedule of Noncash Investing and Financing Activities:
Decrease in current liabilities related to additions of property and equipment	$	(30)	$	(210)	$	(13,926)
Increase in Stockholders' Equity from forgiveness of note payable and accrued interest		6,157		—		—
Issuance of common stock from conversion of 9% Convertible Senior Secured Note		13,175		—		—

See accompanying notes to consolidated financial statements.

S-8

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Note 1 – Organization

Harvest Natural Resources, Inc. (“Harvest” or  the “Company”) is an independent energy company engaged in the acquisition, exploration, development, production and disposition of oil and natural gas properties since 1988, when it was incorporated under Delaware law.

We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through Harvest-Vinccler Dutch Holding B.V., a Dutch private company with limited liability (“Harvest Holding”). Our ownership of Harvest Holding is through HNR Energia B.V. (“HNR Energia”) in which we have a direct controlling interest. 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 (the “SPA”) with Petroandina Resources Corporation N.V. (“Petroandina”, a wholly owned subsidiary of Pluspetrol Resources Corporation B.V. (“Pluspetrol”)) 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 $400.0 million. The first closing occurred on December 16, 2013 contemporaneously with the signing of the SPA, when we sold a 29 percent equity interest in Harvest Holding for $125.0 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.  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 29 percent and Vinccler continuing to own 20 percent. The second closing did not occur during 2014 and the SPA was terminated by the Company on January1, 2015. See Note 5 – Dispositions below for further information on this transaction.

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”). Petrodelta is our cost investment in eastern Venezuela responsible for the exploration, development, production, gathering, transportation and storage of hydrocarbons in six oil fields. Petrodelta is governed by its own charter and bylaws and the shareholders intend that the Company be self-funding and rely on internally-generated cash flows. 

Corporación Venezolana del Petroleo S.A. (“CVP”) and PDVSA Social S.A. owns the remaining 56 percent and 4 percent, 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, and 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.

In addition to our interests in Venezuela, we also hold exploration and exploitation acreage offshore of the Republic of Gabon (“Gabon”) through the Dussafu Marin Permit (“Dussafu PSC”). See Note 8 – Gabon.

On June 19, 2015, the Company and certain of its domestic subsidiaries entered into a securities purchase agreement (the “Purchase Agreement”) with CT Energy Holding SRL (“CT Energy”), a Venezuelan-Italian consortium organized as a Barbados Society with Restricted Liability, under which CT Energy purchased certain securities of the Company and acquired certain governance rights.  Harvest immediately received gross proceeds of $32.2 million from the sale of the securities, as described below.   Key terms of the transaction include:

· CT Energy acquired a $25.2 million, five year, 15.0% non-convertible senior secured promissory note (the “15% Note”). Interest is payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2015. 

· CT Energy acquired a $7.0 million, five year, 9.0% convertible senior secured note (the “9% Note”). The 9% Note face value of $7.0 million and associated accrued interest of $0.1 million was converted into 8,667,597 shares of Harvest common stock at a conversion price of $0.82 per  share on September 15, 2015.  Immediately after the conversion, CT Energy owned approximately 16.6% of Harvest’s common stock.

· CT Energy also acquired a warrant to purchase up to 34,070,820 shares of Harvest's common stock at an initial exercise price of $1.25 per share (the “CT Warrant”). The CT Warrant will become exercisable only after the 30-day volume weighted average price of Harvest's common stock equals or exceeds $2.50 per share (“Stock Appreciation Date”).  The warrant is cash-exercisable, but CT Energy may surrender the 15% Note to pay for a portion of the aggregate exercise price. 

· CT Energy acquired a five-year 15.0% non-convertible senior secured note (the “Additional Draw Note”), under which CT Energy may elect to provide $2.0 million of additional funds to the Company per month for up to six months following the one-year anniversary of the closing date of the transaction (up to $12.0 million in aggregate).  If funds are loaned under the Additional Draw Note, interest will be compounded quarterly at a rate of 15.0% per annum and is payable quarterly on the S-9

first business day of each January, April, July and October, commencing October 1, 2016.  If by June 19, 2016 (the “Claim Date”),  the volume weighted average price of the Company’s common stock over any consecutive 30-day period has not equaled or exceeded $2.50 per share, the maturity date of the Additional Draw Note will be extended by two years and the interest rate on the Additional Draw Note will adjust to 8.0%. During an event of default, the outstanding principal amount will bear additional interest at a rate of 2.0% per annum higher than the rate otherwise applicable.

· CT Energy also acquired 69.75 shares of the Company’s newly created Series C preferred stock, par value $0.01 per share.  The purpose of the Series C preferred stock was to provide the holder of the 9% Note with voting rights equivalent to the common stock underlying the unconverted portion of the 9% Note.  Upon conversion of the 9% Note, the Series C preferred stock ceased to have voting rights and was redeemed. 

· CT Energy was granted certain governance rights in the transaction, including the right to appoint specified directors.  Also, the Company and CT Energia Holding Ltd. (“CT Energia”), a Malta corporation, entered into a Management Agreement (the “Management Agreement”), under which CT Energia and its representatives will manage the day-to-day operations of the Company’s business as it relates to Petrodelta and Venezuela generally.

At our annual shareholder meeting, on September 9, 2015, Harvest stockholders approved, among other proposals, 1) certain aspects of the transaction under NYSE shareholder approval requirements and Delaware law and 2) an amendment to Harvest's charter to increase the number of authorized shares of our common stock from 80,000,000 to 150,000,000, in part to have sufficient shares to issue upon conversion of the 9% Note and exercise of the CT Warrant and an amendment to the 2010 Long Term Incentive Plan increasing the number shares of our common stock to satisfy of stock options, stock appreciation rights (“SARs”), restricted stock, restricted stock units (“RSUs”) and other stock-based awards.  See Note 15 – Stock-Based Compensation and Stock Purchase Plans.  

Note 2 – Liquidity and Going Concern

We expect that for 2016 we will not generate revenue, will continue to generate losses from operations, and our cash flows will not be sufficient to cover our operating expenses. Therefore, expected continued losses from operations, capital needs and uses of cash will be funded through debt or equity financings, farm-downs, delay of the discretionary portion of our capital spending to future periods or operating cost reductions.  Our ability to continue as a going concern depends on our ability to negotiate the management and structure of our investment in Petrodelta and the success of our planned exploration and development activities in Gabon.  There can be no guarantee of future capital acquisition, fundraising or exploration success or that we will realize the value of our exploration and exploitation acreage and suspended wells.  We believe that we will continue to be successful in securing any funds necessary to continue as a going concern.  However, our current cash position and our inability to access additional capital may limit our available opportunities or not provide sufficient cash for operations.

Historically, prior to the transaction pursuant to the Purchase Agreement,  our primary ongoing source of cash had been dividends from Petrodelta, issuance of debt and the sale of oil and naturalgas properties. Our primary use of cash has been to fund oil and naturalgas exploration projects, principal payments on debt, interest, and general and administrative costs. We require capital principally to fund the exploration and development of new oil and naturalgas properties. We have various contractual commitments pertaining to exploration, development and production activities. 

See Note 8 – Gabon and Note 13 – Commitments and Contingencies for our contractual commitments.

We are currently assessing alternatives for our Gabon asset, and we intend to continue our consideration of a possible sale or farm-down of our Gabon asset 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.   Given that we do not currently have any operating cash inflows, we may also decide to access additional capital through equity or debt sales; however, there can be no assurance that such financing will be available to the Company or on terms that are acceptable to the Company.

On December 2, 2015, the Company received notification from the NYSE that the Company was not in compliance with the NYSE's continued listing standards, which require a minimum average closing price of $1.00 per share over 30 consecutive trading days.  Under the NYSE's rules, Harvest has a period of six months from the date of the NYSE notice to bring its share price and 30 trading-day average share price back above $1.00.  During this period, the Company’s common stock will continue to be traded on the NYSE under the symbol “HNR”, subject to the Company’s compliance with other NYSE continued listing requirements, but will be assigned the notation .BC after the listing symbol to signify that the Company is not currently in compliance with the NYSE’s continued listing standards.  As required by the NYSE, in order to maintain its listing, Harvest has notified the NYSE that it intends to cure the price deficiency.

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

The above circumstances raise substantial doubt about our ability to continue as a going concern.  While we believe the issuance of additional equity securities, short- or long-term debt financing, farm-downs, the delay of the discretionary portion of our capital

S-10

spending to future periods or operating cost reductions could be put into place which would not jeopardize our operations and future growth plans, there can be no assurance that such financings will be successful.

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

Note 3 – Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. All intercompany profits, transactions and balances have been eliminated. Third-party interests in our majority-owned subsidiaries are presented as noncontrolling interest owners.

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current period presentation.  These reclassifications did not affect our consolidated financial results.

Investment in Petrodelta

Through December 31, 2014, we included the results of Petrodelta in our financial statements under the equity method.  We ceased recording earnings from Petrodelta in the second quarter 2014 due to the expected sales price of the second closing purchase agreement approximating the recorded value of our investment in Petrodelta.  The Company was not able to obtain approval from the government of Venezuela during 2014 and on January 1, 2015 we terminated the SPA.  Due to our failed sales attempts, lack of management influence, and actions and inactions by the majority owner, PDVSA, we believe we no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.  Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.  

We evaluate our investment in Petrodelta for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may be impaired. A loss is recorded in earnings in the current period if a decline in the value of the investment is determined to be other than temporary. Impairment is calculated as the difference between the carrying value of the investment and its fair value.  We recorded pre-tax impairment charges against the carrying value of our investment in Petrodelta of $164.7 million and $355.7 millionduring the years ended December 31, 2015 and 2014, respectively.  See Note 6 – Investment in Affiliate for further information.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Other important significant estimates are those included in the valuation of our assets and liabilities that are recorded at fair value on a recurring and non-recurring basis.  Actual results could differ from those estimates.

Reporting and Functional Currency

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

See Note 6 – Investment in Affiliate and Note 7 – Venezuela - Other for a discussion of currency exchange rates and currency exchange risk on Petrodelta’s and Harvest Vinccler’s businesses.

Cash and Cash Equivalents

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

S-11

Restricted Cash

Restricted cash is classified as current or non-current based on the terms of the agreement. Restricted cash at December 31, 2014 represented $25,000 held in a U.S. bank as collateral for our foreign credit card program. There was no restricted cash as of December 31, 2015.

Financial Instruments

Financial instruments, which potentially subject us to concentrations of credit risk, are primarily cash and cash equivalents, accounts receivable, notes payable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts with commercial banks with high credit ratings, which, at times may exceed the federally insured limits. We have not experienced any losses from such investments. Concentrations of credit risk with respect to accounts receivable are limited due the nature of our receivables, which include primarily joint venture partner’s receivable, and income tax receivable. In the normal course of business, collateral is not required for financial instruments with credit risk.

Oil and Natural Gas Properties

The major components of property and equipment are as follows: 

	As of December 31,
	2015		2014
	(in thousands)
Unproved property costs - Dussafu PSC	$	28,000	$	50,324
Oilfield inventories		3,006		3,966
Other administrative property		2,937		2,670
Total property and equipment		33,943		56,960
Accumulated depreciation		(2,482)		(2,453)
Total property and equipment, net	$	31,461	$	54,507

Property and equipment are stated at cost less accumulated depreciation. Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of property and equipment, net of the related accumulated depreciation is removed and, if appropriate, gains or losses are recognized in investment earnings and other. We did not record any depletion expense in the years ended December 31, 2015, 2014 and 2013 as there was no production related to proved oil and natural gas properties.

We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that proved reserves, as that term is defined in Securities and Exchange Commission (“SEC”) regulations, have not been discovered, capitalized costs associated with the drilling of the exploratory well are charged to expense. Costs of drilling successful exploratory wells, all development wells, and related production equipment and facilities are capitalized and depleted or depreciated using the unit-of-production method as oil and natural gas is produced. During the years ended December 31, 2015, 2014 and 2013, we expensed no dry hole costs.

Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period. Costs of maintaining and retaining unproved leaseholds are included in exploration expense.  Costs of impairment of unsuccessful leases are included in impairment expense.  We assess our unproved property costs for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of the projects.  The estimated value of our unproved projects is determined using quantitative and qualitative assessments and the carrying value of the projects is adjusted if the carrying value exceeds the assessed value of the projects. 

Impairment is based on specific identification of the lease. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and natural gas properties.

Proved oil and natural gas properties are reviewed for impairment at a level for which identifiable cash flows are independent of cash flows of other assets when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are determined based on estimated future oil and natural gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these undiscounted estimated future net cash flows is less than the carrying amount of the property, an impairment loss is recognized for the excess of the property’s carrying amount over its estimated fair value, which is generally based on discounted future net cash flows. We did not have any proved oil and natural gas properties in 2015, 2014 or 2013.

S-12

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

During the year ended December 31, 2015, we recorded impairment expense related to our Dussafu Project in Gabon of  $24.2 million (including $1.0 million of oilfield inventories). During the year ended December 31, 2014, we recorded impairment expense related to our Budong Project in Indonesia of $7.7 million and our Dussafu Projectof $50.3 million.  During the year ended December 31, 2013, we recorded impairment expense related to our Budong Project in Indonesia of $0.6 million and our project in Colombia of $3.2 million, which is reflected in discontinued operations.

Other Administrative Property

Furniture, fixtures and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to five years. Leasehold improvements are recorded at cost and amortized using the straight-line method over the life of the applicable lease. For the year ended December 31, 2015, depreciation expense was $0.1 million ($0.2 million and $0.3 million for the years ended December 31, 2014 and 2013, respectively).

Other Assets

Other Assets at December 31, 2015 and 2014 include deposits, prepaid expenses which are expected to be realized in the next 12 to 24 months.  During 2015 we fully reserved the blocked payment related to our drilling operations in Gabon in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”) See Note 13 – Commitments and Contingencies.   We recorded an allowance for doubtful accounts of $0.7 million and the remaining balance of the blocked payment was reclassified to a receivable from our joint venture partners for $0.4 million.  Other assets at December 31, 2014 also consisted of deferred financing costs. Deferred financing costs relate to specific financings and are amortized over the life of the financings to which the costs relate using the interest rate method.

	As of December 31,
	2015		2014
	(in thousands)
Deposits and long-term prepaid expenses	$	142	$	101
Deferred financing costs		—		283
Gabon – blocked payment		—		1,100
	$	142	$	1,484

Reserves

We measure and disclose oil and natural 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”). All of our reserves are owned through our investment in Petrodelta. We are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.  Under the cost method, we do not have any reserves at December 31, 2015 and 2014.

Capitalized Interest

We capitalize interest costs for qualifying oil and natural gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation. During the year ended December 31, 2015, we capitalized interest costs for qualifying oil and natural gas property additions related to Gabon of $0.0 million ($0.5 million and $8.3 million during the years ended December 31, 2014 and 2013, respectively).

Fair Value Measurements

We measure and disclose our fair values in accordance with the provisions of ASC 820 “Fair Value Measurements and Disclosures” (“ASC 820”). ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price) and establishes a three-level hierarchy, which encourages an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The three levels of the hierarchy are defined as follows:

· Level 1 – Inputs to the valuation techniques that are quoted prices in active markets for identical assets or liabilities.

S-13

· Level 2 – Inputs to the valuation techniques that are other than quoted prices but are observable for the assets or liabilities, either directly or indirectly.

· Level 3 – Inputs to the valuation techniques that are unobservable for the assets or liabilities.

Financial instruments, which potentially subject us to concentrations of credit risk, are primarily cash and cash equivalents, accounts receivable, SARs, RSUs, debt, embedded derivatives and warrant derivative liabilities. We maintain cash and cash equivalents in bank deposit accounts with commercial banks with high credit ratings, which, at times may exceed the federally insured limits. We have not experienced any losses from such investments. Concentrations of credit risk with respect to accounts receivable are limited due to the nature of our receivables. In the normal course of business, collateral is not required for financial instruments with credit risk.  The estimated fair value of cash and cash equivalents and accounts receivable approximates their carrying value due to their short-term nature (Level 1).  The following tables set forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value as of December 31, 2015 and December 31, 2014. During the year ended December 31, 2015, we impaired the carrying value of our Dussafu project in Gabon by $23.2 million and our investment in affiliate by $164.7 million.  See Note 6 – Investment in Affiliate and Note 8 – Gabon for more information.

	As of December 31, 2015
	Level 1		Level 2		Level 3		Total
	(in thousands)
Non recurring
Assets:
Investment in affiliate	$	—	$	—	$	—	$	—
Dussafu PSC		—		—		28,000		28,000
	$	—	$	—	$	28,000	$	28,000

Recurring
Assets:
Embedded derivative asset	$	—	$	—	$	5,010	$	5,010
	$	—	$	—	$	5,010	$	5,010
Liabilities:
SARs liability	$	—	$	46	$	50	$	96
RSUs liability		—		174		—		174
Warrant derivative liability		—		—		5,503		5,503
	$	—	$	220	$	5,553	$	5,773

	As of December 31, 2014
	Level 1		Level 2		Level 3		Total
	(in thousands)
Non recurring
Assets:
Investment in affiliate	$	—	$	—	$	164,700	$	164,700
Dussafu PSC		—		—		50,324		50,324
	$	—	$	—	$	215,024	$	215,024
Recurring
Liabilities:
SARs liability	$	—	$	356	$	—	$	356
RSUs liability		—		652		—		652
	$	—	$	1,008	$	—	$	1,008

As of December 31, 2015, the fair value of our liability awards included $0.1 million for our SARs and $0.2 million for the RSUs which were recorded in accrued expenses and other long-term liabilities, respectively.  As of December 31, 2014, the fair value of our liability awards of $0.8 million was included in accrued liabilities ($0.4 million for our SARs and $0.4 million for our RSUs) with the remaining $0.2 million fair value of our RSU liability being included in long-term liabilities.

S-14

Derivative Financial Instruments

As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value liabilities and their placement within the fair value hierarchy levels. See Note 12 – Warrant Derivative Liability for a description and discussion of our warrant derivative liability as well as a description of the valuation models and inputs used to calculate the fair value.  See Note 11 – Debt and Financing for a description and discussion of our embedded derivatives related to our 9% Note and 15% Note as well as a description of the valuation models and inputs used to calculate the fair value.  All of our embedded derivatives and warrants are classified as Level 3 within the fair value hierarchy. 

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

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

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial assets -  embedded derivative asset
Beginning balance	$	—	$	—	$	—
Additions - fair value at issuance		2,504		—		—
Change in fair value		2,506		—		—
Ending balance	$	5,010	$	—	$	—

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial liabilities -  embedded derivative liability
Beginning balance	$	—	$	—	$	—
Additions - fair value at issuance		13,449		—		—
Change in fair value		(2,307)		—		—
Conversion of debt		(11,142)		—		—
Ending balance	$	—	$	—	$	—

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial liabilities -  warrant derivative liabilities:
Beginning balance	$	—	$	1,953	$	5,470
Additions - fair value at issuance		40,013		—		—
Change in fair value		(34,510)		(1,953)		(3,517)
Ending balance	$	5,503	$	—	$	1,953

S-15

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial liabilities -  stock appreciation rights
Beginning balance	$	—	$	—	$	—
Additions - fair value at issuance		—		—		—
Change in fair value		50		—		—
Ending balance	$	50	$	—	$	—

During the year ended December 31, 2015, 2014 and 2013, no transfers were made between Level 1, Level 2 and Level 3 liabilities or assets.

Share-Based Compensation

We use the fair value based method of accounting for share-based compensation. In prior years, we utilized the Black-Scholes option pricing model to measure the fair value of stock options and SARs. Restricted stock and RSUs were measured at their fair values.  During 2015, we issued options, SARs, and RSUs with an additional market condition.  To fair value these awards, a Monte Carlo simulation was utilized.  For more information about our share-based compensation, the fair value of these awards, and the additional market condition.   See Note 15 – Stock-Based Compensations and Stock Purchase Plans.

Income Taxes

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

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

Since December of 2013 we have provided deferred income taxes on undistributed earnings of our foreign subsidiaries where we are not able to assert that such earnings were permanently reinvested, or otherwise could be repatriated in a tax free manner, as part of our ongoing business.  As of December 31, 2015, the deferred tax liability provided on such earnings has been reduced to zero due to the impairment of the underlying book investment in Petrodelta.

As the conversion feature of the 9% Note was reasonably expected to be exercised at the time of the note’s issuance due to the conversion price being in-the-money, the interest on the 9% Note paid upon its conversion is non-deductible to the Company under Internal Revenue Code (“IRC”) Section 163(l).  The 15% Note was issued, for income tax purposes, with original issue discount (“OID”).  OID generally is deductible for income tax purposes.  However, if the debt instrument constitutes an “applicable high-yield discount obligation” (“AHYDO”) within the meaning of IRC Section 163(i)(1), then a portion of the OID likely would be non-deductible pursuant to IRC Section 163(e)(5).  Our analysis of the 15% Note is that the note may be an AHYDO; consequently, a portion or all of the OID likely may be non-deductible for income tax purposes.

S-16

Noncontrolling Interests

Changes in noncontrolling interest owners were as follows:

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Balance at beginning of period	$	79,152	$	243,167	$	97,101
Contributions by noncontrolling interest owners		3,382		1,208		—
Increase in equity held by noncontrolling interest owner		—		—		144,796
Dividend to noncontrolling interest owner		—		—		(10,370)
Net income (loss) attributable to noncontrolling interest owners		(82,087)		(165,223)		11,640
Balance at end of period	$	447	$	79,152	$	243,167

Valuation and Qualifying Accounts

Our valuation and qualifying accounts are comprised of the deferred tax valuation allowance, investment valuation allowance and Value-Added Tax (“VAT”) receivable valuation allowance. Balances and changes in these accounts are, in thousands:

			Additions
	Balance at Beginning of Year		Charged to Income			Other			Deductions From Reserves Credited to Income		Balance at End of Period
	(in thousands)
At December 31, 2015
Amounts deducted from applicable assets
Deferred tax valuation allowance	$	181,906	$	—		$	44,014		$	—	$	225,920
Investment valuation allowance		1,350		—			—			—		1,350
VAT valuation allowance		2,792		—			(2,792)	(b)		—		—
Long-term receivable - investment in affiliate		13,753		—			—			—		13,753
At December 31, 2014
Amounts deducted from applicable assets
Deferred tax valuation allowance	$	59,576	$	129,480		$	(7,150)	(a)	$	—	$	181,906
Investment valuation allowance		1,350		—			—			—		1,350
Long-term receivable - investment in affiliate		—		13,753	(c)		—			—		13,753
VAT valuation allowance		2,792		—			—			—		2,792
At December 31, 2013
Amounts deducted from applicable assets
Deferred tax valuation allowance	$	68,419	$	—		$	—		$	(8,843)	$	59,576
Investment valuation allowance		1,350		—			—			—		1,350
VAT valuation allowance		—		2,792			—			—		2,792

(a) Attributable to reversal of temporary differences related to discontinued operations.

(b) Valuation allowance for the VAT receivable associated with Harvest Budong.  On May 4, 2015, the Company sold the shares of Harvest Budong-Budong B.V. to Stockbridge Capital Limited and the rights to the VAT receivable went with the entity to the buyer.

(c) During the year ended December 31, 2014, we fully reserved a dividend receivable of $12.2 million and $1.6 million of long-term receivable due from our investment in affiliate.

New Accounting Pronouncements

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs”. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update.  In June 2015 the FASB issued ASU No. 2015-15 as an amendment to this guidance to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements.  The SEC staff stated that they would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-

S-17

credit arrangement.  The guidance is effective for interim periods and annual period beginning after December 15, 2015; however early adoption is permitted. We do not believe the adoption of this guidance will have a material impact on our financial position and will not have an impact on our results of operations or cash flows.

In August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern”ASU No. 2014-15. ASU No. 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU No. 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.

In April 2014, FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers” which is included in ASC 606, a new topic under the same name. The guidance in this update affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). The guidance supersedes the previous revenue recognition requirements and most industry-specific guidance. Additionally, the update supersedes some cost guidance related to construction type and production-type contracts.  In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in this update.

The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps:  (1) identify the contract(s) with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation.

The new guidance also provides for additional qualitative and quantitative disclosures related to: (1) contracts with customers, including revenue and impairments recognized, disaggregation of revenue, and information about contract balances and performance obligations (including the transaction price allocated to the remaining performance obligations); (2) significant judgments and changes in judgments which impact the determination of the timing of satisfaction of performance obligations (over time or at a point in time), the transaction price and amounts allocated to performance obligations; and (3) assets recognized from the costs to obtain or fulfill a contract.

In July 2015, the FASB issued a decision to delay related to ASU No. 2014-09 for the effective date by one year.  The new guidance is effective for annual and interim periods beginning after December 15, 2017.  An entity should apply the amendments either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of initial application. We are currently evaluating the impact of this guidance.

In November 2015, the FASB issued ASC No. 2015-17, “Balance Sheet Classification of Deferred Taxes”.  ASU No. 2015-17 simplifies the balance sheet presentation of deferred income taxes by requiring all deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The standard is effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted.  The standard may be applied either prospectively or retrospectively to all periods presented.  The Company has decided to adopt the accounting change in its current financial statements and has adopted the change retrospectively.

In February 2016, the FASB issued ASU No. 2016-02, “Leases”.  It is expected to be effective for periods beginning after December 15, 2018 for public entities, and for periods beginning after December 15, 2019 for nonpublic entities.  Early application is permitted.  Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less.  All other leases will fall into one of two categories: (1) Financing leases, similar to capital leases, will require the recognition of an asset and liability, measured at the present value of the lease payments.  Interest on the liability will be recognized separately from amortization of the asset.  Principal repayments will be classified as financing outflows and payments of interest as operating outflows on the statement of cash flows.  (2) Operating leases will also require the recognition of an asset and liability measured at the present value of the lease payments.  A single lease cost, consisting of interest on the obligation and amortization of the asset, calculated such that the amortization of the asset will increase as the interest amount decreases resulting in a straight-line recognition of lease expense.  All cash outflows will be classified as operating on the statement of cash flows.  We do not believe the adoption of this guidance will have a material impact on our financial position, results of operations or cash flows.

In March 2016, the FASB issued ASU No. 2016-07, “Investments — Equity Method and Joint Ventures (Topic 323)”. This amendment simplifies the accounting for equity method of investments, the amendment in the update eliminates the requirement in Topic 323 that an entity retroactively adopt the equity method of accounting if an investment qualifies for use of the equity method as a result of an increase in the level of ownership or degree of influence. The amendment requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt

S-18

equity method of accounting as of the date the investment becomes qualified for equity method accounting. The amendment in this update is effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. The amendment should be applied prospectively upon the effective date to increases in the level of ownership interest or degree of influence that result in the adoption of the equity method. Earlier application is permitted.  We are currently evaluating the impact of this guidance.

Note 4 – Earnings Per Share

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

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Loss from continuing operations(a)	$	(98,570)	$	(192,936)	$	(83,946)
Discontinued operations		—		(554)		(5,150)
Net loss attributable to Harvest	$	(98,570)	$	(193,490)	$	(89,096)
Weighted average common shares outstanding		45,288		42,039		39,579
Weighted average common shares, diluted		45,288		42,039		39,579
Basic loss per share:
Loss from continuing operations(a)	$	(2.18)	$	(4.59)	$	(2.12)
Discontinued operations		—		(0.01)		(0.13)
Basic loss per share	$	(2.18)	$	(4.60)	$	(2.25)
Diluted loss per share:
Loss from continuing operations(a)	$	(2.18)	$	(4.59)	$	(2.12)
Discontinued operations		—		(0.01)		(0.13)
Diluted loss per share	$	(2.18)	$	(4.60)	$	(2.25)

(a) Net of net income attributable to noncontrolling interest owners.

The year ended December 31, 2015 per share calculations above exclude 4.1 million options,  34.1 million warrants and 1.6 million RSUs because we are in a net loss position.   The year ended December 31, 2014 per share calculations above exclude0.2 million unvested restricted shares,4.5 million options and 2.5 million warrants because we were in a net loss position. The year ended December 31, 2013 per share calculations above exclude0.3 million unvested restricted shares,4.2 million options and 2.5 million warrants because we were in a net loss position.

Note 5 – Dispositions

Share Purchase Agreement

On December 16, 2013, Harvest and HNR Energia entered into the SPA 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 $400.0 million. The first closing occurred on December 16, 2013 contemporaneously with the signing of the SPA, when we sold a 29 percent equity interest in Harvest Holding for $125.0 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. 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 29 percent and Vinccler continuing to own 20 percent. The second closing, for the sale of a 51 percent equity interest in Harvest Holding for a cash purchase price of $275.0 million, was 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).

On May 7, 2014, Harvest’s stockholders voted to authorize the sale of the remaining interests in Harvest Holding.  Once stockholders’ approval was obtained, the SPA allowed for 120 days, or until September 7, 2014, for consummation of the sale, extension of the SPA or termination of the SPA.  Petroandina had the right to extend the SPA beyond the termination date in increments of one month, but not beyond December 31, 2014, in exchange for the Company’s right to borrow up to $2.0 million, not to exceed $7.6 million in the aggregate, from Petroandina per each monthly extension.  Petroandina exercised this right through

S-19

December 31, 2014 with the Company borrowing $7.6 million in total during this period.  Repayments of these loans are subject to certain conditions, one of which states that all outstanding loans (along with interest accrued and other amounts) would become due upon the final closing date of the SPA, with the second tranche proceeds being reduced by such outstanding amounts.  If the SPA was terminated by either party, any outstanding loans would become due one year from the date of the termination.

On January 1, 2015, HNR Energia exercised its right to terminate the SPA in accordance with its terms as a result of the failure to obtain the necessary approval from the Government of Venezuela. As a result of the termination of the SPA, the Company retained its 51 percent equity interest in Harvest Holding, and Petroandina retained its 29 percent equity interest in Harvest Holding.

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 became effective upon the termination of the SPA.

China

On July 2, 2014, we completed the sale of our rights under a petroleum contract with China National Offshore Oil Corporation for the WAB-21 area for net proceeds of $2.9 million and recorded that amount as a gain from sale of oil and naturalgas properties.  This area is located in the South China Sea and is the subject of a border dispute between China and Socialist Republic of Vietnam. 

Discontinued Operations

Oman

We have no continuing operations in Oman.  The nominal loss from discontinued operations for Oman for the year ended December 31, 2014 included general and administrative expenses.  The loss from discontinued operations for Oman of $0.7 million for the year ended December 31, 2013 included $0.2 million of exploration expense and $0.5 million of general and administrative expenses and other expenses.

Colombia

In February 2013, we signed farm-down agreements on Block VSM14 and Block VSM15 in Colombia. Under the terms of the farm-down 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 naturalgas regulatory authority, and approval of us as operator.

We received notices of default from our partners for failing to comply with certain terms of the farm-down agreements for Block VSM14 and Block VSM15, followed by notices of termination on November 27, 2013. Our partners filed for arbitration of claims related to these agreements. We accrued $2.0 million as of December 31, 2013 related to this matter. 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, which included the $2.0 million accrual related to arbitration, during the year ended December 31, 2013. In December 2014, we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed.  We are in the process of closing and exiting our Colombia venture.  As we no longer have any interests in Colombia, we have reflected the results in discontinued operations.  The loss from discontinued operations included $0.5 million in general and administrative expenses during the year ended December 31, 2014.  The loss from discontinued operations included $3.2 million in impairment expense, $0.7 million of exploration expense and $0.6 million in general and administrative expenses during the year ended December 31, 2013.

Oman and Colombia operations have been classified as discontinued operations. No revenues were recorded related to these projects for the years presented.  Expenses are shown in the table below:

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Loss from Discontinued Operations
Oman	$	—	$	(27)	$	(674)
Colombia		—		(527)		(4,476)
	$	—	$	(554)	$	(5,150)

S-20

Note 6 – Investment in Affiliate

Venezuela – Petrodelta, S.A.

The following table summarizes the changes in our investment in affiliate (Petrodelta) as of December 31, 2015 and 2014.  Petrodelta’s reporting and functional currency is the USD.

	Year Ended December 31,
	2015		2014
	(in thousands)
Investment at beginning of year	$	164,700	$	485,401
Equity in earnings				34,949
Impairment		(164,700)		(355,650)
Investment at end of period	$	—	$	164,700

Our 40 percent investment in Petrodelta is owned through our subsidiary, Harvest Holding, a Dutch private company with limited liability.   Up until December 16, 2013 we had an 80 percent interest in Harvest Holding.  On December 16, 2013, Harvest entered into a share purchase agreement (“SPA”) with Petroandina Resources Corporation to sell our 80 percent equity interest in Harvest Holding in two closings for an aggregate cash purchase price of $400.0 million.  The first closing occurred on December 16, 2013 when we sold a 29 percent equity interest in Harvest Holding for $125.0 million.  As a result of the first sale, we own 51 percent of Harvest Holding beginning December 16, 2013 and the non-controlling interest owners hold the remaining 49 percent.

The Company was not able to obtain approval from the government of Venezuela during 2014, which was required to complete the second closing for our remaining 51 percent interest in Petrodelta and on January 1, 2015 we terminated the SPA.   Due to our failed sales attempts, lack of management influence, and actions and inactions by the majority owner, PDVSA, we believe we no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.  Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.  

We performed an impairment analysis of the carrying value of our investment of Petrodelta as of December 31, 2014.  The estimated fair value of our investment was determined based on the estimated fair value of Petrodelta’s oil and natural gas properties and other net assets as of December 31, 2014, discounted by a factor for economic instability, foreign currency risks and lack of marketability.  Based on this analysis, we recorded a pre-tax impairment charge against the carrying value of our investment in Petrodelta of $355.7 million as of December 31, 2014. 

We also performed an impairment analysis of the carrying value of our investment of Petrodelta as of December 31, 2015 due to the continued decline in world oil prices and deteriorating economic conditions in Venezuela which have significantly impacted Petrodelta’s operations.  During 2015, Petrodelta’s operating costs exceeded the price realized from the sale of its production due to the significant rate of inflation in Venezuela and the restrictive foreign currency exchange system which Petrodelta is required to operate under.  While we believe that our relationship with CT Energy may allow us to restructure our relationship with PDVSA and Petrodelta and allow us to access the alternative foreign currency systems to companies in Venezuela, there can be no assurances that we will be successful in these negotiations.  Based on the existing economic environment in which Petrodelta is required to operate, we have concluded that the estimated fair value of our investment in Petrodelta is nil and have recorded a pre-tax impairment charge of $164.7 million to fully impair our investment in Petrodelta as of December 31, 2015. The estimated fair value of our investment was determined based on the estimated fair value of Petrodelta’s oil and natural gas properties and other net liabilities as of December 31, 2015 which exceeded the estimated fair value of the oil and natural gas properties.

The model used in the valuation of Petrodelta was based on an income approach which considered three scenarios relating to the future development of proved, probable and possible reserves and its other net liabilities at December 31, 2015.  The three scenarios considered that Petrodelta would have varying degrees of access to foreign exchange regimes as well as our ability to participate in and influence its operations to improve operational performance and efficiencies.  Each scenario also considered three price forecasts for crude oil.  The weighted average cost of capital of 26.5% was used to discount the future cash flows from these scenarios.  The expected value obtained from the income approach less net liabilities at December 31, 2015 resulted in a full impairment of the carrying value of our investment in Petrodelta.

In addition to the impairment charge, we recorded an allowance of $12.2 million to fully reserve the dividend receivable due from Petrodelta relating to the dividend declared in 2011 during the year ended December 31, 2014.

S-21

Petrodelta’s financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”) which we have adjusted to conform to U.S. GAAP for the years ending December 31, 2014 and 2013.  The year ended December 31, 2015 is excluded due to the change to the cost method of accounting.  The differences between IFRS and U.S. GAAP for which we adjusted are:

· Deferred income tax: IFRS allows the inclusion of non-monetary temporary differences impacted by inflationary adjustments, whereas U.S. GAAP does not. In addition, we have adjusted for the impact on deferred income tax of other adjustments to arrive at net income under U.S. GAAP.

· Depletion expense: Oil and naturalgas reserves used by Petrodelta in calculating depletion expense under IFRS are provided by Ministry of the People’s Power for Petroleum and Mining (“MENPET”). MENPET reserves are not prepared using the guidance on extractive activities for oil and naturalgas (ASC 932). Annually at year-end, we prepare reserve reports for Petrodelta’s oil and naturalgas reserves using ASC 932. On a quarterly basis, we recalculate Petrodelta’s depletion using the most recent reserve report using ASC 932 adjusted as appropriate.

· Under U.S. GAAP abandoned well costs are capitalized and depleted using the guidance on extractive activities for oil and natural gas under Successful Efforts accounting.  To conform to U.S. GAAP we reclassified $13.9 million in abandoned wells costs expensed to lease operating costs to depletable costs as per ASC932.

· Windfall Profits Tax Credit: The April 2011 Windfall Profits Tax law 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 from MENPET a Windfall Profits Tax exemption credit under provisions in the April 2011 Windfall Profits Tax law. The exemption was applied to several oil development projects, including Petrodelta. However, MENPET has not defined the projects qualifying for exemption or provided the guidance necessary to calculate the exemption. PDVSA issued to Petrodelta its estimated share of the exemption credit related to 2012 of $55.2 million ($36.4 million net of tax) based on PDVSA’s calculation and projects PDVSA deemed to qualify for the exemption. In July 2014, Petrodelta received confirmation that MENPET had denied PDVSA’s application for the exemption, and Petrodelta reversed its estimated share of the credit.  We determined that until MENPET either issues guidance on the exemption provisions in the 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 would exclude the exemption credit from our equity earnings in Petrodelta under U.S. GAAP.  In March 2013, we included an adjustment for the differences between IFRS and U.S. GAAP which reversed Petrodelta’s accrual for the Windfall Profits Tax credit, and in June 2014 we recorded an adjustment to Petrodelta’s reversal of the Windfall Profits Tax credit.

· Petrodelta’s revenues are not subject to a value-added tax (“VAT”).  However, most of their purchases are subject to VAT.  The result is that Petrodelta has $153.7 million of VAT receivables or VAT credits.   Petrodelta has recorded a corresponding valuation allowance of $38.2 million against these VAT credits.  At December 2014, the valuation allowance of the VAT credits was adjusted for our U.S. GAAP presentation.  Under U.S. GAAP, sufficient evidence did not exist to support Petrodelta’s assumptions of recoverability at December 31, 2014.  Therefore, for U.S. GAAP purposes the estimated recoverability of the VAT credits wasextended to 5 years and the discount rate was increased to 24.0%.  The discount rate approximates the December 31, 2014 yield on the 20-year Venezuelan 9 ¾ % bond.  The resulting value of the VAT credits, net of Petrodelta’s valuation allowance and U.S. GAAP adjustment, is $64.1 million at December 31, 2014.

· Sports Law Overaccrual: The Organic Law on Sports, Physical Activity and Physical Education (“Sports Law”) was published in the Official Gazette on August 24, 2011. The purpose of the Sports Law is to establish the public service nature of physical education and the promotion, organization and administration of sports and physical activity. Funding of the Sports Law is by contributions made by companies or other public or private organizations that perform economic activities for profit in Venezuela. The contribution is one percent of annual net or accounting profit and is not deductible for income tax purposes. Per the Sports Law, contributions are to be calculated on an after-tax basis. However, in March 2012, CVP has instructed Petrodelta to calculate the contribution on a before-tax basis contrary to the Sports Law. In addition to the adjustments to arrive at Petrodelta’s net income under U.S. GAAP, earnings from  affiliate also reflect the amortization of the excess basis in affiliate using the unit-of-production method based on risk adjusted total current estimated reserves.

S-22

All amounts through Net Income under U.S. GAAP represent 100 percent of Petrodelta. Summary financial information is presented for the years ended December 31, 2014 and 2013 and the financial position is presented at December 31, 2014.

	Year Ended December 31,
	2014			2013
Results under IFRS:	(in thousands, except percentages)
Revenues:
Oil sales	$	1,343,452		$	1,326,093
Natural gas sales		4,590			4,000
Royalty		(437,281)			(440,963)
		910,761			889,130
Expenses:
Operating expenses		303,409			141,627
Workovers		28,239			29,168
Depletion, depreciation and amortization		129,409			87,203
General and administrative		45,623			37,778
Windfall profits tax		140,816			234,453
Windfall profits (credit) and reversal of credit		55,168			(55,168)
		702,664			475,061
Income from operations		208,097			414,069
Gain (loss) on exchange rate		(260)			169,582
Investment earnings and other		7,752			1,414
Interest expense		137			(21,728)
Income before income tax		215,726			563,337
Current income tax expense		103,619			325,217
Deferred income tax expense (benefit)		(32,617)			(17,662)
Net income under IFRS		144,724			255,782
Adjustments to increase (decrease) net income under IFRS:
Deferred income tax (expense) benefit		(2,841)			9,080
Depletion expense		(12,437)			(20,353)
Adjustment to lease operating costs to conform with GAAP		13,888			—
Windfall profits credit and (reversal) of credit		55,168			(55,168)
Adjust fair value of value added tax credits		(51,393)			—
Sports law over accrual		1,322			1,313
Net income under U.S. GAAP		148,431			190,654
Interest in investment affiliate		40	%		40	%
Income before amortization of excess basis in investment in affiliate		59,372			76,262
Amortization of excess basis in investment in affiliate		(4,428)			(3,684)
Earnings from investment affiliate excluded from results of operations		(19,995)			—
Earnings from investment affiliate included Harvest's income	$	34,949		$	72,578

S-23

	As of December 31,
	2014
	(in thousands)
Financial Position under IFRS:
Current assets	$	1,459,676
Property and equipment		1,044,797
Other assets		241,478
Current liabilities		1,437,929
Other liabilities		147,242
Net equity		1,160,780

Conversion Contract

On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract was published in the Official Gazette. Petrodelta is governed by its own charter and bylaws and will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from that date. Petrodelta operates a portfolio of properties in eastern Venezuela including large proven oil fields as well as properties with substantial opportunities for both development and exploration. Petrodelta is to undertake its operations in accordance with Petrodelta’s business plan as set forth in its conversion contract. Under its conversion contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta.

Sales Contract

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

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

Since the Sales Contract provides for only one crude pricing formula, the Sales Contract had to be amended to include the Boscan pricing formula to allow Petrodelta to invoice PPSA for El Salto crude oil deliveries. Petrodelta received a draft amendment to the Sales Contract from PDVSA Trade and Supply. The pricing formula in the draft amendment has been used to accrue revenue for El Salto field deliveries from October 1, 2011 through December 31, 2014.Except for the inclusion of the Boscan pricing formula to be used in invoicing El Salto crude oil deliveries, all other terms and conditions of the Sales Contract remain in force. On January 31, 2013, Petrodelta’s board of directors endorsed the amendment to the Sales Contract. The amendment has been approved by CVP’s board of directors. HNR Finance, as shareholder, has agreed to the contract amendment. During 2015, Petrodelta completed billing PPSA for invoices for deliveries through December 2014.

CVP’s board of directors reviewed the amendment on April 30, 2013. A certificate of CVP’s final board resolution approving the amendment dated April 30, 2013 was received by Petrodelta on May 23, 2013. The remaining steps for the contract amendment are to (1) inform MENPET of the approval, (2) receive approval from Petrodelta’s shareholders to amend the Sales Contract including the Boscan formula, and (3) sign the contract amendment with PDVSA Trade and Supply.  As of December 31, 2014 revenues of $1,207.2 million ($756.7 million as of December 31, 2013) for El Salto remained uninvoiced to PPSA pending execution of the amendment. The amendment was signed in November 2014 and during January and February of 2015, Petrodelta completed billing

S-24

PPSA for deliveries through November 2014. This invoicing resulted in an additional $98.6 million in revenue being recognized in the fourth quarter of 2014 due to a pricing change in the formula included in the sales contract.

Payments to Contractors

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

Harvest Vinccler has advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, operations, seismic interpretation, and employee salaries and related benefits for Harvest Vinccler employees seconded into Petrodelta. Currently, we have three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. Harvest Vinccler is considered a contractor to Petrodelta, and as such, Harvest Vinccler is also experiencing the slow payment of invoices. Petrodelta and Petrodelta’s board have not indicated that the advances are not payable, or that they will not be paid. We fully reserved the outstanding receivables of $1.6 million related to these advances as of December 31, 2014, which was reflected in Harvest’s general and administrative costs.

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. The amended Windfall Profits Tax establishes new levels for contribution of extraordinary and exorbitant prices to the Venezuelan government. Extraordinary prices are considered to be above $60 and equal to or lower than $80 per barrel, and exorbitant prices are considered to be over $80 per barrel.

Functional Currency

Petrodelta’s functional and reporting currency is the USD. PPSA is obligated to make payment to Petrodelta in USD in the case of payment for crude oil and in Bolivars for natural gas liquids delivered. In addition, major contracts for capital expenditures and lease operating expenditures are denominated in USD. Any dividend paid by Petrodelta will be made in USD.

Petrodelta has currency exchange risk from fluctuations of the official prevailing exchange rate that applies to their operating costs denominated in 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. The Venezuelan government modified the currency exchange system whereby the official exchange rate of 6.3 Bolivars per USD would only apply to certain economic sectors related to purchases of “essential goods and services” while other sectors of the economy would be subject to a new exchange rate, SICAD I, determined by an auction process conducted by Venezuela's Complimentary System of Foreign Currency Administration. Participation in the SICAD I mechanism is controlled by the Venezuelan government and is limited to certain companies that operate in designated economic sectors.  In March 2014, an additional currency exchange mechanism was established by the Venezuelan government that allows companies within other economic sectors to participate in an additional auction process (“SICAD II”).  The exchange rate averaged  approximately 50 Bolivars per USD for the re-measurement of our Bolivar denominated assets and liabilities and revenue and expenses.  The financial information is prepared using the official fixed exchange rate (6.3 from February 2013 through December 2014). On February 10, 2015, the Ministry of Economy, Finance, and Public Banking, and the Central Bank of Venezuela (BCV) published in the Extraordinary Official Gazette No.6.171 Exchange Agreement No.33 with two Official Notices.  The first notice being that the SICAD II exchange rate would be no longer permitted.  Secondly, a new exchange rate called the Foreign Exchange Marginal System (“SIMADI”) has been created.  The SIMADI rate published on December 31, 2015 is 198.70 Bolivars per USD. The SIMADI’s marginal system is available in limited quantities for individuals and companies to purchase and sell foreign currency via banks and exchange houses.  Currently the SIMADI marginal system is the only mechanism available to Harvest Vinccler. 

S-25

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 USD 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 were signed. The Collective Labor Agreement established a salary raise and payroll and retirement benefits which had a significant impact on Petrodelta’s payroll cost. The most significant impact was a steep increase of salary around 90%, with 59% retroactive from October 1, 2013, a 23% raise in effect from May 1, 2014 and finally the remaining portion 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.  During the year ended December 31, 2014, we recorded an allowance of $12.2 million, which is reflected in Harvest’s general and administrative costs, to fully reserve the dividend due from Petrodelta.  This dividend has not been received as of December 31, 2015.

Note 7 – Venezuela – Other

Harvest Vinccler currently assists us in the oversight of our investment in Petrodelta and in negotiations with PDVSA. Harvest Vinccler’s functional and reporting currency is the USD. They do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”)

In January 2014, the Venezuelan government modified the currency exchange system whereby the official exchange rate of 6.3 Bolivars per USD would only apply to certain economic sectors related to purchases of “essential goods and services” while other sectors of the economy would be subject to a new exchange rate, SICAD I, determined by an auction process conducted by Venezuela's Complimentary System of Foreign Currency Administration. Participation in the SICAD I mechanism is controlled by the Venezuelan government and is limited to certain companies that operate in designated economic sectors.

In March 2014, an additional currency exchange mechanism was established by the Venezuelan government that allows companies within other economic sectors to participate in an additional auction process (“SICAD II”).

On February 10, 2015, the Ministry of Economy, Finance, and Public Banking, and the Central Bank of Venezuela (BCV) published in the Extraordinary Official Gazette No.6.171 Exchange Agreement No.33 with two Official Notices.  The first notice being that the SICAD II exchange rate would be no longer permitted.  Secondly, a new exchange rate called the Foreign Exchange Marginal System (“SIMADI”) has been created.  The SIMADI rate published on December 31, 2015 is 198.70 Bolivars per USD. The SIMADI’s marginal system is available in limited quantities for individuals and companies to purchase and sell foreign currency via banks and exchange houses.  Currently the SIMADI marginal system is the only mechanism available to Harvest Vinccler.

We have determined that Harvest Vinccler is not eligible to apply for exchanges at the official rate. We are eligible and have successfully participated in the SIMADI during 2015 and as a result we have adopted the SIMADI exchange rate of approximately 200 Bolivars per USD for the re-measurement of our Bolivar denominated assets and liabilities and revenue and expenses, as we believe the SIMADI rate is most representative of the economics in which Harvest Vinccler operates. Prior to this change, we were using the SICAD II rate of 50 Bolivars per USD.

During the year ended December 31, 2015, Harvest Vinccler exchanged approximately $0.1 million ($0.4 million during the year ended December 31, 2014) and received an average exchange rate of 212.4 Bolivars (34.4 Bolivars during the year ended December 31, 2014) per U.S. Dollar.  A gain on foreign currency transactions of $0.3 million was recognized during the year ended December 31, 2015 associated with participating in the SIMADI marginal system.  A loss on foreign currency transactions of $0.1 million was recognized during the year ended December 13, 2014 associated with participating in the SICAD II auction process.

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 6.3 Bolivar exchange rate. At December 31, 2015, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 11.9million Bolivars ($0.06million)  and  5.5million Bolivars ($0.03million), respectively.

S-26

Note 8 – Gabon

We are the operator of the Dussafu PSC with a 66.667 percent ownership interest. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC covers an area of 680,000 acres with water depths up to 1,650 feet.

The Dussafu PSC partners and the Republic of 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 Ministry of Mines, Energy, Petroleum and Hydraulic Resources agreed to lengthen the third exploration phase to four years until May 27, 2016.  The Company is currently assessing extension possibilities for the exploration phase.

During 2011, we drilled our first exploratory well, Dussafu Ruche Marin-1 (“DRM-1”), and two appraisal sidetracks.DRM-1 and the sidetracks are currently suspended pending further exploration and development activities.

Well planning progressed during 2012 to drill an exploration well in the fourth quarter of 2012 on the Tortue prospect. DTM-1 well was spud November 19, 2012. DTM-1 was drilled with the Scarabeo 3 semi-submersible drilling unit. On January 4, 2013, we announced that DTM-1 had reached the Dental Formation and discovered oil in both the Gamba and Dentale formations. The first appraisal sidetrack of DTM-1 (“DTM-1ST1”) was spud in January 12, 2013. DTM-1ST1 was drilled in the Dentale Formation. Due to a stuck downhole tool, logging operations were terminated before pressure data could be collected to confirm connectivity. The downhole tool was retrieved and the DTM-1 well suspended for future re-entry.

Operational activities during 2014 included additional evaluation of development alternatives, preparation and a formal remittance of a field development plan along with continued processing of 3D seismic acquired in 2013.  On March 26, 2014, the joint venture partners approved a resolution that the discovered fields are commercial to exploit.  On June 4, 2014, a Declaration of Commerciality (“DOC”) was signed with Gabon pertaining to the four discoveries on the Dussafu Project offshore Gabon.  Furthermore, on July 17, 2014, the Direction Generale Des Hydrocarbures (“DGH”) awarded an Exclusive Exploitation Authorization (“EEA”) for the development and exploitation of certain oil discoveries on the Dussafu Project and on October 10, 2014, the field development plan was approved. The Company has four years from the date of the EEA approval to begin production.

The Company is currently assessing alternatives to farm-down or sell the Dussafu Project, while weighing the liquidity requirements necessary to maintain ongoing Company operations.

Operational activities during the year ended December 31, 2015, included continued evaluation of development plans, based on the 3D seismic data acquired in late 2013 and processed during 2014. 

In December 2014, the Company recorded a $50.3 million impairment related to the unproved costs of the Dussafu PSC based on a qualitative analysis which considered our current liquidity needs, our inability to attract additional capital and the decrease in oil and natural gas prices.  In December 2015, the Company reassessed the carrying value of the unproved costs related to the Dussafu PSC and recorded an additional impairment of $23.2 million based on its analysis of the value of the unproved costs which considered the value of the contingent and exploration resources and the ability of the Company to develop the project given its current liquidity situation and the depressed price of crude oil.If oil and natural gas prices continue to deteriorate or we fail to obtain adequate financing, farm-down or sell the asset, additional impairments may be required on our prospect.

In the impairment analysis in December 2015, the Company prepared a quantitative and qualitative assessment of the unproved property which estimated the value of the estimated contingent and exploration resources based on the Company’s ability to develop the project given its current liquidity situation and the depressed price of crude oil.  The valuation model developed used three price scenarios and a development decision tree model which estimated the value of three development options available to the Company.  The value of the development options was determined using outputs from a Monte Carlo simulation model which estimated the net present value of expected future cash flow to be generated from the development of the contingent and exploratory resources in the Dussafu PSC and discounted using a weighted average cost of capital of 21.5%.  The development options considered the probability that the Company would be: a) able to farm-down50% of their working interest; b) able to sell their working interest; and c) unable to complete either of the first 2 options. All inputs used in the valuation process were primarily level 3 in the fair value hierarchy.The concluded fair value of the unproved property costs in our Dussafu project was $28.0 million.

We also reviewed the value of our oilfield inventories that are in the country of Gabon, of which the majority is steel conductor and casing.  We impaired the value of this inventory by approximately $1.0 million in 2015, leaving $3.0 million related to this inventory as of December 31, 2015.

See Note 13 – Commitments and Contingencies for a discussion related to our Gabon operations.

Note 9 – Indonesia

We fully impaired our investment in the Budong Production Sharing Contract (“Budong PSC”) in Indonesia as of March 31, 2014.  In June 2014, Harvest and our partner adopted a resolution to terminate the Budong PSC.  Harvest advised the Indonesian government of this decision and submitted a request to terminate the Budong PSC.   On February 5, 2015, the Company entered into a Share Purchase Agreement to transfer shares of Harvest Budong-Budong B.V. to Stockbridge Capital Limited for a nominal amount. 

S-27

On February 17, 2015, a withdrawal request of the earlier termination request was made to the Indonesian government and the withdrawal request was accepted on April 15, 2015.  The transfer of shares to Stockbridge Capital Limited was completed on May 4, 2015.

Note 10 – Notes Payable to Noncontrolling Interest Owners

At December 31, 2014, HNR Energia had a note payable to Vinccler of $6.1 million. Principal and interest were payable upon the maturity date of December 31, 2015.  On March 6, 2015, Vinccler forgave the note payable and accrued interest of $6.2 million.  This was reflected as a contribution to stockholders’ equity.

On August 28, 2014 Petroandina exercised its right to a one month extension of the termination date of the SPA.  In accordance with the extension the Company had the option to borrow $2.0 million from Petroandina, which it exercised.  Petroandina again extended the SPA on September 29, and October 30, 2014, with the Company borrowing $2.0 million per extension.  On November 27, 2014, Petroandina exercised their final extension and the Company borrowed the final maximum amount allowed of $1.6 million.  Quarterly interest payments began on December 31, 2014 with the principal due January 1, 2016.  The note payable with Petroandina as of December 31, 2014 was $7.6 million.  Interest accrued at a rate of 11.0%.  We were in default of the loan agreement with Petroandina for not making the April 1, 2015 interest payment.  After default the interest rate increased from 11.0% to 13.0%.On June 23, 2015, the Company repaid the note payable of $7.6 million plus accrued interest of $0.4 million.

Note 11 – Debt and Financing

On June 19, 2015, we issued the CT Warrant, 9% and 15% Notes, the Additional Draw Note and Series C preferred stock in connection with the Purchase Agreement with CT Energy and received proceeds of $30.6 million, net of financing fees of $1.6 million.  We identified embedded derivative assets and derivative liabilities in the notes and determined that the CT Warrant did not meet the required conditions to qualify for equity classification and was required to be classified as a warrant liability (see Note 12 – Warrant Derivative Liability).  The estimated fair value, at issuance, of the embedded derivative asset was $2.5 million, the embedded derivative liability was $13.5 million and the warrant liability was $40.0 million.  In accordance with ASC 815, the proceeds were first allocated to the fair value of the embedded derivatives and warrants, which resulted in no value being attributable to the Series C preferred stock and the 9% and 15% Notes. As a result of the allocation, we recognized a loss on the issuance of these securities of $20.4 million in our consolidated statements of operations and comprehensive loss during the year end December 31, 2015.

The following table summarizes the movement of our long-term debt due to related party net of discount:

	As of December 31,
Long-Term Debt	2015
	(in thousands)
Beginning balance	$	—
Proceeds from 9% and 15% Notes to CT Energy		32,200
Proceeds from note payable to CT Energy		1,300
Repayment of note payable to CT Energy		(1,300)
Value assigned to embedded derivatives		(32,200)
Conversion of 9% Note, net of unamortized discount		(11)
Accretion of discount on debt		225
	$	214

The face value of the 15% and 9% Noteswere recorded net of the discount related to the value allocated to the embedded derivatives and warrant.  The unamortized discount of the 15% Note was $25.0 million at December 31, 2015. The Company will accrete the discount over the life of the note using the interest method.Total interest expense associated with this note was $2.2 million, comprised of $2.0 million related to the stated rate of interest on the note and $0.2 million related to the accretion of the discount on the debt.  The effective interest rate on the note is approximately 141%.  The fair value of the 15% Note at December 31, 2015 was $8.8 million.

15% Non-Convertible Senior Secured Note due June 19, 2020

On June 19, 2015, in connection with the transaction with CT Energy described in Note 1 – Organization, we issued the five-year, 15% Note in the aggregate principal amount of $25.2 million with interest that is compounded quarterly at a rate of 15% per annum and is payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2015.  If by June 19, 2016, the volume weighted average price of the Company’s common stock over any consecutive 30-day period has not equaled or exceeded $2.50 per share, the maturity date of the 15% Note will be extended by two years and the interest rates on the

S-28

15% Note will adjust to 8.0% (the “15% Note Reset Feature”).  During an event of default, the outstanding principal amount bears additional interest at a rate of 2.0% per annum higher than the rate otherwise applicable.

The Company may prepay all or a portion of the note at a prepayment price equal to a make-whole price, as of the prepayment date, with respect to the principal amount of the note being prepaid, plus accrued and unpaid interest.  The make-whole price is defined as the greater of (i) 100% of such outstanding principal amount of the 15% Note and (ii)  the sum of the present values as of such date of determination of (A) such outstanding principal amount of the 15% Note, assumed, for the purpose of determining the present value thereof, to be paid on the earlier of the stated maturity of this 15% Note or the date that is two years after the date of determination, and (B) all remaining payments of interest (excluding interest accrued to the prepayment date) scheduled to become due and payable after the date of determination and on or before the date that is two years after the date of determination with respect to such outstanding principal amount of the 15% Note, in the case of each of the foregoing clauses (ii)(A) and (B), computed using a discount rate equal to the Treasury Rate as of the date of determination plus 50 basis points.

If an event of default occurs (other than an event of default related to certain bankruptcy events), holders of at least 25% of the outstanding principal of the 15% Note may declare the principal, premium, if any, and accrued and unpaid interest of such notes immediately due and payable.  If an event of default related to specified bankruptcy events occurs, an amount equal to the make-whole price for the 15% Note plus accrued and unpaid interest is immediately due and payable. 

We have evaluated the 15% Note Reset Feature related to the interest rate and maturity date using “ASC 815 Derivatives and Hedging”.  Because the interest rate and maturity date reset are linked to achievement of a certain stock price, the feature is not considered clearly and closely related to the debt host. In addition, the interest rate at the reset date is not tied to any approximation of the expected market rate at the date of the term extension as required by ASC 815.  As a result, we are accounting for the 15% Note Reset Feature as an embedded derivative asset that has been measured at fair value with current changes in fair value reflected in our consolidated statements of operations and comprehensive loss.

The embedded 15% Note Reset Feature in the 15% Note was valued using the ‘with’ and ‘without’ method.  A Black-Derman-Toy (“BDT”) Model, which is a binomial interest rate lattice model, was used to value the 15% Note and the incremental value attributed to the embedded option was determined based on a comparison of the value of the 15% Note with the feature included and without the feature included.  Key inputs into this valuation model are our current stock price, U.S. Treasury rate, our credit spread and the underlying yield volatility.  As part of our overall valuation process, management employs processes to evaluate and validate the methodologies, techniques and inputs, including review and approval of valuation judgments, methods, models, process controls, and results. These processes are designed to help ensure that the fair value measurements and disclosures are appropriate, consistently applied, and reliable. We estimate the yield volatility for the 15% Note based on historical daily volatility of the USD denominated Venezuela Sovereign zero coupon yield over a look back period of 6.0 years.  The risk-free interest rate is based on the U.S. Treasury yield curve as of the valuation dates for a maturity similar to the expected remaining life of the 15% Note. The credit spread was estimated based on the option adjusted spread (“OAS”) of the Venezuelan yield over the USD Treasury yield and the implied OAS for the transaction as of the date the term sheet was signed to capture the investor’s assessment of the risk in their investment in the Company.  This model requires Level 3 inputs (see Note 3 – Summary of Significant Accounting Policies, Financial Instruments and Fair Value Measurements) which were based on our estimates of the probability and timing of potential future financings and fundamental transactions.

S-29

The assumptions summarized in the following table were used to calculate the fair value of the derivative asset associated with the 15% Note at the date of issuance:

	Fair Value
	Hierarchy
	Level	June 19, 2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	1.82
Weighted Term (years)			5.0
Yield Volatility	Level 2 input		32.5	%
Risk-free rate	Level 1 input		1.6% to 2.0	%
Dividend yield	Level 2 input		0.0	%
Scenario probability:
Claim date extended with Stock Appreciation Date threshold met	Level 3 input		60.0	%
Claim date extended with Stock Appreciation Date threshold not met	Level 3 input		42.5	%
Claim date not extended with Stock Appreciation Date threshold met	Level 3 input		60.0	%
Claim date not extended with Stock Appreciation Date threshold not met	Level 3 input		40.2	%
Scenario probability (future draws/no future draws)	Level 3 input		50%/50	%

The embedded derivative asset related to the 15% Note contains a Level 3 input related to the probability of our investor lending us additional funds or not lending us funds according to the terms of the loan agreement for the additional draws.  We have assumed a 50/50 scenario of the draw or no draw for valuation of the embedded derivative.  Changes in this assumption have minimal impacts on the embedded derivative asset valuation as HNR stock price is the primary driver of the value. 

The assumptions summarized in the following table were used to calculate the fair value of the derivative asset associated with the 15% Note that was outstanding as of December 31, 2015 on our consolidated balance sheet:

	Fair Value
	Hierarchy	As of December 31,
	Level	2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	0.43
Weighted Term (years)			4.47
Yield Volatility	Level 2 input		35	%
Risk-free rate	Level 1 input		1.6% to 2.0	%
Dividend yield	Level 2 input		0.0	%
Scenario probability:
Claim date extended with Stock Appreciation Date threshold met	Level 3 input		54.8	%
Claim date extended with Stock Appreciation Date threshold not met	Level 3 input		36.1	%
Claim date not extended with Stock Appreciation Date threshold met	Level 3 input		54.8	%
Claim date not extended with Stock Appreciation Date threshold not met	Level 3 input		33.4	%
Scenario probability (future draws/no future draws)	Level 3 input		50%/50	%

The fair value of the embedded derivative asset was $2.5 million at issuance and $5.0 million as of December 31, 2015.  We recognized $2.5 million in income related to the change in fair value of this embedded derivative asset in change in fair value of derivative assets and liabilities in our consolidated statement of operations for the year ended December 31, 2015.

15% Non-Convertible Senior Secured Additional Draw Note

On June 19, 2015, in connection with the transaction with CT Energy described in Note 1 – Organization, the Company also issued the Additional Draw Note which, under certain circumstances, CT Energy may elect to provide $2.0 million of additional funds to the Company per month for up to six months following the one-year anniversary of the closing date of the transaction (up to $12.0 million in aggregate).  If funds are loaned under the Additional Draw Note, interest will be compounded quarterly at a rate of 15.0% per annum and will be payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2016.  If by the Claim Date, the volume weighted average price of the Company’s common stock over any consecutive 30-day period has not equaled or exceeded $2.50 per share, the maturity date of the Additional Draw Note will be extended by two years and the interest rate on the Additional Draw Note will adjust to 8.0%. During an event of default, the outstanding principal amount will bear additional interest at a rate of 2.0% per annum higher than the rate otherwise applicable.

S-30

The Company may prepay all or a portion of the Additional Draw Note at a prepayment price equal to the make-whole price, as of the prepayment date, with respect to the principal amount of the Additional Draw Note being prepaid, plus accrued and unpaid interest. The make-whole price with respect to the Additional Draw Note has the same meaning described above with respect to the 15% Note under.

If an event of default occurs (other than an event of default related to certain bankruptcy events), holders of at least 25% of the outstanding principal of the 15% Note (including the Additional Draw Note, if outstanding) may declare the principal, premium, if any, and accrued and unpaid interest of such notes immediately due and payable.  If an event of default related to specified bankruptcy events occurs, an amount equal to the make-whole price for the Additional Draw Note plus accrued and unpaid interest is immediately due and payable.  

Because we have not withdrawn any proceeds on this note at issuance and at December 31, 2015, we have assigned no value to the Additional Draw Note, as it does not meet the definition of a derivative in ASC 815 and there is no principal amount outstanding.

9% Convertible Senior Secured Note due June 19, 2020

On June 19, 2015, in connection with the transaction with CT Energy described in Note 1 – Organization we issued the five-year, 9% Note in the aggregate principal amount of $7.0 million, which was immediately convertible into 8,506,098 shares of the Company’s common stock, par value $0.01 per share, at an initial conversion price of $0.82 per share (“Beneficial Conversion Feature”).

Interest on the 9% Note was compounded quarterly at a rate of 9.0% per annum and was payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2015.  If by June 19, 2016, the volume weighted average price of the Company’s common stock over any consecutive 30-day period had not equaled or exceeded $2.50 per share, the maturity date of the 9% Note will be extended by two years and the interest rates on the 9% Note will adjust to 8.0% (the “9% Note Reset Feature”). 

Regarding the 9% Note Reset Feature, because the interest rate and maturity date reset were linked to achievement of a certain stock price, the feature was not considered clearly and closely related to the debt host. In addition, the interest rate at the reset date was not tied to any approximation of the expected market rate at the date of the term extension as required by ASC 815.  As a result, we accounted for the 9% Note Reset Feature as an embedded derivative asset that was measured at fair value with current changes in fair value reflected in change of fair value of derivative assets and liabilities in our consolidated statements of operations and comprehensive loss.  The changes in the fair value of this embedded derivative asset was netted against the changes in the fair value of the embedded derivative liabilities relating to the 9% Down-Round Provision and Note Reset Feature discussed below.

The conversion price was subject to adjustment upon the occurrence of certain events, including a stock issuance, dividend, or stock split.   If the Company completes an issuance of common stock at a price less than the current conversion price, then the conversion price will be fully reduced to the new issuance price for such below-price issuance (the “9% Down-Round Provision”).  This is a full ratchet down round provision that could compensate the holder for an amount greater than dilution related to a stock issuance.  For example, in the event of an issuance of stock causing a 10% dilution, the note holder could theoretically be compensated greater than 10% under certain circumstances. 

The embedded 9% Down-Round Provision and the 9% Note Reset Feature were valued using the ‘with’ and ‘without’ method.  A Binomial Lattice Model was used to value the 9% Note and the incremental value attributed to the embedded options was determined based on a comparison of the value of the 9% Note with the features included and without the features included.  Key inputs into this valuation model were our current stock price, U.S. Treasury rate, our credit spread and the underlying stock price volatility.  As part of our overall valuation process, management employs processes to evaluate and validate the methodologies, techniques and inputs, including review and approval of valuation judgments, methods, models, process controls, and results. These processes are designed to help ensure that the fair value measurements and disclosures are appropriate, consistently applied, and reliable. We estimated the volatility of our common stock based on historical volatility that matches the expected remaining life of the longest instrument in the transaction, seven years. The risk-free interest rate was based on the U.S. Treasury yield curve as of the valuation dates for a maturity similar to the expected remaining life of the 9% Note.  The credit spread was estimated based on the option adjusted spread (“OAS”) of the Venezuelan yield over the USD Treasury yield and the implied OAS for the transaction as of the date the term sheet was signed to capture the investor’s assessment of the risk in their investment in the Company.  This model requires Level 3 inputs (see Note 3 – Summary of Significant Accounting Policies, Financial Instruments and Fair Value Measurements) which were based on our estimates of the probability and timing of potential future draws.

We have evaluated the 9% Down-Round Provision and the 9% Note Reset Feature using ASC 815. The Convertible Down-Round Provision is not consistent with a fixed-price-for-fixed-number of shares instrument and therefore precludes the conversion option from being indexed to the Company’s own stock. As a result, the conversion option did not meet the scope exception in ASC 815 and was bifurcated as a separate liability that has been measured at fair value with current changes in fair value reflected in our consolidated statements of operations and comprehensive loss.

S-31

The fair value of the net embedded derivative liabilities was $13.5 million at issuance and $11.1 million immediately prior to the conversion of the 9% Note.  We recognized $2.3 million in income for the change in the fair value of this embedded derivative liabilities in our consolidated statement of operations for the year ended December 31, 2015.

On September 15, 2015, the 9% Note,  the associated accrued interest and related derivative liabilities were converted into 8,667,597shares of the Company’s common stock.  The Company recognized a $1.9 million loss on debt conversion.   The $1.9 million loss on debt conversion was the result of the difference between the September 14, 2015 carrying value of the 9% Note, including accrued interest and unamortized debt discount  ($0.2 million) and the fair value of therelated derivative liabilities  ($11.1 million) less the fair value of the 8,667,597 shares issued upon conversion  ($13.2 million) at September 15, 2015.

The assumptions summarized in the following table were used to calculate the fair value of the net embedded derivative liability associated with the 9% Note at the date of issuance:

	Fair Value
	Hierarchy
	Level	June 19, 2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	1.82
Term (years)			5.0
Volatility	Level 2 input		90	%
Risk-free rate (base)	Level 1 input		0.27	%
Risk-free rate (5 year)	Level 1 input		2.05	%
Risk-free rate (7 year)	Level 1 input		2.40	%
Dividend yield	Level 2 input		0.0	%

Note 12 – Warrant Derivative Liability

CT Warrant

On June 19, 2015, in connection with the transaction with CT Energy described in Note 1 – Organization, we issued a warrant exercisable for 34,070,820 shares of the Company’s common stock at an initial exercise price of $1.25 per share.  The CT Warrant may not be exercised until the volume weighted average price of the Company’s common stock over any consecutive 30-day period equals or exceeds $2.50 per share.

The CT Warrant can be exercised at the option of the investor in cash or by effecting a reduction in the principal amount of the 15% Note (See Note 11 – Debt and Financing).  If the CT Warrant is exercised through the reduction in the principal amount of the 15% Note, the reduction will be equal to the amount obtained by multiplying the number of shares of common stock for which the CT Warrant is exercised by (i) the exercise price then in effect divided by (ii) (A) the defined make-whole price with respect to the outstanding principal amount of such 15% Note divided by (B) the outstanding principal amount of such 15% Note.  The exercise price of the CT Warrant is subject to adjustment upon the occurrence of certain events, including stock issuance, dividend or stock split.

In addition, the holder of the CT Warrant has certain registration rights regarding the CT Warrant and the shares of common stock issuable upon exercise of the CT Warrant.

We have analyzed the CT Warrant to determine whether it should be classified as a derivative liability or equity instrument.  Provisions of the CT Warrant agreement allow for a change in the exercise price of the CT Warrant upon the occurrence of certain corporate events.  These exercise price adjustments incorporate variables other than those used to determine the fair value of a fixed-for-fixed forward or option on equity shares therefore the CT Warrant is not considered to be “indexed to the issuer’s own stock” and does not meet the exception from derivative treatment in ASC 815.  HNR continues to account for the CT Warrant as a derivative which was marked to market as of December 31, 2015.  

Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument with related changes in internal and external market factors. In addition, option-based techniques (such as the Monte Carlo model) are highly volatile and sensitive to changes in the trading market price of our common stock. Since derivative financial instruments are initially and subsequently carried at fair value, our income will reflect the volatility in these estimate and assumption changes.  A Monte Carlo simulation model is used to value the CT Warrant to determine if the Stock Appreciation Date is achieved, which is based on the average stock price over a 30 day period (21 trading days) reaching $2.50.  This requires Level 3 inputs (see Note 3 – Summary of Significant Accounting Policies, Financial Instruments and Fair Value Measurements) which arefundamentally based on market data but require complex modeling.  The additional modeling is

S-32

required in order to simulate future stock prices, to determine whether the Stock Appreciation Date is achieved and to model the projected exercise behavior of the warrant holders.  

The assumptions summarized in the following table were used to calculate the fair value of the warrant derivative liability at the date of issuance:

	Fair Value
	Hierarchy
	Level	June 19, 2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	1.82
Exercise price	Level 1 input	$	1.25
Stock appreciation date price (hurdle)	Level 1 input	$	2.50
Term (warrants)			3.0
Term (claim date)			1.0
Term (claim date extended)			1.5
Volatility	Level 2 input		90.0	%
Risk-free rate (warrants)	Level 1 input		1.09	%
Risk-free rate (claim date)	Level 1 input		0.27	%
Risk-free rate (claim date extended)	Level 1 input		0.48	%
Dividend yield	Level 2 input		0.0	%

The assumptions summarized in the following table were used to calculate the fair value of the warrant derivative liability that was outstanding as of the balance sheet date presented on our consolidated balance sheet:

	Fair Value
	Hierarchy	As of December 31,
	Level	2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	0.43
Exercise price	Level 1 input	$	1.25
Stock appreciation date price (hurdle)	Level 1 input	$	2.50
Term (warrants)			2.4668
Term (claim date)			0.4672
Term (claim date extended)			0.9672
Volatility	Level 2 input		110.0	%
Risk-free rate (warrants)	Level 1 input		1.27	%
Risk-free rate (claim date)	Level 1 input		0.55	%
Risk-free rate (claim date extended)	Level 1 input		0.70	%
Dividend yield	Level 2 input		0.0	%

Inherent in the Monte Carlo valuation model are assumptions related to expected stock price volatility, expected life, risk-free interest rate and dividend yield. As part of our overall valuation process, management employs processes to evaluate and validate the methodologies, techniques and inputs, including review and approval of valuation judgments, methods, models, process controls, and results. These processes are designed to help ensure that the fair value measurements and disclosures are appropriate, consistently applied, and reliable. We estimate the volatility of our common stock based on historical volatility that matches the expected remaining life of the longest instrument in the transaction, seven years. The risk-free interest rate is based on the U.S. Treasury yield curve as of the valuation dates for a maturity similar to the expected remaining life of the CT Warrant. The expected life of the CT Warrants is assumed to be equivalent to their remaining contractual term. The dividend rate is based on the historical rate, which we anticipate to remain at zero.

The fair value of the CT Warrant was $40.0 million at issuance and $5.5 million as of December 31, 2015.  We recognized income of $34.5 million related to thechange in fair value of the warrant liability in our consolidated statement of operations and comprehensive loss for the year ended December 31, 2015.

S-33

MSD Warrants

On October 28, 2015, the warrants issued as inducements in connection with a $60 million term loan facility that was paid off in May 2011(“MSD Warrants”) expired (1,846,088 warrants outstanding: December 31, 2014).  The fair value of these warrants as of December 31, 2014 and at expiration was $0.00 per warrant.  The Warrant Purchase Agreement dated as of October 28, 2010 includes certain anti-dilution provisions which adjust the number of warrants and the exercise price per warrant.   The issuance of the CT Energy 9% Note, because of the initial conversion price and the CT Warrant of 34,070,820 shares triggered the anti-dilution provisions on the MSD Warrants which resulted in the issuance of 1,547,739 additional warrants during the year ended December 31, 2015.  In addition, the exercise price per share for all warrants was repriced to $6.97 per warrant during the year ended December 31, 2015.  The warrants had been classified as a liability on our consolidated balance sheets and marked to market.  The valuation for the warrants had based primarily on our stock price of $1.81 at December 31, 2014, their remaining life of 0.83 years and their strike price of $6.97 as of December 31, 2014.  We recognized $0.0 million in warrant liability income in our consolidated statement of operations and comprehensive loss year ended December 31, 2015 for these warrants ($2.0 million and $3.5 million for the years ended December 31, 2014 and 2013, respectively).  The assumptions summarized in the following table were used to calculate the fair value of the warrant derivative liability related to the MSD warrants that were outstanding at December 31, 2014:

	Fair Value
	Hierarchy	As of December 31,
	Level	2014
Significant assumptions (or ranges):
Stock price	Level 1 input	$	1.81
Term (years)			0.83
Volatility	Level 2 input		67	%
Risk-free rate	Level 1 input		0.21	%
Dividend yield	Level 2 input		0.0	%
Scenario probability (fundamental change event/debt raise/equity raise)	Level 3 input		0%/100%/0	%

Note 13 – Commitments and Contingencies

We have employment contracts with five executive officers which provide for annual base salaries, eligibility for bonus compensation and various benefits. The contracts provide for a lump sum payment as a multiple of base salary in the event of termination of employment without cause. In addition, these contracts provide for payments as a multiple of base salary and bonus, excise tax reimbursement, outplacement services and a continuation of benefits in the event of termination without cause following a change in control. By providing one year notice, these agreements may be terminated by either party on or before May 31, 2016.

We have various contractual commitments pertaining to leasehold, training, and development costs for the Dussafu PSC totaling $4.5 million. Under the EEA granted for the Dussafu PSC on July 17, 2014, we are required to commence production within four years of the date of grant in order to preserve our rights to production under the EEA.  We expect that significant capital expenditures will be required prior to commencement of production which is expected in 2016 under the approved field development plan. These work commitments are non-discretionary; however, we do have the ability to control the pace of expenditures.The table below consists of our contractual commitments for office space and various other commitments:

	Payments Due by Period
			Less than
	Total		1 Year		1 - 2 Years		3-4 Years		After 4 Years
	(in thousands)
Obligations:
Oil and  natural gas activities	$	4,520	$	1,130	$	1,130	$	1,130	$	1,130
Office leases		171		157		14		—		—
Total contractual obligations	$	4,691	$	1,287	$	1,144	$	1,130	$	1,130

Under the agreements with our partners in the Dussafu PSC and the Budong PSC, we are jointly and severally liable to various third parties. As of December 31, 2015, the gross carrying amount associated with obligations to third parties which were fixed at the end of the period was $0.3 million ($2.4 million as of December 31, 2014) and is related to accounts payable to vendors, accrued expenses and withholding taxes payable to taxing authorities. As we are the operators for the Dussafu PSC and Budong PSC, the gross carrying amount related to accounts payable and withholding taxes and the net amount related to other accrued expenses are reflected in the consolidated balance sheet in accounts payable and accrued expenses leaving $0.1 million in fixed obligations as of December 31, 2015  ($0.3 million as of December 31, 2014) attributable to our joint partners’ share which is not accrued in our balance sheet. Our partners have advanced$0.0 million($0.5 million as of December 31, 2014) to satisfy their share of these obligations which was$0.1 million as of December 31, 2015  ($0.8 million as of December 31, 2014). As we expect our partners will continue to meet their

S-34

obligations to fund their share of expenditures, we have not recognized any additional liability related to fixed joint interest obligations attributable to our joint interest partners.

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 alleged that the area belonged to the people of Taiwan and sought 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, and the WAB-21 area.  The Company filed a motion to dismiss the suit, which was granted by the district court in August 2014.  The plaintiffs appealed the dismissal.  The Fifth Circuit Court of Appeals heard oral arguments on June 3, 2015 and affirmed the district court’s dismissal on June 4, 2015.  The plaintiffs filed a petition for writ of certiorari with the Supreme Court of the United States. On October 13, 2015, the Supreme Court denied the petition.

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.  We are currently unable to estimate the amount or range of any possible loss.

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.  We are currently unable to estimate the amount or range of any possible loss.

On May 31, 2011, the United Kingdom branch of our subsidiary, Harvest Natural Resources, Inc. (UK), initiated a wire transfer of approximately $1.1 million ($0.7 million net to our 66.667 percent interest) intending to pay Libya Oil Gabon S.A. (“LOGSA”) for fuel that LOGSA supplied to our subsidiary in the Netherlands, Harvest Dussafu, B.V., for the company’s drilling operations in Gabon. On June 1, 2011, our bank notified us that it had been required to block the payment in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by OFAC, because the payee, LOGSA, may be a blocked party under the sanctions. The bank further advised us that it could not release the funds to the payee or return the funds to us unless we obtain authorization from OFAC. On October 26, 2011, we filed an application with OFAC for return of the blocked funds to us. 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. On April 23, 2014, we received a notice that OFAC had denied our October 26, 2011 application for the return of the blocked funds.   During the year ended December 31, 2015 primarily due to the passage of  time, we recorded a $0.7 million allowance for doubtful accounts to general and administrative costs associated with the blocked payment and $0.4 million receivable from our joint venture partner.   On October 13, 2015, we filed a request that OFAC reconsider its decision and on March 8, 2016 OFAC denied our October 13, 2015 request for the return of blocked funds; however, the Company will continue attempts to recover the funds from 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. The court administratively closed the case in 2013. The case was reopened in 2014 as a result of a Circuit Court of Appeals’ ruling.  On November 3, 2015, the court granted a stipulated motion to dismiss with prejudice and the lawsuit was dismissed.

Uracoa Municipality Tax Assessments. Harvest Vinccler, a subsidiary of Harvest Holding, 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:

S-35

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

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

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

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

Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions 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:

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

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

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

Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. 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 January 15, 2015, HNR Finance and Harvest Vinccler S.C.A submitted a Request for Arbitration against the Government of Venezuela before the International Centre for Settlement of Investment Disputes ("ICSID") regarding HNR Finance's interest in Petrodelta.  The Request for Arbitration set forth numerous claims, including (a) the failure of the Venezuelan government to approve the Company’s negotiated sale of its 51 percent interest in Harvest Holding to Petroandina on any reasonable grounds in 2013-2014, resulting in the termination of the SPA (b) the failure of the Venezuelan government to approve the Company’s previously negotiated sale of its interest in Petrodelta to PT Pertamina (Persero) on any reasonable grounds in 2012-2013, resulting in the termination of a purchase agreement entered into between HNR Energia and PT Pertamina (Persero); (c) the failure of the Venezuelan government to allow Petrodelta to pay approved and declared dividends for 2009; (d) the failure of the Venezuelan government to allow Petrodelta to approve and declare dividends since 2010, in violation of Petrodelta’s bylaws and despite Petrodelta’s positive financial results between 2010 and 2013; (e) the denial of Petrodelta’s right to fully explore the reserves within its designated areas; (f) the failure of the Venezuelan government to pay Petrodelta for all hydrocarbons sales since Petrodelta’s incorporation, recording them instead as an ongoing balance in the accounts of PDVSA, the Venezuelan government-owned oil company that controls Venezuela’s 60 percent interest in Petrodelta, and as a result disregarding Petrodelta’s managerial and financial autonomy; (g) the failure of the Venezuelan government to pay Petrodelta in US dollars for the hydrocarbons sold to PDVSA, as required under the mixed company contract; (h) interference with Petrodelta’s operations, including PDVSA’s insistence that PDVSA and its affiliates act as a supplier of materials and equipment and provider of services to Petrodelta; (i) interference with Petrodelta’s financial management, including the use of low exchange rates Bolivars/US dollars to the detriment of the Company and to the benefit of the Venezuelan government, PDVSA and its

S-36

affiliates; and (j) the forced migration of the Company’s investment in Venezuela from an operating services agreement to a mixed company structure in 2007.

On January 26, 2015, Petroandina filed a complaint for breach of contract against the Company and its subsidiary HNR Energia in Court of Chancery of the State of Delaware (“Court of Chancery”).  The complaint states that HNR Energia breached provisions of the Shareholders Agreement between Petroandina and HNR Energia, which provisions require HNR Energia to provide advance notice of, and deposit $5.0 million into an escrow account, before bringing any claim against the Venezuelan government. Under those provisions, if Petroandina so requests, an appraisal of Petroandina's 29 percent interest in Harvest Holdings must be performed, and Petroandina has the right to require HNR Energia to purchase that 29 percent interest at the appraised value.  Petroandina's claim requests that, among other things, the court (a) declare that HNR Energia has breached the Shareholders' Agreement by submitting the Request for Arbitration against the Venezuelan government on January 15, 2015 (which Request for Arbitration was subsequently withdrawn without prejudice); (b) declare that the Company has breached its guaranty of HNR Energia's obligations under the Shareholders' Agreement; (c) direct the Company and HNR Energia to refrain from prosecuting any legal proceeding against the Venezuelan government (including the previously filed Request for Arbitration) until such time as they have complied with the relevant provisions of the Shareholders' Agreement; (d) award Petroandina costs and fees related to the lawsuit; and (e) award Petroandina such other relief as the court deems just and proper.On January 28, 2015, the Court of Chancery issued an injunction ordering the Company and HNR Energia to withdraw the Request for Arbitration and not take any action to pursue its claims against Venezuela until Harvest and HNR Energia have complied with the provisions of the Shareholders’ Agreement or otherwise reached an agreement with Petroandina.  Accordingly, on January 28, 2015, HNR Finance B.V. and Harvest Vinccler S.C.A. withdrew without prejudice the Request for Arbitration. In the Delaware proceeding, the Company and HNR Energia have until May 23, 2016 to respond to Petroandina’s complaint.We are currently unable to estimate the amount or range of any possible loss.

On February 27, 2015, Harvest (US) Holdings, Inc. (“Harvest US”), a wholly owned subsidiary of Harvest, Branta, LLC and Branta Exploration & Production Company, LLC (together, “Branta,” and together with Harvest US, “Plaintiffs”) filed a complaint against Newfield Production Company (“Newfield”) in the United States District Court for the District of Colorado.  Plaintiffs previously sold oil and natural gas assets located in Utah’s Uinta Basin to Newfield pursuant to two Purchase and Sale Agreements, each dated March 21, 2011.  In the complaint, Plaintiffs allege that, prior to the sale, Newfield breached separate confidentiality agreements with Harvest US and Branta by discussing the auction of the assets with a potential bidder for the assets, which caused the potential bidder not to participate in the auction and resulted in a depressed sales price for the assets.  The complaint seeks damages and fees for breach of contract, violation of the Colorado Antitrust Act, violation of the Sherman Antitrust Act and tortious interference with a prospective business advantage.  In September 2015, Plaintiffs amended their complaint to add Ute Energy, LLC and Crescent Point Energy Corporation as defendants.

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

S-37

Note 14 – Taxes

Taxes on Income

The tax effects of significant items comprising our net deferred income taxes are as follows:

	As of  December 31,
		2015			2014
	Foreign		United States and Other		Foreign		United States and Other
	(in thousands)
Deferred tax assets:
Operating loss carryforwards	$	50,974	$	13,547	$	54,722	$	8,718
Stock-based compensation		—		3,471		—		6,479
Accrued compensation		—		653		—		376
Oil and natural gas properties		26,065		—		18,515		—
Investment in affiliate		130,088		—		88,913		—
Alternative minimum tax credit		—		2,545		—		4,299
Other		—		89		—		81
Total deferred tax assets		207,127		20,305		162,150		19,953
Deferred tax liabilities:
Tax on unremitted earnings of foreign subsidiaries		—		—		—		(14,700)
Other liabilities		(1,111)		(278)		—		(141)
Fixed assets		—		(3)		—		(3)
Total deferred tax liabilities		(1,111)		(281)		—		(14,844)
Net deferred tax asset (liability)		206,016		20,024		162,150		5,109
Valuation allowance		(205,896)		(20,024)		(162,097)		(19,809)
Net deferred tax asset (liability) after valuation allowance	$	120	$	—	$	53	$	(14,700)

As a result of the adoption of ASU No. 2015-17 the net deferred tax assets (liabilities) as of December 31, 2015 and 2014, were included in the consolidated balance sheets as Long-term deferred tax assets of $0.1 million and $0.1 million and Long-term deferred tax liabilities of $0.0 and $14.7 million, respectively.  

After assessing the possible actions which management may take in 2016 and the next few years during the year ended December 31, 2015, we continued to recognize that a deferred tax liability related to income tax on undistributed earnings of our foreign subsidiaries may be appropriate.  The Company is pursuing various alternatives with respect to its future operations and cannot assert that any future earnings will not be remitted to the U.S. as operations require.  The deferred tax liability recognized in prior periods, however, was decreased during 2015 to zero due to the impairment of the Company’s remaining investment in Petrodelta.

Management assesses the available positive and negative evidence to estimate if sufficient future taxable income will be generated to use the existing deferred tax assets (“DTAs”). A significant piece of objective negative evidence evaluated was the cumulative losses incurred in our foreign operating entities over the three-year period ended December 31, 2015. Such objective evidence limits the ability to consider other subjective evidence such as our projections for future growth or future asset dispositions. We have therefore placed a valuation allowance on all but a small amount of our foreignDTAs.

S-38

Management also reviewed the earnings history of our U.S. operations and determined that the Company is not expected to have sufficient taxable income in the U.S. due to its inability to sell the remaining equity interest in Harvest Holding and the lack of other income producing operations. Consequently, the Company is not expected to utilize its deferred tax assets and carries a valuation allowance on these deferred tax assets. Additionally, there was a significant increase to the valuation allowance attributable to the recognition of deferred tax assets related to the impairments of Petrodelta and the Dussafu PSC as these deferred tax assets are more likely than not to be unrealizable. The components of loss from continuing operations before income taxes are as follows:

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Income (loss) before income taxes
United States	$	1,457	$	(12,809)	$	(31,072)
Foreign		(198,537)		(438,589)		(40,725)
Total	$	(197,080)	$	(451,398)	$	(71,797)

The provision (benefit) for income taxes on continuing operations consisted of the following at December 31:

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Current:
United States	$	(1,755)	$	(87)	$	2,279
Foreign		32		47		44
		(1,723)		(40)		2,323
Deferred:
United States		(14,700)		(58,250)		72,971
Foreign		—		—		(2,207)
		(14,700)		(58,250)		70,764
	$	(16,423)	$	(58,290)	$	73,087

S-39

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

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Income tax expense (benefit) from continuing operations:
Tax expense (benefit) at U.S. statutory rate	$	(68,978)	$	(157,989)	$	(25,129)
Effect of foreign source income and rate differentials on foreign income		(10,870)		38,198		204
Tax gain associated with sale of interest in Harvest Holding		—		—		7,474
Subpart F income		—		—		16,615
Non-deductible interest		11,397		—		—
Tax on unremitted earnings of foreign subsidiaries		(14,700)		(75,200)		89,900
Expired losses		24,554		2,778		1,356
Other changes in valuation allowance		44,014		129,480		(10,643)
Change in applicable statutory rate		—		—		(404)
Other permanent differences		—		2,010		(2,546)
Return to accrual and other true-ups		11,823		1,955		2,919
Debt exchange		(12,079)		—		—
Warrant derivatives		(1,685)		(684)		(1,180)
Liability for uncertain tax positions		67		(30)		(5,553)
Other		34		1,192		74
Total income tax expense (benefit) – continuing operations	$	(16,423)	$	(58,290)	$	73,087

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

At December 31, 2015, we have the following net operating losses available for carryforward (in thousands):

United States	$	38,707	Available for up to 20 years from 2012
Gabon		22,269	Available for up to 3 years from 2013
The Netherlands		157,695	Available for up to 9 years from 2007
Venezuela		7,274	Available for up to 3 years from 2013

As a result of the first Petroandina closing in 2013, the Company realized a tax gain of $47.4 million which was included in U.S. taxable income pursuant to the provisions of the Internal Revenue Code. The Company utilized $9.8 million of available losses from prior years as well as a current year tax loss of $37.6 million to offset income resulting from the sale resulting in no regular tax for the year ended December 31, 2013 and leaving $9.3 million of losses available to offset taxable income in future periods. However, as a result of the alternative minimum tax provisions (“AMT”), we did incur AMT of $1.9 million increasing the amount of the AMT credit carryforward.  During 2014, the Company incurred a net operating loss (“NOL”) for AMT purposes.  A portion of this AMT NOL was carried back to 2013 to offset 90% of the $1.9 million AMT liability incurred during the year.  Accounts receivable at December 31, 2015 included a tax receivable of $1.7 million which was received from the Internal Revenue Service on February 12, 2016.  The AMT credit carryforward at December 31, 2015 amounts to $2.6 million.

If the U.S. operating loss carryforwards are ultimately realized, there would be no amounts credited to additional paid in capital for tax benefits associated with deductions for income tax purposes related to stock options and convertible debt.

Accumulated Undistributed Earnings of Foreign Subsidiaries

Under ASC 740-30-25-17, no deferred tax liability must be recorded if sufficient evidence shows that a foreign subsidiary has invested or will invest its 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

S-40

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.

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 into our foreign operations.  During the fourth quarter of 2013, management evaluated numerous factors related to the timing and amounts of possible future distribution of foreign earnings to the parent company, with consideration of the sale of non-U.S. assets. Because management was pursuing various alternatives with respect to the Company’s future operations and disposition of any sale proceeds, 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. However, due primarily to the $355.7 million pre-tax impairment of Petrodelta, this balance decreased by $75.2 million to $14.7 million at December 31, 2014.

As of December 31, 2015, the book-tax outside basis difference in our foreign subsidiary resulting from unremitted earnings was reduced to zero due to a pre-tax impairment of the Company’s remaining investment in Petrodelta of $164.7 million.  Consequently, the deferred tax liability associated with the foreign earnings was reduced to zero. The entire net deferred tax liability as of December 31, 2014 has been reflected as a long-term liability, a characterization consistent with the Company’s adoption of Accounting Standards Update (“ASU”) No. 2015-17.

Accounting for Uncertainty in Income Taxes

The FASB issued ASC 740-10 (prior authoritative literature: Financial Interpretation No. (“FIN”) 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109 (“FIN 48”) to create a single model to address accounting for uncertainty in tax positions. ASC 740-10 clarifies the accounting for income taxes, by prescribing a minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. ASC 740-10 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods and disclosure.

We or one of our subsidiaries file income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions. With few exceptions, we are no longer subject to tax examinations by tax authorities for years before 2010. Our primary income tax jurisdictions and their respective open audit years are:

Tax Jurisdiction	Open Audit Years
United States	2012 – 2015
The Netherlands	2013 – 2015
Venezuela	2010 – 2015

In January 2014, the U.S. IRS began an audit of our U.S. tax returns for 2011 and 2012.  The audit was concluded in October 2014 with an increase in tax of $0.01 million.  The Company has recently received notice from the U.S. IRS that it intends to audit the Company’s 2013 and 2014 tax years. The audit is expected to commence in April 2016.

The changes in our reserve for unrecognized tax benefits follow:

	Year Ended December 31,
	2015		2014
	(in thousands)
Balance at beginning of year	$	288	$	318
Additions for tax positions of prior years		—		—
Reductions for tax positions of prior years		(168)		(30)
Balance at end of year	$	120	$	288

The release of the reserve for uncertain tax positions of $0.03 million during the year ended December 31, 2014 was primarily related to the resolution of a Dutch tax matter regarding treatment of certain costs charged to our Dutch affiliate. However, this amount was offset by an adjustment to the valuation allowance resulting in a nil net tax.In 2015, the reserve was adjusted for a law change re-opening a prior closed year ($0.1 million) offset by a benefit ($0.3 million) from the expiration of the period of assessment on a tax related interest issue.  The benefit was included as a reduction of interest expense in our consolidated results of operations and comprehensive income for the year ended December 31, 2015.We believe that it is likely that remaining amount for the uncertain tax position will be resolved within the next twelve months, and the amount of unrecognized tax benefits will significantly decrease.

Note 15 – Stock-Based Compensation and Stock Purchase Plans

Total share-based compensation expense, which includes stock options, restricted stock, SARs, and RSUs, totaled $2.0 million for the year ended December 31, 2015  ($1.6 million and $2.3 million for the years ended December 31, 2014 and 2013, respectively). All awards utilize the straight line method of amortization over the vesting period.    The following table is a summary of

S-41

compensation expense (income) recorded in general and administrative expense in our consolidated statements of operations and comprehensive loss by type of awards:

	As of December 31,
Employee Stock-Based Compensation	2015		2014		2013
	(in thousands)
Equity based awards:
Stock options	$	2,003	$	2,073	$	2,119
Restricted stock		135		579		927
RSUs		133		—		—
Total expense related to equity based awards		2,271		2,652		3,046
Liability based awards:
SARs		(260)		(1,237)		(247)
RSUs		12		197		(534)
Total expense related to liability based awards		(248)		(1,040)		(781)
Total compensation expense	$	2,023	$	1,612	$	2,265

Long Term Incentive Plans

As of December 31, 2015, we had several long term incentive plans under which stock options, restricted stock, SARs and RSUs can be granted to eligible participants including employees, non-employee directors and consultants of our Company or subsidiaries:

· 2010 Long Term Incentive Plan, as amended (“2010 Plan”) – Provides for the issuance of up to 7,725,000 shares of our common stock in satisfaction of stock options, SARs, restricted stock, RSUs and other stock-based awards. No more than 2,425,000 shares may be granted as restricted stock and annually no individual may be granted more than 1,000,000 stock options or SARs. The 2010 Plan also permits the granting of performance awards to eligible employees and consultants. In the event of a change in control, all outstanding stock options and SARs become immediately exercisable to the extent permitted by the plan, and any restrictions on restricted stock and RSUs lapse.  At December 31, 2015, all shares available under the 2010 Plan had been granted.

· 2006 Long Term Incentive Plan (“2006 Plan”) – Provides for the issuance of up to 1,825,000 shares of our common stock in satisfaction of stock options, SARs and restricted stock. No more than 325,000 shares may be granted as restricted stock, and no individual may be granted more than 900,000 stock options or SARs and not more than 175,000 shares of restricted stock during any period of three consecutive calendar years. The 2006 Plan also permits the granting of performance awards to eligible employees and consultants. In the event of a change in control, all outstanding stock options and SARs become immediately exercisable to the extent permitted by the plan, and any restrictions on restricted stock lapse.The termination date for the 2006 LTIP Plan is May 17, 2016.   At December 31, 2015, all shares available under the 2006 Plan had been granted.

· 2004 Long Term Incentive Plan (“2004 Plan”) – Provides for the issuance of up to 1,750,000 shares of our common stock in satisfaction of stock options, SARs and restricted stock. No more than 438,000 shares may be granted as restricted stock, and no individual may be granted more than 438,000 stock options and not more than 110,000 shares of restricted stock over the life of the plan. The 2004 Plan also permits the granting of performance awards to eligible employees and consultants. In the event of a change in control, all outstanding stock options and SARs become immediately exercisable to the extent permitted by the plan, and any restrictions on restricted stock lapse.  With the exception of outstanding awards, the 2004 Plan terminated on May 20, 2014.

· 2001 Long Term Stock Incentive Plan (“2001 Plan”) – Provides for the issuance of up to 1,697,000 shares of our common stock in the form of Incentive Stock Options and Non-Qualified Stock Options. No officer may be granted more than 500,000 stock options during any one fiscal year, as adjusted for any changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the 2001 Plan.  At December 31, 2015, stock option awards to purchase 85,000 common shares remain available for grant.

Stock Options

Stock options granted under the plans must be no less than the fair market value of our common stock on the date of grant. Stock options granted under the plans generally vest ratably over a three year period beginning from the date of grant. Stock options granted under the plans expire five to ten years from the date of grant.

Prior to 2015, the fair value of each stock option award was estimated on the date of grant using the Black-Scholes option-pricing model which uses assumptions for the risk-free interest rate, volatility, dividend yield and the expected term of the options.

S-42

The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the option. Expected volatility is based on historical volatilities of our stock. We do not assume any dividend yield since we do not pay dividends. The expected term of options granted is the weighted average life of stock options and represents the period of time that options are expected to be outstanding.

In 2015, the fair value of each stock option was estimated on the date of grant using a Monte Carlo simulation since the options were also subject to a market condition.  These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share (“VWAP condition”) in addition to the ratable vesting over a three year period.  The Monte Carlo simulation includes this VWAP condition and uses assumptions for the risk-free interest rate, volatility, and dividend yield whilea suboptimal exercise factor determines the expected term of the options. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the option. Expected volatility is based on historical volatilities of our stock. We do not assume any dividend yield since we do not pay dividends. The expected term of options granted represents the period of time that options are expected to be outstanding. The Monte Carlo simulation assumed a suboptimal exercise factor of 2.5meaning that exercise is generally expected to occur when the share price reaches 2.5 times the award’s exercise price.

December 31, 2015, we awarded stock options vesting over three years to purchase 847,000 of our common shares to our employees and executive officers (683,000 and 920,004 stock options were granted during the years ended December 31, 2014 and 2013, respectively).

On December 9, 2015, we additionally issued 3,528,201 options with a life of 4.6 years and an exercise price of $1.13 subject to the VWAP condition.   These options vest one-third on July 22, 2016, one-third on July 22, 2017 and one-third on July 22, 2018 with an expiry date of July 22, 2020.  These options were issued as replacement awards for the equivalent number of SARs issued on July 22, 2015.  The options were issued with the equivalent terms, exercise price, and VWAP conditions as the SARs. 

We also consider an estimated forfeiture rate for all stock option awards, and we recognize compensation cost only for those shares that are expected to vest, on a straight-line basis over the requisite service period of the award, which is generally the vesting term of three years. The forfeiture rate is based on historical experience.

Options	Outstanding	Weighted- Average Exercise Price			Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)
Options outstanding as of December 31, 2014	4,536	$	7.81		2.0	$	—
Granted	4,375		1.13	(1)			—
Exercised	—		—
Cancelled	(1,769)		(9.85)
Options outstanding as of December 31, 2015	7,142		3.21		3.5		—
Options exercisable as of December 31, 2015	2,011	$	7.16		1.5		—

(1) These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE in addition to the ratable vesting over a three year period.

Of the options outstanding, 2.0 million were exercisable at a weighted-average exercise price of $7.16 as of December 31, 2015 (2.7 million at $8.85 at December 31, 2014; 2.9 million at $9.85 at December 31, 2013).

S-43

In 2014 and 2013, the value of each stock option grant is estimated on the date of grant using the Black-Scholes option pricing model.  In 2015, the value of each stock option grant is estimated on the date of grant using a Monte Carlo simulation.  Each have the following weighted average assumptions:

	As of December 31,
For options granted during:	2015			2014			2013
Weighted average fair value	$	0.43		$	2.97		$	3.06
Weighted average expected life		4.7 years			5 years			5 years
Expected volatility (1)		100	%		76.7	%		79.4	%
Risk-free interest rate		1.7	%		1.5	%		1.3	%
Suboptimal exercise factor (2)		2.5			—			—
Weighted average pre-vest forfeiture rate		1.1	%		1.0	%		1.2	%
Dividend yield		0.0	%		0.0	%		0.0	%

(1) Expected volatilities are based on historical volatilities of our stock.

(2) A suboptimal exercise factor of 2.5 means that exercise is generally expected to occur when the share price reaches 2.5 times the award’s exercise price.

A summary of our unvested stock option awards as of December 31, 2015, and the changes during the year then ended is presented below:

Unvested Stock Options	Outstanding		Weighted- Average Grant-Date Fair Value
	(in thousands)
Unvested as of December 31, 2014	1,876	$	3.85
Granted	4,375		0.43
Vested	(645)		(2.99)
Expired	(475)		(6.38)
Unvested as of December 31, 2015	5,131	$	0.81

The total intrinsic value of stock options exercised during the year ended December 31, 2015 was $0.0 million (2014: $0.0 million; 2013: $0.1 million). The total fair value of stock options that vested during the year ended December 31, 2015, was $1.9 million ($2.4 million and $1.9 million during the years ended December 31, 2014 and 2013, respectively).

As of December 31, 2015, there was $3.0 million of total future compensation cost related to unvested stock option awards that are expected to vest. That cost is expected to be recognized over a weighted average period of 1.86 years.

Restricted Stock

Restricted stock is issued on the grant date, but cannot be sold or transferred. Restricted stock granted to directors vest one year after date of grant. Restricted stock granted to employees vest at the third year after date of grant. Vesting of the restricted stock is dependent upon the employee’s continued service to Harvest.

A summary of our restricted stock awards as of December 31, 2015, and the changes during the year then ended is presented below:

Restricted Stock	Outstanding		Weighted- Average Grant-Date Fair Value
	(in thousands)
Unvested as of December 31, 2014	86	$	4.82
Granted	—		—
Vested	(2)		(5.85)
Forfeited	—		—
Unvested as of December 31, 2015	84	$	4.80

S-44

No restricted stock shares were awarded during the years ended December 31, 2015 and 2014. In 2013, we awarded 190,002 shares to directors and employees.  The restricted stock granted in 2013 had an aggregate fair value of $0.9 million. The restricted stock is scheduled to vest at the third year after date of grant for employees and vestedone year after date of grant for directors. The fair value of the restricted stock that vested during the year ended December 31, 2015 was $11,700 ($1.9  million and $1.2 million during the years ended December 31, 2014 and 2013, respectively). The weighted average grant date fair value of awards granted in 2013 was $4.80.

As of December 31, 2015 there was $0.1 million of total future compensation cost related to unvested restricted stock awards that are expected to vest. That cost is expected to be recognized over a weighted average period of 0.5 years.

Stock Appreciation Rights (“SARs”)

All SAR awards granted to date have been granted outside of active long-term incentive plans and are held by Harvest employees. SARs granted in 2013 and 2015 vest ratably over three years beginning in the first year of grant. Vesting of SARs is dependent upon the employee’s continued service to Harvest. SAR awards are settled either in cash or Harvest common stock if available through an equity compensation plan. For recording of compensation, we assume the SAR award will be cash-settled and record compensation expense based on the fair value of the SAR awards at the end of each period.

The significant assumptions are summarized in the following table thatwere used to calculate the fair value of the SARs granted on July 22, 2015 and amended December 9, 2015 that were outstanding as of the balance sheet date presented on our consolidated balance sheet:

	Fair Value
	Hierarchy	As of December 31,
	Level	2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	0.43
Exercise price	Level 1 input	$	1.13
Threshold price	Level 1 input	$	2.50
Suboptimal exercise factor	Level 3 input		2.5
Term (years)			4.56
Volatility	Level 2 input		105.0	%
Risk-free rate	Level 1 input		1.66	%
Dividend yield	Level 2 input		0.0	%

As these awards are accounted for as liabilities,the fair value of each SAR was estimated at December 31, 2015 using a Monte Carlo simulation since the SARs were also subject to a market condition.  These SARs will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share (“VWAP condition”) in addition to the ratable vesting over a three year period.  The Monte Carlo simulation includes this VWAP condition and uses assumptions for the risk-free interest rate, volatility, and dividend yield whilea suboptimal exercise factor determines the expected term of the SARs. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the SAR. Expected volatility is based on historical volatilities of our stock. We do not assume any dividend yield since we do not pay dividends. The expected term of SARs granted represents the period of time that SARs are expected to be outstanding. The Monte Carlo simulation assumed a suboptimal exercise factor of 2.5meaning that exercise is generally expected to occur when the share price reaches 2.5 times the award’s exercise price.The suboptimal exercise factor was the Level 3 input used for the valuation of the SARs.  In general, if the suboptimal exercise factor increases then the fair value of the SAR will increase or vice versa.A change in the Level 3 input has a minimal effect on the valuation of the SARs as the primary driver is our stock price.

S-45

SAR award transactions under our employee compensation plans are presented below:

SARs	Outstanding	Weighted- Average Exercise Price			Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)
SARS outstanding as of December 31, 2014	1,123	$	4.95		2.2	$	—
Granted	5,062		1.13	(1)	5.0		—
Cancelled	(3,528)		(1.13)	(1)
Expired	(86)		(5.12)
SARS outstanding as of December 31, 2015	2,571		2.67		3.3		—
SARS exercisable as of December 31, 2015	966	$	4.95		1.3		—

(1) These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE in addition to the ratable vesting over a three year period.

Of the SAR awards outstanding,  1.0 millionwere exercisable at the weighted-average exercise price of$4.95 as of December 31, 2015,  0.8 million exercisable at the weighted-average exercise price of$4.94 as of December 31, 2014 and 0.4million were exercisable at the weighted-average exercise price of $4.91 at December 31, 2013.

During the year ended December 31, 2015, there were 5.1 million SAR awards granted (zero and 0.2 million during the years ended December 31, 2014 and 2013, respectively). 

On July 22, 2015, we issued 5.1 million SARs at an exercise price of $1.13 per share, vesting ratably over three years from the date of grant and on the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE.  The dual vesting requirements necessitated that all of these awards be valued using a Monte Carlo simulation.  Since the Company had an insufficient numbers of shares available from existing long-term incentive plans, the SARs were classified as liability awards when issued.  

On December 9, 2015, our board of directors approved modifications of a portion of the July 22, 2015 awards.  Of the 5.1 million SARs issued, 3.5 million were cancelled and replaced with options under the 2010 Plan.  All other terms remained the same.    The fair value of the vested portion of the cancelled SARs approximated the fair value of the replacement options granted on December 9, 2015.  The remaining 1.6 million SARs continue to be classified as liability awards.

A summary of our unvested SAR awards as of December 31, 2015, and the changes during the year then ended is presented below:

Unvested SARs	Outstanding		Weighted- Average Fair Value
	(in thousands)
Unvested as of December 31, 2014	339	$	0.51
Granted	5,062		0.32
Vested	(264)		(0.06)
Cancelled	(3,528)		(0.35)
Expired	(4)		(0.05)
Unvested as of December 31, 2015	1,605	$	0.21

No SAR awards were exercised during the years ended December 31, 2015,2014 and 2013.  The total fair value of SAR awards that vested during the year ended December 31, 2015, was $15,960 ($0.2  million and $0.8 million during the years ended December 31, 2014 and 2013, respectively).

Restricted Stock Units (“RSUs”)

RSU awards granted prior to 2015 have been granted outside of active long-term incentive plans, are held by Harvest employees and directors, and are settled either in cash or Harvest common stock if available through an equity compensation plan and are accounted for as liability awards . RSU awards granted in 2012,  2014 and 2015 to employees vest at the third year after date of grant.

S-46

RSU awards granted in 2015 to our board of directors vest one year after the date of grant. Vesting of the RSU awards is dependent upon the employee’s and director’s continued service to Harvest.

On September 9, 2015, we issued 320,004RSUs vesting one year from the date of grant to our directors.  These awards are classified as liability awards.  These awards are measured at their fair values based on our closing stock price at December 31, 2015.

The significant assumptions are summarized in the following table that were used to calculate the fair value of the restricted stock units granted on July 22, 2015 and amended December 9, 2015 that were outstanding as of the balance sheet date presented on our consolidated balance sheet:

	Fair Value
	Hierarchy	As of December 9,
	Level	2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	0.63
Threshold price	Level 1 input	$	2.50
Term (years)			10.0
Volatility	Level 2 input		80.0	%
Risk-free rate	Level 1 input		2.27	%
Dividend yield	Level 2 input		0.0	%

A summary of our RSU awards as of December 31, 2015, and the changes during the year then ended is presented below: 

RSUs	Outstanding		Weighted- Average Fair Value
	(in thousands)
Unvested as of December 31, 2014	905	$	1.81
Granted	1,891		0.73
Vested	(326)		(1.50)
Forfeited	—		—
Unvested as of December 31, 2015 (1)	2,470	$	0.52

1) At December 31, 2015, unvested RSUs of 1.6 million and 0.9 million were accounted for as equity and liability awards, respectively.

The 326,142 RSU awards vesting in 2015 were settled for cash of $0.5 million.  The 103,338 RSU awards which vested in 2014 were settled for cash of $0.5 million (202,668 RSU awards settled for cash of $0.6 million during 2013). The fair value of the RSU awards that vested during the year ended December 31, 2015 was $0.3 million ($0.2 million and $0.8 million during the years ended December 31, 2014 and 2013, respectively).

On July 22, 2015, we issued 1.6 million restricted stock units vesting at three years from the date of grant as stock based compensation awards to certain employees.  Subject to the three year vesting requirement, the RSUs awarded will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE.  The dual vesting requirements necessitated that all of these awards be valued using a Monte Carlo simulation.  Since an insufficient numbers of shares were available from existing long-term incentive plans, the RSUs were classified as liability awards at issuance.  

On December 9, 2015, our board of directors approved a modification to share-settle the 1.6 million RSUs granted on July 22, 2015.  This modification changed the classification of these awards from liability to equity awards. The fair value of the vested portion of the initial RSUs approximated the fair value of the modified RSUs on December 9, 2015.  The grant-date fair value of the modified RSUs was $0.57 per RSU.

As of December 31, 2015 there was $1.0 million of total future compensation cost related to unvested RSU awards expected to vest. That cost is expected to be recognized over a weighted average period of 2.2 years.

Common Stock Warrants

In connection with the transaction with CT Energy on June 19, 2015,we issued a warrant exercisable for 34,070,820 shares of the Company’s common stock at an initial exercise price of $1.25 per share with an expiration date of June 19, 2018.  The CT Warrant

S-47

may not be exercised until the volume weighted average price of the Company’s common stock over any consecutive 30-day period equals or exceeds $2.50 per share.  See Note 1 – Organization and Note 12 – Warrant Derivative Liability.  

Note 16 – Operating Segments

We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Operations included under the heading “United States” include corporate management, cash management, business development and financing activities performed in the United States and other countries, which do not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the United States segment and are not allocated to other operating segments. In previous years, charges for intersegment general and administrative and interest expenses were included in results for the respective operating segments, and operating segment assets included intersegment receivables and loans. Segment loss and operating segment assets for prior periods have been adjusted to conform to the current presentation method in which intersegment items are eliminated from each segment’s results and assets.

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Segment Loss Attributable to Harvest
Venezuela		(83,953)		(171,801)		58,640
Gabon		(28,448)		(55,564)		(12,908)
Indonesia		(43)		(9,558)		(9,213)
United States and other		13,874		43,987		(120,465)
Loss from continuing operations(a)		(98,570)		(192,936)		(83,946)
Discontinued operations		—		(554)		(5,150)
Net loss attributable to Harvest	$	(98,570)	$	(193,490)	$	(89,096)

(a) Net of net income attributable to noncontrolling interest owners.

	As of December 31,
	2015		2014
	(in thousands)
Operating Segment Assets
Venezuela	$	5,290	$	165,214
Gabon		32,710		60,051
Indonesia		5		176
United States and other		9,776		2,602
		47,781		228,043
Discontinued operations		—		3
Total assets	$	47,781	$	228,046

Note 17 – Related Party Transactions

The noncontrolling interest owners in Harvest Holdings, Vinccler (currently owning 20 percent) and Petroandina (currently owning 29 percent) are both related parties of the Company. 

As of December 31, 2014, HNR Energia had a note payable to Vinccler of $6.1 million. Principal and interest were payable upon the maturity date of December 31, 2015. Interest accrued at a rate of U.S. Dollar based three month LIBOR plus 0.5%.  On March 9, 2015, Vinccler forgave the note payable and accrued interest totaling $6.2 million.  This was reflected as a contribution to stockholders’ equity.

On May 11, 2015, the Company borrowed $1.3 million to fund certain corporate expenses and issued a note payable to CT Energy bearing an interest rate of 15.0% per annum, with a maturity date of January 1, 2016.  On June 19, 2015, the Company repaid the note payable and accrued interest.

S-48

On June 3, 2015, the Company entered into the note with James A. Edmiston, President and Chief Executive Officer of the Company, for $50,000. The note carried interest at 11.0% per year and was to mature upon the earlier to occur of June 30, 2016 or the date on which the Loan Obligations (as defined in that certain Loan Agreement, dated as of September 11, 2014, by and among the Company, HNR Energia B.V. and Petroandina Resources Corporation N.V.) are paid in full. On June 19, 2015, the Company repaid the note payable and accrued interest.

As of December 31, 2014, HNR Energia had a note payable to Petroandina of $7.6 million. Principal was due by January 1, 2016.  Interest payments were quarterly beginning on December 31, 2014.  On June 23, 2015 the Company repaid the note payable of $7.6 million plus accrued interest of $0.4 million.

On June 19, 2015, Harvest sold to CT Energy the 15% Note, the 9% Note and the Series C preferred stock.  Shortly after this transaction two representatives of CT Energy were appointed to Harvest’s board of directors.  On September 15, 2015, CT Energy converted the 9% Note, including accrued interest, into 8,667,597 shares of Harvest’s common stock and Harvest redeemed the Series C preferred stock.  See Note 1 – Organization for more information about the CT Energy transaction.

On January 4, 2016, HNR Finance made a loan to CT Energia in the amount of $5.2 million under an 11.0% promissory note due 2019 (the “CT Energia Note”), dated January 4, 2016, executed by CT Energia. The purpose of the loan is to provide CT Energia with collateral to obtain funds for one or more loans to Petrodelta. The loans to Petrodelta are to assist Petrodelta in satisfying its working capital needs and discharging its obligations. Interest on the CT Energia Note is due and payable on the first of each January and July, commencing July 1, 2016. The full amount outstanding, including any unpaid accrued interest, is due on January 4, 2019; however, HNR Finance’s sole recourse for payment of the principal amount of the loan is the payments of principal and interest from loans that CT Energia has made to Petrodelta. If and when CT Energia receives any payments of principal or interest from loans it has made to Petrodelta, then those proceeds must be used to prepay unpaid interest and principal under the CT Energia Note.  The source of funds for HNR Finance’s $5.2 million loan to CT Energia was a capital contribution from Harvest Holding, which, in return, received the same aggregate amount of capital contributions from its shareholders, pro rata according to their equity interests in Harvest Holding. Of that aggregate amount of capital contributions, HNR Energia contributed $2.6 million, which it had received as a capital contribution from Harvest.

Note18 – Mezzanine Equity

In connection with the CT Energy transaction described in Note 1 – Organization, the Company also issued CT Energy 69.75 shares of its newly created Series C preferred stock, par value $0.01 per share.  The primary purpose of the Series C preferred stock was to provide the holder of the 9% Note with voting rights equivalent to the common stock underlying the unconverted portion of the 9% Note.  The Series C preferred stock was not entitled to receive dividends, had perpetual maturity, and had a $1.00 per share liquidation preference.  On September 15, 2015, upon the conversion of the 9% Note, the shares of Series C preferred stock were redeemed.

As discussed in Note 11 – Debt and Financing, no value was attributed to the Series C preferred stock.  Prior to its redemption on September 15, 2015, shares of the Series C preferred stock were recorded in temporary equityin accordance with ASC 480 – Distinguishing Liabilities from Equity, as the redemption of the shares was outside of the control of the Company. 

S-49

Note 19 – Quarterly Financial Data (unaudited)

Summarized quarterly financial data is as follows:

	Quarter Ended
	March 31		June 30		September 30		December 31
	(amounts in thousands, except for share data)
Year ended December 31, 2015
Expenses (1)	$	(6,119)		(6,119)		(6,767)		(192,891)
Non-operating gain (loss)		(234)		(17,964)		10,335		22,679
Income (loss) from continuing operations before income taxes		(6,353)		(24,083)		3,568		(170,212)
Income tax expense (benefit)		(384)		1,604		(1,850)		(15,793)
Income (loss) from continuing operations		(5,969)		(25,687)		5,418		(154,419)
Less: Net loss attributable to noncontrolling interest owners		(352)		(262)		(294)		(81,179)
Net income (loss) attributable to Harvest	$	(5,617)	$	(25,425)	$	5,712	$	(73,240)
Basic Earnings (Loss) per Share:
Income (loss) from continuing operations	$	(0.13)	$	(0.60)	$	0.13	$	(1.42)
Net income (loss) attributable to Harvest	$	(0.13)	$	(0.60)	$	0.13	$	(1.42)
Diluted Earnings (Loss) per Share:
Income (loss) from continuing operations	$	(0.13)	$	(0.60)	$	0.13	$	(1.42)
Net income (loss) attributable to Harvest	$	(0.13)	$	(0.60)	$	0.13	$	(1.42)

	Quarter Ended
	March 31		June 30		September 30		December 31
	(amounts in thousands, except for share data)
Year ended December 31, 2014
Expenses (2)	$	(12,670)	$	(9,759)	$	(4,977)	$	(422,199)
Non-operating gain (loss)		(6,447)		(147)		3,067		1,734
Loss from continuing operations before income taxes		(19,117)		(9,906)		(1,910)		(420,465)
Income tax expense (benefit)		(954)		(88)		2,361		(59,609)
Loss from continuing operations		(18,163)		(9,818)		(4,271)		(360,856)
Earnings (loss) from investment in affiliate		18,887		16,062		—		—
Income (loss) from continuing operations		724		6,244		(4,271)		(360,856)
Discontinued operations		(131)		(230)		(142)		(51)
Net income (loss)		593		6,014		(4,413)		(360,907)
Less: Net income (loss) attributable to noncontrolling interest owners		8,601		7,665		(273)		(181,216)
Net income (loss) attributable to Harvest	$	(8,008)	$	(1,651)	$	(4,140)	$	(179,691)
Basic Earnings (Loss) per Share:
Income (loss) from continuing operations	$	0.19	$	(0.03)	$	(0.10)	$	(4.23)
Discontinued operations		—		(0.01)		—		—
Net income (loss) attributable to Harvest	$	0.19	$	(0.04)	$	(0.10)	$	(4.23)
Diluted Earnings (Loss) per Share:
Income (loss) from continuing operations	$	0.19	$	(0.03)	$	(0.10)	$	(4.23)
Discontinued operations		—		(0.01)		—		—
Net income (loss) attributable to Harvest	$	0.19	$	(0.04)	$	(0.10)	$	(4.23)

(1) Includes $164.7 million impairment during the quarter ended December 31, 2015 related to our investment in Petrodelta and $24.2 million impairment of oil and natural gas properties (including oilfield inventory) for Dussafu PSC.  See Note 6 – Investment in Affiliate and Note 8- Gabon.  

S-50

(2) Includes $355.7 million impairment during the quarter ended December 31, 2014 related to our investment in Petrodelta, $13.8 million allowance for doubtful accounts for long-term receivable – investment in affiliate, and $50.3 million impairment of oil and natural gas properties for Dussafu PSC.  See Note 6 – Investment in Affiliate and Note 8- Gabon.

Note 20 – Subsequent Events

On January 4, 2016, Harvest entered into transactions to amend its existing 15.0% non-convertible note due 2020 and to make a loan, via one of its subsidiaries, to a third party. The parties involved in the transactions are HNR Energia, Harvest Holding, HNR Finance, CT Energy and CT Energia Holding Ltd., a Malta corporation (“CT Energia”) that is the service provider under the June 19, 2015 management agreement with Harvest and HNR Finance.  Harvest and CT Energy executed a first amendment of Harvest’s 15% non-convertible promissory note due 2020 (the “Original Note”), dated June 19, 2015, payable to CT Energy in the original principal amount of $25.2 million. The amendment increases the principal amount of the Original Note to $26.1 million to reflect a loan back to Harvest equal to the amount of interest that otherwise would have been due to CT Energy on January 1, 2016, less withholding tax due as a result of the interest that was owed at January 1, 2016.

On January 4, 2016, HNR Finance provided a loan to CT Energia in the amount of $5.2 million under an 11.0% promissory note due 2019 (the “CT Energia Note”), dated January 4, 2016, executed by CT Energia. The purpose of the loan is to provide CT Energia with collateral to obtain funds for one or more loans to Petrodelta that is 40% owned by HNR Finance and through which Harvest’s Venezuelan oil and naturalgas interests are held. The loans to Petrodelta are to assist Petrodelta in satisfying its working capital needs and discharging its obligations. Interest on the CT Energia Note is due and payable on the first of each January and July, commencing July 1, 2016. The full amount outstanding, including any unpaid accrued interest, is due on January 4, 2019; however, HNR Finance’s sole recourse for payment of the principal amount of the loan is the payments of principal and interest from loans that CT Energia has made to Petrodelta. If and when CT Energia receives any payments of principal or interest from loans it has made to Petrodelta, then those proceeds must be used to prepay unpaid interest and principal under the CT Energia Note. All payments made by CT Energia to HNR Finance under the CT Energia Note must be made in USD.  The source of funds for HNR Finance’s $5.2 million loan to CT Energia was a capital contribution from Harvest Holding, which, in return, received the same aggregate amount of capital contributions from its shareholders, pro rata according to their equity interests in Harvest Holding. Of that aggregate amount of capital contributions, HNR Energia contributed $2.6 million, which it had received as a capital contribution from Harvest.

On March 9, 2016, Venezuela Vice President for Economic Area announced a new exchange agreement No.35 (the “Exchange Agreement No.35”).  Exchange Agreement No. 35 was published in Venezuela’s Official Gazette No. 40865 dated March 9, 2016, and became effective on March 10, 2016.  Exchange Agreement No. 35 will have a dual exchange rate for a controlled rate (named DIPRO) fixed at 10 USD/Bolivars for priority goods and services and a complimentary rate (named DICOM) starting at 206.92USD/Bolivars for travel and other non-essential goods. We are evaluating the impact Exchange Agreement No. 35 has on Harvest Vinccler and Petrodelta.

S-51

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

The following tables summarize our proved reserves, drilling and production activity, and financial operating data at the end of each year. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

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

	Gabon
	(in thousands)
Year Ended December 31, 2015
Unproved exploration costs (a)	$	894
	$	894
Year Ended December 31, 2014
Unproved exploration costs (a)	$	1,202
	$	1,202
Year Ended December 31, 2013
Unproved exploration costs (a)	$	26,214
	$	26,214

(a) See Note 8 – Gabon for additional information.

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

	Gabon (a)		Indonesia		Total
		(in thousands)
As of December 31, 2015
Unproved property costs	$	28,000	$	—	$	28,000
Oilfield Inventories		3,006		—		3,006
	$	31,006	$	—	$	31,006
As of December 31, 2014
Unproved property costs	$	50,324	$	—	$	50,324
Oilfield Inventories		3,966		—		3,966
	$	54,290	$	—	$	54,290
As of  December 31, 2013
Unproved property costs	$	99,447	$	4,470	$	103,917
Oilfield Inventories		3,966		130		4,096
	$	103,413	$	4,600	$	108,013

(a) During 2013, we announced that Dussafu Ruche Marin-1 (“DRM-1”) had reached a vertical depth of 11,260 feet within the Dentale Formation. Log evaluation and pressure data indicate that we had 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 downhole tool was retrieved and the DTM-1 well suspended for future re-entry. Work on DRM-1 and the sidetracks are currently suspended pending further exploration and development activities. Since approval of the Field Development Plan (“FDP”) in October 2014, Harvest has continued to move toward development of the Ruche Exclusive Exploitation Area. A tender for all the subsea equipment was concluded in January 2015 where prices exceeded the costs employed in the FDP. Efforts continue to negotiate with the lowest priced vendors and to revise the development scheme to bring the projected cost back to the FDP levels. The depth volume from the 2013 3D seismic acquisition over the discovered fields and the outboard area of the license has been received and interpreted. S-52

This new data was incorporated into our reservoir models and optimization of well trajectories to maximize oil recovery is ongoing. In addition, the prospect inventory was updated and several prospects have been high graded for drilling in the first half of 2016. To accommodate the drilling schedule, a site survey, including bathymetry and geophysical data gathering with respect to prospects A/B, 6/7 and 8/9, was completed in August 2015. A tender for a drilling rig for the planned well was completed in November 2015 and a tender for well testing and other services were concluded in January 2016.

In December 2014, the Company recorded a $50.3 million impairment related to the unproved costs of the Dussafu PSC based on a qualitative analysis.  In December 2015, the Company recorded an additional impairment of $24.2 million related based on its analysis of the value of the unproved costs (including oilfield inventory) which considered the value of the contingent and exploration resources and the ability of the Company to develop the project given its current liquidity situation and the depressed price of crude oil.

TABLE III – Results of operations for oil and natural gas producing activities:

	Year Ended December 31,
	2015		2014
	(in thousands)
Expenses:
Exploration expense	$	3,900	$	6,267
Impairment of oil and natural gas properties costs		24,178		57,994
Total expenses		28,078		64,261
Results of operations from oil and natural gas producing activities.	$	(28,078)	$	(64,261)

TABLE IV – Quantities of Oil and Natural Gas Reserves

Estimating oil and natural gas reserves is a very complex process requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may change substantially over time as a result of numerous factors such as production history, additional development activity and continual reassessment of the viability of production under various economic and political conditions. Consequently, material upward or downward revisions to existing reserve estimates may occur from time to time; although, every reasonable efforts is made to ensure that reported results are the most accurate assessment available. We ensure that the data provided to our external independent experts, and their interpretation of that data, corresponds with our development plans and management’s assessment of each reservoir. The significance of subjective decisions required and variances in available data make estimates generally less precise than other estimates presented in connection with financial statement disclosures.

We measure and disclose oil and natural 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”).

The process for preparation of our oil and natural gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided for, 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, has more than 25 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.

See the following section Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela Investment in Affiliate as of December 31, 2014 and 2013, TABLE IV – Quantities of Oil and Natural Gas Reserves for Petrodelta’s reserves.

S-53

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

The standardized measure of discounted future net cash flows is presented in accordance with the provisions of the accounting standard on disclosures about oil and natural gas producing activities. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.

Future cash inflows are estimated by applying the average price during the 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the contract, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes are estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.

As of December 31, 2015 and 2014, we did not have a direct interest in any proved reserves. See the following section Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela Investment in Affiliate as of December 31, 2014 and 2013, TABLE V – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities for Petrodelta’s reserves.

Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Petrodelta S.A.

We no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.  Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.  Due to the change in accounting method from equity method to cost method of accounting for our investment in Petrodelta, additional supplemental information on oil and natural gas producing activities for 2015 have been excluded.

The following tables summarize the proved reserves, drilling and production activity, and financial operating data at the end of each year for our net interest in Petrodelta. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

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

	Year ended December 31
		2014		2013
	(in thousands)
Development costs	$	88,498	$	83,680

(1) These costs are stated net to our 32 percent interest through December 15, 2013 and 20.4 percent thereafter.

S-54

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

	Year ended December 31
		2014		2013
	(in thousands)
Proved property costs	$	291,967	$	213,181
Unproved property costs		—		—
Oilfield inventories		26,712		25,393
Less accumulated depletion and impairment		(100,591)		(72,683)
	$	218,088	$	165,891

(1) These results are stated net to our 32.0 percent interest through December 15, 2013 and 20.4 percent thereafter.

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

	Year ended December 31 (2)
		2014		2013
	(in thousands)
Revenue:
Oil and natural gas revenues	$	274,999	$	419,307
Royalty		(89,177)		(139,093)
		185,822		280,214
Expenses:
Operating, selling and distribution expenses and taxes other than on income (1)		117,120		120,613
Depletion		27,668		31,660
Income tax expense		20,517		63,970
Total expenses		165,305		216,243
Results of operations from oil and natural gas producing activities	$	20,517	$	63,971

(1) Expenses include operating expenses, production taxes and Windfall Profits Tax. Net to our percent interest, Windfall Profits Tax for December 31, 2014 was $40.0 million and $54.4 million for the year ended December 31, 2013.

(2) These results are stated net to our 32.0 percent interest through December 15, 2013 and 20.4 percent thereafter.

TABLE IV – Quantities of Oil and Natural Gas Reserves

We measure and disclose oil and natural 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”).

Petrodelta is producing from, and continuing to develop, the Petrodelta Fields. Petrodelta has both developed and undeveloped oil and natural gas reserves identified in all six fields. Petrodelta produces the fields in accordance with a business plan originally defined by its Conversion Contract executed in late 2007. Proved Undeveloped (“PUD”) oil and natural gas reserves are drilled in accordance with Petrodelta’s business plan, but can be revised where drilling results indicate a change is warranted.

During 2014, Petrodelta drilled and completed 13 production wells.  Eight of the wells were previously identified Proved Undeveloped (“PUD”) locations and five wells were previously classified Probable, Possible or undefined locations. In 2014, an additional 26 PUD locations were identified through drilling activity; however, 101 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, 2015, Petrodelta had a total of 66 PUD (7.5 MM barrels of oil equivalent (“BOE”) locations identified. Since the implementation of its 2007 business plan, Petrodelta has drilled 93 gross production wells (2008 9 wells [1.4 MMBOE], (2009 15 wells [2.0 MMBOE], 2010 16 wells [2.0 MMBOE], 2011 15 wells [2.1 MMBOE], 2012 12 wells [2.2 MMBOE], 2013 13 wells [1.2 MMBOE]) and 2014 13 wells [1.3MMBOE] which have moved to the proved developed producing (“PDP”) category.

Petrodelta has a track record of identifying, executing and converting its PUD locations to PDP locations in accordance with the business plan defined by the conversion contract executed in 2007 and subsequent updates. However, the timing and pace of the development is controlled by the majority owner, PDVSA through CVP, although we have substantial negative control provisions as a noncontrolling interest shareholder. In 2010, Petrodelta submitted a revised business plan to PDVSA which substantially increases the total projected drilling activity and production volumes compared to the 2007 business plan, but which is otherwise consistent with the 2007 business plan. The 2010 business plan, as approved by PDVSA, contemplates sustained drilling activities through the year 2024

S-55

to fully develop the El Salto and Temblador fields. As a noncontrolling interest shareholder in Petrodelta, HNR Finance has limited ability to control the development plans that are periodically prepared or approved by the Venezuelan government. Since this constraint represents a hindrance to development not experienced by typical operations, the PUD locations which are now scheduled to be drilled five years after they were originally identified have been reclassified as Probable reserves.

As of December 31, 2014, proved undeveloped reserves of 7.5 MMBOE from 66 gross PUD locations are all scheduled to be drilled within the period from 2015 to 2019 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.

The tables shown below represent HNR Finance’s 40 percent ownership interest and our net percent ownership interest, both net of a 33.33 percent royalty, in Venezuela in each of the years.

	HNR Finance	Minority Interest in Venezuela	32%/20.4% Net Total
	(in thousands)
Proved Reserves-Crude oil, condensate,
and natural gas liquids (MBbls)
Year Ended December 31, 2014 (20.4% net interest)
Proved Reserves at January 1, 2014	36,420	(17,846)	18,574
Revisions	(5,259)	2,577	(2,682)
Extensions	3,728	(1,827)	1,901
Production	(4,150)	2,034	(2,116)
Proved Reserves at end of the year	30,739	(15,062)	15,677
As of December 31, 2014 (20.4% net interest)
Proved
Developed	16,459	(8,065)	8,394
Undeveloped	14,280	(6,997)	7,283
Total Proved	30,739	(15,062)	15,677
Year Ended December 31, 2013 (32% to 20.4% net interest)
Proved Reserves at January 1, 2013 (32% net interest)	43,161	(8,632)	34,529
Revisions	(3,668)	1,798	(1,870)
Extensions	804	(161)	643
Production	(3,877)	775	(3,102)
Reduction in indirect ownership interest to 20.4% net interest	—	(11,626)	(11,626)
Proved Reserves at end of the year (20.4% net interest)	36,420	(17,846)	18,574
As of December 31, 2013 (20.4% net interest)
Proved
Developed	16,436	(8,054)	8,382
Undeveloped	19,984	(9,792)	10,192
Total Proved	36,420	(17,846)	18,574

S-56

		HNR Finance	Minority Interest in Venezuela	32%/20.4% Net Total
	(in thousands)
Proved Reserves-Natural gas (MMcf)
Year Ended December 31, 2014 (20.4% net interest)
Proved Reserves at January 1, 2014		24,797	(12,150)	12,647
Revisions		(12,131)	5,944	(6,187)
Extensions		1,014	(497)	517
Production		(1,504)	737	(767)
Proved Reserves at end of the year		12,176	(5,966)	6,210
As of December 31, 2014 (20.4% net interest)
Proved
Developed		9,582	(4,695)	4,887
Undeveloped		2,594	(1,271)	1,323
Total Proved		12,176	(5,966)	6,210
Year Ended December 31, 2013 (32% to 20.4% net interest)
Proved Reserves at January 1, 2013 (32% net interest)		29,012	(5,802)	23,210
Revisions		(2,914)	1,428	(1,486)
Extensions		126	(25)	101
Production		(1,427)	285	(1,142)
Reduction in indirect ownership interest to 20.4% net interest		—	(8,036)	(8,036)
Proved Reserves at end of the year (20.4% net interest)		24,797	(12,150)	12,647
As of December 31, 2013 (20.4% net interest)
Proved
Developed		20,451	(10,021)	10,430
Undeveloped		4,346	(2,129)	2,217
Total Proved		24,797	(12,150)	12,647

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

The standardized measure of discounted future net cash flows is presented in accordance with the provisions of the accounting standard on disclosures about oil and natural gas producing activities. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.

Future cash inflows are estimated by an applying the average price during the 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the contract, to the estimated future production of year-end proved reserves. Our average prices used for 2014 were $78.04 per barrel for oil for the El Salto field ($84.14 in 2013) and $86.56 per barrel for the other fields ($97.89 in 2013), and $1.54 per Mcf for natural gas ($1.54 per Mcf in 2013). Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.

S-57

The table shown below represents HNR Finance’s net interest in Petrodelta.

		HNR Finance		Minority Interest in Venezuela		32%/20.4% Net Total
	(in thousands)
As of December 31, 2014 (20.4% net interest)
Future cash inflows from sales of oil and natural gas	$	2,507,395	$	(1,228,624)	$	1,278,771
Future production costs (1)		(740,295)		362,745		(377,550)
Future development costs		(118,595)		58,112		(60,483)
Future income tax expenses		(637,378)		312,315		(325,063)
Future net cash flows		1,011,127		(495,452)		515,675
Effect of discounting net cash flows at 10%		(329,294)		161,354		(167,940)
Standardized measure of discounted future net cash flows	$	681,833	$	(334,098)	$	347,735
As of December 31, 2013 (20.4% net interest)
Future cash inflows from sales of oil and natural gas	$	3,267,240	$	(1,600,948)	$	1,666,292
Future production costs (1)		(1,352,126)		662,542		(689,584)
Future development costs		(240,844)		118,014		(122,830)
Future income tax expenses		(696,657)		341,362		(355,295)
Future net cash flows		977,613		(479,030)		498,583
Effect of discounting net cash flows at 10%		(346,113)		169,595		(176,518)
Standardized measure of discounted future net cash flows	$	631,500	$	(309,435)	$	322,065

(1) Future production costs include operating costs, production taxes and Windfall Profits Tax. For 2014, Windfall Profits Tax equates to $347 million, or 47 percent, of the $ 740 million of undiscounted future production costs.

(2) Future production costs include operating costs, production taxes and Windfall Profits Tax. For 2013, Windfall Profits Tax equates to $848 million, or 63 percent, of the $1,352 million of undiscounted future production costs.

TABLE VI – Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (in thousands):

	Year ended December 31
		2014	2013
	(20.4%)		(32% to 20.4%)
Standardized Measure at January 1	$	322,065	$	449,774
Sales of oil and natural gas, net of related costs		(68,702)		(159,601)
Revisions to estimates of proved reserves:
Net changes in prices, net of production taxes		21,045		57,745
Quantities		(142,136)		(61,614)
Extensions, discoveries and improved recovery, net of future costs		59,039		21,040
Accretion of discount		50,794		51,710
Net change in income taxes		37,049		12,656
Development costs incurred		88,498		83,680
Changes in estimated development costs		(19,545)		7,356
Reduction in indirect ownership interest to 20.4%		—		(142,007)
Timing differences and other		(373)		1,326
Standardized Measure at December 31	$	347,734	$	322,065

S-58

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

			HARVEST NATURAL RESOURCES, INC.
			(Registrant)
Date:	March 29, 2016	By:	/s/ James A. Edmiston
			James A. Edmiston
			Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the 29th of  March 2016, on behalf of the registrant and in the capacities indicated:

Signature	Title
/s/ James A. Edmiston James A. Edmiston	Director, President and Chief Executive Officer (Principal Executive Officer)
/s/ Stephen C. Haynes Stephen C. Haynes	Vice President – Finance, Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer)
/s/ Stephen D. Chesebro’ Stephen D. Chesebro’	Chairman of the Board and Director
/s/ Oswaldo Cisneros Oswaldo Cisneros	Director
/s/ Francisco D'Agostino Francisco D'Agostino	Director
/s/ R. E. Irelan R. E. Irelan	Director
/s/ Patrick M. Murray Patrick M. Murray	Director
/s/ Edgard Leal Edgard Leal	Director

S-59

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S‑8 (Nos. 333-196012, 333-167887, 333-134630, 333-115841 and 333-85900) and Form S‑3 (Nos. 333‑207191 and 333‑197345) of our report dated March 17, 2014, with respect to the consolidated financial statements of Harvest Natural Resources, Inc. and subsidiaries for the year ended December 31, 2013, included on this Annual Report on Form 10-K for the year ended December 31, 2015.

/s/ UHY LLP

Farmington Hills, Michigan

March 29, 2016

EX-23.2

EXHIBIT23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-196012, 333-167887, 333-134630, 333-115841 and 333-85900) and Form S-3 (Nos. 333-197345 and 333-207191) of Harvest Natural Resources, Inc. and subsidiaries (the “Company”) of our reports dated March 29, 2016, relating to the consolidated financial statements and the effectiveness of Harvest Natural Resources Inc. and subsidiaries’ internal control over financial reporting, which appear in this Form 10-K.  Our report contains an explanatory paragraph regarding the Company’s ability to continue as a going concern.

/s/ BDO USA, LLP

Houston, Texas

March 29, 2016

EX-31.1

EXHIBIT 31.1

I, James A. Edmiston, certify that:

1. I have reviewed this report on Form 10-K of Harvest Natural Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March29, 2016

By:	/s/James A. Edmiston
	James A. Edmiston
	President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

I, Stephen C. Haynes, certify that:

1. I have reviewed this report on Form 10-K of Harvest Natural Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  March29,  2016

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

EX-32.1

EXHIBIT 32.1

Accompanying Certificate

Pursuant to Rule 13a – 14(b) or Rule 15d – 14(b)

and 18 U.S.C Section 1350

Not Filed Pursuant to the Securities Exchange Act of 1934

The undersigned Chief Executive Officer of Harvest Natural Resources, Inc. (the “Company”) does hereby certify as follows:

This report on Form 10-K of Harvest Natural Resources, Inc. for the period ended December 31, 2015 and filed with the Securities and Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:  March29, 2016	By:	/s/James A. Edmiston
		James A. Edmiston
		President and Chief Executive Officer

EX-32.2

EXHIBIT 32.2

Accompanying Certificate

Pursuant to Rule 13a – 14 (b) or Rule 15d – 14(b)

and 18 U.S.C Section 1350

Not Filed Pursuant to the Securities Exchange Act of 1934

The undersigned Chief Financial Officer of Harvest Natural Resources, Inc. (the “Company”) does hereby certify as follows:

This report on Form 10-K of Harvest Natural Resources, Inc. for the period ended December 31, 2015 and filed with the Securities and Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:  March29, 2016	By:	/s/ Stephen C. Haynes
		Stephen C. Haynes
		Vice President – Finance, Chief Financial Officer
		and Treasurer

XML

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 23, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Entity Registrant Name	HARVEST NATURAL RESOURCES, INC.
Entity Filer Category	Accelerated Filer
Entity Central Index Key	0000845289
Amendment Flag	false
Entity Current Reporting Status	Yes
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Document Type	10-K
Document Fiscal Period Focus	FY
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2015
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		51,415,164
Entity Public Float			$ 72,142,875

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 7,761	$ 6,585
Restricted cash		25
Accounts receivable	2,461	339
Prepaid expenses and other	826	353
TOTAL CURRENT ASSETS	$ 11,048	7,302
INVESTMENT IN AFFILIATE		164,700
PROPERTY AND EQUIPMENT:
Oil and natural gas properties (successful efforts method)	$ 31,006	54,290
Other administrative property, net	455	217
TOTAL PROPERTY AND EQUIPMENT, net	31,461	54,507
EMBEDDED DERIVATIVE ASSET	5,010
LONG-TERM DEFERRED INCOME TAX ASSETS	120	53
OTHER ASSETS, net of allowance for $0.7 million and $0.0 million at December 31, 2015 and 2014, respectively	142	1,484
TOTAL ASSETS	47,781	228,046
CURRENT LIABILITIES:
Accounts payable, trade and other	370	1,697
Accrued expenses	3,327	4,617
Accrued interest	954	97
Notes payable to noncontrolling interest owners		13,709
Other current liabilities	165	133
TOTAL CURRENT LIABILITIES	4,816	20,253
LONG-TERM DEBT DUE TO RELATED PARTY, net of discount	214
LONG-TERM DEFERRED TAX LIABILITIES, net		14,700
WARRANT DERIVATIVE LIABILITY WITH RELATED PARTY	5,503
OTHER LONG-TERM LIABILITIES	42	215
TOTAL LIABILITIES	$ 10,575	$ 35,168
COMMITMENTS AND CONTINGENCIES (Note 13)
STOCKHOLDERS' EQUITY:
Preferred stock, par value $0.01 per share; authorized 5,000 shares; issued and outstanding, none
Common stock, par value $0.01 per share; shares authorized 150,000 (2015) and 80,000 (2014); shares issued (2015 - 57,987; 2014 - 49,320); shares outstanding (2015 - 51,415; 2014 - 42,748)	$ 580	$ 493
Additional paid-in capital	302,273	280,757
Accumulated deficit	(199,778)	(101,208)
Treasury stock, at cost, 6,572 shares (2015 and 2014)	(66,316)	(66,316)
TOTAL HARVEST STOCKHOLDERS' EQUITY	36,759	113,726
NONCONTROLLING INTEREST OWNERS	447	79,152
TOTAL EQUITY	37,206	192,878
TOTAL LIABILITIES AND EQUITY	$ 47,781	$ 228,046

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
ASSETS
OTHER ASSETS, allowance	$ 0.7	$ 0.0
STOCKHOLDERS' EQUITY:
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	150,000,000	80,000,000
Common stock, shares issued	57,987,000	49,320,000
Common stock, shares outstanding	51,415,000	42,748,000
Treasury stock, at cost, shares	6,572,000	6,572,000

XML

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
EXPENSES:
Depreciation and amortization		$ 108	$ 198	$ 341
Exploration expense		3,900	6,267	15,155
Impairment expense - unproved property costs and oilfield inventories		24,178	57,994	575
Impairment expense - cost investment in affiliate		164,700
Impairment expense - equity investment in affiliate			355,650
General and administrative		19,010	29,496	29,365
Total expense		211,896	449,605	45,436
LOSS FROM OPERATIONS		(211,896)	(449,605)	(45,436)
OTHER NON-OPERATING INCOME (EXPENSE):
Loss on the sale of interest in Harvest Holding			(1,574)	(22,994)
Gain on sale of oil and natural gas properties			2,865
Change in fair value of warrant liabilities		34,510	1,953	3,517
Change in fair value of derivative assets and liabilities		4,813
Interest expense		(2,959)	(11)	(4,495)
Loss on debt conversion		(1,890)
Loss on issuance of debt and warrants		(20,402)
Loss on extinguishment of long-term debt			(4,749)
Foreign currency transaction gains (losses), net		261	(219)	(820)
Other non-operating income (expense), net		483	(58)	(1,569)
Total other non-operating income (expense)		14,816	(1,793)	(26,361)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND EARNINGS FROM INVESTMENT IN AFFILIATE		(197,080)	(451,398)	(71,797)
INCOME TAX EXPENSE (BENEFIT)		(16,423)	(58,290)	73,087
LOSS FROM CONTINUING OPERATIONS BEFORE EARNINGS FROM INVESTMENT IN AFFILIATE		(180,657)	(393,108)	(144,884)
EARNINGS FROM INVESTMENT IN AFFILIATE			34,949	72,578
LOSS FROM CONTINUING OPERATIONS		$ (180,657)	(358,159)	(72,306)
DISCONTINUED OPERATIONS			(554)	(5,150)
NET LOSS		$ (180,657)	(358,713)	(77,456)
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST OWNERS		(82,087)	(165,223)	11,640
NET LOSS AND COMPREHENSIVE LOSS ATTRIBUTABLE TO HARVEST		$ (98,570)	$ (193,490)	$ (89,096)
BASIC LOSS PER SHARE:
Loss from continuing operations	[1]	$ (2.18)	$ (4.59)	$ (2.12)
Discontinued operations			(0.01)	(0.13)
Basic loss per share		(2.18)	(4.60)	(2.25)
DILUTED LOSS PER SHARE:
Loss from continuing operations	[1]	(2.18)	(4.59)	(2.12)
Discontinued operations			(0.01)	(0.13)
Diluted loss per share		$ (2.18)	$ (4.60)	$ (2.25)

[1] Net of net income attributable to noncontrolling interest owners.

XML

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings (Loss) [Member]	Treasury Stock [Member]	Non-Controlling Interests [Member]	Total
Balance at Dec. 31, 2012	$ 458	$ 263,646	$ 181,378	$ (66,145)	$ 97,101	$ 476,438
Balance, shares at Dec. 31, 2012	45,882
Issuance of common shares:
Exercise of stock options		122				122
Exercise of stock options, shares	20
Sales of common shares	$ 25	9,273				9,298
Sales of common shares, shares	2,495
Employee stock-based compensation	$ 4	3,042				3,046
Employee stock-based compensation, shares	269
Purchase of treasury shares				(77)		(77)
Increase in equity held by noncontrolling interests due to sale of interest in affiliate					144,796	144,796
Dividend to noncontrolling interest owner					(10,370)	(10,370)
Net income (loss)			(89,096)		11,640	(77,456)
Balance at Dec. 31, 2013	$ 487	276,083	92,282	(66,222)	243,167	545,797
Balance, shares at Dec. 31, 2013	48,666
Issuance of common shares:
Sales of common shares	$ 6	2,022				2,028
Sales of common shares, shares	654
Employee stock-based compensation		2,652				2,652
Purchase of treasury shares				(94)		(94)
Contributions from noncontrolling interest owners					1,208	1,208
Net income (loss)			(193,490)		(165,223)	(358,713)
Balance at Dec. 31, 2014	$ 493	280,757	(101,208)	(66,316)	79,152	192,878
Balance, shares at Dec. 31, 2014	49,320
Issuance of common shares:
Employee stock-based compensation		2,271				2,271
Conversion of 9% Note	$ 87	13,088				13,175
Conversion of 9% Note, shares	8,667
Contribution from noncontrolling owner of note payable and accrued interest payable		6,157				6,157
Contributions from noncontrolling interest owners					3,382	3,382
Net income (loss)			(98,570)		(82,087)	(180,657)
Balance at Dec. 31, 2015	$ 580	$ 302,273	$ (199,778)	$ (66,316)	$ 447	$ 37,206
Balance, shares at Dec. 31, 2015	57,987

XML

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical)	Dec. 31, 2015
CT Energy [Member] | 9% Note [Member]
Interest rate	9.00%

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (180,657)	$ (358,713)	$ (77,456)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization	108	198	354
Impairment expense - unproved property costs and oilfield inventories	24,178	57,994	3,770
Impairment expense - cost investment in affiliate	164,700
Impairment expense - equity investment in affiliate		355,650
Amortization of debt financing costs	283	28	1,489
Accretion of discount on debt	225		2,641
Allowance for long-term receivable	734	13,753
Loss on the sale of interest in Harvest Holding		1,574	22,994
Gain on sale of oil and natural gas properties		(2,865)
Loss on debt issuance	20,402
Loss on debt conversion	1,890
Foreign currency transaction loss		1,239	436
Loss on extinguishment of long-term debt		4,749
Earnings from investment in affiliate		(34,949)	(72,578)
Share-based compensation-related charges	2,271	2,652	3,046
Deferred income tax expense (benefit)	(14,767)	(58,221)	73,689
Change in fair value of warrant liabilities	(34,510)	(1,953)	(3,517)
Change in fair value of derivative assets and liabilities	(4,813)
Changes in operating assets and liabilities:
Accounts receivable	(2,122)	1,623	993
Prepaid expenses and other	(473)	339	710
Other assets	350	(328)	3,971
Accounts payable	(1,327)	(2,701)	428
Accrued expenses	(1,259)	(16,112)	3,790
Accrued interest	1,036	(360)	(244)
Other current liabilities	32	(2,464)	(1,043)
Other long-term liabilities	(173)	(343)	(550)
NET CASH USED IN OPERATING ACTIVITIES	(23,892)	(39,210)	(37,077)
CASH FLOWS FROM INVESTING ACTIVITIES:
Transaction costs from the sale of interest in Harvest Holding		(3,742)
Net proceeds from sale of oil and natural gas properties		2,865
Net proceeds from sale of interest in investment in affiliate			124,045
Additions of property and equipment, net	(1,270)	(4,382)	(43,906)
Payment from (advances to) investment in affiliate, net		105	(531)
Decrease in restricted cash		123	852
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(1,270)	(5,031)	80,460
CASH FLOWS FROM FINANCING ACTIVITIES:
Debt repayment	(8,900)	(79,750)
Debt extinguishment costs		(760)
Gross proceeds from issuance of debt and warrant	33,500
Proceeds from issuance of note payable to noncontrolling interest owner		7,600
Proceeds from issuance of common stock		2,036	9,420
Contributions from noncontrolling interest owners	3,382	1,208
Treasury stock purchases		(94)	(77)
Payments on note payable to noncontrolling interest owner			(4,260)
Financing costs	(1,644)	(311)	(196)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	26,338	(70,071)	4,887
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,176	(114,312)	48,270
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	6,585	120,897	72,627
CASH AND CASH EQUIVALENTS AT END OF YEAR	7,761	6,585	120,897
Supplemental Cash Flow Information:
Cash paid during the period for interest expense	1,547		487
Cash paid during the period for income taxes	6	1,128	495
Supplemental Schedule of Noncash Investing and Financing Activities:
Decrease in current liabilities related to additions of property and equipment	(30)	$ (210)	$ (13,926)
Increase in Stockholders' Equity from forgiveness of note payable and accrued interest	6,157
Issuance of common stock from conversion of 9% Convertible Senior Secured Note	$ 13,175

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Dec. 31, 2015
CT Energy [Member] | 9% Note [Member]
Interest rate	9.00%

XML

Organization

12 Months Ended

Dec. 31, 2015

Organization [Abstract]

Organization

Note 1 – Organization

Harvest Natural Resources, Inc. (“Harvest” or  the “Company”) is an independent energy company engaged in the acquisition, exploration, development, production and disposition of oil and natural gas properties since 1988, when it was incorporated under Delaware law.

We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through Harvest-Vinccler Dutch Holding B.V., a Dutch private company with limited liability (“Harvest Holding”). Our ownership of Harvest Holding is through HNR Energia B.V. (“HNR Energia”) in which we have a direct controlling interest. 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 (the “SPA”) with Petroandina Resources Corporation N.V. (“Petroandina”, a wholly owned subsidiary of Pluspetrol Resources Corporation B.V. (“Pluspetrol”)) 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 $400.0 million. The first closing occurred on December 16, 2013 contemporaneously with the signing of the SPA, when we sold a 29 percent equity interest in Harvest Holding for $125.0 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.  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 29 percent and Vinccler continuing to own 20 percent. The second closing did not occur during 2014 and the SPA was terminated by the Company on January 1, 2015. See Note 5 – Dispositions below for further information on this transaction.

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”). Petrodelta is our cost investment in eastern Venezuela responsible for the exploration, development, production, gathering, transportation and storage of hydrocarbons in six oil fields. Petrodelta is governed by its own charter and bylaws and the shareholders intend that the Company be self-funding and rely on internally-generated cash flows. 

Corporación Venezolana del Petroleo S.A. (“CVP”) and PDVSA Social S.A. owns the remaining 56 percent and 4 percent, 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, and 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.

In addition to our interests in Venezuela, we also hold exploration and exploitation acreage offshore of the Republic of Gabon (“Gabon”) through the Dussafu Marin Permit (“Dussafu PSC”). See Note 8 – Gabon.

On June 19, 2015, the Company and certain of its domestic subsidiaries entered into a securities purchase agreement (the “Purchase Agreement”) with CT Energy Holding SRL (“CT Energy”), a Venezuelan-Italian consortium organized as a Barbados Society with Restricted Liability, under which CT Energy purchased certain securities of the Company and acquired certain governance rights.  Harvest immediately received gross proceeds of $32.2 million from the sale of the securities, as described below.   Key terms of the transaction include:

· CT Energy acquired a $25.2 million, five year, 15.0% non-convertible senior secured promissory note (the “15% Note”). Interest is payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2015. 

· CT Energy acquired a $7.0 million, five year, 9.0% convertible senior secured note (the “9% Note”). The 9% Note face value of $7.0 million and associated accrued interest of $0.1 million was converted into 8,667,597 shares of Harvest common stock at a conversion price of $0.82 per  share on September 15, 2015.  Immediately after the conversion, CT Energy owned approximately 16.6% of Harvest’s common stock.

· CT Energy also acquired a warrant to purchase up to 34,070,820 shares of Harvest's common stock at an initial exercise price of $1.25 per share (the “CT Warrant”). The CT Warrant will become exercisable only after the 30-day volume weighted average price of Harvest's common stock equals or exceeds $2.50 per share (“Stock Appreciation Date”).  The warrant is cash-exercisable, but CT Energy may surrender the 15% Note to pay for a portion of the aggregate exercise price. 

· CT Energy acquired a five-year 15.0% non-convertible senior secured note (the “Additional Draw Note”), under which CT Energy may elect to provide $2.0 million of additional funds to the Company per month for up to six months following the one-year anniversary of the closing date of the transaction (up to $12.0 million in aggregate).  If funds are loaned under the Additional Draw Note, interest will be compounded quarterly at a rate of 15.0% per annum and is payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2016.  If by June 19, 2016 (the “Claim Date”),  the volume weighted average price of the Company’s common stock over any consecutive 30-day period has not equaled or exceeded $2.50 per share, the maturity date of the Additional Draw Note will be extended by two years and the interest rate on the Additional Draw Note will adjust to 8.0%. During an event of default, the outstanding principal amount will bear additional interest at a rate of 2.0% per annum higher than the rate otherwise applicable.

· CT Energy also acquired 69.75 shares of the Company’s newly created Series C preferred stock, par value $0.01 per share.  The purpose of the Series C preferred stock was to provide the holder of the 9% Note with voting rights equivalent to the common stock underlying the unconverted portion of the 9% Note.  Upon conversion of the 9% Note, the Series C preferred stock ceased to have voting rights and was redeemed. 

· CT Energy was granted certain governance rights in the transaction, including the right to appoint specified directors.  Also, the Company and CT Energia Holding Ltd. (“CT Energia”), a Malta corporation, entered into a Management Agreement (the “Management Agreement”), under which CT Energia and its representatives will manage the day-to-day operations of the Company’s business as it relates to Petrodelta and Venezuela generally.

At our annual shareholder meeting, on September 9, 2015, Harvest stockholders approved, among other proposals, 1) certain aspects of the transaction under NYSE shareholder approval requirements and Delaware law and 2) an amendment to Harvest's charter to increase the number of authorized shares of our common stock from 80,000,000 to 150,000,000, in part to have sufficient shares to issue upon conversion of the 9% Note and exercise of the CT Warrant and an amendment to the 2010 Long Term Incentive Plan increasing the number shares of our common stock to satisfy of stock options, stock appreciation rights (“SARs”), restricted stock, restricted stock units (“RSUs”) and other stock-based awards.  See Note 15 – Stock-Based Compensation and Stock Purchase Plans.  

XML

Liquidity and Going Concern

12 Months Ended

Dec. 31, 2015

Liquidity and Going Concern [Abstract]

Liquidity and Going Concern

Note 2 – Liquidity and Going Concern

We expect that for 2016 we will not generate revenue, will continue to generate losses from operations, and our cash flows will not be sufficient to cover our operating expenses. Therefore, expected continued losses from operations, capital needs and uses of cash will be funded through debt or equity financings, farm-downs, delay of the discretionary portion of our capital spending to future periods or operating cost reductions.  Our ability to continue as a going concern depends on our ability to negotiate the management and structure of our investment in Petrodelta and the success of our planned exploration and development activities in Gabon.  There can be no guarantee of future capital acquisition, fundraising or exploration success or that we will realize the value of our exploration and exploitation acreage and suspended wells.  We believe that we will continue to be successful in securing any funds necessary to continue as a going concern.  However, our current cash position and our inability to access additional capital may limit our available opportunities or not provide sufficient cash for operations.

Historically, prior to the transaction pursuant to the Purchase Agreement, our primary ongoing source of cash had been dividends from Petrodelta, issuance of debt and the sale of oil and natural gas properties. Our primary use of cash has been to fund oil and natural gas exploration projects, principal payments on debt, interest, and general and administrative costs. We require capital principally to fund the exploration and development of new oil and natural gas properties. We have various contractual commitments pertaining to exploration, development and production activities. 

See Note 8 – Gabon and Note 13 – Commitments and Contingencies for our contractual commitments.

We are currently assessing alternatives for our Gabon asset, and we intend to continue our consideration of a possible sale or farm-down of our Gabon asset 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.   Given that we do not currently have any operating cash inflows, we may also decide to access additional capital through equity or debt sales; however, there can be no assurance that such financing will be available to the Company or on terms that are acceptable to the Company.

On December 2, 2015, the Company received notification from the NYSE that the Company was not in compliance with the NYSE's continued listing standards, which require a minimum average closing price of $1.00 per share over 30 consecutive trading days.  Under the NYSE's rules, Harvest has a period of six months from the date of the NYSE notice to bring its share price and 30 trading-day average share price back above $1.00.  During this period, the Company’s common stock will continue to be traded on the NYSE under the symbol “HNR”, subject to the Company’s compliance with other NYSE continued listing requirements, but will be assigned the notation .BC after the listing symbol to signify that the Company is not currently in compliance with the NYSE’s continued listing standards.  As required by the NYSE, in order to maintain its listing, Harvest has notified the NYSE that it intends to cure the price deficiency.

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

The above circumstances raise substantial doubt about our ability to continue as a going concern.  While we believe the issuance of additional equity securities, short- or long-term debt financing, farm-downs, the delay of the discretionary portion of our capital spending to future periods or operating cost reductions could be put into place which would not jeopardize our operations and future growth plans, there can be no assurance that such financings will be successful.

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

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 3 – Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. All intercompany profits, transactions and balances have been eliminated. Third-party interests in our majority-owned subsidiaries are presented as noncontrolling interest owners.

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current period presentation.  These reclassifications did not affect our consolidated financial results.

Investment in Petrodelta

Through December 31, 2014, we included the results of Petrodelta in our financial statements under the equity method.  We ceased recording earnings from Petrodelta in the second quarter 2014 due to the expected sales price of the second closing purchase agreement approximating the recorded value of our investment in Petrodelta.  The Company was not able to obtain approval from the government of Venezuela during 2014 and on January 1, 2015 we terminated the SPA.  Due to our failed sales attempts, lack of management influence, and actions and inactions by the majority owner, PDVSA, we believe we no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.  Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.  

We evaluate our investment in Petrodelta for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may be impaired. A loss is recorded in earnings in the current period if a decline in the value of the investment is determined to be other than temporary. Impairment is calculated as the difference between the carrying value of the investment and its fair value.  We recorded pre-tax impairment charges against the carrying value of our investment in Petrodelta of $164.7 million and $355.7 million during the years ended December 31, 2015 and 2014, respectively.  See Note 6 – Investment in Affiliate for further information.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Other important significant estimates are those included in the valuation of our assets and liabilities that are recorded at fair value on a recurring and non-recurring basis.  Actual results could differ from those estimates.

Reporting and Functional Currency

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

See Note 6 – Investment in Affiliate and Note 7 – Venezuela - Other for a discussion of currency exchange rates and currency exchange risk on Petrodelta’s and Harvest Vinccler’s businesses.

Cash and Cash Equivalents

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

Restricted Cash

Restricted cash is classified as current or non-current based on the terms of the agreement. Restricted cash at December 31, 2014 represented $25,000 held in a U.S. bank as collateral for our foreign credit card program. There was no restricted cash as of December 31, 2015.

Financial Instruments

Financial instruments, which potentially subject us to concentrations of credit risk, are primarily cash and cash equivalents, accounts receivable, notes payable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts with commercial banks with high credit ratings, which, at times may exceed the federally insured limits. We have not experienced any losses from such investments. Concentrations of credit risk with respect to accounts receivable are limited due the nature of our receivables, which include primarily joint venture partner’s receivable, and income tax receivable. In the normal course of business, collateral is not required for financial instruments with credit risk.

Oil and Natural Gas Properties

The major components of property and equipment are as follows: 

	As of December 31,
	2015		2014
	(in thousands)
Unproved property costs - Dussafu PSC	$	28,000	$	50,324
Oilfield inventories		3,006		3,966
Other administrative property		2,937		2,670
Total property and equipment		33,943		56,960
Accumulated depreciation		(2,482)		(2,453)
Total property and equipment, net	$	31,461	$	54,507

Property and equipment are stated at cost less accumulated depreciation. Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of property and equipment, net of the related accumulated depreciation is removed and, if appropriate, gains or losses are recognized in investment earnings and other. We did not record any depletion expense in the years ended December 31, 2015, 2014 and 2013 as there was no production related to proved oil and natural gas properties.

We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that proved reserves, as that term is defined in Securities and Exchange Commission (“SEC”) regulations, have not been discovered, capitalized costs associated with the drilling of the exploratory well are charged to expense. Costs of drilling successful exploratory wells, all development wells, and related production equipment and facilities are capitalized and depleted or depreciated using the unit-of-production method as oil and natural gas is produced. During the years ended December 31, 2015, 2014 and 2013, we expensed no dry hole costs.

Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period. Costs of maintaining and retaining unproved leaseholds are included in exploration expense.  Costs of impairment of unsuccessful leases are included in impairment expense.  We assess our unproved property costs for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of the projects.  The estimated value of our unproved projects is determined using quantitative and qualitative assessments and the carrying value of the projects is adjusted if the carrying value exceeds the assessed value of the projects. 

Impairment is based on specific identification of the lease. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and natural gas properties.

Proved oil and natural gas properties are reviewed for impairment at a level for which identifiable cash flows are independent of cash flows of other assets when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are determined based on estimated future oil and natural gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these undiscounted estimated future net cash flows is less than the carrying amount of the property, an impairment loss is recognized for the excess of the property’s carrying amount over its estimated fair value, which is generally based on discounted future net cash flows. We did not have any proved oil and natural gas properties in 2015,  2014 or 2013.

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

During the year ended December 31, 2015, we recorded impairment expense related to our Dussafu Project in Gabon of $24.2 million (including $1.0 million of oilfield inventories). During the year ended December 31, 2014, we recorded impairment expense related to our Budong Project in Indonesia of $7.7 million and our Dussafu Project of $50.3 million.  During the year ended December 31, 2013, we recorded impairment expense related to our Budong Project in Indonesia of $0.6 million and our project in Colombia of $3.2 million, which is reflected in discontinued operations.

Other Administrative Property

Furniture, fixtures and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to five years. Leasehold improvements are recorded at cost and amortized using the straight-line method over the life of the applicable lease. For the year ended December 31, 2015, depreciation expense was $0.1 million ($0.2 million and $0.3 million for the years ended December 31, 2014 and 2013, respectively).

Other Assets

Other Assets at December 31, 2015 and 2014 include deposits, prepaid expenses which are expected to be realized in the next 12 to 24 months.  During 2015 we fully reserved the blocked payment related to our drilling operations in Gabon in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”) See Note 13 – Commitments and Contingencies.   We recorded an allowance for doubtful accounts of $0.7 million and the remaining balance of the blocked payment was reclassified to a receivable from our joint venture partners for $0.4 million.  Other assets at December 31, 2014 also consisted of deferred financing costs. Deferred financing costs relate to specific financings and are amortized over the life of the financings to which the costs relate using the interest rate method.

	As of December 31,
	2015		2014
	(in thousands)
Deposits and long-term prepaid expenses	$	142	$	101
Deferred financing costs		—		283
Gabon – blocked payment		—		1,100
	$	142	$	1,484

Reserves

We measure and disclose oil and natural 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”). All of our reserves are owned through our investment in Petrodelta. We are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.  Under the cost method, we do not have any reserves at December 31, 2015 and 2014.

Capitalized Interest

We capitalize interest costs for qualifying oil and natural gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation. During the year ended December 31, 2015, we capitalized interest costs for qualifying oil and natural gas property additions related to Gabon of $0.0 million ($0.5 million and $8.3 million during the years ended December 31, 2014 and 2013, respectively).

Fair Value Measurements

We measure and disclose our fair values in accordance with the provisions of ASC 820 “Fair Value Measurements and Disclosures” (“ASC 820”). ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price) and establishes a three-level hierarchy, which encourages an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The three levels of the hierarchy are defined as follows:

· Level 1 – Inputs to the valuation techniques that are quoted prices in active markets for identical assets or liabilities.

· Level 2 – Inputs to the valuation techniques that are other than quoted prices but are observable for the assets or liabilities, either directly or indirectly.

· Level 3 – Inputs to the valuation techniques that are unobservable for the assets or liabilities.

Financial instruments, which potentially subject us to concentrations of credit risk, are primarily cash and cash equivalents, accounts receivable, SARs, RSUs, debt, embedded derivatives and warrant derivative liabilities. We maintain cash and cash equivalents in bank deposit accounts with commercial banks with high credit ratings, which, at times may exceed the federally insured limits. We have not experienced any losses from such investments. Concentrations of credit risk with respect to accounts receivable are limited due to the nature of our receivables. In the normal course of business, collateral is not required for financial instruments with credit risk.  The estimated fair value of cash and cash equivalents and accounts receivable approximates their carrying value due to their short-term nature (Level 1).  The following tables set forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value as of December 31, 2015 and December 31, 2014. During the year ended December 31, 2015, we impaired the carrying value of our Dussafu project in Gabon by $23.2 million and our investment in affiliate by $164.7 million.  See Note 6 – Investment in Affiliate and Note 8 – Gabon for more information.

	As of December 31, 2015
	Level 1		Level 2		Level 3		Total
	(in thousands)
Non recurring
Assets:
Investment in affiliate	$	—	$	—	$	—	$	—
Dussafu PSC		—		—		28,000		28,000
	$	—	$	—	$	28,000	$	28,000

Recurring
Assets:
Embedded derivative asset	$	—	$	—	$	5,010	$	5,010
	$	—	$	—	$	5,010	$	5,010
Liabilities:
SARs liability	$	—	$	46	$	50	$	96
RSUs liability		—		174		—		174
Warrant derivative liability		—		—		5,503		5,503
	$	—	$	220	$	5,553	$	5,773

	As of December 31, 2014
	Level 1		Level 2		Level 3		Total
	(in thousands)
Non recurring
Assets:
Investment in affiliate	$	—	$	—	$	164,700	$	164,700
Dussafu PSC		—		—		50,324		50,324
	$	—	$	—	$	215,024	$	215,024
Recurring
Liabilities:
SARs liability	$	—	$	356	$	—	$	356
RSUs liability		—		652		—		652
	$	—	$	1,008	$	—	$	1,008

As of December 31, 2015, the fair value of our liability awards included $0.1 million for our SARs and $0.2 million for the RSUs which were recorded in accrued expenses and other long-term liabilities, respectively.  As of December 31, 2014, the fair value of our liability awards of $0.8 million was included in accrued liabilities ($0.4 million for our SARs and $0.4 million for our RSUs) with the remaining $0.2 million fair value of our RSU liability being included in long-term liabilities.

Derivative Financial Instruments

As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value liabilities and their placement within the fair value hierarchy levels. See Note 12 – Warrant Derivative Liability for a description and discussion of our warrant derivative liability as well as a description of the valuation models and inputs used to calculate the fair value.  See Note 11 – Debt and Financing for a description and discussion of our embedded derivatives related to our 9% Note and 15% Note as well as a description of the valuation models and inputs used to calculate the fair value.  All of our embedded derivatives and warrants are classified as Level 3 within the fair value hierarchy. 

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

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

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial assets -  embedded derivative asset
Beginning balance	$	—	$	—	$	—
Additions - fair value at issuance		2,504		—		—
Change in fair value		2,506		—		—
Ending balance	$	5,010	$	—	$	—

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial liabilities -  embedded derivative liability
Beginning balance	$	—	$	—	$	—
Additions - fair value at issuance		13,449		—		—
Change in fair value		(2,307)		—		—
Conversion of debt		(11,142)		—		—
Ending balance	$	—	$	—	$	—

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial liabilities -  warrant derivative liabilities:
Beginning balance	$	—	$	1,953	$	5,470
Additions - fair value at issuance		40,013		—		—
Change in fair value		(34,510)		(1,953)		(3,517)
Ending balance	$	5,503	$	—	$	1,953

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial liabilities -  stock appreciation rights
Beginning balance	$	—	$	—	$	—
Additions - fair value at issuance		—		—		—
Change in fair value		50		—		—
Ending balance	$	50	$	—	$	—

During the year ended December 31, 2015, 2014 and 2013, no transfers were made between Level 1, Level 2 and Level 3 liabilities or assets.

Share-Based Compensation

We use the fair value based method of accounting for share-based compensation. In prior years, we utilized the Black-Scholes option pricing model to measure the fair value of stock options and SARs. Restricted stock and RSUs were measured at their fair values.  During 2015, we issued options, SARs, and RSUs with an additional market condition.  To fair value these awards, a Monte Carlo simulation was utilized.  For more information about our share-based compensation, the fair value of these awards, and the additional market condition.   See Note 15 – Stock-Based Compensations and Stock Purchase Plans.

Income Taxes

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

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

Since December of 2013 we have provided deferred income taxes on undistributed earnings of our foreign subsidiaries where we are not able to assert that such earnings were permanently reinvested, or otherwise could be repatriated in a tax free manner, as part of our ongoing business.  As of December 31, 2015, the deferred tax liability provided on such earnings has been reduced to zero due to the impairment of the underlying book investment in Petrodelta.

As the conversion feature of the 9% Note was reasonably expected to be exercised at the time of the note’s issuance due to the conversion price being in-the-money, the interest on the 9% Note paid upon its conversion is non-deductible to the Company under Internal Revenue Code (“IRC”) Section 163(l).  The 15% Note was issued, for income tax purposes, with original issue discount (“OID”).  OID generally is deductible for income tax purposes.  However, if the debt instrument constitutes an “applicable high-yield discount obligation” (“AHYDO”) within the meaning of IRC Section 163(i)(1), then a portion of the OID likely would be non-deductible pursuant to IRC Section 163(e)(5).  Our analysis of the 15% Note is that the note may be an AHYDO; consequently, a portion or all of the OID likely may be non-deductible for income tax purposes.

Noncontrolling Interests

Changes in noncontrolling interest owners were as follows:

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Balance at beginning of period	$	79,152	$	243,167	$	97,101
Contributions by noncontrolling interest owners		3,382		1,208		—
Increase in equity held by noncontrolling interest owner		—		—		144,796
Dividend to noncontrolling interest owner		—		—		(10,370)
Net income (loss) attributable to noncontrolling interest owners		(82,087)		(165,223)		11,640
Balance at end of period	$	447	$	79,152	$	243,167

Valuation and Qualifying Accounts

Our valuation and qualifying accounts are comprised of the deferred tax valuation allowance, investment valuation allowance and Value-Added Tax (“VAT”) receivable valuation allowance. Balances and changes in these accounts are, in thousands:

			Additions
	Balance at Beginning of Year		Charged to Income			Other			Deductions From Reserves Credited to Income		Balance at End of Period
	(in thousands)
At December 31, 2015
Amounts deducted from applicable assets
Deferred tax valuation allowance	$	181,906	$	—		$	44,014		$	—	$	225,920
Investment valuation allowance		1,350		—			—			—		1,350
VAT valuation allowance		2,792		—			(2,792)	(b)		—		—
Long-term receivable - investment in affiliate		13,753		—			—			—		13,753
At December 31, 2014
Amounts deducted from applicable assets
Deferred tax valuation allowance	$	59,576	$	129,480		$	(7,150)	(a)	$	—	$	181,906
Investment valuation allowance		1,350		—			—			—		1,350
Long-term receivable - investment in affiliate		—		13,753	(c)		—			—		13,753
VAT valuation allowance		2,792		—			—			—		2,792
At December 31, 2013
Amounts deducted from applicable assets
Deferred tax valuation allowance	$	68,419	$	—		$	—		$	(8,843)	$	59,576
Investment valuation allowance		1,350		—			—			—		1,350
VAT valuation allowance		—		2,792			—			—		2,792

(a) Attributable to reversal of temporary differences related to discontinued operations.

(b) Valuation allowance for the VAT receivable associated with Harvest Budong.  On May 4, 2015, the Company sold the shares of Harvest Budong-Budong B.V. to Stockbridge Capital Limited and the rights to the VAT receivable went with the entity to the buyer.

(c) During the year ended December 31, 2014, we fully reserved a dividend receivable of $12.2 million and $1.6 million of long-term receivable due from our investment in affiliate.

New Accounting Pronouncements

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs”. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update.  In June 2015 the FASB issued ASU No. 2015-15 as an amendment to this guidance to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements.  The SEC staff stated that they would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement.  The guidance is effective for interim periods and annual period beginning after December 15, 2015; however early adoption is permitted. We do not believe the adoption of this guidance will have a material impact on our financial position and will not have an impact on our results of operations or cash flows.

In August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern” ASU No. 2014-15. ASU No. 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU No. 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.

In April 2014, FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers” which is included in ASC 606, a new topic under the same name. The guidance in this update affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). The guidance supersedes the previous revenue recognition requirements and most industry-specific guidance. Additionally, the update supersedes some cost guidance related to construction type and production-type contracts.  In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in this update.

The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps:  (1) identify the contract(s) with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation.

The new guidance also provides for additional qualitative and quantitative disclosures related to: (1) contracts with customers, including revenue and impairments recognized, disaggregation of revenue, and information about contract balances and performance obligations (including the transaction price allocated to the remaining performance obligations); (2) significant judgments and changes in judgments which impact the determination of the timing of satisfaction of performance obligations (over time or at a point in time), the transaction price and amounts allocated to performance obligations; and (3) assets recognized from the costs to obtain or fulfill a contract.

In July 2015, the FASB issued a decision to delay related to ASU No. 2014-09 for the effective date by one year.  The new guidance is effective for annual and interim periods beginning after December 15, 2017.  An entity should apply the amendments either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of initial application. We are currently evaluating the impact of this guidance.

In November 2015, the FASB issued ASC No. 2015-17, “Balance Sheet Classification of Deferred Taxes”.  ASU No. 2015-17 simplifies the balance sheet presentation of deferred income taxes by requiring all deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The standard is effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted.  The standard may be applied either prospectively or retrospectively to all periods presented.  The Company has decided to adopt the accounting change in its current financial statements and has adopted the change retrospectively.

In February 2016, the FASB issued ASU No. 2016-02, “Leases”.  It is expected to be effective for periods beginning after December 15, 2018 for public entities, and for periods beginning after December 15, 2019 for nonpublic entities.  Early application is permitted.  Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less.  All other leases will fall into one of two categories: (1) Financing leases, similar to capital leases, will require the recognition of an asset and liability, measured at the present value of the lease payments.  Interest on the liability will be recognized separately from amortization of the asset.  Principal repayments will be classified as financing outflows and payments of interest as operating outflows on the statement of cash flows.  (2) Operating leases will also require the recognition of an asset and liability measured at the present value of the lease payments.  A single lease cost, consisting of interest on the obligation and amortization of the asset, calculated such that the amortization of the asset will increase as the interest amount decreases resulting in a straight-line recognition of lease expense.  All cash outflows will be classified as operating on the statement of cash flows.  We do not believe the adoption of this guidance will have a material impact on our financial position, results of operations or cash flows.

In March 2016, the FASB issued ASU No. 2016-07, “Investments — Equity Method and Joint Ventures (Topic 323)”. This amendment simplifies the accounting for equity method of investments, the amendment in the update eliminates the requirement in Topic 323 that an entity retroactively adopt the equity method of accounting if an investment qualifies for use of the equity method as a result of an increase in the level of ownership or degree of influence. The amendment requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt equity method of accounting as of the date the investment becomes qualified for equity method accounting. The amendment in this update is effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. The amendment should be applied prospectively upon the effective date to increases in the level of ownership interest or degree of influence that result in the adoption of the equity method. Earlier application is permitted.  We are currently evaluating the impact of this guidance.

XML

Earnings Per Share

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Earnings Per Share

Note 4 – Earnings Per Share

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

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Loss from continuing operations(a)	$	(98,570)	$	(192,936)	$	(83,946)
Discontinued operations		—		(554)		(5,150)
Net loss attributable to Harvest	$	(98,570)	$	(193,490)	$	(89,096)
Weighted average common shares outstanding		45,288		42,039		39,579
Weighted average common shares, diluted		45,288		42,039		39,579
Basic loss per share:
Loss from continuing operations(a)	$	(2.18)	$	(4.59)	$	(2.12)
Discontinued operations		—		(0.01)		(0.13)
Basic loss per share	$	(2.18)	$	(4.60)	$	(2.25)
Diluted loss per share:
Loss from continuing operations(a)	$	(2.18)	$	(4.59)	$	(2.12)
Discontinued operations		—		(0.01)		(0.13)
Diluted loss per share	$	(2.18)	$	(4.60)	$	(2.25)

(a) Net of net income attributable to noncontrolling interest owners.

The year ended December 31, 2015 per share calculations above exclude 4.1 million options,  34.1 million warrants and 1.6 million RSUs because we are in a net loss position.   The year ended December 31, 2014 per share calculations above exclude0.2 million unvested restricted shares,4.5 million options and 2.5 million warrants because we were in a net loss position. The year ended December 31, 2013 per share calculations above exclude0.3 million unvested restricted shares,4.2 million options and 2.5 million warrants because we were in a net loss position.

XML

Dispositions

12 Months Ended

Dec. 31, 2015

Dispositions [Abstract]

Dispositions

Note 5 – Dispositions

Share Purchase Agreement

On December 16, 2013, Harvest and HNR Energia entered into the SPA 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 $400.0 million. The first closing occurred on December 16, 2013 contemporaneously with the signing of the SPA, when we sold a 29 percent equity interest in Harvest Holding for $125.0 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. 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 29 percent and Vinccler continuing to own 20 percent. The second closing, for the sale of a 51 percent equity interest in Harvest Holding for a cash purchase price of $275.0 million, was 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).

On May 7, 2014, Harvest’s stockholders voted to authorize the sale of the remaining interests in Harvest Holding.  Once stockholders’ approval was obtained, the SPA allowed for 120 days, or until September 7, 2014, for consummation of the sale, extension of the SPA or termination of the SPA.  Petroandina had the right to extend the SPA beyond the termination date in increments of one month, but not beyond December 31, 2014, in exchange for the Company’s right to borrow up to $2.0 million, not to exceed $7.6 million in the aggregate, from Petroandina per each monthly extension.  Petroandina exercised this right through December 31, 2014 with the Company borrowing $7.6 million in total during this period.  Repayments of these loans are subject to certain conditions, one of which states that all outstanding loans (along with interest accrued and other amounts) would become due upon the final closing date of the SPA, with the second tranche proceeds being reduced by such outstanding amounts.  If the SPA was terminated by either party, any outstanding loans would become due one year from the date of the termination.

On January 1, 2015, HNR Energia exercised its right to terminate the SPA in accordance with its terms as a result of the failure to obtain the necessary approval from the Government of Venezuela. As a result of the termination of the SPA, the Company retained its 51 percent equity interest in Harvest Holding, and Petroandina retained its 29 percent equity interest in Harvest Holding.

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 became effective upon the termination of the SPA.

China

On July 2, 2014, we completed the sale of our rights under a petroleum contract with China National Offshore Oil Corporation for the WAB-21 area for net proceeds of $2.9 million and recorded that amount as a gain from sale of oil and natural gas properties.  This area is located in the South China Sea and is the subject of a border dispute between China and Socialist Republic of Vietnam. 

Discontinued Operations

Oman

We have no continuing operations in Oman.  The nominal loss from discontinued operations for Oman for the year ended December 31, 2014 included general and administrative expenses.  The loss from discontinued operations for Oman of $0.7 million for the year ended December 31, 2013 included $0.2 million of exploration expense and $0.5 million of general and administrative expenses and other expenses.

Colombia

In February 2013, we signed farm-down agreements on Block VSM14 and Block VSM15 in Colombia. Under the terms of the farm-down 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 natural gas regulatory authority, and approval of us as operator.

We received notices of default from our partners for failing to comply with certain terms of the farm-down agreements for Block VSM14 and Block VSM15, followed by notices of termination on November 27, 2013. Our partners filed for arbitration of claims related to these agreements. We accrued $2.0 million as of December 31, 2013 related to this matter. 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, which included the $2.0 million accrual related to arbitration, during the year ended December 31, 2013. In December 2014, we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed.  We are in the process of closing and exiting our Colombia venture.  As we no longer have any interests in Colombia, we have reflected the results in discontinued operations.  The loss from discontinued operations included $0.5 million in general and administrative expenses during the year ended December 31, 2014.  The loss from discontinued operations included $3.2 million in impairment expense, $0.7 million of exploration expense and $0.6 million in general and administrative expenses during the year ended December 31, 2013.

Oman and Colombia operations have been classified as discontinued operations. No revenues were recorded related to these projects for the years presented.  Expenses are shown in the table below:

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Loss from Discontinued Operations
Oman	$	—	$	(27)	$	(674)
Colombia		—		(527)		(4,476)
	$	—	$	(554)	$	(5,150)

XML

Investment in Affiliate

12 Months Ended

Dec. 31, 2015

Investment in Affiliate [Abstract]

Investment in Affiliate

Note 6 – Investment in Affiliate

Venezuela – Petrodelta, S.A.

The following table summarizes the changes in our investment in affiliate (Petrodelta) as of December 31, 2015 and 2014.  Petrodelta’s reporting and functional currency is the USD.

	Year Ended December 31,
	2015		2014
	(in thousands)
Investment at beginning of year	$	164,700	$	485,401
Equity in earnings				34,949
Impairment		(164,700)		(355,650)
Investment at end of period	$	—	$	164,700

Our 40 percent investment in Petrodelta is owned through our subsidiary, Harvest Holding, a Dutch private company with limited liability.   Up until December 16, 2013 we had an 80 percent interest in Harvest Holding.  On December 16, 2013, Harvest entered into a share purchase agreement (“SPA”) with Petroandina Resources Corporation to sell our 80 percent equity interest in Harvest Holding in two closings for an aggregate cash purchase price of $400.0 million.  The first closing occurred on December 16, 2013 when we sold a 29 percent equity interest in Harvest Holding for $125.0 million.  As a result of the first sale, we own 51 percent of Harvest Holding beginning December 16, 2013 and the non-controlling interest owners hold the remaining 49 percent.

The Company was not able to obtain approval from the government of Venezuela during 2014, which was required to complete the second closing for our remaining 51 percent interest in Petrodelta and on January 1, 2015 we terminated the SPA.   Due to our failed sales attempts, lack of management influence, and actions and inactions by the majority owner, PDVSA, we believe we no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.  Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.  

We performed an impairment analysis of the carrying value of our investment of Petrodelta as of December 31, 2014.  The estimated fair value of our investment was determined based on the estimated fair value of Petrodelta’s oil and natural gas properties and other net assets as of December 31, 2014, discounted by a factor for economic instability, foreign currency risks and lack of marketability.  Based on this analysis, we recorded a pre-tax impairment charge against the carrying value of our investment in Petrodelta of $355.7 million as of December 31, 2014. 

We also performed an impairment analysis of the carrying value of our investment of Petrodelta as of December 31, 2015 due to the continued decline in world oil prices and deteriorating economic conditions in Venezuela which have significantly impacted Petrodelta’s operations.  During 2015, Petrodelta’s operating costs exceeded the price realized from the sale of its production due to the significant rate of inflation in Venezuela and the restrictive foreign currency exchange system which Petrodelta is required to operate under.  While we believe that our relationship with CT Energy may allow us to restructure our relationship with PDVSA and Petrodelta and allow us to access the alternative foreign currency systems to companies in Venezuela, there can be no assurances that we will be successful in these negotiations.  Based on the existing economic environment in which Petrodelta is required to operate, we have concluded that the estimated fair value of our investment in Petrodelta is nil and have recorded a pre-tax impairment charge of $164.7 million to fully impair our investment in Petrodelta as of December 31, 2015. The estimated fair value of our investment was determined based on the estimated fair value of Petrodelta’s oil and natural gas properties and other net liabilities as of December 31, 2015 which exceeded the estimated fair value of the oil and natural gas properties.

The model used in the valuation of Petrodelta was based on an income approach which considered three scenarios relating to the future development of proved, probable and possible reserves and its other net liabilities at December 31, 2015.  The three scenarios considered that Petrodelta would have varying degrees of access to foreign exchange regimes as well as our ability to participate in and influence its operations to improve operational performance and efficiencies.  Each scenario also considered three price forecasts for crude oil.  The weighted average cost of capital of 26.5% was used to discount the future cash flows from these scenarios.  The expected value obtained from the income approach less net liabilities at December 31, 2015 resulted in a full impairment of the carrying value of our investment in Petrodelta.

In addition to the impairment charge, we recorded an allowance of $12.2 million to fully reserve the dividend receivable due from Petrodelta relating to the dividend declared in 2011 during the year ended December 31, 2014.

Petrodelta’s financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”) which we have adjusted to conform to U.S. GAAP for the years ending December 31, 2014 and 2013. The year ended December 31, 2015 is excluded due to the change to the cost method of accounting.  The differences between IFRS and U.S. GAAP for which we adjusted are:

· Deferred income tax: IFRS allows the inclusion of non-monetary temporary differences impacted by inflationary adjustments, whereas U.S. GAAP does not. In addition, we have adjusted for the impact on deferred income tax of other adjustments to arrive at net income under U.S. GAAP.

· Depletion expense: Oil and natural gas reserves used by Petrodelta in calculating depletion expense under IFRS are provided by Ministry of the People’s Power for Petroleum and Mining (“MENPET”). MENPET reserves are not prepared using the guidance on extractive activities for oil and natural gas (ASC 932). Annually at year-end, we prepare reserve reports for Petrodelta’s oil and natural gas reserves using ASC 932. On a quarterly basis, we recalculate Petrodelta’s depletion using the most recent reserve report using ASC 932 adjusted as appropriate.

· Under U.S. GAAP abandoned well costs are capitalized and depleted using the guidance on extractive activities for oil and natural gas under Successful Efforts accounting.  To conform to U.S. GAAP we reclassified $13.9 million in abandoned wells costs expensed to lease operating costs to depletable costs as per ASC 932.

· Windfall Profits Tax Credit: The April 2011 Windfall Profits Tax law 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 from MENPET a Windfall Profits Tax exemption credit under provisions in the April 2011 Windfall Profits Tax law. The exemption was applied to several oil development projects, including Petrodelta. However, MENPET has not defined the projects qualifying for exemption or provided the guidance necessary to calculate the exemption. PDVSA issued to Petrodelta its estimated share of the exemption credit related to 2012 of $55.2 million ($36.4 million net of tax) based on PDVSA’s calculation and projects PDVSA deemed to qualify for the exemption. In July 2014, Petrodelta received confirmation that MENPET had denied PDVSA’s application for the exemption, and Petrodelta reversed its estimated share of the credit.  We determined that until MENPET either issues guidance on the exemption provisions in the 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 would exclude the exemption credit from our equity earnings in Petrodelta under U.S. GAAP.  In March 2013, we included an adjustment for the differences between IFRS and U.S. GAAP which reversed Petrodelta’s accrual for the Windfall Profits Tax credit, and in June 2014 we recorded an adjustment to Petrodelta’s reversal of the Windfall Profits Tax credit.

· Petrodelta’s revenues are not subject to a value-added tax (“VAT”).  However, most of their purchases are subject to VAT.  The result is that Petrodelta has $153.7 million of VAT receivables or VAT credits.   Petrodelta has recorded a corresponding valuation allowance of $38.2 million against these VAT credits.  At December 2014, the valuation allowance of the VAT credits was adjusted for our U.S. GAAP presentation.  Under U.S. GAAP, sufficient evidence did not exist to support Petrodelta’s assumptions of recoverability at December 31, 2014.  Therefore, for U.S. GAAP purposes the estimated recoverability of the VAT credits wasextended to 5 years and the discount rate was increased to 24.0%.  The discount rate approximates the December 31, 2014 yield on the 20-year Venezuelan 9 ¾ % bond.  The resulting value of the VAT credits, net of Petrodelta’s valuation allowance and U.S. GAAP adjustment, is $64.1 million at December 31, 2014.

· Sports Law Overaccrual: The Organic Law on Sports, Physical Activity and Physical Education (“Sports Law”) was published in the Official Gazette on August 24, 2011. The purpose of the Sports Law is to establish the public service nature of physical education and the promotion, organization and administration of sports and physical activity. Funding of the Sports Law is by contributions made by companies or other public or private organizations that perform economic activities for profit in Venezuela. The contribution is one percent of annual net or accounting profit and is not deductible for income tax purposes. Per the Sports Law, contributions are to be calculated on an after-tax basis. However, in March 2012, CVP has instructed Petrodelta to calculate the contribution on a before-tax basis contrary to the Sports Law. In addition to the adjustments to arrive at Petrodelta’s net income under U.S. GAAP, earnings from  affiliate also reflect the amortization of the excess basis in affiliate using the unit-of-production method based on risk adjusted total current estimated reserves.

All amounts through Net Income under U.S. GAAP represent 100 percent of Petrodelta. Summary financial information is presented for the years ended December 31, 2014 and 2013 and the financial position is presented at December 31, 2014.

	Year Ended December 31,
	2014			2013
Results under IFRS:	(in thousands, except percentages)
Revenues:
Oil sales	$	1,343,452		$	1,326,093
Natural gas sales		4,590			4,000
Royalty		(437,281)			(440,963)
		910,761			889,130
Expenses:
Operating expenses		303,409			141,627
Workovers		28,239			29,168
Depletion, depreciation and amortization		129,409			87,203
General and administrative		45,623			37,778
Windfall profits tax		140,816			234,453
Windfall profits (credit) and reversal of credit		55,168			(55,168)
		702,664			475,061
Income from operations		208,097			414,069
Gain (loss) on exchange rate		(260)			169,582
Investment earnings and other		7,752			1,414
Interest expense		137			(21,728)
Income before income tax		215,726			563,337
Current income tax expense		103,619			325,217
Deferred income tax expense (benefit)		(32,617)			(17,662)
Net income under IFRS		144,724			255,782
Adjustments to increase (decrease) net income under IFRS:
Deferred income tax (expense) benefit		(2,841)			9,080
Depletion expense		(12,437)			(20,353)
Adjustment to lease operating costs to conform with GAAP		13,888			—
Windfall profits credit and (reversal) of credit		55,168			(55,168)
Adjust fair value of value added tax credits		(51,393)			—
Sports law over accrual		1,322			1,313
Net income under U.S. GAAP		148,431			190,654
Interest in investment affiliate		40	%		40	%
Income before amortization of excess basis in investment in affiliate		59,372			76,262
Amortization of excess basis in investment in affiliate		(4,428)			(3,684)
Earnings from investment affiliate excluded from results of operations		(19,995)			—
Earnings from investment affiliate included Harvest's income	$	34,949		$	72,578

	As of December 31,
	2014
	(in thousands)
Financial Position under IFRS:
Current assets	$	1,459,676
Property and equipment		1,044,797
Other assets		241,478
Current liabilities		1,437,929
Other liabilities		147,242
Net equity		1,160,780

Conversion Contract

On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract was published in the Official Gazette. Petrodelta is governed by its own charter and bylaws and will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from that date. Petrodelta operates a portfolio of properties in eastern Venezuela including large proven oil fields as well as properties with substantial opportunities for both development and exploration. Petrodelta is to undertake its operations in accordance with Petrodelta’s business plan as set forth in its conversion contract. Under its conversion contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta.

Sales Contract

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

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

Since the Sales Contract provides for only one crude pricing formula, the Sales Contract had to be amended to include the Boscan pricing formula to allow Petrodelta to invoice PPSA for El Salto crude oil deliveries. Petrodelta received a draft amendment to the Sales Contract from PDVSA Trade and Supply. The pricing formula in the draft amendment has been used to accrue revenue for El Salto field deliveries from October 1, 2011 through December 31, 2014.  Except for the inclusion of the Boscan pricing formula to be used in invoicing El Salto crude oil deliveries, all other terms and conditions of the Sales Contract remain in force. On January 31, 2013, Petrodelta’s board of directors endorsed the amendment to the Sales Contract. The amendment has been approved by CVP’s board of directors. HNR Finance, as shareholder, has agreed to the contract amendment. During 2015, Petrodelta completed billing PPSA for invoices for deliveries through December 2014.

CVP’s board of directors reviewed the amendment on April 30, 2013. A certificate of CVP’s final board resolution approving the amendment dated April 30, 2013 was received by Petrodelta on May 23, 2013. The remaining steps for the contract amendment are to (1) inform MENPET of the approval, (2) receive approval from Petrodelta’s shareholders to amend the Sales Contract including the Boscan formula, and (3) sign the contract amendment with PDVSA Trade and Supply.  As of December 31, 2014 revenues of $1,207.2 million ($756.7 million as of December 31, 2013) for El Salto remained uninvoiced to PPSA pending execution of the amendment. The amendment was signed in November 2014 and during January and February of 2015, Petrodelta completed billing PPSA for deliveries through November 2014. This invoicing resulted in an additional $98.6 million in revenue being recognized in the fourth quarter of 2014 due to a pricing change in the formula included in the sales contract.

Payments to Contractors

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

Harvest Vinccler has advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, operations, seismic interpretation, and employee salaries and related benefits for Harvest Vinccler employees seconded into Petrodelta. Currently, we have three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. Harvest Vinccler is considered a contractor to Petrodelta, and as such, Harvest Vinccler is also experiencing the slow payment of invoices. Petrodelta and Petrodelta’s board have not indicated that the advances are not payable, or that they will not be paid. We fully reserved the outstanding receivables of $1.6 million related to these advances as of December 31, 2014, which was reflected in Harvest’s general and administrative costs.

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. The amended Windfall Profits Tax establishes new levels for contribution of extraordinary and exorbitant prices to the Venezuelan government. Extraordinary prices are considered to be above $60 and equal to or lower than $80 per barrel, and exorbitant prices are considered to be over $80 per barrel.

Functional Currency

Petrodelta’s functional and reporting currency is the USD. PPSA is obligated to make payment to Petrodelta in USD in the case of payment for crude oil and in Bolivars for natural gas liquids delivered. In addition, major contracts for capital expenditures and lease operating expenditures are denominated in USD. Any dividend paid by Petrodelta will be made in USD.

Petrodelta has currency exchange risk from fluctuations of the official prevailing exchange rate that applies to their operating costs denominated in 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. The Venezuelan government modified the currency exchange system whereby the official exchange rate of 6.3 Bolivars per USD would only apply to certain economic sectors related to purchases of “essential goods and services” while other sectors of the economy would be subject to a new exchange rate, SICAD I, determined by an auction process conducted by Venezuela's Complimentary System of Foreign Currency Administration. Participation in the SICAD I mechanism is controlled by the Venezuelan government and is limited to certain companies that operate in designated economic sectors.  In March 2014, an additional currency exchange mechanism was established by the Venezuelan government that allows companies within other economic sectors to participate in an additional auction process (“SICAD II”).  The exchange rate averaged  approximately 50 Bolivars per USD for the re-measurement of our Bolivar denominated assets and liabilities and revenue and expenses.  The financial information is prepared using the official fixed exchange rate (6.3 from February 2013 through December 2014). On February 10, 2015, the Ministry of Economy, Finance, and Public Banking, and the Central Bank of Venezuela (BCV) published in the Extraordinary Official Gazette No.6.171 Exchange Agreement No.33 with two Official Notices.  The first notice being that the SICAD II exchange rate would be no longer permitted.  Secondly, a new exchange rate called the Foreign Exchange Marginal System (“SIMADI”) has been created.  The SIMADI rate published on December 31, 2015 is 198.70 Bolivars per USD. The SIMADI’s marginal system is available in limited quantities for individuals and companies to purchase and sell foreign currency via banks and exchange houses.  Currently the SIMADI marginal system is the only mechanism available to Harvest Vinccler. 

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 USD 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 were signed. The Collective Labor Agreement established a salary raise and payroll and retirement benefits which had a significant impact on Petrodelta’s payroll cost. The most significant impact was a steep increase of salary around 90%, with 59% retroactive from October 1, 2013, a 23% raise in effect from May 1, 2014 and finally the remaining portion 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.  During the year ended December 31, 2014, we recorded an allowance of $12.2 million, which is reflected in Harvest’s general and administrative costs, to fully reserve the dividend due from Petrodelta.  This dividend has not been received as of December 31, 2015.

XML

Venezuela – Other

12 Months Ended

Dec. 31, 2015

Venezuela - Other [Abstract]

Venezuela - Other

Note 7 – Venezuela – Other

Harvest Vinccler currently assists us in the oversight of our investment in Petrodelta and in negotiations with PDVSA. Harvest Vinccler’s functional and reporting currency is the USD. They do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”)

In January 2014, the Venezuelan government modified the currency exchange system whereby the official exchange rate of 6.3 Bolivars per USD would only apply to certain economic sectors related to purchases of “essential goods and services” while other sectors of the economy would be subject to a new exchange rate, SICAD I, determined by an auction process conducted by Venezuela's Complimentary System of Foreign Currency Administration. Participation in the SICAD I mechanism is controlled by the Venezuelan government and is limited to certain companies that operate in designated economic sectors.

In March 2014, an additional currency exchange mechanism was established by the Venezuelan government that allows companies within other economic sectors to participate in an additional auction process (“SICAD II”).

On February 10, 2015, the Ministry of Economy, Finance, and Public Banking, and the Central Bank of Venezuela (BCV) published in the Extraordinary Official Gazette No.6.171 Exchange Agreement No.33 with two Official Notices.  The first notice being that the SICAD II exchange rate would be no longer permitted.  Secondly, a new exchange rate called the Foreign Exchange Marginal System (“SIMADI”) has been created.  The SIMADI rate published on December 31, 2015 is 198.70 Bolivars per USD. The SIMADI’s marginal system is available in limited quantities for individuals and companies to purchase and sell foreign currency via banks and exchange houses.  Currently the SIMADI marginal system is the only mechanism available to Harvest Vinccler.

We have determined that Harvest Vinccler is not eligible to apply for exchanges at the official rate. We are eligible and have successfully participated in the SIMADI during 2015 and as a result we have adopted the SIMADI exchange rate of approximately 200 Bolivars per USD for the re-measurement of our Bolivar denominated assets and liabilities and revenue and expenses, as we believe the SIMADI rate is most representative of the economics in which Harvest Vinccler operates. Prior to this change, we were using the SICAD II rate of 50 Bolivars per USD.

During the year ended December 31, 2015, Harvest Vinccler exchanged approximately $0.1 million ($0.4 million during the year ended December 31, 2014) and received an average exchange rate of 212.4 Bolivars (34.4 Bolivars during the year ended December 31, 2014) per U.S. Dollar.  A gain on foreign currency transactions of $0.3 million was recognized during the year ended December 31, 2015 associated with participating in the SIMADI marginal system.  A loss on foreign currency transactions of $0.1 million was recognized during the year ended December 13, 2014 associated with participating in the SICAD II auction process.

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 6.3 Bolivar exchange rate. At December 31, 2015, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 11.9 million Bolivars ($0.06 million)  and 5.5 million Bolivars ($0.03 million), respectively.

XML

Gabon

12 Months Ended

Dec. 31, 2015

Gabon [Abstract]

Gabon

Note 8 – Gabon

We are the operator of the Dussafu PSC with a 66.667 percent ownership interest. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC covers an area of 680,000 acres with water depths up to 1,650 feet.

The Dussafu PSC partners and the Republic of 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 Ministry of Mines, Energy, Petroleum and Hydraulic Resources agreed to lengthen the third exploration phase to four years until May 27, 2016.  The Company is currently assessing extension possibilities for the exploration phase.

During 2011, we drilled our first exploratory well, Dussafu Ruche Marin-1 (“DRM-1”), and two appraisal sidetracks.DRM-1 and the sidetracks are currently suspended pending further exploration and development activities.

Well planning progressed during 2012 to drill an exploration well in the fourth quarter of 2012 on the Tortue prospect. DTM-1 well was spud November 19, 2012. DTM-1 was drilled with the Scarabeo 3 semi-submersible drilling unit. On January 4, 2013, we announced that DTM-1 had reached the Dental Formation and discovered oil in both the Gamba and Dentale formations. The first appraisal sidetrack of DTM-1 (“DTM-1ST1”) was spud in January 12, 2013. DTM-1ST1 was drilled in the Dentale Formation. Due to a stuck downhole tool, logging operations were terminated before pressure data could be collected to confirm connectivity. The downhole tool was retrieved and the DTM-1 well suspended for future re-entry.

Operational activities during 2014 included additional evaluation of development alternatives, preparation and a formal remittance of a field development plan along with continued processing of 3D seismic acquired in 2013.  On March 26, 2014, the joint venture partners approved a resolution that the discovered fields are commercial to exploit.  On June 4, 2014, a Declaration of Commerciality (“DOC”) was signed with Gabon pertaining to the four discoveries on the Dussafu Project offshore Gabon.  Furthermore, on July 17, 2014, the Direction Generale Des Hydrocarbures (“DGH”) awarded an Exclusive Exploitation Authorization (“EEA”) for the development and exploitation of certain oil discoveries on the Dussafu Project and on October 10, 2014, the field development plan was approved. The Company has four years from the date of the EEA approval to begin production.

The Company is currently assessing alternatives to farm-down or sell the Dussafu Project, while weighing the liquidity requirements necessary to maintain ongoing Company operations.

Operational activities during the year ended December 31, 2015, included continued evaluation of development plans, based on the 3D seismic data acquired in late 2013 and processed during 2014. 

In December 2014, the Company recorded a $50.3 million impairment related to the unproved costs of the Dussafu PSC based on a qualitative analysis which considered our current liquidity needs, our inability to attract additional capital and the decrease in oil and natural gas prices.  In December 2015, the Company reassessed the carrying value of the unproved costs related to the Dussafu PSC and recorded an additional impairment of $23.2 million based on its analysis of the value of the unproved costs which considered the value of the contingent and exploration resources and the ability of the Company to develop the project given its current liquidity situation and the depressed price of crude oil.  If oil and natural gas prices continue to deteriorate or we fail to obtain adequate financing, farm-down or sell the asset, additional impairments may be required on our prospect.

In the impairment analysis in December 2015, the Company prepared a quantitative and qualitative assessment of the unproved property which estimated the value of the estimated contingent and exploration resources based on the Company’s ability to develop the project given its current liquidity situation and the depressed price of crude oil.  The valuation model developed used three price scenarios and a development decision tree model which estimated the value of three development options available to the Company.  The value of the development options was determined using outputs from a Monte Carlo simulation model which estimated the net present value of expected future cash flow to be generated from the development of the contingent and exploratory resources in the Dussafu PSC and discounted using a weighted average cost of capital of 21.5%.  The development options considered the probability that the Company would be: a) able to farm-down 50% of their working interest; b) able to sell their working interest; and c) unable to complete either of the first 2 options. All inputs used in the valuation process were primarily level 3 in the fair value hierarchy. The concluded fair value of the unproved property costs in our Dussafu project was $28.0 million.

We also reviewed the value of our oilfield inventories that are in the country of Gabon, of which the majority is steel conductor and casing.  We impaired the value of this inventory by approximately $1.0 million in 2015, leaving $3.0 million related to this inventory as of December 31, 2015.

See Note 13 – Commitments and Contingencies for a discussion related to our Gabon operations.

XML

Indonesia

12 Months Ended

Dec. 31, 2015

Indonesia [Abstract]

Indonesia

Note 9 – Indonesia

We fully impaired our investment in the Budong Production Sharing Contract (“Budong PSC”) in Indonesia as of March 31, 2014.  In June 2014, Harvest and our partner adopted a resolution to terminate the Budong PSC.  Harvest advised the Indonesian government of this decision and submitted a request to terminate the Budong PSC.   On February 5, 2015, the Company entered into a Share Purchase Agreement to transfer shares of Harvest Budong-Budong B.V. to Stockbridge Capital Limited for a nominal amount.  On February 17, 2015, a withdrawal request of the earlier termination request was made to the Indonesian government and the withdrawal request was accepted on April 15, 2015.  The transfer of shares to Stockbridge Capital Limited was completed on May 4, 2015.

XML

Notes Payable to Noncontrolling Interest Owners

12 Months Ended

Dec. 31, 2015

Notes Payable to Noncontrolling Interest Owners [Abstract]

Notes Payable to Noncontrolling Interest Owners

Note 10 – Notes Payable to Noncontrolling Interest Owners

At December 31, 2014, HNR Energia had a note payable to Vinccler of $6.1 million. Principal and interest were payable upon the maturity date of December 31, 2015.  On March 6, 2015, Vinccler forgave the note payable and accrued interest of $6.2 million.  This was reflected as a contribution to stockholders’ equity.

On August 28, 2014 Petroandina exercised its right to a one month extension of the termination date of the SPA.  In accordance with the extension the Company had the option to borrow $2.0 million from Petroandina, which it exercised.  Petroandina again extended the SPA on September 29, and October 30, 2014, with the Company borrowing $2.0 million per extension.  On November 27, 2014, Petroandina exercised their final extension and the Company borrowed the final maximum amount allowed of $1.6 million.  Quarterly interest payments began on December 31, 2014 with the principal due January 1, 2016.  The note payable with Petroandina as of December 31, 2014 was $7.6 million.  Interest accrued at a rate of 11.0%.  We were in default of the loan agreement with Petroandina for not making the April 1, 2015 interest payment.  After default the interest rate increased from 11.0% to 13.0%.  On June 23, 2015, the Company repaid the note payable of $7.6 million plus accrued interest of $0.4 million.

XML

Debt and Financing

12 Months Ended

Dec. 31, 2015

Debt and Financing [Abstract]

Debt and Financing

Note 11 – Debt and Financing

On June 19, 2015, we issued the CT Warrant, 9% and 15% Notes, the Additional Draw Note and Series C preferred stock in connection with the Purchase Agreement with CT Energy and received proceeds of $30.6 million, net of financing fees of $1.6 million.  We identified embedded derivative assets and derivative liabilities in the notes and determined that the CT Warrant did not meet the required conditions to qualify for equity classification and was required to be classified as a warrant liability (see Note 12 – Warrant Derivative Liability).  The estimated fair value, at issuance, of the embedded derivative asset was $2.5 million, the embedded derivative liability was $13.5 million and the warrant liability was $40.0 million.  In accordance with ASC 815, the proceeds were first allocated to the fair value of the embedded derivatives and warrants, which resulted in no value being attributable to the Series C preferred stock and the 9% and 15% Notes. As a result of the allocation, we recognized a loss on the issuance of these securities of $20.4 million in our consolidated statements of operations and comprehensive loss during the year end December 31, 2015.

The following table summarizes the movement of our long-term debt due to related party net of discount:

	As of December 31,
Long-Term Debt	2015
	(in thousands)
Beginning balance	$	—
Proceeds from 9% and 15% Notes to CT Energy		32,200
Proceeds from note payable to CT Energy		1,300
Repayment of note payable to CT Energy		(1,300)
Value assigned to embedded derivatives		(32,200)
Conversion of 9% Note, net of unamortized discount		(11)
Accretion of discount on debt		225
	$	214

The face value of the 15% and 9% Noteswere recorded net of the discount related to the value allocated to the embedded derivatives and warrant.  The unamortized discount of the 15% Note was $25.0 million at December 31, 2015. The Company will accrete the discount over the life of the note using the interest method.Total interest expense associated with this note was $2.2 million, comprised of $2.0 million related to the stated rate of interest on the note and $0.2 million related to the accretion of the discount on the debt.  The effective interest rate on the note is approximately 141%.  The fair value of the 15% Note at December 31, 2015 was $8.8 million.

15% Non-Convertible Senior Secured Note due June 19, 2020

On June 19, 2015, in connection with the transaction with CT Energy described in Note 1 – Organization, we issued the five-year, 15% Note in the aggregate principal amount of $25.2 million with interest that is compounded quarterly at a rate of 15% per annum and is payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2015.  If by June 19, 2016, the volume weighted average price of the Company’s common stock over any consecutive 30-day period has not equaled or exceeded $2.50 per share, the maturity date of the 15% Note will be extended by two years and the interest rates on the 15% Note will adjust to 8.0% (the “15% Note Reset Feature”).  During an event of default, the outstanding principal amount bears additional interest at a rate of 2.0% per annum higher than the rate otherwise applicable.

The Company may prepay all or a portion of the note at a prepayment price equal to a make-whole price, as of the prepayment date, with respect to the principal amount of the note being prepaid, plus accrued and unpaid interest.  The make-whole price is defined as the greater of (i) 100% of such outstanding principal amount of the 15% Note and (ii)  the sum of the present values as of such date of determination of (A) such outstanding principal amount of the 15% Note, assumed, for the purpose of determining the present value thereof, to be paid on the earlier of the stated maturity of this 15% Note or the date that is two years after the date of determination, and (B) all remaining payments of interest (excluding interest accrued to the prepayment date) scheduled to become due and payable after the date of determination and on or before the date that is two years after the date of determination with respect to such outstanding principal amount of the 15% Note, in the case of each of the foregoing clauses (ii)(A) and (B), computed using a discount rate equal to the Treasury Rate as of the date of determination plus 50 basis points.

If an event of default occurs (other than an event of default related to certain bankruptcy events), holders of at least 25% of the outstanding principal of the 15% Note may declare the principal, premium, if any, and accrued and unpaid interest of such notes immediately due and payable.  If an event of default related to specified bankruptcy events occurs, an amount equal to the make-whole price for the 15% Note plus accrued and unpaid interest is immediately due and payable. 

We have evaluated the 15% Note Reset Feature related to the interest rate and maturity date using “ASC 815 Derivatives and Hedging”.  Because the interest rate and maturity date reset are linked to achievement of a certain stock price, the feature is not considered clearly and closely related to the debt host. In addition, the interest rate at the reset date is not tied to any approximation of the expected market rate at the date of the term extension as required by ASC 815.  As a result, we are accounting for the 15% Note Reset Feature as an embedded derivative asset that has been measured at fair value with current changes in fair value reflected in our consolidated statements of operations and comprehensive loss.

The embedded 15% Note Reset Feature in the 15% Note was valued using the ‘with’ and ‘without’ method.  A Black-Derman-Toy (“BDT”) Model, which is a binomial interest rate lattice model, was used to value the 15% Note and the incremental value attributed to the embedded option was determined based on a comparison of the value of the 15% Note with the feature included and without the feature included.  Key inputs into this valuation model are our current stock price, U.S. Treasury rate, our credit spread and the underlying yield volatility.  As part of our overall valuation process, management employs processes to evaluate and validate the methodologies, techniques and inputs, including review and approval of valuation judgments, methods, models, process controls, and results. These processes are designed to help ensure that the fair value measurements and disclosures are appropriate, consistently applied, and reliable. We estimate the yield volatility for the 15% Note based on historical daily volatility of the USD denominated Venezuela Sovereign zero coupon yield over a look back period of 6.0 years.  The risk-free interest rate is based on the U.S. Treasury yield curve as of the valuation dates for a maturity similar to the expected remaining life of the 15% Note. The credit spread was estimated based on the option adjusted spread (“OAS”) of the Venezuelan yield over the USD Treasury yield and the implied OAS for the transaction as of the date the term sheet was signed to capture the investor’s assessment of the risk in their investment in the Company.  This model requires Level 3 inputs (see Note 3 – Summary of Significant Accounting Policies, Financial Instruments and Fair Value Measurements) which were based on our estimates of the probability and timing of potential future financings and fundamental transactions.

The assumptions summarized in the following table were used to calculate the fair value of the derivative asset associated with the 15% Note at the date of issuance:

	Fair Value
	Hierarchy
	Level	June 19, 2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	1.82
Weighted Term (years)			5.0
Yield Volatility	Level 2 input		32.5	%
Risk-free rate	Level 1 input		1.6% to 2.0	%
Dividend yield	Level 2 input		0.0	%
Scenario probability:
Claim date extended with Stock Appreciation Date threshold met	Level 3 input		60.0	%
Claim date extended with Stock Appreciation Date threshold not met	Level 3 input		42.5	%
Claim date not extended with Stock Appreciation Date threshold met	Level 3 input		60.0	%
Claim date not extended with Stock Appreciation Date threshold not met	Level 3 input		40.2	%
Scenario probability (future draws/no future draws)	Level 3 input		50%/50	%

The embedded derivative asset related to the 15% Note contains a Level 3 input related to the probability of our investor lending us additional funds or not lending us funds according to the terms of the loan agreement for the additional draws.  We have assumed a 50/50 scenario of the draw or no draw for valuation of the embedded derivative.  Changes in this assumption have minimal impacts on the embedded derivative asset valuation as HNR stock price is the primary driver of the value. 

The assumptions summarized in the following table were used to calculate the fair value of the derivative asset associated with the 15% Note that was outstanding as of December 31, 2015 on our consolidated balance sheet:

	Fair Value
	Hierarchy	As of December 31,
	Level	2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	0.43
Weighted Term (years)			4.47
Yield Volatility	Level 2 input		35	%
Risk-free rate	Level 1 input		1.6% to 2.0	%
Dividend yield	Level 2 input		0.0	%
Scenario probability:
Claim date extended with Stock Appreciation Date threshold met	Level 3 input		54.8	%
Claim date extended with Stock Appreciation Date threshold not met	Level 3 input		36.1	%
Claim date not extended with Stock Appreciation Date threshold met	Level 3 input		54.8	%
Claim date not extended with Stock Appreciation Date threshold not met	Level 3 input		33.4	%
Scenario probability (future draws/no future draws)	Level 3 input		50%/50	%

The fair value of the embedded derivative asset was $2.5 million at issuance and $5.0 million as of December 31, 2015.  We recognized $2.5 million in income related to the change in fair value of this embedded derivative asset in change in fair value of derivative assets and liabilities in our consolidated statement of operations for the year ended December 31, 2015. 

15% Non-Convertible Senior Secured Additional Draw Note

On June 19, 2015, in connection with the transaction with CT Energy described in Note 1 – Organization, the Company also issued the Additional Draw Note which, under certain circumstances, CT Energy may elect to provide $2.0 million of additional funds to the Company per month for up to six months following the one-year anniversary of the closing date of the transaction (up to $12.0 million in aggregate).  If funds are loaned under the Additional Draw Note, interest will be compounded quarterly at a rate of 15.0% per annum and will be payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2016.  If by the Claim Date, the volume weighted average price of the Company’s common stock over any consecutive 30-day period has not equaled or exceeded $2.50 per share, the maturity date of the Additional Draw Note will be extended by two years and the interest rate on the Additional Draw Note will adjust to 8.0%. During an event of default, the outstanding principal amount will bear additional interest at a rate of 2.0% per annum higher than the rate otherwise applicable.

The Company may prepay all or a portion of the Additional Draw Note at a prepayment price equal to the make-whole price, as of the prepayment date, with respect to the principal amount of the Additional Draw Note being prepaid, plus accrued and unpaid interest. The make-whole price with respect to the Additional Draw Note has the same meaning described above with respect to the 15% Note under.

If an event of default occurs (other than an event of default related to certain bankruptcy events), holders of at least 25% of the outstanding principal of the 15% Note (including the Additional Draw Note, if outstanding) may declare the principal, premium, if any, and accrued and unpaid interest of such notes immediately due and payable.  If an event of default related to specified bankruptcy events occurs, an amount equal to the make-whole price for the Additional Draw Note plus accrued and unpaid interest is immediately due and payable.  

Because we have not withdrawn any proceeds on this note at issuance and at December 31, 2015, we have assigned no value to the Additional Draw Note, as it does not meet the definition of a derivative in ASC 815 and there is no principal amount outstanding.

9% Convertible Senior Secured Note due June 19, 2020

On June 19, 2015, in connection with the transaction with CT Energy described in Note 1 – Organization we issued the five-year, 9% Note in the aggregate principal amount of $7.0 million, which was immediately convertible into 8,506,098 shares of the Company’s common stock, par value $0.01 per share, at an initial conversion price of $0.82 per share (“Beneficial Conversion Feature”).

Interest on the 9% Note was compounded quarterly at a rate of 9.0% per annum and was payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2015.  If by June 19, 2016, the volume weighted average price of the Company’s common stock over any consecutive 30-day period had not equaled or exceeded $2.50 per share, the maturity date of the 9% Note will be extended by two years and the interest rates on the 9% Note will adjust to 8.0% (the “9% Note Reset Feature”). 

Regarding the 9% Note Reset Feature, because the interest rate and maturity date reset were linked to achievement of a certain stock price, the feature was not considered clearly and closely related to the debt host. In addition, the interest rate at the reset date was not tied to any approximation of the expected market rate at the date of the term extension as required by ASC 815.  As a result, we accounted for the 9% Note Reset Feature as an embedded derivative asset that was measured at fair value with current changes in fair value reflected in change of fair value of derivative assets and liabilities in our consolidated statements of operations and comprehensive loss.  The changes in the fair value of this embedded derivative asset was netted against the changes in the fair value of the embedded derivative liabilities relating to the 9% Down-Round Provision and Note Reset Feature discussed below.

The conversion price was subject to adjustment upon the occurrence of certain events, including a stock issuance, dividend, or stock split.   If the Company completes an issuance of common stock at a price less than the current conversion price, then the conversion price will be fully reduced to the new issuance price for such below-price issuance (the “9% Down-Round Provision”).  This is a full ratchet down round provision that could compensate the holder for an amount greater than dilution related to a stock issuance.  For example, in the event of an issuance of stock causing a 10% dilution, the note holder could theoretically be compensated greater than 10% under certain circumstances. 

The embedded 9% Down-Round Provision and the 9% Note Reset Feature were valued using the ‘with’ and ‘without’ method.  A Binomial Lattice Model was used to value the 9% Note and the incremental value attributed to the embedded options was determined based on a comparison of the value of the 9% Note with the features included and without the features included.  Key inputs into this valuation model were our current stock price, U.S. Treasury rate, our credit spread and the underlying stock price volatility.  As part of our overall valuation process, management employs processes to evaluate and validate the methodologies, techniques and inputs, including review and approval of valuation judgments, methods, models, process controls, and results. These processes are designed to help ensure that the fair value measurements and disclosures are appropriate, consistently applied, and reliable. We estimated the volatility of our common stock based on historical volatility that matches the expected remaining life of the longest instrument in the transaction, seven years. The risk-free interest rate was based on the U.S. Treasury yield curve as of the valuation dates for a maturity similar to the expected remaining life of the 9% Note.  The credit spread was estimated based on the option adjusted spread (“OAS”) of the Venezuelan yield over the USD Treasury yield and the implied OAS for the transaction as of the date the term sheet was signed to capture the investor’s assessment of the risk in their investment in the Company.  This model requires Level 3 inputs (see Note 3 – Summary of Significant Accounting Policies, Financial Instruments and Fair Value Measurements) which were based on our estimates of the probability and timing of potential future draws.

We have evaluated the 9% Down-Round Provision and the 9% Note Reset Feature using ASC 815. The Convertible Down-Round Provision is not consistent with a fixed-price-for-fixed-number of shares instrument and therefore precludes the conversion option from being indexed to the Company’s own stock. As a result, the conversion option did not meet the scope exception in ASC 815 and was bifurcated as a separate liability that has been measured at fair value with current changes in fair value reflected in our consolidated statements of operations and comprehensive loss.

The fair value of the net embedded derivative liabilities was $13.5 million at issuance and $11.1 million immediately prior to the conversion of the 9% Note.  We recognized $2.3 million in income for the change in the fair value of this embedded derivative liabilities in our consolidated statement of operations for the year ended December 31, 2015.

On September 15, 2015, the 9% Note, the associated accrued interest and related derivative liabilities were converted into 8,667,597shares of the Company’s common stock.  The Company recognized a $1.9 million loss on debt conversion.   The $1.9 million loss on debt conversion was the result of the difference between the September 14, 2015 carrying value of the 9% Note, including accrued interest and unamortized debt discount ($0.2 million) and the fair value of therelated derivative liabilities ($11.1 million) less the fair value of the 8,667,597 shares issued upon conversion  ($13.2 million) at September 15, 2015.

The assumptions summarized in the following table were used to calculate the fair value of the net embedded derivative liability associated with the 9% Note at the date of issuance:

	Fair Value
	Hierarchy
	Level	June 19, 2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	1.82
Term (years)			5.0
Volatility	Level 2 input		90	%
Risk-free rate (base)	Level 1 input		0.27	%
Risk-free rate (5 year)	Level 1 input		2.05	%
Risk-free rate (7 year)	Level 1 input		2.40	%
Dividend yield	Level 2 input		0.0	%

XML

Warrant Derivative Liability

12 Months Ended

Dec. 31, 2015

Warrant Derivative Liability [Abstract]

Warrant Derivative Liability

Note 12 – Warrant Derivative Liability

CT Warrant

On June 19, 2015, in connection with the transaction with CT Energy described in Note 1 – Organization, we issued a warrant exercisable for 34,070,820 shares of the Company’s common stock at an initial exercise price of $1.25 per share.  The CT Warrant may not be exercised until the volume weighted average price of the Company’s common stock over any consecutive 30-day period equals or exceeds $2.50 per share.

The CT Warrant can be exercised at the option of the investor in cash or by effecting a reduction in the principal amount of the 15% Note (See Note 11 – Debt and Financing).  If the CT Warrant is exercised through the reduction in the principal amount of the 15% Note, the reduction will be equal to the amount obtained by multiplying the number of shares of common stock for which the CT Warrant is exercised by (i) the exercise price then in effect divided by (ii) (A) the defined make-whole price with respect to the outstanding principal amount of such 15% Note divided by (B) the outstanding principal amount of such 15% Note.  The exercise price of the CT Warrant is subject to adjustment upon the occurrence of certain events, including stock issuance, dividend or stock split.

In addition, the holder of the CT Warrant has certain registration rights regarding the CT Warrant and the shares of common stock issuable upon exercise of the CT Warrant.

We have analyzed the CT Warrant to determine whether it should be classified as a derivative liability or equity instrument.  Provisions of the CT Warrant agreement allow for a change in the exercise price of the CT Warrant upon the occurrence of certain corporate events.  These exercise price adjustments incorporate variables other than those used to determine the fair value of a fixed-for-fixed forward or option on equity shares therefore the CT Warrant is not considered to be “indexed to the issuer’s own stock” and does not meet the exception from derivative treatment in ASC 815.  HNR continues to account for the CT Warrant as a derivative which was marked to market as of December 31, 2015.  

Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument with related changes in internal and external market factors. In addition, option-based techniques (such as the Monte Carlo model) are highly volatile and sensitive to changes in the trading market price of our common stock. Since derivative financial instruments are initially and subsequently carried at fair value, our income will reflect the volatility in these estimate and assumption changes.  A Monte Carlo simulation model is used to value the CT Warrant to determine if the Stock Appreciation Date is achieved, which is based on the average stock price over a 30 day period (21 trading days) reaching $2.50.  This requires Level 3 inputs (see Note 3 – Summary of Significant Accounting Policies, Financial Instruments and Fair Value Measurements) which arefundamentally based on market data but require complex modeling.  The additional modeling is required in order to simulate future stock prices, to determine whether the Stock Appreciation Date is achieved and to model the projected exercise behavior of the warrant holders.  

The assumptions summarized in the following table were used to calculate the fair value of the warrant derivative liability at the date of issuance:

	Fair Value
	Hierarchy
	Level	June 19, 2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	1.82
Exercise price	Level 1 input	$	1.25
Stock appreciation date price (hurdle)	Level 1 input	$	2.50
Term (warrants)			3.0
Term (claim date)			1.0
Term (claim date extended)			1.5
Volatility	Level 2 input		90.0	%
Risk-free rate (warrants)	Level 1 input		1.09	%
Risk-free rate (claim date)	Level 1 input		0.27	%
Risk-free rate (claim date extended)	Level 1 input		0.48	%
Dividend yield	Level 2 input		0.0	%

The assumptions summarized in the following table were used to calculate the fair value of the warrant derivative liability that was outstanding as of the balance sheet date presented on our consolidated balance sheet:

	Fair Value
	Hierarchy	As of December 31,
	Level	2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	0.43
Exercise price	Level 1 input	$	1.25
Stock appreciation date price (hurdle)	Level 1 input	$	2.50
Term (warrants)			2.4668
Term (claim date)			0.4672
Term (claim date extended)			0.9672
Volatility	Level 2 input		110.0	%
Risk-free rate (warrants)	Level 1 input		1.27	%
Risk-free rate (claim date)	Level 1 input		0.55	%
Risk-free rate (claim date extended)	Level 1 input		0.70	%
Dividend yield	Level 2 input		0.0	%

Inherent in the Monte Carlo valuation model are assumptions related to expected stock price volatility, expected life, risk-free interest rate and dividend yield. As part of our overall valuation process, management employs processes to evaluate and validate the methodologies, techniques and inputs, including review and approval of valuation judgments, methods, models, process controls, and results. These processes are designed to help ensure that the fair value measurements and disclosures are appropriate, consistently applied, and reliable. We estimate the volatility of our common stock based on historical volatility that matches the expected remaining life of the longest instrument in the transaction, seven years. The risk-free interest rate is based on the U.S. Treasury yield curve as of the valuation dates for a maturity similar to the expected remaining life of the CT Warrant. The expected life of the CT Warrants is assumed to be equivalent to their remaining contractual term. The dividend rate is based on the historical rate, which we anticipate to remain at zero.

The fair value of the CT Warrant was $40.0 million at issuance and $5.5million as of December 31, 2015.  We recognized income of $34.5 million related to thechange in fair value of the warrant liability in our consolidated statement of operations and comprehensive loss for the year ended December 31, 2015.

MSD Warrants

On October 28, 2015, the warrants issued as inducements in connection with a $60 million term loan facility that was paid off in May 2011(“MSD Warrants”) expired (1,846,088 warrants outstanding: December 31, 2014).  The fair value of these warrants as of December 31, 2014 and at expiration was $0.00 per warrant.  The Warrant Purchase Agreement dated as of October 28, 2010 includes certain anti-dilution provisions which adjust the number of warrants and the exercise price per warrant.   The issuance of the CT Energy 9% Note, because of the initial conversion price and the CT Warrant of 34,070,820 shares triggered the anti-dilution provisions on the MSD Warrants which resulted in the issuance of 1,547,739 additional warrants during the year ended December 31, 2015.  In addition, the exercise price per share for all warrants was repriced to $6.97 per warrant during the year ended December 31, 2015.  The warrants had been classified as a liability on our consolidated balance sheets and marked to market.  The valuation for the warrants had based primarily on our stock price of $1.81 at December 31, 2014, their remaining life of 0.83 years and their strike price of $6.97 as of December 31, 2014.  We recognized $0.0 million in warrant liability income in our consolidated statement of operations and comprehensive loss year ended December 31, 2015 for these warrants ($2.0 million and $3.5 million for the years ended December 31, 2014 and 2013, respectively).  The assumptions summarized in the following table were used to calculate the fair value of the warrant derivative liability related to the MSD warrants that were outstanding at December 31, 2014:

	Fair Value
	Hierarchy	As of December 31,
	Level	2014
Significant assumptions (or ranges):
Stock price	Level 1 input	$	1.81
Term (years)			0.83
Volatility	Level 2 input		67	%
Risk-free rate	Level 1 input		0.21	%
Dividend yield	Level 2 input		0.0	%
Scenario probability (fundamental change event/debt raise/equity raise)	Level 3 input		0%/100%/0	%

XML

Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies [Abstract]

Commitments and Contingencies

Note 13 – Commitments and Contingencies

We have employment contracts with five executive officers which provide for annual base salaries, eligibility for bonus compensation and various benefits. The contracts provide for a lump sum payment as a multiple of base salary in the event of termination of employment without cause. In addition, these contracts provide for payments as a multiple of base salary and bonus, excise tax reimbursement, outplacement services and a continuation of benefits in the event of termination without cause following a change in control. By providing one year notice, these agreements may be terminated by either party on or before May 31, 2016.

We have various contractual commitments pertaining to leasehold, training, and development costs for the Dussafu PSC totaling $4.5 million. Under the EEA granted for the Dussafu PSC on July 17, 2014, we are required to commence production within four years of the date of grant in order to preserve our rights to production under the EEA.  We expect that significant capital expenditures will be required prior to commencement of production which is expected in 2016 under the approved field development plan. These work commitments are non-discretionary; however, we do have the ability to control the pace of expenditures.The table below consists of our contractual commitments for office space and various other commitments:

	Payments Due by Period
			Less than
	Total		1 Year		1 - 2 Years		3-4 Years		After 4 Years
	(in thousands)
Obligations:
Oil and  natural gas activities	$	4,520	$	1,130	$	1,130	$	1,130	$	1,130
Office leases		171		157		14		—		—
Total contractual obligations	$	4,691	$	1,287	$	1,144	$	1,130	$	1,130

Under the agreements with our partners in the Dussafu PSC and the Budong PSC, we are jointly and severally liable to various third parties. As of December 31, 2015, the gross carrying amount associated with obligations to third parties which were fixed at the end of the period was $0.3 million ($2.4 million as of December 31, 2014) and is related to accounts payable to vendors, accrued expenses and withholding taxes payable to taxing authorities. As we are the operators for the Dussafu PSC and Budong PSC, the gross carrying amount related to accounts payable and withholding taxes and the net amount related to other accrued expenses are reflected in the consolidated balance sheet in accounts payable and accrued expenses leaving $0.1 million in fixed obligations as of December 31, 2015  ($0.3 million as of December 31, 2014) attributable to our joint partners’ share which is not accrued in our balance sheet. Our partners have advanced $0.0 million ($0.5 million as of December 31, 2014) to satisfy their share of these obligations which was $0.1 million as of December 31, 2015  ($0.8 million as of December 31, 2014). As we expect our partners will continue to meet their obligations to fund their share of expenditures, we have not recognized any additional liability related to fixed joint interest obligations attributable to our joint interest partners.

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 alleged that the area belonged to the people of Taiwan and sought 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, and the WAB-21 area.  The Company filed a motion to dismiss the suit, which was granted by the district court in August 2014.  The plaintiffs appealed the dismissal.  The Fifth Circuit Court of Appeals heard oral arguments on June 3, 2015 and affirmed the district court’s dismissal on June 4, 2015.  The plaintiffs filed a petition for writ of certiorari with the Supreme Court of the United States. On October 13, 2015, the Supreme Court denied the petition.

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.  We are currently unable to estimate the amount or range of any possible loss.

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.  We are currently unable to estimate the amount or range of any possible loss.

On May 31, 2011, the United Kingdom branch of our subsidiary, Harvest Natural Resources, Inc. (UK), initiated a wire transfer of approximately $1.1 million ($0.7 million net to our 66.667 percent interest) intending to pay Libya Oil Gabon S.A. (“LOGSA”) for fuel that LOGSA supplied to our subsidiary in the Netherlands, Harvest Dussafu, B.V., for the company’s drilling operations in Gabon. On June 1, 2011, our bank notified us that it had been required to block the payment in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by OFAC, because the payee, LOGSA, may be a blocked party under the sanctions. The bank further advised us that it could not release the funds to the payee or return the funds to us unless we obtain authorization from OFAC. On October 26, 2011, we filed an application with OFAC for return of the blocked funds to us. 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. On April 23, 2014, we received a notice that OFAC had denied our October 26, 2011 application for the return of the blocked funds.  During the year ended December 31, 2015 primarily due to the passage of  time, we recorded a $0.7 million allowance for doubtful accounts to general and administrative costs associated with the blocked payment and $0.4 million receivable from our joint venture partner.   On October 13, 2015, we filed a request that OFAC reconsider its decision and on March 8, 2016 OFAC denied our October 13, 2015 request for the return of blocked funds; however, the Company will continue attempts to recover the funds from 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. The court administratively closed the case in 2013. The case was reopened in 2014 as a result of a Circuit Court of Appeals’ ruling.  On November 3, 2015, the court granted a stipulated motion to dismiss with prejudice and the lawsuit was dismissed.

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

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

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

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

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

Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions 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:

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

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

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

Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. 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 January 15, 2015, HNR Finance and Harvest Vinccler S.C.A submitted a Request for Arbitration against the Government of Venezuela before the International Centre for Settlement of Investment Disputes ("ICSID") regarding HNR Finance's interest in Petrodelta.  The Request for Arbitration set forth numerous claims, including (a) the failure of the Venezuelan government to approve the Company’s negotiated sale of its 51 percent interest in Harvest Holding to Petroandina on any reasonable grounds in 2013-2014, resulting in the termination of the SPA (b) the failure of the Venezuelan government to approve the Company’s previously negotiated sale of its interest in Petrodelta to PT Pertamina (Persero) on any reasonable grounds in 2012-2013, resulting in the termination of a purchase agreement entered into between HNR Energia and PT Pertamina (Persero); (c) the failure of the Venezuelan government to allow Petrodelta to pay approved and declared dividends for 2009; (d) the failure of the Venezuelan government to allow Petrodelta to approve and declare dividends since 2010, in violation of Petrodelta’s bylaws and despite Petrodelta’s positive financial results between 2010 and 2013; (e) the denial of Petrodelta’s right to fully explore the reserves within its designated areas; (f) the failure of the Venezuelan government to pay Petrodelta for all hydrocarbons sales since Petrodelta’s incorporation, recording them instead as an ongoing balance in the accounts of PDVSA, the Venezuelan government-owned oil company that controls Venezuela’s 60 percent interest in Petrodelta, and as a result disregarding Petrodelta’s managerial and financial autonomy; (g) the failure of the Venezuelan government to pay Petrodelta in US dollars for the hydrocarbons sold to PDVSA, as required under the mixed company contract; (h) interference with Petrodelta’s operations, including PDVSA’s insistence that PDVSA and its affiliates act as a supplier of materials and equipment and provider of services to Petrodelta; (i) interference with Petrodelta’s financial management, including the use of low exchange rates Bolivars/US dollars to the detriment of the Company and to the benefit of the Venezuelan government, PDVSA and its affiliates; and (j) the forced migration of the Company’s investment in Venezuela from an operating services agreement to a mixed company structure in 2007.

On January 26, 2015, Petroandina filed a complaint for breach of contract against the Company and its subsidiary HNR Energia in Court of Chancery of the State of Delaware (“Court of Chancery”).  The complaint states that HNR Energia breached provisions of the Shareholders Agreement between Petroandina and HNR Energia, which provisions require HNR Energia to provide advance notice of, and deposit $5.0 million into an escrow account, before bringing any claim against the Venezuelan government. Under those provisions, if Petroandina so requests, an appraisal of Petroandina's 29 percent interest in Harvest Holdings must be performed, and Petroandina has the right to require HNR Energia to purchase that 29 percent interest at the appraised value.  Petroandina's claim requests that, among other things, the court (a) declare that HNR Energia has breached the Shareholders' Agreement by submitting the Request for Arbitration against the Venezuelan government on January 15, 2015 (which Request for Arbitration was subsequently withdrawn without prejudice); (b) declare that the Company has breached its guaranty of HNR Energia's obligations under the Shareholders' Agreement; (c) direct the Company and HNR Energia to refrain from prosecuting any legal proceeding against the Venezuelan government (including the previously filed Request for Arbitration) until such time as they have complied with the relevant provisions of the Shareholders' Agreement; (d) award Petroandina costs and fees related to the lawsuit; and (e) award Petroandina such other relief as the court deems just and proper.On January 28, 2015, the Court of Chancery issued an injunction ordering the Company and HNR Energia to withdraw the Request for Arbitration and not take any action to pursue its claims against Venezuela until Harvest and HNR Energia have complied with the provisions of the Shareholders’ Agreement or otherwise reached an agreement with Petroandina.  Accordingly, on January 28, 2015, HNR Finance B.V. and Harvest Vinccler S.C.A. withdrew without prejudice the Request for Arbitration. In the Delaware proceeding, the Company and HNR Energia have until May 23, 2016 to respond to Petroandina’s complaint.We are currently unable to estimate the amount or range of any possible loss.

On February 27, 2015, Harvest (US) Holdings, Inc. (“Harvest US”), a wholly owned subsidiary of Harvest, Branta, LLC and Branta Exploration & Production Company, LLC (together, “Branta,” and together with Harvest US, “Plaintiffs”) filed a complaint against Newfield Production Company (“Newfield”) in the United States District Court for the District of Colorado.  Plaintiffs previously sold oil and natural gas assets located in Utah’s Uinta Basin to Newfield pursuant to two Purchase and Sale Agreements, each dated March 21, 2011.  In the complaint, Plaintiffs allege that, prior to the sale, Newfield breached separate confidentiality agreements with Harvest US and Branta by discussing the auction of the assets with a potential bidder for the assets, which caused the potential bidder not to participate in the auction and resulted in a depressed sales price for the assets.  The complaint seeks damages and fees for breach of contract, violation of the Colorado Antitrust Act, violation of the Sherman Antitrust Act and tortious interference with a prospective business advantage.  In September 2015, Plaintiffs amended their complaint to add Ute Energy, LLC and Crescent Point Energy Corporation as defendants.

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

XML

Taxes

12 Months Ended

Dec. 31, 2015

Taxes [Abstract]

Taxes

Note 14 – Taxes

Taxes on Income

The tax effects of significant items comprising our net deferred income taxes are as follows:

	As of  December 31,
		2015			2014
	Foreign		United States and Other		Foreign		United States and Other
	(in thousands)
Deferred tax assets:
Operating loss carryforwards	$	50,974	$	13,547	$	54,722	$	8,718
Stock-based compensation		—		3,471		—		6,479
Accrued compensation		—		653		—		376
Oil and natural gas properties		26,065		—		18,515		—
Investment in affiliate		130,088		—		88,913		—
Alternative minimum tax credit		—		2,545		—		4,299
Other		—		89		—		81
Total deferred tax assets		207,127		20,305		162,150		19,953
Deferred tax liabilities:
Tax on unremitted earnings of foreign subsidiaries		—		—		—		(14,700)
Other liabilities		(1,111)		(278)		—		(141)
Fixed assets		—		(3)		—		(3)
Total deferred tax liabilities		(1,111)		(281)		—		(14,844)
Net deferred tax asset (liability)		206,016		20,024		162,150		5,109
Valuation allowance		(205,896)		(20,024)		(162,097)		(19,809)
Net deferred tax asset (liability) after valuation allowance	$	120	$	—	$	53	$	(14,700)

As a result of the adoption of ASU No. 2015-17 the net deferred tax assets (liabilities) as of December 31, 2015 and 2014, were included in the consolidated balance sheets as Long-term deferred tax assets of $0.1 million and $0.1 million and Long-term deferred tax liabilities of $0.0 and $14.7 million, respectively.  

After assessing the possible actions which management may take in 2016 and the next few years during the year ended December 31, 2015, we continued to recognize that a deferred tax liability related to income tax on undistributed earnings of our foreign subsidiaries may be appropriate.  The Company is pursuing various alternatives with respect to its future operations and cannot assert that any future earnings will not be remitted to the U.S. as operations require.  The deferred tax liability recognized in prior periods, however, was decreased during 2015 to zero due to the impairment of the Company’s remaining investment in Petrodelta.

Management assesses the available positive and negative evidence to estimate if sufficient future taxable income will be generated to use the existing deferred tax assets (“DTAs”). A significant piece of objective negative evidence evaluated was the cumulative losses incurred in our foreign operating entities over the three-year period ended December 31, 2015. Such objective evidence limits the ability to consider other subjective evidence such as our projections for future growth or future asset dispositions. We have therefore placed a valuation allowance on all but a small amount of our foreignDTAs.

Management also reviewed the earnings history of our U.S. operations and determined that the Company is not expected to have sufficient taxable income in the U.S. due to its inability to sell the remaining equity interest in Harvest Holding and the lack of other income producing operations. Consequently, the Company is not expected to utilize its deferred tax assets and carries a valuation allowance on these deferred tax assets. Additionally, there was a significant increase to the valuation allowance attributable to the recognition of deferred tax assets related to the impairments of Petrodelta and the Dussafu PSC as these deferred tax assets are more likely than not to be unrealizable. The components of loss from continuing operations before income taxes are as follows:

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Income (loss) before income taxes
United States	$	1,457	$	(12,809)	$	(31,072)
Foreign		(198,537)		(438,589)		(40,725)
Total	$	(197,080)	$	(451,398)	$	(71,797)

The provision (benefit) for income taxes on continuing operations consisted of the following at December 31:

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Current:
United States	$	(1,755)	$	(87)	$	2,279
Foreign		32		47		44
		(1,723)		(40)		2,323
Deferred:
United States		(14,700)		(58,250)		72,971
Foreign		—		—		(2,207)
		(14,700)		(58,250)		70,764
	$	(16,423)	$	(58,290)	$	73,087

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

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Income tax expense (benefit) from continuing operations:
Tax expense (benefit) at U.S. statutory rate	$	(68,978)	$	(157,989)	$	(25,129)
Effect of foreign source income and rate differentials on foreign income		(10,870)		38,198		204
Tax gain associated with sale of interest in Harvest Holding		—		—		7,474
Subpart F income		—		—		16,615
Non-deductible interest		11,397		—		—
Tax on unremitted earnings of foreign subsidiaries		(14,700)		(75,200)		89,900
Expired losses		24,554		2,778		1,356
Other changes in valuation allowance		44,014		129,480		(10,643)
Change in applicable statutory rate		—		—		(404)
Other permanent differences		—		2,010		(2,546)
Return to accrual and other true-ups		11,823		1,955		2,919
Debt exchange		(12,079)		—		—
Warrant derivatives		(1,685)		(684)		(1,180)
Liability for uncertain tax positions		67		(30)		(5,553)
Other		34		1,192		74
Total income tax expense (benefit) – continuing operations	$	(16,423)	$	(58,290)	$	73,087

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

At December 31, 2015, we have the following net operating losses available for carryforward (in thousands):

United States	$	38,707	Available for up to 20 years from 2012
Gabon		22,269	Available for up to 3 years from 2013
The Netherlands		157,695	Available for up to 9 years from 2007
Venezuela		7,274	Available for up to 3 years from 2013

As a result of the first Petroandina closing in 2013, the Company realized a tax gain of $47.4 million which was included in U.S. taxable income pursuant to the provisions of the Internal Revenue Code. The Company utilized $9.8 million of available losses from prior years as well as a current year tax loss of $37.6 million to offset income resulting from the sale resulting in no regular tax for the year ended December 31, 2013 and leaving $9.3 million of losses available to offset taxable income in future periods. However, as a result of the alternative minimum tax provisions (“AMT”), we did incur AMT of $1.9 million increasing the amount of the AMT credit carryforward.  During 2014, the Company incurred a net operating loss (“NOL”) for AMT purposes.  A portion of this AMT NOL was carried back to 2013 to offset 90% of the $1.9 million AMT liability incurred during the year.  Accounts receivable at December 31, 2015 included a tax receivable of $1.7 million which was received from the Internal Revenue Service on February 12, 2016.  The AMT credit carryforward at December 31, 2015 amounts to $2.6 million.

If the U.S. operating loss carryforwards are ultimately realized, there would be no amounts credited to additional paid in capital for tax benefits associated with deductions for income tax purposes related to stock options and convertible debt.

Accumulated Undistributed Earnings of Foreign Subsidiaries

Under ASC 740-30-25-17, no deferred tax liability must be recorded if sufficient evidence shows that a foreign subsidiary has invested or will invest its 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.

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 into our foreign operations.  During the fourth quarter of 2013, management evaluated numerous factors related to the timing and amounts of possible future distribution of foreign earnings to the parent company, with consideration of the sale of non-U.S. assets. Because management was pursuing various alternatives with respect to the Company’s future operations and disposition of any sale proceeds, 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. However, due primarily to the $355.7 million pre-tax impairment of Petrodelta, this balance decreased by $75.2 million to $14.7 million at December 31, 2014.

As of December 31, 2015, the book-tax outside basis difference in our foreign subsidiary resulting from unremitted earnings was reduced to zero due to a pre-tax impairment of the Company’s remaining investment in Petrodelta of $164.7 million.  Consequently, the deferred tax liability associated with the foreign earnings was reduced to zero. The entire net deferred tax liability as of December 31, 2014 has been reflected as a long-term liability, a characterization consistent with the Company’s adoption of Accounting Standards Update (“ASU”) No. 2015-17.

Accounting for Uncertainty in Income Taxes

The FASB issued ASC 740-10 (prior authoritative literature: Financial Interpretation No. (“FIN”) 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109 (“FIN 48”) to create a single model to address accounting for uncertainty in tax positions. ASC 740-10 clarifies the accounting for income taxes, by prescribing a minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. ASC 740-10 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods and disclosure.

We or one of our subsidiaries file income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions. With few exceptions, we are no longer subject to tax examinations by tax authorities for years before 2010. Our primary income tax jurisdictions and their respective open audit years are:

Tax Jurisdiction	Open Audit Years
United States	2012 – 2015
The Netherlands	2013 – 2015
Venezuela	2010 – 2015

In January 2014, the U.S. IRS began an audit of our U.S. tax returns for 2011 and 2012.  The audit was concluded in October 2014 with an increase in tax of $0.01 million.  The Company has recently received notice from the U.S. IRS that it intends to audit the Company’s 2013 and 2014 tax years. The audit is expected to commence in April 2016.

The changes in our reserve for unrecognized tax benefits follow:

	Year Ended December 31,
	2015		2014
	(in thousands)
Balance at beginning of year	$	288	$	318
Additions for tax positions of prior years		—		—
Reductions for tax positions of prior years		(168)		(30)
Balance at end of year	$	120	$	288

The release of the reserve for uncertain tax positions of $0.03 million during the year ended December 31, 2014 was primarily related to the resolution of a Dutch tax matter regarding treatment of certain costs charged to our Dutch affiliate. However, this amount was offset by an adjustment to the valuation allowance resulting in a nil net tax.In 2015, the reserve was adjusted for a law change re-opening a prior closed year ($0.1 million) offset by a benefit ($0.3 million) from the expiration of the period of assessment on a tax related interest issue.  The benefit was included as a reduction of interest expense in our consolidated results of operations and comprehensive income for the year ended December 31, 2015.  We believe that it is likely that remaining amount for the uncertain tax position will be resolved within the next twelve months, and the amount of unrecognized tax benefits will significantly decrease.

XML

Stock-Based Compensation and Stock Purchase Plans

12 Months Ended

Dec. 31, 2015

Stock-Based Compensation and Stock Purchase Plans [Abstract]

Stock-Based Compensation and Stock Purchase Plans

Note 15 – Stock-Based Compensation and Stock Purchase Plans

Total share-based compensation expense, which includes stock options, restricted stock, SARs, and RSUs, totaled $2.0 million for the year ended December 31, 2015  ($1.6 million and $2.3 million for the years ended December 31, 2014 and 2013, respectively). All awards utilize the straight line method of amortization over the vesting period.    The following table is a summary of compensation expense (income) recorded in general and administrative expense in our consolidated statements of operations and comprehensive loss by type of awards:

	As of December 31,
Employee Stock-Based Compensation	2015		2014		2013
	(in thousands)
Equity based awards:
Stock options	$	2,003	$	2,073	$	2,119
Restricted stock		135		579		927
RSUs		133		—		—
Total expense related to equity based awards		2,271		2,652		3,046
Liability based awards:
SARs		(260)		(1,237)		(247)
RSUs		12		197		(534)
Total expense related to liability based awards		(248)		(1,040)		(781)
Total compensation expense	$	2,023	$	1,612	$	2,265

Long Term Incentive Plans

As of December 31, 2015, we had several long term incentive plans under which stock options, restricted stock, SARs and RSUs can be granted to eligible participants including employees, non-employee directors and consultants of our Company or subsidiaries:

· 2010 Long Term Incentive Plan, as amended (“2010 Plan”) – Provides for the issuance of up to 7,725,000 shares of our common stock in satisfaction of stock options, SARs, restricted stock, RSUs and other stock-based awards. No more than 2,425,000 shares may be granted as restricted stock and annually no individual may be granted more than 1,000,000 stock options or SARs. The 2010 Plan also permits the granting of performance awards to eligible employees and consultants. In the event of a change in control, all outstanding stock options and SARs become immediately exercisable to the extent permitted by the plan, and any restrictions on restricted stock and RSUs lapse.  At December 31, 2015, all shares available under the 2010 Plan had been granted.   

· 2006 Long Term Incentive Plan (“2006 Plan”) – Provides for the issuance of up to 1,825,000 shares of our common stock in satisfaction of stock options, SARs and restricted stock. No more than 325,000 shares may be granted as restricted stock, and no individual may be granted more than 900,000 stock options or SARs and not more than 175,000 shares of restricted stock during any period of three consecutive calendar years. The 2006 Plan also permits the granting of performance awards to eligible employees and consultants. In the event of a change in control, all outstanding stock options and SARs become immediately exercisable to the extent permitted by the plan, and any restrictions on restricted stock lapse.The termination date for the 2006 LTIP Plan is May 17, 2016.   At December 31, 2015, all shares available under the 2006 Plan had been granted.

· 2004 Long Term Incentive Plan (“2004 Plan”) – Provides for the issuance of up to 1,750,000 shares of our common stock in satisfaction of stock options, SARs and restricted stock. No more than 438,000 shares may be granted as restricted stock, and no individual may be granted more than 438,000 stock options and not more than 110,000 shares of restricted stock over the life of the plan. The 2004 Plan also permits the granting of performance awards to eligible employees and consultants. In the event of a change in control, all outstanding stock options and SARs become immediately exercisable to the extent permitted by the plan, and any restrictions on restricted stock lapse.  With the exception of outstanding awards, the 2004 Plan terminated on May 20, 2014.

· 2001 Long Term Stock Incentive Plan (“2001 Plan”) – Provides for the issuance of up to 1,697,000 shares of our common stock in the form of Incentive Stock Options and Non-Qualified Stock Options. No officer may be granted more than 500,000 stock options during any one fiscal year, as adjusted for any changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the 2001 Plan.  At December 31, 2015, stock option awards to purchase 85,000 common shares remain available for grant.

Stock Options

Stock options granted under the plans must be no less than the fair market value of our common stock on the date of grant. Stock options granted under the plans generally vest ratably over a three year period beginning from the date of grant. Stock options granted under the plans expire five to ten years from the date of grant.

Prior to 2015, the fair value of each stock option award was estimated on the date of grant using the Black-Scholes option-pricing model which uses assumptions for the risk-free interest rate, volatility, dividend yield and the expected term of the options. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the option. Expected volatility is based on historical volatilities of our stock. We do not assume any dividend yield since we do not pay dividends. The expected term of options granted is the weighted average life of stock options and represents the period of time that options are expected to be outstanding.

In 2015, the fair value of each stock option was estimated on the date of grant using a Monte Carlo simulation since the options were also subject to a market condition.  These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share (“VWAP condition”) in addition to the ratable vesting over a three year period.  The Monte Carlo simulation includes this VWAP condition and uses assumptions for the risk-free interest rate, volatility, and dividend yield whilea suboptimal exercise factor determines the expected term of the options. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the option. Expected volatility is based on historical volatilities of our stock. We do not assume any dividend yield since we do not pay dividends. The expected term of options granted represents the period of time that options are expected to be outstanding. The Monte Carlo simulation assumed a suboptimal exercise factor of 2.5meaning that exercise is generally expected to occur when the share price reaches 2.5 times the award’s exercise price.

December 31, 2015, we awarded stock options vesting over three years to purchase 847,000 of our common shares to our employees and executive officers (683,000 and 920,004 stock options were granted during the years ended December 31, 2014 and 2013, respectively).

On December 9, 2015, we additionally issued 3,528,201 options with a life of 4.6 years and an exercise price of $1.13 subject to the VWAP condition.   These options vest one-third on July 22, 2016, one-third on July 22, 2017 and one-third on July 22, 2018 with an expiry date of July 22, 2020.  These options were issued as replacement awards for the equivalent number of SARs issued on July 22, 2015.  The options were issued with the equivalent terms, exercise price, and VWAP conditions as the SARs. 

We also consider an estimated forfeiture rate for all stock option awards, and we recognize compensation cost only for those shares that are expected to vest, on a straight-line basis over the requisite service period of the award, which is generally the vesting term of three years. The forfeiture rate is based on historical experience.

Options	Outstanding	Weighted- Average Exercise Price			Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)
Options outstanding as of December 31, 2014	4,536	$	7.81		2.0	$	—
Granted	4,375		1.13	(1)			—
Exercised	—		—
Cancelled	(1,769)		(9.85)
Options outstanding as of December 31, 2015	7,142		3.21		3.5		—
Options exercisable as of December 31, 2015	2,011	$	7.16		1.5		—

(1) These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE in addition to the ratable vesting over a three year period.

Of the options outstanding, 2.0 million were exercisable at a weighted-average exercise price of $7.16 as of December 31, 2015  (2.7 million at $8.85 at December 31, 2014;  2.9 million at $9.85 at December 31, 2013).

In 2014 and 2013, the value of each stock option grant is estimated on the date of grant using the Black-Scholes option pricing model.  In 2015, the value of each stock option grant is estimated on the date of grant using a Monte Carlo simulation.  Each have the following weighted average assumptions:

	As of December 31,
For options granted during:	2015			2014			2013
Weighted average fair value	$	0.43		$	2.97		$	3.06
Weighted average expected life		4.7 years			5 years			5 years
Expected volatility (1)		100	%		76.7	%		79.4	%
Risk-free interest rate		1.7	%		1.5	%		1.3	%
Suboptimal exercise factor (2)		2.5			—			—
Weighted average pre-vest forfeiture rate		1.1	%		1.0	%		1.2	%
Dividend yield		0.0	%		0.0	%		0.0	%

(1) Expected volatilities are based on historical volatilities of our stock.

(2) A suboptimal exercise factor of 2.5 means that exercise is generally expected to occur when the share price reaches 2.5 times the award’s exercise price.

A summary of our unvested stock option awards as of December 31, 2015, and the changes during the year then ended is presented below:

Unvested Stock Options	Outstanding		Weighted- Average Grant-Date Fair Value
	(in thousands)
Unvested as of December 31, 2014	1,876	$	3.85
Granted	4,375		0.43
Vested	(645)		(2.99)
Expired	(475)		(6.38)
Unvested as of December 31, 2015	5,131	$	0.81

The total intrinsic value of stock options exercised during the year ended December 31, 2015 was $0.0 million (2014: $0.0 million; 2013: $0.1 million). The total fair value of stock options that vested during the year ended December 31, 2015, was $1.9 million ($2.4 million and $1.9 million during the years ended December 31, 2014 and 2013, respectively).

As of December 31, 2015, there was $3.0 million of total future compensation cost related to unvested stock option awards that are expected to vest. That cost is expected to be recognized over a weighted average period of 1.86 years.

Restricted Stock

Restricted stock is issued on the grant date, but cannot be sold or transferred. Restricted stock granted to directors vest one year after date of grant. Restricted stock granted to employees vest at the third year after date of grant. Vesting of the restricted stock is dependent upon the employee’s continued service to Harvest.

A summary of our restricted stock awards as of December 31, 2015, and the changes during the year then ended is presented below:

Restricted Stock	Outstanding		Weighted- Average Grant-Date Fair Value
	(in thousands)
Unvested as of December 31, 2014	86	$	4.82
Granted	—		—
Vested	(2)		(5.85)
Forfeited	—		—
Unvested as of December 31, 2015	84	$	4.80

No restricted stock shares were awarded during the years ended December 31, 2015 and 2014. In 2013, we awarded 190,002 shares to directors and employees.  The restricted stock granted in 2013 had an aggregate fair value of $0.9 million. The restricted stock is scheduled to vest at the third year after date of grant for employees and vestedone year after date of grant for directors. The fair value of the restricted stock that vested during the year ended December 31, 2015 was $11,700 ($1.9  million and $1.2 million during the years ended December 31, 2014 and 2013, respectively). The weighted average grant date fair value of awards granted in 2013 was $4.80.

As of December 31, 2015 there was $0.1 million of total future compensation cost related to unvested restricted stock awards that are expected to vest. That cost is expected to be recognized over a weighted average period of 0.5 years.

Stock Appreciation Rights (“SARs”)

All SAR awards granted to date have been granted outside of active long-term incentive plans and are held by Harvest employees. SARs granted in 2013 and 2015 vest ratably over three years beginning in the first year of grant. Vesting of SARs is dependent upon the employee’s continued service to Harvest. SAR awards are settled either in cash or Harvest common stock if available through an equity compensation plan. For recording of compensation, we assume the SAR award will be cash-settled and record compensation expense based on the fair value of the SAR awards at the end of each period.

The significant assumptions are summarized in the following table thatwere used to calculate the fair value of the SARs granted on July 22, 2015 and amended December 9, 2015 that were outstanding as of the balance sheet date presented on our consolidated balance sheet:

	Fair Value
	Hierarchy	As of December 31,
	Level	2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	0.43
Exercise price	Level 1 input	$	1.13
Threshold price	Level 1 input	$	2.50
Suboptimal exercise factor	Level 3 input		2.5
Term (years)			4.56
Volatility	Level 2 input		105.0	%
Risk-free rate	Level 1 input		1.66	%
Dividend yield	Level 2 input		0.0	%

As these awards are accounted for as liabilities, the fair value of each SAR was estimated at December 31, 2015 using a Monte Carlo simulation since the SARs were also subject to a market condition.  These SARs will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share (“VWAP condition”) in addition to the ratable vesting over a three year period.  The Monte Carlo simulation includes this VWAP condition and uses assumptions for the risk-free interest rate, volatility, and dividend yield whilea suboptimal exercise factor determines the expected term of the SARs. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the SAR. Expected volatility is based on historical volatilities of our stock. We do not assume any dividend yield since we do not pay dividends. The expected term of SARs granted represents the period of time that SARs are expected to be outstanding. The Monte Carlo simulation assumed a suboptimal exercise factor of 2.5meaning that exercise is generally expected to occur when the share price reaches 2.5 times the award’s exercise price.  The suboptimal exercise factor was the Level 3 input used for the valuation of the SARs.  In general, if the suboptimal exercise factor increases then the fair value of the SAR will increase or vice versa.  A change in the Level 3 input has a minimal effect on the valuation of the SARs as the primary driver is our stock price. 

SAR award transactions under our employee compensation plans are presented below:

SARs	Outstanding	Weighted- Average Exercise Price			Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)
SARS outstanding as of December 31, 2014	1,123	$	4.95		2.2	$	—
Granted	5,062		1.13	(1)	5.0		—
Cancelled	(3,528)		(1.13)	(1)
Expired	(86)		(5.12)
SARS outstanding as of December 31, 2015	2,571		2.67		3.3		—
SARS exercisable as of December 31, 2015	966	$	4.95		1.3		—

(1) These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE in addition to the ratable vesting over a three year period.

Of the SAR awards outstanding,  1.0 millionwere exercisable at the weighted-average exercise price of$4.95 as of December 31, 2015,  0.8 million exercisable at the weighted-average exercise price of$4.94 as of December 31, 2014 and 0.4million were exercisable at the weighted-average exercise price of $4.91 at December 31, 2013.

During the year ended December 31, 2015, there were 5.1 million SAR awards granted (zero and 0.2 million during the years ended December 31, 2014 and 2013, respectively). 

On July 22, 2015, we issued 5.1 million SARs at an exercise price of $1.13 per share, vesting ratably over three years from the date of grant and on the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE.  The dual vesting requirements necessitated that all of these awards be valued using a Monte Carlo simulation.  Since the Company had an insufficient numbers of shares available from existing long-term incentive plans, the SARs were classified as liability awards when issued.  

On December 9, 2015, our board of directors approved modifications of a portion of the July 22, 2015 awards.  Of the 5.1 million SARs issued, 3.5 million were cancelled and replaced with options under the 2010 Plan.  All other terms remained the same.    The fair value of the vested portion of the cancelled SARs approximated the fair value of the replacement options granted on December 9, 2015.  The remaining 1.6 million SARs continue to be classified as liability awards.

A summary of our unvested SAR awards as of December 31, 2015, and the changes during the year then ended is presented below:

Unvested SARs	Outstanding		Weighted- Average Fair Value
	(in thousands)
Unvested as of December 31, 2014	339	$	0.51
Granted	5,062		0.32
Vested	(264)		(0.06)
Cancelled	(3,528)		(0.35)
Expired	(4)		(0.05)
Unvested as of December 31, 2015	1,605	$	0.21

No SAR awards were exercised during the years ended December 31, 2015,2014 and 2013.  The total fair value of SAR awards that vested during the year ended December 31, 2015, was $15,960 ($0.2  million and $0.8 million during the years ended December 31, 2014 and 2013, respectively).

Restricted Stock Units (“RSUs”)

RSU awards granted prior to 2015 have been granted outside of active long-term incentive plans, are held by Harvest employees and directors, and are settled either in cash or Harvest common stock if available through an equity compensation plan and are accounted for as liability awards . RSU awards granted in 2012,  2014 and 2015 to employees vest at the third year after date of grant. RSU awards granted in 2015 to our board of directors vest one year after the date of grant. Vesting of the RSU awards is dependent upon the employee’s and director’s continued service to Harvest.

On September 9, 2015, we issued 320,004RSUs vesting one year from the date of grant to our directors.  These awards are classified as liability awards.  These awards are measured at their fair values based on our closing stock price at December 31, 2015.

The significant assumptions are summarized in the following table that were used to calculate the fair value of the restricted stock units granted on July 22, 2015 and amended December 9, 2015 that were outstanding as of the balance sheet date presented on our consolidated balance sheet:

	Fair Value
	Hierarchy	As of December 9,
	Level	2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	0.63
Threshold price	Level 1 input	$	2.50
Term (years)			10.0
Volatility	Level 2 input		80.0	%
Risk-free rate	Level 1 input		2.27	%
Dividend yield	Level 2 input		0.0	%

A summary of our RSU awards as of December 31, 2015, and the changes during the year then ended is presented below: 

RSUs	Outstanding		Weighted- Average Fair Value
	(in thousands)
Unvested as of December 31, 2014	905	$	1.81
Granted	1,891		0.73
Vested	(326)		(1.50)
Forfeited	—		—
Unvested as of December 31, 2015 (1)	2,470	$	0.52

1) At December 31, 2015, unvested RSUs of 1.6 million and 0.9 million were accounted for as equity and liability awards, respectively.

The 326,142 RSU awards vesting in 2015 were settled for cash of $0.5 million.  The 103,338 RSU awards which vested in 2014 were settled for cash of $0.5 million (202,668 RSU awards settled for cash of $0.6 million during 2013). The fair value of the RSU awards that vested during the year ended December 31, 2015 was $0.3 million ($0.2 million and $0.8 million during the years ended December 31, 2014 and 2013, respectively).

On July 22, 2015, we issued 1.6 million restricted stock units vesting at three years from the date of grant as stock based compensation awards to certain employees.  Subject to the three year vesting requirement, the RSUs awarded will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE.  The dual vesting requirements necessitated that all of these awards be valued using a Monte Carlo simulation.  Since an insufficient numbers of shares were available from existing long-term incentive plans, the RSUs were classified as liability awards at issuance.

On December 9, 2015, our board of directors approved a modification to share-settle the 1.6 million RSUs granted on July 22, 2015.  This modification changed the classification of these awards from liability to equity awards. The fair value of the vested portion of the initial RSUs approximated the fair value of the modified RSUs on December 9, 2015.  The grant-date fair value of the modified RSUs was $0.57 per RSU.

As of December 31, 2015 there was $1.0 million of total future compensation cost related to unvested RSU awards expected to vest. That cost is expected to be recognized over a weighted average period of 2.2 years.

Common Stock Warrants

In connection with the transaction with CT Energy on June 19, 2015,we issued a warrant exercisable for 34,070,820 shares of the Company’s common stock at an initial exercise price of $1.25 per share with an expiration date of June 19, 2018.  The CT Warrant may not be exercised until the volume weighted average price of the Company’s common stock over any consecutive 30-day period equals or exceeds $2.50 per share.  See Note 1 – Organization and Note 12 – Warrant Derivative Liability.  

XML

Operating Segments

12 Months Ended

Dec. 31, 2015

Operating Segments [Abstract]

Operating Segments

Note 16 – Operating Segments

We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Operations included under the heading “United States” include corporate management, cash management, business development and financing activities performed in the United States and other countries, which do not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the United States segment and are not allocated to other operating segments. In previous years, charges for intersegment general and administrative and interest expenses were included in results for the respective operating segments, and operating segment assets included intersegment receivables and loans. Segment loss and operating segment assets for prior periods have been adjusted to conform to the current presentation method in which intersegment items are eliminated from each segment’s results and assets.

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Segment Loss Attributable to Harvest
Venezuela		(83,953)		(171,801)		58,640
Gabon		(28,448)		(55,564)		(12,908)
Indonesia		(43)		(9,558)		(9,213)
United States and other		13,874		43,987		(120,465)
Loss from continuing operations(a)		(98,570)		(192,936)		(83,946)
Discontinued operations		—		(554)		(5,150)
Net loss attributable to Harvest	$	(98,570)	$	(193,490)	$	(89,096)

(a) Net of net income attributable to noncontrolling interest owners.

	As of December 31,
	2015		2014
	(in thousands)
Operating Segment Assets
Venezuela	$	5,290	$	165,214
Gabon		32,710		60,051
Indonesia		5		176
United States and other		9,776		2,602
		47,781		228,043
Discontinued operations		—		3
Total assets	$	47,781	$	228,046

XML

Related Party Transactions

12 Months Ended

Dec. 31, 2015

Related Party Transactions [Abstract]

Related Party Transactions

Note 17 – Related Party Transactions

The noncontrolling interest owners in Harvest Holdings, Vinccler (currently owning 20 percent) and Petroandina (currently owning 29 percent) are both related parties of the Company. 

As of December 31, 2014, HNR Energia had a note payable to Vinccler of $6.1 million. Principal and interest were payable upon the maturity date of December 31, 2015. Interest accrued at a rate of U.S. Dollar based three month LIBOR plus 0.5%.  On March 9, 2015, Vinccler forgave the note payable and accrued interest totaling $6.2 million.  This was reflected as a contribution to stockholders’ equity.

On May 11, 2015, the Company borrowed $1.3 million to fund certain corporate expenses and issued a note payable to CT Energy bearing an interest rate of 15.0% per annum, with a maturity date of January 1, 2016.  On June 19, 2015, the Company repaid the note payable and accrued interest.

On June 3, 2015, the Company entered into the note with James A. Edmiston, President and Chief Executive Officer of the Company, for $50,000. The note carried interest at 11.0% per year and was to mature upon the earlier to occur of June 30, 2016 or the date on which the Loan Obligations (as defined in that certain Loan Agreement, dated as of September 11, 2014, by and among the Company, HNR Energia B.V. and Petroandina Resources Corporation N.V.) are paid in full. On June 19, 2015, the Company repaid the note payable and accrued interest.

As of December 31, 2014, HNR Energia had a note payable to Petroandina of $7.6 million. Principal was due by January 1, 2016.  Interest payments were quarterly beginning on December 31, 2014.  On June 23, 2015 the Company repaid the note payable of $7.6 million plus accrued interest of $0.4 million.

On June 19, 2015, Harvest sold to CT Energy the 15% Note, the 9% Note and the Series C preferred stock.  Shortly after this transaction two representatives of CT Energy were appointed to Harvest’s board of directors.  On September 15, 2015, CT Energy converted the 9% Note, including accrued interest, into 8,667,597 shares of Harvest’s common stock and Harvest redeemed the Series C preferred stock.  See Note 1 – Organization for more information about the CT Energy transaction.

On January 4, 2016, HNR Finance made a loan to CT Energia in the amount of $5.2 million under an 11.0% promissory note due 2019 (the “CT Energia Note”), dated January 4, 2016, executed by CT Energia. The purpose of the loan is to provide CT Energia with collateral to obtain funds for one or more loans to Petrodelta. The loans to Petrodelta are to assist Petrodelta in satisfying its working capital needs and discharging its obligations. Interest on the CT Energia Note is due and payable on the first of each January and July, commencing July 1, 2016. The full amount outstanding, including any unpaid accrued interest, is due on January 4, 2019; however, HNR Finance’s sole recourse for payment of the principal amount of the loan is the payments of principal and interest from loans that CT Energia has made to Petrodelta. If and when CT Energia receives any payments of principal or interest from loans it has made to Petrodelta, then those proceeds must be used to prepay unpaid interest and principal under the CT Energia Note.  The source of funds for HNR Finance’s $5.2 million loan to CT Energia was a capital contribution from Harvest Holding, which, in return, received the same aggregate amount of capital contributions from its shareholders, pro rata according to their equity interests in Harvest Holding. Of that aggregate amount of capital contributions, HNR Energia contributed $2.6 million, which it had received as a capital contribution from Harvest.

XML

Mezzanine Equity

12 Months Ended

Dec. 31, 2015

Mezzanine Equity [Abstract]

Mezzanine Equity

Note 18 – Mezzanine Equity

In connection with the CT Energy transaction described in Note 1 – Organization, the Company also issued CT Energy 69.75 shares of its newly created Series C preferred stock, par value $0.01 per share.  The primary purpose of the Series C preferred stock was to provide the holder of the 9% Note with voting rights equivalent to the common stock underlying the unconverted portion of the 9% Note.  The Series C preferred stock was not entitled to receive dividends, had perpetual maturity, and had a $1.00 per share liquidation preference.  On September 15, 2015, upon the conversion of the 9% Note, the shares of Series C preferred stock were redeemed.

As discussed in Note 11 – Debt and Financing, no value was attributed to the Series C preferred stock.  Prior to its redemption on September 15, 2015, shares of the Series C preferred stock were recorded in temporary equityin accordance with ASC 480 – Distinguishing Liabilities from Equity, as the redemption of the shares was outside of the control of the Company. 

XML

Quarterly Financial Data

12 Months Ended

Dec. 31, 2015

Quarterly Financial Data [Abstract]

Quarterly Financial Data

Note 19 – Quarterly Financial Data (unaudited)

Summarized quarterly financial data is as follows:

	Quarter Ended
	March 31		June 30		September 30		December 31
	(amounts in thousands, except for share data)
Year ended December 31, 2015
Expenses (1)	$	(6,119)		(6,119)		(6,767)		(192,891)
Non-operating gain (loss)		(234)		(17,964)		10,335		22,679
Income (loss) from continuing operations before income taxes		(6,353)		(24,083)		3,568		(170,212)
Income tax expense (benefit)		(384)		1,604		(1,850)		(15,793)
Income (loss) from continuing operations		(5,969)		(25,687)		5,418		(154,419)
Less: Net loss attributable to noncontrolling interest owners		(352)		(262)		(294)		(81,179)
Net income (loss) attributable to Harvest	$	(5,617)	$	(25,425)	$	5,712	$	(73,240)
Basic Earnings (Loss) per Share:
Income (loss) from continuing operations	$	(0.13)	$	(0.60)	$	0.13	$	(1.42)
Net income (loss) attributable to Harvest	$	(0.13)	$	(0.60)	$	0.13	$	(1.42)
Diluted Earnings (Loss) per Share:
Income (loss) from continuing operations	$	(0.13)	$	(0.60)	$	0.13	$	(1.42)
Net income (loss) attributable to Harvest	$	(0.13)	$	(0.60)	$	0.13	$	(1.42)

	Quarter Ended
	March 31		June 30		September 30		December 31
	(amounts in thousands, except for share data)
Year ended December 31, 2014
Expenses (2)	$	(12,670)	$	(9,759)	$	(4,977)	$	(422,199)
Non-operating gain (loss)		(6,447)		(147)		3,067		1,734
Loss from continuing operations before income taxes		(19,117)		(9,906)		(1,910)		(420,465)
Income tax expense (benefit)		(954)		(88)		2,361		(59,609)
Loss from continuing operations		(18,163)		(9,818)		(4,271)		(360,856)
Earnings (loss) from investment in affiliate		18,887		16,062		—		—
Income (loss) from continuing operations		724		6,244		(4,271)		(360,856)
Discontinued operations		(131)		(230)		(142)		(51)
Net income (loss)		593		6,014		(4,413)		(360,907)
Less: Net income (loss) attributable to noncontrolling interest owners		8,601		7,665		(273)		(181,216)
Net income (loss) attributable to Harvest	$	(8,008)	$	(1,651)	$	(4,140)	$	(179,691)
Basic Earnings (Loss) per Share:
Income (loss) from continuing operations	$	0.19	$	(0.03)	$	(0.10)	$	(4.23)
Discontinued operations		—		(0.01)		—		—
Net income (loss) attributable to Harvest	$	0.19	$	(0.04)	$	(0.10)	$	(4.23)
Diluted Earnings (Loss) per Share:
Income (loss) from continuing operations	$	0.19	$	(0.03)	$	(0.10)	$	(4.23)
Discontinued operations		—		(0.01)		—		—
Net income (loss) attributable to Harvest	$	0.19	$	(0.04)	$	(0.10)	$	(4.23)

(1) Includes $164.7 million impairment during the quarter ended December 31, 2015 related to our investment in Petrodelta and $24.2 million impairment of oil and natural gas properties (including oilfield inventory) for Dussafu PSC.  See Note 6 – Investment in Affiliate and Note 8- Gabon.

(2) Includes $355.7 million impairment during the quarter ended December 31, 2014 related to our investment in Petrodelta, $13.8 million allowance for doubtful accounts for long-term receivable – investment in affiliate, and $50.3 million impairment of oil and natural gas properties for Dussafu PSC.  See Note 6 – Investment in Affiliate and Note 8- Gabon.

XML

Subsequent Events

12 Months Ended

Dec. 31, 2015

Subsequent Events [Abstract]

Subsequent Events

Note 20 – Subsequent Events

On January 4, 2016, Harvest entered into transactions to amend its existing 15.0% non-convertible note due 2020 and to make a loan, via one of its subsidiaries, to a third party. The parties involved in the transactions are HNR Energia, Harvest Holding, HNR Finance, CT Energy and CT Energia Holding Ltd., a Malta corporation (“CT Energia”) that is the service provider under the June 19, 2015 management agreement with Harvest and HNR Finance.  Harvest and CT Energy executed a first amendment of Harvest’s 15% non-convertible promissory note due 2020 (the “Original Note”), dated June 19, 2015, payable to CT Energy in the original principal amount of $25.2 million. The amendment increases the principal amount of the Original Note to $26.1 million to reflect a loan back to Harvest equal to the amount of interest that otherwise would have been due to CT Energy on January 1, 2016, less withholding tax due as a result of the interest that was owed at January 1, 2016.

On January 4, 2016, HNR Finance provided a loan to CT Energia in the amount of $5.2 million under an 11.0% promissory note due 2019 (the “CT Energia Note”), dated January 4, 2016, executed by CT Energia. The purpose of the loan is to provide CT Energia with collateral to obtain funds for one or more loans to Petrodelta that is 40% owned by HNR Finance and through which Harvest’s Venezuelan oil and natural gas interests are held. The loans to Petrodelta are to assist Petrodelta in satisfying its working capital needs and discharging its obligations. Interest on the CT Energia Note is due and payable on the first of each January and July, commencing July 1, 2016. The full amount outstanding, including any unpaid accrued interest, is due on January 4, 2019; however, HNR Finance’s sole recourse for payment of the principal amount of the loan is the payments of principal and interest from loans that CT Energia has made to Petrodelta. If and when CT Energia receives any payments of principal or interest from loans it has made to Petrodelta, then those proceeds must be used to prepay unpaid interest and principal under the CT Energia Note. All payments made by CT Energia to HNR Finance under the CT Energia Note must be made in USD.  The source of funds for HNR Finance’s $5.2 million loan to CT Energia was a capital contribution from Harvest Holding, which, in return, received the same aggregate amount of capital contributions from its shareholders, pro rata according to their equity interests in Harvest Holding. Of that aggregate amount of capital contributions, HNR Energia contributed $2.6 million, which it had received as a capital contribution from Harvest.

On March 9, 2016, Venezuela Vice President for Economic Area announced a new exchange agreement No.35 (the “Exchange Agreement No.35”).  Exchange Agreement No. 35 was published in Venezuela’s Official Gazette No. 40865 dated March 9, 2016, and became effective on March 10, 2016.  Exchange Agreement No. 35 will have a dual exchange rate for a controlled rate (named DIPRO) fixed at 10 USD/Bolivars for priority goods and services and a complimentary rate (named DICOM) starting at 206.92 USD/Bolivars for travel and other non-essential goods.  We are evaluating the impact Exchange Agreement No. 35 has on Harvest Vinccler and Petrodelta.

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. All intercompany profits, transactions and balances have been eliminated. Third-party interests in our majority-owned subsidiaries are presented as noncontrolling interest owners.

Reclassifications

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current period presentation.  These reclassifications did not affect our consolidated financial results.

Investment in Petrodelta

Investment in Petrodelta

Through December 31, 2014, we included the results of Petrodelta in our financial statements under the equity method.  We ceased recording earnings from Petrodelta in the second quarter 2014 due to the expected sales price of the second closing purchase agreement approximating the recorded value of our investment in Petrodelta.  The Company was not able to obtain approval from the government of Venezuela during 2014 and on January 1, 2015 we terminated the SPA.  Due to our failed sales attempts, lack of management influence, and actions and inactions by the majority owner, PDVSA, we believe we no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.  Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.  

We evaluate our investment in Petrodelta for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may be impaired. A loss is recorded in earnings in the current period if a decline in the value of the investment is determined to be other than temporary. Impairment is calculated as the difference between the carrying value of the investment and its fair value.  We recorded pre-tax impairment charges against the carrying value of our investment in Petrodelta of $164.7 million and $355.7 million during the years ended December 31, 2015 and 2014, respectively.  See Note 6 – Investment in Affiliate for further information.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Other important significant estimates are those included in the valuation of our assets and liabilities that are recorded at fair value on a recurring and non-recurring basis.  Actual results could differ from those estimates.

Reporting and Functional Currency

Reporting and Functional Currency

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

See Note 6 – Investment in Affiliate and Note 7 – Venezuela - Other for a discussion of currency exchange rates and currency exchange risk on Petrodelta’s and Harvest Vinccler’s businesses.

Cash and Cash Equivalents

Cash and Cash Equivalents

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

Restricted Cash

Restricted Cash

Restricted cash is classified as current or non-current based on the terms of the agreement. Restricted cash at December 31, 2014 represented $25,000 held in a U.S. bank as collateral for our foreign credit card program. There was no restricted cash as of December 31, 2015.

Financial Instruments

Financial Instruments

Financial instruments, which potentially subject us to concentrations of credit risk, are primarily cash and cash equivalents, accounts receivable, notes payable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts with commercial banks with high credit ratings, which, at times may exceed the federally insured limits. We have not experienced any losses from such investments. Concentrations of credit risk with respect to accounts receivable are limited due the nature of our receivables, which include primarily joint venture partner’s receivable, and income tax receivable. In the normal course of business, collateral is not required for financial instruments with credit risk.

Oil and Natural Gas Properties

Oil and Natural Gas Properties

The major components of property and equipment are as follows: 

	As of December 31,
	2015		2014
	(in thousands)
Unproved property costs - Dussafu PSC	$	28,000	$	50,324
Oilfield inventories		3,006		3,966
Other administrative property		2,937		2,670
Total property and equipment		33,943		56,960
Accumulated depreciation		(2,482)		(2,453)
Total property and equipment, net	$	31,461	$	54,507

Property and equipment are stated at cost less accumulated depreciation. Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of property and equipment, net of the related accumulated depreciation is removed and, if appropriate, gains or losses are recognized in investment earnings and other. We did not record any depletion expense in the years ended December 31, 2015, 2014 and 2013 as there was no production related to proved oil and natural gas properties.

We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that proved reserves, as that term is defined in Securities and Exchange Commission (“SEC”) regulations, have not been discovered, capitalized costs associated with the drilling of the exploratory well are charged to expense. Costs of drilling successful exploratory wells, all development wells, and related production equipment and facilities are capitalized and depleted or depreciated using the unit-of-production method as oil and natural gas is produced. During the years ended December 31, 2015, 2014 and 2013, we expensed no dry hole costs.

Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period. Costs of maintaining and retaining unproved leaseholds are included in exploration expense.  Costs of impairment of unsuccessful leases are included in impairment expense.  We assess our unproved property costs for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of the projects.  The estimated value of our unproved projects is determined using quantitative and qualitative assessments and the carrying value of the projects is adjusted if the carrying value exceeds the assessed value of the projects. 

Impairment is based on specific identification of the lease. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and natural gas properties.

Proved oil and natural gas properties are reviewed for impairment at a level for which identifiable cash flows are independent of cash flows of other assets when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are determined based on estimated future oil and natural gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these undiscounted estimated future net cash flows is less than the carrying amount of the property, an impairment loss is recognized for the excess of the property’s carrying amount over its estimated fair value, which is generally based on discounted future net cash flows. We did not have any proved oil and natural gas properties in 2015,  2014 or 2013.

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

During the year ended December 31, 2015, we recorded impairment expense related to our Dussafu Project in Gabon of $24.2 million (including $1.0 million of oilfield inventories). During the year ended December 31, 2014, we recorded impairment expense related to our Budong Project in Indonesia of $7.7 million and our Dussafu Project of $50.3 million.  During the year ended December 31, 2013, we recorded impairment expense related to our Budong Project in Indonesia of $0.6 million and our project in Colombia of $3.2 million, which is reflected in discontinued operations.

Other Administrative Property

Other Administrative Property

Furniture, fixtures and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to five years. Leasehold improvements are recorded at cost and amortized using the straight-line method over the life of the applicable lease. For the year ended December 31, 2015, depreciation expense was $0.1 million ($0.2 million and $0.3 million for the years ended December 31, 2014 and 2013, respectively).

Other Assets

Other Assets

Other Assets at December 31, 2015 and 2014 include deposits, prepaid expenses which are expected to be realized in the next 12 to 24 months.  During 2015 we fully reserved the blocked payment related to our drilling operations in Gabon in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”) See Note 13 – Commitments and Contingencies.   We recorded an allowance for doubtful accounts of $0.7 million and the remaining balance of the blocked payment was reclassified to a receivable from our joint venture partners for $0.4 million.  Other assets at December 31, 2014 also consisted of deferred financing costs. Deferred financing costs relate to specific financings and are amortized over the life of the financings to which the costs relate using the interest rate method.

	As of December 31,
	2015		2014
	(in thousands)
Deposits and long-term prepaid expenses	$	142	$	101
Deferred financing costs		—		283
Gabon – blocked payment		—		1,100
	$	142	$	1,484

Reserves

Reserves

We measure and disclose oil and natural 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”). All of our reserves are owned through our investment in Petrodelta. We are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014.  Under the cost method, we do not have any reserves at December 31, 2015 and 2014.

Capitalized Interest

Capitalized Interest

We capitalize interest costs for qualifying oil and natural gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation. During the year ended December 31, 2015, we capitalized interest costs for qualifying oil and natural gas property additions related to Gabon of $0.0 million ($0.5 million and $8.3 million during the years ended December 31, 2014 and 2013, respectively).

Fair Value Measurements

Fair Value Measurements

We measure and disclose our fair values in accordance with the provisions of ASC 820 “Fair Value Measurements and Disclosures” (“ASC 820”). ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price) and establishes a three-level hierarchy, which encourages an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The three levels of the hierarchy are defined as follows:

· Level 1 – Inputs to the valuation techniques that are quoted prices in active markets for identical assets or liabilities.

· Level 2 – Inputs to the valuation techniques that are other than quoted prices but are observable for the assets or liabilities, either directly or indirectly.

· Level 3 – Inputs to the valuation techniques that are unobservable for the assets or liabilities.

Financial instruments, which potentially subject us to concentrations of credit risk, are primarily cash and cash equivalents, accounts receivable, SARs, RSUs, debt, embedded derivatives and warrant derivative liabilities. We maintain cash and cash equivalents in bank deposit accounts with commercial banks with high credit ratings, which, at times may exceed the federally insured limits. We have not experienced any losses from such investments. Concentrations of credit risk with respect to accounts receivable are limited due to the nature of our receivables. In the normal course of business, collateral is not required for financial instruments with credit risk.  The estimated fair value of cash and cash equivalents and accounts receivable approximates their carrying value due to their short-term nature (Level 1).  The following tables set forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value as of December 31, 2015 and December 31, 2014. During the year ended December 31, 2015, we impaired the carrying value of our Dussafu project in Gabon by $23.2 million and our investment in affiliate by $164.7 million.  See Note 6 – Investment in Affiliate and Note 8 – Gabon for more information.

	As of December 31, 2015
	Level 1		Level 2		Level 3		Total
	(in thousands)
Non recurring
Assets:
Investment in affiliate	$	—	$	—	$	—	$	—
Dussafu PSC		—		—		28,000		28,000
	$	—	$	—	$	28,000	$	28,000

Recurring
Assets:
Embedded derivative asset	$	—	$	—	$	5,010	$	5,010
	$	—	$	—	$	5,010	$	5,010
Liabilities:
SARs liability	$	—	$	46	$	50	$	96
RSUs liability		—		174		—		174
Warrant derivative liability		—		—		5,503		5,503
	$	—	$	220	$	5,553	$	5,773

	As of December 31, 2014
	Level 1		Level 2		Level 3		Total
	(in thousands)
Non recurring
Assets:
Investment in affiliate	$	—	$	—	$	164,700	$	164,700
Dussafu PSC		—		—		50,324		50,324
	$	—	$	—	$	215,024	$	215,024
Recurring
Liabilities:
SARs liability	$	—	$	356	$	—	$	356
RSUs liability		—		652		—		652
	$	—	$	1,008	$	—	$	1,008

As of December 31, 2015, the fair value of our liability awards included $0.1 million for our SARs and $0.2 million for the RSUs which were recorded in accrued expenses and other long-term liabilities, respectively.  As of December 31, 2014, the fair value of our liability awards of $0.8 million was included in accrued liabilities ($0.4 million for our SARs and $0.4 million for our RSUs) with the remaining $0.2 million fair value of our RSU liability being included in long-term liabilities.

Derivative Financial Instruments

As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value liabilities and their placement within the fair value hierarchy levels. See Note 12 – Warrant Derivative Liability for a description and discussion of our warrant derivative liability as well as a description of the valuation models and inputs used to calculate the fair value.  See Note 11 – Debt and Financing for a description and discussion of our embedded derivatives related to our 9% Note and 15% Note as well as a description of the valuation models and inputs used to calculate the fair value.  All of our embedded derivatives and warrants are classified as Level 3 within the fair value hierarchy. 

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

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

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial assets -  embedded derivative asset
Beginning balance	$	—	$	—	$	—
Additions - fair value at issuance		2,504		—		—
Change in fair value		2,506		—		—
Ending balance	$	5,010	$	—	$	—

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial liabilities -  embedded derivative liability
Beginning balance	$	—	$	—	$	—
Additions - fair value at issuance		13,449		—		—
Change in fair value		(2,307)		—		—
Conversion of debt		(11,142)		—		—
Ending balance	$	—	$	—	$	—

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial liabilities -  warrant derivative liabilities:
Beginning balance	$	—	$	1,953	$	5,470
Additions - fair value at issuance		40,013		—		—
Change in fair value		(34,510)		(1,953)		(3,517)
Ending balance	$	5,503	$	—	$	1,953

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial liabilities -  stock appreciation rights
Beginning balance	$	—	$	—	$	—
Additions - fair value at issuance		—		—		—
Change in fair value		50		—		—
Ending balance	$	50	$	—	$	—

During the year ended December 31, 2015, 2014 and 2013, no transfers were made between Level 1, Level 2 and Level 3 liabilities or assets.

Share-Based Compensation

Share-Based Compensation

We use the fair value based method of accounting for share-based compensation. In prior years, we utilized the Black-Scholes option pricing model to measure the fair value of stock options and SARs. Restricted stock and RSUs were measured at their fair values.  During 2015, we issued options, SARs, and RSUs with an additional market condition.  To fair value these awards, a Monte Carlo simulation was utilized.  For more information about our share-based compensation, the fair value of these awards, and the additional market condition.   See Note 15 – Stock-Based Compensations and Stock Purchase Plans.

Income Taxes

Income Taxes

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

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

Since December of 2013 we have provided deferred income taxes on undistributed earnings of our foreign subsidiaries where we are not able to assert that such earnings were permanently reinvested, or otherwise could be repatriated in a tax free manner, as part of our ongoing business.  As of December 31, 2015, the deferred tax liability provided on such earnings has been reduced to zero due to the impairment of the underlying book investment in Petrodelta.

As the conversion feature of the 9% Note was reasonably expected to be exercised at the time of the note’s issuance due to the conversion price being in-the-money, the interest on the 9% Note paid upon its conversion is non-deductible to the Company under Internal Revenue Code (“IRC”) Section 163(l).  The 15% Note was issued, for income tax purposes, with original issue discount (“OID”).  OID generally is deductible for income tax purposes.  However, if the debt instrument constitutes an “applicable high-yield discount obligation” (“AHYDO”) within the meaning of IRC Section 163(i)(1), then a portion of the OID likely would be non-deductible pursuant to IRC Section 163(e)(5).  Our analysis of the 15% Note is that the note may be an AHYDO; consequently, a portion or all of the OID likely may be non-deductible for income tax purposes.

Noncontrolling Interests

Noncontrolling Interests

Changes in noncontrolling interest owners were as follows:

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Balance at beginning of period	$	79,152	$	243,167	$	97,101
Contributions by noncontrolling interest owners		3,382		1,208		—
Increase in equity held by noncontrolling interest owner		—		—		144,796
Dividend to noncontrolling interest owner		—		—		(10,370)
Net income (loss) attributable to noncontrolling interest owners		(82,087)		(165,223)		11,640
Balance at end of period	$	447	$	79,152	$	243,167

Valuation and Qualifying Accounts

Valuation and Qualifying Accounts

Our valuation and qualifying accounts are comprised of the deferred tax valuation allowance, investment valuation allowance and Value-Added Tax (“VAT”) receivable valuation allowance. Balances and changes in these accounts are, in thousands:

			Additions
	Balance at Beginning of Year		Charged to Income			Other			Deductions From Reserves Credited to Income		Balance at End of Period
	(in thousands)
At December 31, 2015
Amounts deducted from applicable assets
Deferred tax valuation allowance	$	181,906	$	—		$	44,014		$	—	$	225,920
Investment valuation allowance		1,350		—			—			—		1,350
VAT valuation allowance		2,792		—			(2,792)	(b)		—		—
Long-term receivable - investment in affiliate		13,753		—			—			—		13,753
At December 31, 2014
Amounts deducted from applicable assets
Deferred tax valuation allowance	$	59,576	$	129,480		$	(7,150)	(a)	$	—	$	181,906
Investment valuation allowance		1,350		—			—			—		1,350
Long-term receivable - investment in affiliate		—		13,753	(c)		—			—		13,753
VAT valuation allowance		2,792		—			—			—		2,792
At December 31, 2013
Amounts deducted from applicable assets
Deferred tax valuation allowance	$	68,419	$	—		$	—		$	(8,843)	$	59,576
Investment valuation allowance		1,350		—			—			—		1,350
VAT valuation allowance		—		2,792			—			—		2,792

(a) Attributable to reversal of temporary differences related to discontinued operations.

(b) Valuation allowance for the VAT receivable associated with Harvest Budong.  On May 4, 2015, the Company sold the shares of Harvest Budong-Budong B.V. to Stockbridge Capital Limited and the rights to the VAT receivable went with the entity to the buyer.

(c) During the year ended December 31, 2014, we fully reserved a dividend receivable of $12.2 million and $1.6 million of long-term receivable due from our investment in affiliate.

New Accounting Pronouncements

New Accounting Pronouncements

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs”. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update.  In June 2015 the FASB issued ASU No. 2015-15 as an amendment to this guidance to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements.  The SEC staff stated that they would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement.  The guidance is effective for interim periods and annual period beginning after December 15, 2015; however early adoption is permitted. We do not believe the adoption of this guidance will have a material impact on our financial position and will not have an impact on our results of operations or cash flows.

In August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern” ASU No. 2014-15. ASU No. 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU No. 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.

In April 2014, FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers” which is included in ASC 606, a new topic under the same name. The guidance in this update affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). The guidance supersedes the previous revenue recognition requirements and most industry-specific guidance. Additionally, the update supersedes some cost guidance related to construction type and production-type contracts.  In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in this update.

The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps:  (1) identify the contract(s) with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation.

The new guidance also provides for additional qualitative and quantitative disclosures related to: (1) contracts with customers, including revenue and impairments recognized, disaggregation of revenue, and information about contract balances and performance obligations (including the transaction price allocated to the remaining performance obligations); (2) significant judgments and changes in judgments which impact the determination of the timing of satisfaction of performance obligations (over time or at a point in time), the transaction price and amounts allocated to performance obligations; and (3) assets recognized from the costs to obtain or fulfill a contract.

In July 2015, the FASB issued a decision to delay related to ASU No. 2014-09 for the effective date by one year.  The new guidance is effective for annual and interim periods beginning after December 15, 2017.  An entity should apply the amendments either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of initial application. We are currently evaluating the impact of this guidance.

In November 2015, the FASB issued ASC No. 2015-17, “Balance Sheet Classification of Deferred Taxes”.  ASU No. 2015-17 simplifies the balance sheet presentation of deferred income taxes by requiring all deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The standard is effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted.  The standard may be applied either prospectively or retrospectively to all periods presented.  The Company has decided to adopt the accounting change in its current financial statements and has adopted the change retrospectively.

In February 2016, the FASB issued ASU No. 2016-02, “Leases”.  It is expected to be effective for periods beginning after December 15, 2018 for public entities, and for periods beginning after December 15, 2019 for nonpublic entities.  Early application is permitted.  Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less.  All other leases will fall into one of two categories: (1) Financing leases, similar to capital leases, will require the recognition of an asset and liability, measured at the present value of the lease payments.  Interest on the liability will be recognized separately from amortization of the asset.  Principal repayments will be classified as financing outflows and payments of interest as operating outflows on the statement of cash flows.  (2) Operating leases will also require the recognition of an asset and liability measured at the present value of the lease payments.  A single lease cost, consisting of interest on the obligation and amortization of the asset, calculated such that the amortization of the asset will increase as the interest amount decreases resulting in a straight-line recognition of lease expense.  All cash outflows will be classified as operating on the statement of cash flows.  We do not believe the adoption of this guidance will have a material impact on our financial position, results of operations or cash flows.

In March 2016, the FASB issued ASU No. 2016-07, “Investments — Equity Method and Joint Ventures (Topic 323)”. This amendment simplifies the accounting for equity method of investments, the amendment in the update eliminates the requirement in Topic 323 that an entity retroactively adopt the equity method of accounting if an investment qualifies for use of the equity method as a result of an increase in the level of ownership or degree of influence. The amendment requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt equity method of accounting as of the date the investment becomes qualified for equity method accounting. The amendment in this update is effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. The amendment should be applied prospectively upon the effective date to increases in the level of ownership interest or degree of influence that result in the adoption of the equity method. Earlier application is permitted.  We are currently evaluating the impact of this guidance.

XML

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies [Abstract]

Major Components of Property and Equipment

	As of December 31,
	2015		2014
	(in thousands)
Unproved property costs - Dussafu PSC	$	28,000	$	50,324
Oilfield inventories		3,006		3,966
Other administrative property		2,937		2,670
Total property and equipment		33,943		56,960
Accumulated depreciation		(2,482)		(2,453)
Total property and equipment, net	$	31,461	$	54,507

Schedule of Other Assets

	As of December 31,
	2015		2014
	(in thousands)
Deposits and long-term prepaid expenses	$	142	$	101
Deferred financing costs		—		283
Gabon – blocked payment		—		1,100
	$	142	$	1,484

Schedule of Fair Value Hierarchy of Financial Assets and Liabilities

	As of December 31, 2015
	Level 1		Level 2		Level 3		Total
	(in thousands)
Non recurring
Assets:
Investment in affiliate	$	—	$	—	$	—	$	—
Dussafu PSC		—		—		28,000		28,000
	$	—	$	—	$	28,000	$	28,000

Recurring
Assets:
Embedded derivative asset	$	—	$	—	$	5,010	$	5,010
	$	—	$	—	$	5,010	$	5,010
Liabilities:
SARs liability	$	—	$	46	$	50	$	96
RSUs liability		—		174		—		174
Warrant derivative liability		—		—		5,503		5,503
	$	—	$	220	$	5,553	$	5,773

	As of December 31, 2014
	Level 1		Level 2		Level 3		Total
	(in thousands)
Non recurring
Assets:
Investment in affiliate	$	—	$	—	$	164,700	$	164,700
Dussafu PSC		—		—		50,324		50,324
	$	—	$	—	$	215,024	$	215,024
Recurring
Liabilities:
SARs liability	$	—	$	356	$	—	$	356
RSUs liability		—		652		—		652
	$	—	$	1,008	$	—	$	1,008

Reconciliation of Financial Assets and Liabilities Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3)

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial assets -  embedded derivative asset
Beginning balance	$	—	$	—	$	—
Additions - fair value at issuance		2,504		—		—
Change in fair value		2,506		—		—
Ending balance	$	5,010	$	—	$	—

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial liabilities -  embedded derivative liability
Beginning balance	$	—	$	—	$	—
Additions - fair value at issuance		13,449		—		—
Change in fair value		(2,307)		—		—
Conversion of debt		(11,142)		—		—
Ending balance	$	—	$	—	$	—

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial liabilities -  warrant derivative liabilities:
Beginning balance	$	—	$	1,953	$	5,470
Additions - fair value at issuance		40,013		—		—
Change in fair value		(34,510)		(1,953)		(3,517)
Ending balance	$	5,503	$	—	$	1,953

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Financial liabilities -  stock appreciation rights
Beginning balance	$	—	$	—	$	—
Additions - fair value at issuance		—		—		—
Change in fair value		50		—		—
Ending balance	$	50	$	—	$	—

Schedule of Changes in Noncontrolling Interest Owners

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Balance at beginning of period	$	79,152	$	243,167	$	97,101
Contributions by noncontrolling interest owners		3,382		1,208		—
Increase in equity held by noncontrolling interest owner		—		—		144,796
Dividend to noncontrolling interest owner		—		—		(10,370)
Net income (loss) attributable to noncontrolling interest owners		(82,087)		(165,223)		11,640
Balance at end of period	$	447	$	79,152	$	243,167

Schedule of Valuation and Qualifying Accounts

			Additions
	Balance at Beginning of Year		Charged to Income			Other			Deductions From Reserves Credited to Income		Balance at End of Period
	(in thousands)
At December 31, 2015
Amounts deducted from applicable assets
Deferred tax valuation allowance	$	181,906	$	—		$	44,014		$	—	$	225,920
Investment valuation allowance		1,350		—			—			—		1,350
VAT valuation allowance		2,792		—			(2,792)	(b)		—		—
Long-term receivable - investment in affiliate		13,753		—			—			—		13,753
At December 31, 2014
Amounts deducted from applicable assets
Deferred tax valuation allowance	$	59,576	$	129,480		$	(7,150)	(a)	$	—	$	181,906
Investment valuation allowance		1,350		—			—			—		1,350
Long-term receivable - investment in affiliate		—		13,753	(c)		—			—		13,753
VAT valuation allowance		2,792		—			—			—		2,792
At December 31, 2013
Amounts deducted from applicable assets
Deferred tax valuation allowance	$	68,419	$	—		$	—		$	(8,843)	$	59,576
Investment valuation allowance		1,350		—			—			—		1,350
VAT valuation allowance		—		2,792			—			—		2,792

(a) Attributable to reversal of temporary differences related to discontinued operations.

(b) Valuation allowance for the VAT receivable associated with Harvest Budong.  On May 4, 2015, the Company sold the shares of Harvest Budong-Budong B.V. to Stockbridge Capital Limited and the rights to the VAT receivable went with the entity to the buyer.

(c) During the year ended December 31, 2014, we fully reserved a dividend receivable of $12.2 million and $1.6 million of long-term receivable due from our investment in affiliate.

XML

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Schedule of Earnings Per Share

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Loss from continuing operations(a)	$	(98,570)	$	(192,936)	$	(83,946)
Discontinued operations		—		(554)		(5,150)
Net loss attributable to Harvest	$	(98,570)	$	(193,490)	$	(89,096)
Weighted average common shares outstanding		45,288		42,039		39,579
Weighted average common shares, diluted		45,288		42,039		39,579
Basic loss per share:
Loss from continuing operations(a)	$	(2.18)	$	(4.59)	$	(2.12)
Discontinued operations		—		(0.01)		(0.13)
Basic loss per share	$	(2.18)	$	(4.60)	$	(2.25)
Diluted loss per share:
Loss from continuing operations(a)	$	(2.18)	$	(4.59)	$	(2.12)
Discontinued operations		—		(0.01)		(0.13)
Diluted loss per share	$	(2.18)	$	(4.60)	$	(2.25)

(a) Net of net income attributable to noncontrolling interest owners.

XML

Dispositions (Tables)

12 Months Ended

Dec. 31, 2015

Dispositions [Abstract]

Schedule of Discontinued Operations Expenses

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Loss from Discontinued Operations
Oman	$	—	$	(27)	$	(674)
Colombia		—		(527)		(4,476)
	$	—	$	(554)	$	(5,150)

XML

Investment in Affiliate (Tables)

12 Months Ended

Dec. 31, 2015

Investment in Affiliate [Abstract]

Schedule of Changes in Investment in Affiliate

	Year Ended December 31,
	2015		2014
	(in thousands)
Investment at beginning of year	$	164,700	$	485,401
Equity in earnings				34,949
Impairment		(164,700)		(355,650)
Investment at end of period	$	—	$	164,700

Summary of Financial Information

	Year Ended December 31,
	2014			2013
Results under IFRS:	(in thousands, except percentages)
Revenues:
Oil sales	$	1,343,452		$	1,326,093
Natural gas sales		4,590			4,000
Royalty		(437,281)			(440,963)
		910,761			889,130
Expenses:
Operating expenses		303,409			141,627
Workovers		28,239			29,168
Depletion, depreciation and amortization		129,409			87,203
General and administrative		45,623			37,778
Windfall profits tax		140,816			234,453
Windfall profits (credit) and reversal of credit		55,168			(55,168)
		702,664			475,061
Income from operations		208,097			414,069
Gain (loss) on exchange rate		(260)			169,582
Investment earnings and other		7,752			1,414
Interest expense		137			(21,728)
Income before income tax		215,726			563,337
Current income tax expense		103,619			325,217
Deferred income tax expense (benefit)		(32,617)			(17,662)
Net income under IFRS		144,724			255,782
Adjustments to increase (decrease) net income under IFRS:
Deferred income tax (expense) benefit		(2,841)			9,080
Depletion expense		(12,437)			(20,353)
Adjustment to lease operating costs to conform with GAAP		13,888			—
Windfall profits credit and (reversal) of credit		55,168			(55,168)
Adjust fair value of value added tax credits		(51,393)			—
Sports law over accrual		1,322			1,313
Net income under U.S. GAAP		148,431			190,654
Interest in investment affiliate		40	%		40	%
Income before amortization of excess basis in investment in affiliate		59,372			76,262
Amortization of excess basis in investment in affiliate		(4,428)			(3,684)
Earnings from investment affiliate excluded from results of operations		(19,995)			—
Earnings from investment affiliate included Harvest's income	$	34,949		$	72,578

Schedule of Assets and Liabilities

	As of December 31,
	2014
	(in thousands)
Financial Position under IFRS:
Current assets	$	1,459,676
Property and equipment		1,044,797
Other assets		241,478
Current liabilities		1,437,929
Other liabilities		147,242
Net equity		1,160,780

XML

Debt and Financing (Tables)

12 Months Ended

Dec. 31, 2015

Debt Instrument [Line Items]

Schedule of Long-Term Debt

	As of December 31,
Long-Term Debt	2015
	(in thousands)
Beginning balance	$	—
Proceeds from 9% and 15% Notes to CT Energy		32,200
Proceeds from note payable to CT Energy		1,300
Repayment of note payable to CT Energy		(1,300)
Value assigned to embedded derivatives		(32,200)
Conversion of 9% Note, net of unamortized discount		(11)
Accretion of discount on debt		225
	$	214

15% Note [Member]

Debt Instrument [Line Items]

Schedule of Fair Value Assumptions

The assumptions summarized in the following table were used to calculate the fair value of the derivative asset associated with the 15% Note at the date of issuance:

	Fair Value
	Hierarchy
	Level	June 19, 2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	1.82
Weighted Term (years)			5.0
Yield Volatility	Level 2 input		32.5	%
Risk-free rate	Level 1 input		1.6% to 2.0	%
Dividend yield	Level 2 input		0.0	%
Scenario probability:
Claim date extended with Stock Appreciation Date threshold met	Level 3 input		60.0	%
Claim date extended with Stock Appreciation Date threshold not met	Level 3 input		42.5	%
Claim date not extended with Stock Appreciation Date threshold met	Level 3 input		60.0	%
Claim date not extended with Stock Appreciation Date threshold not met	Level 3 input		40.2	%
Scenario probability (future draws/no future draws)	Level 3 input		50%/50	%

The embedded derivative asset related to the 15% Note contains a Level 3 input related to the probability of our investor lending us additional funds or not lending us funds according to the terms of the loan agreement for the additional draws.  We have assumed a 50/50 scenario of the draw or no draw for valuation of the embedded derivative.  Changes in this assumption have minimal impacts on the embedded derivative asset valuation as HNR stock price is the primary driver of the value. 

The assumptions summarized in the following table were used to calculate the fair value of the derivative asset associated with the 15% Note that was outstanding as of December 31, 2015 on our consolidated balance sheet:

	Fair Value
	Hierarchy	As of December 31,
	Level	2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	0.43
Weighted Term (years)			4.47
Yield Volatility	Level 2 input		35	%
Risk-free rate	Level 1 input		1.6% to 2.0	%
Dividend yield	Level 2 input		0.0	%
Scenario probability:
Claim date extended with Stock Appreciation Date threshold met	Level 3 input		54.8	%
Claim date extended with Stock Appreciation Date threshold not met	Level 3 input		36.1	%
Claim date not extended with Stock Appreciation Date threshold met	Level 3 input		54.8	%
Claim date not extended with Stock Appreciation Date threshold not met	Level 3 input		33.4	%
Scenario probability (future draws/no future draws)	Level 3 input		50%/50	%

9% Note [Member]

Debt Instrument [Line Items]

Schedule of Fair Value Assumptions

	Fair Value
	Hierarchy
	Level	June 19, 2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	1.82
Term (years)			5.0
Volatility	Level 2 input		90	%
Risk-free rate (base)	Level 1 input		0.27	%
Risk-free rate (5 year)	Level 1 input		2.05	%
Risk-free rate (7 year)	Level 1 input		2.40	%
Dividend yield	Level 2 input		0.0	%

XML

Warrant Derivative Liability (Tables)

12 Months Ended

Dec. 31, 2015

MSD Warrants [Member]

Derivative [Line Items]

Schedule of Fair Value Assumptions

	Fair Value
	Hierarchy	As of December 31,
	Level	2014
Significant assumptions (or ranges):
Stock price	Level 1 input	$	1.81
Term (years)			0.83
Volatility	Level 2 input		67	%
Risk-free rate	Level 1 input		0.21	%
Dividend yield	Level 2 input		0.0	%
Scenario probability (fundamental change event/debt raise/equity raise)	Level 3 input		0%/100%/0	%

CT Energy [Member]

Derivative [Line Items]

Schedule of Fair Value Assumptions

The assumptions summarized in the following table were used to calculate the fair value of the warrant derivative liability at the date of issuance:

	Fair Value
	Hierarchy
	Level	June 19, 2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	1.82
Exercise price	Level 1 input	$	1.25
Stock appreciation date price (hurdle)	Level 1 input	$	2.50
Term (warrants)			3.0
Term (claim date)			1.0
Term (claim date extended)			1.5
Volatility	Level 2 input		90.0	%
Risk-free rate (warrants)	Level 1 input		1.09	%
Risk-free rate (claim date)	Level 1 input		0.27	%
Risk-free rate (claim date extended)	Level 1 input		0.48	%
Dividend yield	Level 2 input		0.0	%

The assumptions summarized in the following table were used to calculate the fair value of the warrant derivative liability that was outstanding as of the balance sheet date presented on our consolidated balance sheet:

	Fair Value
	Hierarchy	As of December 31,
	Level	2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	0.43
Exercise price	Level 1 input	$	1.25
Stock appreciation date price (hurdle)	Level 1 input	$	2.50
Term (warrants)			2.4668
Term (claim date)			0.4672
Term (claim date extended)			0.9672
Volatility	Level 2 input		110.0	%
Risk-free rate (warrants)	Level 1 input		1.27	%
Risk-free rate (claim date)	Level 1 input		0.55	%
Risk-free rate (claim date extended)	Level 1 input		0.70	%
Dividend yield	Level 2 input		0.0	%

XML

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies [Abstract]

Schedule Of Contractual Commitments

	Payments Due by Period
			Less than
	Total		1 Year		1 - 2 Years		3-4 Years		After 4 Years
	(in thousands)
Obligations:
Oil and  natural gas activities	$	4,520	$	1,130	$	1,130	$	1,130	$	1,130
Office leases		171		157		14		—		—
Total contractual obligations	$	4,691	$	1,287	$	1,144	$	1,130	$	1,130

XML

Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Taxes [Abstract]

Tax Effects of Significant Items of Deferred Income Taxes

	As of  December 31,
		2015			2014
	Foreign		United States and Other		Foreign		United States and Other
	(in thousands)
Deferred tax assets:
Operating loss carryforwards	$	50,974	$	13,547	$	54,722	$	8,718
Stock-based compensation		—		3,471		—		6,479
Accrued compensation		—		653		—		376
Oil and natural gas properties		26,065		—		18,515		—
Investment in affiliate		130,088		—		88,913		—
Alternative minimum tax credit		—		2,545		—		4,299
Other		—		89		—		81
Total deferred tax assets		207,127		20,305		162,150		19,953
Deferred tax liabilities:
Tax on unremitted earnings of foreign subsidiaries		—		—		—		(14,700)
Other liabilities		(1,111)		(278)		—		(141)
Fixed assets		—		(3)		—		(3)
Total deferred tax liabilities		(1,111)		(281)		—		(14,844)
Net deferred tax asset (liability)		206,016		20,024		162,150		5,109
Valuation allowance		(205,896)		(20,024)		(162,097)		(19,809)
Net deferred tax asset (liability) after valuation allowance	$	120	$	—	$	53	$	(14,700)

Components of Loss from Continuing Operations Before Income Taxes

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Income (loss) before income taxes
United States	$	1,457	$	(12,809)	$	(31,072)
Foreign		(198,537)		(438,589)		(40,725)
Total	$	(197,080)	$	(451,398)	$	(71,797)

Provision (Benefit) for Income Taxes on Continuing Operations

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Current:
United States	$	(1,755)	$	(87)	$	2,279
Foreign		32		47		44
		(1,723)		(40)		2,323
Deferred:
United States		(14,700)		(58,250)		72,971
Foreign		—		—		(2,207)
		(14,700)		(58,250)		70,764
	$	(16,423)	$	(58,290)	$	73,087

Income Tax Expense (Benefit) on Continuing Operations at Federal Statutory Rate

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Income tax expense (benefit) from continuing operations:
Tax expense (benefit) at U.S. statutory rate	$	(68,978)	$	(157,989)	$	(25,129)
Effect of foreign source income and rate differentials on foreign income		(10,870)		38,198		204
Tax gain associated with sale of interest in Harvest Holding		—		—		7,474
Subpart F income		—		—		16,615
Non-deductible interest		11,397		—		—
Tax on unremitted earnings of foreign subsidiaries		(14,700)		(75,200)		89,900
Expired losses		24,554		2,778		1,356
Other changes in valuation allowance		44,014		129,480		(10,643)
Change in applicable statutory rate		—		—		(404)
Other permanent differences		—		2,010		(2,546)
Return to accrual and other true-ups		11,823		1,955		2,919
Debt exchange		(12,079)		—		—
Warrant derivatives		(1,685)		(684)		(1,180)
Liability for uncertain tax positions		67		(30)		(5,553)
Other		34		1,192		74
Total income tax expense (benefit) – continuing operations	$	(16,423)	$	(58,290)	$	73,087

Net Operating Losses Available for Carryforward

United States	$	38,707	Available for up to 20 years from 2012
Gabon		22,269	Available for up to 3 years from 2013
The Netherlands		157,695	Available for up to 9 years from 2007
Venezuela		7,274	Available for up to 3 years from 2013

Primary Income Tax Jurisdictions and Respective Open Audit Years

Tax Jurisdiction	Open Audit Years
United States	2012 – 2015
The Netherlands	2013 – 2015
Venezuela	2010 – 2015

Changes in Reserve for Unrecognized Tax Benefits

	Year Ended December 31,
	2015		2014
	(in thousands)
Balance at beginning of year	$	288	$	318
Additions for tax positions of prior years		—		—
Reductions for tax positions of prior years		(168)		(30)
Balance at end of year	$	120	$	288

XML

Stock-Based Compensation and Stock Purchase Plans (Tables)

12 Months Ended

Dec. 31, 2015

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Summary of Compensation Expense (Income)

	As of December 31,
Employee Stock-Based Compensation	2015		2014		2013
	(in thousands)
Equity based awards:
Stock options	$	2,003	$	2,073	$	2,119
Restricted stock		135		579		927
RSUs		133		—		—
Total expense related to equity based awards		2,271		2,652		3,046
Liability based awards:
SARs		(260)		(1,237)		(247)
RSUs		12		197		(534)
Total expense related to liability based awards		(248)		(1,040)		(781)
Total compensation expense	$	2,023	$	1,612	$	2,265

Summary of Stock Option Activity

Options	Outstanding	Weighted- Average Exercise Price			Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)
Options outstanding as of December 31, 2014	4,536	$	7.81		2.0	$	—
Granted	4,375		1.13	(1)			—
Exercised	—		—
Cancelled	(1,769)		(9.85)
Options outstanding as of December 31, 2015	7,142		3.21		3.5		—
Options exercisable as of December 31, 2015	2,011	$	7.16		1.5		—

(1) These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE in addition to the ratable vesting over a three year period.

Summary of Value of Option Grant Estimated on Date of Grant

	As of December 31,
For options granted during:	2015			2014			2013
Weighted average fair value	$	0.43		$	2.97		$	3.06
Weighted average expected life		4.7 years			5 years			5 years
Expected volatility (1)		100	%		76.7	%		79.4	%
Risk-free interest rate		1.7	%		1.5	%		1.3	%
Suboptimal exercise factor (2)		2.5			—			—
Weighted average pre-vest forfeiture rate		1.1	%		1.0	%		1.2	%
Dividend yield		0.0	%		0.0	%		0.0	%

(1) Expected volatilities are based on historical volatilities of our stock.

(2) A suboptimal exercise factor of 2.5 means that exercise is generally expected to occur when the share price reaches 2.5 times the award’s exercise price.

Summary of Restricted Stock Awards

Restricted Stock	Outstanding		Weighted- Average Grant-Date Fair Value
	(in thousands)
Unvested as of December 31, 2014	86	$	4.82
Granted	—		—
Vested	(2)		(5.85)
Forfeited	—		—
Unvested as of December 31, 2015	84	$	4.80

SAR Award Transactions Under Employee Compensation Plans

SARs	Outstanding	Weighted- Average Exercise Price			Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)
SARS outstanding as of December 31, 2014	1,123	$	4.95		2.2	$	—
Granted	5,062		1.13	(1)	5.0		—
Cancelled	(3,528)		(1.13)	(1)
Expired	(86)		(5.12)
SARS outstanding as of December 31, 2015	2,571		2.67		3.3		—
SARS exercisable as of December 31, 2015	966	$	4.95		1.3		—

(1) These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE in addition to the ratable vesting over a three year period.

Summary of RSU Awards

RSUs	Outstanding		Weighted- Average Fair Value
	(in thousands)
Unvested as of December 31, 2014	905	$	1.81
Granted	1,891		0.73
Vested	(326)		(1.50)
Forfeited	—		—
Unvested as of December 31, 2015 (1)	2,470	$	0.52

1) At December 31, 2015, unvested RSUs of 1.6 million and 0.9 million were accounted for as equity and liability awards, respectively.

Stock Options [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Summary of Unvested Awards

Unvested Stock Options	Outstanding		Weighted- Average Grant-Date Fair Value
	(in thousands)
Unvested as of December 31, 2014	1,876	$	3.85
Granted	4,375		0.43
Vested	(645)		(2.99)
Expired	(475)		(6.38)
Unvested as of December 31, 2015	5,131	$	0.81

Stock Appreciation Rights [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Summary of Unvested Awards

Unvested SARs	Outstanding		Weighted- Average Fair Value
	(in thousands)
Unvested as of December 31, 2014	339	$	0.51
Granted	5,062		0.32
Vested	(264)		(0.06)
Cancelled	(3,528)		(0.35)
Expired	(4)		(0.05)
Unvested as of December 31, 2015	1,605	$	0.21

Summary of Fair Value of Awards Granted

	Fair Value
	Hierarchy	As of December 31,
	Level	2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	0.43
Exercise price	Level 1 input	$	1.13
Threshold price	Level 1 input	$	2.50
Suboptimal exercise factor	Level 3 input		2.5
Term (years)			4.56
Volatility	Level 2 input		105.0	%
Risk-free rate	Level 1 input		1.66	%
Dividend yield	Level 2 input		0.0	%

Restricted Stock Units [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Summary of Fair Value of Awards Granted

	Fair Value
	Hierarchy	As of December 9,
	Level	2015
Significant assumptions (or ranges):
Stock price	Level 1 input	$	0.63
Threshold price	Level 1 input	$	2.50
Term (years)			10.0
Volatility	Level 2 input		80.0	%
Risk-free rate	Level 1 input		2.27	%
Dividend yield	Level 2 input		0.0	%

XML

Operating Segments (Tables)

12 Months Ended

Dec. 31, 2015

Operating Segments [Abstract]

Schedule of Segment Income (Loss) Attributable to Harvest

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Segment Loss Attributable to Harvest
Venezuela		(83,953)		(171,801)		58,640
Gabon		(28,448)		(55,564)		(12,908)
Indonesia		(43)		(9,558)		(9,213)
United States and other		13,874		43,987		(120,465)
Loss from continuing operations(a)		(98,570)		(192,936)		(83,946)
Discontinued operations		—		(554)		(5,150)
Net loss attributable to Harvest	$	(98,570)	$	(193,490)	$	(89,096)

(a) Net of net income attributable to noncontrolling interest owners.

Schedule of Operating Segment Assets

	As of December 31,
	2015		2014
	(in thousands)
Operating Segment Assets
Venezuela	$	5,290	$	165,214
Gabon		32,710		60,051
Indonesia		5		176
United States and other		9,776		2,602
		47,781		228,043
Discontinued operations		—		3
Total assets	$	47,781	$	228,046

XML

Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Data [Abstract]

Summarized Quarterly Financial Data

	Quarter Ended
	March 31		June 30		September 30		December 31
	(amounts in thousands, except for share data)
Year ended December 31, 2015
Expenses (1)	$	(6,119)		(6,119)		(6,767)		(192,891)
Non-operating gain (loss)		(234)		(17,964)		10,335		22,679
Income (loss) from continuing operations before income taxes		(6,353)		(24,083)		3,568		(170,212)
Income tax expense (benefit)		(384)		1,604		(1,850)		(15,793)
Income (loss) from continuing operations		(5,969)		(25,687)		5,418		(154,419)
Less: Net loss attributable to noncontrolling interest owners		(352)		(262)		(294)		(81,179)
Net income (loss) attributable to Harvest	$	(5,617)	$	(25,425)	$	5,712	$	(73,240)
Basic Earnings (Loss) per Share:
Income (loss) from continuing operations	$	(0.13)	$	(0.60)	$	0.13	$	(1.42)
Net income (loss) attributable to Harvest	$	(0.13)	$	(0.60)	$	0.13	$	(1.42)
Diluted Earnings (Loss) per Share:
Income (loss) from continuing operations	$	(0.13)	$	(0.60)	$	0.13	$	(1.42)
Net income (loss) attributable to Harvest	$	(0.13)	$	(0.60)	$	0.13	$	(1.42)

	Quarter Ended
	March 31		June 30		September 30		December 31
	(amounts in thousands, except for share data)
Year ended December 31, 2014
Expenses (2)	$	(12,670)	$	(9,759)	$	(4,977)	$	(422,199)
Non-operating gain (loss)		(6,447)		(147)		3,067		1,734
Loss from continuing operations before income taxes		(19,117)		(9,906)		(1,910)		(420,465)
Income tax expense (benefit)		(954)		(88)		2,361		(59,609)
Loss from continuing operations		(18,163)		(9,818)		(4,271)		(360,856)
Earnings (loss) from investment in affiliate		18,887		16,062		—		—
Income (loss) from continuing operations		724		6,244		(4,271)		(360,856)
Discontinued operations		(131)		(230)		(142)		(51)
Net income (loss)		593		6,014		(4,413)		(360,907)
Less: Net income (loss) attributable to noncontrolling interest owners		8,601		7,665		(273)		(181,216)
Net income (loss) attributable to Harvest	$	(8,008)	$	(1,651)	$	(4,140)	$	(179,691)
Basic Earnings (Loss) per Share:
Income (loss) from continuing operations	$	0.19	$	(0.03)	$	(0.10)	$	(4.23)
Discontinued operations		—		(0.01)		—		—
Net income (loss) attributable to Harvest	$	0.19	$	(0.04)	$	(0.10)	$	(4.23)
Diluted Earnings (Loss) per Share:
Income (loss) from continuing operations	$	0.19	$	(0.03)	$	(0.10)	$	(4.23)
Discontinued operations		—		(0.01)		—		—
Net income (loss) attributable to Harvest	$	0.19	$	(0.04)	$	(0.10)	$	(4.23)

(1) Includes $164.7 million impairment during the quarter ended December 31, 2015 related to our investment in Petrodelta and $24.2 million impairment of oil and natural gas properties (including oilfield inventory) for Dussafu PSC.  See Note 6 – Investment in Affiliate and Note 8- Gabon.

(2) Includes $355.7 million impairment during the quarter ended December 31, 2014 related to our investment in Petrodelta, $13.8 million allowance for doubtful accounts for long-term receivable – investment in affiliate, and $50.3 million impairment of oil and natural gas properties for Dussafu PSC.  See Note 6 – Investment in Affiliate and Note 8- Gabon.

XML

Organization (Details)			12 Months Ended
	Dec. 16, 2013 USD ($) item	Dec. 15, 2013	Dec. 31, 2015 USD ($) property $ / shares shares	Dec. 31, 2014 USD ($) shares	Dec. 31, 2013 USD ($)	Apr. 01, 2015	Mar. 31, 2015	Jan. 15, 2015
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net proceeds from sale of interest in investment in affiliate					$ 124,045,000
Loss on the sale of interest in Harvest Holding				$ (1,574,000)	$ (22,994,000)
Convertible senior secured note converted			$ 13,175,000
Accrued interest			$ 954,000	$ 97,000
Common stock, shares authorized | shares			150,000,000	80,000,000
CT Energy [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Gross proceeds from sale of securities			$ 32,200,000
Shares issuable upon warrant conversion | shares			34,070,820
Warrant exercise price per share | $ / shares			$ 1.25
Threshold price per share | $ / shares			$ 2.50
CT Energy [Member] | 15% Note [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Promissory note			$ 25,200,000
Debt term			5 years
Interest rate			15.00%
Commencement date of quarterly interest payment			Oct. 01, 2015
Threshold price per share | $ / shares			$ 2.50
Addition default interest rate			2.00%
CT Energy [Member] | 9% Note [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Debt term			5 years
Interest rate			9.00%
Commencement date of quarterly interest payment			Oct. 01, 2015
Convertible senior secured note			$ 7,000,000
Convertible senior secured note converted			7,000,000
Accrued interest			$ 100,000
Common stock converted from convertible senior secured note | shares			8,667,597
Conversion price per share | $ / shares			$ 0.82
Threshold price per share | $ / shares			$ 2.50
CT Energy [Member] | Additional Draw Note [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Debt term			5 years
Interest rate			15.00%
Commencement date of quarterly interest payment			Oct. 01, 2016
Threshold price per share | $ / shares			$ 2.50
Potential additional periodic borrowing availability			$ 2,000,000
Period additional draw may be utilized			6 months
Period after transaction additional funds become available			1 year
Potential additional borrowing availability			$ 12,000,000
Addition default interest rate			2.00%
Petroandina [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Interest rate						13.00%	11.00%
Commencement date of quarterly interest payment			Dec. 31, 2014
Debt extension term			1 month
Harvest Holding [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership interest before "Share Purchase Agreement"		80.00%
Number of closings of equity interest | item	2
Aggregate cash purchase price	$ 400,000,000
Harvest Holding [Member] | First Closing [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership interest in subsidiary sold	29.00%
Ownership interest after "Share Purchase Agreement"	51.00%
Ownership interest held by noncontrolling interest owners	49.00%
Harvest Holding [Member] | Vinccler [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership interest held by noncontrolling interest owners		20.00%	20.00%
Harvest Holding [Member] | Vinccler [Member] | First Closing [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership interest held by noncontrolling interest owners	20.00%
Harvest Holding [Member] | Petroandina [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership interest held by noncontrolling interest owners			29.00%
Harvest Holding [Member] | Petroandina [Member] | First Closing [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership interest held by noncontrolling interest owners	29.00%
Harvest Holding [Member] | CT Energy [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership percentage			16.60%
HNR Finance [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Indirect ownership percentage			100.00%
Petrodelta [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership interest before "Share Purchase Agreement"		32.00%
Ownership interest after "Share Purchase Agreement"			20.40%
Indirect ownership percentage								51.00%
Indirect ownership percentage			40.00%
Number of oil fields | property			6
Petrodelta [Member] | CVP [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership percentage			56.00%
Petrodelta [Member] | PDVSA [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership percentage			4.00%
Harvest Vinccler [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Indirect ownership percentage			100.00%
CVP And PDVSA [Member] | PDVSA [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership percentage			100.00%
Series C Preferred Stock [Member] | CT Energy [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Mezzanine equity, shares issued | shares			69.75
Mezzanine equity, par value | $ / shares			$ 0.01
Trigger Price Not Met [Member] | CT Energy [Member] | 15% Note [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Interest rate			8.00%
Debt extension term			2 years
Trigger Price Not Met [Member] | CT Energy [Member] | 9% Note [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Interest rate			8.00%
Debt extension term			2 years
Trigger Price Not Met [Member] | CT Energy [Member] | Additional Draw Note [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Interest rate			8.00%
Debt extension term			2 years

XML

Summary of Significant Accounting Policies (Narrative) (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2015 USD ($) bbl	Dec. 31, 2014 USD ($) bbl	Dec. 31, 2013 USD ($) bbl
Summary Of Significant Accounting Policies [Line Items]
Pre-tax cost impairment charge		$ 164,700
Pre-tax equity impairment charge			$ 355,650
Restricted cash			25
Depletion expense		$ 0	$ 0	$ 0
Production of proved oil and natural gas properties | bbl		0	0	0
Dry hole costs		$ 0	$ 0	$ 0
Proved oil and natural gas properties	$ 0	0	0	0
Impairment of oil and natural gas property		24,178	57,994	3,770
Impairment expense		24,178	57,994	575
Impairment of oilfied inventories	1,000	1,000
Depreciation expense		108	198	341
Allowance for doubtful accounts		734	13,753
Receivable from joint venture partners	$ 400	400
Capitalized interest costs		$ 0	500	8,300
9% Note [Member] | CT Energy [Member]
Summary Of Significant Accounting Policies [Line Items]
Interest rate	9.00%	9.00%
15% Note [Member] | CT Energy [Member]
Summary Of Significant Accounting Policies [Line Items]
Interest rate	15.00%	15.00%
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Prepaid expenses recognition term		12 months
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Prepaid expenses recognition term		24 months
Accrued Liabilities [Member] | Recurring [Member]
Summary Of Significant Accounting Policies [Line Items]
Obligations			800
Stock Appreciation Rights [Member] | Recurring [Member]
Summary Of Significant Accounting Policies [Line Items]
Obligations	$ 96	$ 96	356
Restricted Stock Units [Member] | Recurring [Member]
Summary Of Significant Accounting Policies [Line Items]
Obligations	174	$ 174	652
Restricted Stock Units [Member] | Accrued Liabilities [Member] | Recurring [Member]
Summary Of Significant Accounting Policies [Line Items]
Obligations			400
Restricted Stock Units [Member] | Long-Term Liabilities [Member] | Recurring [Member]
Summary Of Significant Accounting Policies [Line Items]
Obligations			200
Dussafu PSC [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and natural gas property	$ 23,200		50,300
Budong PSC [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and natural gas property			7,700
Furniture, Fixtures and Equipment [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives		3 years
Furniture, Fixtures and Equipment [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives		5 years
Colombia [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and natural gas property				$ 3,200
United States And Other [Member]
Summary Of Significant Accounting Policies [Line Items]
Deferred tax liability on undistributed earnings of foreign subsidiaries			$ 14,700

XML

Summary of Significant Accounting Policies (Major Components of Property and Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Summary of Significant Accounting Policies [Abstract]
Unproved property costs - Dussafu PSC	$ 28,000	$ 50,324
Oilfield inventories	3,006	3,966
Other administrative property	2,937	2,670
Total property and equipment	33,943	56,960
Accumulated depreciation	(2,482)	(2,453)
TOTAL PROPERTY AND EQUIPMENT, net	$ 31,461	$ 54,507

XML

Summary of Significant Accounting Policies (Schedule of Other Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Summary of Significant Accounting Policies [Abstract]
Deposits and long-term prepaid expenses	$ 142	$ 101
Deferred financing costs		283
Gabon - blocked payment		1,100
Other assets	$ 142	$ 1,484

XML

Summary of Significant Accounting Policies (Schedule of Fair Value Hierarchy of Financial Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Dussafu PSC	$ 28,000	$ 50,324
Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment in affiliate		164,700
Dussafu PSC	$ 28,000	50,324
Assets, fair value	28,000	215,024
Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, fair value	5,010
Liabilities, fair value	5,773	1,008
Recurring [Member] | Warrants [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	5,503
Recurring [Member] | Embedded Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5,010
Recurring [Member] | Stock Appreciation Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Obligations	96	356
Recurring [Member] | Restricted Stock Units [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Obligations	$ 174	$ 652
Level 1 Input [Member] | Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment in affiliate
Dussafu PSC
Assets, fair value
Level 1 Input [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, fair value
Liabilities, fair value
Level 1 Input [Member] | Recurring [Member] | Warrants [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities
Level 1 Input [Member] | Recurring [Member] | Embedded Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets
Level 1 Input [Member] | Recurring [Member] | Stock Appreciation Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Obligations
Level 1 Input [Member] | Recurring [Member] | Restricted Stock Units [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Obligations
Level 2 Input [Member] | Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment in affiliate
Dussafu PSC
Assets, fair value
Level 2 Input [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, fair value	$ 220	$ 1,008
Level 2 Input [Member] | Recurring [Member] | Stock Appreciation Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Obligations	46	356
Level 2 Input [Member] | Recurring [Member] | Restricted Stock Units [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Obligations	$ 174	652
Level 3 Input [Member] | Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment in affiliate		164,700
Dussafu PSC	$ 28,000	50,324
Assets, fair value	28,000	$ 215,024
Level 3 Input [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, fair value	5,010
Liabilities, fair value	5,553
Level 3 Input [Member] | Recurring [Member] | Warrants [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	5,503
Level 3 Input [Member] | Recurring [Member] | Embedded Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5,010
Level 3 Input [Member] | Recurring [Member] | Stock Appreciation Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Obligations	$ 50
Level 3 Input [Member] | Recurring [Member] | Restricted Stock Units [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Obligations

XML

Summary of Significant Accounting Policies (Reconciliation of Financial Assets and Liabilities Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Warrants [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Beginning balance, liabilities		$ 1,953	$ 5,470
Additions - fair value at issuance, liabilities	$ 40,013
Change in fair value, liabilities	(34,510)	$ (1,953)	$ (3,517)
Ending balance, liabilities	$ 5,503		$ 1,953
Stock Appreciation Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Beginning balance, liabilities
Additions - fair value at issuance, liabilities
Change in fair value, liabilities	$ 50
Ending balance, liabilities	$ 50
Embedded Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Beginning balance, assets
Additions - fair value at issuance, assets	$ 2,504
Change in fair value, assets	2,506
Ending balance, assets	$ 5,010
Beginning balance, liabilities
Additions - fair value at issuance, liabilities	$ 13,449
Change in fair value, liabilities	(2,307)
Conversion of debt, liabilities	$ (11,142)
Ending balance, liabilities

XML

Summary of Significant Accounting Policies (Schedule of Changes in Noncontrolling Interest Owners) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary of Significant Accounting Policies [Abstract]
Balance at beginning of period				$ 79,152				$ 243,167	$ 79,152	$ 243,167	$ 97,101
Contributions by noncontrolling interest owners									3,382	1,208
Increase in equity held by noncontrolling interest owner											144,796
Dividend to noncontrolling interest owner											(10,370)
Net income (loss) attributable to noncontrolling interest owners	$ (81,179)	$ (294)	$ (262)	$ (352)	$ (181,216)	$ (273)	$ 7,665	$ 8,601	(82,087)	(165,223)	11,640
Balance at end of period	$ 447				$ 79,152				$ 447	$ 79,152	$ 243,167

XML

Summary of Significant Accounting Policies (Schedule of Valuation and Qualifying Accounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Valuation and Qualifying Accounts Disclosure [Line Items]
Dividend receivable reserved	$ 734		$ 13,753
Long-term receivable reserved	2,122		(1,623)		$ (993)
Deferred Tax Valuation Allowance [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Year	$ 181,906		59,576		$ 68,419
Charged to Income			129,480
Other	$ 44,014		$ (7,150)	[1]
Deductions From Reserves Credited to Income					$ (8,843)
Balance at End of Period	$ 225,920		$ 181,906		59,576
Investment Valuation Allowance [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Year	$ 1,350		$ 1,350		$ 1,350
Charged to Income
Other
Deductions From Reserves Credited to Income
Balance at End of Period	$ 1,350		$ 1,350		$ 1,350
VAT Valuation Allowance [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Year	$ 2,792		$ 2,792
Charged to Income					$ 2,792
Other	$ (2,792)	[2]
Deductions From Reserves Credited to Income
Balance at End of Period	$ 2,792		$ 2,792		$ 2,792
Long-Term Receivable - Investment In Affiliate [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Year	$ 13,753
Charged to Income			$ 13,753	[3]
Other
Deductions From Reserves Credited to Income
Balance at End of Period	$ 13,753		$ 13,753
Petrodelta [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Dividend receivable reserved			$ 12,200

[1] Attributable to reversal of temporary differences related to discontinued operations.

[2] Valuation allowance for the VAT receivable associated with Harvest Budong. On May 4, 2015, the Company sold the shares of Harvest Budong-Budong B.V. to Stockbridge Capital Limited and the rights to the VAT receivable went with the entity to the buyer.

[3] During the year ended December 31, 2014, we fully reserved a dividend receivable of $12.2 million and $1.6 million of long-term receivable due from our investment in affiliate.

XML

Earnings Per Share (Narrative) (Details) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share		200,000	300,000
Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	4,100,000	4,500,000	4,200,000
Warrants [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share		2,500,000	2,500,000
Restricted Stock Units [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	1,600,000
CT Energy [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Shares issuable upon warrant conversion	34,070,820

XML

Earnings Per Share (Schedule of Earnings Per Share) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Earnings Per Share [Abstract]
Loss from continuing operations	[1]									$ (98,570)		$ (192,936)		$ (83,946)
DISCONTINUED OPERATIONS						$ (51)	$ (142)	$ (230)	$ (131)			(554)		(5,150)
NET LOSS AND COMPREHENSIVE LOSS ATTRIBUTABLE TO HARVEST		$ (73,240)	$ 5,712	$ (25,425)	$ (5,617)	$ (179,691)	$ (4,140)	$ (1,651)	$ (8,008)	$ (98,570)		$ (193,490)		$ (89,096)
Weighted average common shares outstanding										45,288		42,039		39,579
Weighted average common shares, diluted										45,288		42,039		39,579
Loss from continuing operations		$ (1.42)	$ 0.13	$ (0.60)	$ (0.13)	$ (4.23)	$ (0.10)	$ (0.03)	$ 0.19	$ (2.18)	[1]	$ (4.59)	[1]	$ (2.12)	[1]
Discontinued operations								(0.01)				(0.01)		(0.13)
Basic loss per share		(1.42)	0.13	(0.60)	(0.13)	(4.23)	(0.10)	(0.04)	0.19	(2.18)		(4.60)		(2.25)
Loss from continuing operations		(1.42)	0.13	(0.60)	(0.13)	(4.23)	(0.10)	(0.03)	0.19	(2.18)	[1]	(4.59)	[1]	(2.12)	[1]
Discontinued operations								(0.01)				(0.01)		(0.13)
Diluted loss per share		$ (1.42)	$ 0.13	$ (0.60)	$ (0.13)	$ (4.23)	$ (0.10)	$ (0.04)	$ 0.19	$ (2.18)		$ (4.60)		$ (2.25)

[1] Net of net income attributable to noncontrolling interest owners.

XML

Dispositions (Narrative) (Details) $ in Thousands			1 Months Ended	3 Months Ended				12 Months Ended
	Dec. 16, 2013 USD ($) item	Dec. 15, 2013	Feb. 28, 2013	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Jan. 15, 2015
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Net proceeds from sale of interest in investment in affiliate										$ 124,045
Loss on the sale of interest in Harvest Holding									$ (1,574)	(22,994)
Proceeds from issuance of note payable to noncontrolling interest owner									7,600
Proceeds from sale of WAB-21 area									2,865
Loss from discontinued operations				$ (51)	$ (142)	$ (230)	$ (131)		(554)	(5,150)
Exploration expense								$ 3,900	6,267	15,155
General and administrative expenses								19,010	29,496	29,365
Impairment of oil and natural gas property								$ 24,178	57,994	3,770
Harvest Holding [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Ownership interest before "Share Purchase Agreement"		80.00%
Number of closings of equity interest | item	2
Aggregate cash purchase price	$ 400,000
Harvest Holding [Member] | First Closing [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Ownership interest in subsidiary sold	29.00%
Ownership interest after "Share Purchase Agreement"	51.00%
Ownership interest held by noncontrolling interest owners	49.00%
Harvest Holding [Member] | Second Closing [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Aggregate cash purchase price	$ 275,000
Ownership interest in subsidiary sold	51.00%
Harvest Holding [Member] | Vinccler [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Ownership interest held by noncontrolling interest owners		20.00%						20.00%
Harvest Holding [Member] | Vinccler [Member] | First Closing [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Ownership interest held by noncontrolling interest owners	20.00%
Harvest Holding [Member] | Petroandina [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Ownership interest held by noncontrolling interest owners								29.00%
SPA term								120 days
SPA incremental extension term								1 month
SPA maximum incremental borrowing									2,000
SPA outstanding loans payable term following termination date								1 year
Harvest Holding [Member] | Petroandina [Member] | First Closing [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Ownership interest held by noncontrolling interest owners	29.00%
Petrodelta [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Ownership interest before "Share Purchase Agreement"		32.00%
Ownership interest after "Share Purchase Agreement"								20.40%
Indirect ownership percentage											51.00%
Venezuela [Member] | Petroandina [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Indirect ownership percentage	60.00%							60.00%
Oman [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Loss from discontinued operations									(27)	(674)
Colombia [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Loss from discontinued operations									(527)	(4,476)
Farm-down agreements, working interest percentage			75.00%
Partners carried interest for the minimum exploratory work commitment			25.00%
Accrued settlement costs										2,000
Impairment of oil and natural gas property										3,200
Arbitration settlement									$ 2,000
Discontinued Operations [Member] | Oman [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Exploration expense										200
General and administrative expenses										500
Discontinued Operations [Member] | Colombia [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Exploration expense										700
General and administrative expenses										$ 600

XML

Dispositions (Schedule of Discontinued Operations Expenses) (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues from discontinued operations					$ 0	$ 0	$ 0
Loss from Discontinued Operations	$ (51)	$ (142)	$ (230)	$ (131)		(554)	(5,150)
Oman [Member]
Loss from Discontinued Operations						(27)	(674)
Colombia [Member]
Loss from Discontinued Operations						$ (527)	$ (4,476)

XML

Investment in Affiliate (Narrative) (Details) $ in Thousands					3 Months Ended		12 Months Ended
	May. 01, 2014	Dec. 16, 2013 USD ($) item	Dec. 15, 2013	Oct. 01, 2013	Dec. 31, 2014 USD ($) VEF / $	Dec. 31, 2013 USD ($)	Dec. 31, 2015 USD ($) item $ / Mcf VEF / $	Dec. 31, 2014 USD ($) VEF / $	Dec. 31, 2013 USD ($)	Feb. 28, 2013 VEF / $	Nov. 12, 2010 USD ($)
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net proceeds from sale of interest in investment in affiliate									$ 124,045
Pre-tax equity impairment charge								$ 355,650
Cost investment in affiliate					$ 164,700			164,700
Pre-tax cost impairment charge							$ 164,700
Allowance recorded							734	13,753
Uninvoiced revenues								1,207,200	756,700
Previously uninvoiced revenue recognized					98,600
Outstanding receivables reversed							$ 2,122	(1,623)	(993)
Percentage increase in salary	23.00%			59.00%			90.00%
Petrodelta [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Indirect ownership percentage							40.00%
Ownership interest before "Share Purchase Agreement"			32.00%
Ownership interest after "Share Purchase Agreement"							20.40%
Number of scenarios related to future development of proved, probable and possible reserves and other net liabilities | item							3
Number of price forecasts for crude oil | item							3
Weighted average cost of capital							26.50%
Allowance recorded								12,200
Reclassification amount								13,888
Winfall tax credit, gross								(55,168)	55,168
Windfall tax credit, net of tax								(36,400)
VAT receivable							$ 153,700
Value added tax receivable, allowance							$ 38,200
VAT receivable, net					$ 64,100			$ 64,100
Valuation allowance assumption, term							5 years
Valuation allowance assumption, discount rate							24.00%
Sports Law contribution percentage of annual net or accounting profit							1.00%
Hydrocarbon contract term							20 years
Participation required for decision making process							75.00%
Contract price per MCF | $ / Mcf							1.54
Payment period of each invoice following end of invoiced production month							60 days
Exchange rate | VEF / $					6.3			6.3		4.3
Revaluation of non-income tax related assets and liabilities								$ (260)	$ 169,582
Exchange rate remeasurement | VEF / $					50.0		198.70	50.0
Foreign currency loss						$ 14,200
Dividends declared, date							Nov. 12, 2010
Dividends declared											$ 30,600
Petrodelta [Member] | HNR Finance [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Dividends declared											$ 12,200
Harvest Holding [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership interest before "Share Purchase Agreement"			80.00%
Number of closings for sale of shares | item		2
Aggregate cash purchase price		$ 400,000
Harvest Holding [Member] | First Closing [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Ownership interest in subsidiary sold		29.00%
Ownership interest after "Share Purchase Agreement"		51.00%
Ownership interest held by noncontrolling interest owners		49.00%

XML

Investment in Affiliate (Schedule of Changes in Investment in Affiliate) (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Investment in Affiliate [Abstract]
Equity investment in affiliate					$ 485,401
Cost investment in affiliate				$ 164,700
Equity in earnings	$ 16,062	$ 18,887		34,949	$ 72,578
Equity impairment				$ (355,650)
Cost impairment			$ (164,700)

XML

Investment in Affiliate (Summary of Financial Information) (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
Adjustments to increase (decrease) net income under IFRS:
Earnings from investment affiliate included Harvest's income	$ 16,062	$ 18,887	$ 34,949	$ 72,578
Petrodelta [Member]
Revenues:
Oil sales			1,343,452	1,326,093
Natural gas sales			4,590	4,000
Royalty			(437,281)	(440,963)
Total revenues			910,761	889,130
EXPENSES:
Operating expenses			303,409	141,627
Workovers			28,239	29,168
Depletion, depreciation and amortization			129,409	87,203
General and administrative			45,623	37,778
Windfall profits tax			140,816	234,453
Windfall profits (credit) and reversal of credit			55,168	(55,168)
Total expenses			702,664	475,061
Income from operations			208,097	414,069
Gain (loss) on exchange rate			(260)	169,582
Investment earnings and other			7,752	1,414
Interest expense			137	(21,728)
Income before income tax			215,726	563,337
Current income tax expense			103,619	325,217
Deferred income tax expense (benefit)			(32,617)	(17,662)
Net income under IFRS			144,724	255,782
Adjustments to increase (decrease) net income under IFRS:
Deferred income tax (expense) benefit			(2,841)	9,080
Depletion expense			(12,437)	(20,353)
Adjustment to lease operating costs to conform with GAAP			13,888
Windfall profits tax credit and (reversal) of credit			55,168	(55,168)
Adjust fair value of value added tax credits			(51,393)
Sports law over accrual			1,322	1,313
Net income under U.S. GAAP			$ 148,431	$ 190,654
Interest in investment affiliate			40.00%	40.00%
Income before amortization of excess basis in investment in affiliate			$ 59,372	$ 76,262
Amortization of excess basis in investment in affiliate			(4,428)	(3,684)
Earnings from investment affiliate excluded from results of operations			(19,995)
Earnings from investment affiliate included Harvest's income			$ 34,949	$ 72,578

XML

Investment in Affiliate (Schedule of Assets and Liabilities) (Details) - Petrodelta [Member] $ in Thousands	Dec. 31, 2014 USD ($)
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Current assets	$ 1,459,676
Property and equipment	1,044,797
Other assets	241,478
Current liabilities	1,437,929
Other liabilities	147,242
Net equity	$ 1,160,780

XML

Venezuela - Other (Details) $ in Thousands, VEF in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) VEF / $	Dec. 31, 2014 USD ($) VEF / $	Dec. 31, 2013 USD ($)	Dec. 31, 2015 VEF VEF / $	Dec. 31, 2015 USD ($) VEF / $	Feb. 28, 2013 VEF / $
Schedule of Cost-method Investments [Line Items]
Foreign currency transactions gain (loss) | $	$ 261	$ (219)	$ (820)
Petrodelta [Member]
Schedule of Cost-method Investments [Line Items]
Exchange rate | VEF / $		6.3				4.3
Exchange rate remeasurement | VEF / $		50.0		198.70	198.70
Harvest Vinccler [Member]
Schedule of Cost-method Investments [Line Items]
Foreign currency average exchange rate | VEF / $	212.4	34.40
Foreign currency transactions gain (loss) | $		$ (100)
Exchange value of foreign currency to domestic currency | $	$ 100	$ 400
Assets account, balance				VEF 11.9	$ 60
Liabilities account, balance				VEF 5.5	$ 30

XML

Gabon (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2015 USD ($) ft	Dec. 31, 2015 USD ($) a item ft	Dec. 31, 2014 USD ($) item	Dec. 31, 2013 USD ($)	Dec. 31, 2011 item
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Impairment of oil and natural gas property		$ 24,178	$ 57,994	$ 3,770
Unproved property costs - Dussafu PSC	$ 28,000	28,000	50,324
Impairment of oilfied inventory	1,000	1,000
Oilfield inventory	$ 3,006	$ 3,006	$ 3,966
Dussafu PSC [Member]
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Ownership percentage		66.667%
Area covered by acquiree entity | a		680,000
Area covered bv acquiree entity under water depths | ft	1,650	1,650
Extended period of third exploration phase		4 years
Number of appraisal sidetracks | item					2
Number of discoveries | item			4
Term from approval date to begin production		4 years
Impairment of oil and natural gas property	$ 23,200		$ 50,300
Number of price scenarios | item		3
Number of development options | item		3
Weighted average cost of capital		21.50%
Farm-Out [Member] | Dussafu PSC [Member]
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Ownership percentage		50.00%

XML

Notes Payable to Noncontrolling Interest Owners (Details) - USD ($) $ in Thousands					12 Months Ended
	Nov. 27, 2014	Oct. 30, 2014	Sep. 29, 2014	Aug. 28, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Apr. 01, 2015	Mar. 31, 2015
Related Party Transaction [Line Items]
Notes payable to noncontrolling interest owners					$ 6,157
Related party debt forgiven					6,157
Proceeds from issuance of note payable to noncontrolling interest owner						$ 7,600
Accrued interest paid					$ 1,547		$ 487
Petroandina [Member]
Related Party Transaction [Line Items]
Notes payable maturity date					Jan. 01, 2016
Related party debt forgiven					$ 7,600
Debt extension term					1 month
Short-term borrowings	$ 1,600	$ 2,000	$ 2,000	$ 2,000
Commencement date of quarterly interest payment					Dec. 31, 2014
Interest rate								13.00%	11.00%
Accrued interest paid					$ 400
Vinccler [Member]
Related Party Transaction [Line Items]
Notes payable maturity date					Dec. 31, 2015

XML

Debt and Financing (Narrative) (Details)		12 Months Ended
	Jun. 19, 2015	Dec. 31, 2015 USD ($) item $ / shares shares	Dec. 31, 2014 USD ($) $ / shares	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)
Debt Instrument [Line Items]
Financing fees		$ 1,644,000	$ 311,000	$ 196,000
Loss on issuance of securities		(20,402,000)
Accretion of discount on debt		$ 225,000		$ 2,641,000
Common stock, par value | $ / shares		$ 0.01	$ 0.01
Loss on debt conversion		$ (1,890,000)
Convertible senior secured note converted		13,175,000
CT Energy [Member]
Debt Instrument [Line Items]
Proceeds from debt, net of financing fees		$ 30,600,000
Threshold price per share | $ / shares		$ 2.50
Expected remaining life of the longest instrument in the common stock transaction		7 years
CT Energy [Member] | 15% Note [Member]
Debt Instrument [Line Items]
Unamortized discount		$ 25,000,000
Interest expense		2,200,000
Stated rate of interest expense		$ 2,000,000
Effective interest rate		141.00%
Fair value of note payable		$ 8,800,000
Notes payable maturity date		Jun. 19, 2020
Debt term		5 years
Interest rate		15.00%
Promissory note		$ 25,200,000
Commencement date of quarterly interest payment		Oct. 01, 2015
Threshold price per share | $ / shares		$ 2.50
Addition default interest rate		2.00%
Make whole price, as percentage of principal		100.00%
Debt covenant, period after date of determination for measurement		2 years
Variable spread on reference rate		0.50%
Holders of principal needed to declare debt immediatele due, percent		25.00%
Period of volatility calculation		6 years
CT Energy [Member] | 15% Note [Member] | Trigger Price Not Met [Member]
Debt Instrument [Line Items]
Interest rate		8.00%
Debt extension term		2 years
CT Energy [Member] | Additional Draw Note [Member]
Debt Instrument [Line Items]
Proceeds from debt, net of financing fees		$ 0
Debt term		5 years
Interest rate		15.00%
Commencement date of quarterly interest payment		Oct. 01, 2016
Threshold price per share | $ / shares		$ 2.50
Addition default interest rate		2.00%
Holders of principal needed to declare debt immediatele due, percent		25.00%
Potential additional periodic borrowing availability		$ 2,000,000
Period additional draw may be utilized		6 months
Period after transaction additional funds become available		1 year
Potential additional borrowing availability		$ 12,000,000
CT Energy [Member] | Additional Draw Note [Member] | Trigger Price Not Met [Member]
Debt Instrument [Line Items]
Interest rate		8.00%
Debt extension term		2 years
CT Energy [Member] | 9% Note [Member]
Debt Instrument [Line Items]
Unamortized discount		$ 200,000
Notes payable maturity date		Jun. 19, 2020
Debt term		5 years
Interest rate		9.00%
Commencement date of quarterly interest payment		Oct. 01, 2015
Threshold price per share | $ / shares		$ 2.50
Convertible senior secured note		$ 7,000,000
Common stock issuable upon conversion from note | item		8,506,098
Conversion price per share | $ / shares		$ 0.82
Percent of dilution related to stock issuance		10.00%
Expected remaining life of the longest instrument in the common stock transaction		7 years
Common stock converted from convertible senior secured note | shares		8,667,597
Convertible senior secured note converted		$ 7,000,000
CT Energy [Member] | 9% Note [Member] | Trigger Price Not Met [Member]
Debt Instrument [Line Items]
Interest rate		8.00%
Debt extension term		2 years
Embedded Derivative [Member]
Debt Instrument [Line Items]
Fair value of embedded derivative assets at issuance		$ 2,504,000
Fair value of net embedded derivative liabilities at issuance		13,449,000
Fair value of embedded derivative assets		5,010,000
Derivative income related to embedded derivative assets		$ 2,506,000
Fair value of embedded derivative liabilities
Fair value of net embedded derivative liabilities prior to conversion		$ 11,142,000
Derivative income related to embedded derivative liabilities		2,307,000
Warrants [Member]
Debt Instrument [Line Items]
Fair value of net embedded derivative liabilities at issuance		40,013,000
Fair value of embedded derivative liabilities		5,503,000		$ 1,953,000	$ 5,470,000
Derivative income related to embedded derivative liabilities		$ 34,510,000	$ 1,953,000	$ 3,517,000
Level 3 Input [Member] | 15% Note [Member] | Future Draws [Member]
Debt Instrument [Line Items]
Scenario probability	50.00%	50.00%
Level 3 Input [Member] | 15% Note [Member] | No Future Draws [Member]
Debt Instrument [Line Items]
Scenario probability	50.00%	50.00%

XML

Debt and Financing (Schedule of Long-Term Debt) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Proceeds from note payable to CT Energy		$ 7,600
Repayment of note payable to CT Energy			$ (4,260)
Accretion of discount on debt	$ 225		$ 2,641
Long-term debt due to related party, net of discount	214
Embedded Derivative [Member]
Related Party Transaction [Line Items]
Conversion of 9% Note, net of unamortized discount	(11,142)
CT Energy [Member]
Related Party Transaction [Line Items]
Proceeds from 9% and 15% Notes to CT Energy	32,200
Proceeds from note payable to CT Energy	1,300
Repayment of note payable to CT Energy	(1,300)
Value assigned to embedded derivatives	$ (32,200)
CT Energy [Member] | 9% Note [Member]
Related Party Transaction [Line Items]
Interest rate	9.00%
CT Energy [Member] | 15% Note [Member]
Related Party Transaction [Line Items]
Interest rate	15.00%

XML

Debt and Financing (Schedule of Fair Value Assumptions-15% Notes) (Details) - 15% Note [Member] - $ / shares		12 Months Ended
	Jun. 19, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Weighted Term (years)	5 years	4 years 5 months 19 days
Level 1 Input [Member]
Debt Instrument [Line Items]
Stock price	$ 1.82	$ 0.43
Level 1 Input [Member] | Minimum [Member]
Debt Instrument [Line Items]
Risk-free rate	1.60%	1.60%
Level 1 Input [Member] | Maximum [Member]
Debt Instrument [Line Items]
Risk-free rate	2.00%	2.00%
Level 2 Input [Member]
Debt Instrument [Line Items]
Yield Volatility	32.50%	35.00%
Dividend yield	0.00%	0.00%
Level 3 Input [Member] | Claim Date Extended With Stock Appreciation Date Threshold Met [Member]
Debt Instrument [Line Items]
Scenario probability	60.00%	54.80%
Level 3 Input [Member] | Claim Date Extended With Stock Appreciation Date Threshold Not Met [Member]
Debt Instrument [Line Items]
Scenario probability	42.50%	36.10%
Level 3 Input [Member] | Claim Date Not Extended With Stock Appreciation Date Threshold Met [Member]
Debt Instrument [Line Items]
Scenario probability	60.00%	54.80%
Level 3 Input [Member] | Claim Date Not Extended With Stock Appreciation Date Threshold Not Met [Member]
Debt Instrument [Line Items]
Scenario probability	40.20%	33.40%
Level 3 Input [Member] | Future Draws [Member]
Debt Instrument [Line Items]
Scenario probability	50.00%	50.00%
Level 3 Input [Member] | No Future Draws [Member]
Debt Instrument [Line Items]
Scenario probability	50.00%	50.00%

XML

Debt and Financing (Schedule of Fair Value Assumptions-9% Notes) (Details) - 9% Note [Member]	Jun. 19, 2015 $ / shares
Debt Instrument [Line Items]
Term (years)	5 years
Level 1 Input [Member]
Debt Instrument [Line Items]
Stock price	$ 1.82
Risk-free rate	0.27%
Level 1 Input [Member] | 5 Year [Member]
Debt Instrument [Line Items]
Term (years)	5 years
Risk-free rate	2.05%
Level 1 Input [Member] | 7 Year [Member]
Debt Instrument [Line Items]
Term (years)	7 years
Risk-free rate	2.40%
Level 2 Input [Member]
Debt Instrument [Line Items]
Volatility	90.00%
Dividend yield	0.00%

XML

Warrant Derivative Liability (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
	Jun. 19, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Oct. 28, 2015
Class Of Warrant Or Right [Line Items]
Warrant liability income		$ 34,510	$ 1,953	$ 3,517
15% Note [Member]
Class Of Warrant Or Right [Line Items]
Term (years)	5 years	4 years 5 months 19 days
9% Note [Member]
Class Of Warrant Or Right [Line Items]
Term (years)	5 years
CT Energy [Member]
Class Of Warrant Or Right [Line Items]
Shares issuable upon warrant conversion		34,070,820
Threshold price per share		$ 2.50
Consecutive trading days		21 days
Expected remaining life of the longest instrument in the common stock transaction		7 years
Warrant exercise price per share		$ 1.25
Term (years)	3 years	2 years 5 months 18 days
CT Energy [Member] | 15% Note [Member]
Class Of Warrant Or Right [Line Items]
Threshold price per share		$ 2.50
Interest rate		15.00%
CT Energy [Member] | 9% Note [Member]
Class Of Warrant Or Right [Line Items]
Threshold price per share		$ 2.50
Interest rate		9.00%
Expected remaining life of the longest instrument in the common stock transaction		7 years
Warrants [Member]
Class Of Warrant Or Right [Line Items]
Fair value of net embedded derivative liabilities at issuance		$ 40,013
Derivative income related to embedded derivative liabilities		34,510	$ 1,953	$ 3,517
Warrants [Member] | Recurring [Member]
Class Of Warrant Or Right [Line Items]
Derivative liabilities		$ 5,503
MSD Warrants [Member]
Class Of Warrant Or Right [Line Items]
Shares issuable upon warrant conversion		1,547,739
Warrant exercise price per share		$ 6.97
Term (years)			9 months 29 days
Warrant liability income		$ 0
MSD Warrants [Member] | Term Loan Facility [Member]
Class Of Warrant Or Right [Line Items]
Warrants outstanding			1,846,088
Term loan facility amount					$ 60,000
Fair value of warrants per warrant			$ 0.00
Level 1 Input [Member] | 15% Note [Member]
Class Of Warrant Or Right [Line Items]
Share price	$ 1.82	$ 0.43
Level 1 Input [Member] | 9% Note [Member]
Class Of Warrant Or Right [Line Items]
Share price	1.82
Level 1 Input [Member] | CT Energy [Member]
Class Of Warrant Or Right [Line Items]
Initial exercise price	1.25	1.25
Threshold price per share	2.50	2.50
Share price	$ 1.82	$ 0.43
Level 1 Input [Member] | Warrants [Member] | Recurring [Member]
Class Of Warrant Or Right [Line Items]
Derivative liabilities
Level 1 Input [Member] | MSD Warrants [Member]
Class Of Warrant Or Right [Line Items]
Share price			$ 1.81

XML

Warrant Derivative Liability (Schedule of Fair Value Assumptions-CT Energy Warrant) (Details) - CT Energy [Member] - $ / shares		12 Months Ended
	Jun. 19, 2015	Dec. 31, 2015
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Stock appreciation date price (hurdle)		$ 2.50
Term (years)	3 years	2 years 5 months 18 days
Claim Date [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Term (years)	1 year	5 months 18 days
Claim Date Extended [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Term (years)	1 year 6 months	11 months 18 days
Level 1 Input [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Stock price	$ 1.82	$ 0.43
Exercise price	1.25	1.25
Stock appreciation date price (hurdle)	$ 2.50	$ 2.50
Risk-free rate	1.09%	1.27%
Level 1 Input [Member] | Claim Date [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Risk-free rate	0.27%	0.55%
Level 1 Input [Member] | Claim Date Extended [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Risk-free rate	0.48%	0.70%
Level 2 Input [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Volatility	90.00%	110.00%
Dividend yield	0.00%	0.00%

XML

Warrant Derivative Liability (Schedule of Fair Value Assumptions-MSD Warrants) (Details) - MSD Warrants [Member]	12 Months Ended
	Dec. 31, 2014 $ / shares
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Term (years)	9 months 29 days
Level 1 Input [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Stock price	$ 1.81
Risk-free rate	0.21%
Level 2 Input [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Volatility	67.00%
Dividend yield	0.00%
Level 3 Input [Member] | Fundamental Change Event [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Scenario probability	0.00%
Level 3 Input [Member] | Debt Raise [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Scenario probability	100.00%
Level 3 Input [Member] | Equity Raise [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Scenario probability	0.00%

XML

Commitments and Contingencies (Narrative) (Details) $ in Thousands			1 Months Ended								12 Months Ended
	Jan. 26, 2015 USD ($)	Jul. 24, 2013 USD ($) plaintiff	May. 31, 2011 USD ($)	Jul. 31, 2007 claim	Jun. 30, 2007 claim	Mar. 31, 2007 claim	Aug. 31, 2006 claim	Jul. 31, 2006 claim	Apr. 30, 2005 claim	Jul. 31, 2004 claim	Dec. 31, 2015 USD ($) claim contract	Dec. 31, 2014 USD ($)	Jan. 15, 2015	Dec. 16, 2013
Loss Contingencies [Line Items]
Number of employment contracts | contract											5
Contractual commitments											$ 4,520
Production commencement term following date of grant											4 years
Contractual obligations											$ 4,691
Blocked payment net to interest												$ 1,100
Allowance recorded											734	13,753
Receivable from joint venture partners											400
Dussafu PSC and Budong PSC [Member]
Loss Contingencies [Line Items]
Contractual obligations											$ 300	2,400
Petrodelta [Member]
Loss Contingencies [Line Items]
Allowance recorded												12,200
Indirect ownership percentage													51.00%
Kensho Sone, Et Al. V. Harvest Natural Resources, Inc [Member]
Loss Contingencies [Line Items]
Number of plaintiffs | plaintiff		70
Estimated loss		$ 2,900
OFAC [Member]
Loss Contingencies [Line Items]
Estimated loss			$ 1,100
Blocked payment net to interest			$ 700
Percentage of cost sharing interest in work commitments			66.667%
Uracoa Municipality Tax Assessments [Member]
Loss Contingencies [Line Items]
Number of claims filed | claim						2	2	2		3	9
Libertador Municipality Tax Assessments [Member]
Loss Contingencies [Line Items]
Number of claims filed | claim				2	2				1
Joint Partners [Member] | Dussafu PSC and Budong PSC [Member]
Loss Contingencies [Line Items]
Contractual obligations											$ 100	800
Joint and several obligations, partners share											100	300
Amount advanced by partners to satisfy the obligations											$ 0	$ 500
HNR Energia [Member]
Loss Contingencies [Line Items]
Contingency, escrow deposit requirement	$ 5,000
Petroandina [Member] | Harvest Holding [Member]
Loss Contingencies [Line Items]
Ownership interest held by noncontrolling interest owners											29.00%
Petroandina [Member] | Venezuela [Member]
Loss Contingencies [Line Items]
Indirect ownership percentage											60.00%			60.00%

XML

Commitments and Contingencies (Schedule Of Contractual Commitments) (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Commitments and Contingencies [Abstract]
Oil and natural gas activities, Total	$ 4,520
Oil and natural gas activities, Payments Due Less than 1 Year	1,130
Oil and natural gas activities, Payments Due 1-2 Years	1,130
Oil and natural gas activities, Payments Due 3-4 Years	1,130
Oil and natural gas activities, Payments Due After 4 Years	1,130
Office leases, Total	171
Office leases, Payments Due Less than 1 Year	157
Office leases, Payments Due 1-2 Years	$ 14
Office leases, Payments Due 3-4 Years
Office leases, Payments Due After 4 Years
Contractual obligations, Total	$ 4,691
Contractual obligations, Payments Due Less than 1 Year	1,287
Contractual obligaions, Payments Due 1-2 Years	1,144
Contractual obligations, Payments Due 3-4 Years	1,130
Contractual obligations, Payments Due After 4 Years	$ 1,130

XML

Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Oct. 31, 2014
Income Taxes [Line Items]
Long-term deferred tax assets	$ 120	$ 53
Long-term deferred tax liabilities		14,700
Realized tax gain			$ 47,400
Offset taxable income future period			9,300
AMT credit carryforward			$ 1,900
Percentage of AMT liability offset			90.00%
Tax receivable	1,700
Tax on unremitted earnings of foreign subsidiaries	14,700	75,200	$ (89,900)
Pre-tax equity impairment charge		355,650
Pre-tax cost impairment charge	164,700
Increase in tax				$ 10
Uncertain tax positions reserve	168	30
Reserve adjustments	100
Offsetting benefit	$ 300
Prior Year [Member]
Income Taxes [Line Items]
Offset taxable income by loss			9,800
Current Year [Member]
Income Taxes [Line Items]
Offset taxable income by loss			$ 37,600
United States And Other [Member]
Income Taxes [Line Items]
Deferred tax liability on undistributed earnings of foreign subsidiaries		14,700
AMT credit carryforward	$ 2,545	4,299
Tax on unremitted earnings of foreign subsidiaries		14,700
Net tax		$ 14,700

XML

Taxes (Tax Effects of Significant Items of Deferred Income Taxes) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred tax assets:
Alternative minimum tax credit			$ 1,900
Foreign [Member]
Deferred tax assets:
Operating loss carryforwards	$ 50,974	$ 54,722
Stock-based compensation
Accrued compensation
Oil and natural gas properties	$ 26,065	$ 18,515
Investment in affiliate	$ 130,088	$ 88,913
Alternative minimum tax credit
Other
Total deferred tax assets	$ 207,127	$ 162,150
Deferred tax liabilities:
Tax on unremitted earnings of foreign subsidiaries
Other liabilities	$ (1,111)
Fixed assets
Total deferred tax liabilities	$ (1,111)
Net deferred tax asset (liability)	206,016	$ 162,150
Valuation allowance	(205,896)	(162,097)
Net deferred tax asset (liability) after valuation allowance	120	53
United States And Other [Member]
Deferred tax assets:
Operating loss carryforwards	13,547	8,718
Stock-based compensation	3,471	6,479
Accrued compensation	$ 653	$ 376
Oil and natural gas properties
Investment in affiliate
Alternative minimum tax credit	$ 2,545	$ 4,299
Other	89	81
Total deferred tax assets	$ 20,305	19,953
Deferred tax liabilities:
Tax on unremitted earnings of foreign subsidiaries		(14,700)
Other liabilities	$ (278)	(141)
Fixed assets	(3)	(3)
Total deferred tax liabilities	(281)	(14,844)
Net deferred tax asset (liability)	20,024	5,109
Valuation allowance	$ (20,024)	(19,809)
Net deferred tax asset (liability) after valuation allowance		$ (14,700)

XML

Taxes (Components of Loss from Continuing Operations Before Income Taxes) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Loss before income taxes
United States									$ 1,457	$ (12,809)	$ (31,072)
Foreign									(198,537)	(438,589)	(40,725)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND EARNINGS FROM INVESTMENT IN AFFILIATE	$ (170,212)	$ 3,568	$ (24,083)	$ (6,353)	$ (420,465)	$ (1,910)	$ (9,906)	$ (19,117)	$ (197,080)	$ (451,398)	$ (71,797)

XML

Taxes (Provision (Benefit) for Income Taxes on Continuing Operations) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current:
United States									$ (1,755)	$ (87)	$ 2,279
Foreign									32	47	44
Total									(1,723)	(40)	2,323
Deferred:
United States									(14,700)	(58,250)	72,971
Foreign											(2,207)
Total									(14,700)	(58,250)	70,764
Income Tax Expense (Benefit), Total	$ (15,793)	$ (1,850)	$ 1,604	$ (384)	$ (59,609)	$ 2,361	$ (88)	$ (954)	$ (16,423)	$ (58,290)	$ 73,087

XML

Taxes (Income Tax Expense (Benefit) on Continuing Operations at Federal Statutory Rate) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income tax expense (benefit) from continuing operations:
Tax expense (benefit) at U.S. statutory rate									$ (68,978)	$ (157,989)	$ (25,129)
Effect of foreign source income and rate differentials on foreign income									(10,870)	38,198	204
Tax gain associated with sale of interest in Harvest Holding											7,474
Subpart F income											16,615
Non-deductible interest									11,397
Tax on unremitted earnings of foreign subsidiaries									(14,700)	(75,200)	89,900
Expired losses									24,554	2,778	1,356
Other changes in valuation allowance									44,014	129,480	(10,643)
Change in applicable statutory rate											(404)
Other permanent differences										2,010	(2,546)
Return to accrual and other true-ups									11,823	$ 1,955	$ 2,919
Debt exchange									(12,079)
Warrant derivatives									(1,685)	$ (684)	$ (1,180)
Liability for uncertain tax positions									67	(30)	(5,553)
Other									34	1,192	74
Total income tax expense (benefit) - continuing operations	$ (15,793)	$ (1,850)	$ 1,604	$ (384)	$ (59,609)	$ 2,361	$ (88)	$ (954)	(16,423)	(58,290)	73,087
Total income tax expense (benefit)									$ (16,423)	$ (58,290)	$ 73,087

XML

Taxes (Net Operating Losses Available for Carryforward) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($)
United States [Member]
Operating loss carryforwards	$ 38,707
Net operating losses available for carryforward	Available for up to 20 years from 2012
Gabon [Member]
Operating loss carryforwards	$ 22,269
Net operating losses available for carryforward	Available for up to 3 years from 2013
The Netherlands [Member]
Operating loss carryforwards	$ 157,695
Net operating losses available for carryforward	Available for up to 9 years from 2007
Venezuela [Member]
Operating loss carryforwards	$ 7,274
Net operating losses available for carryforward	Available for up to 3 years from 2013

XML

Taxes (Primary Income Tax Jurisdictions and Respective Open Audit Years) (Details)	12 Months Ended
	Dec. 31, 2015
United States [Member] | Earliest Tax Year [Member]
Income Tax Examination [Line Items]
Open tax audit year	2012
United States [Member] | Latest Tax Year [Member]
Income Tax Examination [Line Items]
Open tax audit year	2015
The Netherlands [Member] | Earliest Tax Year [Member]
Income Tax Examination [Line Items]
Open tax audit year	2013
The Netherlands [Member] | Latest Tax Year [Member]
Income Tax Examination [Line Items]
Open tax audit year	2015
Venezuela [Member] | Earliest Tax Year [Member]
Income Tax Examination [Line Items]
Open tax audit year	2010
Venezuela [Member] | Latest Tax Year [Member]
Income Tax Examination [Line Items]
Open tax audit year	2015

XML

Taxes (Changes in Reserve for Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Taxes [Abstract]
Balance at beginning of year	$ 288	$ 318
Additions for tax positions of prior years
Reductions for tax positions of prior years	$ (168)	$ (30)
Balance at end of year	$ 120	$ 288

XML

Stock-Based Compensation and Stock Purchase Plans (Narrative) (Details)					12 Months Ended
		Dec. 09, 2015 $ / shares shares	Sep. 09, 2015 shares	Jul. 22, 2015 shares	Dec. 31, 2015 USD ($) $ / shares shares	Dec. 31, 2014 USD ($) $ / shares shares	Dec. 31, 2013 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total-share based compensation expense | $					$ 2,023,000	$ 1,612,000	$ 2,265,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected weighted average period of recognizing compensation cost					6 months
Awards granted						0	190,002
Aggregate fair value of awards | $							$ 900,000
Fair value of awards vested | $					$ 11,700	$ 1,900,000	$ 1,200,000
Exercise price per share | $ / shares							$ 4.80
Total future compensation cost | $					$ 100,000
Awards vested					2,000
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					3 years
Threshold price per share | $ / shares					$ 2.50
Suboptimal exercise factor	[1]				2.5
Options issued					4,375,000	683,000	920,004
Exercise price per share | $ / shares	[2]				$ 1.13
Options exercisable					2,011,000	2,700,000	2,900,000
Exercise price per share | $ / shares					$ 7.16	$ 8.85	$ 9.85
Total intrinsic value of stock options exercised | $					$ 0	$ 0	$ 100,000
Total fair value shares vested | $					1,900,000	2,400,000	1,900,000
Total future compensation cost related to unvested stock option awards that are expected to vest | $					$ 3,000,000
Expected weighted average period of recognizing compensation cost					1 year 10 months 10 days
Stock Appreciation Rights [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					3 years
Threshold price per share | $ / shares					$ 2.50
Suboptimal exercise factor					2.5
Fair value of awards vested | $					$ 15,960	$ 200,000	$ 800,000
Exercise price per share | $ / shares					$ 0.32
Exercisable awards					966,000	800,000	400,000
Exercise price per share | $ / shares					$ 4.95	$ 4.94	$ 4.91
SARs granted					5,062,000	0	200,000
Exercise price per share | $ / shares	[3]				$ 1.13
SARs cancelled					3,528,000
Remaining SARs					1,600,000
SARs exercised					0	0	0
Awards vested					264,000
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected weighted average period of recognizing compensation cost					2 years 2 months 12 days
Awards granted					1,891,000
Aggregate fair value of awards | $					$ 500,000	$ 500,000	$ 600,000
Fair value of awards vested | $					$ 300,000	$ 200,000	$ 800,000
Exercise price per share | $ / shares					$ 0.73
Total future compensation cost | $					$ 1,000,000
Awards vested					326,142	103,338	202,668
2010 Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be granted					7,725,000
2010 Long Term Incentive Plan [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be granted					2,425,000
2010 Long Term Incentive Plan [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum grants per individual					1,000,000
2010 Long Term Incentive Plan [Member] | Stock Appreciation Rights [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum grants per individual					1,000,000
2006 Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be granted					1,825,000
2006 Long Term Incentive Plan [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be granted					325,000
Maximum grants per individual					175,000
Term of maximum grants per individual					3 years
2006 Long Term Incentive Plan [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum grants per individual					900,000
2006 Long Term Incentive Plan [Member] | Stock Appreciation Rights [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum grants per individual					900,000
2004 Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be granted					1,750,000
2004 Long Term Incentive Plan [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be granted					438,000
Maximum grants per individual					110,000
2004 Long Term Incentive Plan [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum grants per individual					438,000
2001 Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be granted					1,697,000
2001 Long Term Incentive Plan [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum grants per individual					500,000
Term of maximum grants per individual					1 year
Options remaining available for grant					85,000
December 31, 2015 [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					3 years
Options issued				847,000
December 9, 2015 [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period					4 years 7 months 6 days
Options issued		3,528,201
Exercise price per share | $ / shares		$ 1.13
Expiration date					Jul. 22, 2020
December 9, 2015 [Member] | Restricted Stock Units Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted		1,600,000
Exercise price per share | $ / shares		$ 0.57
December 9, 2015 [Member] | July 22, 2016 [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage					33.33%
December 9, 2015 [Member] | July 22, 2017 [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage					33.33%
December 9, 2015 [Member] | July 22, 2018 [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage					33.33%
September 9, 2015 [Member] | Restricted Stock Units Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					1 year
Awards granted			320,004
July 22, 2015 [Member] | Restricted Stock Units Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted				1,600,000
July 22, 2015 [Member] | Restricted Stock Units Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					3 years
Threshold price per share | $ / shares					$ 2.50
Minimum [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period					5 years
Maximum [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period					10 years
Directors [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					1 year
Directors [Member] | Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					1 year
Employee [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					3 years
Employee [Member] | Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					3 years
CT Energy [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Threshold price per share | $ / shares					$ 2.50
Expiration date					Jun. 19, 2018
Shares issuable upon warrant conversion					34,070,820
Warrant exercise price per share | $ / shares					$ 1.25

[1] A suboptimal exercise factor of 2.5 means that exercise is generally expected to occur when the share price reaches 2.5 times the award's exercise price.

[2] These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE in addition to the ratable vesting over a three year period.

[3] These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE in addition to the ratable vesting over a three year period.

XML

Stock-Based Compensation and Stock Purchase Plans (Summary of Compensation Expense (Income)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total expense related to equity based awards	$ 2,271	$ 2,652	$ 3,046
Total expense related to liability based awards	(248)	(1,040)	(781)
Total compensation expense	2,023	1,612	2,265
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total expense related to equity based awards	2,003	2,073	2,119
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total expense related to equity based awards	135	579	927
Stock Appreciation Rights [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total expense related to liability based awards	(260)	(1,237)	(247)
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total expense related to equity based awards	133
Total expense related to liability based awards	$ 12	$ 197	$ (534)

XML

Stock-Based Compensation and Stock Purchase Plans (Summary of Stock Option Activity) (Details) - Stock Options [Member] - USD ($)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options outstanding, Beginning balance, Shares		4,536,000
Granted, Shares		4,375,000	683,000	920,004
Exercised, Shares
Cancelled, Shares		(1,769,000)
Options outstanding, Ending balance, Shares		7,142,000	4,536,000
Options exercisable, Shares		2,011,000	2,700,000	2,900,000
Options outstanding, Beginning balance, Weighted-Average Exercise Price		$ 7.81
Granted, Weighted-Average Exercise Price	[1]	$ 1.13
Exercised, Weighted-Average Exercise Price
Cancelled, Weighted-Average Exercise Price		$ (9.85)
Options outstanding, Ending balance, Weighted-Average Exercise Price		3.21	$ 7.81
Options exercisable, Weighted-Average Exercise Price		$ 7.16	$ 8.85	$ 9.85
Options outstanding, Weighted-Average Remaining Contractual Term		3 years 6 months	2 years
Options exercisable, Weighted-Average Remaining Contractual Term		1 year 6 months
Granted, Aggregate Intrinsic Value
Options outstanding, Aggregate Intrinsic Value
Options exercisable, Aggregate Intrinsic Value
Threshold price per share		$ 2.50
Vesting period		3 years

[1] These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE in addition to the ratable vesting over a three year period.

XML

Stock-Based Compensation and Stock Purchase Plans (Summary of Value of Option Grant Estimated on Date of Grant (Details) - Stock Options [Member]		12 Months Ended
		Dec. 31, 2015 $ / shares	Dec. 31, 2014 $ / shares	Dec. 31, 2013 $ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value		$ 0.43	$ 2.97	$ 3.06
Weighted average expected life		4 years 8 months 12 days	5 years	5 years
Expected volatility	[1]	100.00%	76.70%	79.40%
Risk-free interest rate		1.70%	1.50%	1.30%
Suboptimal exercise factor	[2]	2.5
Weighted average pre-vest forfeiture rate		1.10%	1.00%	1.20%
Dividend yield		0.00%	0.00%	0.00%

[1] Expected volatilities are based on historical volatilities of our stock.

[2] A suboptimal exercise factor of 2.5 means that exercise is generally expected to occur when the share price reaches 2.5 times the award's exercise price.

XML

Stock-Based Compensation and Stock Purchase Plans (Summary of Unvested Stock Option Awards (Details) - Stock Options [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested, Beginning balance, Shares	1,876,000
Granted, Shares	4,375,000	683,000	920,004
Vested, Shares	(645,000)
Expired, Shares	(475,000)
Unvested, Ending balance, Shares	5,131,000	1,876,000
Unvested, Beginning balance, Weighted-Average Grant-Date Fair Value	$ 3.85
Granted, Weighted-Average Grant-Date Fair Value	0.43	$ 2.97	$ 3.06
Vested, Weighted-Average Grant-Date Fair Value	(2.99)
Expired, Weighted-Average Grant-Date Fair Value	(6.38)
Unvested, Ending balance, Weighted-Average Grant-Date Fair Value	$ 0.81	$ 3.85

XML

Stock-Based Compensation and Stock Purchase Plans (Summary of Restricted Stock Awards) (Details) - Restricted Stock [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested, Beginning balance, Shares	86,000
Granted, Shares		0	190,002
Vested, Shares	(2,000)
Forfeited, Shares
Unvested, Ending balance, Shares	84,000	86,000
Unvested, Beginning balance, Weighted-Average Grant-Date Fair Value	$ 4.82
Granted, Weighted-Average Grant-Date Fair Value			$ 4.80
Vested, Weighted-Average Grant-Date Fair Value	$ (5.85)
Forfeited, Weighted-Average Grant-Date Fair Value
Unvested, Ending balance, Weighted-Average Grant-Date Fair Value	$ 4.80	$ 4.82

XML

Stock-Based Compensation and Stock Purchase Plans (Summary of Fair Value of SARs Granted) (Details) - Stock Appreciation Rights [Member]	12 Months Ended
	Dec. 31, 2015 $ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Threshold price	$ 2.50
Suboptimal exercise factor	2.5
Term (years)	4 years 6 months 22 days
Level 1 Input [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock price	$ 0.43
Exercise price	1.13
Threshold price	$ 2.50
Rik-free rate	1.66%
Level 2 Input [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility	105.00%
Dividend yield	0.00%
Level 3 Input [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Suboptimal exercise factor	2.5

XML

Stock-Based Compensation and Stock Purchase Plans (Schedule of SAR Award Transactions Under Employee Compensation Plans) (Details) - Stock Appreciation Rights [Member] - USD ($)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
SARS outstanding, Beginning balance, Shares		1,123,000
Granted, Shares		5,062,000	0	200,000
Cancelled, Shares		(3,528,000)
Expired, Shares		(86,000)
SARS outstanding, Ending balance, Shares		2,571,000	1,123,000
SARS exercisable, Shares		966,000	800,000	400,000
SARs outstanding, Beginning balance, Weighted-Average Exercise Price		$ 4.95
Granted, Weighted-Average Exercise Price	[1]	1.13
Cancelled, Weighted-Average Exercise Price	[1]	(1.13)
Expired, Weighted-Average Exercise Price		(5.12)
SARs outstanding, Ending balance, Weighted-Average Exercise Price		2.67	$ 4.95
SARs exercisable, Weighted-Average Exercise Price		$ 4.95	$ 4.94	$ 4.91
Granted, Weighted-Average Remaining Contractual Term		5 years
SARs outstanding, Weighted-Average Remaining Contractual Term		3 years 3 months 18 days	2 years 2 months 12 days
SARs exercisable, Weighted-Average Remaining Contractual Term		1 year 3 months 18 days
Granted, Aggregate Intrinsic Value
SARs outstanding, Aggregate Intrinsic Value
SARs exercisable, Aggregate Intrinsic Value
Threshold price per share		$ 2.50
Vesting period		3 years

[1] These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE in addition to the ratable vesting over a three year period.

XML

Stock-Based Compensation and Stock Purchase Plans (Summary of Unvested SAR Awards) (Details) - Stock Appreciation Rights [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested, Beginning balance, Shares	339,000
Granted, Shares	5,062,000	0	200,000
Vested, Shares	(264,000)
Cancelled, Shares	(3,528,000)
Expired, Shares	(4,000)
Unvested, Ending balance, Shares	1,605,000	339,000
Unvested, Beginning balance, Weighted-Average Grant-Date Fair Value	$ 0.51
Granted, Weighted-Average Grant-Date Fair Value	0.32
Vested, Weighted-Average Grant-Date Fair Value	(0.06)
Cancelled, Weighted-Average Grant-Date Fair Value	(0.35)
Expired, Weighted-Average Grant-Date Fair Value	(0.05)
Unvested, Ending balance, Weighted-Average Grant-Date Fair Value	$ 0.21	$ 0.51

XML

Stock-Based Compensation and Stock Purchase Plans (Summary of Fair Value of Restricted Stock Units Granted) (Details) - Restricted Stock Units [Member]	Dec. 09, 2015 $ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Term (years)	10 years
Level 1 Input [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock price	$ 0.63
Threshold price	$ 2.50
Rik-free rate	2.27%
Level 2 Input [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility	80.00%
Dividend yield	0.00%

XML

Stock-Based Compensation and Stock Purchase Plans (Summary of Unvested RSU Awards) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested, Beginning balance, Shares	905,000
Granted, Shares	1,891,000
Vested, Shares	(326,142)		(103,338)	(202,668)
Forfeited, Shares
Unvested, Ending balance, Shares	2,470,000	[1]	905,000
Unvested, Beginning balance, Weighted-Average Grant-Date Fair Value	$ 1.81
Granted, Weighted-Average Grant-Date Fair Value	0.73
Vested, Weighted-Average Grant-Date Fair Value	$ (1.50)
Forfeited, Weighted-Average Grant-Date Fair Value
Unvested, Ending balance, Weighted-Average Grant-Date Fair Value	$ 0.52	[1]	$ 1.81
Restricted Stock Units Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested, Ending balance, Shares	1,600,000
Restricted Stock Units Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested, Ending balance, Shares	900,000

[1] At December 31, 2015, unvested RSUs of 1.6 million and 0.9 million were accounted for as equity and liability awards, respectively.

XML

Operating Segments (Schedule of Segment Income (Loss) Attributable to Harvest) (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Loss from continuing operations	[1]									$ (98,570)	$ (192,936)	$ (83,946)
DISCONTINUED OPERATIONS						$ (51)	$ (142)	$ (230)	$ (131)		(554)	(5,150)
NET LOSS AND COMPREHENSIVE LOSS ATTRIBUTABLE TO HARVEST		$ (73,240)	$ 5,712	$ (25,425)	$ (5,617)	$ (179,691)	$ (4,140)	$ (1,651)	$ (8,008)	$ (98,570)	(193,490)	(89,096)
Venezuela [Member]
Loss from continuing operations										(83,953)	(171,801)	58,640
Gabon [Member]
Loss from continuing operations										(28,448)	(55,564)	(12,908)
Indonesia [Member]
Loss from continuing operations										(43)	(9,558)	(9,213)
United States [Member]
Loss from continuing operations										$ 13,874	$ 43,987	$ (120,465)

[1] Net of net income attributable to noncontrolling interest owners.

XML

Operating Segments (Schedule of Operating Segment Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Total assets	$ 47,781	$ 228,046
Continuing Operations [Member]
Total assets	47,781	228,043
Continuing Operations [Member] | Venezuela [Member]
Total assets	5,290	165,214
Continuing Operations [Member] | Gabon [Member]
Total assets	32,710	60,051
Continuing Operations [Member] | Indonesia [Member]
Total assets	5	176
Continuing Operations [Member] | United States [Member]
Total assets	$ 9,776	2,602
Discontinued Operations [Member]
Total assets		$ 3

XML

Related Party Transactions (Details)	12 Months Ended
	Dec. 31, 2015 USD ($) item shares	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Jan. 04, 2016 USD ($)	Apr. 01, 2015	Mar. 31, 2015	Dec. 15, 2013
Related Party Transaction [Line Items]
Notes payable to noncontrolling interest owners	$ 6,157,000
Related party debt forgiven	6,157,000
Proceeds from note payable to related party		$ 7,600,000
Accrued interest paid	$ 1,547,000		$ 487,000
Petroandina [Member]
Related Party Transaction [Line Items]
Notes payable maturity date	Jan. 01, 2016
Related party debt forgiven	$ 7,600,000
Interest rate					13.00%	11.00%
Commencement date of quarterly interest payment	Dec. 31, 2014
Accrued interest paid	$ 400,000
Harvest Holding [Member] | Vinccler [Member]
Related Party Transaction [Line Items]
Ownership interest held by noncontrolling interest owners	20.00%						20.00%
Harvest Holding [Member] | Petroandina [Member]
Related Party Transaction [Line Items]
Ownership interest held by noncontrolling interest owners	29.00%
11% Note [Member] | President And Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Notes payable maturity date	Jun. 30, 2016
Proceeds from note payable to related party	$ 50,000
Interest rate	11.00%
Vinccler [Member]
Related Party Transaction [Line Items]
Notes payable maturity date	Dec. 31, 2015
Vinccler [Member] | LIBOR [Member]
Related Party Transaction [Line Items]
Variable spread on reference rate	0.50%
CT Energy [Member]
Related Party Transaction [Line Items]
Proceeds from note payable to related party	$ 1,300,000
CT Energy [Member] | Directors [Member]
Related Party Transaction [Line Items]
Number of representatives | item	2
CT Energy [Member] | 15.0% Per Annum Note [Member]
Related Party Transaction [Line Items]
Notes payable maturity date	Jan. 01, 2016
Interest rate	15.00%
CT Energy [Member] | 15% Note [Member]
Related Party Transaction [Line Items]
Notes payable maturity date	Jun. 19, 2020
Variable spread on reference rate	0.50%
Interest rate	15.00%
Commencement date of quarterly interest payment	Oct. 01, 2015
Promissory note	$ 25,200,000
CT Energy [Member] | 9% Note [Member]
Related Party Transaction [Line Items]
Notes payable maturity date	Jun. 19, 2020
Interest rate	9.00%
Commencement date of quarterly interest payment	Oct. 01, 2015
Common stock converted from convertible senior secured note | shares	8,667,597
CT Energy [Member] | Subsequent Event [Member] | 15% Note [Member]
Related Party Transaction [Line Items]
Promissory note				$ 26,100,000
CT Energia [Member] | CT Energia Note [Member]
Related Party Transaction [Line Items]
Notes payable maturity date	Jan. 04, 2019
Commencement date of quarterly interest payment	Jul. 01, 2016
CT Energia [Member] | Subsequent Event [Member] | CT Energia Note [Member]
Related Party Transaction [Line Items]
Interest rate				11.00%
Promissory note				$ 5,200,000
Aggregate amount of capital contributions				$ 2,600,000

XML

Mezzanine Equity (Details) - CT Energy [Member]	Dec. 31, 2015 $ / shares shares
9% Note [Member]
Temporary Equity [Line Items]
Interest rate	9.00%
Series C Preferred Stock [Member]
Temporary Equity [Line Items]
Mezzanine equity, shares issued | shares	69.75
Mezzanine equity, par value	$ 0.01
Mezzanine equity, liquidation preference per share	$ 1.00

XML

Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended																12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Expenses		$ (192,891)	[1]	$ (6,767)	[1]	$ (6,119)	[1]	$ (6,119)	[1]	$ (422,199)	[2]	$ (4,977)	[2]	$ (9,759)	[2]	$ (12,670)	[2]	$ (211,896)		$ (449,605)		$ (45,436)
Non-operating gain (loss)		22,679		10,335		(17,964)		(234)		1,734		3,067		(147)		(6,447)		14,816		(1,793)		(26,361)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND EARNINGS FROM INVESTMENT IN AFFILIATE		(170,212)		3,568		(24,083)		(6,353)		(420,465)		(1,910)		(9,906)		(19,117)		(197,080)		(451,398)		(71,797)
Income tax expense (benefit)		(15,793)		(1,850)		1,604		(384)		(59,609)		2,361		(88)		(954)		(16,423)		(58,290)		73,087
Income (loss) from continuing operations										(360,856)		(4,271)		(9,818)		(18,163)		(180,657)		(393,108)		(144,884)
Earnings (loss) from investment in affiliate														16,062		18,887				34,949		72,578
Income (loss) from continuing operations		(154,419)		5,418		(25,687)		(5,969)		(360,856)		(4,271)		6,244		724		$ (180,657)		(358,159)		(72,306)
Discontinued operations										(51)		(142)		(230)		(131)				(554)		(5,150)
Net income (loss)										(360,907)		(4,413)		6,014		593		$ (180,657)		(358,713)		(77,456)
Less: Net income (loss) attributable to noncontrolling interest owners		(81,179)		(294)		(262)		(352)		(181,216)		(273)		7,665		8,601		(82,087)		(165,223)		11,640
Net income (loss) attributable to Harvest		$ (73,240)		$ 5,712		$ (25,425)		$ (5,617)		$ (179,691)		$ (4,140)		$ (1,651)		$ (8,008)		$ (98,570)		$ (193,490)		$ (89,096)
Basic Earnings (Loss) per Share:
Income (loss) from continuing operations		$ (1.42)		$ 0.13		$ (0.60)		$ (0.13)		$ (4.23)		$ (0.10)		$ (0.03)		$ 0.19		$ (2.18)	[3]	$ (4.59)	[3]	$ (2.12)	[3]
Discontinued operations														(0.01)						(0.01)		(0.13)
Net income (loss) attributable to Harvest		(1.42)		0.13		(0.60)		(0.13)		(4.23)		(0.10)		(0.04)		0.19		(2.18)		(4.60)		(2.25)
Diluted Earnings (Loss) per Share:
Income (loss) from continuing operations		(1.42)		0.13		(0.60)		(0.13)		(4.23)		(0.10)		(0.03)		0.19		(2.18)	[3]	(4.59)	[3]	(2.12)	[3]
Discontinued operations														(0.01)						(0.01)		(0.13)
Net income (loss) attributable to Harvest		$ (1.42)		$ 0.13		$ (0.60)		$ (0.13)		$ (4.23)		$ (0.10)		$ (0.04)		$ 0.19		$ (2.18)		$ (4.60)		$ (2.25)
Impairment expense - cost investment in affiliate																		$ 164,700
Impairment of oil and natural gas property																		24,178		$ 57,994		$ 3,770
Impairment expense - equity investment in affiliate																				355,650
Allowance for doubtful accounts																		$ 734		13,753
Dussafu PSC [Member]
Diluted Earnings (Loss) per Share:
Impairment of oil and natural gas property	$ 23,200																			$ 50,300

[1] Includes $164.7 million impairment during the quarter ended December 31, 2015 related to our investment in Petrodelta and $24.2 million impairment of oil and natural gas properties (including oilfield inventory) for Dussafu PSC. See Note 6 - Investment in Affiliate and Note 8- Gabon.

[2] Includes $355.7 million impairment during the quarter ended December 31, 2014 related to our investment in Petrodelta, $13.8 million allowance for doubtful accounts for long-term receivable - investment in affiliate, and $50.3 million impairment of oil and natural gas properties for Dussafu PSC. See Note 6 - Investment in Affiliate and Note 8- Gabon.

[3] Net of net income attributable to noncontrolling interest owners.

XML

Subsequent Events (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Jan. 04, 2016
Petrodelta [Member]
Subsequent Event [Line Items]
Indirect ownership percentage	40.00%
CT Energy [Member] | 15% Note [Member]
Subsequent Event [Line Items]
Interest rate	15.00%
Notes payable maturity date	Jun. 19, 2020
Promissory note	$ 25,200,000
Commencement date of quarterly interest payment	Oct. 01, 2015
CT Energia [Member] | CT Energia Note [Member]
Subsequent Event [Line Items]
Notes payable maturity date	Jan. 04, 2019
Commencement date of quarterly interest payment	Jul. 01, 2016
Subsequent Event [Member] | CT Energy [Member] | 15% Note [Member]
Subsequent Event [Line Items]
Promissory note		$ 26,100,000
Subsequent Event [Member] | CT Energia [Member] | CT Energia Note [Member]
Subsequent Event [Line Items]
Interest rate		11.00%
Promissory note		$ 5,200,000
Aggregate amount of capital contributions		$ 2,600,000