10-K 1 c289-20151231x10k.htm 10-K 20151231 10K

  

 

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.  

 

 

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HARVEST NATURAL RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS

 

 

 

 

 

 

 

 

 

Page

Part I 

 

 

Item 1.

Business

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.

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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 exploration acreage 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.

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·

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 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.

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 oil    We 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.

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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 ContingenciesOn 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%

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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

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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’s natural 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 and 6,412 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 and 14,538 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 and 2,593 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 investment in 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.

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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

 

 —

 

 —

 

 —

 

 —

 

 

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

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·

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 27 full-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 cause fluctuations 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 natural gas, 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.

 

Picture 1

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.

ColombiaDiscontinued 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 by recording 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 the Additional 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 the related 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 variances of 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, 2014The 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. See Part 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 

 

%

 

 

 

Natural gas

  

 

4,590 

  

 

4,000 

  

 

590 

 

15 

%

 

 

 

Total revenues

  

$

1,348,042 

  

$

1,330,093 

  

$

17,949 

 

%

 

 

 

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 

 

%

 

 

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

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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 alternative