UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K10-K/A
Amendment No. 1
(Mark One)
☒[ X ]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
☐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)
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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
Registrant's telephone number, including area code: (281) 899-5700
Securities registered pursuant to Section 12(b) of the Act:
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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 ☒ X
Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ X
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ X No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ X No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒ [ X ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large Accelerated Filer Accelerated Filer X Non-Accelerated Filer Smaller Reporting Company
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ X
The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 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,April 25, 2016, shares outstanding: 51,415,164.
DOCUMENTS INCORPORATED BY REFERENCE
Portions
None.
HARVEST NATURAL RESOURCES, INC.
FORM 10-K/A
EXPLANATORY NOTE
The purpose of this Amendment No. 1 on Form 10-K/A (“Amended Report”) is to its 2016 annual meetingamend Part III, Items 10 through 14 of shareholders, or information to be included in an amendment to theour Annual Report on Form 10-K in either casefor the fiscal year ended December 31, 2015, which the Registrant intends will bewas filed with the Securities and Exchange Commission not later than(the “SEC”) on March 29, 2016 (the “2015 10-K”), to include information previously omitted from the 2015 10-K in reliance on General Instruction G to Form 10-K, which provides that registrants may incorporate by reference certain information from a definitive proxy statement filed with the SEC within 120 days after the end of the Registrant’s fiscal year,year. The Company’s definitive proxy statement will not be filed within 120 days after the end of the Company’s 2015 fiscal year.
As required by Rule 12b-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), new certifications by our principal executive officer and principal financial officer are incorporatedfiled as exhibits to this Amended Report under Item 15 of Part IV hereof.
Except as stated herein, the Company has not modified or updated disclosures presented in the 2015 10-K in this Amended Report. Accordingly, this Amended Report does not reflect events occurring after the filing of our 2015 10-K or modify or update those disclosures, including the exhibits to the 2015 10-K, affected by reference under Partsubsequent events. As such, our 2015 10-K continues to speak as of March 29, 2016 (the date it was filed with the SEC). Accordingly, this Amended Report should be read in conjunction with the 2015 10-K and our other reports filed with the SEC subsequent to the filing of our 2015 10-K, including any amendments to those filings.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
BOARD OF DIRECTORS
The Company’s Board is comprised of this Form 10-K where indicated. seven members:
Stephen D. Chesebro’
Appointed Director in October 2000
Age 74
Mr. Chesebro’ has served as the Chairman of the Board of the Company since 2001. From December 1998 until he retired in 1999, he served as President and Chief Executive Officer of PennzEnergy, the independent oil and gas exploration and production company that was formerly a business unit of Pennzoil Company. From February 1997 to December 1997, Mr. Chesebro’ served as Group Vice President – Oil and Gas and from December 1997 until December 1998 he served as President and Chief Operating Officer of Pennzoil Company, an integrated oil and gas company. From 1993 to 1996, Mr. Chesebro’ was Chairman and Chief Executive Officer of Tenneco Energy. Tenneco Energy was part of Tenneco, Inc., a worldwide corporation that owned diversified holdings in six major industries. Mr. Chesebro’ is an advisory director to Preng & Associates, an executive search consulting firm. In 1964, Mr. Chesebro’ graduated from the Colorado School of Mines. He was awarded the school’s Distinguished Achievement Medal in 1991 and received his honorary doctorate from the institution in 1998. He currently serves on the school’s visiting committee for petroleum engineering, and is a member of the Colorado School of Mines Foundation Board of Governors. In 1994, Mr. Chesebro’ was the first American awarded the H. E. Jones London Medal by the Institution of Gas Engineers, a British professional association.
Oswaldo Cisneros
Appointed Director in June 2015
Age 75
Mr. Cisneros started his career in the soft drink industry in 1961 and served as the president of Pepsi Cola Venezuela until 1996, when the Cisneros Group undertook a strategic alliance with the Coca Cola Company. Mr. Cisneros also served as the president of Telcel Celular, C.A., a partner of Bellsouth International. Mr. Cisneros currently serves as president and is a shareholder of the following companies: Corporación Digitel, a telecom company, Maritime Contractors de Venezuela, an oil drilling services company, Fabrica Nacional de Vidrios, a glass bottle manufacturer, and Central Azucarero Portuguesa, a sugar mill factory. Mr. Cisneros received a degree in Business Administration from Babson College, USA, in 1961.
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Francisco D’Agostino
Appointed Director in June 2015
Age 41
From 1996 to 1999, Mr. D’Agostino was vice president - Finance of Dayco Holding Corp, his family’s real estate management and construction company. From 2000 to 2010, he served as director and president of Grupo Empresarial Alfa-Caracas, Venezula, a real estate management and construction company. Since 2000 he has served as director and vice president of Private Banking at Banco Occidentel de Descuento – Caracas, Venezuela, and since 2007 he has also served as president of D’Agostino & Company, Ltd., a financial advisory and investment firm. In 2008, he founded and has served as president of Element Capital Group – Panama City, Panama, an asset management firm. Mr. D’Agostino is a director of Dayco Telecom-Venezuela, a Venezuelan internet company; BancAmerica – Dominican Republic, a commercial bank; and Fundacion Dayco – Caracas, a Venezuelan family charitable foundation. Mr. D’Agostino graduated from Boston College with a Bachelor of Science in Economics and Finance.
Elected Director in May 2005
Age 56
Mr. Edmiston was elected President and Chief Executive Officer of Harvest Natural Resources, Inc. on October 1, 2005. He joined the Company as Executive Vice President and Chief Operating Officer on September 1, 2004. Prior to joining Harvest, Mr. Edmiston was with Conoco and ConocoPhillips for 22 years in various management positions including President, Dubai Petroleum Company (2002-2004), a ConocoPhillips affiliate company in the United Arab Emirates and General Manager, Petrozuata, C.A., in Puerto La Cruz, Venezuela (1999-2001). Prior to 1999, Mr. Edmiston also served as Vice President and General Manager of Conoco Russia and then as Asset Manager of Conoco’s South Texas Lobo Trend gas operations. On March 27, 2014, Mr. Edmiston was appointed to the board of Sonde Resources Corp. He earned a Bachelor of Science degree in Petroleum Engineering from the Texas Tech University and a Masters of Business Administration from the Fuqua School of Business at Duke University. Mr. Edmiston was inducted into the Petroleum Engineering Academy and was recognized as a Distinguished Engineer by the Texas Tech College of Engineering in 2009. Mr. Edmiston is a Member of the Society of Petroleum Engineers.
Robert E. Irelan
Appointed Director in February 2008
Age 69
Mr. Irelan has over 45 years of experience in the oil and gas industry. He retired from Occidental Petroleum as Executive Vice President of Worldwide Operations in April 2004, having started there in 1998. Prior to Occidental Petroleum, Mr. Irelan held various positions at Conoco, Inc., from 1967 until 1998. Upon his retirement he opened his own company, Naleri Investments LLC. He also partnered in several entrepreneurial ventures including Rapid Retail Solutions LLC, BISS Product Development LLC and All About Baby LLC. Mr. Irelan earned his Professional Engineering degree in Petroleum Engineering from Colorado School of Mines. He also has advanced studies in Mineral Economics. He was awarded the Distinguished Achievement Award from the school in 1998.
Edgard Leal
Appointed Director in June 2015
Age 74
Since 2005 Mr. Leal has served as a director of Leal, Leal & Associados, an advisory service to Venezuelan companies and investor groups, and as managing director of Asesorias y Servicios Gaspetro, C.A., an advisory services company. From 1998 to 2006, Mr. Leal was Senior Associate of Cambridge Energy Research Associates, providing advisory services to Latin American oil and gas companies. From 1980 to 2003, he was a director of Shipowners Mutual Protection and Indemnity, an insurance company. From 1998 to 2001, he was vice president of Banco Caracas, a private section bank in Venezuela. From 1994 to 1998, he was president of Centro de Aralisis y Negociacion – Internacional, C.A., providing advisory services to banks and other financial institutions in Venezuela. From 1975 to 1994, he served as a director, president of Bariven and a managing director of Petroleos de Venezuela (PDVSA), managing the centralized finances for PDVSA. From 1989 to 1990, Mr. Leal was the Commissioner of the President of Venezuela, negotiating foreign commercial bank debt with international banks. From 1969 to 1975, he was a Vice President of CitiBank, managing its credit and public sector lending in Venezuela. From 1966 to 1975, Mr. Leal represented the Government of Venezuela in the Economic Commission of the Organization of Petroleum-Exporting Countries; from 1963 to 1966 he served as Assistant to the Minister Counselor for Petroleum Affairs in the Embassy of Venezuela in the United States, conducting discussions with the U.S. Department of Energy on the U.S. Oil Import Program. Mr. Leal received a Bachelor of Arts degree in Economics from Rollins College in 1962 and a Master of Arts degree in Economics from Catholic University of America in 1966.
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Patrick M. Murray
Appointed Director in October 2000
Age 73
In 2007, Mr. Murray retired from Dresser, Inc. He had been the Chairman of the Board and Chief Executive Officer since 2004. Dresser, Inc. is an energy infrastructure and oilfield products and services company. From 2000 until becoming Chairman of the Board, Mr. Murray served as President and Chief Executive Officer of Dresser, Inc. Mr. Murray was President of Halliburton Company’s Dresser Equipment Group, Inc.; Vice President, Strategic Initiatives of Dresser Industries, Inc.; and Vice President, Operations of Dresser, Inc. from 1996 to 2000. Mr. Murray has also served as the President of Sperry-Sun Drilling Services from 1988 through 1996. Mr. Murray joined NL Industries in 1973 as a Systems Application Consultant and served in a variety of increasingly senior management positions. Mr. Murray is on the board of the World Affairs Council of Dallas Fort Worth. He is on the board of advisors for the Maguire Energy Institute at the Edwin L. Cox School of Business, Southern Methodist University, and a member of the Board of Regents of Seton Hall University. Mr. Murray holds a B.S. degree in Accounting and a Master of Business Administration from Seton Hall University. He served for two years in the U.S. Army as a commissioned officer.
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HARVEST NATURAL RESOURCES, INC.
FORM 10-K
TABLE EXEOF CONTENTSCUTIVE OFFICERS
The following table provides information regarding each of our executive officers.
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| President and Chief Executive Officer | |||
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| Vice President, Finance, Chief Financial Officer and Treasurer | |||
Keith L. Head | 58 | Vice President, General Counsel and Corporate Secretary | ||
Karl L. Nesselrode | 58 | Vice President, Engineering & Business Development | ||
Robert Speirs | 60 | Senior Vice President, Eastern Operations |
* See Mr. Edmiston’s biography on page 2.
Stephen C. Haynes has served as our Vice President, Finance, Chief Financial Officer and Treasurer since May 19, 2008. Mr. Haynes performed various financial consulting engagements from January 1, 2008 until his appointment with Harvest. Previously, he served as Chief Financial Officer for Cygnus Oil and Gas Corporation for the period February 1, 2006 through December 31, 2007. Before joining Cygnus, Mr. Haynes was the Corporate Controller with Carrizo Oil and Gas for the period January 1, 2005 through January 31, 2006. Mr. Haynes served as an independent consultant from March 2001 through the end of 2004. From March 1990 through December 2000, Mr. Haynes served in a series of increasing responsibilities in international managerial and executive positions with British Gas, culminating in his appointment as Vice President-Finance of Atlantic LNG, a joint venture of British Gas and several industry partners in Trinidad and Tobago. Mr. Haynes is a Certified Public Accountant, holds a Master of Business Administration degree with a concentration in Finance from the University of Houston and a Bachelor of Business Administration degree in Accounting from Sam Houston State University. He also attended the Executive Development Program at Harvard University.
Keith L. Head has served as our Vice President, General Counsel and Corporate Secretary since May 7, 2007. He joined Texas Eastern upon graduation from law school and remained with the same organization through mergers with Panhandle Eastern, Duke Energy Corporation and Cinergy Corp. Mr. Head held various business development positions with Duke Energy Corporation from 1995 to 2001. His corporate development work included the identification, evaluation and negotiation of acquisitions in Latin America, North America and the United Kingdom. Mr. Head was Senior Vice President and General Counsel at Duke Energy North America from 2001 to 2004 and Associate General Counsel of Duke Energy Corporation from 2004 through December 2006. After leaving Duke Energy, Mr. Head joined Harvest in May 2007. He is a board member of the Houston chapter of The General Counsel Forum and formerly served as president of the board for the Texas Accountants and Lawyers for the Arts. Mr. Head holds a Bachelor of Science degree in Business Administration from the University of North Carolina. He received both a Juris Doctorate and Masters in Business Administration from the University of Texas in 1983.
Karl L. Nesselrode has served as Vice President, Engineering and Business Development of the Company since November 17, 2003. From August 9, 2007 to August 2, 2010, he accepted a long-term secondment to Petrodelta as its Operations and Technical Manager while remaining an officer of Harvest. From February 2002 until November 2003, Mr. Nesselrode was President of Reserve Insights, LLC, a strategy and management consulting company for oil and gas. He was employed with Anadarko Petroleum Corporation as Manager Minerals and Special Projects from July 2000 to February 2002. Mr. Nesselrode served in various managerial positions with Union Pacific Resources Company from August 1979 to July 2000. Mr. Nesselrode earned a Bachelor of Science in Petroleum Engineering from the University of Tulsa in 1979 and completed Harvard Business School Program for Management Development in 1995.
Robert Speirs has served as Senior Vice President, Eastern Operations since July of 2011. Prior to his promotion, his title had been Vice President, Eastern Operations since December 6, 2007. He joined Harvest in June 2006 as President and General Manager, Russia. Previously Mr. Speirs was President of Marathon Petroleum Russia and General Director of their wholly-owned subsidiary, KhantyMansciskNefte Gas Geologia from March 2004 through May 2006. Prior to joining Marathon, Mr. Speirs was Executive Vice President of YUKOS EP responsible for engineering and construction from June 2001. During both these periods, Mr. Speirs spent considerable time in West Siberia where he oversaw substantial increases in production at both companies. From November 1997 until March 2001, Mr. Speirs resided in Jakarta where he served as President of Premier Oil Indonesia. During this period, Premier was active in all phases of the Upstream business, culminating in the commissioning of the West Natuna Gas Project. Prior to 1997, Mr. Speirs was with Conoco for 21 years in various leadership positions in the US, UK, Russia, Indonesia, Singapore and Dubai, UAE. Mr. Speirs earned a Bachelor of Science degree with Honors in Engineering Science from the University of Edinburgh. He also attended the Executive Management Program at INSEAD.
Cautionary Notice Regarding Forward-Looking Statements
CORPORATE GOVERNANCE
Harvest Natural Resources, Inc. (“Harvest”Audit Committee
Our Board of Directors has established a standing audit committee (the “Audit Committee”). The Audit Committee operates pursuant to a written charter. The charter is accessible in the Corporate Governance section of our website (http://www.harvestnr.com).
From January 1, 2015 until June 19, 2015, our audit committee consisted of Patrick M. Murray as Chairman, Igor Effimoff, H. H. Hardee and J. Michael Stinson. On June 19, 2015, in connection with a financing involving CT Energy Holding SRL, the Company’s Board of Directors accepted the resignations of Dr. Effimoff, Mr. Hardee and Mr. Stinson and appointed Mr. Oswaldo Cisneros, Mr. Francisco D’Agostino and Mr. Edgard Leal as Board members, effective the same date. The Board determined that Mr. Leal is independent for the purposes of the NYSE and its own internal policies. Effective as of June 30, 2015, the audit committee of the Board is comprised of Mr. Murray as Chairman, Mr. Leal and Mr. Robert Irelan.
The Audit Committee assists the Board in its oversight of our accounting and financial reporting policies and practices; the integrity of our financial statements; the independent registered public accounting firm’s qualifications, independence and objectivity; the performance of our internal audit function and our independent registered public accounting firm; and our compliance with legal and regulatory requirements.
The Audit Committee acts as a liaison between our independent registered public accounting firm and the Board, and it has the sole authority to appoint or replace the “Company”) cautionsindependent registered public accounting firm and to approve any non-audit relationship with the independent registered public accounting firm. Our internal audit function and the independent registered public accounting firm report directly to the Audit Committee.
Our Audit Committee has established procedures for our employees or consultants to make a confidential, anonymous complaint or raise a concern over accounting, internal accounting controls or auditing matters concerning us or any of our companies and is responsible for the proper implementation of such procedures. The Audit Committee is also responsible for understanding and assessing our processes and policies for communications with stockholders, institutional investors, analysts and brokers.
The Audit Committee has access to our records and employees, and has the sole authority to retain independent legal, accounting or other advisors for committee matters. We will provide appropriate funding for the payment of the independent registered public accounting firm and any advisors employed by the Audit Committee.
The Audit Committee makes regular reports to the Board. Each year the Audit Committee assesses the adequacy of its charter and conducts a self-assessment review to determine its effectiveness.
The Board has determined that any forward-looking statements as such term is defined in Section 27Aeach member of the Audit Committee meets the independence standards of the Securities Actand Exchange Commission’s (“SEC”) requirements, the rules of 1933,the New York Stock Exchange and the Company Guidelines for Corporate Governance. No member of the Audit Committee serves on the audit committee of more than three public companies. The Board has further determined that each member of the Audit Committee is financially literate and that Mr. Murray qualifies as amended (the “Securities Act”), and an audit committee financial expert, as defined in Item 407(d)(5) of SEC Regulation S-K. Information on the relevant experience of Mr. Murray is set forth in “Board of Directors” above.
Section 21E16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”(“Section 16(a)”) containedrequires our directors, executive officers and beneficial holders of more than 10 percent of our common stock to file reports with the SEC regarding their ownership and changes in ownership of our stock. Based solely upon our review of SEC Forms 3, 4 and 5 and any amendments thereto furnished to us, to our knowledge, during fiscal year 2015, our officers, directors and 10 percent stockholders complied with all Section 16(a) filing requirements. In making this reportstatement, we have relied upon the written representations of our directors and officers.
Code of Ethics
The Board has adopted a Code of Business Conduct and Ethics, which applies to all of our directors, officers and employees. The Board last amended the Code of Business Conduct and Ethics in December 2014. The Board has not granted any waivers to the Code of Business Conduct and Ethics.
The Guidelines for Corporate Governance, the Code of Business Conduct and Ethics and the charters of all the Board committees are accessible on our website under the Corporate Governance section at http://www.harvestnr.com. Any amendments to or made by managementwaivers of the Company involve risksCode of Conduct and uncertainties and are subject to change basedBusiness Ethics will also be posted 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.website.
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Item 1. Bus11. Executive Compeinessnsation
COMPENSATION DISCUSSION AND ANALYSIS
Introduction
The Company’s Compensation Discussion and Analysis explains the key elements of our executive compensation program for our President and Chief Executive Officer and our other named executive officers whose 2015 compensation is in the Executive Compensation Tables starting on page 15.
· | James A. Edmiston, President and Chief Executive Officer (CEO); |
· | Stephen C. Haynes, Vice President, Finance, Chief Financial Officer and Treasurer; |
· | Robert Speirs, Senior Vice President, Eastern Operations; |
· | Karl L. Nesselrode, Vice President, Engineering & Business Development; and |
· | Keith L. Head, Vice President, General Counsel and Corporate Secretary. |
Executive Summary
Harvest Natural Resources, Inc. is a petroleum exploration and production company incorporated under Delaware law in 1988. Our focus isCompany focuses on acquiring exploration, development, and producing properties in geological basins with proven and 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 significanthold interests in the Bolivarian Republic of Venezuela (“Venezuela”). In addition to our interests in Venezuela, we hold and exploration acreage offshore of the Republic of Gabon (“Gabon”).Gabon. We operate from our Houston, Texas headquarters. We also have a regionalheadquarters with an office in Caracas, Venezuela, and a field office in Port-Gentil, Gabon to support operations in those areas.Port Gentil, Gabon.
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). Performance Highlights
Petrodelta, a Venezuelan mixed company formed in 2007, is our cost investment in eastern Venezuela responsible
2015 held many challenges 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% ofCompany. Among 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. accomplishments were:
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:
· | In June of 2015, we entered into a securities purchase agreement with CT Energy |
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· | We secured the approval of a four billion Venezuelan Bolivar loan to Petrodelta by CT |
· | We completed 3D processing in Gabon which has significantly enhanced our prospect inventory. |
· | We negotiated an optional two-year extension to the |
· | We completed the sale of Budong Budong, liquidated the Indonesian Branch of Harvest Far East and closed the Singapore office. |
· | We reduced general overhead expenses 36 percent from year-end 2014 to |
Compensation Highlights
· | For the |
· | As of March 2016, all executive salaries have been deferred until resolution or improvement of the |
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The following graphs highlight the Company results for 2015:
See Part IV – Item 15 – Exhibits
The Human Resources Committee (the “Committee”) of the Board of Directors has the discretion to exercise their judgment in weighing the achievement of specific performance measures. For 2015, it again considered total shareholder return (“TSR”), reserves, social responsibility/governance and Financial Statements Schedules, Note 1 – Organization safety as well as strategic individual objectives for further information on the CT Energy transaction.
Through December 31, 2014, we included the resultsnamed executive officers. TSR was down 76%. We calculate TSR as current year-end closing share price minus prior year closing share price divided by prior year closing share price. Annual net production 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. Duenet 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 2015 was down 4% over 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 theprior 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, There were no Foreign Corrupt Practices Act (“FCPA”) incidents in 2015, HNR Finance and Harvest Vinccler S.C.A. (“Harvest Vinccler”) submitted a Request for Arbitration against the Government of Venezuela before the International Centre for Settlement of Investment Disputes (“ICSID”) regarding HNR Finance's interest in Petrodelta. The Request for Arbitration set forth numerous claims, as further described in Part IV – Item 15 – Exhibits and Financial Statement Schedules, Note 13 – Commitments and Contingencies.
On January 26, 2015, Petroandina filed a complaint for breach of contract against the Company and its subsidiary HNR Energia B.V. (“HNR Energia”) in Court of Chancery of the State of Delaware (“Court of Chancery”). The complaint states that HNR Energia breached provisions of the Shareholders Agreement between Petroandina and HNR Energia, which provisions require HNR Energia to provide advance notice, and deposit $5 million into an escrow account, before bringing any claim against the Venezuelan government. Under those provisions, if Petroandina so requests, an appraisal of Petroandina's 29 percent interest in Harvest Holdings must be performed, and Petroandina has the right to require HNR Energia to purchase that 29 percent interest at the appraised value. Petroandina's claim requests relief as further described in Part IV – Item 15 – Exhibits and Financial Statements Schedules,Note 13 – Commitments and Contingencies. On January 28, 2015, the Court of Chancery issued an injunction ordering the Company and HNR Energia to withdraw the Request for Arbitration and not take any action to pursue its claims against Venezuela until Harvest and HNR Energia have complied with the provisions of the Shareholders’ Agreement or otherwise reached an agreement with Petroandina. Accordingly, on January 28, 2015, HNR Finance B.V. and Harvest Vinccler withdrew without prejudice the Request for Arbitration.
On February 5, 2015, the Company entered into a Share Purchase Agreement to transfer shares of Harvest Budong-Budong B.V. to Stockbridge Capital Limited. The transfer of shares was completed on May 4, 2015.
On March 9, 2015, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., (“Vinccler”) forgave a note payable by HNR Energia and accrued interest totaling $6.2 million. This was reflected as a contribution to stockholders’ equity.
On March 31, 2015, the Company closed its Singapore office.
On May 11, 2015, the Company borrowed $1.3 million to fund certain corporate expenses. The Company issued a note payable to the lender bearing an interest rate of 15.0% per annum, with a maturity date of January 1, 2016. On June 19, 2015, the Company repaid the note payable and accrued interest.
On June 19, 2015, Dr. Igor Effimoff, Mr. H. H. Hardee and Mr. J. Michael Stinson resigned as directors of the Company in connection with the CT Energy transaction. CT Energy appointed Oswaldo Cisneros, Francisco D'Agostino and Edgard Leal as directors of the Company.
As of December 31, 2014, HNR Energia had a note payable to Petroandina of $7.6 million. Principal was due by January 1, 2016. On June 23, 2015 the Company repaid the note payable of $7.6 million plus accrued interest of $0.4 million.
On July 14, 2015, HNR Finance entered into a non-binding term sheet with CVP and PDVSA. The term sets forth a framework for definitive agreements that would govern the restructuring of the management and operations of Petrodelta. Because the term sheet is non-binding and subject to several conditions precedent, we cannot guarantee that HNR Finance will be able to consummate the transactions contemplated by the term sheet.
On September 9, 2015, our stockholders approved all proposals related to the transaction with CT Energy.
On September 15, 2015, the 9% Note and associated accrued interest were converted into 8,667,597 shares of Harvest common stock. The Company recognized a $1.9 million loss on debt conversion. Immediately after the conversion, CT Energy owned approximately 16.6% of Harvest’s common stock.
On December 2, 2015, the Company received notification from the NYSE that the Company was notaccident-free 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.2015.
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%Compensation Philosophy
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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 loanOur compensation philosophy is to provide CT Energia with collateraloffer a competitive total compensation package to obtain funds for one or more loansenable us to Petrodelta. The loans to Petrodelta are to assist Petrodelta in satisfying its working capital needsattract, motivate 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.
retain key executives. 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 operationscompensation objectives include:
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· | Providing annual cash incentive awards that take into account performance factors weighted by both corporate and individual goals; |
· | Aligning the interest of executive officers and directors with stockholder value creation by providing significant equity based long-term incentives. |
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The Committee oversees the development and execution of our compensation program. The Committee annually reviews our compensation philosophy and tests its ability to promote meeting the objectives stated above. The Committee recommends compensation for the named executive officers, short-term cash bonuses, long-term cash and non-cash compensation, and submits its recommendations to the Board of Directors for approval. Three independent directors comprise the Committee. The Committee meets as needed, but no less than quarterly to review compensation and benefit programs with management. It subsequently approves any changes. Our Human Resources, Accounting and Legal Department employees handle the day-to-day design and administration of employee compensation and benefit programs available to our employees.
Say-on-Pay Results
We hold our Say-on-Pay vote every other year. At our September 9, 2015 annual stockholders meeting, Harvest received support for our compensation program with approval from approximately 76.5% of the stockholders who voted. The Committee considered this support when contemplating potential changes to the Company’s compensation.
Setting Executive Compensation
Our compensation program consists of base salary, annual performance-based incentive awards, long-term incentives and personal benefits. Base salary and annual performance based incentive awards are cash-based. Long-term incentives typically consist of stock options, stock appreciation rights, restricted stock units and/or restricted stock awards. The Committee reviews the compensation recommendations from the CEO and our independent consultants’ advice on competitive trends regarding base salary, annual incentive awards and long-term incentives. The Committee exercises its collective judgment in establishing executive compensation based on performance, compensation history and market information. The recommendations are then made to the full Board of Directors for its approval.
The Role of the Compensation Consultant; Compensation Consultant Independence
In 2015, the Committee again engaged Frost Human Resource Consulting (“Frost HR Consulting”) as the Committee’s independent compensation consultant, to benchmark our executive officer compensation levels with similar positions in our industry peer group. The Committee reviews the relationship annually for any conflicts of interest. To ensure Frost HR Consulting’s independence:
· | The Committee directly retained and has the authority to terminate Frost HR Consulting. |
· | Frost HR Consulting reports directly to the Committee and its Chairperson. |
· | Frost HR Consulting meets regularly in executive sessions with the Committee. |
· | Frost HR Consulting has direct access to all members of the Committee during and between meetings. |
· | Interactions between Frost HR Consulting and management generally are |
· | Frost HR Consulting has procedures in place to prevent conflicts of interest. |
· | Frost HR Consulting does not have any business or personal relationship with any member of management or the Committee. |
· | Frost HR Consulting consultants do not own any of our |
Peer Group and Compensation Surveys
The Committee considered market information from 2014 and 2015 compensation surveys and peer company proxy statements in determining compensation for each of the executive officers. The Committee reviews proxy statement data from a peer group of companies. The surveys used for benchmarking included:
· | Economic Research Institute 2015 Executive Compensation Assessor |
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Petrodelta
General
On October 25, 2007,The Committee reviews the Venezuelan Presidential Decree, which formally transferred to Petrodelta the rights to the Petrodelta Fields subject to the conditionscomposition of the Conversion Contract, was published inpeer group and 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 fieldscompensation paid at these companies, as well as properties with very substantial opportunitiestheir corporate performance and other comparative factors in determining the appropriate compensation levels for both developmentour executives. No company in our peer group shares our unique risk profile, which is a function of our portfolio of producing assets and exploration. We have seconded key technicalexploratory prospects as well as the regulatory and managerial personnel into Petrodeltapolitical environments in which we operate. Therefore, the Committee uses its judgment 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 companiesexperience 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 enactedpeer group data 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).determining executive compensation.
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On February 10, 2015,The Committee selects peer companies for their shared similarities, including a common industry oil exploration focus, assets, market capitalization and enterprise value, among other factors. Revenue at 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 andpeer 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”). Seerange from 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$11.5 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.
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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 $1148.3 million.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,
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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.
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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 $2.0 million and the arbitration was dismissed. We are in the process of closing and exiting our Colombia venture. As we no longer have any interests in Colombia, we reflected the results in discontinued operations.
Production, Prices and Lifting Cost Summary
In the following table we have set forth, for Venezuela, our net production, average sales prices and average operating expenses for the years ended December 31, 2015, 2014 and 2013. The presentation for Venezuela shows our net ownership interest in Petrodelta which was 32 percent through December 15, 2013 and 20.4 percent thereafter.
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Venezuela (Petrodelta) |
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Crude Oil Production (MBbls) (b) |
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| 2,008 |
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Natural Gas Production (MMcf) (a)(c) |
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| 535 |
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Average Crude Oil Sales Price ($ 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) |
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| $ | 19.79 |
| $ | 11.41 |
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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:
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Wells Drilled Productive: |
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Development |
| 18 |
| 3.7 |
| 13 |
| 2.7 |
| 13 |
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Gabon |
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Exploration |
| — |
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| 1 |
| 0.7 |
Producing Wells (1): |
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Venezuela (Petrodelta) |
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Crude Oil |
| 142 |
| 29.0 |
| 170 |
| 34.7 |
| 173 |
| 35.0 |
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Carrizo Oil and Gas Inc. | Halcón Resources, LLC |
Contango Oil and Gas Inc.* |
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FX Energy, Inc. | PetroQuest Energy, Inc. |
Gastar Exploration Ltd. | VAALCO Energy, Inc. |
Gran Tierra Energy, Inc.* | Yuma Energy, Inc.* |
Gulfport Energy, Corp. | ZaZa Energy Corp. |
* New in |
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Average Depth of Wells (Feet) Drilled |
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Crude Oil |
| 8,618 |
| 6,881 |
| 7,979 |
Gabon |
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| 11,260 |
In Gabon, followingFrost HR Consulting typically benchmarks the success in both25th, 50th and 75th percentiles for the pre-salt Gambadata sources mentioned above to provide the Committee with an understanding of competitive pay practices. These surveys, equally weighted with the proxy data, consider each element of compensation and Dentale reservoirs inare collectively referred to as the two Harvest exploration wells, a new seismic survey commenced in October 2013“market data” throughout this Compensation Discussion and we receivedAnalysis. Frost HR Consulting also provides the first high quality seismic products during the second quarterCommittee with advice on equity incentive compensation trends, including types and value 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.
Acreageawards being used by other public companies.
The following table summarizesRole of the developedExecutives in Human Resources Committee Meetings
The Committee invites our CEO, the Vice President, Administration and undeveloped acreage that we own, lease or hold under concessionHuman Resources and the Vice President, General Counsel and Corporate Secretary to attend its meetings. The Vice President, Administration and Human Resources acts as the Committee Secretary and provides reports on plan administration and human resources policies and programs. The Vice President, General Counsel and Corporate Secretary provides legal advice on human resource matters. The CEO makes recommendations with respect to specific compensation decisions. The Committee, without management present, regularly meets in executive session and with its compensation consultant to review executive compensation matters including market data as well as peer group information.
The CEO makes recommendations to the Committee on performance evaluations, base salary changes, and both equity and annual incentive based compensation for executive officers and senior management (other than the CEO). From time to time, the CEO and members of December 31, 2015:
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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 operationsmanagement are invited to participate in Committee meetings to provide information regarding our strategic objectives, financial performance and our abilityrecommendations regarding compensation plans. Management may be asked to finance and fund our growth strategy are affected by political developments and laws and regulations inprepare information for any Committee meeting. Depending on the areas in which we operate. Inagenda for a particular oil and natural gas production operations and economics are affected by:meeting, these materials may include:
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Executive Compensation Components
Our compensation program components are designed to reward executive officers’ contributions, while considering our specific operating situation and how they manage this situation consistent with our strategy. Factors considered in compensating our executives include individual experience, skill sets that are required for multi-national oil and gas operations and their proven record of performance. The principal components of compensation and their purposes for executive officers are:
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Element | Form of Compensation | Purpose | ||
Base salary | Cash | Provide competitive, fixed compensation to attract and retain executive talent | ||
Annual performance based incentive awards | Cash | Create strong financial incentive for achieving financial and strategic successes | ||
Long-term incentive compensation | Stock Options, Stock Appreciation Rights (SARs), Restricted Stock Units (RSU) and Restricted Stock Grants | Provides alignment between executive and shareholder interests by rewarding executives for performance based on appreciation in | ||
Personal benefits | Eligibility to | Broad-based employee benefits for health and welfare and retirement |
Base Salary
We pay base salaries to our executive officers to compensate them for specific job responsibilities during the calendar year. In determining base salaries for our executive officers, the Committee considers market and competitive benchmark data for the executive’s level of responsibility targeting between the 50th and 75th percentile of executive officers in comparable companies, with variation based on individual executive skill sets. Compared to 2015 market data, our base salaries were between 91% and 110% of the target market median.
Based on our current financial situation, the Committee did not recommend salary increases in 2016 for the CEO and the other named executive officers. In March 2014, the CEO and other named executive officers received an average salary increase of 3%.
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Base Salary-Annualized |
| Edmiston |
| Speirs |
| Haynes |
| Nesselrode |
| Head | |||||
2014 |
| $ | 588,000 |
| $ | 370,000 |
| $ | 314,000 |
| $ | 289,000 |
| $ | 283,000 |
2015 |
| $ | 588,000 |
| $ | 370,000 |
| $ | 314,000 |
| $ | 289,000 |
| $ | 283,000 |
2016 |
| $ | 588,000 |
| $ | 370,000 |
| $ | 314,000 |
| $ | 289,000 |
| $ | 283,000 |
Annual Performance-Based Incentive Awards (Bonus)
Each year, in addition to individual performance objectives, the Committee establishes Company performance measures for determining annual incentive awards as follows:
· | Total Shareholder Return (weight 60%) |
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· | Social Responsibility and |
These measures and their weightings are reviewed and modified, if appropriate, in light of changing Company priorities and strategic objectives. The corporate targets and weightings are recommended by the CEO and reviewed and approved by the Committee. The Committee focuses on these corporate goals in evaluating Company performance for the purpose of compensation. Individual performance results of the named executive officers are measured and assessed by the CEO.
Among these corporate goals, total shareholder return was weighted at 60%. The Company realized a total shareholder return of negative 76%, due in part to declining oil prices. This total shareholder return places Harvest in the 3rd quartile among its peer group.
Reserves/Production/Estimated Market Value (EMV) was weighted at 30%. Production decreased by approximately 4% over 2014 at Petrodelta, our Venezuelan affiliate.
Social Responsibility and Governance was weighted at 10% and is used at the discretion of the Committee in deciding the final corporate rating. As expected, there were no violations of our FCPA and Ethics and Business Conduct policies and the Company was accident-free in 2015.
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Individual performance and operational results were combined with the Company performance results and weighted equally to determine each executive’s final annual incentive award. Target award levels for annual incentives are set at 100% of base salary for the CEO and 60% of base salary for the other named executive officers. For 2015 performance, the CEO and the other named executive officer’s individual awards were eligible for 65% of their bonus targets. However, these bonuses have been deferred and will not be paid until the outcome of the sale of Gabon and/or resolution of the sale of Petrodelta.
Long-Term Incentive Compensation
Long-term incentive awards have been granted under our 2001, 2004, 2006 and 2010 Long Term Incentive Plans (“LTIPs”), and the awards are granted to our executive officers to align their personal financial interests with our stockholders. The LTIPs include provisions for stock options, stock appreciation rights (SARs), restricted stock, restricted stock units and cash awards.
Our policy on stock awards is focused on determining the right mix of retention and ownership requirements to drive and motivate our executive officers’ behavior consistent with long-term interests of stockholders. The Committee is the administrator of our LTIPs and, subject to Board of Director approval, has full power to determine the size of awards to our executives, to determine the terms and conditions of grants in a manner consistent with the LTIPs, and to amend the terms and conditions of any outstanding award.
The CEO presents individual stock award recommendations for executive officers to the Committee, and after review and discussion the Committee submits their recommendation to the Board of Directors for approval. The Committee’s policy is to grant awards on the date the Board of Directors approves them. Stock options, stock appreciation rights, restricted stock and/or restricted stock units will be granted once each calendar year on a predetermined date or at the effective date of a new hire or promotion, but not within six months of a previous award to the same individual. The price of options and the value of a restricted stock award issued to a new employee will be set at the closing price on the employee’s effective start date. The price of options and the value of a restricted stock award issued to an employee as a result of a promotion will be set at the closing price on the effective date of that promotion. Under no circumstances will a grant date be set retroactively.
The Board of Directors has adopted stock retention guidelines as an additional means to promote ownership of stock by executive officers and directors. The guidelines apply to any award of restricted stock or options to purchase our stock granted to executive officers and directors after February 2004. Under these guidelines, an executive officer or director must retain at least 50 percent of the shares of restricted stock for at least three years after the restriction lapses. Consequences for failure to adhere to these guidelines shall be determined by the Committee in its discretion including, without limitation, actions with respect to future compensation, and future grants of stock options or restricted stock and performance measures. Under our Insider Trading Policy, executive officers and directors are strictly prohibited from speculative trading including short sales and buying or selling puts or calls on the Company’s securities.
We believe the Company should have the ability to recover compensation paid to executive officers and key employees under certain circumstances. On May 20, 2010, our stockholders approved the 2010 Long-Term Incentive Plan (the “2010 Plan”). This 2010 Plan allows us to recover any award which the Company deems was not warranted after any restatement of corporate performance.
The long-term incentive awards for 2015 included stock options, stock appreciation rights and restricted stock units. Stock appreciation rights can be settled as cash or equity. This mix provides upside potential with the stock options/SARs and a more stable award in the form of restricted stock units. Of the total award value, 70 percent was allocated to options and SARs and 30 percent to restricted stock units based on available shares. As of April 30, 2016, the total shares available for grant under the LTIPs approved by our stockholders are as follows:
Total available for grant as options | 102,000 | |
Total available for grants as restricted stock or options | 6,999 |
Personal Benefits
Our executive officers are covered under the same health and welfare and retirement plans, including our 401(k) plan, as all employees. The executive officers also receive supplemental life insurance to cover the risks of extensive travel required in conducting our global business. We pay 100 percent of all premiums for the following benefits for employees and their eligible dependents:
· | All employees are entitled to a medical benefit with unlimited maximum lifetime benefits, with an annual out-of-pocket deductible of $3,125 per individual and |
· | Life and accidental death and dismemberment (“AD&D”) insurance equal to two times annual salary with a minimum of |
· | Long-term disability benefits provide a monthly benefit of 60 percent of base salary up to a maximum of $10,000 per month. |
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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.
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
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$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
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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:
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An increaseWe do not offer a pension plan or a non-qualified deferred compensation plan for executive officers or employees. In 2015, we did not offer perquisites to executive officers or other employees. We offer relocation and foreign service premiums to employees serving 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.an international location. The Windfall Profits Tax also establishes a special contribution for exorbitant prices to the Venezuelan government of (1) 80 percent when the average priceamount of the Venezuelan Export Basket (“VEB”) exceeds $80 per barrel but is less than $100 per barrel; (2) 90 percent whenpremium will vary depending upon the average priceliving conditions, political situation and general safety conditions of the VEB greater than or equalinternational location. Expatriate employees are also provided housing and utilities allowances where applicable. They also receive a cost of living allowance to $100 per barrel but is less than $110 per barrel; and (3) 95 percent whencover the average price of the VEB is greater than or equal to $110 per barrel. Any increasedifferential between normal living expenses 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 ushost 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 havehome countries, and will continue to take measuresparticipate in the employee benefit plans available to mitigate our risks, no assurance can be providedhome country employees.
Total Direct Compensation
Executive Compensation Compared to Market Data
Compared to 2015 market data, total direct compensation ranged between 45th and 52nd percentile of the target market for all named executive officers. In 2015, actual compensation fell at the following percentiles:
2015 Actual Compensation in Relationship to 2014 Actual Peer Market Data | CEO | Other Named Executive Officers | ||
Base Salary | 54th Percentile | 42nd to 47th percentile | ||
Actual Total Cash | 46th Percentile | 42nd to 47th percentile | ||
Actual Total Direct Compensation | 57th Percentile | 44th to 55th percentile |
Tax and Accounting Implications of Executive Compensation
Deductibility of Executive Compensation
As part of its role, the Committee reviews and considers the deductibility of executive compensation under Section 162(m) of the Internal Revenue Code of 1986 which imposes a limit of $1.0 million on the amount that we will be successfula publicly-held corporation may deduct in doing soany year for the compensation paid or that events beyond our control will not adversely affectaccrued with respect to its named executive officers unless the valuecompensation is performance based. None of our minority investment in Petrodelta.
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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 engagedexecutive officers currently receives compensation exceeding the limits imposed 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. WeSection 162(m). While 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,predict 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 wouldcertainty how executive compensation might 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 by Section 162(m) or applicable tax regulations issued, we may attempt to preserve the tax deductibility of all executive compensation while maintaining our executive compensation program as described in this discussion and may result in further dilutionanalysis.
Employment Agreements
We have entered into Executive Employment Agreements with our current named executive officers: Messrs. Edmiston, Haynes, Speirs, Nesselrode and Head. The contracts have an initial term that automatically extends for one year upon each anniversary unless a one-year notice not to our stockholders. extend is given to the executive. 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 exercisecurrent terms of the CT Warrant, thereby increasing the number of shares received upon exercise. Accordingly, if weemployment agreements 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. through May 31, 2016.
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
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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 Quantities12 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:
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The prevailing price of oil also affects the cost of and availability for drilling rigs, production equipment and related services. We cannot give any assurance that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs.
We operate in 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:
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Under these laws, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs, natural resource damages and other environmental damages. We also could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action orders. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition, results of operations or cash flows.
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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:
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If any of these events occur, we could incur substantial losses as a result of:
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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.
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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.
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:
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| Speirs | Nesselrode | Head | |||
A lump sum amount equal to a certain multiple of base salary | 3 times | 2 times | 2 times | 2 times | 2 times | |||||
An amount equal to a certain number of years times the maximum annual employer contributions made under our 401(k) plan | 3 years |
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| 2 years | 2 years | ||||
Vesting of all stock options and SARs | Yes | Yes | Yes | Yes | Yes | |||||
Vesting of all restricted stock awards and RSUs | Yes | Yes | Yes | Yes | Yes | |||||
Reimbursement of Outplacement Services | Yes | Yes | Yes | Yes | Yes | |||||
Restrictions on ability to compete with our company after termination of employment | 2 years | 2 years | 2 years | 2 years | 2 years |
See Item 1. Business, Operationsthe table titled “Potential Payments under Termination or Change of Control” for details on the above information.
The Committee believes the termination payment included in these employment agreements is needed to attract and retain the executives necessary to achieve our business objectives. However, the Committee also believes termination payments should not be guaranteed. Accordingly, a descriptiontermination payment will not be paid if a termination occurs after notice and lapse of the notice period to terminate the employment agreement. Also, a termination payment will not be made if the executive officer resigns other than for good reason. Good reason under the employment contracts includes: (1) a material breach of the employment agreement by the Company; (2) failure to maintain or reelect the executive officer to his position; (3) a significant reduction of the executive officer’s duties, position or responsibilities; (4) a substantial reduction, without good business reasons, of the facilities and perquisites available to the executive officer; (5) a reduction by the Company of the executive officer’s monthly base salary; (6) failure of the Company to continue the executive officer’s participation in any bonus, incentive, profit sharing, performance, savings, retirement or pension policy, plan, program or arrangement on substantially the same or better basis relative to other participants; or (7) the relocation of the executive officer more than fifty miles from the location of the Company’s principal office.
Change of Control
Since it is in our best interest to retain during uncertain times executive officers who will act in the best interests of the stockholders without concern for personal outcome, our Executive Employment Agreements provide benefits in the event of loss of employment for employees in good standing due to a change of control. Change of control is defined as the acquisition of 50 percent or more of our oil and natural gas properties.
Kensho Sone, et al. v. Harvest Natural Resources, Inc., invoting stock, 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 areacessation of the South China Sea. The complaint alleged that the area belongedincumbent board of directors 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 filedconstitute 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 Courtmajority of the United States. On October 13, 2015,board of directors, or, in certain circumstances, the Supreme Court deniedreorganization, merger, or sale or disposition of at least 50 percent of our assets where we are not the petition.surviving entity. Change of control severance benefits apply to terminations taking place between 240 days before a change of control and 730 days after a change of control.
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.
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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:
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Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions based on the interpretation of the tax code by SENIAT (the Venezuelan income tax authority), as it applies to operating service agreements, Harvest Holding has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.
Libertador Municipality Tax Assessments. Harvest Vinccler has received five assessments from a tax inspector for the Libertador municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:
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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
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.
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Year |
| Quarter |
| High |
| Low |
2014 |
| First quarter |
| 4.80 |
| 3.75 |
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| Second quarter |
| 5.30 |
| 3.51 |
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| Third quarter |
| 5.01 |
| 3.67 |
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| Fourth quarter |
| 3.97 |
| 1.68 |
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2015 |
| First quarter |
| 1.09 |
| 0.44 |
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| Second quarter |
| 2.08 |
| 0.44 |
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| Third quarter |
| 1.65 |
| 0.83 |
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| Fourth quarter |
| 1.50 |
| 0.43 |
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On March 23, 2015, the last sales price for the common stock as reported by the NYSE was $0.59 a share.
Historically, our policy has been to retain earnings to support the growth of our business, and accordingly, our Board of Directors has never declared a cash dividend on our common stock.
On December 2, 2015, the Company received notification from the NYSE that the Company had fallen below the NYSE's continued listing standards, which require a minimum average closing price of $1.00 per share over 30 consecutive trading days. Under the NYSE's rules, Harvest has a period of six months from the date of the NYSE notice to bring its share price and 30 trading-day average share price back above $1.00. During this period, the Company’s common stock will continue to be traded on the NYSE under the symbol "HNR", subject to the Company’s compliance with other NYSE continued listing requirements, but will be assigned the notation .BC after the listing symbol to signify that the Company is not currently in compliance with the NYSE’s continued listing standards. As required by the NYSE, in order to maintain its listing, Harvest has notified the NYSE that it intends to cure the price deficiency. However, there can be no assurance that the Company will be able to do so. While we have not yet received any notification from the NYSE, as of the date of this Report, we believe we may be in noncompliance with a second NYSE continued listing standard, which states that a company will be in noncompliance if its average global market capitalization over a consecutive 30 trading-day period is less than $50.0 million at a time when its stockholders’ equity is less than $50.0 million. We believe the NYSE will give us an opportunity to cure this deficiency, but there can be no assurance that we will be able to cure or will be given such opportunity before the NYSE commences delisting procedures.
24
Stock Performance Graph
The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2015, assuming an investment of $100 on December 31, 2010 in each of Harvest’s common stock, the Dow Jones U.S. Select Oil Exploration & Production Index and the S&P Composite 500 Stock Index.
This graph assumes that the value of the investment in Harvest stock and each index was $100 at December 31, 2010 and all dividends were reinvested.
PLOT POINTS
(December 31 of each year)
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| 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 |
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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.
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| Year Ended December 31, |
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| 2015 |
| 2014 |
| 2013 |
| 2012 |
| 2011 |
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| (in thousands, except per share data) |
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Operating loss |
| $ | (211,896) |
| $ | (449,605) |
| $ | (45,436) |
| $ | (38,826) |
| $ | (77,155) |
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Earnings from Investment in Affiliates |
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| — |
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| 34,949 |
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| 72,578 |
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| 67,769 |
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| 73,451 |
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Income (loss) from continuing operations (1) |
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| (98,570) |
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| (192,936) |
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| (83,946) |
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| 2,199 |
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| (30,285) |
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Net income (loss) attributable to Harvest |
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| (98,570) |
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| (193,490) |
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| (89,096) |
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| (12,211) |
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| 55,960 |
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Net income (loss) from continuing operations attributable to Harvest per common share: |
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Basic (1) |
| $ | (2.18) |
| $ | (4.59) |
| $ | (2.12) |
| $ | 0.06 |
| $ | (0.89) |
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Diluted (1) |
| $ | (2.18) |
| $ | (4.59) |
| $ | (2.12) |
| $ | 0.06 |
| $ | (0.89) |
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Weighted average common shares outstanding |
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Basic |
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| 45,288 |
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| 42,039 |
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| 39,579 |
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| 37,424 |
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| 34,117 |
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Diluted |
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| 45,288 |
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| 42,039 |
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| 39,579 |
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| 37,591 |
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| 34,117 |
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(1) Net of net income attributable to noncontrolling interest owners. |
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| As of December 31, |
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| 2015 |
| 2014 |
| 2013 |
| 2012 |
| 2011 |
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Balance Sheet Data: |
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Total assets |
| $ | 47,781 |
| $ | 228,046 |
| $ | 734,880 |
| $ | 596,837 |
| $ | 507,203 |
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Long-term debt (3) |
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| 214 |
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| — |
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| — |
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| 74,839 |
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| 31,535 |
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Total Harvest stockholders’ equity (1) (2) |
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| 36,759 |
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| 113,726 |
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| 302,630 |
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| 379,337 |
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| 355,691 |
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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.
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| Year Ended December 31, | |||||||
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| 2015 |
| 2014 |
| 2013 | |||
Thousand barrels of oil sold |
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| 14,761 |
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| 15,561 |
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| 14,538 |
Million cubic feet of natural gas sold |
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| 3,934 |
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| 2,981 |
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| 2,593 |
Total thousand BOE |
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| 15,417 |
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| 16,058 |
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| 14,970 |
Average BOE per day |
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| 42,237 |
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| 43,994 |
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| 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) |
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| (c) |
| $ | 289,521 |
| $ | 141,627 |
Capital expenditures (thousands) |
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| (c) |
| $ | 430,629 |
| $ | 269,239 |
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Dussafu Project – Gabon
We have a 66.667 percent ownership interest in the Dussafu PSC through two separate acquisitions, and we are the operator. The Dussafu PSC partners and Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources, is in the third exploration phase of the Dussafu PSC which was extended to May 27, 2016. The Company is currently assessing extension possibilities for the exploration phase.
During 2011, we drilled our first exploratory well, Dussafu Ruche Marin-1 (“DRM-1”), and two appraisal sidetracks. DRM-1 and sidetracks discovered oil of approximately 149 feet of pay within the Gamba and Middle Dentale Formations. DRM-1 and the sidetracks are currently suspended pending further exploration and development activities.
During the fourth quarter of 2012, our second exploration well on the Tortue prospect to target stacked pre-salt Gamba and Dentale reservoirs commenced. DTM-1 was spud on November 19, 2012 in a water depth of 380 feet. On January 4, 2013, we announced that DTM-1 had reached a vertical depth of 11,260 feet within the Dentale Formation. Log evaluation and pressure data indicate that we have an oil discovery of approximately 42 feet of pay in a 72-foot column within the Gamba Formation and 123 feet of pay in stacked reservoirs within the Dentale Formation. The first appraisal sidetrack of DTM-1 (“DTM-1ST1”) was spud in January 12, 2013. DTM-1ST1 was drilled to a total depth of 11,385 feet in the Dentale Formation, approximately 1,800 feet from DTM-1 wellbore and found 65 feet of pay in the primary Dentale reservoir. Several other stacked sands with oil shows were encountered; however, due to a stuck downhole tool, logging operations were terminated before pressure data could be collected to confirm connectivity. The downhole tool was retrieved and the DTM-1 well was suspended for future re-entry. We have met all funding commitments for the third exploration phase of the Dussafu PSC.
Central/inboard 3D seismic data acquired in 2011 has been processed and interpreted to review prospectivity. We have begun processing data from the 1,260 Sq Km of 3D seismic survey performed during the fourth quarter of 2013. This survey provides 3D coverage over the outboard portion of the block where significant pre-salt prospectivity has been recognized on 2D seismic data. The new 3D seismic data also covers the Ruche, Tortue and Moubenga discoveries and is expected to enhance the placement of future development wells in the Ruche and Tortue development program as well as provide improved assessment of the numerous undrilled structures already identified on older 2D seismic surveys.
On March 26, 2014, the joint venture partners approved a resolution that the discovered fields are commercial to exploit. On June 4, 2014, a Declaration of Commerciality (“DOC”) was signed with Gabon pertaining to the four discoveries on the Dussafu Project offshore Gabon. Furthermore, on July 17, 2014, the Direction Generale Des Hydrocarbures (“DGH”) awarded an Exclusive Exploitation Authorization (“EEA”) for the development and exploitation of certain oil discoveries on the Dussafu Project and on October 10, 2014, the field development plan was approved. The Company has four years from the date of the EEA approval to begin production.
Since approval of the Field Development Plan (“FDP”) in October 2014, Harvest has continued to move toward development of the Ruche Exclusive Exploitation Area. A tender for all the subsea equipment was concluded in January 2015 where prices exceeded the costs employed in the FDP. Efforts continue to negotiate with the lowest priced vendors and to revise the development scheme to
28
bring the projected cost back to the FDP levels. The depth volume from the 2013 3D seismic acquisition over the discovered fields and the outboard area of the license has been received and interpreted. This new data was incorporated into our reservoir models and optimization of well trajectories to maximize oil recovery is ongoing. In addition, the prospect inventory was updated and several prospects have been high graded for drilling in the first half of 2016. To accommodate the drilling schedule, a site survey, including bathymetry and geophysical data gathering with respect to prospects A/B, 6/7 and 8/9, was completed in August 2015. A tender for a drilling rig for the planned well was completed in November 2015 and a tender for well testing and other services were concluded in January 2016.
Harvest and its joint venture partner engaged a contractor to undertake a fixed-price, geophysical site survey over multiple potential well locations in the Dussafu block in August 2015. The survey is a pre-requisite for siting mobile drilling units and other installations required for continuing exploration and development activities over the license. The survey will provide information about the seabed and shallow geological conditions, essential for the safe siting and operation of these installations.
During the year ended December 31, 2015, we had cash capital expenditures of $0.9 million for site survey ($1.2 million for well costs during the year ended December 31, 2014). The 2016 budget for the Dussafu PSC is $3.6 million. See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon for further information on the Dussafu Project.
The Company is considering options to develop, sell or farm-down its interest in the Dussafu Project in order to obtain the maximum value from the asset, while maintaining the required liquidity to continue our current operations.
In December 2014, the Company recorded a $50.3 million impairment related to the unproved costs of the Dussafu PSC based on a qualitative analysis which considered our current liquidity needs, our inability to attract additional capital and the decrease in oil and natural gas prices. In December 2015, the Company reassessed the carrying value of the unproved costs related to the Dussafu PSC and recorded an additional impairment of $23.2 million based on its analysis of the value of the unproved costs which considered the value of the contingent and exploration resources and the ability of the Company to develop the project given its current liquidity situation and the depressed price of crude oil.
We reviewed the value of our oilfield inventories that are in the country of Gabon, of which the majority is steel conductor and casing. We impaired the value of this inventory by approximately $1.0 million, leaving $3.0 million related to this inventory as of December 31, 2015.
Colombia – Discontinued Operations
In February 2013, we signed farm-down agreements on Block VSM14 and Block VSM15 in Colombia. Under the terms of the farm-down agreements, we had a 75 percent beneficial working interest and our partners had a 25 percent carried interest for the minimum exploratory work commitments on each block. We requested the legal assignment of the interest by the Agencia Nacional de Hidrocarburos (“ANH”), Colombia’s oil and natural gas regulatory authority, and approval of us as operator.
For both blocks, phase one of the contract began on December 15, 2012 and expired on December 15, 2015. We have received notices of default from our partners for failing to comply with certain terms of the farm-down agreements for Block VSM14 and Block VSM15, followed by notices of termination on November 27, 2013. Our partners filed for arbitration of claims related to these agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests, and we recorded an impairment charge of $3.2 million during the year ended December 31, 2013 which included an accrual of $2.0 million related to this matter. On December 14, 2014 we paid our partners $2.0 million to settle the arbitration. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations. We are in the process of closing and exiting our Colombia venture. During the year ended December 31, 2013 we had capital expenditures of $1.2 million for leasehold acquisition costs. See Item 1. Business, Operations, Colombia – Discontinued Operations for further information on this project.
Results of Operations
The following discussion on results of operations for each of the years in the three-year period ended December 31, 2015 should be read in conjunction with our consolidated financial statements and related notes thereto.
Years Ended December 31, 2015 and 2014
We reported a net loss attributable to Harvest of $98.6 million, or $2.18 diluted earnings per share, for the year ended December 31, 2015, compared with a net loss attributable to Harvest of $193.5 million, or $4.60 diluted earnings per share, for the year ended December 31, 2014.
29
Loss From Continuing Operations
Expenses and other non-operating (income) expense from continuing operations were:
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| Year Ended December 31, |
| Increase | |||||
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| 2015 |
| 2014 |
| (Decrease) | |||
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Depreciation and amortization |
| $ | 108 |
| $ | 198 |
| $ | (90) |
Exploration expense |
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| 3,900 |
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| 6,267 |
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| (2,367) |
Impairment expense - unproved property costs and oilfield inventories |
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| 24,178 |
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| 57,994 |
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| (33,816) |
Impairment expense - investment in affiliate |
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| 164,700 |
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| 355,650 |
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| (190,950) |
General and administrative |
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| 19,010 |
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| 29,496 |
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| (10,486) |
Loss on sale of interest in Harvest Holding |
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| — |
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| 1,574 |
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| (1,574) |
Gain on sale of oil and gas properties |
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| — |
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| (2,865) |
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| 2,865 |
Change in fair value of warrant liabilities |
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| (34,510) |
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| (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, 2014. The net loss attributable to noncontrolling interest owners in 2015 was related to the impairment of our investment in Petrodelta as well as to our ongoing operations at Harvest Vinccler as they continue oversight of our investment in Petrodelta. The net loss attributable to noncontrolling interest owners in 2014 was related to the impairment of our investment in Petrodelta and our decision to cease recording earnings from Petrodelta in the second quarter due to the expected sales price of the second tranche purchase agreement approximating the recorded value of our investment in Petrodelta.
Discontinued Operations
Oman
As a result of the decision to not request an extension of the first phase or enter the second phase of the EPSA A1 Ghubar / Qarn Alam license (“Block 64 EPSA”), Block 64 was relinquished effective May 23, 2013. The carrying value of Block 64 EPSA of $6.4 million was written off to impairment expense at December 31, 2012. Operations in Oman were terminated, and the field office was closed May 31, 2013. We have no continuing involvement in Oman. The nominal loss from discontinued operations for Oman for the year ended December 31, 2014 included general and administrative expenses for legal and other professional fees.
Colombia
We received notices of default from our partners for failing to comply with certain terms of the farm-down agreements for Block VSM14 and Block VSM15 in Colombia, followed by notices of termination on November 27, 2013. As discussed further in Item 3. Legal Proceedings, our partners filed for arbitration of claims related to these agreements. We accrued $2.0 million as of December 31, 2013 related to obligations under the farm-down agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests. On December 14, 2014 we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations. We are in the process of closing and exiting our Colombia venture. The loss from discontinued operations included $0.5 million in general and administrative expenses during the year ended December 31, 2014.
Oman and Colombia operations have been classified as discontinued operations. There were no revenues applicable to discontinued operations during the years ended December 31, 2015 and 2014. Losses from discontinued operations were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, | ||||
|
| 2015 |
| 2014 | ||
|
|
|
|
|
|
|
|
| (in thousands) | ||||
Oman |
| $ | — |
| $ | (27) |
Colombia |
|
| — |
|
| (527) |
Net loss from discontinued operations |
| $ | — |
| $ | (554) |
|
|
|
|
|
|
|
Years Ended December 31, 2014 and 2013
We reported a net loss attributable to Harvest of $193.5 million, or $4.60 diluted earnings per share, for the year ended December 31, 2014, compared with a net loss attributable to Harvest of $89.1 million, or $2.25 diluted earnings per share, for the year ended December 31, 2013.
32
Loss From Continuing Operations
Expenses and other non-operating (income) expense from continuing operations were:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| % |
|
|
| |||||
|
| Year Ended December 31, |
| Increase |
| Increase |
| Increase | |||||||
|
| 2014 |
| 2013 |
| (Decrease) |
| (Decrease) |
| (Decrease) | |||||
|
| (dollars in thousands, except prices) | |||||||||||||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
| $ | 1,343,452 |
| $ | 1,326,093 |
| $ | 17,359 |
| 1 | % |
|
|
|
Natural gas |
|
| 4,590 |
|
| 4,000 |
|
| 590 |
| 15 | % |
|
|
|
Total revenues |
| $ | 1,348,042 |
| $ | 1,330,093 |
| $ | 17,949 |
| 1 | % |
|
|
|
Price and Volume Variances: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil price variance (per Bbl) |
| $ | 86.33 |
| $ | 91.22 |
| $ | (4.89) |
| (5.36) |
|
|
| $ (70,965) |
Natural gas sales prices Variance (per Mcf) |
|
| 1.54 |
|
| 1.54 |
|
| — |
| — |
|
|
| — |
Volume variances: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil volumes (MBbls) |
|
| 15,561 |
|
| 14,538 |
|
| 1,023 |
| 7 | % |
|
| 88,316 |
Natural gas volumes (MMcf) |
|
| 2,981 |
|
| 2,593 |
|
| 388 |
| 15 | % |
|
| 598 |
Total variance |
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 17,949 |
Revenues were higher in the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to an increase in sales volumes resulting from running a six drilling rig program as well as an additional pricing adjustments related to the approved El Salto contract, $38.2 million for 2014 and $60.4 million for previous years that were invoiced in 2014 offset by a decrease in crude oil prices. The decrease in price primarily reflects an overall decrease in market oil prices, but also resulted from increased El Salto field production, which is sold at the lower Boscan price.
34
Total expenses and other non-operating (income) expense, inclusive of all adjustments necessary to reconcile Net Income from Petrodelta to Earnings from Affiliate:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, |
| Increase | |||||
|
| 2014 |
| 2013 |
| (Decrease) | |||
|
| (in thousands) | |||||||
Royalties |
| $ | 437,281 |
| $ | 440,963 |
| $ | (3,682) |
Operating expenses (inclusive of U.S. GAAP adjustment) |
|
| 289,521 |
|
| 141,627 |
|
| 147,894 |
Workovers |
|
| 28,239 |
|
| 29,168 |
|
| (929) |
Depletion, depreciation and amortization (inclusive of U.S. GAAP adjustment) |
|
| 141,846 |
|
| 107,556 |
|
| 34,290 |
General and administrative |
|
| 45,623 |
|
| 37,778 |
|
| 7,845 |
Windfall profits tax (inclusive of U.S. GAAP adjustment) |
|
| 140,816 |
|
| 234,453 |
|
| (93,637) |
(Gain) loss on exchange rate |
|
| 260 |
|
| (169,582) |
|
| 169,842 |
Investment earnings and other |
|
| (7,752) |
|
| (1,414) |
|
| (6,338) |
Interest expense (inclusive of U.S. GAAP adjustment) |
|
| 51,256 |
|
| 21,728 |
|
| 29,528 |
Income tax expense (inclusive of U.S. GAAP adjustment) |
|
| 73,843 |
|
| 298,475 |
|
| (224,632) |
Adjustment stated at our 40% interest related to amortization of excess basis |
|
| 4,428 |
|
| 3,684 |
|
| 744 |
For the year ended December 31, 2014 compared to the year ended December 31, 2013, royalties, which is a function of revenue, decreased due to the decrease in crude oil prices offset by an increase in sales volumes discussed above (net increase in revenue of $17.9 million at 30 percent royalty). The increase in operating expense is due to higher personnel costs as a result of new labor contract, higher maintenance costs and increased chemical costs. Workover expense is lower for the year ended December 31, 2014 than the year ended December 31, 2013 due to running one workover rig in 2014 versus between one and two workovers rigs in 2013. Depletion, depreciation and amortization increased as a result of higher capitalized costs, including wells and infrastructure placed in service during 2014. Windfall profits tax expense decreased from declining Venezuela crude basket prices in line with declining world oil prices in 2014. The foreign currency transaction gain in 2013 is due to the Bolivar devaluation in February 2013 from 4.30 Bolivars/U.S. Dollar to 6.30 Bolivars/U.S. Dollar and Petrodelta having more Bolivar denominated liabilities than Bolivar denominated assets. Interest expense is due to increase in adjustments to the fair value of VAT credits ($47.7 million) offset by decrease accretion expense ($18.2 million). Income tax expense decreased between the years primarily due to a revision to inflation adjustments to fixed assets and by the decrease in pre-tax income.
Net Income Attributable to Noncontrolling Interests Owners
Net loss attributable to noncontrolling interest owners was $165.2 million for the year ended December 31, 2014 compared to net income attributable to noncontrolling interest owners of $11.6 million for year ended December 31, 2013. The net loss attributable to noncontrolling interest owners in 2014 was related to the impairment of our investment in Petrodelta and our decision to cease recording earnings from Petrodelta in the second quarter due to the expected sales price of the second tranche purchase agreement approximating the recorded value of our investment in Petrodelta. During 2013 the net income attributable to noncontrolling interest owners was impacted by the sale of a portion of our interest in Harvest Holding which occurred in December.
Discontinued Operations
Oman
As a result of the decision to not request an extension of the first phase or enter the second phase of the EPSA A1 Ghubar / Qarn Alam license (“Block 64 EPSA”), Block 64 was relinquished effective May 23, 2013. The carrying value of Block 64 EPSA of $6.4 million was written off to impairment expense at December 31, 2012. Operations in Oman were terminated, and the field office was closed May 31, 2013. We have no continuing involvement in Oman. The nominal loss from discontinued operations for Oman for the year ended December 31, 2014 included general and administrative expenses for legal and other professional fees. The loss from discontinued operations for Oman of $0.7 million for the year ended December 31, 2013 included $0.2 million of exploration expense and $0.5 million of general and administrative expenses and other expenses.
Colombia
We received notices of default from our partners for failing to comply with certain terms of the farm-down agreements for Block VSM14 and Block VSM15 in Colombia, followed by notices of termination on November 27, 2013. Our partners filed for arbitration of claims related to these agreements. We accrued $2.0 million as of December 31, 2013 related to obligations under the farm-down agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests. On December 14, 2014 we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations. We are in the process of closing and exiting our Colombia venture. The loss from discontinued operations included $0.5 million in general and administrative expenses for primarily contract service during the year ended December 31, 2014. The loss from
35
discontinued operations included $3.2 million in impairment expense, $0.7 million of exploration expense and $0.6 million in general and administrative expenses for contract services and travel during the year ended December 31, 2013.
Oman and Colombia operations have been classified as discontinued operations. There were no revenues applicable to discontinued operations during the years ended December 31, 2014 and 2013. Losses from discontinued operations were:
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| 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 alternatives to farm-down or sell our interest in the Dussafu Project, while weighing the liquidity requirements necessary to maintain ongoing Company operations. The development of, or a transaction regarding, the Dussafu project and the success of negotiations between PDVSA, CT Energy, and HNR Finance for the management of Petrodelta will directly impact our future earnings, cash flows, and balance sheet. Without these transactions or additional financings or other sources of cash, we may not have sufficient liquidity for operations or capital requirements. There can be no guarantee of realizing the value of our exploration and exploitation acreage or suspended wells in the Dussafu project or our investment in Petrodelta or that we can obtain further financings or sources of cash.
On June 19, 2015, CT Energy purchased from the Company 9% and 15% Notes and the CT Warrant. The Company immediately received gross proceeds of $32.2 million from the sale of the securities. The Company used $9.7 million of these
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proceeds to repay its existing debt plus accrued interest and certain financing fees. The remaining proceeds will be used to position the Company for long-term growth, both in Venezuela and Gabon as well as to fund general and administrative costs. On September 15, 2015, the 9% Note and associated accrued interest was converted into 8,667,597 shares of Harvest common stock. See Part IV – Item 15 – Exhibit and Financial Statement Schedules, Note 1 – Organization for further information.
As of December 31, 2014, HNR Energia had a note payable to Petroandina of $7.6 million. Principal was due by January 1, 2016. Interest payments were to be paid quarterly beginning on December 31, 2014. On June 23, 2015 the Company repaid the note payable of $7.6 million plus accrued interest of $0.4 million.
At December 31, 2014, HNR Energia had a note payable to Vinccler of $6.1 million. Principal and interest were payable upon the maturity date of December 31, 2015. On March 6, 2015, Vinccler forgave the note payable and accrued interest of $6.2 million. This was reflected as a contribution to stockholders’ equity.
Accumulated Undistributed Earnings of Foreign Subsidiaries
Under ASC 740-30-25-17, no deferred tax liability must be recorded if sufficient evidence shows that a foreign subsidiary has invested or will invest its undistributed earnings or that the earnings will be remitted in a tax-free manner. Management must consider numerous factors in determining timing and amounts of possible future distribution of these earnings to the parent company and whether a U.S. deferred tax liability should be recorded for these earnings. These factors include the future operating and capital requirements of both the parent company and the subsidiaries, remittance restrictions imposed by foreign governments or financial agreements and tax consequences of the remittance, including possible application of U.S. foreign tax credits and limitations on foreign tax credits that may be imposed by the Internal Revenue Code and regulations.
Prior to 2013, no U.S. taxes had been recorded on these earnings as it was our practice and intention to reinvest the earnings of our non-U.S. subsidiaries into our foreign operations. During the fourth quarter of 2013, management evaluated numerous factors related to the timing and amounts of possible future distribution of foreign earnings to the parent company, with consideration of the sale of non-U.S. assets. Because management was pursuing various alternatives with respect to the Company’s future operations and disposition of any sale proceeds, a determination was made that it was appropriate to record a deferred tax liability associated with the unremitted earnings of our foreign subsidiaries of $89.9 million in the fourth quarter of 2013. However, due primarily to the $355.7 million pre-tax impairment of Petrodelta, this balance decreased by $75.2 million to $14.7 million at December 31, 2014.
As of December 31, 2015, the book-tax outside basis difference in our foreign subsidiary resulting from unremitted earnings was reduced to zero due to a pre-tax impairment of the Company’s remaining investment in Petrodelta of $164.7 million. Consequently, the deferred tax liability associated with the foreign earnings was reduced to zero. The entire net deferred tax liability as of December 31, 2014 has been reflected as a long-term liability, a characterization consistent with the Company’s adoption of Accounting Standards Update (“ASU”) No. 2015-17. See New Accounting Pronouncements for further information.
Working Capital and Cash Flows
The net funds raised or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:
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| 2014 |
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Net cash used in operating activities |
| $ | (23,892) |
| $ | (39,210) |
| $ | (37,077) |
Net cash provided by (used in) investing activities |
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| (1,270) |
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| (5,031) |
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| 80,460 |
Net cash provided by (used in) financing activities |
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| 26,338 |
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| (70,071) |
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| 4,887 |
Net increase (decrease) in cash |
| $ | 1,176 |
| $ | (114,312) |
| $ | 48,270 |
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Working capital |
| $ | 6,232 |
| $ | (12,951) |
| $ | 88,894 |
Current ratio |
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| 2.3 |
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| 0.4 |
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| 3.5 |
Total cash, including restricted cash |
| $ | 7,761 |
| $ | 6,610 |
| $ | 121,045 |
Total debt (net of discount) |
| $ | 214 |
| $ | 13,709 |
| $ | 83,589 |
Working Capital
The increase in working capital of $19.2 million between December 31, 2014 and December 31, 2015 was primarily due to cash proceeds from issuance of debt and the CT Warrant in the CT Energy transaction offset by cash used to fund our loss from operations, capital expenditures and interest payments on notes payable and the 9% and 15% Notes.
The decrease in working capital of $101.8 million between December 31, 2013 and December 31, 2014 was primarily due to cash used to fund our loss from operations, interest payments as well as the extinguishment of certain debt in January 2014.
Cash Flow from Operating Activities
During the year ended December 31, 2015, net cash used in operating activities was approximately $23.9 million ($39.2 million during the year ended December 31, 2014). The $15.3 million decrease in use of cash from operations was primarily from the decreased use of working capital in 2015 due to our decreased activity levels.
Cash Flow from Investing Activities
Our cash capital expenditures for property and equipment are summarized in the following table:
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| Year Ended December 31, | |||||||
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| 2014 |
| 2013 | |||
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Budong PSC |
| $ | — |
| $ | 3,152 |
| $ | 175 |
Dussafu PSC |
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| 947 |
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| 1,194 |
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| 42,536 |
Other |
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| 323 |
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| 36 |
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| — |
Total additions of property and equipment – continuing operations |
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| 1,270 |
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| 4,382 |
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| 42,711 |
Colombia-discontinued operations (1) |
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| — |
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| — |
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| 1,195 |
Total additions of property and equipment |
| $ | 1,270 |
| $ | 4,382 |
| $ | 43,906 |
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Our only investing activities in during the year ended December 31, 2015 were cash capital expenditures.
In addition to cash capital expenditures, during the year ended December 31, 2014 we:
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In addition to cash capital expenditures, during the year ended December 31, 2013, we:
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Our budgeted capital expenditures of $4.0 million for 2016 for U.S. and Gabon operations will be funded through our existing cash balances, accessing equity and debt markets, and cost reductions. In addition, we could delay the discretionary portion of our capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, as warranted.
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Cash Flow from Financing Activities
During the year ended December 31, 2015, we:
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During the year ended December 31, 2014, we:
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During the year ended December 31, 2013, we:
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Contractual Obligations
At December 31, 2015, we had the following lease commitments for office space in Houston, Texas and regional office in Caracas, Venezuela.
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At December 31, 2015, we had the following contractual obligations:
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| 1 Year |
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Debt: |
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15% Note with related party (1) |
| $ | 25,225 |
| $ | — |
| $ | — |
| $ | — |
| $ | 25,225 |
Total debt |
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| 25,225 |
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| — |
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| — |
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| — |
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| 25,225 |
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Other obligations: |
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Interest payments |
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| 17,494 |
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| 3,923 |
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| 3,913 |
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| 3,913 |
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| 5,745 |
Oil and natural gas activities (2) |
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| 4,520 |
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| 1,130 |
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| 1,130 |
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| 1,130 |
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| 1,130 |
Office leases |
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| 171 |
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| 157 |
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| 14 |
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| — |
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| — |
Total other obligations |
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| 22,185 |
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| 5,210 |
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| 5,057 |
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| 5,043 |
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| 6,875 |
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Total contractual obligations |
| $ | 47,410 |
| $ | 5,210 |
| $ | 5,057 |
| $ | 5,043 |
| $ | 32,100 |
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15% Non-Convertible Senior Secured Note due June 19, 2020
On June 19, 2015, in connection with the transaction with CT Energy described in Part IV – Item 15 – Exhibits and Financial Statements Schedules Note 1 – Organization, we issued the five-year, 15% Note in the aggregate principal amount of $25.2 million with interest that is compounded quarterly at a rate of 15.0% per annum and is payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2015. If by June 19, 2016, the volume weighted average price of the Company’s common stock over any consecutive 30-day period has not equaled or exceeded $2.50 per share, the maturity date of the 15% Note will be extended by two years and the interest rates on the 15% Note will adjust to 8.0% (the “15% Note Reset Feature”). During an event of default, the outstanding principal amount bears additional interest at a rate of 2.0% per annum higher than the rate otherwise applicable. See Part IV – Item 15 – Exhibits and Financial Statements Schedules, Note 11 – Debt and Financing.
Effects of Changing Prices, Foreign Exchange Rates and Inflation
Our results of operations and cash flow are affected by changing oil prices. Fluctuations in oil prices may affect our total planned development activities and capital expenditure program.
Our net foreign exchange gain attributable to our international operations was $0.3 million for the year ended December 31, 2015 compared to $0.2 million loss on foreign currency transactions for the year ended December 31, 2014. The gains in 2015 are primarily associated with favorable changes in the Bolivar denominated liabilities. The loss in 2014 is primarily related to converting USD to Bolivars from participating in the SICAD II auctions and USD to Euros. There are many factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our control. Petrodelta, our investment in affiliate, is required to follow the foreign exchange controls placed on PDVSA which requires them to use a 6.3 Bolivars per USD exchange rate. Harvest Vinccler is able to bring money into the country using the SIMADI foreign exchange system which is at a 200 Bolivars per USD exchange rate. The foreign exchange gains and losses referred to here are generated from activity of Harvest Vinccler and not Petrodelta. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.
On March 9, 2016, Venezuela Vice President for Economic Area announced a new exchange agreement No. 35 (the “Exchange Agreement No. 35”). Exchange Agreement No. 35 was published in Venezuela’s Official Gazette No. 40865 dated March 9, 2016, and became effective on March 10, 2016. Exchange Agreement No. 35 will have a dual exchange rate for a controlled rate (named DIPRO) fixed at 10 USD/Bolivars for priority goods and services and a complimentary rate (named DICOM) starting at 206.92 USD/Bolivars for travel and other non-essential goods. We are evaluating the impact Exchange Agreement No. 35 has on Harvest Vinccler and Petrodelta.
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Harvest Vinccler’s functional and reporting currency is the USD. They do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”) (198.70 Bolivars per USD).
Within the United States and other countries in which we conduct business, inflation has had a minimal effect on us, but it is an important factor with respect to certain aspects of the results of operations in Venezuela. The 2015 annual inflation rate in Venezuela provided by the Central Bank of Venezuela (BCV) through December 2015 was 180.9 percent.
Critical Accounting Policies
Reporting and Functional Currency
USD is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. Amounts denominated in non-USD currencies are re-measured into USD, and all currency gains or losses are recorded in the consolidated statements of operations and comprehensive loss. There are many factors that affect foreign exchange rates and the resulting exchange gains and losses, many of which are beyond our influence.
Investment in Affiliate
We evaluate our investments in unconsolidated companies under “ASC 323 – Investments – Equity Method and Joint Ventures” and “ASC 325 – Investments – Other”. In accordance with ASC 323, investments in which we have significant influence were accounted for under the equity method of accounting. Under the equity method, our Investment in Affiliate was increased by additional investments and earnings and decreased by dividends and losses. We review our Investment in Affiliate for impairment whenever events and circumstances indicate a loss in investment value is other than a temporary decline. Once an event is identified that is other than temporary, a loss is recognized and the Investment in Affiliate is reduced to fair value.
Investments where we do not have significant influence are accounted for in accordance with ASC 325. Under this method we will not recognize any equity in earnings from our investments in our results of operations, but will recognize any cash dividends in the period they are received. We review our Investment in Affiliate for impairment whenever events and circumstances indicate a loss in investment value is other than a temporary decline. Once an event is identified that is other than temporary, a loss is recognized and the Investment in Affiliate is reduced to fair value.
Through December 31, 2014, we included the results of Petrodelta in our financial statements under the equity method. We ceased recording earnings from Petrodelta in the second quarter 2014 due to the expected sales price of the second closing purchase agreement approximating the recorded value of our investment in Petrodelta. The Company was not able to obtain approval from the government of Venezuela during 2014 and on January 1, 2015 we terminated the SPA. Due to our failed sales attempts, lack of management influence, and actions and inactions by the majority owner, PDVSA, we believe we no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014. Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.
Capitalized Interest
We capitalize interest costs for qualifying oil and natural gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation.
Property and Equipment
We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. We assess our unproved property costs for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of the projects. The estimated value of our unproved projects is determined using quantitative and qualitative assessments and the carrying value of the projects is adjusted if the carrying value exceeds the assessed value of the projects.
During the years ended December 31, 2015 and 2014, we recorded impairment expense, related to our Dussafu Project in Gabon, of $24.2 million (including $1.0 million relating to oilfield inventories) and $50.3 million, respectively, which reflect management’s estimate of the decreased value of the project given our current liquidity situation and the decline in global crude oil prices. During 2014, we recognized impairments related to our Budong Project in Indonesia of $7.7 million and in 2013, we also recognized impairments of $0.6 and $3.2 million related to projects in Indonesia and Colombia that we elected to abandon and which is reflected in discontinued operations.
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If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and natural gas properties. Lease rentals are expensed as incurred. Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered proved reserves. Exploratory drilling costs are capitalized when drilling is completed if it is determined that there is economic producibility supported by either actual production, conclusive formation tests or by certain technical data. If proved reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development wells and related equipment used in production of crude oil and natural gas, are capitalized.
Depletion, depreciation, and amortization (“DD&A”) of the cost of proved oil and natural gas properties are calculated using the unit of production method. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is proved reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base is proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.
Assets are grouped based upon a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
Amortization rates are updated to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions or property dispositions and 4) impairments.
We account for impairments of proved properties under the provisions of ASC 360, “Property, Plant, and Equipment”. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field level to the amortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the amortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.
Income Taxes
Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Since December 31, 2013, we have provided deferred income taxes on undistributed earnings of our foreign subsidiaries where we are not able to assert that such earnings were permanently reinvested, or otherwise could be repatriated in a tax free manner, as part of our ongoing business. As of December 31, 2015, the deferred tax liability provided on such earnings has been reduced to zero due to the impairment of the underlying book investment in Petrodelta.
As the conversion feature of the 9% Note was reasonably expected to be exercised at the time of the note’s issuance due to the conversion price being in-the-money, the interest on the 9% Note paid upon its conversion is non-deductible to the Company under Internal Revenue Code (“IRC”) Section 163(l). The 15% Note was issued, for income tax purposes, with original issue discount (“OID”). OID generally is deductible for income tax purposes. However, if the debt instrument constitutes an “applicable high-yield discount obligation” (“AHYDO”) within the meaning of IRC Section 163(i)(1), then a portion of the OID likely would be non-deductible pursuant to IRC Section 163(e)(5). Our analysis of the 15% Note is that the note may be an AHYDO; consequently, a portion or all of the OID likely may be non-deductible for income tax purposes.
New Accounting Pronouncements
In April 2015, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs”. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. In June 2015 the FASB issued ASU No. 2015-15 as an amendment to this guidance to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements. The SEC staff stated that they would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance is effective for interim periods and annual period beginning after December 15, 2015; however early adoption is permitted. We do not believe the adoption of this guidance will have a material impact on our financial position and will not have an impact on our results of operations or cash flows.
In August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern”. ASU No. 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide
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related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU No. 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.
In April 2014, FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers” which is included in ASC 606, a new topic under the same name. The guidance in this update affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). The guidance supersedes the previous revenue recognition requirements and most industry-specific guidance. Additionally, the update supersedes some cost guidance related to construction type and production-type contracts. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in this update.
The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps: (1) identify the contract(s) with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation.
The new guidance also provides for additional qualitative and quantitative disclosures related to: (1) contracts with customers, including revenue and impairments recognized, disaggregation of revenue, and information about contract balances and performance obligations (including the transaction price allocated to the remaining performance obligations); (2) significant judgments and changes in judgments which impact the determination of the timing of satisfaction of performance obligations (over time or at a point in time), the transaction price and amounts allocated to performance obligations; and (3) assets recognized from the costs to obtain or fulfill a contract.
In July 2015, the FASB issued a decision to delay related to ASU No. 2014-09 for the effective date by one year. The new guidance is effective for annual and interim periods beginning after December 15, 2017. An entity should apply the amendments either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of initial application. We are currently evaluating the impact of this guidance.
In November 2015, the FASB issued ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes”. ASU No. 2015-17 simplifies the balance sheet presentation of deferred income taxes by requiring all deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The standard is effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted. The standard may be applied either prospectively or retrospectively to all periods presented. The Company has decided to adopt the accounting change in its current financial statements and has adopted the change retrospectively.
In February 2016, the FASB issued ASU No. 2016-02, “Leases”. It is expected to be effective for periods beginning after December 15, 2018 for public entities, and for periods beginning after December 15, 2019 for nonpublic entities. Early application is permitted. Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less. All other leases will fall into one of two categories: (1) Financing leases, similar to capital leases, will require the recognition of an asset and liability, measured at the present value of the lease payments. Interest on the liability will be recognized separately from amortization of the asset. Principal repayments will be classified as financing outflows and payments of interest as operating outflows on the statement of cash flows. (2) Operating leases will also require the recognition of an asset and liability measured at the present value of the lease payments. A single lease cost, consisting of interest on the obligation and amortization of the asset, calculated such that the amortization of the asset will increase as the interest amount decreases resulting in a straight-line recognition of lease expense. All cash outflows will be classified as operating on the statement of cash flows. We do not believe the adoption of this guidance will have a material impact on our financial position, results of operations or cash flows.
In March 2016, the FASB issued ASU No. 2016-07, “Investments — Equity Method and Joint Ventures (Topic 323)”. This amendment simplifies the accounting for equity method investments; the amendment in the update eliminates the requirement in Topic 323 that an entity retroactively adopt the equity method of accounting if an investment qualifies for use of the equity method as a result of an increase in the level of ownership or degree of influence. The amendment requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt equity method of accounting as of the date the investment becomes qualified for equity method accounting. The amendment in this update is effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. The amendment should be applied prospectively upon the effective date to increases in the level of ownership interest or degree of influence that result in the adoption of the equity method. Earlier application is permitted. We are currently evaluating the impact of this guidance.
43
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk from adverse changes in oil and natural gas prices and foreign exchange risk and are not able to quantify this risk, as discussed below.
Oil Prices
Oil and natural gas prices historically have been volatile, and this volatility is expected to continue. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control. Being primarily a crude oil producer, we are more significantly impacted by changes in crude oil prices than by changes in natural gas prices. As an independent oil producer, our revenue, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. We did not have any revenues for the years ended December 31, 2015, 2014 or 2013.
We and our investment in affiliate currently do not have any oil production that is hedged. While hedging limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements.
Interest Rates
The $25.2 million face value of our debt at December 31, 2015 consisted of a 15.0% Note with interest that compounds quarterly at a rate of 15.0% per annum and is payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2015. On January 4, 2016, the outstanding principal amount of the 15% Note increased to $26.1 million. See Part IV – Item 15 – Exhibits and Financial Statements Schedules, Note 10 – Debt and Financing.
Foreign Exchange
The Bolivar is not readily convertible into the U.S. Dollar. We have not utilized currency hedging programs to mitigate any risks associated with operations in Venezuela, and, therefore, our financial results are subject to favorable or unfavorable fluctuations in exchange rates and inflation in that country. Venezuela has imposed currency exchange controls. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Effects of Changing Prices, Foreign Exchange Rates and Inflation above.
Item 8. Financial Statements and Supplementary Data
The information required by this item is included herein and begins on page S-1.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures that are designed to ensure the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Management of the Company, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures. Based on their evaluation as of December 31, 2015, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) were effective.
Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the 2013 Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of The Treadway Commission. Based on our evaluation under the 2013 Internal Control Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2015. The effectiveness of our internal control over financial reporting as of December 31,
44
2015, has been audited by BDO USA, LLP, an independent registered public accounting firm, as stated in their report which appears herein in Part IV – Item 15 – Exhibits and Financial Statement Schedules, Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting.
Changes in Internal Control over Financial Reporting. There have been no changes in internal control over financial reporting during the quarter ended December 31, 2015 that have materially affected or are reasonably likely to materially affect that Company’s internal control over financial reporting.
None.
45
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is, or the Company intends that the information required by this item will be, set forth in the definitive proxy statement relating to the 2016 Annual Meeting of Stockholders of Harvest Natural Resources, Inc. (the Proxy Statement”) or an amendment to this report. Such information is incorporated by reference into this item pursuant to General Instruction G(3) to Form 10-K.
Item 11. Executive Compensation
The information required by this item is, or the Company intends that the information required by this item will be, set forth in the Proxy Statement or in an amendment to this report. Such information is incorporated by reference pursuant to General Instruction G(3) to Form 10-K.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is, or the Company intends that the information required by this item will be, set forth in the Proxy Statement or in an amendment to this report. Such information is incorporated by reference pursuant to General Instruction G(3) to Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is, or the Company intends that the information required by this item will be, set forth in the Proxy Statement or in an amendment to this report. Such information is incorporated by reference pursuant to General Instruction G(3) to Form 10-K.
Item 14. Principal Accountant Fees and Services
The information required by this item is, or the Company intends that the information required by this item will be, set forth in the Proxy Statement or in an amendment to this report. Such information is incorporated by reference pursuant to General Instruction G(3) to Form 10-K.
46
Item 15. Exhibits and Financial Statement Schedules
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Entitlements based on terms in Executive Agreements if we terminate the employment without cause or notice related to a Change of Control |
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Edmiston |
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Haynes |
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Speirs |
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Nesselrode |
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A lump sum amount equal to a certain multiple of base salary |
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3 times |
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A lump sum amount equal to a certain multiple of the highest annual bonus over the past 3 years or target bonus, whichever is higher | 3 times | 2 times | 2 times | 2 times | 2 times | |||||
An amount equal to a certain number of years times the maximum annual employer contributions made under our 401(k) plan | 3 years | 2 years | 2 years | 2 years | 2 years | |||||
Continuation of accident, life, disability, dental and health benefits for a certain number of years | 3 years | 2 years | 2 years | 2 years | 2 years | |||||
Excise tax reimbursement and gross up on the reimbursement | Yes | Yes | Yes | Yes | Yes | |||||
Vesting of all stock options and SARs | Yes | Yes | Yes | Yes | Yes | |||||
Vesting of all restricted stock awards and RSUs | Yes | Yes | Yes | Yes | Yes | |||||
Reimbursement of outplacement services | Yes | Yes | Yes | Yes | Yes | |||||
Restrictions on ability to compete with our company after termination of employment | 2 years | 2 years | 2 years | 2 years | 2 years |
All schedules are omitted because they are not applicable or the required information is shownThe change of control benefits in the financial statementsemployment agreements contain a double trigger in that both a change of control must occur and the executive officer must be terminated without cause or resign for good reason within a specified period of time after the notes thereto.
(b)change of control. The Committee believes that the double trigger avoids unnecessarily rewarding an executive officer when a change of control occurs and the executive officer’s status is not changed as a result. However, because of the significant uncertainty that can arise during a period of a potential or actual change of control, the Committee has provided greater benefits to the executive officer in the event of a termination resulting from a change of control. Change of control benefits are detailed in the “Potential Payments under Termination or Change of Control” table in the 3. Exhibits:
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* Filed herewith.
^ Furnished herewith.
† Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15(a) and (b) of Form 10-K. section.
HUMAN RESOURCES COMMITTEE REPORT
The Human Resources Committee has reviewed and discussed with management the Compensation Discussion and Analysis filed in this document. Based on such review and discussions, the Human Resources Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Amended Report.
R. E. Irelan, Committee Chairman
Edgard A. Leal
Patrick M. Murray
49
- 14 -
REPORTCOMPENSATION OF INDEPENDENT REGISTERED EXEPUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTINGCUTIVE OFFICERS
To the Board of Directors and
Stockholders of Harvest Natural Resources, Inc.
Houston, Texas
We have audited Harvest Natural Resources, Inc. and subsidiaries (the “Company”) internal control over financial reporting as of December 31, 2015, based on criteria established in SuInternal Control – Integrated Framework (2013)mmary Compensation Table issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A., Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Harvest Natural Resources, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Harvest Natural Resources, Inc. and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations and comprehensive loss, stockholders’ equity and cash flows for the years then ended and our report dated March 29, 2016 expressed an unqualified opinion thereon and contains explanatory paragraphs referring to the Company’s change in the method of accounting for the classification of deferred taxes and the Company’s ability to continue as a going concern.
/s/ BDO USA, LLP
Houston, Texas
March 29, 2016
S-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ToThe following table summarizes the Board of Directors and
Stockholders of Harvest Natural Resources, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Harvest Natural Resources, Inc. and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations and comprehensive loss, stockholders’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibilitycompensation of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Harvest Natural Resources, Inc. and subsidiaries at December 31, 2015 and 2014, and the consolidated results of their operations and their cash flowsnamed executive officers for the years then ended in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, the Company has changed its method of accounting for the classification of deferred taxes in the consolidated balance sheets as of December 31, 2015 and 2014 due to the retrospective adoption of Financial Accounting Standards Board, Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As described in Note 2 to the consolidated financial statements, the Company has not generated revenues and has suffered recurring losses and negative cash flows from operations that raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Harvest Natural Resources, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 29, 2016 expressed an unqualified opinion thereon.
/s/ BDO USA, LLP
Houston, Texas
March 29, 2016
S-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Stockholders of Harvest Natural Resources, Inc.
We have audited the accompanying consolidated statements of operations and comprehensive loss, stockholders’ equity and cash flows of Harvest Natural Resources, Inc. and subsidiaries (the “Company”) for the year ended December 31, 2013. The Company’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the Company’s consolidated results of operations and cash flows for the year ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.
/s/ UHY LLP
Houston, Texas
March 17, 2014
S-3
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
(in thousands, except per share data)
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| December 31, | ||||
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| 2015 |
| 2014 | ||
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ASSETS |
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CURRENT ASSETS: |
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Cash and cash equivalents |
| $ | 7,761 |
| $ | 6,585 |
Restricted cash |
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| — |
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| 25 |
Accounts receivable |
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| 2,461 |
|
| 339 |
Prepaid expenses and other |
|
| 826 |
|
| 353 |
TOTAL CURRENT ASSETS |
|
| 11,048 |
|
| 7,302 |
INVESTMENT IN AFFILIATE |
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| — |
|
| 164,700 |
PROPERTY AND EQUIPMENT: |
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|
|
Oil and natural gas properties (successful efforts method) |
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| 31,006 |
|
| 54,290 |
Other administrative property, net |
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| 455 |
|
| 217 |
TOTAL PROPERTY AND EQUIPMENT, net |
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| 31,461 |
|
| 54,507 |
EMBEDDED DERIVATIVE ASSET |
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| 5,010 |
|
| — |
LONG-TERM DEFERRED INCOME TAX ASSETS |
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| 120 |
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| 53 |
OTHER ASSETS, net of allowance for $0.7 million and $0.0 million at December 31, 2015 and 2014, respectively. |
|
| 142 |
|
| 1,484 |
TOTAL ASSETS |
| $ | 47,781 |
| $ | 228,046 |
LIABILITIES AND EQUITY |
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|
|
CURRENT LIABILITIES: |
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|
|
Accounts payable, trade and other |
| $ | 370 |
| $ | 1,697 |
Accrued expenses |
|
| 3,327 |
|
| 4,617 |
Accrued interest |
|
| 954 |
|
| 97 |
Notes payable to noncontrolling interest owners |
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| — |
|
| 13,709 |
Other current liabilities |
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| 165 |
|
| 133 |
TOTAL CURRENT LIABILITIES |
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| 4,816 |
|
| 20,253 |
LONG-TERM DEBT DUE TO RELATED PARTY, net of discount |
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| 214 |
|
| — |
LONG-TERM DEFERRED TAX LIABILITIES, net |
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| — |
|
| 14,700 |
WARRANT DERIVATIVE LIABILITY WITH RELATED PARTY |
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| 5,503 |
|
| — |
OTHER LONG-TERM LIABILITIES |
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| 42 |
|
| 215 |
TOTAL LIABILITIES |
|
| 10,575 |
|
| 35,168 |
COMMITMENTS AND CONTINGENCIES (Note 13) |
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STOCKHOLDERS’ EQUITY: |
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|
|
Preferred stock, par value $0.01 per share; authorized 5,000 shares; issued and outstanding, none |
|
| — |
|
| — |
Common stock, par value $0.01 per share; shares authorized 150,000 (2015) and 80,000 (2014); shares issued (2015 - 57,987; 2014 - 49,320); shares outstanding (2015 - 51,415; 2014 - 42,748) |
|
| 580 |
|
| 493 |
Additional paid-in capital |
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| 302,273 |
|
| 280,757 |
Accumulated deficit |
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| (199,778) |
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| (101,208) |
Treasury stock, at cost, 6,572 shares (2015 and 2014) |
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| (66,316) |
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| (66,316) |
TOTAL HARVEST STOCKHOLDERS’ EQUITY |
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| 36,759 |
|
| 113,726 |
NONCONTROLLING INTEREST OWNERS |
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| 447 |
|
| 79,152 |
TOTAL EQUITY |
|
| 37,206 |
|
| 192,878 |
TOTAL LIABILITIES AND EQUITY |
| $ | 47,781 |
| $ | 228,046 |
See accompanying notes to consolidated financial statements.
S-4
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS
(in thousands, except per share data)
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| Year Ended December 31, | |||||||
| 2015 |
| 2014 |
| 2013 | |||
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EXPENSES: |
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Depreciation and amortization | $ | 108 |
| $ | 198 |
| $ | 341 |
Exploration expense |
| 3,900 |
|
| 6,267 |
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| 15,155 |
Impairment expense - unproved property costs and oilfield inventories |
| 24,178 |
|
| 57,994 |
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| 575 |
Impairment expense - investment in affiliate |
| 164,700 |
|
| 355,650 |
|
| — |
General and administrative |
| 19,010 |
|
| 29,496 |
|
| 29,365 |
|
| 211,896 |
|
| 449,605 |
|
| 45,436 |
LOSS FROM OPERATIONS |
| (211,896) |
|
| (449,605) |
|
| (45,436) |
OTHER NON-OPERATING INCOME (EXPENSE): |
|
|
|
|
|
|
|
|
Loss on the sale of interest in Harvest Holding |
| — |
|
| (1,574) |
|
| (22,994) |
Gain on sale of oil and natural gas properties |
| — |
|
| 2,865 |
|
| — |
Change in fair value of warrant liabilities |
| 34,510 |
|
| 1,953 |
|
| 3,517 |
Change in fair value of derivative assets and liabilities |
| 4,813 |
|
| — |
|
| — |
Interest expense |
| (2,959) |
|
| (11) |
|
| (4,495) |
Loss on debt conversion |
| (1,890) |
|
| — |
|
| — |
Loss on issuance of debt and warrants |
| (20,402) |
|
| — |
|
| — |
Loss on extinguishment of long-term debt |
| — |
|
| (4,749) |
|
| — |
Foreign currency transaction gains (losses), net |
| 261 |
|
| (219) |
|
| (820) |
Other non-operating income (expense), net |
| 483 |
|
| (58) |
|
| (1,569) |
|
| 14,816 |
|
| (1,793) |
|
| (26,361) |
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND EARNINGS FROM INVESTMENT IN AFFILIATE |
| (197,080) |
|
| (451,398) |
|
| (71,797) |
INCOME TAX EXPENSE (BENEFIT) |
| (16,423) |
|
| (58,290) |
|
| 73,087 |
LOSS FROM CONTINUING OPERATIONS BEFORE EARNINGS FROM INVESTMENT IN AFFILIATE |
| (180,657) |
|
| (393,108) |
|
| (144,884) |
EARNINGS FROM INVESTMENT IN AFFILIATE |
| — |
|
| 34,949 |
|
| 72,578 |
LOSS FROM CONTINUING OPERATIONS |
| (180,657) |
|
| (358,159) |
|
| (72,306) |
DISCONTINUED OPERATIONS |
| — |
|
| (554) |
|
| (5,150) |
NET LOSS |
| (180,657) |
|
| (358,713) |
|
| (77,456) |
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST OWNERS |
| (82,087) |
|
| (165,223) |
|
| 11,640 |
NET LOSS AND COMPREHENSIVE LOSS ATTRIBUTABLE TO HARVEST | $ | (98,570) |
| $ | (193,490) |
| $ | (89,096) |
BASIC LOSS PER SHARE: |
|
|
|
|
|
|
|
|
Loss from continuing operations | $ | (2.18) |
| $ | (4.59) |
| $ | (2.12) |
Discontinued operations |
| — |
|
| (0.01) |
|
| (0.13) |
Basic loss per share | $ | (2.18) |
| $ | (4.60) |
| $ | (2.25) |
DILUTED LOSS PER SHARE: |
|
|
|
|
|
|
|
|
Loss from continuing operations | $ | (2.18) |
| $ | (4.59) |
| $ | (2.12) |
Discontinued operations |
| — |
|
| (0.01) |
|
| (0.13) |
Diluted loss per share | $ | (2.18) |
| $ | (4.60) |
| $ | (2.25) |
See accompanying notes to consolidated financial statements.
S-5
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)
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|
|
|
|
|
|
| Common Shares Issued |
| Common Stock |
| Additional Paid-in Capital |
| Retained Earnings (Loss) |
| Treasury Stock |
| Non- Controlling Interests |
| Total Equity | ||||||
Balance at January 1, 2013 | 45,882 |
| $ | 458 |
| $ | 263,646 |
| $ | 181,378 |
| $ | (66,145) |
| $ | 97,101 |
| $ | 476,438 |
Issuance of common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of stock options | 20 |
|
| — |
|
| 122 |
|
| — |
|
| — |
|
| — |
|
| 122 |
Sales of common shares | 2,495 |
|
| 25 |
|
| 9,273 |
|
| — |
|
| — |
|
| — |
|
| 9,298 |
Employee stock-based compensation | 269 |
|
| 4 |
|
| 3,042 |
|
| — |
|
| — |
|
| — |
|
| 3,046 |
Purchase of treasury shares | — |
|
| — |
|
| — |
|
| — |
|
| (77) |
|
| — |
|
| (77) |
Increase in equity held by noncontrolling interests due to sale of interest in affiliate | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 144,796 |
|
| 144,796 |
Dividend to noncontrolling interest owner | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| (10,370) |
|
| (10,370) |
Net income (loss) | — |
|
| — |
|
| — |
|
| (89,096) |
|
| — |
|
| 11,640 |
|
| (77,456) |
Balance at December 31, 2013 | 48,666 |
| $ | 487 |
| $ | 276,083 |
| $ | 92,282 |
| $ | (66,222) |
| $ | 243,167 |
| $ | 545,797 |
Issuance of common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of common shares | 654 |
|
| 6 |
|
| 2,022 |
|
| — |
|
| — |
|
| — |
|
| 2,028 |
Employee stock-based compensation | — |
|
| — |
|
| 2,652 |
|
| — |
|
| — |
|
| — |
|
| 2,652 |
Purchase of treasury shares | — |
|
| — |
|
| — |
|
| — |
|
| (94) |
|
| — |
|
| (94) |
Contributions from noncontrolling interest owners | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 1,208 |
|
| 1,208 |
Net loss | — |
|
| — |
|
| — |
|
| (193,490) |
|
| — |
|
| (165,223) |
|
| (358,713) |
Balance at December 31, 2014 | 49,320 |
| $ | 493 |
| $ | 280,757 |
| $ | (101,208) |
| $ | (66,316) |
| $ | 79,152 |
| $ | 192,878 |
Issuance of common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee stock-based compensation | — |
|
| — |
|
| 2,271 |
|
| — |
|
| — |
|
| — |
|
| 2,271 |
Conversion of 9% Note | 8,667 |
|
| 87 |
|
| 13,088 |
|
| — |
|
| — |
|
| — |
|
| 13,175 |
Contribution from noncontrolling owner of note payable and accrued interest payable | — |
|
| — |
|
| 6,157 |
|
| — |
|
| — |
|
| — |
|
| 6,157 |
Contributions from noncontrolling interest owners | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 3,382 |
|
| 3,382 |
Net loss | — |
|
| — |
|
| — |
|
| (98,570) |
|
| — |
|
| (82,087) |
|
| (180,657) |
Balance at December 31, 2015 | 57,987 |
| $ | 580 |
| $ | 302,273 |
| $ | (199,778) |
| $ | (66,316) |
| $ | 447 |
| $ | 37,206 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
S-6
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, | |||||||
| 2015 |
| 2014 |
| 2013 | |||
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
Net loss | $ | (180,657) |
| $ | (358,713) |
| $ | (77,456) |
Adjustments to reconcile net loss to net cash used in operating activities: |
|
|
|
|
|
|
|
|
Depreciation and amortization |
| 108 |
|
| 198 |
|
| 354 |
Impairment expense - unproved property costs and oilfield inventories |
| 24,178 |
|
| 57,994 |
|
| 3,770 |
Impairment expense - investment in affiliate |
| 164,700 |
|
| 355,650 |
|
| — |
Amortization of debt financing costs |
| 283 |
|
| 28 |
|
| 1,489 |
Accretion of discount on debt |
| 225 |
|
| — |
|
| 2,641 |
Allowance for long-term receivable |
| 734 |
|
| 13,753 |
|
| — |
Loss on the sale of interest in Harvest Holding |
| — |
|
| 1,574 |
|
| 22,994 |
Gain on sale of oil and natural gas properties |
| — |
|
| (2,865) |
|
| — |
Loss on debt issuance |
| 20,402 |
|
| — |
|
| — |
Loss on debt conversion |
| 1,890 |
|
| — |
|
| — |
Foreign currency transaction loss |
| — |
|
| 1,239 |
|
| 436 |
Loss on extinguishment of long-term debt |
| — |
|
| 4,749 |
|
| — |
Earnings from investment in affiliate |
| — |
|
| (34,949) |
|
| (72,578) |
Share-based compensation-related charges |
| 2,271 |
|
| 2,652 |
|
| 3,046 |
Deferred income tax expense (benefit) |
| (14,767) |
|
| (58,221) |
|
| 73,689 |
Change in fair value of warrant liabilities |
| (34,510) |
|
| (1,953) |
|
| (3,517) |
Change in fair value of derivative assets and liabilities |
| (4,813) |
|
| — |
|
| — |
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
| (2,122) |
|
| 1,623 |
|
| 993 |
Prepaid expenses and other |
| (473) |
|
| 339 |
|
| 710 |
Other assets |
| 350 |
|
| (328) |
|
| 3,971 |
Accounts payable |
| (1,327) |
|
| (2,701) |
|
| 428 |
Accrued expenses |
| (1,259) |
|
| (16,112) |
|
| 3,790 |
Accrued interest |
| 1,036 |
|
| (360) |
|
| (244) |
Other current liabilities |
| 32 |
|
| (2,464) |
|
| (1,043) |
Other long-term liabilities |
| (173) |
|
| (343) |
|
| (550) |
NET CASH USED IN OPERATING ACTIVITIES |
| (23,892) |
|
| (39,210) |
|
| (37,077) |
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Transaction costs from the sale of interest in Harvest Holding |
| — |
|
| (3,742) |
|
| — |
Net proceeds from sale of oil and natural gas properties |
| — |
|
| 2,865 |
|
| — |
Net proceeds from sale of interest in investment in affiliate |
| — |
|
| — |
|
| 124,045 |
Additions of property and equipment, net |
| (1,270) |
|
| (4,382) |
|
| (43,906) |
Payment from (advances to) investment in affiliate, net |
| — |
|
| 105 |
|
| (531) |
Decrease in restricted cash |
| — |
|
| 123 |
|
| 852 |
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES |
| (1,270) |
|
| (5,031) |
|
| 80,460 |
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Debt repayment |
| (8,900) |
|
| (79,750) |
|
| — |
Debt extinguishment costs |
| — |
|
| (760) |
|
| — |
Gross proceeds from issuance of debt and warrant |
| 33,500 |
|
| — |
|
| — |
Proceeds from issuance of note payable to noncontrolling interest owner |
| — |
|
| 7,600 |
|
| — |
Proceeds from issuance of common stock |
| — |
|
| 2,036 |
|
| 9,420 |
Contributions from noncontrolling interest owners |
| 3,382 |
|
| 1,208 |
|
| — |
Treasury stock purchases |
| — |
|
| (94) |
|
| (77) |
Payments on note payable to noncontrolling interest owner |
| — |
|
| — |
|
| (4,260) |
Financing costs |
| (1,644) |
|
| (311) |
|
| (196) |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES |
| 26,338 |
|
| (70,071) |
|
| 4,887 |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS |
| 1,176 |
|
| (114,312) |
|
| 48,270 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR |
| 6,585 |
|
| 120,897 |
|
| 72,627 |
CASH AND CASH EQUIVALENTS AT END OF YEAR | $ | 7,761 |
| $ | 6,585 |
| $ | 120,897 |
See accompanying notes to consolidated financial statements.
S-7
Supplemental Schedule of Noncash Investing and Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, | |||||||
|
|
|
|
|
|
|
|
|
|
|
| 2015 |
| 2014 |
| 2013 | |||
Supplemental Cash Flow Information: |
| (in thousands) | |||||||
Cash paid during the period for interest expense |
| $ | 1,547 |
| $ | — |
| $ | 487 |
Cash paid during the period for income taxes |
|
| 6 |
|
| 1,128 |
|
| 495 |
Supplemental Schedule of Noncash Investing and Financing Activities: |
|
|
|
|
|
|
|
|
|
Decrease in current liabilities related to additions of property and equipment |
| $ | (30) |
| $ | (210) |
| $ | (13,926) |
Increase in Stockholders' Equity from forgiveness of note payable and accrued interest |
|
| 6,157 |
|
| — |
|
| — |
Issuance of common stock from conversion of 9% Convertible Senior Secured Note |
|
| 13,175 |
|
| — |
|
| — |
See accompanying notes to consolidated financial statements.
S-8
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Harvest Natural Resources, Inc. (“Harvest” or the “Company”) is an independent energy company engaged in the acquisition, exploration, development, production and disposition of oil and natural gas properties since 1988, when it was incorporated under Delaware law.
We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through Harvest-Vinccler Dutch Holding B.V., a Dutch private company with limited liability (“Harvest Holding”). Our ownership of Harvest Holding is through HNR Energia B.V. (“HNR Energia”) in which we have a direct controlling interest. Prior to December 16, 2013, we indirectly owned 80 percent of Harvest Holding and we had one partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., (“Vinccler”, a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A.), which owned the remaining noncontrolling interest in Harvest Holding of 20 percent. We do not have a business relationship with Vinccler outside of Venezuela. On December 16, 2013, Harvest and HNR Energia entered into a Share Purchase Agreement (the “SPA”) with Petroandina Resources Corporation N.V. (“Petroandina”, a wholly owned subsidiary of Pluspetrol Resources Corporation B.V. (“Pluspetrol”)) and Pluspetrol to sell all of our 80 percent equity interest in Harvest Holding to Petroandina in two closings for an aggregate cash purchase price of $400.0 million. The first closing occurred on December 16, 2013 contemporaneously with the signing of the SPA, when we sold a 29 percent equity interest in Harvest Holding for $125.0 million. This first transaction resulted in a loss on the sale of the interest in Harvest Holding of $23.0 million in the year ended December 31, 2013. As a result of this first sale, we indirectly own 51 percent of Harvest Holding beginning December 16, 2013 and the noncontrolling interest owners hold the remaining 49 percent with Petroandina having 29 percent and Vinccler continuing to own 20 percent. The second closing did not occur during 2014 and the SPA was terminated by the Company on January 1, 2015. See Note 5 – Dispositions below for further information on this transaction.
Harvest Holding owns 100 percent of HNR Finance B.V. (“HNR Finance”), and HNR Finance owns a 40 percent interest in Petrodelta, S.A. (“Petrodelta”). Petrodelta is our cost investment in eastern Venezuela responsible for the exploration, development, production, gathering, transportation and storage of hydrocarbons in six oil fields. Petrodelta is governed by its own charter and bylaws and the shareholders intend that the Company be self-funding and rely on internally-generated cash flows.
Corporación Venezolana del Petroleo S.A. (“CVP”) and PDVSA Social S.A. owns the remaining 56 percent and 4 percent, respectively, of Petrodelta. Petroleos de Venezuela S.A. (“PDVSA”) owns 100 percent of CVP and PDVSA Social S.A. Through our indirect 51 percent in Harvest Holding, we indirectly own a net 20.4 percent interest in Petrodelta for the period from December 16, 2013 to date, and prior to December 16, 2013 we indirectly owned a 32 percent interest in Petrodelta through our indirect 80 percent interest in Harvest Holding during this period.
In addition to its 40 percent interest in Petrodelta, Harvest Holding also indirectly owns 100 percent of Harvest Vinccler, S.C.A. (“Harvest Vinccler”). Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with PDVSA.
In addition to our interests in Venezuela, we also hold exploration and exploitation acreage offshore of the Republic of Gabon (“Gabon”) through the Dussafu Marin Permit (“Dussafu PSC”). See Note 8 – Gabon.
On June 19, 2015, the Company and certain of its domestic subsidiaries entered into a securities purchase agreement (the “Purchase Agreement”) with CT Energy Holding SRL (“CT Energy”), a Venezuelan-Italian consortium organized as a Barbados Society with Restricted Liability, under which CT Energy purchased certain securities of the Company and acquired certain governance rights. Harvest immediately received gross proceeds of $32.2 million from the sale of the securities, as described below. Key terms of the transaction include:
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|
|
|
|
|
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|
|
At our annual shareholder meeting, on September 9, 2015, Harvest stockholders approved, among other proposals, 1) certain aspects of the transaction under NYSE shareholder approval requirements and Delaware law and 2) an amendment to Harvest's charter to increase the number of authorized shares of our common stock from 80,000,000 to 150,000,000, in part to have sufficient shares to issue upon conversion of the 9% Note and exercise of the CT Warrant and an amendment to the 2010 Long Term Incentive Plan increasing the number shares of our common stock to satisfy of stock options, stock appreciation rights (“SARs”), restricted stock, restricted stock units (“RSUs”) and other stock-based awards. See Note 15 – Stock-Based Compensation and Stock Purchase Plans.
Note 2 – Liquidity and Going Concern
We expect that for 2016 we will not generate revenue, will continue to generate losses from operations, and our cash flows will not be sufficient to cover our operating expenses. Therefore, expected continued losses from operations, capital needs and uses of cash will be funded through debt or equity financings, farm-downs, delay of the discretionary portion of our capital spending to future periods or operating cost reductions. Our ability to continue as a going concern depends on our ability to negotiate the management and structure of our investment in Petrodelta and the success of our planned exploration and development activities in Gabon. There can be no guarantee of future capital acquisition, fundraising or exploration success or that we will realize the value of our exploration and exploitation acreage and suspended wells. We believe that we will continue to be successful in securing any funds necessary to continue as a going concern. However, our current cash position and our inability to access additional capital may limit our available opportunities or not provide sufficient cash for operations.
Historically, prior to the transaction pursuant to the Purchase Agreement, our primary ongoing source of cash had been dividends from Petrodelta, issuance of debt and the sale of oil and natural gas properties. Our primary use of cash has been to fund oil and natural gas exploration projects, principal payments on debt, interest, and general and administrative costs. We require capital principally to fund the exploration and development of new oil and natural gas properties. We have various contractual commitments pertaining to exploration, development and production activities.
See Note 8 – Gabon and Note 13 – Commitments and Contingencies for our contractual commitments.
We are currently assessing alternatives for our Gabon asset, and we intend to continue our consideration of a possible sale or farm-down of our Gabon asset if we are able to negotiate a sale or sales in transactions that our Board of Directors believes are in the best interests of the Company and its stockholders. Given that we do not currently have any operating cash inflows, we may also decide to access additional capital through equity or debt sales; however, there can be no assurance that such financing will be available to the Company or on terms that are acceptable to the Company.
On December 2, 2015, the Company received notification from the NYSE that the Company was not in compliance with the NYSE's continued listing standards, which require a minimum average closing price of $1.00 per share over 30 consecutive trading days. Under the NYSE's rules, Harvest has a period of six months from the date of the NYSE notice to bring its share price and 30 trading-day average share price back above $1.00. During this period, the Company’s common stock will continue to be traded on the NYSE under the symbol “HNR”, subject to the Company’s compliance with other NYSE continued listing requirements, but will be assigned the notation .BC after the listing symbol to signify that the Company is not currently in compliance with the NYSE’s continued listing standards. As required by the NYSE, in order to maintain its listing, Harvest has notified the NYSE that it intends to cure the price deficiency.
Failure to generate sufficient cash flow, raise additional capital through debt or equity financings, farm-downs, or reduce operating costs could have a material adverse effect on our ability to meet our short- and long-term liquidity needs and achieve our intended long-term business objectives.
The above circumstances raise substantial doubt about our ability to continue as a going concern. While we believe the issuance of additional equity securities, short- or long-term debt financing, farm-downs, the delay of the discretionary portion of our capital
S-10
spending to future periods or operating cost reductions could be put into place which would not jeopardize our operations and future growth plans, there can be no assurance that such financings will be successful.
Our financial statements have been prepared under the assumption that we will continue as a going concern, which contemplates that we will continue in operation for the foreseeable future and will be able to realize assets and settle liabilities and commitments in the normal course of business. The accompanying consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or amounts and classification of liabilities that could result should we be unable to continue as a going concern.
Note 3 – Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. All intercompany profits, transactions and balances have been eliminated. Third-party interests in our majority-owned subsidiaries are presented as noncontrolling interest owners.
Reclassifications
Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications did not affect our consolidated financial results.
Investment in Petrodelta
Through December 31, 2014, we included the results of Petrodelta in our financial statements under the equity method. We ceased recording earnings from Petrodelta in the second quarter 2014 due to the expected sales price of the second closing purchase agreement approximating the recorded value of our investment in Petrodelta. The Company was not able to obtain approval from the government of Venezuela during 2014 and on January 1, 2015 we terminated the SPA. Due to our failed sales attempts, lack of management influence, and actions and inactions by the majority owner, PDVSA, we believe we no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014. Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.
We evaluate our investment in Petrodelta for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may be impaired. A loss is recorded in earnings in the current period if a decline in the value of the investment is determined to be other than temporary. Impairment is calculated as the difference between the carrying value of the investment and its fair value. We recorded pre-tax impairment charges against the carrying value of our investment in Petrodelta of $164.7 million and $355.7 million during the years ended December 31, 2015 and 2014, respectively. See Note 6 – Investment in Affiliate for further information.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Other important significant estimates are those included in the valuation of our assets and liabilities that are recorded at fair value on a recurring and non-recurring basis. Actual results could differ from those estimates.
Reporting and Functional Currency
The United States Dollar (“USD”) is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. Amounts denominated in non-USD currencies are re-measured into USD, and all currency gains or losses are recorded in the consolidated statements of operations and comprehensive loss. There are many factors that affect foreign exchange rates and the resulting exchange gains and losses, many of which are beyond our influence.
See Note 6 – Investment in Affiliate and Note 7 – Venezuela - Other for a discussion of currency exchange rates and currency exchange risk on Petrodelta’s and Harvest Vinccler’s businesses.
Cash and Cash Equivalents
Cash equivalents include money market funds and short term certificates of deposit with original maturity dates of less than three months.
S-11
Restricted Cash
Restricted cash is classified as current or non-current based on the terms of the agreement. Restricted cash at December 31, 2014 represented $25,000 held in a U.S. bank as collateral for our foreign credit card program. There was no restricted cash as of December 31, 2015.
Financial Instruments
Financial instruments, which potentially subject us to concentrations of credit risk, are primarily cash and cash equivalents, accounts receivable, notes payable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts with commercial banks with high credit ratings, which, at times may exceed the federally insured limits. We have not experienced any losses from such investments. Concentrations of credit risk with respect to accounts receivable are limited due the nature of our receivables, which include primarily joint venture partner’s receivable, and income tax receivable. In the normal course of business, collateral is not required for financial instruments with credit risk.
Oil and Natural Gas Properties
The major components of property and equipment are as follows:
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|
|
| As of December 31, | ||||
| 2015 |
| 2014 | ||
| (in thousands) | ||||
Unproved property costs - Dussafu PSC | $ | 28,000 |
| $ | 50,324 |
Oilfield inventories |
| 3,006 |
|
| 3,966 |
Other administrative property |
| 2,937 |
|
| 2,670 |
Total property and equipment |
| 33,943 |
|
| 56,960 |
Accumulated depreciation |
| (2,482) |
|
| (2,453) |
Total property and equipment, net | $ | 31,461 |
| $ | 54,507 |
Property and equipment are stated at cost less accumulated depreciation. Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of property and equipment, net of the related accumulated depreciation is removed and, if appropriate, gains or losses are recognized in investment earnings and other. We did not record any depletion expense in themost recently completed fiscal years ended December 31, 2015, 2014 and 2013 as there was no production related to proved oil and natural gas properties.
We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that proved reserves, as that term is defined in Securities and Exchange Commission (“SEC”) regulations, have not been discovered, capitalized costs associated with the drilling of the exploratory well are charged to expense. Costs of drilling successful exploratory wells, all development wells, and related production equipment and facilities are capitalized and depleted or depreciated using the unit-of-production method as oil and natural gas is produced. During the years ended December 31, 2015, 2014 and 2013, we expensed no dry hole costs.
Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period. Costs of maintaining and retaining unproved leaseholds are included in exploration expense. Costs of impairment of unsuccessful leases are included in impairment expense. We assess our unproved property costs for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of the projects. The estimated value of our unproved projects is determined using quantitative and qualitative assessments and the carrying value of the projects is adjusted if the carrying value exceeds the assessed value of the projects.
Impairment is based on specific identification of the lease. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and natural gas properties.
Proved oil and natural gas properties are reviewed for impairment at a level for which identifiable cash flows are independent of cash flows of other assets when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are determined based on estimated future oil and natural gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these undiscounted estimated future net cash flows is less than the carrying amount of the property, an impairment loss is recognized for the excess of the property’s carrying amount over its estimated fair value, which is generally based on discounted future net cash flows. We did not have any proved oil and natural gas properties in 2015, 2014 or 2013.
S-12
Costs of drilling and equipping successful exploratory wells, development wells, asset retirement liabilities and costs to construct or acquire offshore platforms and other facilities, are depleted using the unit-of-production method based on total estimated proved developed reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved leaseholds, are depleted using the unit-of-production method based on total estimated proved reserves. All other properties are stated at historical acquisition cost, net of impairment, and depreciated using the straight-line method over the useful lives of the assets.
During the year ended December 31, 2015, we recorded impairment expense related to our Dussafu Project in Gabon of $24.2 million (including $1.0 million of oilfield inventories). During the year ended December 31, 2014, we recorded impairment expense related to our Budong Project in Indonesia of $7.7 million and our Dussafu Project of $50.3 million. During the year ended December 31, 2013, we recorded impairment expense related to our Budong Project in Indonesia of $0.6 million and our project in Colombia of $3.2 million, which is reflected in discontinued operations.
Other Administrative Property
Furniture, fixtures and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to five years. Leasehold improvements are recorded at cost and amortized using the straight-line method over the life of the applicable lease. For the year ended December 31, 2015, depreciation expense was $0.1 million ($0.2 million and $0.3 million for the years ended December 31, 2014 and 2013, respectively).
Other Assets
Other Assets at December 31, 2015 and 2014 include deposits, prepaid expenses which are expected to be realized in the next 12 to 24 months. During 2015 we fully reserved the blocked payment related to our drilling operations in Gabon in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”) See Note 13 – Commitments and Contingencies. We recorded an allowance for doubtful accounts of $0.7 million and the remaining balance of the blocked payment was reclassified to a receivable from our joint venture partners for $0.4 million. Other assets at December 31, 2014 also consisted of deferred financing costs. Deferred financing costs relate to specific financings and are amortized over the life of the financings to which the costs relate using the interest rate method.
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| As of December 31, | ||||
|
| 2015 |
| 2014 | ||
|
| (in thousands) | ||||
Deposits and long-term prepaid expenses |
| $ | 142 |
| $ | 101 |
Deferred financing costs |
|
| — |
|
| 283 |
Gabon – blocked payment |
|
| — |
|
| 1,100 |
|
| $ | 142 |
| $ | 1,484 |
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| |
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| Non-Equity |
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| |
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|
| Stock |
| Option |
| Incentive Plan |
| All Other |
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|
| ||||
Name and Principal |
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|
| Bonus |
| Awards |
| Awards |
| Compensation |
| Compensation |
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|
| ||||
Position |
| Year |
| Salary ($) |
|
| ($) (1) |
| ($) (2) |
| ($) (3) |
| ($) (4) |
| ($) (5) |
| Total ($) | ||||||
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|
James A. Edmiston |
| 2015 |
| $ | 610,616 |
| $ | 382,200 |
| $ | 285,000 |
| $ | 554,440 |
| $ | 214,550 |
| $ | 20,008 |
| $ | 2,066,814 |
President and Chief |
| 2014 |
|
| 584,539 |
|
| 382,200 |
|
| — |
|
| 769,230 |
|
| 966,280 |
|
| 19,724 |
|
| 2,721,973 |
Executive Officer |
| 2013 |
|
| 566,154 |
|
| 399,000 |
|
| 115,200 |
|
| 1,117,719 |
|
| 125,580 |
|
| 18,149 |
|
| 2,341,802 |
|
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|
|
Stephen C. Haynes |
| 2015 |
| $ | 326,077 |
| $ | 122,460 |
| $ | 95,190 |
| $ | 193,735 |
| $ | 63,315 |
| $ | 17,255 |
| $ | 818,032 |
Vice President, Finance, |
| 2014 |
|
| 312,269 |
|
| 122,460 |
|
| — |
|
| 249,480 |
|
| 314,160 |
|
| 17,423 |
|
| 1,015,792 |
Chief Financial Officer |
| 2013 |
|
| 303,077 |
|
| 128,100 |
|
| 33,600 |
|
| 320,633 |
|
| 35,490 |
|
| 18,923 |
|
| 839,823 |
and Treasurer |
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Robert Speirs |
| 2015 |
| $ | 370,000 |
| $ | 144,300 |
| $ | 112,290 |
| $ | 228,218 |
| $ | 74,592 |
| $ | 488,912 |
| $ | 1,418,312 |
Senior Vice President |
| 2014 |
|
| 368,333 |
|
| 144,300 |
|
| — |
|
| 294,030 |
|
| 371,280 |
|
| 537,459 |
|
| 1,715,402 |
Eastern Operations |
| 2013 |
|
| 357,500 |
|
| 151,200 |
|
| 38,400 |
|
| 377,567 |
|
| 43,680 |
|
| 385,363 |
|
| 1,353,710 |
|
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Karl L. Nesselrode |
| 2015 |
| $ | 300,116 |
| $ | 112,710 |
| $ | 87,780 |
| $ | 178,416 |
| $ | 58,264 |
| $ | 18,594 |
| $ | 755,880 |
Vice President |
| 2014 |
|
| 287,269 |
|
| 112,710 |
|
| — |
|
| 228,690 |
|
| 290,360 |
|
| 18,323 |
|
| 937,352 |
Engineering and |
| 2013 |
|
| 278,077 |
|
| 117,600 |
|
| 33,600 |
|
| 293,663 |
|
| 32,760 |
|
| 17,898 |
|
| 773,598 |
Business Development |
|
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|
Keith L. Head |
| 2015 |
| $ | 293,885 |
| $ | 110,370 |
| $ | 86,070 |
| $ | 174,570 |
| $ | 57,090 |
| $ | 14,183 |
| $ | 736,168 |
Vice President |
| 2014 |
|
| 281,462 |
|
| 110,370 |
|
| — |
|
| 225,720 |
|
| 285,600 |
|
| 14,036 |
|
| 917,188 |
General Counsel |
| 2013 |
|
| 273,077 |
|
| 115,500 |
|
| 33,600 |
|
| 287,670 |
|
| 32,760 |
|
| 20,368 |
|
| 762,975 |
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Notes: |
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1. Harvest pays bonuses one year in arrears but reflects the bonus in the table above in the year to which it related. Bonuses related to 2013 were paid February 28, | |||||||||||||||||||||||
2014 and are reflected in the schedule above as 2013 bonuses. Bonuses related to 2014 were paid June 25, 2015 and are reflected in the schedule above as 2014 | |||||||||||||||||||||||
bonuses. Bonuses related to 2015 were approved on March 15, 2016 but have been deferred until our current financial situation is resolved and are reflected in the | |||||||||||||||||||||||
above schedule as 2015 bonuses. | |||||||||||||||||||||||
2. In 2015, Harvest issued restricted stock units to employees and the named executive officers. The fair value of each restricted stock unit ("RSU") was estimated | |||||||||||||||||||||||
on the date of grant using a Monte Carlo simulation since the RSU's were also subject to a market condition. These RSUs will not become exercisable until the first | |||||||||||||||||||||||
day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per | |||||||||||||||||||||||
share (“VWAP condition”) in addition to the required three year cliff vesting period. The Monte Carlo simulation includes this VWAP condition and uses | |||||||||||||||||||||||
assumptions for the risk-free interest rate of 2.27%, volatility of 80%, term of 10 years and a 0% dividend yield. | |||||||||||||||||||||||
3. In 2015, the fair value of each stock option was estimated on the date of grant using a Monte Carlo simulation since the options were also subject to a market | |||||||||||||||||||||||
condition. These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, | |||||||||||||||||||||||
commencing on or after the award date, equals or exceeds $2.50 per share (“VWAP condition”) in addition to the ratable vesting over a three year period. The Monte | |||||||||||||||||||||||
Carlo simulation includes this VWAP condition and uses assumptions for the risk-free interest rate of 1.7%, volatility of 100%, exercise price of $1.13 and a 0% | |||||||||||||||||||||||
dividend yield. A suboptimal exercise factor determines the expected term of the options. The Monte Carlo simulation assumed a suboptimal exercise factor of 2.5 | |||||||||||||||||||||||
meaning that exercise is generally expected to occur when the share price reaches 2.5 times the award’s exercise price. The resulting weighted average term was 4.7 | |||||||||||||||||||||||
years. A forfeiture rate of 1.1% was assumed in calculating the value of the options. | |||||||||||||||||||||||
4. In 2015, Harvest issued stock appreciation rights ("SARs"). The fair value of each SAR was estimated on the date of grant using a Monte Carlo simulation since | |||||||||||||||||||||||
the SARs were also subject to a market condition. These SARs will not become exercisable until the first day on which the volume weighted average price of the | |||||||||||||||||||||||
common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share (“VWAP condition”) in addition to the ratable vesting | |||||||||||||||||||||||
over a three year period. The Monte Carlo simulation includes this VWAP condition and uses assumptions for the risk-free interest rate of 1.7%, volatility of 105%, | |||||||||||||||||||||||
exercise price of $1.13 and a 0% dividend yield. A suboptimal exercise factor determines the expected term of the options. The Monte Carlo simulation assumed a | |||||||||||||||||||||||
suboptimal exercise factor of 2.5 meaning that exercise is generally expected to occur when the share price reaches 2.5 times the award’s exercise price. The resulting | |||||||||||||||||||||||
weighted average term was 4.6 years. A forfeiture rate of 0.7% was assumed in calculating the value of the SARs. | |||||||||||||||||||||||
The SARs can be settled in cash or equity. Currently, no plan has been approved by the shareholders for equity settlement and Harvest is recording the liability and | |||||||||||||||||||||||
expense associated with the awards based on the fair value of the awards. | |||||||||||||||||||||||
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(5) See table below: |
Reserves
We measure and disclose oil and natural gas reserves in accordance with the provisions of the SEC’s Modernization of Oil and Gas Reporting and ASC 932, “Extractive Activities – Oil and Gas” (“ASC 932”). All of our reserves are owned through our investment in Petrodelta. We are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014. Under the cost method, we do not have any reserves at December 31, 2015 and 2014.
Capitalized Interest
We capitalize interest costs for qualifying oil and natural gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation. During the year ended December 31, 2015, we capitalized interest costs for qualifying oil and natural gas property additions related to Gabon of $0.0 million ($0.5 million and $8.3 million during the years ended December 31, 2014 and 2013, respectively).
Fair Value Measurements
We measure and disclose our fair values in accordance with the provisions of ASC 820 “Fair Value Measurements and Disclosures” (“ASC 820”). ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price) and establishes a three-level hierarchy, which encourages an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The three levels of the hierarchy are defined as follows:
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S-13
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|
Financial instruments, which potentially subject us to concentrations of credit risk, are primarily cash and cash equivalents, accounts receivable, SARs, RSUs, debt, embedded derivatives and warrant derivative liabilities. We maintain cash and cash equivalents in bank deposit accounts with commercial banks with high credit ratings, which, at times may exceed the federally insured limits. We have not experienced any losses from such investments. Concentrations of credit risk with respect to accounts receivable are limited due to the nature of our receivables. In the normal course of business, collateral is not required for financial instruments with credit risk. The estimated fair value of cash and cash equivalents and accounts receivable approximates their carrying value due to their short-term nature (Level 1). The following tables set forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value as of December 31, 2015 and December 31, 2014. During the year ended December 31, 2015, we impaired the carrying value of our Dussafu project in Gabon by $23.2 million and our investment in affiliate by $164.7 million. See Note 6 – Investment in Affiliate and Note 8 – Gabon for more information.
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| As of December 31, 2015 | ||||||||||
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| Level 1 |
| Level 2 |
| Level 3 |
| Total | ||||
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|
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|
|
|
|
| (in thousands) | ||||||||||
Non recurring |
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|
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|
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|
|
Assets: |
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|
|
|
|
|
|
|
|
|
|
|
Investment in affiliate |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
Dussafu PSC |
|
| — |
|
| — |
|
| 28,000 |
|
| 28,000 |
|
| $ | — |
| $ | — |
| $ | 28,000 |
| $ | 28,000 |
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Recurring |
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|
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Assets: |
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|
|
|
|
|
|
|
|
|
|
|
Embedded derivative asset |
| $ | — |
| $ | — |
| $ | 5,010 |
| $ | 5,010 |
|
| $ | — |
| $ | — |
| $ | 5,010 |
| $ | 5,010 |
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|
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|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
SARs liability |
| $ | — |
| $ | 46 |
| $ | 50 |
| $ | 96 |
RSUs liability |
|
| — |
|
| 174 |
|
| — |
|
| 174 |
Warrant derivative liability |
|
| — |
|
| — |
|
| 5,503 |
|
| 5,503 |
|
| $ | — |
| $ | 220 |
| $ | 5,553 |
| $ | 5,773 |
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| As of December 31, 2014 | ||||||||||
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| Level 1 |
| Level 2 |
| Level 3 |
| Total | ||||
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| (in thousands) | ||||||||||
Non recurring |
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|
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Assets: |
|
|
|
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|
|
|
|
|
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|
|
Investment in affiliate |
| $ | — |
| $ | — |
| $ | 164,700 |
| $ | 164,700 |
Dussafu PSC |
|
| — |
|
| — |
|
| 50,324 |
|
| 50,324 |
|
| $ | — |
| $ | — |
| $ | 215,024 |
| $ | 215,024 |
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Recurring |
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Liabilities: |
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|
SARs liability |
| $ | — |
| $ | 356 |
| $ | — |
| $ | 356 |
RSUs liability |
|
| — |
|
| 652 |
|
| — |
|
| 652 |
|
| $ | — |
| $ | 1,008 |
| $ | — |
| $ | 1,008 |
As of December 31, 2015, the fair value of our liability awards included $0.1 million for our SARs and $0.2 million for the RSUs which were recorded in accrued expenses and other long-term liabilities, respectively. As of December 31, 2014, the fair value of our liability awards of $0.8 million was included in accrued liabilities ($0.4 million for our SARs and $0.4 million for our RSUs) with the remaining $0.2 million fair value of our RSU liability being included in long-term liabilities.
S-14
Derivative Financial Instruments
As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value liabilities and their placement within the fair value hierarchy levels. See Note 12 – Warrant Derivative Liability for a description and discussion of our warrant derivative liability as well as a description of the valuation models and inputs used to calculate the fair value. See Note 11 – Debt and Financing for a description and discussion of our embedded derivatives related to our 9% Note and 15% Note as well as a description of the valuation models and inputs used to calculate the fair value. All of our embedded derivatives and warrants are classified as Level 3 within the fair value hierarchy.
Changes in Level 3 Instruments Measured at Fair Value on a Recurring Basis
The following table provides a reconciliation of financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3).
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| Year Ended December 31, | |||||||
| 2015 |
| 2014 |
| 2013 | |||
| (in thousands) | |||||||
Financial assets - embedded derivative asset |
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|
|
Beginning balance | $ | — |
| $ | — |
| $ | — |
Additions - fair value at issuance |
| 2,504 |
|
| — |
|
| — |
Change in fair value |
| 2,506 |
|
| — |
|
| — |
Ending balance | $ | 5,010 |
| $ | — |
| $ | — |
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| Year Ended December 31, | |||||||
| 2015 |
| 2014 |
| 2013 | |||
| (in thousands) | |||||||
Financial liabilities - embedded derivative liability |
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|
|
|
|
|
|
|
Beginning balance | $ | — |
| $ | — |
| $ | — |
Additions - fair value at issuance |
| 13,449 |
|
| — |
|
| — |
Change in fair value |
| (2,307) |
|
| — |
|
| — |
Conversion of debt |
| (11,142) |
|
| — |
|
| — |
Ending balance | $ | — |
| $ | — |
| $ | — |
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| Year Ended December 31, | |||||||
| 2015 |
| 2014 |
| 2013 | |||
| (in thousands) | |||||||
Financial liabilities - warrant derivative liabilities: |
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|
|
|
|
|
|
|
Beginning balance | $ | — |
| $ | 1,953 |
| $ | 5,470 |
Additions - fair value at issuance |
| 40,013 |
|
| — |
|
| — |
Change in fair value |
| (34,510) |
|
| (1,953) |
|
| (3,517) |
Ending balance | $ | 5,503 |
| $ | — |
| $ | 1,953 |
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S-15
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| Year Ended December 31, | |||||||
| 2015 |
| 2014 |
| 2013 | |||
| (in thousands) | |||||||
Financial liabilities - stock appreciation rights |
|
|
|
|
|
|
|
|
Beginning balance | $ | — |
| $ | — |
| $ | — |
Additions - fair value at issuance |
| — |
|
| — |
|
| — |
Change in fair value |
| 50 |
|
| — |
|
| — |
Ending balance | $ | 50 |
| $ | — |
| $ | — |
During the year ended December 31, 2015, 2014 and 2013, no transfers were made between Level 1, Level 2 and Level 3 liabilities or assets.
Share-Based Compensation
We use the fair value based method of accounting for share-based compensation. In prior years, we utilized the Black-Scholes option pricing model to measure the fair value of stock options and SARs. Restricted stock and RSUs were measured at their fair values. During 2015, we issued options, SARs, and RSUs with an additional market condition. To fair value these awards, a Monte Carlo simulation was utilized. For more information about our share-based compensation, the fair value of these awards, and the additional market condition. See Note 15 – Stock-Based Compensations and Stock Purchase Plans.
Income Taxes
Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carryforwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
We classify interest related to income tax liabilities and penalties as applicable, as interest expense.
Since December of 2013 we have provided deferred income taxes on undistributed earnings of our foreign subsidiaries where we are not able to assert that such earnings were permanently reinvested, or otherwise could be repatriated in a tax free manner, as part of our ongoing business. As of December 31, 2015, the deferred tax liability provided on such earnings has been reduced to zero due to the impairment of the underlying book investment in Petrodelta.
As the conversion feature of the 9% Note was reasonably expected to be exercised at the time of the note’s issuance due to the conversion price being in-the-money, the interest on the 9% Note paid upon its conversion is non-deductible to the Company under Internal Revenue Code (“IRC”) Section 163(l). The 15% Note was issued, for income tax purposes, with original issue discount (“OID”). OID generally is deductible for income tax purposes. However, if the debt instrument constitutes an “applicable high-yield discount obligation” (“AHYDO”) within the meaning of IRC Section 163(i)(1), then a portion of the OID likely would be non-deductible pursuant to IRC Section 163(e)(5). Our analysis of the 15% Note is that the note may be an AHYDO; consequently, a portion or all of the OID likely may be non-deductible for income tax purposes.
S-16
Noncontrolling Interests
Changes in noncontrolling interest owners were as follows:
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|
| Year Ended December 31, | |||||||
| 2015 |
| 2014 |
| 2013 | |||
| (in thousands) | |||||||
Balance at beginning of period | $ | 79,152 |
| $ | 243,167 |
| $ | 97,101 |
Contributions by noncontrolling interest owners |
| 3,382 |
|
| 1,208 |
|
| — |
Increase in equity held by noncontrolling interest owner |
| — |
|
| — |
|
| 144,796 |
Dividend to noncontrolling interest owner |
| — |
|
| — |
|
| (10,370) |
Net income (loss) attributable to noncontrolling interest owners |
| (82,087) |
|
| (165,223) |
|
| 11,640 |
Balance at end of period | $ | 447 |
| $ | 79,152 |
| $ | 243,167 |
Valuation and Qualifying Accounts
Our valuation and qualifying accounts are comprised of the deferred tax valuation allowance, investment valuation allowance and Value-Added Tax (“VAT”) receivable valuation allowance. Balances and changes in these accounts are, in thousands:
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| Additions |
|
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|
|
| ||||
| Balance at Beginning of Year |
| Charged to Income |
| Other |
| Deductions From Reserves Credited to Income |
| Balance at End of Period | |||||
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| (in thousands) | |||||||||||||
At December 31, 2015 |
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Amounts deducted from applicable assets |
|
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|
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|
|
Deferred tax valuation allowance | $ | 181,906 |
| $ | — |
| $ | 44,014 |
| $ | — |
| $ | 225,920 |
Investment valuation allowance |
| 1,350 |
|
| — |
|
| — |
|
| — |
|
| 1,350 |
VAT valuation allowance |
| 2,792 |
|
| — |
|
| (2,792) | (b) |
| — |
|
| — |
Long-term receivable - investment in affiliate |
| 13,753 |
|
| — |
|
| — |
|
| — |
|
| 13,753 |
At December 31, 2014 |
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Amounts deducted from applicable assets |
|
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|
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|
|
Deferred tax valuation allowance | $ | 59,576 |
| $ | 129,480 |
| $ | (7,150) | (a) | $ | — |
| $ | 181,906 |
Investment valuation allowance |
| 1,350 |
|
| — |
|
| — |
|
| — |
|
| 1,350 |
Long-term receivable - investment in affiliate |
| — |
|
| 13,753 | (c) |
| — |
|
| — |
|
| 13,753 |
VAT valuation allowance |
| 2,792 |
|
| — |
|
| — |
|
| — |
|
| 2,792 |
At December 31, 2013 |
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|
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Amounts deducted from applicable assets |
|
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|
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|
|
Deferred tax valuation allowance | $ | 68,419 |
| $ | — |
| $ | — |
| $ | (8,843) |
| $ | 59,576 |
Investment valuation allowance |
| 1,350 |
|
| — |
|
| — |
|
| — |
|
| 1,350 |
VAT valuation allowance |
| — |
|
| 2,792 |
|
| — |
|
| — |
|
| 2,792 |
|
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|
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|
New Accounting Pronouncements
In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs”. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. In June 2015 the FASB issued ASU No. 2015-15 as an amendment to this guidance to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements. The SEC staff stated that they would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-
S-17
credit arrangement. The guidance is effective for interim periods and annual period beginning after December 15, 2015; however early adoption is permitted. We do not believe the adoption of this guidance will have a material impact on our financial position and will not have an impact on our results of operations or cash flows.
In August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern” ASU No. 2014-15. ASU No. 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU No. 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.
In April 2014, FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers” which is included in ASC 606, a new topic under the same name. The guidance in this update affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). The guidance supersedes the previous revenue recognition requirements and most industry-specific guidance. Additionally, the update supersedes some cost guidance related to construction type and production-type contracts. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in this update.
The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps: (1) identify the contract(s) with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation.
The new guidance also provides for additional qualitative and quantitative disclosures related to: (1) contracts with customers, including revenue and impairments recognized, disaggregation of revenue, and information about contract balances and performance obligations (including the transaction price allocated to the remaining performance obligations); (2) significant judgments and changes in judgments which impact the determination of the timing of satisfaction of performance obligations (over time or at a point in time), the transaction price and amounts allocated to performance obligations; and (3) assets recognized from the costs to obtain or fulfill a contract.
In July 2015, the FASB issued a decision to delay related to ASU No. 2014-09 for the effective date by one year. The new guidance is effective for annual and interim periods beginning after December 15, 2017. An entity should apply the amendments either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of initial application. We are currently evaluating the impact of this guidance.
In November 2015, the FASB issued ASC No. 2015-17, “Balance Sheet Classification of Deferred Taxes”. ASU No. 2015-17 simplifies the balance sheet presentation of deferred income taxes by requiring all deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The standard is effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted. The standard may be applied either prospectively or retrospectively to all periods presented. The Company has decided to adopt the accounting change in its current financial statements and has adopted the change retrospectively.
In February 2016, the FASB issued ASU No. 2016-02, “Leases”. It is expected to be effective for periods beginning after December 15, 2018 for public entities, and for periods beginning after December 15, 2019 for nonpublic entities. Early application is permitted. Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less. All other leases will fall into one of two categories: (1) Financing leases, similar to capital leases, will require the recognition of an asset and liability, measured at the present value of the lease payments. Interest on the liability will be recognized separately from amortization of the asset. Principal repayments will be classified as financing outflows and payments of interest as operating outflows on the statement of cash flows. (2) Operating leases will also require the recognition of an asset and liability measured at the present value of the lease payments. A single lease cost, consisting of interest on the obligation and amortization of the asset, calculated such that the amortization of the asset will increase as the interest amount decreases resulting in a straight-line recognition of lease expense. All cash outflows will be classified as operating on the statement of cash flows. We do not believe the adoption of this guidance will have a material impact on our financial position, results of operations or cash flows.
In March 2016, the FASB issued ASU No. 2016-07, “Investments — Equity Method and Joint Ventures (Topic 323)”. This amendment simplifies the accounting for equity method of investments, the amendment in the update eliminates the requirement in Topic 323 that an entity retroactively adopt the equity method of accounting if an investment qualifies for use of the equity method as a result of an increase in the level of ownership or degree of influence. The amendment requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt
S-18
equity method of accounting as of the date the investment becomes qualified for equity method accounting. The amendment in this update is effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. The amendment should be applied prospectively upon the effective date to increases in the level of ownership interest or degree of influence that result in the adoption of the equity method. Earlier application is permitted. We are currently evaluating the impact of this guidance.
Note 4 – Earnings Per Share
Basic earnings per common share (“EPS”) are computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that would occur if securities or other contracts to issue common stock were exercised or converted into common stock.
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|
| Year Ended December 31, | |||||||
| 2015 |
| 2014 |
| 2013 | |||
|
|
|
|
|
|
|
|
|
| (in thousands) | |||||||
Loss from continuing operations(a) | $ | (98,570) |
| $ | (192,936) |
| $ | (83,946) |
Discontinued operations |
| — |
|
| (554) |
|
| (5,150) |
Net loss attributable to Harvest | $ | (98,570) |
| $ | (193,490) |
| $ | (89,096) |
Weighted average common shares outstanding |
| 45,288 |
|
| 42,039 |
|
| 39,579 |
Weighted average common shares, diluted |
| 45,288 |
|
| 42,039 |
|
| 39,579 |
Basic loss per share: |
|
|
|
|
|
|
|
|
Loss from continuing operations(a) | $ | (2.18) |
| $ | (4.59) |
| $ | (2.12) |
Discontinued operations |
| — |
|
| (0.01) |
|
| (0.13) |
Basic loss per share | $ | (2.18) |
| $ | (4.60) |
| $ | (2.25) |
Diluted loss per share: |
|
|
|
|
|
|
|
|
Loss from continuing operations(a) | $ | (2.18) |
| $ | (4.59) |
| $ | (2.12) |
Discontinued operations |
| — |
|
| (0.01) |
|
| (0.13) |
Diluted loss per share | $ | (2.18) |
| $ | (4.60) |
| $ | (2.25) |
|
|
The year ended December 31, 2015 per share calculations above exclude 4.1 million options, 34.1 million warrants and 1.6 million RSUs because we are in a net loss position. The year ended December 31, 2014 per share calculations above exclude 0.2 million unvested restricted shares, 4.5 million options and 2.5 million warrants because we were in a net loss position. The year ended December 31, 2013 per share calculations above exclude 0.3 million unvested restricted shares, 4.2 million options and 2.5 million warrants because we were in a net loss position.
Note 5 – Dispositions
Share Purchase Agreement
On December 16, 2013, Harvest and HNR Energia entered into the SPA with Petroandina and Pluspetrol, its parent, to sell all of our 80 percent equity interest in Harvest Holding to Petroandina in two closings for an aggregate cash purchase price of $400.0 million. The first closing occurred on December 16, 2013 contemporaneously with the signing of the SPA, when we sold a 29 percent equity interest in Harvest Holding for $125.0 million. This first transaction resulted in a loss on the sale of the interest in Harvest Holding of $23.0 million in the year ended December 31, 2013. As a result of this first sale, we indirectly own 51 percent of Harvest Holding beginning December 16, 2013 and the noncontrolling interest owners hold the remaining 49 percent, with Petroandina having 29 percent and Vinccler continuing to own 20 percent. The second closing, for the sale of a 51 percent equity interest in Harvest Holding for a cash purchase price of $275.0 million, was subject to, among other things, approval by the holders of a majority of our common stock and approval by the Ministerio del Poder Popular de Petroleo y Mineria representing the Government of Venezuela (which indirectly owns the other 60 percent interest in Petrodelta).
On May 7, 2014, Harvest’s stockholders voted to authorize the sale of the remaining interests in Harvest Holding. Once stockholders’ approval was obtained, the SPA allowed for 120 days, or until September 7, 2014, for consummation of the sale, extension of the SPA or termination of the SPA. Petroandina had the right to extend the SPA beyond the termination date in increments of one month, but not beyond December 31, 2014, in exchange for the Company’s right to borrow up to $2.0 million, not to exceed $7.6 million in the aggregate, from Petroandina per each monthly extension. Petroandina exercised this right through
S-19
December 31, 2014 with the Company borrowing $7.6 million in total during this period. Repayments of these loans are subject to certain conditions, one of which states that all outstanding loans (along with interest accrued and other amounts) would become due upon the final closing date of the SPA, with the second tranche proceeds being reduced by such outstanding amounts. If the SPA was terminated by either party, any outstanding loans would become due one year from the date of the termination.
On January 1, 2015, HNR Energia exercised its right to terminate the SPA in accordance with its terms as a result of the failure to obtain the necessary approval from the Government of Venezuela. As a result of the termination of the SPA, the Company retained its 51 percent equity interest in Harvest Holding, and Petroandina retained its 29 percent equity interest in Harvest Holding.
HNR Energia and Petroandina also entered into a Shareholders’ Agreement (the “Shareholders’ Agreement”) on December 16, 2013, regarding the shares of Harvest Holding. The Shareholders’ Agreement became effective upon the termination of the SPA.
China
On July 2, 2014, we completed the sale of our rights under a petroleum contract with China National Offshore Oil Corporation for the WAB-21 area for net proceeds of $2.9 million and recorded that amount as a gain from sale of oil and natural gas properties. This area is located in the South China Sea and is the subject of a border dispute between China and Socialist Republic of Vietnam.
Discontinued Operations
Oman
We have no continuing operations in Oman. The nominal loss from discontinued operations for Oman for the year ended December 31, 2014 included general and administrative expenses. The loss from discontinued operations for Oman of $0.7 million for the year ended December 31, 2013 included $0.2 million of exploration expense and $0.5 million of general and administrative expenses and other expenses.
Colombia
In February 2013, we signed farm-down agreements on Block VSM14 and Block VSM15 in Colombia. Under the terms of the farm-down agreements, we had a 75 percent beneficial working interest and our partners had a 25 percent carried interest for the minimum exploratory work commitments on each block. We requested the legal assignment of the interest by the Agencia Nacional de Hidrocarburos (“ANH”), Colombia’s oil and natural gas regulatory authority, and approval of us as operator.
We received notices of default from our partners for failing to comply with certain terms of the farm-down agreements for Block VSM14 and Block VSM15, followed by notices of termination on November 27, 2013. Our partners filed for arbitration of claims related to these agreements. We accrued $2.0 million as of December 31, 2013 related to this matter. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests, and we recorded an impairment charge of $3.2 million, which included the $2.0 million accrual related to arbitration, during the year ended December 31, 2013. In December 2014, we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed. We are in the process of closing and exiting our Colombia venture. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations. The loss from discontinued operations included $0.5 million in general and administrative expenses during the year ended December 31, 2014. The loss from discontinued operations included $3.2 million in impairment expense, $0.7 million of exploration expense and $0.6 million in general and administrative expenses during the year ended December 31, 2013.
Oman and Colombia operations have been classified as discontinued operations. No revenues were recorded related to these projects for the years presented. Expenses are shown in the table below:
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| Year Ended December 31, | |||||||
|
| 2015 |
| 2014 |
| 2013 | |||
|
| (in thousands) | |||||||
Loss from Discontinued Operations |
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oman |
| $ | — |
| $ | (27) |
| $ | (674) |
Colombia |
|
| — |
|
| (527) |
|
| (4,476) |
|
| $ | — |
| $ | (554) |
| $ | (5,150) |
S-20
Note 6 – Investment in Affiliate
Venezuela – Petrodelta, S.A.
The following table summarizes the changes in our investment in affiliate (Petrodelta) as of December 31, 2015 and 2014. Petrodelta’s reporting and functional currency is the USD.
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| Year Ended December 31, | ||||
| 2015 |
| 2014 | ||
| (in thousands) | ||||
Investment at beginning of year | $ | 164,700 |
| $ | 485,401 |
Equity in earnings |
|
|
|
| 34,949 |
Impairment |
| (164,700) |
|
| (355,650) |
Investment at end of period | $ | — |
| $ | 164,700 |
Our 40 percent investment in Petrodelta is owned through our subsidiary, Harvest Holding, a Dutch private company with limited liability. Up until December 16, 2013 we had an 80 percent interest in Harvest Holding. On December 16, 2013, Harvest entered into a share purchase agreement (“SPA”) with Petroandina Resources Corporation to sell our 80 percent equity interest in Harvest Holding in two closings for an aggregate cash purchase price of $400.0 million. The first closing occurred on December 16, 2013 when we sold a 29 percent equity interest in Harvest Holding for $125.0 million. As a result of the first sale, we own 51 percent of Harvest Holding beginning December 16, 2013 and the non-controlling interest owners hold the remaining 49 percent.
The Company was not able to obtain approval from the government of Venezuela during 2014, which was required to complete the second closing for our remaining 51 percent interest in Petrodelta and on January 1, 2015 we terminated the SPA. Due to our failed sales attempts, lack of management influence, and actions and inactions by the majority owner, PDVSA, we believe we no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014. Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.
We performed an impairment analysis of the carrying value of our investment of Petrodelta as of December 31, 2014. The estimated fair value of our investment was determined based on the estimated fair value of Petrodelta’s oil and natural gas properties and other net assets as of December 31, 2014, discounted by a factor for economic instability, foreign currency risks and lack of marketability. Based on this analysis, we recorded a pre-tax impairment charge against the carrying value of our investment in Petrodelta of $355.7 million as of December 31, 2014.
We also performed an impairment analysis of the carrying value of our investment of Petrodelta as of December 31, 2015 due to the continued decline in world oil prices and deteriorating economic conditions in Venezuela which have significantly impacted Petrodelta’s operations. During 2015, Petrodelta’s operating costs exceeded the price realized from the sale of its production due to the significant rate of inflation in Venezuela and the restrictive foreign currency exchange system which Petrodelta is required to operate under. While we believe that our relationship with CT Energy may allow us to restructure our relationship with PDVSA and Petrodelta and allow us to access the alternative foreign currency systems to companies in Venezuela, there can be no assurances that we will be successful in these negotiations. Based on the existing economic environment in which Petrodelta is required to operate, we have concluded that the estimated fair value of our investment in Petrodelta is nil and have recorded a pre-tax impairment charge of $164.7 million to fully impair our investment in Petrodelta as of December 31, 2015. The estimated fair value of our investment was determined based on the estimated fair value of Petrodelta’s oil and natural gas properties and other net liabilities as of December 31, 2015 which exceeded the estimated fair value of the oil and natural gas properties.
The model used in the valuation of Petrodelta was based on an income approach which considered three scenarios relating to the future development of proved, probable and possible reserves and its other net liabilities at December 31, 2015. The three scenarios considered that Petrodelta would have varying degrees of access to foreign exchange regimes as well as our ability to participate in and influence its operations to improve operational performance and efficiencies. Each scenario also considered three price forecasts for crude oil. The weighted average cost of capital of 26.5% was used to discount the future cash flows from these scenarios. The expected value obtained from the income approach less net liabilities at December 31, 2015 resulted in a full impairment of the carrying value of our investment in Petrodelta.
In addition to the impairment charge, we recorded an allowance of $12.2 million to fully reserve the dividend receivable due from Petrodelta relating to the dividend declared in 2011 during the year ended December 31, 2014.
S-21
Petrodelta’s financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”) which we have adjusted to conform to U.S. GAAP for the years ending December 31, 2014 and 2013. The year ended December 31, 2015 is excluded due to the change to the cost method of accounting. The differences between IFRS and U.S. GAAP for which we adjusted are:
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S-22
All amounts through Net Income under U.S. GAAP represent 100 percent of Petrodelta. Summary financial information is presented for the years ended December 31, 2014 and 2013 and the financial position is presented at December 31, 2014.
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|
|
| Year Ended December 31, |
| ||||
| 2014 |
| 2013 |
| ||
|
|
|
|
|
|
|
Results under IFRS: | (in thousands, except percentages) |
| ||||
Revenues: |
|
|
|
|
|
|
Oil sales | $ | 1,343,452 |
| $ | 1,326,093 |
|
Natural gas sales |
| 4,590 |
|
| 4,000 |
|
Royalty |
| (437,281) |
|
| (440,963) |
|
|
| 910,761 |
|
| 889,130 |
|
Expenses: |
|
|
|
|
|
|
Operating expenses |
| 303,409 |
|
| 141,627 |
|
Workovers |
| 28,239 |
|
| 29,168 |
|
Depletion, depreciation and amortization |
| 129,409 |
|
| 87,203 |
|
General and administrative |
| 45,623 |
|
| 37,778 |
|
Windfall profits tax |
| 140,816 |
|
| 234,453 |
|
Windfall profits (credit) and reversal of credit |
| 55,168 |
|
| (55,168) |
|
|
| 702,664 |
|
| 475,061 |
|
Income from operations |
| 208,097 |
|
| 414,069 |
|
Gain (loss) on exchange rate |
| (260) |
|
| 169,582 |
|
Investment earnings and other |
| 7,752 |
|
| 1,414 |
|
Interest expense |
| 137 |
|
| (21,728) |
|
Income before income tax |
| 215,726 |
|
| 563,337 |
|
Current income tax expense |
| 103,619 |
|
| 325,217 |
|
Deferred income tax expense (benefit) |
| (32,617) |
|
| (17,662) |
|
Net income under IFRS |
| 144,724 |
|
| 255,782 |
|
Adjustments to increase (decrease) net income under IFRS: |
|
|
|
|
|
|
Deferred income tax (expense) benefit |
| (2,841) |
|
| 9,080 |
|
Depletion expense |
| (12,437) |
|
| (20,353) |
|
Adjustment to lease operating costs to conform with GAAP |
| 13,888 |
|
| — |
|
Windfall profits credit and (reversal) of credit |
| 55,168 |
|
| (55,168) |
|
Adjust fair value of value added tax credits |
| (51,393) |
|
| — |
|
Sports law over accrual |
| 1,322 |
|
| 1,313 |
|
Net income under U.S. GAAP |
| 148,431 |
|
| 190,654 |
|
Interest in investment affiliate |
| 40 | % |
| 40 | % |
Income before amortization of excess basis in investment in affiliate |
| 59,372 |
|
| 76,262 |
|
Amortization of excess basis in investment in affiliate |
| (4,428) |
|
| (3,684) |
|
Earnings from investment affiliate excluded from results of operations |
| (19,995) |
|
| — |
|
Earnings from investment affiliate included Harvest's income | $ | 34,949 |
| $ | 72,578 |
|
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Conversion Contract
On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract was published in the Official Gazette. Petrodelta is governed by its own charter and bylaws and will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from that date. Petrodelta operates a portfolio of properties in eastern Venezuela including large proven oil fields as well as properties with substantial opportunities for both development and exploration. Petrodelta is to undertake its operations in accordance with Petrodelta’s business plan as set forth in its conversion contract. Under its conversion contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta.
Sales Contract
The sale of oil and natural gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PDVSA Petroleo S.A. (“PPSA”) signed on January 17, 2008. The form of the agreement is set forth in the Conversion Contract. Crude oil delivered from the Petrodelta Fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets, and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices are quoted and sold in USD. Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. Natural gas deliveries are paid in Venezuela Bolivars (“Bolivars”), but the pricing for natural gas is referenced to the U.S. Dollar. PPSA is obligated to make payment to Petrodelta of each invoice within 60 days of the end of the invoiced production month by wire transfer, in USD in the case of payment for crude oil and natural gas liquids delivered, and in Bolivars in the case of payment for natural gas delivered, in immediately available funds to the bank accounts designated by Petrodelta.
When the Sales Contract was executed, Petrodelta was producing only one type of crude, Merey 16. Beginning in October 2011, the Ministry of the People’s Power for Petroleum and Mining (“MENPET”) determined that Petrodelta’s production flowing through the COMOR transfer point was a heavier type of crude, Boscan. Since Petrodelta was producing only Merey 16 when the Sales Contract was executed, the Boscan gravity and sulphur correction factors and crude pricing formula are not included in the Sales Contract. However, under the Sales Contract, PPSA is obligated to receive all of Petrodelta’s production. All production deliveries for all of Petrodelta’s fields have been certified by MENPET and acknowledged by PPSA. All pricing factors to be used in the Merey 16 and Boscan pricing formulas have been provided by and certified by MENPET to Petrodelta.
Since the Sales Contract provides for only one crude pricing formula, the Sales Contract had to be amended to include the Boscan pricing formula to allow Petrodelta to invoice PPSA for El Salto crude oil deliveries. Petrodelta received a draft amendment to the Sales Contract from PDVSA Trade and Supply. The pricing formula in the draft amendment has been used to accrue revenue for El Salto field deliveries from October 1, 2011 through December 31, 2014. Except for the inclusion of the Boscan pricing formula to be used in invoicing El Salto crude oil deliveries, all other terms and conditions of the Sales Contract remain in force. On January 31, 2013, Petrodelta’s board of directors endorsed the amendment to the Sales Contract. The amendment has been approved by CVP’s board of directors. HNR Finance, as shareholder, has agreed to the contract amendment. During 2015, Petrodelta completed billing PPSA for invoices for deliveries through December 2014.
CVP’s board of directors reviewed the amendment on April 30, 2013. A certificate of CVP’s final board resolution approving the amendment dated April 30, 2013 was received by Petrodelta on May 23, 2013. The remaining steps for the contract amendment are to (1) inform MENPET of the approval, (2) receive approval from Petrodelta’s shareholders to amend the Sales Contract including the Boscan formula, and (3) sign the contract amendment with PDVSA Trade and Supply. As of December 31, 2014 revenues of $1,207.2 million ($756.7 million as of December 31, 2013) for El Salto remained uninvoiced to PPSA pending execution of the amendment. The amendment was signed in November 2014 and during January and February of 2015, Petrodelta completed billing
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PPSA for deliveries through November 2014. This invoicing resulted in an additional $98.6 million in revenue being recognized in the fourth quarter of 2014 due to a pricing change in the formula included in the sales contract.
Payments to Contractors
PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA, through PPSA, purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors, including Harvest Vinccler. As a result, Petrodelta has experienced, and is continuing to experience, difficulty in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is having an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.
Harvest Vinccler has advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, operations, seismic interpretation, and employee salaries and related benefits for Harvest Vinccler employees seconded into Petrodelta. Currently, we have three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. Harvest Vinccler is considered a contractor to Petrodelta, and as such, Harvest Vinccler is also experiencing the slow payment of invoices. Petrodelta and Petrodelta’s board have not indicated that the advances are not payable, or that they will not be paid. We fully reserved the outstanding receivables of $1.6 million related to these advances as of December 31, 2014, which was reflected in Harvest’s general and administrative costs.
Windfall Profits Tax
In April 2011, the Venezuelan government published in the Official Gazette the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (“Windfall Profits Tax”). In February 2013, the Venezuelan government published in the Official Gazette an amendment to the Windfall Profits Tax. The amended Windfall Profits Tax establishes new levels for contribution of extraordinary and exorbitant prices to the Venezuelan government. Extraordinary prices are considered to be above $60 and equal to or lower than $80 per barrel, and exorbitant prices are considered to be over $80 per barrel.
Functional Currency
Petrodelta’s functional and reporting currency is the USD. PPSA is obligated to make payment to Petrodelta in USD in the case of payment for crude oil and in Bolivars for natural gas liquids delivered. In addition, major contracts for capital expenditures and lease operating expenditures are denominated in USD. Any dividend paid by Petrodelta will be made in USD.
Petrodelta has currency exchange risk from fluctuations of the official prevailing exchange rate that applies to their operating costs denominated in Bolivars. The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals, current and deferred income tax and other tax obligations and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. The official prevailing currency exchange rate was increased from 4.3 Bolivars per U.S. Dollar to 6.3 Bolivars per U.S. Dollar in February 2013. Petrodelta reflected a gain of approximately $169.6 million on revaluation of its non-income tax related assets and liabilities during the year ended December 31, 2013 primarily related to the February 2013 devaluation.
As a result of legislation enacted in December 2013 and January and February of 2014, Venezuela now has a multiple exchange rate system. Most of Petrodelta’s transactions are subject to a fixed official exchange rate of 6.3. The Venezuelan government modified the currency exchange system whereby the official exchange rate of 6.3 Bolivars per USD would only apply to certain economic sectors related to purchases of “essential goods and services” while other sectors of the economy would be subject to a new exchange rate, SICAD I, determined by an auction process conducted by Venezuela's Complimentary System of Foreign Currency Administration. Participation in the SICAD I mechanism is controlled by the Venezuelan government and is limited to certain companies that operate in designated economic sectors. In March 2014, an additional currency exchange mechanism was established by the Venezuelan government that allows companies within other economic sectors to participate in an additional auction process (“SICAD II”). The exchange rate averaged approximately 50 Bolivars per USD for the re-measurement of our Bolivar denominated assets and liabilities and revenue and expenses. The financial information is prepared using the official fixed exchange rate (6.3 from February 2013 through December 2014). On February 10, 2015, the Ministry of Economy, Finance, and Public Banking, and the Central Bank of Venezuela (BCV) published in the Extraordinary Official Gazette No.6.171 Exchange Agreement No.33 with two Official Notices. The first notice being that the SICAD II exchange rate would be no longer permitted. Secondly, a new exchange rate called the Foreign Exchange Marginal System (“SIMADI”) has been created. The SIMADI rate published on December 31, 2015 is 198.70 Bolivars per USD. The SIMADI’s marginal system is available in limited quantities for individuals and companies to purchase and sell foreign currency via banks and exchange houses. Currently the SIMADI marginal system is the only mechanism available to Harvest Vinccler.
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Petrodelta’s results were also impacted by PDVSA changing its policy with respect to invoicing for disbursements made in Bolivars on behalf of Petrodelta to require that such invoices be denominated in USD rather than Bolivars. This change was implemented in the fourth quarter of 2013 with retroactive application to certain transactions occurring in 2011 and thereafter. As a result of this change, Petrodelta recorded a $14.2 million foreign currency loss in the three months ended December 31, 2013.
Collective Labor Agreement
On February 11, 2014, the Collective Labor Agreement for the period from October 1, 2013 thru October 1, 2015, between the employees of the oil industry represented by the Venezuelan Unitary Federation of workers of the oil, gas, and derivatives (FUTPV) and PDVSA were signed. The Collective Labor Agreement established a salary raise and payroll and retirement benefits which had a significant impact on Petrodelta’s payroll cost. The most significant impact was a steep increase of salary around 90%, with 59% retroactive from October 1, 2013, a 23% raise in effect from May 1, 2014 and finally the remaining portion adjusted on January 1, 2015.
Dividends
On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance. Petrodelta shareholder approval of the dividend was received on March 14, 2011. During the year ended December 31, 2014, we recorded an allowance of $12.2 million, which is reflected in Harvest’s general and administrative costs, to fully reserve the dividend due from Petrodelta. This dividend has not been received as of December 31, 2015.
Note 7 – Venezuela – Other
Harvest Vinccler currently assists us in the oversight of our investment in Petrodelta and in negotiations with PDVSA. Harvest Vinccler’s functional and reporting currency is the USD. They do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”)
In January 2014, the Venezuelan government modified the currency exchange system whereby the official exchange rate of 6.3 Bolivars per USD would only apply to certain economic sectors related to purchases of “essential goods and services” while other sectors of the economy would be subject to a new exchange rate, SICAD I, determined by an auction process conducted by Venezuela's Complimentary System of Foreign Currency Administration. Participation in the SICAD I mechanism is controlled by the Venezuelan government and is limited to certain companies that operate in designated economic sectors.
In March 2014, an additional currency exchange mechanism was established by the Venezuelan government that allows companies within other economic sectors to participate in an additional auction process (“SICAD II”).
On February 10, 2015, the Ministry of Economy, Finance, and Public Banking, and the Central Bank of Venezuela (BCV) published in the Extraordinary Official Gazette No.6.171 Exchange Agreement No.33 with two Official Notices. The first notice being that the SICAD II exchange rate would be no longer permitted. Secondly, a new exchange rate called the Foreign Exchange Marginal System (“SIMADI”) has been created. The SIMADI rate published on December 31, 2015 is 198.70 Bolivars per USD. The SIMADI’s marginal system is available in limited quantities for individuals and companies to purchase and sell foreign currency via banks and exchange houses. Currently the SIMADI marginal system is the only mechanism available to Harvest Vinccler.
We have determined that Harvest Vinccler is not eligible to apply for exchanges at the official rate. We are eligible and have successfully participated in the SIMADI during 2015 and as a result we have adopted the SIMADI exchange rate of approximately 200 Bolivars per USD for the re-measurement of our Bolivar denominated assets and liabilities and revenue and expenses, as we believe the SIMADI rate is most representative of the economics in which Harvest Vinccler operates. Prior to this change, we were using the SICAD II rate of 50 Bolivars per USD.
During the year ended December 31, 2015, Harvest Vinccler exchanged approximately $0.1 million ($0.4 million during the year ended December 31, 2014) and received an average exchange rate of 212.4 Bolivars (34.4 Bolivars during the year ended December 31, 2014) per U.S. Dollar. A gain on foreign currency transactions of $0.3 million was recognized during the year ended December 31, 2015 associated with participating in the SIMADI marginal system. A loss on foreign currency transactions of $0.1 million was recognized during the year ended December 13, 2014 associated with participating in the SICAD II auction process.
The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals, current and deferred income tax and other tax obligations and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official 6.3 Bolivar exchange rate. At December 31, 2015, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 11.9 million Bolivars ($0.06 million) and 5.5 million Bolivars ($0.03 million), respectively.
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Note 8 – Gabon
We are the operator of the Dussafu PSC with a 66.667 percent ownership interest. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC covers an area of 680,000 acres with water depths up to 1,650 feet.
The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources, entered into the third exploration phase of the Dussafu PSC with an effective date of May 28, 2012. The Ministry of Mines, Energy, Petroleum and Hydraulic Resources agreed to lengthen the third exploration phase to four years until May 27, 2016. The Company is currently assessing extension possibilities for the exploration phase.
During 2011, we drilled our first exploratory well, Dussafu Ruche Marin-1 (“DRM-1”), and two appraisal sidetracks. DRM-1 and the sidetracks are currently suspended pending further exploration and development activities.
Well planning progressed during 2012 to drill an exploration well in the fourth quarter of 2012 on the Tortue prospect. DTM-1 well was spud November 19, 2012. DTM-1 was drilled with the Scarabeo 3 semi-submersible drilling unit. On January 4, 2013, we announced that DTM-1 had reached the Dental Formation and discovered oil in both the Gamba and Dentale formations. The first appraisal sidetrack of DTM-1 (“DTM-1ST1”) was spud in January 12, 2013. DTM-1ST1 was drilled in the Dentale Formation. Due to a stuck downhole tool, logging operations were terminated before pressure data could be collected to confirm connectivity. The downhole tool was retrieved and the DTM-1 well suspended for future re-entry.
Operational activities during 2014 included additional evaluation of development alternatives, preparation and a formal remittance of a field development plan along with continued processing of 3D seismic acquired in 2013. On March 26, 2014, the joint venture partners approved a resolution that the discovered fields are commercial to exploit. On June 4, 2014, a Declaration of Commerciality (“DOC”) was signed with Gabon pertaining to the four discoveries on the Dussafu Project offshore Gabon. Furthermore, on July 17, 2014, the Direction Generale Des Hydrocarbures (“DGH”) awarded an Exclusive Exploitation Authorization (“EEA”) for the development and exploitation of certain oil discoveries on the Dussafu Project and on October 10, 2014, the field development plan was approved. The Company has four years from the date of the EEA approval to begin production.
The Company is currently assessing alternatives to farm-down or sell the Dussafu Project, while weighing the liquidity requirements necessary to maintain ongoing Company operations.
Operational activities during the year ended December 31, 2015, included continued evaluation of development plans, based on the 3D seismic data acquired in late 2013 and processed during 2014.
In December 2014, the Company recorded a $50.3 million impairment related to the unproved costs of the Dussafu PSC based on a qualitative analysis which considered our current liquidity needs, our inability to attract additional capital and the decrease in oil and natural gas prices. In December 2015, the Company reassessed the carrying value of the unproved costs related to the Dussafu PSC and recorded an additional impairment of $23.2 million based on its analysis of the value of the unproved costs which considered the value of the contingent and exploration resources and the ability of the Company to develop the project given its current liquidity situation and the depressed price of crude oil. If oil and natural gas prices continue to deteriorate or we fail to obtain adequate financing, farm-down or sell the asset, additional impairments may be required on our prospect.
In the impairment analysis in December 2015, the Company prepared a quantitative and qualitative assessment of the unproved property which estimated the value of the estimated contingent and exploration resources based on the Company’s ability to develop the project given its current liquidity situation and the depressed price of crude oil. The valuation model developed used three price scenarios and a development decision tree model which estimated the value of three development options available to the Company. The value of the development options was determined using outputs from a Monte Carlo simulation model which estimated the net present value of expected future cash flow to be generated from the development of the contingent and exploratory resources in the Dussafu PSC and discounted using a weighted average cost of capital of 21.5%. The development options considered the probability that the Company would be: a) able to farm-down 50% of their working interest; b) able to sell their working interest; and c) unable to complete either of the first 2 options. All inputs used in the valuation process were primarily level 3 in the fair value hierarchy. The concluded fair value of the unproved property costs in our Dussafu project was $28.0 million.
We also reviewed the value of our oilfield inventories that are in the country of Gabon, of which the majority is steel conductor and casing. We impaired the value of this inventory by approximately $1.0 million in 2015, leaving $3.0 million related to this inventory as of December 31, 2015.
See Note 13 – Commitments and Contingencies for a discussion related to our Gabon operations.
Note 9 – Indonesia
We fully impaired our investment in the Budong Production Sharing Contract (“Budong PSC”) in Indonesia as of March 31, 2014. In June 2014, Harvest and our partner adopted a resolution to terminate the Budong PSC. Harvest advised the Indonesian government of this decision and submitted a request to terminate the Budong PSC. On February 5, 2015, the Company entered into a Share Purchase Agreement to transfer shares of Harvest Budong-Budong B.V. to Stockbridge Capital Limited for a nominal amount.
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On February 17, 2015, a withdrawal request of the earlier termination request was made to the Indonesian government and the withdrawal request was accepted on April 15, 2015. The transfer of shares to Stockbridge Capital Limited was completed on May 4, 2015.
Note 10 – Notes Payable to Noncontrolling Interest Owners
At December 31, 2014, HNR Energia had a note payable to Vinccler of $6.1 million. Principal and interest were payable upon the maturity date of December 31, 2015. On March 6, 2015, Vinccler forgave the note payable and accrued interest of $6.2 million. This was reflected as a contribution to stockholders’ equity.
On August 28, 2014 Petroandina exercised its right to a one month extension of the termination date of the SPA. In accordance with the extension the Company had the option to borrow $2.0 million from Petroandina, which it exercised. Petroandina again extended the SPA on September 29, and October 30, 2014, with the Company borrowing $2.0 million per extension. On November 27, 2014, Petroandina exercised their final extension and the Company borrowed the final maximum amount allowed of $1.6 million. Quarterly interest payments began on December 31, 2014 with the principal due January 1, 2016. The note payable with Petroandina as of December 31, 2014 was $7.6 million. Interest accrued at a rate of 11.0%. We were in default of the loan agreement with Petroandina for not making the April 1, 2015 interest payment. After default the interest rate increased from 11.0% to 13.0%. On June 23, 2015, the Company repaid the note payable of $7.6 million plus accrued interest of $0.4 million.
Note 11 – Debt and Financing
On June 19, 2015, we issued the CT Warrant, 9% and 15% Notes, the Additional Draw Note and Series C preferred stock in connection with the Purchase Agreement with CT Energy and received proceeds of $30.6 million, net of financing fees of $1.6 million. We identified embedded derivative assets and derivative liabilities in the notes and determined that the CT Warrant did not meet the required conditions to qualify for equity classification and was required to be classified as a warrant liability (see Note 12 – Warrant Derivative Liability). The estimated fair value, at issuance, of the embedded derivative asset was $2.5 million, the embedded derivative liability was $13.5 million and the warrant liability was $40.0 million. In accordance with ASC 815, the proceeds were first allocated to the fair value of the embedded derivatives and warrants, which resulted in no value being attributable to the Series C preferred stock and the 9% and 15% Notes. As a result of the allocation, we recognized a loss on the issuance of these securities of $20.4 million in our consolidated statements of operations and comprehensive loss during the year end December 31, 2015.
The following table summarizes the movement of our long-term debt due to related party net of discount:
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The face value of the 15% and 9% Notes were recorded net of the discount related to the value allocated to the embedded derivatives and warrant. The unamortized discount of the 15% Note was $25.0 million at December 31, 2015. The Company will accrete the discount over the life of the note using the interest method. Total interest expense associated with this note was $2.2 million, comprised of $2.0 million related to the stated rate of interest on the note and $0.2 million related to the accretion of the discount on the debt. The effective interest rate on the note is approximately 141%. The fair value of the 15% Note at December 31, 2015 was $8.8 million.
15% Non-Convertible Senior Secured Note due June 19, 2020
On June 19, 2015, in connection with the transaction with CT Energy described in Note 1 – Organization, we issued the five-year, 15% Note in the aggregate principal amount of $25.2 million with interest that is compounded quarterly at a rate of 15% per annum and is payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2015. If by June 19, 2016, the volume weighted average price of the Company’s common stock over any consecutive 30-day period has not equaled or exceeded $2.50 per share, the maturity date of the 15% Note will be extended by two years and the interest rates on the
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15% Note will adjust to 8.0% (the “15% Note Reset Feature”). During an event of default, the outstanding principal amount bears additional interest at a rate of 2.0% per annum higher than the rate otherwise applicable.
The Company may prepay all or a portion of the note at a prepayment price equal to a make-whole price, as of the prepayment date, with respect to the principal amount of the note being prepaid, plus accrued and unpaid interest. The make-whole price is defined as the greater of (i) 100% of such outstanding principal amount of the 15% Note and (ii) the sum of the present values as of such date of determination of (A) such outstanding principal amount of the 15% Note, assumed, for the purpose of determining the present value thereof, to be paid on the earlier of the stated maturity of this 15% Note or the date that is two years after the date of determination, and (B) all remaining payments of interest (excluding interest accrued to the prepayment date) scheduled to become due and payable after the date of determination and on or before the date that is two years after the date of determination with respect to such outstanding principal amount of the 15% Note, in the case of each of the foregoing clauses (ii)(A) and (B), computed using a discount rate equal to the Treasury Rate as of the date of determination plus 50 basis points.
If an event of default occurs (other than an event of default related to certain bankruptcy events), holders of at least 25% of the outstanding principal of the 15% Note may declare the principal, premium, if any, and accrued and unpaid interest of such notes immediately due and payable. If an event of default related to specified bankruptcy events occurs, an amount equal to the make-whole price for the 15% Note plus accrued and unpaid interest is immediately due and payable.
We have evaluated the 15% Note Reset Feature related to the interest rate and maturity date using “ASC 815 Derivatives and Hedging”. Because the interest rate and maturity date reset are linked to achievement of a certain stock price, the feature is not considered clearly and closely related to the debt host. In addition, the interest rate at the reset date is not tied to any approximation of the expected market rate at the date of the term extension as required by ASC 815. As a result, we are accounting for the 15% Note Reset Feature as an embedded derivative asset that has been measured at fair value with current changes in fair value reflected in our consolidated statements of operations and comprehensive loss.
The embedded 15% Note Reset Feature in the 15% Note was valued using the ‘with’ and ‘without’ method. A Black-Derman-Toy (“BDT”) Model, which is a binomial interest rate lattice model, was used to value the 15% Note and the incremental value attributed to the embedded option was determined based on a comparison of the value of the 15% Note with the feature included and without the feature included. Key inputs into this valuation model are our current stock price, U.S. Treasury rate, our credit spread and the underlying yield volatility. As part of our overall valuation process, management employs processes to evaluate and validate the methodologies, techniques and inputs, including review and approval of valuation judgments, methods, models, process controls, and results. These processes are designed to help ensure that the fair value measurements and disclosures are appropriate, consistently applied, and reliable. We estimate the yield volatility for the 15% Note based on historical daily volatility of the USD denominated Venezuela Sovereign zero coupon yield over a look back period of 6.0 years. The risk-free interest rate is based on the U.S. Treasury yield curve as of the valuation dates for a maturity similar to the expected remaining life of the 15% Note. The credit spread was estimated based on the option adjusted spread (“OAS”) of the Venezuelan yield over the USD Treasury yield and the implied OAS for the transaction as of the date the term sheet was signed to capture the investor’s assessment of the risk in their investment in the Company. This model requires Level 3 inputs (see Note 3 – Summary of Significant Accounting Policies, Financial Instruments and Fair Value Measurements) which were based on our estimates of the probability and timing of potential future financings and fundamental transactions.
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The assumptions summarized in the following table were used to calculate the fair value of the derivative asset associated with the 15% Note at the date of issuance:
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The embedded derivative asset related to the 15% Note contains a Level 3 input related to the probability of our investor lending us additional funds or not lending us funds according to the terms of the loan agreement for the additional draws. We have assumed a 50/50 scenario of the draw or no draw for valuation of the embedded derivative. Changes in this assumption have minimal impacts on the embedded derivative asset valuation as HNR stock price is the primary driver of the value.
The assumptions summarized in the following table were used to calculate the fair value of the derivative asset associated with the 15% Note that was outstanding as of December 31, 2015 on our consolidated balance sheet:
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The fair value of the embedded derivative asset was $2.5 million at issuance and $5.0 million as of December 31, 2015. We recognized $2.5 million in income related to the change in fair value of this embedded derivative asset in change in fair value of derivative assets and liabilities in our consolidated statement of operations for the year ended December 31, 2015.
15% Non-Convertible Senior Secured Additional Draw Note
On June 19, 2015, in connection with the transaction with CT Energy described in Note 1 – Organization, the Company also issued the Additional Draw Note which, under certain circumstances, CT Energy may elect to provide $2.0 million of additional funds to the Company per month for up to six months following the one-year anniversary of the closing date of the transaction (up to $12.0 million in aggregate). If funds are loaned under the Additional Draw Note, interest will be compounded quarterly at a rate of 15.0% per annum and will be payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2016. If by the Claim Date, the volume weighted average price of the Company’s common stock over any consecutive 30-day period has not equaled or exceeded $2.50 per share, the maturity date of the Additional Draw Note will be extended by two years and the interest rate on the Additional Draw Note will adjust to 8.0%. During an event of default, the outstanding principal amount will bear additional interest at a rate of 2.0% per annum higher than the rate otherwise applicable.
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The Company may prepay all or a portion of the Additional Draw Note at a prepayment price equal to the make-whole price, as of the prepayment date, with respect to the principal amount of the Additional Draw Note being prepaid, plus accrued and unpaid interest. The make-whole price with respect to the Additional Draw Note has the same meaning described above with respect to the 15% Note under.
If an event of default occurs (other than an event of default related to certain bankruptcy events), holders of at least 25% of the outstanding principal of the 15% Note (including the Additional Draw Note, if outstanding) may declare the principal, premium, if any, and accrued and unpaid interest of such notes immediately due and payable. If an event of default related to specified bankruptcy events occurs, an amount equal to the make-whole price for the Additional Draw Note plus accrued and unpaid interest is immediately due and payable.
Because we have not withdrawn any proceeds on this note at issuance and at December 31, 2015, we have assigned no value to the Additional Draw Note, as it does not meet the definition of a derivative in ASC 815 and there is no principal amount outstanding.
9% Convertible Senior Secured Note due June 19, 2020
On June 19, 2015, in connection with the transaction with CT Energy described in Note 1 – Organization we issued the five-year, 9% Note in the aggregate principal amount of $7.0 million, which was immediately convertible into 8,506,098 shares of the Company’s common stock, par value $0.01 per share, at an initial conversion price of $0.82 per share (“Beneficial Conversion Feature”).
Interest on the 9% Note was compounded quarterly at a rate of 9.0% per annum and was payable quarterly on the first business day of each January, April, July and October, commencing October 1, 2015. If by June 19, 2016, the volume weighted average price of the Company’s common stock over any consecutive 30-day period had not equaled or exceeded $2.50 per share, the maturity date of the 9% Note will be extended by two years and the interest rates on the 9% Note will adjust to 8.0% (the “9% Note Reset Feature”).
Regarding the 9% Note Reset Feature, because the interest rate and maturity date reset were linked to achievement of a certain stock price, the feature was not considered clearly and closely related to the debt host. In addition, the interest rate at the reset date was not tied to any approximation of the expected market rate at the date of the term extension as required by ASC 815. As a result, we accounted for the 9% Note Reset Feature as an embedded derivative asset that was measured at fair value with current changes in fair value reflected in change of fair value of derivative assets and liabilities in our consolidated statements of operations and comprehensive loss. The changes in the fair value of this embedded derivative asset was netted against the changes in the fair value of the embedded derivative liabilities relating to the 9% Down-Round Provision and Note Reset Feature discussed below.
The conversion price was subject to adjustment upon the occurrence of certain events, including a stock issuance, dividend, or stock split. If the Company completes an issuance of common stock at a price less than the current conversion price, then the conversion price will be fully reduced to the new issuance price for such below-price issuance (the “9% Down-Round Provision”). This is a full ratchet down round provision that could compensate the holder for an amount greater than dilution related to a stock issuance. For example, in the event of an issuance of stock causing a 10% dilution, the note holder could theoretically be compensated greater than 10% under certain circumstances.
The embedded 9% Down-Round Provision and the 9% Note Reset Feature were valued using the ‘with’ and ‘without’ method. A Binomial Lattice Model was used to value the 9% Note and the incremental value attributed to the embedded options was determined based on a comparison of the value of the 9% Note with the features included and without the features included. Key inputs into this valuation model were our current stock price, U.S. Treasury rate, our credit spread and the underlying stock price volatility. As part of our overall valuation process, management employs processes to evaluate and validate the methodologies, techniques and inputs, including review and approval of valuation judgments, methods, models, process controls, and results. These processes are designed to help ensure that the fair value measurements and disclosures are appropriate, consistently applied, and reliable. We estimated the volatility of our common stock based on historical volatility that matches the expected remaining life of the longest instrument in the transaction, seven years. The risk-free interest rate was based on the U.S. Treasury yield curve as of the valuation dates for a maturity similar to the expected remaining life of the 9% Note. The credit spread was estimated based on the option adjusted spread (“OAS”) of the Venezuelan yield over the USD Treasury yield and the implied OAS for the transaction as of the date the term sheet was signed to capture the investor’s assessment of the risk in their investment in the Company. This model requires Level 3 inputs (see Note 3 – Summary of Significant Accounting Policies, Financial Instruments and Fair Value Measurements) which were based on our estimates of the probability and timing of potential future draws.
We have evaluated the 9% Down-Round Provision and the 9% Note Reset Feature using ASC 815. The Convertible Down-Round Provision is not consistent with a fixed-price-for-fixed-number of shares instrument and therefore precludes the conversion option from being indexed to the Company’s own stock. As a result, the conversion option did not meet the scope exception in ASC 815 and was bifurcated as a separate liability that has been measured at fair value with current changes in fair value reflected in our consolidated statements of operations and comprehensive loss.
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The fair value of the net embedded derivative liabilities was $13.5 million at issuance and $11.1 million immediately prior to the conversion of the 9% Note. We recognized $2.3 million in income for the change in the fair value of this embedded derivative liabilities in our consolidated statement of operations for the year ended December 31, 2015.
On September 15, 2015, the 9% Note, the associated accrued interest and related derivative liabilities were converted into 8,667,597 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 liabilities ($11.1 million) less the fair value of the 8,667,597 shares issued upon conversion ($13.2 million) at September 15, 2015.
The assumptions summarized in the following table were used to calculate the fair value of the net embedded derivative liability associated with the 9% Note at the date of issuance:
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Note 12 – Warrant Derivative Liability
CT Warrant
On June 19, 2015, in connection with the transaction with CT Energy described in Note 1 – Organization, we issued a warrant exercisable for 34,070,820 shares of the Company’s common stock at an initial exercise price of $1.25 per share. The CT Warrant may not be exercised until the volume weighted average price of the Company’s common stock over any consecutive 30-day period equals or exceeds $2.50 per share.
The CT Warrant can be exercised at the option of the investor in cash or by effecting a reduction in the principal amount of the 15% Note (See Note 11 – Debt and Financing). If the CT Warrant is exercised through the reduction in the principal amount of the 15% Note, the reduction will be equal to the amount obtained by multiplying the number of shares of common stock for which the CT Warrant is exercised by (i) the exercise price then in effect divided by (ii) (A) the defined make-whole price with respect to the outstanding principal amount of such 15% Note divided by (B) the outstanding principal amount of such 15% Note. The exercise price of the CT Warrant is subject to adjustment upon the occurrence of certain events, including stock issuance, dividend or stock split.
In addition, the holder of the CT Warrant has certain registration rights regarding the CT Warrant and the shares of common stock issuable upon exercise of the CT Warrant.
We have analyzed the CT Warrant to determine whether it should be classified as a derivative liability or equity instrument. Provisions of the CT Warrant agreement allow for a change in the exercise price of the CT Warrant upon the occurrence of certain corporate events. These exercise price adjustments incorporate variables other than those used to determine the fair value of a fixed-for-fixed forward or option on equity shares therefore the CT Warrant is not considered to be “indexed to the issuer’s own stock” and does not meet the exception from derivative treatment in ASC 815. HNR continues to account for the CT Warrant as a derivative which was marked to market as of December 31, 2015.
Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument with related changes in internal and external market factors. In addition, option-based techniques (such as the Monte Carlo model) are highly volatile and sensitive to changes in the trading market price of our common stock. Since derivative financial instruments are initially and subsequently carried at fair value, our income will reflect the volatility in these estimate and assumption changes. A Monte Carlo simulation model is used to value the CT Warrant to determine if the Stock Appreciation Date is achieved, which is based on the average stock price over a 30 day period (21 trading days) reaching $2.50. This requires Level 3 inputs (see Note 3 – Summary of Significant Accounting Policies, Financial Instruments and Fair Value Measurements) which are fundamentally based on market data but require complex modeling. The additional modeling is
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required in order to simulate future stock prices, to determine whether the Stock Appreciation Date is achieved and to model the projected exercise behavior of the warrant holders.
The assumptions summarized in the following table were used to calculate the fair value of the warrant derivative liability at the date of issuance:
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The assumptions summarized in the following table were used to calculate the fair value of the warrant derivative liability that was outstanding as of the balance sheet date presented on our consolidated balance sheet:
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Inherent in the Monte Carlo valuation model are assumptions related to expected stock price volatility, expected life, risk-free interest rate and dividend yield. As part of our overall valuation process, management employs processes to evaluate and validate the methodologies, techniques and inputs, including review and approval of valuation judgments, methods, models, process controls, and results. These processes are designed to help ensure that the fair value measurements and disclosures are appropriate, consistently applied, and reliable. We estimate the volatility of our common stock based on historical volatility that matches the expected remaining life of the longest instrument in the transaction, seven years. The risk-free interest rate is based on the U.S. Treasury yield curve as of the valuation dates for a maturity similar to the expected remaining life of the CT Warrant. The expected life of the CT Warrants is assumed to be equivalent to their remaining contractual term. The dividend rate is based on the historical rate, which we anticipate to remain at zero.
The fair value of the CT Warrant was $40.0 million at issuance and $5.5 million as of December 31, 2015. We recognized income of $34.5 million related to the change in fair value of the warrant liability in our consolidated statement of operations and comprehensive loss for the year ended December 31, 2015.
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MSD Warrants
On October 28, 2015, the warrants issued as inducements in connection with a $60 million term loan facility that was paid off in May 2011 (“MSD Warrants”) expired (1,846,088 warrants outstanding: December 31, 2014). The fair value of these warrants as of December 31, 2014 and at expiration was $0.00 per warrant. The Warrant Purchase Agreement dated as of October 28, 2010 includes certain anti-dilution provisions which adjust the number of warrants and the exercise price per warrant. The issuance of the CT Energy 9% Note, because of the initial conversion price and the CT Warrant of 34,070,820 shares triggered the anti-dilution provisions on the MSD Warrants which resulted in the issuance of 1,547,739 additional warrants during the year ended December 31, 2015. In addition, the exercise price per share for all warrants was repriced to $6.97 per warrant during the year ended December 31, 2015. The warrants had been classified as a liability on our consolidated balance sheets and marked to market. The valuation for the warrants had based primarily on our stock price of $1.81 at December 31, 2014, their remaining life of 0.83 years and their strike price of $6.97 as of December 31, 2014. We recognized $0.0 million in warrant liability income in our consolidated statement of operations and comprehensive loss year ended December 31, 2015 for these warrants ($2.0 million and $3.5 million for the years ended December 31, 2014 and 2013, respectively). The assumptions summarized in the following table were used to calculate the fair value of the warrant derivative liability related to the MSD warrants that were outstanding at December 31, 2014:
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Note 13 – Commitments and Contingencies
We have employment contracts with five executive officers which provide for annual base salaries, eligibility for bonus compensation and various benefits. The contracts provide for a lump sum payment as a multiple of base salary in the event of termination of employment without cause. In addition, these contracts provide for payments as a multiple of base salary and bonus, excise tax reimbursement, outplacement services and a continuation of benefits in the event of termination without cause following a change in control. By providing one year notice, these agreements may be terminated by either party on or before May 31, 2016.
We have various contractual commitments pertaining to leasehold, training, and development costs for the Dussafu PSC totaling $4.5 million. Under the EEA granted for the Dussafu PSC on July 17, 2014, we are required to commence production within four years of the date of grant in order to preserve our rights to production under the EEA. We expect that significant capital expenditures will be required prior to commencement of production which is expected in 2016 under the approved field development plan. These work commitments are non-discretionary; however, we do have the ability to control the pace of expenditures.The table below consists of our contractual commitments for office space and various other commitments:
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Obligations: |
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Oil and natural gas activities |
| $ | 4,520 |
| $ | 1,130 |
| $ | 1,130 |
| $ | 1,130 |
| $ | 1,130 |
Office leases |
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| 171 |
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| 157 |
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| 14 |
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Total contractual obligations |
| $ | 4,691 |
| $ | 1,287 |
| $ | 1,144 |
| $ | 1,130 |
| $ | 1,130 |
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Under the agreements with our partners in the Dussafu PSC and the Budong PSC, we are jointly and severally liable to various third parties. As of December 31, 2015, the gross carrying amount associated with obligations to third parties which were fixed at the end of the period was $0.3 million ($2.4 million as of December 31, 2014) and is related to accounts payable to vendors, accrued expenses and withholding taxes payable to taxing authorities. As we are the operators for the Dussafu PSC and Budong PSC, the gross carrying amount related to accounts payable and withholding taxes and the net amount related to other accrued expenses are reflected in the consolidated balance sheet in accounts payable and accrued expenses leaving $0.1 million in fixed obligations as of December 31, 2015 ($0.3 million as of December 31, 2014) attributable to our joint partners’ share which is not accrued in our balance sheet. Our partners have advanced $0.0 million ($0.5 million as of December 31, 2014) to satisfy their share of these obligations which was $0.1 million as of December 31, 2015 ($0.8 million as of December 31, 2014). As we expect our partners will continue to meet their
S-34
obligations to fund their share of expenditures, we have not recognized any additional liability related to fixed joint interest obligations attributable to our joint interest partners.
Kensho Sone, et al. v. Harvest Natural Resources, Inc., in the United States District Court, Southern District of Texas, Houston Division. On July 24, 2013, 70 individuals, all alleged to be citizens of Taiwan, filed an original complaint and application for injunctive relief relating to the Company’s interest in the WAB-21 area of the South China Sea. The complaint alleged that the area belonged to the people of Taiwan and sought damages in excess of $2.9 million and preliminary and permanent injunctions to prevent the Company from exploring, developing plans to extract hydrocarbons from, conducting future operations in, and extracting hydrocarbons from, and the WAB-21 area. The Company filed a motion to dismiss the suit, which was granted by the district court in August 2014. The plaintiffs appealed the dismissal. The Fifth Circuit Court of Appeals heard oral arguments on June 3, 2015 and affirmed the district court’s dismissal on June 4, 2015. The plaintiffs filed a petition for writ of certiorari with the Supreme Court of the United States. On October 13, 2015, the Supreme Court denied the petition.
The following related class action lawsuits were filed on the dates specified in the United States District Court, Southern District of Texas: John Phillips v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (March 22, 2013) (“Phillips case”); Sang Kim v. Harvest Natural Resources, Inc., James A. Edmiston, Stephen C. Haynes, Stephen D. Chesebro’, Igor Effimoff, H. H. Hardee, Robert E. Irelan, Patrick M. Murray and J. Michael Stinson (April 3, 2013); Chris Kean v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 11, 2013); Prastitis v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 17, 2013); Alan Myers v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 22, 2013); and Edward W. Walbridge and the Edward W. Walbridge Trust v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 26, 2013). The complaints allege that the Company made certain false or misleading public statements and demand that the defendants pay unspecified damages to the class action plaintiffs based on stock price declines. All of these actions have been consolidated into the Phillips case. The Company and the other named defendants have filed a motion to dismiss and intend to vigorously defend the consolidated lawsuits. We are currently unable to estimate the amount or range of any possible loss.
In May 2012, Newfield Production Company (“Newfield”) filed notice pursuant to the Purchase and Sale Agreement between Harvest (US) Holdings, Inc. (“Harvest US”), a wholly owned subsidiary of Harvest, and Newfield dated March 21, 2011 (the “PSA”) of a potential environmental claim involving certain wells drilled on the Antelope Project. The claim asserts that locations constructed by Harvest US were built on, within, or otherwise impact or potentially impact wetlands and other water bodies. The notice asserts that, to the extent of potential penalties or other obligations that might result from potential violations, Harvest US must indemnify Newfield pursuant to the PSA. In June 2012, we provided Newfield with notice pursuant to the PSA (1) denying that Newfield has any right to indemnification from us, (2) alleging that any potential environmental claim related to Newfield’s notice would be an assumed liability under the PSA and (3) asserting that Newfield indemnify us pursuant to the PSA. We dispute Newfield’s claims and plan to vigorously defend against them. We are currently unable to estimate the amount or range of any possible loss.
On May 31, 2011, the United Kingdom branch of our subsidiary, Harvest Natural Resources, Inc. (UK), initiated a wire transfer of approximately $1.1 million ($0.7 million net to our 66.667 percent interest) intending to pay Libya Oil Gabon S.A. (“LOGSA”) for fuel that LOGSA supplied to our subsidiary in the Netherlands, Harvest Dussafu, B.V., for the company’s drilling operations in Gabon. On June 1, 2011, our bank notified us that it had been required to block the payment in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by OFAC, because the payee, LOGSA, may be a blocked party under the sanctions. The bank further advised us that it could not release the funds to the payee or return the funds to us unless we obtain authorization from OFAC. On October 26, 2011, we filed an application with OFAC for return of the blocked funds to us. Until that application is approved, the funds will remain in the blocked account, and we can give no assurance when OFAC will permit the funds to be released. On April 23, 2014, we received a notice that OFAC had denied our October 26, 2011 application for the return of the blocked funds. During the year ended December 31, 2015 primarily due to the passage of time, we recorded a $0.7 million allowance for doubtful accounts to general and administrative costs associated with the blocked payment and $0.4 million receivable from our joint venture partner. On October 13, 2015, we filed a request that OFAC reconsider its decision and on March 8, 2016 OFAC denied our October 13, 2015 request for the return of blocked funds; however, the Company will continue attempts to recover the funds from OFAC.
Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc., Branta Exploration & Production, LLC, Ute Energy LLC, Cameron Cuch, Paula Black, Johnna Blackhair, and Elton Blackhair in the United States District Court for the District of Utah. This suit was served in April 2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the defendants, among other things, intentionally interfered with plaintiffs’ employment agreement with the Ute Indian Tribe – Energy & Minerals Department and intentionally interfered with plaintiffs’ prospective economic relationships. Plaintiffs seek actual damages, punitive damages, costs and attorney’s fees. The court administratively closed the case in 2013. The case was reopened in 2014 as a result of a Circuit Court of Appeals’ ruling. On November 3, 2015, the court granted a stipulated motion to dismiss with prejudice and the lawsuit was dismissed.
Uracoa Municipality Tax Assessments. Harvest Vinccler, a subsidiary of Harvest Holding, has received nine assessments from a tax inspector for the Uracoa municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:
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Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions based on the interpretation of the tax code by SENIAT (the Venezuelan income tax authority), as it applies to operating service agreements, Harvest Holding has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.
Libertador Municipality Tax Assessments. Harvest Vinccler has received five assessments from a tax inspector for the Libertador municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:
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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
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affiliates; and (j) the forced migration of the Company’s investment in Venezuela from an operating services agreement to a mixed company structure in 2007.
On January 26, 2015, Petroandina filed a complaint for breach of contract against the Company and its subsidiary HNR Energia in Court of Chancery of the State of Delaware (“Court of Chancery”). The complaint states that HNR Energia breached provisions of the Shareholders Agreement between Petroandina and HNR Energia, which provisions require HNR Energia to provide advance notice of, and deposit $5.0 million into an escrow account, before bringing any claim against the Venezuelan government. Under those provisions, if Petroandina so requests, an appraisal of Petroandina's 29 percent interest in Harvest Holdings must be performed, and Petroandina has the right to require HNR Energia to purchase that 29 percent interest at the appraised value. Petroandina's claim requests that, among other things, the court (a) declare that HNR Energia has breached the Shareholders' Agreement by submitting the Request for Arbitration against the Venezuelan government on January 15, 2015 (which Request for Arbitration was subsequently withdrawn without prejudice); (b) declare that the Company has breached its guaranty of HNR Energia's obligations under the Shareholders' Agreement; (c) direct the Company and HNR Energia to refrain from prosecuting any legal proceeding against the Venezuelan government (including the previously filed Request for Arbitration) until such time as they have complied with the relevant provisions of the Shareholders' Agreement; (d) award Petroandina costs and fees related to the lawsuit; and (e) award Petroandina such other relief as the court deems just and proper. On January 28, 2015, the Court of Chancery issued an injunction ordering the Company and HNR Energia to withdraw the Request for Arbitration and not take any action to pursue its claims against Venezuela until Harvest and HNR Energia have complied with the provisions of the Shareholders’ Agreement or otherwise reached an agreement with Petroandina. Accordingly, on January 28, 2015, HNR Finance B.V. and Harvest Vinccler S.C.A. withdrew without prejudice the Request for Arbitration. In the Delaware proceeding, the Company and HNR Energia have until May 23, 2016 to respond to Petroandina’s complaint. We are currently unable to estimate the amount or range of any possible loss.
On February 27, 2015, Harvest (US) Holdings, Inc. (“Harvest US”), a wholly owned subsidiary of Harvest, Branta, LLC and Branta Exploration & Production Company, LLC (together, “Branta,” and together with Harvest US, “Plaintiffs”) filed a complaint against Newfield Production Company (“Newfield”) in the United States District Court for the District of Colorado. Plaintiffs previously sold oil and natural gas assets located in Utah’s Uinta Basin to Newfield pursuant to two Purchase and Sale Agreements, each dated March 21, 2011. In the complaint, Plaintiffs allege that, prior to the sale, Newfield breached separate confidentiality agreements with Harvest US and Branta by discussing the auction of the assets with a potential bidder for the assets, which caused the potential bidder not to participate in the auction and resulted in a depressed sales price for the assets. The complaint seeks damages and fees for breach of contract, violation of the Colorado Antitrust Act, violation of the Sherman Antitrust Act and tortious interference with a prospective business advantage. In September 2015, Plaintiffs amended their complaint to add Ute Energy, LLC and Crescent Point Energy Corporation as defendants.
We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such incidental litigation that will have a material adverse effect on our financial condition, results of operations and cash flows.
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Note 14 – Taxes
Taxes on Income
The tax effects of significant items comprising our net deferred income taxes are as follows:
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Deferred tax assets: |
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Operating loss carryforwards |
| $ | 50,974 |
| $ | 13,547 |
| $ | 54,722 |
| $ | 8,718 |
Stock-based compensation |
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| — |
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| 3,471 |
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| — |
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| 6,479 |
Accrued compensation |
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| — |
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| 653 |
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| — |
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| 376 |
Oil and natural gas properties |
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| 26,065 |
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| — |
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| 18,515 |
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| — |
Investment in affiliate |
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| 130,088 |
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| — |
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| 88,913 |
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Alternative minimum tax credit |
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| — |
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| 2,545 |
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| — |
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| 4,299 |
Other |
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| — |
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| 89 |
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| — |
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| 81 |
Total deferred tax assets |
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| 207,127 |
|
| 20,305 |
|
| 162,150 |
|
| 19,953 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Tax on unremitted earnings of foreign subsidiaries |
|
| — |
|
| — |
|
| — |
|
| (14,700) |
Other liabilities |
|
| (1,111) |
|
| (278) |
|
| — |
|
| (141) |
Fixed assets |
|
| — |
|
| (3) |
|
| — |
|
| (3) |
Total deferred tax liabilities |
|
| (1,111) |
|
| (281) |
|
| — |
|
| (14,844) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax asset (liability) |
|
| 206,016 |
|
| 20,024 |
|
| 162,150 |
|
| 5,109 |
Valuation allowance |
|
| (205,896) |
|
| (20,024) |
|
| (162,097) |
|
| (19,809) |
Net deferred tax asset (liability) after valuation allowance |
| $ | 120 |
| $ | — |
| $ | 53 |
| $ | (14,700) |
|
|
|
|
|
|
|
|
|
|
|
|
|
As a result of the adoption of ASU No. 2015-17 the net deferred tax assets (liabilities) as of December 31, 2015 and 2014, were included in the consolidated balance sheets as Long-term deferred tax assets of $0.1 million and $0.1 million and Long-term deferred tax liabilities of $0.0 and $14.7 million, respectively.
After assessing the possible actions which management may take in 2016 and the next few years during the year ended December 31, 2015, we continued to recognize that a deferred tax liability related to income tax on undistributed earnings of our foreign subsidiaries may be appropriate. The Company is pursuing various alternatives with respect to its future operations and cannot assert that any future earnings will not be remitted to the U.S. as operations require. The deferred tax liability recognized in prior periods, however, was decreased during 2015 to zero due to the impairment of the Company’s remaining investment in Petrodelta.
Management assesses the available positive and negative evidence to estimate if sufficient future taxable income will be generated to use the existing deferred tax assets (“DTAs”). A significant piece of objective negative evidence evaluated was the cumulative losses incurred in our foreign operating entities over the three-year period ended December 31, 2015. Such objective evidence limits the ability to consider other subjective evidence such as our projections for future growth or future asset dispositions. We have therefore placed a valuation allowance on all but a small amount of our foreign DTAs.
S-38
Management also reviewed the earnings history of our U.S. operations and determined that the Company is not expected to have sufficient taxable income in the U.S. due to its inability to sell the remaining equity interest in Harvest Holding and the lack of other income producing operations. Consequently, the Company is not expected to utilize its deferred tax assets and carries a valuation allowance on these deferred tax assets. Additionally, there was a significant increase to the valuation allowance attributable to the recognition of deferred tax assets related to the impairments of Petrodelta and the Dussafu PSC as these deferred tax assets are more likely than not to be unrealizable. The components of loss from continuing operations before income taxes are as follows:
|
|
|
|
|
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|
|
|
|
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|
|
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|
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|
| Year Ended December 31, | |||||||
|
| 2015 |
| 2014 |
| 2013 | |||
|
|
|
|
|
|
|
|
|
|
|
| (in thousands) | |||||||
Income (loss) before income taxes |
|
|
|
|
|
|
|
|
|
United States |
| $ | 1,457 |
| $ | (12,809) |
| $ | (31,072) |
Foreign |
|
| (198,537) |
|
| (438,589) |
|
| (40,725) |
Total |
| $ | (197,080) |
| $ | (451,398) |
| $ | (71,797) |
|
|
|
|
|
|
|
|
|
|
The provision (benefit) for income taxes on continuing operations consisted of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, | |||||||
|
| 2015 |
| 2014 |
| 2013 | |||
|
|
|
|
|
|
|
|
|
|
|
| (in thousands) | |||||||
Current: |
|
|
|
|
|
|
|
|
|
United States |
| $ | (1,755) |
| $ | (87) |
| $ | 2,279 |
Foreign |
|
| 32 |
|
| 47 |
|
| 44 |
|
|
| (1,723) |
|
| (40) |
|
| 2,323 |
Deferred: |
|
|
|
|
|
|
|
|
|
United States |
|
| (14,700) |
|
| (58,250) |
|
| 72,971 |
Foreign |
|
| — |
|
| — |
|
| (2,207) |
|
|
| (14,700) |
|
| (58,250) |
|
| 70,764 |
|
| $ | (16,423) |
| $ | (58,290) |
| $ | 73,087 |
|
|
|
|
|
|
|
|
|
|
S-39
A comparison of the income tax expense (benefit) on continuing operations at the federal statutory rate to our provision for income taxes is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, | |||||||
|
| 2015 |
| 2014 |
| 2013 | |||
|
|
|
|
|
|
|
|
|
|
|
| (in thousands) | |||||||
Income tax expense (benefit) from continuing operations: |
|
|
|
|
|
|
|
|
|
Tax expense (benefit) at U.S. statutory rate |
| $ | (68,978) |
| $ | (157,989) |
| $ | (25,129) |
Effect of foreign source income and rate differentials on foreign income |
|
| (10,870) |
|
| 38,198 |
|
| 204 |
Tax gain associated with sale of interest in Harvest Holding |
|
| — |
|
| — |
|
| 7,474 |
Subpart F income |
|
| — |
|
| — |
|
| 16,615 |
Non-deductible interest |
|
| 11,397 |
|
| — |
|
| — |
Tax on unremitted earnings of foreign subsidiaries |
|
| (14,700) |
|
| (75,200) |
|
| 89,900 |
Expired losses |
|
| 24,554 |
|
| 2,778 |
|
| 1,356 |
Other changes in valuation allowance |
|
| 44,014 |
|
| 129,480 |
|
| (10,643) |
Change in applicable statutory rate |
|
| — |
|
| — |
|
| (404) |
Other permanent differences |
|
| — |
|
| 2,010 |
|
| (2,546) |
Return to accrual and other true-ups |
|
| 11,823 |
|
| 1,955 |
|
| 2,919 |
Debt exchange |
|
| (12,079) |
|
| — |
|
| — |
Warrant derivatives |
|
| (1,685) |
|
| (684) |
|
| (1,180) |
Liability for uncertain tax positions |
|
| 67 |
|
| (30) |
|
| (5,553) |
Other |
|
| 34 |
|
| 1,192 |
|
| 74 |
Total income tax expense (benefit) – continuing operations |
| $ | (16,423) |
| $ | (58,290) |
| $ | 73,087 |
|
|
|
|
|
|
|
|
|
|
Rate differentials for foreign income result from tax rates different from the U.S. tax rate being applied in foreign jurisdictions.
At December 31, 2015, we have the following net operating losses available for carryforward (in thousands):
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| ||
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| ||||
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| ||||
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- 15 -
|
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|
|
|
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|
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|
|
| ||
|
|
|
|
|
|
|
|
|
| Foreign |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
| Group |
| Company |
| Housing and |
| Cost of |
|
|
|
|
|
|
| Foreign |
|
|
|
|
|
| |||||||
Name and Principal |
|
|
| Term |
| 401(K) |
| Living |
| Living |
| Vacation |
| Transportation |
| Service |
| Foreign |
|
|
| ||||||||||
Position |
| Year |
| Life |
| Match |
| Expense |
| Adjustment |
| Allowance |
| Allowance |
| Premium |
| Taxes |
| Total ($) | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
James A. Edmiston |
| 2015 |
| $ | 9,408 |
| $ | 10,600 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 20,008 | ||
President and Chief |
| 2014 |
|
| 9,324 |
|
| 10,400 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 19,724 | ||
Executive Officer |
| 2013 |
|
| 7,949 |
|
| 10,200 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 18,149 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Stephen C. Haynes |
| 2015 |
| $ | 6,655 |
| $ | 10,600 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 17,255 | ||
Vice President, Finance |
| 2014 |
|
| 7,023 |
|
| 10,400 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 17,423 | ||
Chief Financial Officer |
| 2013 |
|
| 8,723 |
|
| 10,200 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 18,923 | ||
and Treasurer |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Robert Speirs |
| 2015 |
| $ | 1,980 |
| $ | — |
| $ | 156,325 |
| $ | 83,464 |
| $ | 44,281 |
| $ | 33,661 |
| $ | 28,500 |
| $ | 140,701 |
| $ | 488,912 | ||
Senior Vice President |
| 2014 |
|
| 1,290 |
|
| — |
|
| 173,840 |
|
| 93,600 |
|
| 45,714 |
|
| 33,661 |
|
| 28,500 |
|
| 160,854 |
|
| 537,459 | ||
Eastern Operations |
| 2013 |
|
| 1,290 |
|
| — |
|
| 175,242 |
|
| 93,894 |
|
| 48,276 |
|
| 34,000 |
|
| 28,500 |
|
| 4,161 |
|
| 385,363 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Karl L. Nesselrode |
| 2015 |
| $ | 7,994 |
| $ | 10,600 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 18,594 | ||
Vice President |
| 2014 |
|
| 7,923 |
|
| 10,400 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 18,323 | ||
Engineering and |
| 2013 |
|
| 7,698 |
|
| 10,200 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 17,898 | ||
Business Development |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Keith L. Head |
| 2015 |
| $ | 3,583 |
| $ | 10,600 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 14,183 | ||
Vice President |
| 2014 |
|
| 3,636 |
|
| 10,400 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 14,036 | ||
General Counsel |
| 2013 |
|
| 10,168 |
|
| 10,200 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 20,368 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As a result
Grants of the first Petroandina closing in 2013, the Company realized a tax gainPlan-Based Awards
The following table shows information concerning options to purchase our common stock granted to each of $47.4 million which was included in U.S. taxable income pursuant to the provisions of the Internal Revenue Code. The Company utilized $9.8 million of available losses from prior years as well as a current year tax loss of $37.6 million to offset income resulting from the sale resulting in no regular tax for the year ended December 31, 2013 and leaving $9.3 million of losses available to offset taxable income in future periods. However, as a result of the alternative minimum tax provisions (“AMT”), we did incur AMT of $1.9 million increasing the amount of the AMT credit carryforward. During 2014, the Company incurred a net operating loss (“NOL”) for AMT purposes. A portion of this AMT NOL was carried back to 2013 to offset 90% of the $1.9 million AMT liability incurredour named executive officers during the year. Accounts receivable at December 31, 2015 included a tax receivable of $1.7 million which was received from the Internal Revenue Service on February 12, 2016. The AMT credit carryforward at December 31, 2015 amounts to $2.6 million..
If the U.S. operating loss carryforwards are ultimately realized, there would be no amounts credited to additional paid in capital for tax benefits associated with deductions for income tax purposes related to stock options and convertible debt.
Accumulated Undistributed Earnings of Foreign Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| All Other Stock |
| All Other Option |
| Exercise or |
|
| Grant Date | |
|
|
|
|
| Awards: Number |
| Awards: Number |
| Base Price |
|
| Fair Value of | |
|
|
|
|
| of Shares of |
| of Securities |
| Of Option |
|
| Stock Based | |
|
| Grant |
|
| Stock or Units |
| Underlying Options |
| Awards |
|
| Awards | |
Name |
| Date |
|
| (#) |
| (#) |
| ($/Sh) |
|
| ($) | |
James A. Edmiston |
| 7/22/2015 |
|
|
|
| 269,000 |
| $ | 1.13 |
| $ | 204,440 |
|
| 12/9/2015 |
|
|
|
| 1,000,000 |
|
| 1.13 |
|
| 350,000 |
|
| 12/9/2015 |
|
| 500,000 |
|
|
|
|
|
|
| 285,000 |
Stephen Haynes |
| 7/22/2015 |
|
|
|
| 90,000 |
| $ | 1.13 |
| $ | 68,400 |
|
| 12/9/2015 |
|
|
|
| 358,099 |
|
| 1.13 |
|
| 125,335 |
|
| 12/9/2015 |
|
| 167,000 |
|
|
|
|
|
|
| 95,190 |
Robert Speirs |
| 7/22/2015 |
|
|
|
| 106,000 |
| $ | 1.13 |
| $ | 80,560 |
|
| 12/9/2015 |
|
|
|
| 421,879 |
|
| 1.13 |
|
| 147,658 |
|
| 12/9/2015 |
|
| 197,000 |
|
|
|
|
|
|
| 112,290 |
Karl Nesselrode |
| 7/22/2015 |
|
|
|
| 83,000 |
| $ | 1.13 |
| $ | 63,080 |
|
| 12/9/2015 |
|
|
|
| 329,531 |
|
| 1.13 |
|
| 115,336 |
|
| 12/9/2015 |
|
| 154,000 |
|
|
|
|
|
|
| 87,780 |
Keith L. Head |
| 7/22/2015 |
|
|
|
| 81,000 |
| $ | 1.13 |
| $ | 61,560 |
|
| 12/9/2015 |
|
|
|
| 322,887 |
|
| 1.13 |
|
| 113,010 |
|
| 12/9/2015 |
|
| 151,000 |
|
|
|
|
|
|
| 86,070 |
Notes:
1) | Options granted July 22, 2015 vest 1/3 each year over a three year period. |
2) | Options granted December 9, 2015 vest 1/3 on July 22, 2016, 1/3 on July 22, 2017 and 1/3 on July 22, 2018 |
3) | Harvest granted options representing 4,375,201 shares to employees in 2015. |
4) | All employee grants awarded in 2015 are subject to an additional vesting condition of a 30-day volume weighted average closing price of $2.50/share (VWAP condition). The shares do not vest unless VWAP condition is met. |
Under ASC 740-30-25-17, no deferred tax liability must be recorded if sufficient evidence shows that a foreign subsidiary has invested or will invest its undistributed earnings or that the earnings will be remitted in a tax-free manner. Management must consider numerous factors in determining timing and amounts of possible future distribution of these earnings to the parent company and whether a U.S. deferred tax liability should be recorded for these earnings. These factors include the future operating and capital requirements of both the parent company and the subsidiaries, remittance restrictions imposed by foreign governments or financial
S-40
- 16 -
agreements and tax consequences of the remittance, including possible application of U.S. foreign tax credits and limitations on foreign tax credits that may be imposed by the Internal Revenue Code and regulations.Outstanding Equity Awards at Fiscal Year End
Prior to 2013, no U.S. taxes had been recorded on these earnings
The following table shows information concerning outstanding equity awards as it was our practice and intention to reinvest the earnings of our non-U.S. subsidiaries into our foreign operations. During the fourth quarter of 2013, management evaluated numerous factors related to the timing and amounts of possible future distribution of foreign earnings to the parent company, with consideration of the sale of non-U.S. assets. Because management was pursuing various alternatives with respect to the Company’s future operations and disposition of any sale proceeds, a determination was made that it was appropriate to record a deferred tax liability associated with the unremitted earnings of our foreign subsidiaries of $89.9 million in the fourth quarter of 2013. However, due primarily to the $355.7 million pre-tax impairment of Petrodelta, this balance decreased by $75.2 million to $14.7 million at December 31, 2014.
As of December 31, 2015 held by the book-tax outside basis difference in our foreign subsidiary resulting from unremitted earnings was reduced to zero due to a pre-tax impairment of the Company’s remaining investment in Petrodelta of $164.7 million. Consequently, the deferred tax liability associated with the foreign earnings was reduced to zero. The entire net deferred tax liability as of December 31, 2014 has been reflected as a long-term liability, a characterization consistent with the Company’s adoption of Accounting Standards Update (“ASU”) No. 2015-17.
Accounting for Uncertainty in Income Taxes
The FASB issued ASC 740-10 (prior authoritative literature: Financial Interpretation No. (“FIN”) 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109 (“FIN 48”) to create a single model to address accounting for uncertainty in tax positions. ASC 740-10 clarifies the accounting for income taxes, by prescribing a minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. ASC 740-10 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods and disclosure.
We or one of our subsidiaries file income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions. With few exceptions, we are no longer subject to tax examinations by tax authorities for years before 2010. Our primary income tax jurisdictions and their respective open audit years are:
named executive officers.
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| Option Awards |
| Stock Awards | ||||||||||||||||
|
|
|
| Equity Incentive |
|
|
|
|
|
|
|
| Market |
| Equity Incentive |
| Equity Incentive | |||
|
|
|
| Plan Number |
|
|
|
|
|
| Number of |
| Value of |
| Plan Awards: |
| Plan Awards: | |||
|
|
|
| of Securities |
|
|
|
|
|
| Shares or |
| Shares or |
| Number of |
| Market or Payout | |||
|
| Number of Securities |
| Underlying |
|
|
|
|
|
| Units of |
| Units of |
| Unearned |
| Value of Unearned | |||
|
| Underlying Unexercised |
| Unexercised |
| Option |
|
|
| Stock |
| Stock That |
| Shares, Units or |
| Shares, Units or | ||||
|
| Options |
| Unearned |
| Exercise |
| Option |
| That Have |
| Have Not |
| Other Rights That |
| Other Rights That | ||||
|
| (#) |
| Options |
| Price |
| Expiration |
| Not Vested |
| Vested (1) |
| Have Not Vested |
| Have Not Vested | ||||
Name |
| Exercisable |
| Unexercisable |
| (#) |
| ($) |
| Date |
| (#) |
| ($) |
| (#) |
| ($) | ||
James A. Edmiston |
| 17,000 |
| — |
|
|
| $ | 9.605 |
| 3/2/2016 |
|
|
|
|
|
|
|
|
|
|
| 24,334 |
| — |
|
|
| $ | 9.605 |
| 3/2/2016 |
|
|
|
|
|
|
|
|
|
|
| 65,000 |
| — |
|
|
| $ | 4.595 |
| 6/18/2016 |
|
|
|
|
|
|
|
|
|
|
| 114,200 |
| — |
|
|
| $ | 11.190 |
| 5/20/2016 |
|
|
|
|
|
|
|
|
|
|
| 130,000 |
| — |
|
|
| $ | 5.120 |
| 5/17/2017 |
|
|
|
|
|
|
|
|
|
|
| 248,667 |
| 124,333 |
|
|
| $ | 4.800 |
| 7/17/2018 |
| 24,000 |
| 10,320 |
|
|
|
|
|
|
| 86,333 |
| 172,667 |
|
|
| $ | 4.760 |
| 5/21/2019 |
|
|
|
|
|
|
|
|
|
|
|
|
| 1,269,000 |
|
|
| $ | 1.130 |
| 7/22/2020 |
| 500,000 |
| 215,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stephen Haynes |
| 12,000 |
| — |
|
|
| $ | 4.595 |
| 6/18/2016 |
|
|
|
|
|
|
|
|
|
|
| 51,100 |
| — |
|
|
| $ | 11.190 |
| 5/20/2016 |
|
|
|
|
|
|
|
|
|
|
| 37,000 |
| — |
|
|
| $ | 5.120 |
| 5/17/2017 |
|
|
|
|
|
|
|
|
|
|
| 71,333 |
| 35,667 |
|
|
| $ | 4.800 |
| 7/17/2018 |
| 7,000 |
| 3,010 |
|
|
|
|
|
|
| 28,000 |
| 56,000 |
|
|
| $ | 4.760 |
| 5/21/2019 |
|
|
|
|
|
|
|
|
|
|
|
|
| 448,099 |
|
|
| $ | 1.130 |
| 7/22/2020 |
| 167,000 |
| 71,810 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert Speirs |
| 80,000 |
| — |
|
|
| $ | 13.690 |
| 6/1/2016 |
|
|
|
|
|
|
|
|
|
|
| 12,500 |
| — |
|
|
| $ | 4.595 |
| 6/18/2016 |
|
|
|
|
|
|
|
|
|
|
| 66,300 |
| — |
|
|
| $ | 11.190 |
| 5/20/2016 |
|
|
|
|
|
|
|
|
|
|
| 43,000 |
| — |
|
|
| $ | 5.120 |
| 5/17/2017 |
|
|
|
|
|
|
|
|
|
|
| 84,000 |
| 42,000 |
|
|
| $ | 4.800 |
| 7/17/2018 |
| 8,000 |
| 3,440 |
|
|
|
|
|
|
| 33,000 |
| 66,000 |
|
|
| $ | 4.760 |
| 5/21/2019 |
|
|
|
|
|
|
|
|
|
|
|
|
| 527,879 |
|
|
| $ | 1.130 |
| 7/22/2020 |
| 197,000 |
| 84,710 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Karl Nesselrode |
| 13,334 |
| — |
|
|
| $ | 9.605 |
| 3/2/2016 |
|
|
|
|
|
|
|
|
|
|
| 47,400 |
| — |
|
|
| $ | 11.190 |
| 5/20/2016 |
|
|
|
|
|
|
|
|
|
|
| 34,000 |
| — |
|
|
| $ | 5.120 |
| 5/17/2017 |
|
|
|
|
|
|
|
|
|
|
| 65,333 |
| 32,667 |
|
|
| $ | 4.800 |
| 7/17/2018 |
| 7,000 |
| 3,010 |
|
|
|
|
|
|
| 25,667 |
| 51,333 |
|
|
| $ | 4.760 |
| 5/21/2019 |
|
|
|
|
|
|
|
|
|
|
|
|
| 412,531 |
|
|
| $ | 1.130 |
| 7/22/2020 |
| 154,000 |
| 66,220 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Keith L. Head |
| 30,500 |
| — |
|
|
| $ | 11.190 |
| 5/20/2016 |
|
|
|
|
|
|
|
|
|
|
| 34,000 |
| — |
|
|
| $ | 5.120 |
| 5/17/2017 |
|
|
|
|
|
|
|
|
|
|
| 64,000 |
| 32,000 |
|
|
| $ | 4.800 |
| 7/17/2018 |
| 7,000 |
| 3,010 |
|
|
|
|
|
|
| 25,333 |
| 50,667 |
|
|
| $ | 4.760 |
| 5/21/2019 |
|
|
|
|
|
|
|
|
|
|
|
|
| 403,887 |
|
|
| $ | 1.130 |
| 7/22/2020 |
| 151,000 |
| 64,930 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) The market value of shares is $0.43 per share, based upon the closing price of HNR stock on the NYSE on December 31, 2015. |
In January 2014, the U.S. IRS began an audit of our U.S. tax returns for 2011 and 2012. The audit was concluded in October 2014 with an increase in tax of $0.01 million. The Company has recently received notice from the U.S. IRS that it intends to audit the Company’s 2013 and 2014 tax years. The audit is expected to commence in April 2016.
The changes in our reserve for unrecognized tax benefits follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, | ||||
|
| 2015 |
| 2014 | ||
|
|
|
|
|
|
|
|
| (in thousands) | ||||
Balance at beginning of year |
| $ | 288 |
| $ | 318 |
Additions for tax positions of prior years |
|
| — |
|
| — |
Reductions for tax positions of prior years |
|
| (168) |
|
| (30) |
Balance at end of year |
| $ | 120 |
| $ | 288 |
|
|
|
|
|
|
|
The release of the reserve for uncertain tax positions of $0.03 million during the year ended December 31, 2014 was primarily related to the resolution of a Dutch tax matter regarding treatment of certain costs charged to our Dutch affiliate. However, this amount was offset by an adjustment to the valuation allowance resulting in a nil net tax. In 2015, the reserve was adjusted for a law change re-opening a prior closed year ($0.1 million) offset by a benefit ($0.3 million) from the expiration of the period of assessment on a tax related interest issue. The benefit was included as a reduction of interest expense in our consolidated results of operations and comprehensive income for the year ended December 31, 2015. We believe that it is likely that remaining amount for the uncertain tax position will be resolved within the next twelve months, and the amount of unrecognized tax benefits will significantly decrease.
Note 15 – Stock-Based Compensation and Stock Purchase Plans
Total share-based compensation expense, which includes stock options, restricted stock, SARs, and RSUs, totaled $2.0 million for the year ended December 31, 2015 ($1.6 million and $2.3 million for the years ended December 31, 2014 and 2013, respectively). All awards utilize the straight line method of amortization over the vesting period. The following table is a summary of
S-41
- 17 -
compensation expense (income) recorded in generalOptions Exercised and administrative expense in our consolidated statements of operations and comprehensive loss by type of awards:Stock Vested
No options were exercised and no restricted stock vested in 2015.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| As of December 31, | |||||||
Employee Stock-Based Compensation |
| 2015 |
| 2014 |
| 2013 | |||
|
|
|
|
|
|
|
|
|
|
|
| (in thousands) | |||||||
Equity based awards: |
|
|
|
|
|
|
|
|
|
Stock options |
| $ | 2,003 |
| $ | 2,073 |
| $ | 2,119 |
Restricted stock |
|
| 135 |
|
| 579 |
|
| 927 |
RSUs |
|
| 133 |
|
| — |
|
| — |
Total expense related to equity based awards |
|
| 2,271 |
|
| 2,652 |
|
| 3,046 |
|
|
|
|
|
|
|
|
|
|
Liability based awards: |
|
|
|
|
|
|
|
|
|
SARs |
|
| (260) |
|
| (1,237) |
|
| (247) |
RSUs |
|
| 12 |
|
| 197 |
|
| (534) |
Total expense related to liability based awards |
|
| (248) |
|
| (1,040) |
|
| (781) |
Total compensation expense |
| $ | 2,023 |
| $ | 1,612 |
| $ | 2,265 |
- 18 -
Long Term Incentive Plans
AsPotential Payments under Termination or Change of Control
The tables below reflect the additional compensation to the named executive officers of the Company under the terms of their Executive Employment Agreements in the event of termination without cause or without proper notice, termination following change of control, or termination for disability or death. (See Compensation Discussion and Analysis — Employment Agreements and Change of Control above for a description of the terms of the Executive Employment Agreements.) The amounts shown in the tables assume that such termination was effective as of December 31, 2015, and thus include estimated amounts earned through that date that would be paid out to the named executive officers. The actual amounts can only be determined at the time of separation from the Company. Accelerated vesting of stock awards is based on a December 31, 2015 Harvest closing stock price of $0.43.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Voluntary Termination on |
| Termination for Good Reason or Involuntary Termination without Cause or Notice on |
| Termination due to Change in Control on |
| For Cause Termination on |
| Death on |
| Disability on | ||||||
Executive Compensation and Benefits-James Edmiston |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 | ||||||
Compensation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Base Salary |
| $ | — |
| $ | 1,764,000 |
| $ | 1,764,000 |
| $ | - |
| $ | 1,764,000 |
| $ | 1,764,000 |
Short-term Incentive |
|
| — |
|
| - |
|
| 1,764,000 |
|
| - |
|
| - |
|
| - |
Long-term Incentives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options/SARs (Intrinsic Value) |
|
| — |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Restricted Shares/RSUs |
|
| — |
|
| 312,610 |
|
| 312,610 |
|
| - |
|
| 312,610 |
|
| 312,610 |
Benefits and Perquisites: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outplacement |
|
| — |
|
| 20,000 |
|
| 20,000 |
|
| - |
|
| - |
|
| - |
Life Insurance Proceeds |
|
| — |
|
| - |
|
| - |
|
| - |
|
| 300,000 |
|
| - |
Excise Tax Gross Up |
|
| — |
|
| - |
|
| 1,343,847 |
|
| - |
|
| - |
|
| - |
Disability Benefits per year * |
|
| — |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 120,000 |
Medical, Dental, Life, Disability and Accident Insurance |
|
| — |
|
| - |
|
| 107,587 |
|
| - |
|
| - |
|
| - |
401(k) employer match |
|
| — |
|
| 31,800 |
|
| 31,800 |
|
| - |
|
| 31,800 |
|
| 31,800 |
Total |
| $ | — |
| $ | 2,128,410 |
| $ | 5,343,844 |
| $ | — |
| $ | 2,408,410 |
| $ | 2,228,410 |
* until no longer disabled or Social Security Retirement Age
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Voluntary Termination on |
| Termination for Good Reason or Involuntary Termination without Cause or Notice on |
| Termination due to Change in Control on |
| For Cause Termination on |
| Death on |
| Disability on | ||||||
Executive Compensation and Benefits-Stephen Haynes |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 | ||||||
Compensation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Base Salary |
| $ | — |
| $ | 628,000 |
| $ | 628,000 |
| $ | - |
| $ | 628,000 |
| $ | 628,000 |
Short-term Incentive |
|
| — |
|
| - |
|
| 376,800 |
|
| - |
|
| - |
|
| - |
Long-term Incentives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options/SARs (Intrinsic Value) |
|
| — |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Restricted Shares/RSUs |
|
| — |
|
| 103,200 |
|
| 103,200 |
|
| - |
|
| 103,200 |
|
| 103,200 |
Benefits and Perquisites: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outplacement |
|
| — |
|
| 20,000 |
|
| 20,000 |
|
| - |
|
| - |
|
| - |
Life Insurance Proceeds |
|
| — |
|
| - |
|
| - |
|
| - |
|
| 300,000 |
|
| - |
Excise Tax Gross Up |
|
| — |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Disability Benefits per year * |
|
| — |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 120,000 |
Medical, Dental, Life, Disability and Accident Insurance |
|
| — |
|
| - |
|
| 49,834 |
|
| - |
|
| - |
|
| - |
401(k) employer match |
|
| — |
|
| 21,200 |
|
| 21,200 |
|
| - |
|
| 21,200 |
|
| 21,200 |
Total |
| $ | — |
| $ | 772,400 |
| $ | 1,199,034 |
| $ | — |
| $ | 1,052,400 |
| $ | 872,400 |
* until no longer disabled or Social Security Retirement Age
- 19 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Voluntary Termination on |
| Termination for Good Reason or Involuntary Termination without Cause or Notice on |
| Termination due to Change in Control on |
| For Cause Termination on |
| Death on |
| Disability on | ||||||
Executive Compensation and Benefits-Robert Speirs |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 | ||||||
Compensation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Base Salary |
| $ | — |
| $ | 740,000 |
| $ | 740,000 |
| $ | — |
| $ | 740,000 |
| $ | 740,000 |
Short-term Incentive |
|
| — |
|
| - |
|
| 444,000 |
|
| — |
|
| - |
|
| - |
Long-term Incentives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options/SARs (Intrinsic Value) |
|
| — |
|
| - |
|
| - |
|
| — |
|
| - |
|
| - |
Restricted Shares/RSUs |
|
| — |
|
| 121,690 |
|
| 121,690 |
|
| — |
|
| 121,690 |
|
| 121,690 |
Benefits and Perquisites: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outplacement |
|
| — |
|
| 20,000 |
|
| 20,000 |
|
| — |
|
| - |
|
| - |
Life Insurance Proceeds |
|
| — |
|
| — |
|
| - |
|
| — |
|
| 300,000 |
|
| - |
Excise Tax Gross Up |
|
| — |
|
| — |
|
| - |
|
| — |
|
| - |
|
| - |
Disability Benefits per year * |
|
| — |
|
| — |
|
| - |
|
| — |
|
| - |
|
| 120,000 |
Medical, Dental, Life, Disability and Accident Insurance |
|
| — |
|
| — |
|
| 64,046 |
|
| — |
|
| - |
|
| - |
401(k) employer match |
|
| — |
|
| — |
|
| — |
|
| — |
|
| - |
|
| - |
Total |
| $ | — |
| $ | 881,690 |
| $ | 1,389,736 |
| $ | — |
| $ | 1,161,690 |
| $ | 981,690 |
* until no longer disabled or Social Security Retirement Age
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Voluntary Termination on |
| Termination for Good Reason or Involuntary Termination without Cause or Notice on |
| Termination due to Change in Control on |
| For Cause Termination on |
| Death on |
| Disability on | ||||||
Executive Compensation and Benefits-Karl Nesselrode |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 | ||||||
Compensation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Base Salary |
| $ | — |
| $ | 578,000 |
| $ | 578,000 |
| $ | — |
| $ | 578,000 |
| $ | 578,000 |
Short-term Incentive |
|
| — |
|
| - |
|
| 346,800 |
|
| — |
|
| - |
|
| - |
Long-term Incentives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options/SARs (Intrinsic Value) |
|
| — |
|
| - |
|
| - |
|
| — |
|
| - |
|
| - |
Restricted Shares/RSUs |
|
| — |
|
| 95,460 |
|
| 95,460 |
|
| — |
|
| 95,460 |
|
| 95,460 |
Benefits and Perquisites: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outplacement |
|
| — |
|
| 20,000 |
|
| 20,000 |
|
| — |
|
| - |
|
| - |
Life Insurance Proceeds |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 300,000 |
|
| — |
Excise Tax Gross Up |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
Disability Benefits per year * |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 120,000 |
Medical, Dental, Life, Disability and Accident Insurance |
|
| — |
|
| — |
|
| 43,690 |
|
| — |
|
| — |
|
| — |
401(k) employer match |
|
| — |
|
| 21,200 |
|
| 21,200 |
|
| — |
|
| 21,200 |
|
| 21,200 |
Total |
| $ | — |
| $ | 714,660 |
| $ | 1,105,150 |
| $ | — |
| $ | 994,660 |
| $ | 814,660 |
* until no longer disabled or Social Security Retirement Age
- 20 -
|
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|
| Voluntary Termination on |
| Termination for Good Reason or Involuntary Termination without Cause or Notice on |
| Termination due to Change in Control on |
| For Cause Termination on |
| Death on |
| Disability on | ||||||
Executive Compensation and Benefits-Keith Head |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 |
| 12/31/2015 | ||||||
Compensation: |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Base Salary |
| $ | — |
| $ | 566,000 |
| $ | 566,000 |
| $ | — |
| $ | 566,000 |
| $ | 566,000 |
Short-term Incentive |
|
| — |
|
| - |
|
| 339,600 |
|
| — |
|
| - |
|
| - |
Long-term Incentives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options/SARs (Intrinsic Value) |
|
| — |
|
| - |
|
| - |
|
| — |
|
| - |
|
| - |
Restricted Shares/RSUs |
|
| — |
|
| 93,740 |
|
| 93,740 |
| �� | — |
|
| 93,740 |
|
| 93,740 |
Benefits and Perquisites: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outplacement |
|
| — |
|
| 20,000 |
|
| 20,000 |
|
| — |
|
| - |
| — | - |
Life Insurance Proceeds |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 300,000 |
|
| — |
Excise Tax Gross Up |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
Disability Benefits per year * |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 120,000 |
Medical, Dental, Life, Disability and Accident Insurance |
|
| — |
|
| — |
|
| 43,690 |
|
| — |
|
| — |
|
| — |
401(k) employer match |
|
| — |
|
| 21,200 |
|
| 21,200 |
|
| — |
|
| 21,200 |
|
| 21,200 |
Total |
| $ | — |
| $ | 700,940 |
| $ | 1,084,230 |
| $ | — |
| $ | 980,940 |
| $ | 800,940 |
* until no longer disabled or Social Security Retirement Age
- 21 -
Our philosophy in determining director compensation is to align compensation with the long-term interests of the stockholders, adequately compensate the directors for their time and effort and establish an overall compensation package that will attract and retain qualified directors. In determining overall director compensation, we had several long term incentive plans under whichseek to strike the right balance between the cash and stock options,components of director compensation. The Board’s policy is that the directors should hold equity ownership in the Company and that a portion of the director fees should consist of Company equity in the form of restricted stock SARs and RSUs can bestock grants. The Board also believes that directors should develop a meaningful equity position over time and has adopted stock retention guidelines applicable to all directors. These guidelines state directors must retain (i) at least 50 percent of the shares of restricted stock granted to eligible participants including employees,them for at least three years after the restriction lapses and (ii) at least 50 percent of the net shares of stock received through the exercise of an option or stock appreciation right must be retained by a director for at least three years after the exercise date.
Our retainer and meeting fee schedule has remained the same since June 2014. Each non-employee directors and consultantsdirector of ourthe Company or subsidiaries:received cash compensation as follows:
· |
|
· |
|
· |
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|
|
Stock OptionsOur director compensation includes additional compensation for the non-executive Chairman of the Board in recognition of the significant added responsibilities and time commitments of that position. In addition to his compensation as a director, he receives a retainer of $120,000 a year; this 2015 retainer remained the same as the retainer in 2014, 2013, 2012 and 2011.
StockUnder the Harvest Natural Resources 2010 Long Term Incentive Plan, directors are eligible to receive restricted stock, restricted stock units (RSU), stock options granted underand stock appreciation rights (SAR) grants. In September 2015, the plans must be no less thanBoard approved a restricted stock unit award valued at $80,001 for each director.
The following table sets forth the fair market valuecash and other compensation earned by the non-employee members of our common stockBoard of Directors in 2015.
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| Fees |
| Stock |
|
|
| |||
|
| Earned |
| or Stock |
|
|
| |||
|
| or Paid in |
| Unit |
|
|
| |||
Name |
| Cash ($) |
| Awards ($) |
| Total ($) | ||||
Stephen D. Chesebro' |
| $ | 210,000 |
|
| $ | 80,001 |
| $ | 290,001 |
Oswaldo Cisneros |
|
| 80,000 |
|
|
| 80,001 |
|
| 160,001 |
Francisco D'Agostino |
|
| 80,000 |
|
|
| 80,001 |
|
| 160,001 |
R. E. Irelan |
|
| 95,000 |
|
|
| 80,001 |
|
| 175,001 |
Edgard Leal |
|
| 80,000 |
|
|
| 80,001 |
|
| 160,001 |
Patrick M. Murray |
|
| 100,000�� |
|
|
| 80,001 |
|
| 180,001 |
Note: Restricted share units (RSUs) were issued on September 9, 2015 at a price of $1.50 per share with a vesting of one year from grant date.
HUMAN RESOURCES COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
From January 1, 2015 until June 19, 2015, our Human Resources committee consisted of R. E. Irelan as Chairman, Igor Effimoff and J. Michael Stinson. On June 19, 2015, in connection with a financing involving CT Energy Holding SRL, the Company’s Board of Directors accepted the resignations of Dr. Effimoff, Mr. Hardee and Mr. Stinson and appointed Mr. Oswaldo Cisneros, Mr. Francisco D’Agostino and Mr. Edgard Leal, as Board members, effective the same date. The Human Resources committee of the Board is currently comprised of Mr. Irelan as Chairman, Mr. Leal and Mr. Patrick M. Murray. None of the members of the Board’s Human Resources Committee is or has been an officer or employee of the Company or has a relationship requiring disclosure under Item 404(a) of SEC Regulation S-K. No executive officer of the Company serves on the datecompensation committee or serves as a director of grant. Stock options granted under the plans generally vest ratably over a three year period beginning from the dateanother entity where an executive officer of grant. Stock options granted under the plans expire five to ten years from the date of grant.
Prior to 2015, the fair value of each stock option award was estimatedthat entity also serves on the date of grant usingHuman Resources Committee or on the Black-Scholes option-pricing model which uses assumptions for the risk-free interest rate, volatility, dividend yield and the expected term of the options.Board.
S-42
- 22 -
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
STOCK OWNERSHIP
Directors and Named Executive Officers
The risk-free interest ratefollowing table shows the amount of our common stock beneficially owned (unless otherwise indicated) by our directors, each named executive officer and our directors and named executive officers as a group. Except as otherwise indicated, all information is based on the U.S. Treasury yield curve in effect at the timeas of grant for a period equal to the expected termMarch 31, 2016.
The number of shares of our common stock beneficially owned by each director or named executive officer is determined under rules of the option. Expected volatilitySEC, and the information is based on historical volatilitiesnot necessarily indicative of our stock. We do not assumebeneficial ownership for any dividend yield since we do not pay dividends. The expected term of options granted isother purpose. Under such rules, beneficial ownership includes any shares as to which the weighted average lifeindividual has the sole or shared voting power or investment power and also any shares which the individual has the right to acquire within 60 days after March 31, 2016 through the exercise of stock options or other rights. Unless otherwise indicated, each person has sole investment and represents the period of time that options are expected to be outstanding.
In 2015, the fair value of each stock option was estimated on the date of grant using a Monte Carlo simulation since the options were also subject to a market condition. These options will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share (“VWAP condition”) in additionvoting power (or shares such powers with his spouse) with respect to the ratable vesting over a three year period. The Monte Carlo simulation includes this VWAP condition and uses assumptions forshares set forth in the risk-free interest rate, volatility, and dividend yield while a suboptimal exercise factor determines the expected term of the options. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the option. Expected volatility is based on historical volatilities of our stock. We do not assume any dividend yield since we do not pay dividends. The expected term of options granted represents the period of time that options are expected to be outstanding. The Monte Carlo simulation assumed a suboptimal exercise factor of 2.5 meaning that exercise is generally expected to occur when the share price reaches 2.5 times the award’s exercise price.following table.
December 31, 2015, we awarded stock options vesting over three years to purchase 847,000 of our common shares to our employees and executive officers (683,000 and 920,004 stock options were granted during the years ended December 31, 2014 and 2013, respectively).
On December 9, 2015, we additionally issued 3,528,201 options with a life of 4.6 years and an exercise price of $1.13 subject to the VWAP condition. These options vest one-third on July 22, 2016, one-third on July 22, 2017 and one-third on July 22, 2018 with an expiry date of July 22, 2020. These options were issued as replacement awards for the equivalent number of SARs issued on July 22, 2015. The options were issued with the equivalent terms, exercise price, and VWAP conditions as the SARs.
We also consider an estimated forfeiture rate for all stock option awards, and we recognize compensation cost only for those shares that are expected to vest, on a straight-line basis over the requisite service period of the award, which is generally the vesting term of three years. The forfeiture rate is based on historical experience.
|
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|
Options |
|
| Outstanding |
| Weighted- Average Exercise Price |
|
| Weighted- Average Remaining Contractual Term |
| Aggregate Intrinsic Value | ||
|
|
| (in thousands) |
|
|
|
|
|
|
|
|
|
Options outstanding as of December 31, 2014 |
|
| 4,536 |
| $ | 7.81 |
|
| 2.0 |
| $ | — |
Granted |
|
| 4,375 |
|
| 1.13 | (1) |
|
|
|
| — |
Exercised |
|
| — |
|
| — |
|
|
|
|
|
|
Cancelled |
|
| (1,769) |
|
| (9.85) |
|
|
|
|
|
|
Options outstanding as of December 31, 2015 |
|
| 7,142 |
|
| 3.21 |
|
| 3.5 |
|
| — |
Options exercisable as of December 31, 2015 |
|
| 2,011 |
| $ | 7.16 |
|
| 1.5 |
|
| — |
|
|
|
|
|
|
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|
|
|
|
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|
|
|
|
| Amount and Nature of | |||||||
|
| Beneficial Ownership | |||||||
|
| Number of |
| Shares |
|
|
| Percent of | |
|
| Shares |
| Acquirable |
| Total |
| Shares | |
|
| Beneficially |
| Within 60 |
| Beneficial |
| Outstanding | |
Name of Beneficial Owner |
| Owned (1) |
| Days |
| Ownership |
| (2)(3) | |
James A. Edmiston |
| 367,766 |
| 730,532 |
| 1,098,298 |
| 2.11% |
|
Stephen C. Haynes |
| 40,404 |
| 227,433 |
| 267,837 |
| 0.52% | * |
Keith L. Head |
| 34,008 |
| 179,166 |
| 213,174 |
| 0.41% | * |
Karl L. Nesselrode |
| 66,168 |
| 198,066 |
| 264,234 |
| 0.51% | * |
Robert Speirs |
| 225,483 |
| 351,800 |
| 577,283 |
| 1.12% |
|
Stephen D. Chesebro’ |
| 449,521 |
| 5,000 |
| 454,521 |
| 0.88% | * |
Oswaldo Cisneros(4) |
| 8,667,597 |
| — |
| 8,667,597 |
| 16.86% |
|
Francisco D'Agostino |
| — |
| — |
| — |
| 0.00% | * |
Robert E. Irelan |
| 72,667 |
| — |
| 72,667 |
| 0.14% | * |
Edgard Leal |
| — |
| — |
| — |
| 0.00% | * |
Patrick M. Murray |
| 237,521 |
| 5,000 |
| 242,521 |
| 0.47% | * |
All current directors and executive officers as a group of eleven persons |
| 10,161,135 |
| 1,696,997 |
| 11,858,132 |
| 22.33% |
|
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|
|
* Represents less than one percent of our outstanding common stock. |
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|
|
(1) This number does not include common stock that our directors or officers have a right to acquire within 60 days of March 31, 2016. | |||||||||
(2) Percentages are based upon 51,415,164 shares of common stock outstanding on March 31, 2016. | |||||||||
(3) Percentages have been calculated assuming that the vested options have been exercised by the individual for which the percent is being calculated. | |||||||||
(4) Inclusive of holdings of CT Energy Holding SRL. | |||||||||
|
|
|
|
|
|
|
|
|
|
Of the options outstanding, 2.0 million were exercisable at a weighted-average exercise price of $7.16 as of December 31, 2015 (2.7 million at $8.85 at December 31, 2014; 2.9 million at $9.85 at December 31, 2013).
S-43
- 23 -
In 2014 and 2013,
Certain Beneficial Owners
The following table shows the valuebeneficial owners of eachmore than five percent of the Company’s common stock option grant is estimatedas of March 31, 2016 based on the dateinformation available as of grant using the Black-Scholes option pricing model. In 2015, the value of each stock option grant is estimated on the date of grant using a Monte Carlo simulation. Each have the following weighted average assumptions:that date:
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|
|
| As of December 31, |
| |||||||
For options granted during: |
| 2015 |
| 2014 |
| 2013 |
| |||
|
|
|
|
|
|
|
|
|
|
|
Weighted average fair value |
| $ | 0.43 |
| $ | 2.97 |
| $ | 3.06 |
|
Weighted average expected life |
|
| 4.7 years |
|
| 5 years |
|
| 5 years |
|
Expected volatility (1) |
|
| 100 | % |
| 76.7 | % |
| 79.4 | % |
Risk-free interest rate |
|
| 1.7 | % |
| 1.5 | % |
| 1.3 | % |
Suboptimal exercise factor (2) |
|
| 2.5 |
|
| — |
|
| — |
|
Weighted average pre-vest forfeiture rate |
|
| 1.1 | % |
| 1.0 | % |
| 1.2 | % |
Dividend yield |
|
| 0.0 | % |
| 0.0 | % |
| 0.0 | % |
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|
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| Aggregate |
|
|
|
|
|
|
|
| |
|
| Number |
|
|
|
|
|
|
|
| |
|
| of Shares |
| Percent of |
|
|
|
|
| ||
|
| Beneficially |
| Shares |
| Report |
|
|
| ||
Name & Address |
| Owned (1) |
| Outstanding (2) |
| Date |
| Source | |||
CT Energy Holding SRL |
|
|
|
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|
|
|
Av. Principal La Castellana, |
|
|
|
|
|
|
|
|
|
|
|
Torre Digitel, Pisa 22 |
| 8,667,597 |
|
| 16.86% |
|
| 3/10/2016 |
| Sch.13D/A |
|
Caracas, Venezuela |
|
|
|
|
|
|
|
|
|
|
|
Caisse de dépôt et placement du Québec |
|
|
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|
|
1000 place Jean-Paul Riopelle |
|
|
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|
|
Montreal (Quebec), H2Z 2B3 |
| 3,238,100 |
|
| 6.30% |
|
| 2/12/2016 |
| Sch.13G/A |
|
|
|
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|
|
|
|
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|
|
|
(1) The stockholder has sole voting and dispositive power over the shares indicated unless otherwise disclosed. | |||||||||||
(2) The Company’s outstanding common shares as of March 31, 2016 were 51,415,164. | |||||||||||
| |||||||||||
| |||||||||||
| |||||||||||
| |||||||||||
|
.EQUITY COMPENSATION PLAN INFORMATION
|
|
|
|
A summary ofInformation concerning our unvested stock option awardsequity compensation plans as of December 31, 2015 is included in our Form 10-K filed March 29, 2016, Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 15 – Stock-Based Compensation and the changes during the year then endedStock Purchase Plans,which disclosure is presented below:incorporated by reference herein.
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|
|
Unvested Stock Options |
|
| Outstanding |
|
| Weighted- Average Grant-Date Fair Value |
|
|
| (in thousands) |
|
|
|
Unvested as of December 31, 2014 |
|
| 1,876 |
| $ | 3.85 |
Granted |
|
| 4,375 |
|
| 0.43 |
Vested |
|
| (645) |
|
| (2.99) |
Expired |
|
| (475) |
|
| (6.38) |
Unvested as of December 31, 2015 |
|
| 5,131 |
| $ | 0.81 |
The total intrinsic value of stock options exercised during the year ended December 31, 2015 was $0.0 million (2014: $0.0 million; 2013: $0.1 million). The total fair value of stock options that vested during the year ended December 31, 2015, was $1.9 million ($2.4 million and $1.9 million during the years ended December 31, 2014 and 2013, respectively).
As of December 31, 2015, there was $3.0 million of total future compensation cost related to unvested stock option awards that are expected to vest. That cost is expected to be recognized over a weighted average period of 1.86 years.
Restricted Stock
Restricted stock is issued on the grant date, but cannot be sold or transferred. Restricted stock granted to directors vest one year after date of grant. Restricted stock granted to employees vest at the third year after date of grant. Vesting of the restricted stock is dependent upon the employee’s continued service to Harvest.
A summary of our restricted stock awards as of December 31, 2015, and the changes during the year then ended is presented below:
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|
|
Restricted Stock |
|
| Outstanding |
|
| Weighted- Average Grant-Date Fair Value |
|
|
|
|
|
|
|
|
|
| (in thousands) |
|
|
|
Unvested as of December 31, 2014 |
|
| 86 |
| $ | 4.82 |
Granted |
|
| — |
|
| — |
Vested |
|
| (2) |
|
| (5.85) |
Forfeited |
|
| — |
|
| — |
Unvested as of December 31, 2015 |
|
| 84 |
| $ | 4.80 |
S-44
- 24 -
No restricted stock shares were awarded during the years ended December 31, 2015
Item 13. Certain Relationships and 2014. In 2013, we awarded 190,002 sharesRelated Transactions, and Director Independence
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Our Code of Business Conduct and Ethics (the “Code”) applies to all of our directors, officers and employees. The restrictedUnder the Code, individuals subject to the Code and their family members must knowingly avoid owning any interest (other than nominal amounts of stock in publicly-traded companies) in any supplier or customer; consulting with, or being an employee of, any customer, lessor, lessee, contractor, supplier or competitor; purchasing from, or selling to us, assets, goods or services; or serving on the board of directors of any customer, lessor, lessee, contractor, supplier or competitor, except where full disclosure of all facts is made known to us in advance to permit us to protect our interests. Each year we require our executive officers to certify their compliance with the Code. Our Audit Committee has oversight compliance responsibilities for the Code. Exceptions to the Code are reported to the Audit Committee. Waivers of the Code for officers and directors may only be granted by the Board and waivers for employees may only be granted by the CEO and reported to the Audit Committee. No waivers of the Code were granted in 2013 had an aggregate fair value of $0.9 million. The restricted stock is scheduled to vest at the third year after date of grant for employees and vested one year after date of grant for directors. The fair value of the restricted stock that vested during the year ended December 31, 2015 was $11,700 ($1.9 million and $1.2 million during the years ended December 31, 2014 and 2013, respectively). The weighted average grant date fair value of awards granted in 2013 was $4.80.
As of December 31, 2015 there was $0.1 million of total future compensation cost related to unvested restricted stock awards that are expected to vest. That cost is expected to be recognized over a weighted average period of 0.5 years.
Stock Appreciation Rights (“SARs”)
All SAR awards granted to date have been granted outside of active long-term incentive plans and are held by Harvest employees. SARs granted in 2013 and 2015 vest ratably over three years beginning in the first year of grant. Vesting of SARs is dependent upon the employee’s continued service to Harvest. SAR awards are settled either in cash or Harvest common stock if available through an equity compensation plan. For recording of compensation, we assume the SAR award will be cash-settled and record compensation expense based on the fair value of the SAR awards at the end of each period.
The significant assumptions are summarized in the following table that were used to calculate the fair value of the SARs granted on July 22, 2015 and amended December 9, 2015 that were outstanding as of the balance sheet date presented on our consolidated balance sheet:
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| ||||
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| ||||
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| ||||
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| |||||
| ||||||
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| ||||
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| ||||
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|
As these awards are accounted for as liabilities, the fair value of each SAR was estimated at December 31, 2015 using a Monte Carlo simulation since the SARs were also subject to a market condition. These SARs will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share (“VWAP condition”) in2015. In addition to the ratable vesting over a threeCode, each year period. The Monte Carlo simulation includeswe require our directors and executive officers to disclose in writing certain transactions and relationships and this VWAP conditioninformation is used in preparing this report and uses assumptionsthe proxy statement and in making independence determinations for directors.
For the risk-free interest rate, volatility, and dividend yield while a suboptimal exercise factor determines the expected termpurposes of the SARs. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the SAR. Expected volatility is based on historical volatilities of our stock. We do not assume any dividend yield since we do not pay dividends. The expected term of SARs granted represents the period of time that SARs are expected to be outstanding. The Monte Carlo simulation assumed a suboptimal exercise factor of 2.5 meaning that exercise is generally expected to occur when the share price reaches 2.5 times the award’s exercise price. The suboptimal exercise factor was the Level 3 input used for the valuation of the SARs. In general, if the suboptimal exercise factor increases then the fair value of the SAR will increase or vice versa. A change in the Level 3 input has a minimal effect on the valuation of the SARs as the primary driver is our stock price.
S-45
SAR award transactions under our employee compensation plans are presented below:
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SARs |
|
| Outstanding |
| Weighted- Average Exercise Price |
|
| Weighted- Average Remaining Contractual Term |
| Aggregate Intrinsic Value | ||
|
|
| (in thousands) |
|
|
|
|
|
|
|
|
|
SARS outstanding as of December 31, 2014 |
|
| 1,123 |
| $ | 4.95 |
|
| 2.2 |
| $ | — |
Granted |
|
| 5,062 |
|
| 1.13 | (1) |
| 5.0 |
|
| — |
Cancelled |
|
| (3,528) |
|
| (1.13) | (1) |
|
|
|
|
|
Expired |
|
| (86) |
|
| (5.12) |
|
|
|
|
|
|
SARS outstanding as of December 31, 2015 |
|
| 2,571 |
|
| 2.67 |
|
| 3.3 |
|
| — |
SARS exercisable as of December 31, 2015 |
|
| 966 |
| $ | 4.95 |
|
| 1.3 |
|
| — |
|
|
Of the SAR awards outstanding, 1.0 million were exercisable at the weighted-average exercise price of $4.95 as of December 31, 2015, 0.8 million exercisable at the weighted-average exercise price of $4.94 as of December 31, 2014 and 0.4 million were exercisable at the weighted-average exercise price of $4.91 at December 31, 2013.
During the year ended December 31, 2015, there were 5.1 million SAR awards granted (zero and 0.2 million during the years ended December 31, 2014 and 2013, respectively).
On July 22, 2015, we issued 5.1 million SARs at an exercise price of $1.13 per share, vesting ratably over three years from the date of grant and on the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE. The dual vesting requirements necessitated that all of these awards be valued using a Monte Carlo simulation. Sincethis report, the Company had an insufficient numbers of shares available from existing long-term incentive plans, the SARs were classified as liability awards when issued.
On December 9, 2015, our board of directors approved modifications of a portion of the July 22, 2015 awards. Of the 5.1 million SARs issued, 3.5 million were cancelled and replaced with options under the 2010 Plan. All other terms remained the same. The fair value of the vested portion of the cancelled SARs approximated the fair value of the replacement options granted on December 9, 2015. The remaining 1.6 million SARs continue to be classified as liability awards.
A summary of our unvested SAR awards as of December 31, 2015, and the changes during the year then ended is presented below:
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|
|
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|
|
|
|
|
|
|
|
|
Unvested SARs |
|
| Outstanding |
|
| Weighted- Average Fair Value |
|
|
| (in thousands) |
|
|
|
Unvested as of December 31, 2014 |
|
| 339 |
| $ | 0.51 |
Granted |
|
| 5,062 |
|
| 0.32 |
Vested |
|
| (264) |
|
| (0.06) |
Cancelled |
|
| (3,528) |
|
| (0.35) |
Expired |
|
| (4) |
|
| (0.05) |
Unvested as of December 31, 2015 |
|
| 1,605 |
| $ | 0.21 |
No SAR awards were exercised during the years ended December 31, 2015, 2014 and 2013. The total fair value of SAR awards that vested during the year ended December 31, 2015, was $15,960 ($0.2 million and $0.8 million during the years ended December 31, 2014 and 2013, respectively).
Restricted Stock Units (“RSUs”)
RSU awards granted prior to 2015 have been granted outside of active long-term incentive plans, are held by Harvest employees and directors, and are settled either in cash or Harvest common stock if available through an equity compensation plan and are accounted for as liability awards . RSU awards granted in 2012, 2014 and 2015 to employees vest at the third year after date of grant.
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RSU awards granted in 2015 to our board of directors vest one year after the date of grant. Vesting of the RSU awards is dependent upon the employee’s and director’s continued service to Harvest.
On September 9, 2015, we issued 320,004 RSUs vesting one year from the date of grant to our directors. These awards are classified as liability awards. These awards are measured at their fair values based on our closing stock price at December 31, 2015.
The significant assumptions are summarized inhas the following table that were usedtransactions to calculate the fair value of the restricted stock units granted on July 22, 2015 and amended December 9, 2015 that were outstanding as of the balance sheet date presented on our consolidated balance sheet:
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| ||||
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| ||||
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|
|
A summary of our RSU awards as of December 31, 2015, and the changes during the year then ended is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RSUs |
|
| Outstanding |
|
| Weighted- Average Fair Value |
|
|
| (in thousands) |
|
|
|
Unvested as of December 31, 2014 |
|
| 905 |
| $ | 1.81 |
Granted |
|
| 1,891 |
|
| 0.73 |
Vested |
|
| (326) |
|
| (1.50) |
Forfeited |
|
| — |
|
| — |
Unvested as of December 31, 2015 (1) |
|
| 2,470 |
| $ | 0.52 |
|
|
The 326,142 RSU awards vesting in 2015 were settled for cash of $0.5 million. The 103,338 RSU awards which vested in 2014 were settled for cash of $0.5 million (202,668 RSU awards settled for cash of $0.6 million during 2013). The fair value of the RSU awards that vested during the year ended December 31, 2015 was $0.3 million ($0.2 million and $0.8 million during the years ended December 31, 2014 and 2013, respectively).
On July 22, 2015, we issued 1.6 million restricted stock units vesting at three years from the date of grant as stock based compensation awardsdescribe pursuant to certain employees. Subject to the three year vesting requirement, the RSUs awarded will not become exercisable until the first day on which the volume weighted average price of the common stock over any 30-day period, commencing on or after the award date, equals or exceeds $2.50 per share, as reported by the NYSE. The dual vesting requirements necessitated that all of these awards be valued using a Monte Carlo simulation. Since an insufficient numbers of shares were available from existing long-term incentive plans, the RSUs were classified as liability awards at issuance.
On December 9, 2015, our board of directors approved a modification to share-settle the 1.6 million RSUs granted on July 22, 2015. This modification changed the classification of these awards from liability to equity awards. The fair value of the vested portion of the initial RSUs approximated the fair value of the modified RSUs on December 9, 2015. The grant-date fair value of the modified RSUs was $0.57 per RSU.
As of December 31, 2015 there was $1.0 million of total future compensation cost related to unvested RSU awards expected to vest. That cost is expected to be recognized over a weighted average period of 2.2 years.
Common Stock Warrants
In connection with the transaction with CT Energy on June 19, 2015,we issued a warrant exercisable for 34,070,820 shares of the Company’s common stock at an initial exercise price of $1.25 per share with an expiration date of June 19, 2018. The CT Warrant
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may not be exercised until the volume weighted average price of the Company’s common stock over any consecutive 30-day period equals or exceeds $2.50 per share. See Note 1 – Organization and Note 12 – Warrant Derivative Liability.
Note 16 – Operating Segments
We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Operations included under the heading “United States” include corporate management, cash management, business development and financing activities performed in the United States and other countries, which do not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the United States segment and are not allocated to other operating segments. In previous years, charges for intersegment general and administrative and interest expenses were included in results for the respective operating segments, and operating segment assets included intersegment receivables and loans. Segment loss and operating segment assets for prior periods have been adjusted to conform to the current presentation method in which intersegment items are eliminated from each segment’s results and assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, | |||||||
| 2015 |
| 2014 |
| 2013 | |||
|
|
|
|
|
|
|
|
|
| (in thousands) | |||||||
Segment Loss Attributable to Harvest |
|
|
|
|
|
|
|
|
Venezuela |
| (83,953) |
|
| (171,801) |
|
| 58,640 |
Gabon |
| (28,448) |
|
| (55,564) |
|
| (12,908) |
Indonesia |
| (43) |
|
| (9,558) |
|
| (9,213) |
United States and other |
| 13,874 |
|
| 43,987 |
|
| (120,465) |
Loss from continuing operations(a) |
| (98,570) |
|
| (192,936) |
|
| (83,946) |
Discontinued operations |
| — |
|
| (554) |
|
| (5,150) |
Net loss attributable to Harvest | $ | (98,570) |
| $ | (193,490) |
| $ | (89,096) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| As of December 31, | ||||
|
| 2015 |
| 2014 | ||
|
| (in thousands) | ||||
Operating Segment Assets |
|
|
|
|
|
|
Venezuela |
| $ | 5,290 |
| $ | 165,214 |
Gabon |
|
| 32,710 |
|
| 60,051 |
Indonesia |
|
| 5 |
|
| 176 |
United States and other |
|
| 9,776 |
|
| 2,602 |
|
|
| 47,781 |
|
| 228,043 |
Discontinued operations |
|
| — |
|
| 3 |
Total assets |
| $ | 47,781 |
| $ | 228,046 |
Note 17 – Related Party Transactions
The noncontrolling interest owners in Harvest Holdings, Vinccler (currently owning 20 percent) and Petroandina (currently owning 29 percent) are both related parties of the Company.
As of December 31, 2014, HNR Energia had a note payable to Vinccler of $6.1 million. Principal and interest were payable upon the maturity date of December 31, 2015. Interest accrued at a rate of U.S. Dollar based three month LIBOR plus 0.5%. On March 9, 2015, Vinccler forgave the note payable and accrued interest totaling $6.2 million. This was reflected as a contribution to stockholders’ equity.
On May 11, 2015, the Company borrowed $1.3 million to fund certain corporate expenses and issued a note payable to CT Energy bearing an interest rate of 15.0% per annum, with a maturity date of January 1, 2016. On June 19, 2015, the Company repaid the note payable and accrued interest.
S-48
On June 3, 2015, the Company entered into the note with James A. Edmiston, President and Chief Executive Officer of the Company, for $50,000. The note carried interest at 11.0% per year and was to mature upon the earlier to occur of June 30, 2016 or the date on which the Loan Obligations (as defined in that certain Loan Agreement, dated as of September 11, 2014, by and among the Company, HNR Energia B.V. and Petroandina Resources Corporation N.V.) are paid in full. On June 19, 2015, the Company repaid the note payable and accrued interest.
As of December 31, 2014, HNR Energia had a note payable to Petroandina of $7.6 million. Principal was due by January 1, 2016. Interest payments were quarterly beginning on December 31, 2014. On June 23, 2015 the Company repaid the note payable of $7.6 million plus accrued interest of $0.4 million.SEC Regulation S-K Item 404(a):
On June 19, 2015, Harvest sold to CT Energy the 15% Note, the 9% Note and the Series C preferred stock. Shortly after this transaction, two representatives of CT Energy, Mr. Oswaldo Cisneros and Mr. Francisco D’Agostino, were appointed to Harvest’s boardBoard of directors.Directors. Mr. Cisneros is the sole owner of CT Energy and Mr. D’Agostino is a controlling equity owner of CT Energia. On September 15, 2015, CT Energy converted the 9% Note, including accrued interest, into 8,667,597 shares of Harvest’s common stock and Harvest redeemed the Series C preferred stock. See Part IV – Item 15 – Exhibits and Financial Statements Schedules, Note 1 – Organizationand Note 20 – Subsequent Events for more information about the CT Energy transaction.
On January 4, 2016, HNR Finance made a loan
DIRECTOR INDEPENDENCE
Of our current seven directors, four have been affirmatively determined by the Board 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 purposebe independent, including our non-executive Chairman of the loanBoard. The directors our Board has determined to be independent are Stephen D. Chesebro’, Robert E. Irelan, Edgard Leal and Patrick M. Murray. The Board’s determination of independence is to provide CT Energia with collateral to obtain fundsbased upon the standards set forth in its Guidelines for one or more loans to Petrodelta.Corporate Governance, which may be found under the Corporate Governance section on our website at http://www.harvestnr.com. The loans to Petrodelta are to assist Petrodelta in satisfyingGuidelines for Corporate Governance include the New York Stock Exchange independence standards. In making its working capital needs and discharging its obligations. Interest ondetermination of independence, 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 paymentBoard took into account responses of the principal amount of the loan is the payments of principaldirectors to questions concerning their employment history, compensation, affiliations and interest from loans that CT Energia has made to Petrodelta. Iffamily 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.other relationships.
Note 18 – Mezzanine Equity
In connection with the CT Energy transaction described in Note 1 – Organization, the Company also issued CT Energy 69.75 shares of its newly created Series C preferred stock, par value $0.01 per share. The primary purpose of the Series C preferred stock was to provide the holder of the 9% Note with voting rights equivalent to the common stock underlying the unconverted portion of the 9% Note. The Series C preferred stock was not entitled to receive dividends, had perpetual maturity, and had a $1.00 per share liquidation preference. On September 15, 2015, upon the conversion of the 9% Note, the shares of Series C preferred stock were redeemed.
As discussed in Note 11 – Debt and Financing, no value was attributed to the Series C preferred stock. Prior to its redemption on September 15, 2015, shares of the Series C preferred stock were recorded in temporary equity in accordance with ASC 480 – Distinguishing Liabilities from Equity, as the redemption of the shares was outside of the control of the Company.
S-49
- 25 -
Note 19 – Quarterly Financial Data (unaudited)
SummarizedItem 14.Principal Accountant Fees and Services
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
BDO USA, LLP (“BDO”) is our independent registered public accounting firm. On December 1, 2014, UHY LLP ("UHY") informed Harvest that, effective on that date, UHY’s Texas practice had been acquired by BDO USA, LLP ("BDO") (the "UHY Acquisition"). As a result of the UHY Acquisition, effective December 1, 2014, UHY resigned as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2014 and BDO became our independent registered public accounting firm. UHY previously served as the independent registered public accounting firm to audit the financial statements and internal control over financial reporting of the Company for the fiscal year ended December 31, 2013.
The following is a summary of the fees for professional services rendered by BDO and UHY for each of the years ended December 31, 2015 and December 31, 2014.
Audit Fees. The aggregate fees billed by BDO and UHY for each of the last two fiscal years for professional services rendered in connection with the audit of our annual financial statements and review of financial statements included in our quarterly financial data isreports and services that are normally provided by them in connection with statutory and regulatory filings or engagements for the year ending on December 31 were as follows:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Quarter Ended | ||||||||||
|
| March 31 |
| June 30 |
| September 30 |
| December 31 | ||||
| ||||||||||||
|
| (amounts in thousands, except for share data) | ||||||||||
Year ended December 31, 2015 |
|
|
|
|
|
|
|
|
|
|
|
|
Expenses (1) |
| $ | (6,119) |
|
| (6,119) |
|
| (6,767) |
|
| (192,891) |
Non-operating gain (loss) |
|
| (234) |
|
| (17,964) |
|
| 10,335 |
|
| 22,679 |
Income (loss) from continuing operations before income taxes |
|
| (6,353) |
|
| (24,083) |
|
| 3,568 |
|
| (170,212) |
Income tax expense (benefit) |
|
| (384) |
|
| 1,604 |
|
| (1,850) |
|
| (15,793) |
Income (loss) from continuing operations |
|
| (5,969) |
|
| (25,687) |
|
| 5,418 |
|
| (154,419) |
Less: Net loss attributable to noncontrolling interest owners |
|
| (352) |
|
| (262) |
|
| (294) |
|
| (81,179) |
Net income (loss) attributable to Harvest |
| $ | (5,617) |
| $ | (25,425) |
| $ | 5,712 |
| $ | (73,240) |
Basic Earnings (Loss) per Share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations |
| $ | (0.13) |
| $ | (0.60) |
| $ | 0.13 |
| $ | (1.42) |
Net income (loss) attributable to Harvest |
| $ | (0.13) |
| $ | (0.60) |
| $ | 0.13 |
| $ | (1.42) |
Diluted Earnings (Loss) per Share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations |
| $ | (0.13) |
| $ | (0.60) |
| $ | 0.13 |
| $ | (1.42) |
Net income (loss) attributable to Harvest |
| $ | (0.13) |
| $ | (0.60) |
| $ | 0.13 |
| $ | (1.42) |
|
|
|
|
|
|
|
|
|
|
|
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|
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|
|
|
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|
|
|
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|
|
|
|
|
|
|
|
| Quarter Ended | ||||||||||
|
| March 31 |
| June 30 |
| September 30 |
| December 31 | ||||
| ||||||||||||
|
| (amounts in thousands, except for share data) | ||||||||||
Year ended December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
Expenses (2) |
| $ | (12,670) |
| $ | (9,759) |
| $ | (4,977) |
| $ | (422,199) |
Non-operating gain (loss) |
|
| (6,447) |
|
| (147) |
|
| 3,067 |
|
| 1,734 |
Loss from continuing operations before income taxes |
|
| (19,117) |
|
| (9,906) |
|
| (1,910) |
|
| (420,465) |
Income tax expense (benefit) |
|
| (954) |
|
| (88) |
|
| 2,361 |
|
| (59,609) |
Loss from continuing operations |
|
| (18,163) |
|
| (9,818) |
|
| (4,271) |
|
| (360,856) |
Earnings (loss) from investment in affiliate |
|
| 18,887 |
|
| 16,062 |
|
| — |
|
| — |
Income (loss) from continuing operations |
|
| 724 |
|
| 6,244 |
|
| (4,271) |
|
| (360,856) |
Discontinued operations |
|
| (131) |
|
| (230) |
|
| (142) |
|
| (51) |
Net income (loss) |
|
| 593 |
|
| 6,014 |
|
| (4,413) |
|
| (360,907) |
Less: Net income (loss) attributable to noncontrolling interest owners |
|
| 8,601 |
|
| 7,665 |
|
| (273) |
|
| (181,216) |
Net income (loss) attributable to Harvest |
| $ | (8,008) |
| $ | (1,651) |
| $ | (4,140) |
| $ | (179,691) |
Basic Earnings (Loss) per Share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations |
| $ | 0.19 |
| $ | (0.03) |
| $ | (0.10) |
| $ | (4.23) |
Discontinued operations |
|
| — |
|
| (0.01) |
|
| — |
|
| — |
Net income (loss) attributable to Harvest |
| $ | 0.19 |
| $ | (0.04) |
| $ | (0.10) |
| $ | (4.23) |
Diluted Earnings (Loss) per Share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations |
| $ | 0.19 |
| $ | (0.03) |
| $ | (0.10) |
| $ | (4.23) |
Discontinued operations |
|
| — |
|
| (0.01) |
|
| — |
|
| — |
Net income (loss) attributable to Harvest |
| $ | 0.19 |
| $ | (0.04) |
| $ | (0.10) |
| $ | (4.23) |
|
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|
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|
S-50
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| |||||||
|
| 2015 |
|
| 2014 | |||||||
Fees |
| BDO |
| UHY |
| BDO |
| UHY | ||||
Audit |
| $ | 1,058,355 |
| $ | — |
| $ | 608,594 |
| $ | 357,153 |
Audit Related |
|
| 35,000 |
|
| 11,450 |
|
| — |
|
| 32,013 |
Tax |
|
| — |
|
| — |
|
| — |
|
| 1,800 |
All Other |
|
| — |
|
| — |
|
| — |
|
| 26,409 |
Total |
| $ | 1,093,355 |
| $ | 11,450 |
| $ | 608,594 |
| $ | 417,375 |
All of the foregoing fees were approved by the Audit Committee.
Note 20 – Subsequent EventsAudit Committee Pre-Approval Policies and Procedures. The Audit Committee’s Charter provides that our independent registered public accounting firm may provide only those services pre-approved by the Audit Committee, subject to de minimis exceptions for non-audit services described in the rules and regulations of the SEC, which are subsequently ratified by the Audit Committee prior to completion of the audit. The Audit Committee annually reviews and pre-approves the audit, review, attestation and permitted non-audit services to be provided during the next audit cycle by the independent registered public accounting firm. To the extent practicable, at the same meeting the Audit Committee also reviews and approves a budget for each of such services.
On January 4, 2016, Harvest entered into transactions to amend its existing 15.0% non-convertible note due 2020 and to make a loan, via one of its subsidiaries,The Audit Committee may delegate to a third party. The parties involved inmember(s) the transactions are HNR Energia, Harvest Holding, HNR Finance, CT Energyauthority to grant pre-approvals under its policy with respect to audit and CT Energia Holding Ltd., a Malta corporation (“CT Energia”)permitted non-audit services, provided that is the service provider under the June 19, 2015 management agreement with Harvest and HNR Finance. Harvest and CT Energy executed a first amendmentany such grant of Harvest’s 15% non-convertible promissory note due 2020 (the “Original Note”), dated June 19, 2015, payable to CT Energy in the original principal amount of $25.2 million. The amendment increases the principal amount of the Original Note to $26.1 million to reflect a loan back to Harvest equalpre-approval shall be reported to the amountfull Audit Committee no later than its next scheduled meeting.
The Audit Committee has concluded that the provision of interest that otherwise would have been duenon-audit services is compatible with maintaining the registered public accounting firm’s independence.
PART IV
Item 15. Exhibits and Financial Statement Schedules
(b)3.Exhibits.
31.1Certification pursuant to CT Energy on January 1, 2016, less withholding tax due as a result of the interest that was owed at January 1, 2016.
On January 4, 2016, HNR Finance provided a loan to CT Energia in the amount of $5.2 million under an 11.0% promissory note due 2019 (the “CT Energia Note”), dated January 4, 2016,Rule 13a-14(a)/15d-14(a) executed by CT Energia. The purpose of the loan isJames A. Edmiston, President and Chief Executive Officer.
31.2Certification pursuant to provide CT Energia with collateral to obtain funds for one or more loans to Petrodelta that is 40% ownedRule 13a-14(a)/15d-14(a) executed by HNR Finance and through which Harvest’s Venezuelan oil and natural gas interests are held. The loans to Petrodelta are to assist Petrodelta in satisfying its working capital needs and discharging its obligations. Interest on the CT Energia Note is due and payable on the first of each January and July, commencing July 1, 2016. The full amount outstanding, including any unpaid accrued interest, is due on January 4, 2019; however, HNR Finance’s sole recourse for payment of the principal amount of the loan is the payments of principal and interest from loans that CT Energia has made to Petrodelta. If and when CT Energia receives any payments of principal or interest from loans it has made to Petrodelta, then those proceeds must be used to prepay unpaid interest and principal under the CT Energia Note. All payments made by CT Energia to HNR Finance under the CT Energia Note must be made in USD. The source of funds for HNR Finance’s $5.2 million loan to CT Energia was a capital contribution from Harvest Holding, which, in return, received the same aggregate amount of capital contributions from its shareholders, pro rata according to their equity interests in Harvest Holding. Of that aggregate amount of capital contributions, HNR Energia contributed $2.6 million, which it had received as a capital contribution from Harvest.
On March 9, 2016, VenezuelaStephen C. Haynes, Vice President, for Economic Area announced a new exchange agreement No. 35 (the “Exchange Agreement No. 35”). Exchange Agreement No. 35 was published in Venezuela’s Official Gazette No. 40865 dated March 9, 2016,Chief Financial Officer and became effective on March 10, 2016. Exchange Agreement No. 35 will have a dual exchange rate for a controlled rate (named DIPRO) fixed at 10 USD/Bolivars for priority goods and services and a complimentary rate (named DICOM) starting at 206.92 USD/Bolivars for travel and other non-essential goods. We are evaluating the impact Exchange Agreement No. 35 has on Harvest Vinccler and Petrodelta.Treasurer
S-51
- 26 -
Supplemental ISIGNATURESnformation on Oil and Natural Gas Producing Activities (unaudited)
The following tables summarize our proved reserves, drilling and production activity, and financial operating data at the end of each year. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
TABLE I – Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
| |||
| |||
| |||
|
| ||
| |||
| |||
|
| ||
| |||
| |||
|
| ||
|
|
|
TABLE II – Capitalized costs related to oil and natural gas producing activities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
| Gabon (a) |
| Indonesia |
| Total | |||
|
|
|
|
|
|
|
|
|
|
|
|
| (in thousands) | ||||||
As of December 31, 2015 |
|
|
|
|
|
|
|
|
|
Unproved property costs |
| $ | 28,000 |
| $ | — |
| $ | 28,000 |
Oilfield Inventories |
|
| 3,006 |
|
| — |
|
| 3,006 |
|
| $ | 31,006 |
| $ | — |
| $ | 31,006 |
|
|
|
|
|
|
|
|
|
|
As of December 31, 2014 |
|
|
|
|
|
|
|
|
|
Unproved property costs |
| $ | 50,324 |
| $ | — |
| $ | 50,324 |
Oilfield Inventories |
|
| 3,966 |
|
| — |
|
| 3,966 |
|
| $ | 54,290 |
| $ | — |
| $ | 54,290 |
|
|
|
|
|
|
|
|
|
|
As of December 31, 2013 |
|
|
|
|
|
|
|
|
|
Unproved property costs |
| $ | 99,447 |
| $ | 4,470 |
| $ | 103,917 |
Oilfield Inventories |
|
| 3,966 |
|
| 130 |
|
| 4,096 |
|
| $ | 103,413 |
| $ | 4,600 |
| $ | 108,013 |
|
|
|
In December 2014, the Company recorded a $50.3 million impairment related to the unproved costs of the Dussafu PSC based on a qualitative analysis. In December 2015, the Company recorded an additional impairment of $24.2 million related based on its analysis of the value of the unproved costs (including oilfield inventory) which considered the value of the contingent and exploration resources and the ability of the Company to develop the project given its current liquidity situation and the depressed price of crude oil.
TABLE III – Results of operations for oil and natural gas producing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, | ||||
|
| 2015 |
| 2014 | ||
|
|
|
|
|
|
|
|
| (in thousands) | ||||
Expenses: |
|
|
|
|
|
|
Exploration expense |
| $ | 3,900 |
| $ | 6,267 |
Impairment of oil and natural gas properties costs |
|
| 24,178 |
|
| 57,994 |
Total expenses |
|
| 28,078 |
|
| 64,261 |
Results of operations from oil and natural gas producing activities. |
| $ | (28,078) |
| $ | (64,261) |
|
|
|
|
|
|
|
TABLE IV – Quantities of Oil and Natural Gas Reserves
Estimating oil and natural gas reserves is a very complex process requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may change substantially over time as a result of numerous factors such as production history, additional development activity and continual reassessment of the viability of production under various economic and political conditions. Consequently, material upward or downward revisions to existing reserve estimates may occur from time to time; although, every reasonable efforts is made to ensure that reported results are the most accurate assessment available. We ensure that the data provided to our external independent experts, and their interpretation of that data, corresponds with our development plans and management’s assessment of each reservoir. The significance of subjective decisions required and variances in available data make estimates generally less precise than other estimates presented in connection with financial statement disclosures.
We measure and disclose oil and natural gas reserves in accordance with the provisions of the SEC’s Modernization of Oil and Gas Reporting and ASC 932, “Extractive Activities – Oil and Gas” (“ASC 932”).
The process for preparation of our oil and natural gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided for, management reviews and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Arts in Engineering Science, a Master of Science in Petroleum Engineering, has more than 25 years of experience in reservoir engineering and is a member of the Society of Petroleum Engineers.
All reserve information in this report is based on estimates prepared by Ryder Scott Company L.P. (“Ryder Scott”), independent petroleum engineers. The technical personnel responsible for preparing the reserve estimates at Ryder Scott meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.
See the following section Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela Investment in Affiliate as of December 31, 2014 and 2013, TABLE IV – Quantities of Oil and Natural Gas Reserves for Petrodelta’s reserves.
S-53
TABLE V – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities
The standardized measure of discounted future net cash flows is presented in accordance with the provisions of the accounting standard on disclosures about oil and natural gas producing activities. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.
Future cash inflows are estimated by applying the average price during the 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the contract, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes are estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.
As of December 31, 2015 and 2014, we did not have a direct interest in any proved reserves. See the following section Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela Investment in Affiliate as of December 31, 2014 and 2013, TABLE V – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities for Petrodelta’s reserves.
Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Petrodelta S.A.
We no longer exercise significant influence in Petrodelta and in accordance with Accounting Standards Codification “ASC 323 – Investments – Equity Method and Joint Ventures”, we are accounting for our investment in Petrodelta under the cost method (“ASC 325 – Investments – Other”), effective December 31, 2014. Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received. Due to the change in accounting method from equity method to cost method of accounting for our investment in Petrodelta, additional supplemental information on oil and natural gas producing activities for 2015 have been excluded.
The following tables summarize the proved reserves, drilling and production activity, and financial operating data at the end of each year for our net interest in Petrodelta. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
TABLE I – Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year ended December 31 | ||||
|
|
| 2014 |
|
| 2013 |
|
|
|
|
|
|
|
|
| (in thousands) | ||||
Development costs |
| $ | 88,498 |
| $ | 83,680 |
|
|
S-54
TABLE II – Capitalized costs related to oil and natural gas producing activities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year ended December 31 | ||||
|
|
| 2014 |
|
| 2013 |
|
|
|
|
|
|
|
|
| (in thousands) | ||||
Proved property costs |
| $ | 291,967 |
| $ | 213,181 |
Unproved property costs |
|
| — |
|
| — |
Oilfield inventories |
|
| 26,712 |
|
| 25,393 |
Less accumulated depletion and impairment |
|
| (100,591) |
|
| (72,683) |
|
| $ | 218,088 |
| $ | 165,891 |
|
|
TABLE III – Results of operations for oil and natural gas producing activities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year ended December 31 (2) | ||||
|
|
| 2014 |
|
| 2013 |
|
|
|
|
|
|
|
|
| (in thousands) | ||||
Revenue: |
|
|
|
|
|
|
Oil and natural gas revenues |
| $ | 274,999 |
| $ | 419,307 |
Royalty |
|
| (89,177) |
|
| (139,093) |
|
|
| 185,822 |
|
| 280,214 |
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
Operating, selling and distribution expenses and taxes other than on income (1) |
|
| 117,120 |
|
| 120,613 |
Depletion |
|
| 27,668 |
|
| 31,660 |
Income tax expense |
|
| 20,517 |
|
| 63,970 |
Total expenses |
|
| 165,305 |
|
| 216,243 |
Results of operations from oil and natural gas producing activities |
| $ | 20,517 |
| $ | 63,971 |
|
|
|
|
TABLE IV – Quantities of Oil and Natural Gas Reserves
We measure and disclose oil and natural gas reserves in accordance with the provisions of the SEC’s Modernization of Oil and Gas Reporting and ASC 932, “Extractive Activities – Oil and Gas” (“ASC 932”).
Petrodelta is producing from, and continuing to develop, the Petrodelta Fields. Petrodelta has both developed and undeveloped oil and natural gas reserves identified in all six fields. Petrodelta produces the fields in accordance with a business plan originally defined by its Conversion Contract executed in late 2007. Proved Undeveloped (“PUD”) oil and natural gas reserves are drilled in accordance with Petrodelta’s business plan, but can be revised where drilling results indicate a change is warranted.
During 2014, Petrodelta drilled and completed 13 production wells. Eight of the wells were previously identified Proved Undeveloped (“PUD”) locations and five wells were previously classified Probable, Possible or undefined locations. In 2014, an additional 26 PUD locations were identified through drilling activity; however, 101 PUD locations which are scheduled to be drilled five years after the wells were originally identified have been reclassified as Probable reserves. At December 31, 2015, Petrodelta had a total of 66 PUD (7.5 MM barrels of oil equivalent (“BOE”) locations identified. Since the implementation of its 2007 business plan, Petrodelta has drilled 93 gross production wells (2008 9 wells [1.4 MMBOE], (2009 15 wells [2.0 MMBOE], 2010 16 wells [2.0 MMBOE], 2011 15 wells [2.1 MMBOE], 2012 12 wells [2.2 MMBOE], 2013 13 wells [1.2 MMBOE]) and 2014 13 wells [1.3MMBOE] which have moved to the proved developed producing (“PDP”) category.
Petrodelta has a track record of identifying, executing and converting its PUD locations to PDP locations in accordance with the business plan defined by the conversion contract executed in 2007 and subsequent updates. However, the timing and pace of the development is controlled by the majority owner, PDVSA through CVP, although we have substantial negative control provisions as a noncontrolling interest shareholder. In 2010, Petrodelta submitted a revised business plan to PDVSA which substantially increases the total projected drilling activity and production volumes compared to the 2007 business plan, but which is otherwise consistent with the 2007 business plan. The 2010 business plan, as approved by PDVSA, contemplates sustained drilling activities through the year 2024
S-55
to fully develop the El Salto and Temblador fields. As a noncontrolling interest shareholder in Petrodelta, HNR Finance has limited ability to control the development plans that are periodically prepared or approved by the Venezuelan government. Since this constraint represents a hindrance to development not experienced by typical operations, the PUD locations which are now scheduled to be drilled five years after they were originally identified have been reclassified as Probable reserves.
As of December 31, 2014, proved undeveloped reserves of 7.5 MMBOE from 66 gross PUD locations are all scheduled to be drilled within the period from 2015 to 2019 and within five years from when these locations were first identified.
All above MMBOE represent our net 20.4 percent interest, net of a 33.33 percent royalty.
The tables shown below represent HNR Finance’s 40 percent ownership interest and our net percent ownership interest, both net of a 33.33 percent royalty, in Venezuela in each of the years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| HNR Finance |
|
| Minority Interest in Venezuela |
|
| 32%/20.4% Net Total |
|
|
|
|
|
|
|
|
|
|
|
|
| (in thousands) | ||||||
Proved Reserves-Crude oil, condensate, |
|
|
|
|
|
|
|
|
|
and natural gas liquids (MBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014 (20.4% net interest) |
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1, 2014 |
|
| 36,420 |
|
| (17,846) |
|
| 18,574 |
Revisions |
|
| (5,259) |
|
| 2,577 |
|
| (2,682) |
Extensions |
|
| 3,728 |
|
| (1,827) |
|
| 1,901 |
Production |
|
| (4,150) |
|
| 2,034 |
|
| (2,116) |
Proved Reserves at end of the year |
|
| 30,739 |
|
| (15,062) |
|
| 15,677 |
|
|
|
|
|
|
|
|
|
|
As of December 31, 2014 (20.4% net interest) |
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
Developed |
|
| 16,459 |
|
| (8,065) |
|
| 8,394 |
Undeveloped |
|
| 14,280 |
|
| (6,997) |
|
| 7,283 |
Total Proved |
|
| 30,739 |
|
| (15,062) |
|
| 15,677 |
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2013 (32% to 20.4% net interest) |
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1, 2013 (32% net interest) |
|
| 43,161 |
|
| (8,632) |
|
| 34,529 |
Revisions |
|
| (3,668) |
|
| 1,798 |
|
| (1,870) |
Extensions |
|
| 804 |
|
| (161) |
|
| 643 |
Production |
|
| (3,877) |
|
| 775 |
|
| (3,102) |
Reduction in indirect ownership interest to 20.4% net interest |
|
| — |
|
| (11,626) |
|
| (11,626) |
Proved Reserves at end of the year (20.4% net interest) |
|
| 36,420 |
|
| (17,846) |
|
| 18,574 |
|
|
|
|
|
|
|
|
|
|
As of December 31, 2013 (20.4% net interest) |
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
Developed |
|
| 16,436 |
|
| (8,054) |
|
| 8,382 |
Undeveloped |
|
| 19,984 |
|
| (9,792) |
|
| 10,192 |
Total Proved |
|
| 36,420 |
|
| (17,846) |
|
| 18,574 |
S-56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| HNR Finance |
|
| Minority Interest in Venezuela |
|
| 32%/20.4% Net Total |
|
|
|
|
|
|
|
|
|
|
|
| (in thousands) | |||||||
Proved Reserves-Natural gas (MMcf) |
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014 (20.4% net interest) |
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1, 2014 |
|
| 24,797 |
|
| (12,150) |
|
| 12,647 |
Revisions |
|
| (12,131) |
|
| 5,944 |
|
| (6,187) |
Extensions |
|
| 1,014 |
|
| (497) |
|
| 517 |
Production |
|
| (1,504) |
|
| 737 |
|
| (767) |
Proved Reserves at end of the year |
|
| 12,176 |
|
| (5,966) |
|
| 6,210 |
|
|
|
|
|
|
|
|
|
|
As of December 31, 2014 (20.4% net interest) |
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
Developed |
|
| 9,582 |
|
| (4,695) |
|
| 4,887 |
Undeveloped |
|
| 2,594 |
|
| (1,271) |
|
| 1,323 |
Total Proved |
|
| 12,176 |
|
| (5,966) |
|
| 6,210 |
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2013 (32% to 20.4% net interest) |
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1, 2013 (32% net interest) |
|
| 29,012 |
|
| (5,802) |
|
| 23,210 |
Revisions |
|
| (2,914) |
|
| 1,428 |
|
| (1,486) |
Extensions |
|
| 126 |
|
| (25) |
|
| 101 |
Production |
|
| (1,427) |
|
| 285 |
|
| (1,142) |
Reduction in indirect ownership interest to 20.4% net interest |
|
| — |
|
| (8,036) |
|
| (8,036) |
Proved Reserves at end of the year (20.4% net interest) |
|
| 24,797 |
|
| (12,150) |
|
| 12,647 |
|
|
|
|
|
|
|
|
|
|
As of December 31, 2013 (20.4% net interest) |
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
Developed |
|
| 20,451 |
|
| (10,021) |
|
| 10,430 |
Undeveloped |
|
| 4,346 |
|
| (2,129) |
|
| 2,217 |
Total Proved |
|
| 24,797 |
|
| (12,150) |
|
| 12,647 |
TABLE V – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities
The standardized measure of discounted future net cash flows is presented in accordance with the provisions of the accounting standard on disclosures about oil and natural gas producing activities. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.
Future cash inflows are estimated by an applying the average price during the 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the contract, to the estimated future production of year-end proved reserves. Our average prices used for 2014 were $78.04 per barrel for oil for the El Salto field ($84.14 in 2013) and $86.56 per barrel for the other fields ($97.89 in 2013), and $1.54 per Mcf for natural gas ($1.54 per Mcf in 2013). Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.
S-57
The table shown below represents HNR Finance’s net interest in Petrodelta.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| HNR Finance |
|
| Minority Interest in Venezuela |
|
| 32%/20.4% Net Total |
|
|
|
|
|
|
|
|
|
|
|
| (in thousands) | |||||||
As of December 31, 2014 (20.4% net interest) |
|
|
|
|
|
|
|
|
|
Future cash inflows from sales of oil and natural gas |
| $ | 2,507,395 |
| $ | (1,228,624) |
| $ | 1,278,771 |
Future production costs (1) |
|
| (740,295) |
|
| 362,745 |
|
| (377,550) |
Future development costs |
|
| (118,595) |
|
| 58,112 |
|
| (60,483) |
Future income tax expenses |
|
| (637,378) |
|
| 312,315 |
|
| (325,063) |
Future net cash flows |
|
| 1,011,127 |
|
| (495,452) |
|
| 515,675 |
Effect of discounting net cash flows at 10% |
|
| (329,294) |
|
| 161,354 |
|
| (167,940) |
Standardized measure of discounted future net cash flows |
| $ | 681,833 |
| $ | (334,098) |
| $ | 347,735 |
|
|
|
|
|
|
|
|
|
|
As of December 31, 2013 (20.4% net interest) |
|
|
|
|
|
|
|
|
|
Future cash inflows from sales of oil and natural gas |
| $ | 3,267,240 |
| $ | (1,600,948) |
| $ | 1,666,292 |
Future production costs (1) |
|
| (1,352,126) |
|
| 662,542 |
|
| (689,584) |
Future development costs |
|
| (240,844) |
|
| 118,014 |
|
| (122,830) |
Future income tax expenses |
|
| (696,657) |
|
| 341,362 |
|
| (355,295) |
Future net cash flows |
|
| 977,613 |
|
| (479,030) |
|
| 498,583 |
Effect of discounting net cash flows at 10% |
|
| (346,113) |
|
| 169,595 |
|
| (176,518) |
Standardized measure of discounted future net cash flows |
| $ | 631,500 |
| $ | (309,435) |
| $ | 322,065 |
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TABLE VI – Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (in thousands):
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| Year ended December 31 | ||||
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| 2014 |
| 2013 | |
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| (20.4%) |
| (32% to 20.4%) | ||
Standardized Measure at January 1 |
| $ | 322,065 |
| $ | 449,774 |
Sales of oil and natural gas, net of related costs |
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| (68,702) |
|
| (159,601) |
Revisions to estimates of proved reserves: |
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Net changes in prices, net of production taxes |
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| 21,045 |
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| 57,745 |
Quantities |
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| (142,136) |
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| (61,614) |
Extensions, discoveries and improved recovery, net of future costs |
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| 59,039 |
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| 21,040 |
Accretion of discount |
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| 50,794 |
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| 51,710 |
Net change in income taxes |
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| 37,049 |
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| 12,656 |
Development costs incurred |
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| 88,498 |
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| 83,680 |
Changes in estimated development costs |
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| (19,545) |
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| 7,356 |
Reduction in indirect ownership interest to 20.4% |
|
| — |
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| (142,007) |
Timing differences and other |
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| (373) |
|
| 1,326 |
Standardized Measure at December 31 |
| $ | 347,734 |
| $ | 322,065 |
S-58
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
HARVEST NATURAL RESOURCES, INC. (Registrant) | |||
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Date:April 29, 2016By:/s/ Keith L. Head Keith L. Head Vice President and General Counsel |
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Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the 29th of March 2016, on behalf of the registrant and in the capacities indicated:
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S-59
- 27 -