10-K 1 d444289d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

 

FORM 10-K

 

 

(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, 2012

or

 

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

Commission File No.: 1-10762

 

 

HARVEST NATURAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   77-0196707

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

 

1177 Enclave Parkway, Suite 300

Houston, Texas

  77077
(Address of principal executive offices)   (Zip Code)

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

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

 

Title of each class

 

Name of each exchange on which registered

Common Stock, $.01 Par Value   NYSE

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

 

 

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  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 (§ 232.405 of this chapter) 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   ¨

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, 2012 was: $319,236,984.

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 May 2, 2013, shares outstanding: 39,454,279.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for the 2013 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission, not later than 120 days after the close of the registrant’s fiscal year, pursuant to Regulation 14A, are incorporated by reference into Items 10, 11, 12, 13 and 14 of Part III of this annual report.

 

 

 


Table of Contents

HARVEST NATURAL RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS

 

     Page  
Part I   

Item 1.

  

Business

     1   

Item 1A.

  

Risk Factors

     16   

Item 1B.

  

Unresolved Staff Comments

     22   

Item 2.

  

Properties

     22   

Item 3.

  

Legal Proceedings

     22   

Item 4.

  

Mine Safety Disclosures

     24   
Part II   

Item 5.

  

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

     25   

Item 6.

  

Selected Financial Data

     27   

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     27   

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

     49   

Item 8.

  

Financial Statements and Supplementary Data

     50   

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     50   

Item 9A.

  

Controls and Procedures

     50   

Item 9B.

  

Other Information

     52   
Part III   

Item 10.

  

Directors, Executive Officers and Corporate Governance

     53   

Item 11.

  

Executive Compensation

     59   

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     83   

Item 13.

  

Certain Relationships and Related Transactions, and Director Independence

     85   

Item 14.

  

Principal Accountant Fees and Services

     86   
Part IV   

Item 15.

  

Exhibits and Financial Statement Schedules

     87   
Financial Statements      S-2   
Signatures      S-65   


Table of Contents

PART I

Harvest Natural Resources, Inc. (“Harvest” or the “Company”) cautions that any forward-looking statements as such term is defined in Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) contained in this report or made by management of the Company involve risks and uncertainties and are subject to change based on various important factors. When used in this report, the words “budget”, “forecast”, “expect”, “believes”, “goals”, “projects”, “plans”, “anticipates”, “estimates”, “should”, “could”, “assume” and similar expressions are intended to identify forward-looking statements. In accordance with the provisions of the Securities Act and the Exchange Act, we caution you that important factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include our concentration of operations in Venezuela, the political and economic risks associated with international operations (particularly those in Venezuela), the anticipated future development costs for undeveloped reserves, drilling risks, the risk that actual results may vary considerably from reserve estimates, the dependence upon the abilities and continued participation of certain of our key employees, the risks normally incident to the exploration, operation and development of oil and natural gas properties, risks incumbent to being a noncontrolling interest shareholder in a corporation, the permitting and the drilling of oil and natural gas wells, the availability of materials and supplies necessary to projects and operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, the Company’s ability to acquire oil and natural gas properties that meet its objectives, availability and cost of drilling rigs and seismic crews, overall economic conditions, political stability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in governmental policy, lack of liquidity, availability of sufficient financing, estimates of amounts and timing of sales of securities, changes in weather conditions, and ability to hire, retain and train management and personnel. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

Item 1. Business

Executive Summary

Harvest Natural Resources, Inc. is a petroleum exploration and production company incorporated under Delaware law in 1989. Our focus is on acquiring exploration, development and producing properties in geological basins with proven active hydrocarbon systems. Our experienced technical, business development and operating personnel have identified low entry cost exploration opportunities in areas with large hydrocarbon resource potential. We operate from our Houston, Texas headquarters. We also have regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Republic of Indonesia (“Indonesia”); Port Gentil, Republic of Gabon (“Gabon”); and Muscat, Sultanate of Oman (“Oman”) to support field operations in those areas.

We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through Harvest-Vinccler Dutch Holding, B.V., a Dutch private company with limited liability (“Harvest Holding”). Our ownership of Harvest Holding is through HNR Energia, B.V. (“HNR Energia”) in which we have a direct controlling interest. Through HNR Energia, we indirectly own 80 percent of Harvest Holding and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining 20 percent interest of Harvest Holding. Harvest Holding owns, indirectly through wholly owned subsidiaries, a 40 percent of Petrodelta, S.A. (“Petrodelta”). As we indirectly own 80 percent of Harvest Holding, we indirectly own a net 32 percent interest in Petrodelta, and Vinccler indirectly owns eight percent. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petroleos de Venezuela S.A. (“PDVSA”) owns 100 percent of CVP. Harvest Holding has a direct controlling interest in Harvest Vinccler S.C.A. (“Harvest Vinccler”). Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with PDVSA. We do not have a business relationship with Vinccler outside of Venezuela.

Through the pursuit of technically-based strategies, we are building a portfolio of exploration prospects to complement the low-risk production, development and exploration prospects we hold in Venezuela. In addition to our interests in Venezuela, we hold exploration acreage mainly onshore West Sulawesi in Indonesia, offshore of Gabon, onshore in Oman, and offshore of the People’s Republic of China (“China”).

 

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From time to time we learn of possible third party interests in acquiring ownership in certain assets within our property portfolio. We evaluate these potential opportunities taking into consideration our overall property mix, our operational and liquidity requirements, our strategic focus and our commitment to long-term shareholder value.

During the last two years, we have been exploring a broad range of strategic alternatives for enhancing stockholder value. On September 24, 2010, we retained Merrill Lynch, Pierce, Fenner & Smith (“Merrill Lynch”) to provide advisory services to assist us in exploring those strategic alternatives, including, among others, a sale of assets. Since that time, we have received several indications of interest from third parties, provided due diligence materials to third parties under confidentiality agreements and had preliminary discussions with third parties regarding a sale of our interest in Venezuela, but until March 6, 2012, we had not determined that any of the transactions discussed were in our best interests. On March 6, 2012, we announced that we had commenced exclusive negotiations with a third party for the possible sale of our 32 percent interest in Petrodelta. See Share Purchase Agreement (“SPA”) below.

As of December 31, 2012, we had total assets of $596.8 million, unrestricted cash of $72.6 million and long-term debt of $74.8 million. For the year ended December 31, 2012, we had no revenues from continuing operations and net cash used in operating activities of $26.4 million. As of December 31, 2011, we had total assets of $507.2 million, unrestricted cash of $58.9 million and long-term debt of $31.5 million. For the year ended December 31, 2011, we had no revenues from continuing operations and net cash used in operating activities of $55.2 million.

At December 31, 2012, Petrodelta’s reserves net to our 32 percent interest are: Proved reserves 38.4 MMBOE, Probable reserves 61.8 MMBOE, and Possible reserves 104.4 MMBOE. Proved plus Probable reserves at 100.2 MMBOE, after accounting for current year production, are virtually unchanged from last year. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies – Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve estimates.

In March 2012, we entered into exchange agreements with certain holders of our 8.25 percent senior convertible notes. We issued 2.9 million shares of common stock at an effective exchange price of $5.56 per share in exchange for $16.0 million in aggregate principal amount of 8.25 percent senior convertible notes and associated interest. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Long-Term Debt.

In May 2012, we entered the third exploration phase of the Dussafu Marin Permit (“Dussafu PSC”). The third exploration phase has been lengthened to four years. See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon – General.

In June 2012, we and our wholly owned subsidiary HNR Energia entered into a Share Purchase Agreement (“SPA”) with PT Pertamina (Persero), a state-owned limited liability company existing under the laws of Indonesia (“Buyer”). On February 20, 2013, we announced that the SPA was terminated. See Item 1. Business, Operations, Petrodelta, Share Purchase Agreement (“SPA”).

In August 2012, we entered into exchange agreements with certain holders of our 8.25 percent senior convertible notes. We issued 1.2 million shares of common stock at an effective exchange price of $5.60 per share in exchange for $6.5 million in aggregate principal amount of 8.25 percent senior convertible notes and associated interest. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Long-Term Debt.

In October 2012, we announced the sale of $79.8 million aggregate principal amount of 11 percent senior unsecured notes due October 11, 2014, and warrants to purchase up to 0.8 million shares of our common stock with an exercise price of $10.00 per share. The net cash proceeds of the offering were approximately $63.5 million after deducting the issuance discount, placement fees, and other transaction costs. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Long-Term Debt.

 

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In October 2012, we extinguished the remaining 8.25 percent senior convertible notes. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Long-Term Debt.

In November 2012, we announced the commencement of drilling operations on Dussafu Tortue Marin-1 (“DTM-1”) exploration well in the Dussafu PSC. See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon – Drilling and Development Activity.

In December 2012, we received approval for a four year extension of the initial six-year exploration term of the Budong-Budong Production Sharing Contract (“Budong PSC”). See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia – General.

In January 2013, we announced that we had encountered oil in DTM-1. See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon – Drilling and Development Activity.

In January 2013, we acquired an additional 7.1 percent participating interest in the Budong PSC and became interim operator of the Budong PSC effective January 16, 2013. See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia – General.

See Item 1. Business, Operations, Item 1A. Risk Factors, and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a more detailed description of these and other events during 2012.

Our strategy has broadened from our primary focus on Venezuela to identify, access and integrate organic growth hydrocarbon assets through exploration in basins with proven hydrocarbon systems globally as an alternative to purchasing proved producing assets. We seek to leverage our Venezuelan experience as well as our expanded business development and technical platform to create a diversified resource base. We have made significant investments to provide the foundation and global reach required for an organic growth focus. While exploration has become a larger part of our overall portfolio, we generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles.

We intend to use our available cash to pursue additional growth opportunities in Indonesia, Gabon, China and other countries that meet our strategy. However, the execution of this strategy may be limited by factors including, among other things, access to additional capital and the receipt of dividends from Petrodelta as well as the need to preserve adequate development capital in the interim.

The ability to successfully execute our strategy is subject to significant risks including, among other things, receipt of dividends from Petrodelta, exploration, operating, political, legal and financial risks. See Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and other information set forth elsewhere in this Annual Report on Form 10-K for a description of these and other risk factors.

Available Information

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

We also make available, free of charge on or through our Internet website (http://www.harvestnr.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Exchange Act are also available on our website. In

 

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addition, we have adopted a Code of Business Conduct and Ethics that applies to all of our employees, including our chief executive officer, principal financial officer and principal accounting officer. The text of the Code of Business Conduct and Ethics has been posted on the Corporate Governance section of our website. We post on our website any amendments to, or waivers from, our Code of Business Conduct and Ethics applicable to our senior officers. Additionally, the Code of Business Conduct and Ethics is available in print to any person who requests the information. Individuals wishing to obtain this printed material should submit a request to Harvest Natural Resources, Inc., 1177 Enclave Parkway, Suite 300, Houston, Texas 77077, Attention: Investor Relations.

Reserves

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

The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided, management reviews and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Arts in Engineering Science, a Master of Science in Petroleum Engineering, more than 28 years of experience in reservoir engineering, and is a member of the Society of Petroleum Engineers.

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

In Venezuela during 2012, Petrodelta drilled and completed 12 production wells. Six of the wells were previously identified Proved Undeveloped (“PUD”) locations and six wells were previously classified as probable, possible or undefined locations. In 2012, an additional ten PUD locations were identified through drilling activity, however ten PUD locations which are scheduled to be drilled five years after the wells were originally identified have been reclassified as Probable reserves. At December 31, 2012, Petrodelta has a total of 157 identified PUD locations.

Petrodelta’s 2012 business plan, as proposed by Petrodelta, contemplates sustained drilling activities through the year 2023 to fully develop the El Salto, Isleño and Temblador fields. As a noncontrolling interest shareholder in Petrodelta, HNR Finance, B.V. (“HNR Finance”), a wholly owned subsidiary of Harvest Holding, has limited ability to control the development plans that are periodically prepared and/or approved by the Venezuelan government. The PUD locations which are now scheduled to be drilled five years after they were originally identified have been reclassified as Probable reserves.

Proved undeveloped reserves of 22.9 MMBOE from 157 gross PUD locations are scheduled to be drilled within the period from 2013 to 2016 and within five years from when these locations were first identified. All above MMBOE represent our net 32 percent interest, net of a 33.33 percent royalty.

Probable undeveloped reserves of 61.8 MMBOE include 17.5 MMBOE from 79 gross undeveloped locations that would otherwise meet the definition of proved undeveloped reserves, except that they are scheduled to be drilled at least five years after the date that they were originally identified. Of these 79 locations, 72 are scheduled to be drilled within five years from 2013 to 2018.

 

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The following table shows, by country and in the aggregate, a summary of our proved, probable and possible oil and gas reserves as of December 31, 2012.

 

     Oil and
NGLs
     Natural
Gas
     Total  
     (MBls)      (MMcf)      (MBOE)(a)  

Proved Developed Reserves:

        

International – Venezuela(b)

     12,486         17,906         15,470   
  

 

 

    

 

 

    

 

 

 

Total Proved Developed

     12,486         17,906         15,470   
  

 

 

    

 

 

    

 

 

 

Proved Undeveloped Reserves:

        

International – Venezuela(b)

     22,043         5,304         22,927   
  

 

 

    

 

 

    

 

 

 

Total Proved Undeveloped

     22,043         5,304         22,927   
  

 

 

    

 

 

    

 

 

 

Total Proved Reserves

     34,529         23,210         38,397   
  

 

 

    

 

 

    

 

 

 

Probable Developed Reserves:

        

International – Venezuela(b)

     8         —           8   
  

 

 

    

 

 

    

 

 

 

Total Probable Developed

     8         —           8   
  

 

 

    

 

 

    

 

 

 

Probable Undeveloped Reserves:

        

International – Venezuela(b)

     54,668         42,924         61,822   
  

 

 

    

 

 

    

 

 

 

Total Probable Undeveloped

     54,668         42,924         61,822   
  

 

 

    

 

 

    

 

 

 

Total Probable Reserves

     54,676         42,924         61,830   
  

 

 

    

 

 

    

 

 

 

Possible Developed Reserves:

        

International – Venezuela(b)

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total Possible Developed

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Possible Undeveloped Reserves:

        

International – Venezuela(b)

     99,463         29,444         104,370   
  

 

 

    

 

 

    

 

 

 

Total Possible Undeveloped

     99,463         29,444         104,370   
  

 

 

    

 

 

    

 

 

 

Total Possible Reserves

     99,463         29,444         104,370   
  

 

 

    

 

 

    

 

 

 

 

(a) 

Thousand barrels of oil equivalent (“MBOE”) is determined using the approximate heat content ratio of one barrel of crude oil or condensate to six thousand cubic feet (“Mcf”) of natural gas, which ratio does not necessarily reflect price equivalency.

(b) 

Information represents our net 32 percent ownership interest in Petrodelta.

Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves as of December 31, 2012, 2011 and 2010 and changes in proved reserves during the last three years are contained in Item 15. Supplemental Information on Oil and Natural Gas Producing Activities (unaudited). See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation, Critical Accounting Policies – Reserves for additional information on our reserves.

Operations

As of December 31, 2012, our operations include:

 

   

Venezuela. Operations are through our equity affiliate Petrodelta which is governed by the Contract of Conversion (“Conversion Contract”) signed on September 11, 2007. Our ownership of Petrodelta is through Harvest Holding which indirectly, through wholly owned subsidiaries, owns 40 percent of Petrodelta. As we indirectly own 80 percent of Harvest Holding, we indirectly own a net 32 percent interest in Petrodelta.

 

   

Republic of Indonesia (“Indonesia”). Operations are mainly onshore in West Sulawesi in Indonesia through the Budong PSC. We own a 64.51 percent cost sharing interest in the Budong PSC. We became the interim operator in January 2013. Transfer of operatorship is subject to regulatory approval.

 

   

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

 

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Sultanate of Oman (“Oman”). Operations are onshore in Oman through the Exploration and Production Sharing Agreement (“EPSA”) Al Ghubar / Qarn Alam license (“Block 64 EPSA”). We have an 80 percent interest in Block 64 EPSA. We are the operator.

 

   

People’s Republic of China (“China”). Exploration acreage is offshore of China in the South China Sea through the Wab-21 Petroleum Contract (“Wab-21”). We have a 100 percent interest in the WAB-21 petroleum contract. We are the operator.

Petrodelta

General

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

Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Under its conversion contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. Petrodelta’s 2012 proposed capital expenditures were expected to be approximately $401.9 million and included a planned drilling program to utilize three rigs to drill both development and appraisal wells for maintaining production capacity and the continued appraisal of the substantial resource base in the El Salto and Isleño fields. It also included engineering work for the additional infrastructure enhancement projects in El Salto and Temblador. Due to insufficient monetary support and contractual adherence by PDVSA, Petrodelta incurred only $184.2 million of its 2012 proposed capital expenditures.

As discussed in previous filings, PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA 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.

Crude oil delivered from the Petrodelta fields to PDVSA Petroleo S.A. (“PPSA”), a wholly owned subsidiary of PDVSA, is priced with reference to Merey 16 published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices are quoted and sold in U.S. Dollars. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Petrodelta for additional information on Petrodelta’s Contract for Sale and Purchase of Hydrocarbons with PPSA (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 U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered. Natural gas deliveries are paid in Venezuelan Bolivars (“Bolivars”), but the pricing for natural gas is referenced to the U.S. Dollar.

In April 2011, the Venezuelan government published in the Official Gazette the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (the “amended Windfall Profits Tax”). See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Venezuela – Petrodelta for a discussion of the effects of the amended Windfall Profits Tax on Petrodelta’s business.

 

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On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, as of May 2, 2013, this dividend has not been received, although it is due and payable. Petrodelta’s board of directors declared this dividend and has never indicated that the dividend is not payable, nor that it will not be paid. The dividend receivable is classified as a long-term receivable at December 31, 2012 due to the uncertainty in the timing of payment. There is uncertainty with respect to the timing of the receipt of this dividend and whether future dividends will be declared or paid. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable not be collected or facts and circumstances surrounding our investment change, our results of operations and investment in Petrodelta could be adversely impacted.

Share Purchase Agreement (“SPA”)

On June 21, 2012, we announced that we and our wholly owned subsidiary HNR Energia had entered into a SPA with PT Pertamina (Persero), a state-owned limited liability company existing under the laws of Indonesia (“Buyer”) under which HNR Energia agreed to sell, indirectly through subsidiaries, all of its interests in Venezuela for a cash purchase price of $725.0 million, subject to adjustment as described in the SPA.

The closing of the transaction was subject to receipt of three approvals, in addition to satisfaction of other conditions standard in transactions of this type: (a) approval by the Ministerio del Poder Popular de Petroleo y Mineria representing the Government of the Bolivarian Republic of Venezuela (which indirectly owns the other 60 percent interest in Petrodelta); (b) approval by the Government of the Republic of Indonesia in its capacity as Buyer’s sole shareholder; and (c) approval by the holders of a majority of Harvest’s common stock.

After receiving notice from Buyer that Buyer’s sole shareholder, the Government of Indonesia, had decided not to approve the transaction described in the SPA, on February 19, 2013, HNR Energia exercised its right to terminate the agreement in accordance with its terms.

Petrodelta 2013 Capital Budget

As of May 2, 2013, the 2013 budget for Petrodelta had not yet been approved by its shareholders. Since Petrodelta only executed approximately 45.8 percent of its 2012 proposed capital expenditures primarily due to insufficient monetary support and contractual adherence by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2013 budget. Should PDVSA continue in insufficient monetary support and contractual adherence of Petrodelta, underinvestment in the development plan may lead to continued under-performance. However, Petrodelta’s 2013 proposed budget includes a planned drilling program to utilize five rigs to drill both development and appraisal wells for maintaining production capacity and the continued appraisal of the substantial resource base in the El Salto, Temblador and Isleño fields. It also includes engineering work for continued infrastructure enhancement projects in El Salto and Temblador.

Location and Geology

Petrodelta Fields

Uracoa Field

At December 31, 2012, there were 86 (2011: 86) oil and natural gas producing wells and seven (2011: seven) water injection wells in the field. The current production facility has capacity to handle 30 thousand barrels (“MBbls”) of oil per day (down from 60 MBls of oil per day in 2011 due to the relocation of treaters to the El Salto and Temblador fields), 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. All natural gas presently being delivered by Petrodelta is produced from the Uracoa field and is delivered to PDVSA through a 64-mile pipeline to Mamo gas station and PDVSA Gas network.

 

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Tucupita Field

At December 31, 2012, there were 15 (2011: 17) oil producing wells and four (2011: four) 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

East Bombal was drilled in 1992, and currently remains underdeveloped with only one production well (2011: one). In West Bombal, at December 31, 2012, there were three (2011: three) 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, 2012, there were two (2011: no wells) oil producing wells in the field. The oil is transported via vacuum trucks to the Uracoa plant facilities UM-2. See Uracoa Field above. Currently, a 16 inch, 6.2 mile, 20 MBbls per day transfer line capacity is being constructed from Isleño field to Uracoa to transport the fluids produced.

Temblador Field

At December 31, 2012, there were 28 (2011: 27) oil producing wells in the field. The oil is transported through two pipelines: a 5.6-mile, 40 MBbls of oil per day trunkline from TY-8 flow station (east end of the field) to 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 TY-23 flow station. The total crude oil is then delivered from TY-23 flow station into PDVSA’s EPT-1 storage facility.

El Salto Field

At December 31, 2012, there were 17 (2011: nine) oil producing wells and one (2011: one) water injection well in the El Salto field. In October 2011, Petrodelta completed the pipeline to connect the El Salto field to PDVSA’s COMOR EPM-1 storage facility. The oil is now 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 Mamo gas station and PDVSA Gas network with a nominal capacity of 70 million cubic feet (“MMcf”) of natural gas per day and a design capacity of 90 MMcf of natural gas per day.

Petrodelta has at Temblador Field two main gathering systems, one in the East side of the field, a 5.6-mile trunkline from the TY-8 Flow Station to 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, a 4.3 mile, 20 MBbls of total fluid per day gathering system from the end of the field to TY-23 flow station. The total crude oil, on specification, is then delivered from 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.

 

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

Drilling and Development Activity

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

Petrodelta began 2012 with three drilling rigs, but PDVSA relocated one rig to another operation. Currently, Petrodelta is operating three drilling rigs and two workover rigs and is continuing with infrastructure enhancement projects in the El Salto and Temblador fields. A pipeline is currently under construction between the Isleño field and the main production facility at Uracoa. Isleño production is currently being trucked to Uracoa. Petrodelta has received two new drilling rigs. The first drilling rig is currently waiting on repairs and is expected to start drilling operations in the Isleño field in the first quarter of 2013. The second drilling rig has been mobilized and is expected to start drilling operations in the Temblador field in the first quarter of 2013. Petrodelta was notified that it will relocate a current operating rig to another operation with the old rig being replaced with a new rig which arrived in February 2013. These rigs result in an expected five working drilling rigs in 2013.

Risk Factors

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

Budong-Budong, Onshore Indonesia

General

In 2007, we entered into a Farmout Agreement to acquire a 47 percent interest in the Budong PSC located mostly onshore West Sulawesi, Indonesia. In April 2008, the Government of Indonesia approved the assignment to us of the 47 percent interest in the Budong PSC. Our partner is the operator through the exploration phase as required by the terms of the Budong PSC, and we have an option to become operator, if approved by the Government of Indonesia and SKK Migas in any subsequent development and production phase.

We acquired our original 47 percent interest in the Budong PSC by committing to fund the first phase of the exploration program up to a cap of $17.2 million, including the acquisition of 2-D seismic and drilling of the first two exploration wells under a Farmout Agreement with our partner in the Budong PSC. Prior to drilling the first exploration well, our partner had a one-time option to increase the level of the carried interest to a maximum of $20.0 million. On September 15, 2010, our partner exercised their option to increase their carried interest by $2.7 million to a total of $19.9 million. The additional carry increased our ownership by 7.4 percent to 54.4 percent. On March 3, 2011, the Government of Indonesia approved this change in ownership interest.

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

The initial exploration term of the Budong PSC was due to expire on January 15, 2013. In September 2012, the operator of the Budong PSC, on behalf of us and the other co-venturer, submitted a request to BPMIGAS under the terms of the Budong PSC for a four-year extension of the initial six-year exploration term of the Budong PSC. In January 2013, we received written approval from SKK Migas of the four-year extension of the initial six-year exploration term.

 

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In November 2012, the Indonesia constitutional court declared BPMIGAS, Indonesia’s oil and gas regulatory authority, to be unconstitutional. In January 2013, SKK Migas, the Special Task Force for oil and gas upstream sector, was formed to replace BPMIGAS. SKK Migas will supervise all oil and gas industry activities.

In December 2012, we signed a farmout agreement with the operator of the Budong PSC to acquire an additional 7.1 percent participating interest and to become operator of the Budong PSC. We assumed the role of interim operator effective January 16, 2013. Closing of this acquisition will increase our participating ownership interest in the Budong PSC to 71.5 percent with our cost sharing interest becoming 72 percent until first commercial production. The consideration for this transaction is that we will fund 100 percent of the costs of the first exploration well of the four-year extension to the Budong PSC. If the exploration well is not drilled within 18 months of the date of approval from the Government of Indonesia of this transaction, our partner has the right to give notice that the consideration be paid in cash, or $3.2 million. The acquisition of the additional participating interest and the transfer of operatorship are dependent on approval by the Government of Indonesia.

We have satisfied all work commitments for the current exploration phase of the Budong PSC. However, the extension of the initial exploration term includes an exploration well, which if not drilled by January 2016, results in the termination of the Budong PSC.

Location and Geology

During the initial exploration period, the Budong PSC covered 1.35 million acres. The Budong PSC includes a ten-year exploration period and a 20-year development phase. Pursuant to the terms of the Budong PSC, at the end of the first three-year exploration phase, 45 percent of the original area was to be relinquished to BPMIGAS. In January 2010, 35 percent of the original area was relinquished and ten percent of the required relinquishment was deferred until 2011. In January 2011, the deferred ten percent of the original total contract area was relinquished. The Budong PSC currently covers 0.75 million acres. However, pursuant to the request for extension of the initial exploration term, the contract area held by the Budong PSC at the beginning of the extension period should be reduced, per the terms of the Budong PSC, from the current 55 percent to 20 percent of the original contract area. In January 2013, our partner, on our behalf, submitted a relinquishment proposal of 10 percent to SKK Migas. The retained area will contain all the areas of geological interest to the Budong PSC partners.

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

Drilling and Development Activity

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

Operational activities during 2012 focused on a review of geological and geophysical data obtained from the drilling of LG-1 and KD-1 wells to upgrade the prospectivity of the block and to define a prospect for potential drilling in 2013. We have completed remapping of both the Lariang and Karama Basins with eight leads in the Lariang Basin and five leads in the Karama Basin having been identified. The identification of these leads is the basis for the four-year extension request of the first six-year exploration term.

Dussafu Marin, Offshore Gabon

General

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

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

 

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The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period. This commitment was fulfilled with the drilling of DTM-1.

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, Middle Dentale and Upper Dentale Formations. DRM-1 and sidetracks are currently suspended pending further exploration and development activities.

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

Well planning progressed to drill an exploration well in the fourth quarter of 2012 on the Tortue prospect to target stacked pre-salt Gamba and Dentale reservoirs as well as a secondary post-salt Madiela clastic reservoir. DTM-1 was spud on November 19, 2012. DTM-1 was drilled with the Scarabeo 3 semi-submersible drilling unit, and was drilled 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 Dental 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. Additional technical evaluation is on-going.

The first appraisal sidetrack of DTM-1 (“DTM-1ST1”) spud January 12, 2013. DTM-1ST1 was drilled to a Total Depth of 11,385 feet in the Dental 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 early before pressure data could be collected to confirm connectivity. The well can be re-entered, and the downhole tool has since been retrieved. DTM-1 and DTM-1ST1 were suspended pending future appraisal and development activities. The drilling rig was demobilized and released on February 21, 2013.

Block 64 EPSA, Oman

General

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

The First Phase of Block 64 EPSA had a minimum work obligation over a three-year period of $22 million to reprocess 375 square kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup. In order to complete drilling activities of the two exploratory wells, on August 24, 2011, Oman’s Ministry of Oil and Gas approved a one-year extension to May 23, 2013 of the First Phase of the EPSA. Both the work and financial commitments for the First Phase on Block 64 EPSA have been fulfilled.

 

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Location and Geology

Block 64 EPSA was a block designated for exploration and production of non-associated gas and condensate which the Oman Ministry of Oil and Gas awarded over part of the area of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). PDO has the rights to the oil and associated gas on Block 64 EPSA and has continued to produce oil from several shallow oil fields within Block 64 EPSA area. The 955,600 acre block is located in the gas and condensate rich Ghaba Salt Basin in close proximity to the producing Barik, Saih Rawl and Saih Nihayda gas and condensate fields.

Drilling and Development Activity

In 2011, two exploratory wells were drilled, Mafraq South-1 (“MFS-1”) and Al Ghubar North-1 (“AGN-1”). Both wells were plugged and abandoned in the fourth quarter of 2011 and first quarter of 2012, respectively.

Operational activities during 2012 include post well evaluation and review of geological and geophysical data obtained from the drilling of MFS-1and AGN-1 wells.

On March 12, 2013, we elected to not request an extension of the First Phase or enter the Second Phase of Block 64 EPSA and Block 64 will be relinquished effective June 30, 2013. The carrying value of Block 64 EPSA of $6.4 million was written off to impairment expense at December 31, 2012. During the first half of 2013, we will terminate operations and close the field office.

WAB-21, South China Sea

General

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

Location and Geology

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

Drilling and Development Activity

Due to the border dispute between China and Vietnam, we have been unable to pursue an exploration program during Phase One of the contract. As a result, we have obtained license extensions, with the current extension in effect until May 31, 2013. The Joint Management Committee has approved an extension of the license until May 31, 2015. We are meeting with CNOOC in April 2013 to discuss the ratification of the extension. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist.

 

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

Production, Prices and Lifting Cost Summary

In the following table we have set forth, by country, our net production, average sales prices and average operating expenses for the years ended December 31, 2012, 2011 and 2010. The presentation for Venezuela is presented at our net 32 percent ownership interest in Petrodelta. The United States is presented at our ownership interest.

 

     Year Ended December 31,  
     2012      2011      2010  

Venezuela

        

Crude Oil Production (MBbls)(b)

     2,810         2,430         1,826   

Natural Gas Production (MMcf)(a)(c)

     463         483         470   

Average Crude Oil Sales Price ($ per Bbl)

   $ 95.91       $ 98.52       $ 70.57   

Average Natural Gas Sales Price ($ per Mcf)

   $ 1.54       $ 1.54       $ 1.54   

Average Operating Expenses ($ per BOE)(d)

   $ 10.22       $ 8.99       $ 6.01   

United States(e)

        

Monument Butte(e)

        

Net Crude Oil Production (MBbls)

     —           21         106   

Natural Gas Production (MMcf)

     —           324         417   

Average Crude Oil Sales Price ($ per Bbl)

   $ —         $ 77.91       $ 64.85   

Average Natural Gas Sales Price ($ per Mcf)

   $ —         $ 3.73       $ 3.43   

Average Operating Expenses ($ per BOE)

   $ —         $ 10.34       $ 4.26   

Lower Green River/Upper Wasatch(e)

        

Net Crude Oil Production (MBbls)

     —           40         34   

Natural Gas Production (MMcf)

     —           13         6   

Average Crude Oil Sales Price ($ per Bbl)

   $ —         $ 89.60       $ 69.63   

Average Natural Gas Sales Price ($ per Mcf)

   $ —         $ 4.62       $ 3.97   

Average Operating Expenses ($ per BOE)

   $ —         $ 56.86       $ 25.41   

 

(a) 

Royalty-in-kind paid on gas used as fuel by Petrodelta net to our 32 percent interest was 4,256 MMcf for 2012 (2011: 3,226 MMcf, 2010: 1,015 MMcf).

(b) 

Crude oil sales net to our 32 percent interest after deduction of royalty. Crude oil sales for Petrodelta at 100 percent were 13,172 MBbls for 2012 (2011: 11,390 MBbls, 2010: 8,561 MBbls).

(c) 

Natural gas sales net to our 32 percent interest after deduction of royalty. Natural gas sales for Petrodelta at 100 percent were 2,171 MMcf for 2012 (2011: 2,266 MMcf, 2010: 2,204 MMcf).

(d) 

Petrodelta is not subject to ad valorem or severance taxes. Average operating expenses per BOE net of royalties and workovers were $13.41 for 2012 (2011: $9.84 per BOE, 2010: $7.52 per BOE). See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations, Years Ended December 31, 2012 and 2011, Equity in Earnings from Equity Affiliates.

(e) 

Property was sold effective March 1, 2011 and is reported as discontinued operations.

Drilling and Undeveloped Acreage

For acquisitions of leases, development and exploratory drilling, we spent approximately (excluding our share of capital expenditures incurred by equity affiliates) $23.6 million in 2012 (2011: $106.1 million, 2010: $59.5 million). These numbers do not include any costs for the development of proved undeveloped reserves in 2012, 2011 or 2010.

 

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We have participated in the drilling of wells as follows:

 

     Year Ended December 31,  
     2012      2011      2010  
     Gross      Net      Gross      Net      Gross      Net  

Wells Drilled Productive:

                 

Venezuela (Petrodelta)

                 

Development

     12         3.8         15         4.8         16         5.1   

Appraisal

     —           —           1         0.3         —           —     

Gabon

                 

Exploration

     —           —           1         0.7         —           —     

United States

                 

Development

     —           —           1         0.7         8         2.6   

Exploration

     —           —           2         0.7         3         1.0   

Wells Drilled Dry:

                 

Indonesia

                 

Exploration

     —           —           2         1.3         —           —     

Oman

                 

Exploration

     1         0.8         1         0.8         —           —     

Average Depth of Wells (Feet)

                 

Venezuela (Petrodelta)

                 

Crude Oil

     7,905         —           7,298         —           6,839         —     

Indonesia

                 

Crude Oil

     —           —           9,874         —           —           —     

Gabon

                 

Crude Oil

     —           —           11,355         —           —           —     

Oman

                 

Natural Gas

     10,482         —           10,348         —           —           —     

United States

                 

Crude Oil

     —           —           10,021         —           7,938         —     

Natural Gas

     —           —           —        

 

—  

  

     —           —     

Producing Wells(1):

                 

Venezuela (Petrodelta)

                 

Crude Oil

     152         48.6         143         45.8         127         40.6   

United States

                 

Crude Oil

     —           —           —           —           16         8.3   

 

(1) 

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

At December 31, 2012, we were completing drilling activities on the DTM-1 on the Dussafu PSC. The DTM-1 was drilled to a depth of 11,260 feet. On January 12, 2013, we spud the DTM-1ST1. The DTM-1ST1 was drilled to a depth of 11,385 feet. We have 66.667 percent net interest in the DTM-1 and DTM-1ST1.

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

 

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Acreage

The following table summarizes the developed and undeveloped acreage that we own, lease or hold under concession as of December 31, 2012:

 

     Developed      Undeveloped  
     Gross      Net      Gross      Net  

Venezuela – Petrodelta

     26,460         8,467         220,653         70,609   

China

     —           —           7,470,080         7,470,080   

Indonesia

     —           —           747,862         481,623   

Gabon

     —           —           685,470         456,982   

Oman

     —           —           955,600         764,480   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     26,460         8,467         10,079,665         9,243,774   
  

 

 

    

 

 

    

 

 

    

 

 

 

Regulation

General

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

 

   

change in governments;

 

   

civil unrest;

 

   

price and currency controls;

 

   

limitations on oil and natural gas production;

 

   

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

 

   

changes in laws relating to the petroleum industry;

 

   

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

 

   

changes in contract interpretation and policies of contract adherence.

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

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 such oil and natural gas properties include staff and data necessary to identify, investigate and purchase such properties, the financial resources necessary to acquire and develop such 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.

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 gas industry in general, our business and financial results could be adversely affected.

 

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Employees

At December 31, 2012, full-time employees in our various offices were: Houston – 19; Caracas – 12; London – 9; Singapore – 2; Jakarta – 4; and Muscat – 6. We augment our employees from time to time with independent consultants, as required.

 

Item 1A. Risk Factors

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

Our financial condition raises substantial doubt as to our ability to continue as a going concern. The audit opinion on our financial statements as of and for the year ended December 31, 2012 includes an explanatory paragraph expressing substantial doubt regarding our ability to continue as a going concern. Our current capital resources may not be sufficient to support our liquidity requirements through 2013. 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 opportunities. At April 25, 2013, we had $30.7 million (December 31,2012: $72.6 million) of available cash and, until Petrodelta pays a dividend, our available cash may not be sufficient to meet capital and operational commitments for the next twelve months. We have no recurring cash flows. Having Petrodelta dividends as our primary source of cash flow limits our access to additional capital, and our concentration of political risk in Venezuela may limit our ability to leverage our assets. In addition, our future cash position depends upon the payment of dividends by Petrodelta, success with our exploration program, possible delay of discretionary capital spending to future periods, farm-out, or possible sale, or otherwise monetization of assets as necessary to maintain the liquidity required to run our operations. While we believe that Petrodelta will reinvest any excess cash into Petrodelta in 2013 and 2014 which might otherwise be available for payment of dividends, there is no assurance this will be the case, nor that if the cash is not reinvested that it will be paid as dividends. These factors could have a material adverse effect on our financial condition and liquidity and may limit our ability to grow through the acquisition or exploration of additional oil and gas properties and projects.

Our business strategy may be sensitive to market prices for oil and gas. We have made significant investments to provide the foundation and global reach required for an organic growth focus. While exploration has become a larger part of our overall portfolio, to the extent market values of oil and gas decline, our continued investments in exploration projects may be adversely affected.

We have incurred long-term indebtedness obligations, which significantly increased our leverage. On October 11, 2012, we closed a debt offering of $79.8 million in aggregate principal amount of 11.0 percent senior unsecured notes due October 11, 2014. The degree to which we are leveraged could, among other things:

 

   

make it difficult for us to make payments on the debt;

 

   

make it difficult for us to obtain financing for working capital, acquisitions or other purposes on favorable terms, if at all;

 

   

make us more vulnerable to industry downturns and competitive pressures; and

 

   

limit our flexibility in planning for, or reacting to, changes in our business.

Our ability to meet our debt service obligation will depend upon our future performance, which will be subject to financial, business and other factors affecting our operations, many of which are beyond our control.

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.

 

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

Our strategy to identify, access and integrate hydrocarbon assets in known hydrocarbon basins globally carries 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 strategy depends on our ability to have significant influence over operations and financial control.

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

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

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

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

An increase in oil prices could result in increased tax liability in Venezuela affecting Petrodelta’s operations and profitability, which in turn could affect our dividends and profitability. Prices for oil fluctuate widely. In April 2011, the Venezuelan government published the amended Windfall Profits Tax which establishes a special contribution for extraordinary prices to the Venezuelan government of 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $50 per barrel for 2012 [$55 per barrel for 2013]) and $70 per barrel. The amended Windfall Profits Tax also establishes a special contribution for exorbitant prices to the Venezuelan government of (1) 80 percent when the average price of the Venezuelan Export Basket (“VEB”) exceeds $70 per barrel but is less than $90 per barrel; (2) 90 percent when the average price of the VEB exceeds $90 per barrel but is less that $100 per barrel; and (3) 95 percent when the average price of the VEB exceeds $100 per barrel. Any increase in the taxes payable by Petrodelta, including the Windfall Profits Tax, as a result of increased oil prices will reduce cash available for dividends to us and our partner, CVP.

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

 

   

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

 

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export quotas;

 

   

market uncertainty;

 

   

the level of consumer product demand;

 

   

weather conditions;

 

   

domestic and foreign governmental regulations and policies;

 

   

the price and availability of alternative fuels;

 

   

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

 

   

overall economic conditions.

The total capital required for development of Petrodelta’s assets may exceed the ability of Petrodelta to finance such developments. Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Petrodelta’s future capital requirements for the development of its assets may exceed the cash available from existing cash flow. Petrodelta’s ability to secure financing is currently limited and uncertain, and has been, and may be, affected by numerous factors beyond its control, including the risks associated with operating in Venezuela. Because of this financial risk, Petrodelta may not be able to secure either the equity or debt financing necessary to meet its future cash needs for investment, which may limit its ability to fully develop the properties, cause delays with their development or require early divestment of all or a portion of those projects. This could negatively impact our minority equity investment. If we are called upon to fund our share of Petrodelta’s operations, our failure to do so could be considered a default under the Conversion Contract and cause the forfeiture of some or all our shares in Petrodelta. In addition, CVP may be unable or unwilling to fund its share of capital requirements and our ability to require them to do so is limited. Since Petrodelta only executed approximately 45.8 percent its 2012 proposed capital expenditures primarily due to insufficient monetary support and contractual adherence by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2013 budget. Should PDVSA continue in insufficient monetary support and contractual adherence of Petrodelta, underinvestment in the development plan may lead to continued under-performance.

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

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

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

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

 

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reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth. Actual production, revenue, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used, and these variances may be material.

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

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

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

 

   

shortages or delays in the delivery of equipment;

 

   

shortages in experienced labor;

 

   

pressure or irregularities in formations;

 

   

unexpected drilling conditions;

 

   

equipment or facilities failures or accidents;

 

   

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

 

   

government actions or changes in regulations;

 

   

delays in receiving necessary governmental permits;

 

   

delays in receiving partner approvals; and

 

   

weather conditions.

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

 

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

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

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

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

 

   

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

 

   

response to unexpected releases to the environment;

 

   

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

 

   

taxation.

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

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

 

   

fires and explosions;

 

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blow-outs;

 

   

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

 

   

adverse weather conditions or natural disasters;

 

   

pipe or cement failures and casing collapses;

 

   

pipeline ruptures;

 

   

discharges of toxic gases;

 

   

build up of naturally occurring radioactive materials; and

 

   

vandalism.

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

 

   

injury or loss of life;

 

   

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

 

   

pollution and other environmental damage;

 

   

investigatory and clean-up responsibilities;

 

   

regulatory investigation and penalties;

 

   

suspension of our operations; and

 

   

repairs to resume operations.

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

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

Competition within the industry may adversely affect our operations. We operate in a highly competitive environment. We compete with major, national and independent oil and natural gas companies for the acquisition of desirable oil and natural gas properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours.

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

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

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

Our business is dependent upon the proper functioning of our internal business processes and information systems and modification or interruption of such systems may disrupt our business, processes and internal controls. The proper functioning of our internal business processes and information systems is critical to the efficient operation and management of our business. If these information technology systems fail or are interrupted, our operations may be adversely affected and operating results could be harmed. Our business

 

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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.

We have identified material weaknesses in our internal control over financial reporting. We have concluded we did not maintain effective internal controls over financial reporting because material weaknesses in internal control over financial reporting related to (1) a sufficient complement of accounting and financial reporting resources; (2). accounting for certain transactions for oil and gas properties; (3) accounting for income taxes; (4) appropriate segregation of duties related to certain system access rights and the recording and review of journal entries; (5) preparation and review of certain classification and disclosure matters impacting the financial statements and related notes; and (6) significant and complex debt and equity transactions existed as of December 31, 2012. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement in our annual or interim financial statements will not be prevented or detected and corrected on a timely basis.

Although we intend to take appropriate steps to remediate these material weaknesses, we cannot assure you that we will be able to do so in a timely manner, that our initiatives will prove to be successful or that additional material weaknesses will not be identified in the future. Failure to identify material weaknesses in our internal controls in a timely manner, or the identification of material weaknesses in the future, will impair our ability to record, process, summarize and report financial information accurately, timely and in accordance with SEC rules. The failure could also cause investors to lose confidence in our reported financial information, subject us to litigation and regulatory enforcement actions, and adversely impact our business and financial condition.

 

Item 1B. Unresolved Staff Comments

None.

 

Item 2. Properties

We have regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Indonesia; Port Gentil, Gabon; and Muscat, Oman to support field operations in those areas. At December 31, 2012, we had the following lease commitments for office space:

 

Location

   Date
Lease Signed
   Term      Annual
Expense
 

Houston, Texas

   April 2004      10 years       $ 204,000   

Houston, Texas

   December 2008      5 years         160,800   

Caracas, Venezuela

   October 2012      1 year         224,400   

London, U.K.

   September 2010      5 years         108,000   

Singapore

   October 2012      2 years         84,000   

Jakarta, Indonesia

   April 2012      2 years         98,500   

Muscat, Oman

   September 2011      2 years         62,400   

Gabon, Port Gentil

   December 2012      2 years         61,200   

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

 

Item 3. Legal Proceedings

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); 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. On April 18, 2013, the second, third and fourth listed actions were consolidated into the Phillips case. The Company and the other named defendants intend to vigorously defend the consolidated and other listed lawsuits.

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

In June 2012, the operator of the Budong PSC received notice of a claim related to the ownership of part of the land comprising the Karama-1 (“KD-1”) drilling site. The claim asserts that the land on which the drill site is located is partly owned by the claimant. The operator purchased the site from local landowners in January 2010, and the purchase was approved by BPMIGAS, Indonesia’s oil and gas regulatory authority. The claimant is seeking compensation of 16 billion Indonesia Rupiah (approximately $1.7 million, $1.2 million net to our 71.61 percent cost sharing interest) for land that was purchased at a cost of $4,100 in January 2010. On or about March 8, 2013, the operator learned that the court has ruled to dismiss the claim because the claim had not been filed against the proper parties to the claim. The claimant can appeal the dismissal once the ruling has been issued in writing.

In May 2012, Newfield Production Company (“Newfield”) filed notice pursuant to the Purchase and Sale Agreement between Harvest (US) Holdings, Inc. (“Harvest US”), a wholly owned subsidiary of Harvest, and Newfield dated March 21, 2011 (the “PSA”) of a potential environmental claim involving certain wells drilled on the Antelope Project. The claim asserts that locations constructed by Harvest US were built on, within, or otherwise impact or potentially impact wetlands and other water bodies. The notice asserts that to the extent of potential penalties or other obligations that might result from potential violations that Harvest US indemnifies Newfield pursuant to the PSA. In June 2012, we provided Newfield with notice pursuant to the PSA (1) denying that Newfield has any right to indemnification from us, (2) alleging that any potential environmental claim related to Newfield’s notice would be an assumed liability under the PSA and (3) asserting that Newfield indemnify us pursuant to the PSA. We dispute Newfield’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.

 

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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. As of May 2, 2013, our October 26, 2011 application for the return of the blocked funds remains pending with OFAC.

Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc., Branta Exploration & Production, LLC, Ute Energy LLC, Cameron Cuch, Paula Black, Johnna Blackhair, and Elton Blackhair in the United States District Court for the District of Utah. This suit was served in April 2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the defendants, among other things, intentionally interfered with Plaintiffs’ employment agreement with the Ute Indian Tribe – Energy & Minerals Department and intentionally interfered with Plaintiffs’ prospective economic relationships. Plaintiffs seek actual damages, punitive damages, costs and attorney’s fees. We dispute Plaintiffs’ claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.

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

 

   

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

 

   

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

 

   

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

 

   

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

Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s, the Venezuelan income tax authority, interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.

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

 

   

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

 

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

 

   

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

Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the refund of all municipal taxes paid since 2002.

On May 4, 2012, Harvest Vinccler learned that the Political Administrative Chamber of the Supreme Court of Justice has issued a decision dismissing one of Harvest Vinccler’s claims against the Libertador Municipality. Harvest Vinccler continues to believe that it has sufficient arguments to maintain its position in accordance with the Venezuelan Constitution. Harvest Vinccler plans to present a request of Constitutional Revision to the Constitutional Chamber of the Supreme Court of Justice once it is notified officially of the decision. As of May 2, 2013, Harvest Vinccler has not received official notification of the decision. Harvest Vinccler is unable to predict the impact of this decision on the remaining outstanding municipality claims and assessments.

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

 

Item 4. Mine Safety Disclosures

Not applicable.

 

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PART II

 

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

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HNR”. As of December 31, 2012, there were 39,434,279 shares of common stock outstanding, with approximately 433 stockholders of record. The following table sets forth the high and low sales prices for our Common Stock reported by the NYSE.

 

Year

   Quarter    High      Low  

2011

   First quarter      16.75         10.59   
   Second quarter      15.71         10.51   
   Third quarter      13.81         8.57   
   Fourth quarter      12.04         6.58   

2012

   First quarter      8.27         6.14   
   Second quarter      9.12         4.88   
   Third quarter      9.85         7.72   
   Fourth quarter      9.50         8.38   

On April 24, 2013, the last sales price for the common stock as reported by the NYSE was $3.46 per share.

Our policy is to retain earnings to support the growth of our business. Accordingly, our Board of Directors has never declared a cash dividend on our common stock.

STOCK PERFORMANCE GRAPH

The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2012, assuming an investment of $100 on December 31, 2007 in each of Harvest’s common stock, the Dow Jones U.S. Exploration & Production Index and the S&P Composite 500 Stock Index.

This graph assumes that the value of the investment in Harvest stock and each index was $100 at December 31, 2007 and that all dividends were reinvested.

 

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LOGO

PLOT POINTS

(December 31 of each year)

 

     2007      2008      2009      2010      2011      2012  

Harvest Natural Resources, Inc.

   $ 100       $ 34       $ 42       $ 97       $ 59       $ 73   

Dow Jones US E&P Index

   $ 100       $ 58       $ 82       $ 98       $ 96       $ 100   

S&P 500 Index

   $ 100       $ 63       $ 80       $ 92       $ 94       $ 109   

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

 

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Item 6. Selected Financial Data

SELECTED CONSOLIDATED FINANCIAL DATA

The following table sets forth our selected consolidated financial data for each of the years in the five-year period ended December 31, 2012.

 

    Year Ended December 31,  
    2012     2011
(RESTATED)
    2010
(RESTATED)
    2009(3)
(RESTATED)
    2008(3)
(RESTATED)
 
    (in thousands, except per share data)  

Consolidated Statements of Operations and Comprehensive Income (Loss):

         

Operating loss

  $   (51,517   $   (88,512   $   (34,716   $   (30,644   $   (54,779

Net income from Equity Affiliates

    67,769        73,451        66,291        35,253        33,226   

Net income (loss) from continuing operations(1)

    (10,512     (41,656     10,663        (3,326     (22,883

Net income (loss) attributable to Harvest

    (12,211     55,960        14,375        (3,568     (23,179

Net income (loss) from continuing operations attributable to Harvest per common share:

         

Basic(1)

  $ (0.28   $ (1.22   $ 0.32      $ (0.10   $ (0.68
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted(1)

  $ (0.28   $ (1.22   $ 0.29      $ (0.10   $ (0.68
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average common shares outstanding

         

Basic

    37,424        34,117        33,541        33,084        34,073   

Diluted

    37,424        34,117        36,767        33,084        34,073   

 

    As of December 31,  
    2012     2011
(RESTATED)
    2010
(RESTATED)
    2009(4)
(RESTATED)
    2008(4)
(RESTATED)
 
    (in thousands)  

Balance Sheet Data:

         

Total assets

  $  596,837      $  507,203      $  484,622      $  345,214      $  359,263   

Long-term debt, net of current maturities

    74,839        31,535        78,291        —          —     

Total Harvest’s Stockholders’ equity(2)

    379,337        355,691        291,727        271,603        270,713   

 

(1) 

Includes net income attributable to noncontrolling interest.

(2)

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

(3)

For 2009, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense of $58 thousand. For 2008, relates to lease maintenance costs that were erroneously capitalized as oil and gas properties rather than as exploration expense of $635 thousand.

(4) 

Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense of $693 thousand in 2009 and $635 thousand in 2008.

 

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

Operations

We had a net loss attributable to Harvest of $12.2 million, or $(0.33) per diluted share, for the year ended December 31, 2012 compared to net income attributable to Harvest of $56.0 million, or $1.64 per diluted share, for the year ended December 31, 2011. Net loss attributable to Harvest for the year ended December 31, 2012 includes $9.1 million of exploration expense, $9.3 of impairment expense, $5.6 million of dry hole costs and net equity income from Petrodelta’s operations of $67.8 million. Net income attributable to Harvest for the year ended December 31, 2011 includes $12.6 million of exploration expense, $3.3 million of impairment expense, $49.7 million of dry hole costs and net equity income from Petrodelta’s operations of $73.5 million.

Restatement of Prior Period Financial Statements

                  In connection with the preparation of our Annual Report on Form 10-K for the year ended December 31, 2012, we concluded that there were errors in previously filed financial statements. In the course of our review, management determined that (a) certain warrants issued in 2010 in connection with our $60 million term loan facility (the “Warrants”) were improperly valued at inception and improperly classified as equity instruments rather than liability instruments. As a result of the improper classification of the Warrants, (b) the debt discount and associated interest expense related to the amortization of the debt discount was understated for all periods in which the associated debt was outstanding, and (c) the consolidated statement of operations and comprehensive income (loss) for each reporting period was misstated by the omission of the changes in fair value of the Warrants as a liability instrument. Additionally, (d) certain exploration overhead was incorrectly capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed, and (e) certain leasehold maintenance and other costs were improperly capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed. Finally, (f) advances to equity affiliate were improperly classified as an operating activity rather than an investing activity and (g) certain costs were improperly classified as an investing activity rather than an operating activity on the consolidated statement of cash flows. Such errors impacted annual periods ended December 31, 2010 and 2011 and quarterly periods ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012, and September 30, 2012.

As a result of the errors related to the Warrants described above, loss on extinguishment of debt was understated for the year ended December 31, 2011 and the quarters ended June 30, 2011, September 30, 2011 and December 31, 2011.

Additionally, an error was identified in the calculation of earnings (loss) per diluted share for the year ended December 31, 2011 and the three and six months ended June 30, 2011, and an additional error was identified related to the improper expensing of costs associated with debt conversions that should have been recorded to equity for the quarters ended March 31, 2012 and September 30, 2012.

We have restated our segment footnote information to reflect the applicable errors stated above and (a) reclassify noncontrolling interest from United States segment to Venezuela segment, (b) eliminate intrasegment receivables erroneously reported gross of related intrasegment payable, and (c) eliminate intrasegment revenue erroneously reported gross of related intrasegment expense. Such errors impacted annual periods ended December 31, 2010 and 2011 and quarterly periods ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012 and September 30, 2012. We also restated our financial statement schedule to reflect adjustments to the balance sheet related to income taxes for the years ended December 31, 2010 and 2011.

In assessing the severity of the errors, management determined that the errors were material to the consolidated financial statements for the years ended December 31, 2011 and 2010 and quarterly information for all quarters in 2011 and the first, second and third quarters of 2012. In addition to the errors described above, we made corrections for previously identified immaterial errors and errors affecting classification within the consolidated statement of operations and comprehensive income (loss) related to impairment of oil and gas properties and income taxes and the consolidated balance sheets related to income taxes.

The audited financial statements, related notes and analyses for the years ended December 31, 2011 and 2010 have been retrospectively restated in this Annual Report on Form 10-K for the year ended December 31, 2012. We will amend our Quarterly Reports on Form 10-Q/A for each of the quarterly periods shortly after the filing of this Annual Report on Form 10-K.

The following tables set forth the effect of the adjustments described above on the consolidated statements of operations and comprehensive income (loss), the consolidated statements of cash flows and the consolidated statements of stockholders’ equity for the years ended December 31, 2011 and 2010, and the consolidated balance sheet as of December 31, 2011.

 

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Consolidated Statements of Operations and Comprehensive Income (Loss)

 

     December 31, 2011     December 31, 2010  
     As Previously          

As

   

As Previously

          As  
     Reported     Adjustment     RESTATED     Reported     Adjustment     RESTATED  
     (in thousands)  

Expenses

            

Depreciation and amortization

   $ 462      $ —        $ 462      $ 484      $ —        $ 484   

Exploration expense(a)

     13,690        (1,125     12,565        8,016        313        8,329   

Impairment of oil and gas properties(f)

     —          3,335        3,335        —          —          —     

Dry hole costs

     49,676        —          49,676        —          —          —     

General and administrative

     22,474        —          22,474        25,903        —          25,903   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

     86,302        2,210        88,512        34,403        313        34,716   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Loss from operations

     (86,302     (2,210     (88,512     (34,403     (313     (34,716

Other non-operating income (expense)

            

Investment earnings and other

     665        —          665        557        —          557   

Unrealized gain (loss) on warrant derivatives(b)

     —          9,786        9,786        —          344        344   

Interest expense(c)

     (5,336     (1,823     (7,159     (2,689     (1,098     (3,787

Loss on extinguishment of debt(d)

     (9,682     (3,450     (13,132     —          —          —     

Other non-operating expense

     (1,375     —          (1,375     (3,952     —          (3,952

Loss on exchange rates

     (146     —          (146     (1,588     —          (1,588
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
     (15,874     4,513        (11,361     (7,672     (754     (8,426
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Loss from Continuing Operations Before Income taxes

     (102,176     2,303        (99,873     (42,075     (1,067     (43,142

Income tax expense (benefit)(g)

     820        237        1,057        (184     —          (184
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Loss from Continuing Operations

     (102,996     2,066        (100,930     (41,891     (1,067     (42,958

Net Income from Equity Affiliate

     73,451        —          73,451        66,291        —          66,291   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income (Loss) from Continuing Operations

     (29,545     2,066        (27,479     24,400        (1,067     23,333   

Income (Loss) from Discontinued Operations

     97,616        —          97,616        3,712        —          3,712   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income

     68,071        2,066        70,137        28,112        (1,067     27,045   

Less: Net Income Attributable to Noncontrolling Interest

     14,177        —          14,177        12,670        —          12,670   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income (Loss) Attributable To Harvest

   $ 53,894      $ 2,066      $ 55,960      $ 15,442      $ (1,067   $ 14,375   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income (Loss) Attributable to Harvest Per Common Share:

            

Basic

   $ 1.58      $ 0.06      $ 1.64      $ 0.46      $ (0.03   $ 0.43   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted(e)

   $ 1.37      $ 0.27      $ 1.64      $ 0.42      $ (0.03   $ 0.39   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income (loss)

   $ 53,894      $ 2,066      $ 55,960      $ 15,442      $ (1,067   $ 14,375   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense of $2,210 thousand offset by a reclassification from exploration expense to impairment of oil and gas properties of $3,335 thousand for amounts that were erroneously classified as exploration expense. For 2010, relates to lease maintenance costs that were erroneously capitalized as oil and gas properties rather than as exploration expense.
(b) Represents change in fair value of the Warrants for the period. Such Warrants were previously erroneously classified as equity and were, therefore, not marked to market at the end of each reporting period.
(c) The fair value of the Warrants was not appropriately determined at inception because certain features of the Warrants were not originally considered in the fair value calculation. The corrected fair value of the Warrants at inception exceeds the original valuation by $3,878 thousand. As a result of this change in the fair value of the Warrants, the original discount allocated to the debt was understated by approximately $3,878 thousand; therefore, the additional amortization of the discount on debt, which is a component of interest expense, was understated for each period the debt was outstanding. For 2011, income tax expense of $237 thousand was improperly classified as interest expense.
(d) As noted in (c) above, the correction in the fair value of the Warrants and its classification as a liability resulted in an increased discount on debt which also impacted the resulting loss on extinguishment of debt originally recorded in May 2011 when the debt was retired.
(e) In addition to the impact on EPS related to the adjustments described in (a) through (d) above and (f) and (g) below, diluted EPS has been adjusted to reflect an error in the calculation of the weighted average common shares outstanding for dilutive EPS as of December 31, 2011. The weighted average common shares utilized for the calculation of diluted EPS was erroneously 39,339 thousand rather than 34,117 thousand.
(f) Reclassification of impairment of oil and gas properties expense in 2011 of $3,335 thousand that was previously erroneously presented as exploration expense.
(g) Represents income tax improperly classified as interest expense.

Consolidated Balance Sheets

 

     December 31, 2011  
     As  Previously
Reported
     Adjustment     As
RESTATED
 
     (in thousands)  

Deferred income taxes(a)

   $ 2,628       $ (2,628   $ —     

Oil and gas properties(b)

     65,671         (3,216     62,455   

Total assets(a)(b)

     513,047         (5,844     507,203   

Accrued interest payable(g)

     1,372         (396     976   

Other current liabilities(a)(g)

     4,835         (2,203     2,632   

Income taxes payable(g)

     718         (29     689   

Warrant derivative liability(c)

     —           4,870        4,870   

Total liabilities(a)(c)(g)

     65,592         2,242        67,834   

Additional paid in capital(d)

     236,192         (8,392     227,800   

Retained earnings(e)

     193,283         306        193,589   

Total Harvest shareholders’ equity(f)

     363,777         (8,086     355,691   

Total equity(f)

     447,455         (8,086     439,369   

 

(a) Relates to a deferred tax asset that was erroneously reported gross of the related liability.
(b) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense.
(c) Relates to the reclassification of the Warrants out of additional paid in capital to warrant derivative liabilities. The fair value of the Warrants was not appropriately determined at inception because certain features of the Warrants were not originally considered in the fair value calculation. Thus, the correction of the error to record the Warrants as a liability does not agree to the correction of the error removing the Warrants from equity. Additionally, the Warrants were not properly marked to market at the end of each period. The warrant derivative liability was valued at $15,000 thousand at inception with subsequent reductions in fair value of $344 thousand in 2010 and $9,786 thousand in 2011.
(d) Relates to the reversal of the amount recorded to equity at inception for the Warrants of $11,122 thousand and the reversal of the amount removed from additional paid in capital of $2,730 thousand when a portion of the Warrants were redeemed by the Company. In May 2011, additional paid in capital was debited for $2,730 thousand for the reversal of the original fair value of such warrants which was an error as they did not qualify for equity classification.
(e) Relates to (a) net increase in expense in 2010 and 2011 related to exploration expense of $2,523 thousand (inclusive of the reclassification of exploration expense to impairment of oil and gas properties of $3,335 thousand), (b) net increase in unrealized gain on warrant derivatives of $10,130 thousand for cumulative 2010 and 2011, (c) net increase in interest expense of $2,921 thousand cumulative for 2010 and 2011, (d) net increase in loss on extinguishment of debt of $3,450 thousand for 2011 (e) net increase in income tax expense of $237 thousand for income taxes improperly classified as interest expense, offset by a reduction to retained earnings of $693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than expensed prior to January 1, 2010.
(f) Relates to reclassification of the Warrants as described in (d) above plus the impact of retained earnings described in (e) above.
(g) Represents other current liabilities that were improperly classified as interest payable and income taxes payable.

 

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Consolidated Statements of Cash Flows

 

     December 31, 2011     December 31, 2010  
     As Previously           As     As Previously           As  
     Reported     Adjustment     RESTATED     Reported     Adjustment     RESTATED  
     (in thousands)  

Net cash used in operating activities(a)(b)

   $ (52,737   $ (2,506   $ (55,243   $ (5,296   $ (2,830   $ (8,126

Net cash provided by (used in) investing activities(a)(b)

     109,710        2,506        112,216        (59,061     2,830        (56,231

Net cash provided by (used in) financing activities

     (56,730     —          (56,730     90,743        —          90,743   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net increase in cash and cash equivalents

     243        —          243        26,386        —          26,386   

Cash and cash equivalents at beginning of year

     58,703        —          58,703        32,317        —          32,317   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of year

   $ 58,946      $ —        $ 58,946      $ 58,703      $ —        $ 58,703   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) For 2011, relates to the $2,288 thousand of lease maintenance costs, exploration overhead and $900 thousand of certain investment costs that were improperly classified as an investing activity rather than an operating activity. In addition, Advances to Equity Affiliates of $(682) thousand were previously erroneously classified as an operating activity rather than an investing activity.
(b) For 2010, relates to $167 thousand of lease maintenance costs and $(558) thousand of certain investment costs that were improperly classified as an investing activity rather than an operating activity. In addition, Advances to Equity Affiliates of $3,221 thousand were improperly classified as an operating activity rather than an investing activity.

In addition to the above, we have restated the Consolidated Statements of Stockholder’s Equity to reflect the reclassification of the Warrants from equity to warrant derivative liability and to restate the January 1, 2010 beginning balances to reflect cumulative adjustments related to the previously described errors that affect periods prior to the year ended December 31, 2010 as follows:

 

     Common
Shares
Issued
     Common
Stock
     Additional
Paid-in
Capital
     Retained
Earnings
    Treasury
Stock
    Non-
Controlling
Interest
     Total
Equity
 

Balance at January 1, 2010 as originally reported

     39,495       $ 395       $ 213,337       $ 123,947      $ (65,383   $ 56,831       $ 329,127   

Adjustments(a)

     —           —           —           (693     —          —           (693
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Balance at January 1, 2010 as RESTATED

     39,495       $ 395       $ 213,337       $ 123,254      $ (65,383   $ 56,831       $ 328,434   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

 

(a) Relates to lease maintenance costs that were erroneously capitalized as oil and gas properties rather than expensed prior to January 1, 2010 (the “Beginning Retained Earnings Adjustment”).

 

     Common
Shares
Issued
     Common
Stock
     Additional
Paid-in
Capital
    Retained
Earnings
    Treasury
Stock
    Non-
Controlling
Interest
     Total
Equity
 

Balance at December 31, 2010 as originally reported

     40,103       $ 401       $ 230,362      $ 139,389      $ (65,543   $ 69,501       $ 374,110   

Adjustments(a)(b)

     —           —           (11,122     (1,760     —          —           (12,882
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Balance at December 31, 2010 as RESTATED

     40,103       $ 401       $ 219,240      $ 137,629      $ (65,543   $ 69,501       $ 361,228   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

 

(a) The adjustment to additional paid-in capital relates to the reclassification of the Warrants from equity to warrant derivative liability.
(b) The adjustment to retained earnings relates to (a) lease maintenance costs of $313 thousand that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense, (b) the reduction in the fair value of the Warrants for the year ended December 31, 2010 of $344 thousand, additional amortization of debt of $1,098 thousand resulting from the increased discount allocated to the debt, offset by a reduction to retained earnings of $693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized to oil and gas properties rather than expensed to exploration expenses prior to January 1, 2010.

 

     Common
Shares
Issued
     Common
Stock
     Additional
Paid-in
Capital
    Retained
Earnings
     Treasury
Stock
    Non-
Controlling
Interest
     Total
Equity
 

Balance at December 31, 2011 as originally reported

     40,625       $ 406       $ 236,192      $ 193,283       $ (66,104   $ 83,678       $ 447,455   

Adjustments(a)(b)

     —           —           (8,392     306         —          —           (8,086
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Balance at December 31, 2011 as RESTATED

     40,625       $ 406       $ 227,800      $ 193,589       $ (66,104   $ 83,678       $ 439,369   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

 

(a) The adjustment to additional paid-in capital relates to the reclassification of the Warrants from equity to warrant derivative liability of $11,122 thousand offset by an error recorded in 2011 for $2,730 thousand for the reversal of the original fair value of certain Warrants that did not qualify for equity classification.
(b) The adjustment to retained earnings relates to (a) net increase in 2010 and 2011 expense related to exploration expense of $2,523 thousand that was erroneously capitalized as oil and gas properties rather than expensed as exploration expense (includes consideration of reclassification between exploration expense and impairment of oil and gas properties), (b) net increase in unrealized gain on warrant derivatives of $10,130 thousand for cumulative 2010 and 2011, (c) net increase in interest expense of $2,921 thousand cumulative for 2010 and 2011, (d) net increase in loss on extinguishment of debt of $3,450 thousand for 2011, (e) net increase in income tax expense of $237 thousand for income taxes improperly classified as interest expense, offset by a reduction to retained earnings of $693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than expensed prior to January 1, 2010.

In addition to the above, we have restated Operating Segments to reflect the errors stated above and (a) reclassify noncontrolling interest from United States segment to Venezuela segment, (b) eliminate intrasegment receivables erroneously reported gross of related intrasegment payable, and (c) eliminate intrasegment revenue erroneously reported gross of related intrasegment expense.

 

     December 31, 2011     December 31, 2010  
     As Previously
Reported
    Adjustments     As
Restated
    As Previously
Reported
    Adjustments     As
Restated
 

Segment Income (Loss) Attributable to Harvest

            

Venezuela(a)

   $ 69,577      $ (14,603   $ 54,974      $ 62,177      $ (13,019   $ 49,158   

Indonesia(b)

     (44,800     (2,888     (47,688     (7,108     843        (6,265

Gabon(c)

     (5,743     (2,245     (7,988     (543     (1,099     (1,642

Oman(d)

     (11,325     (535     (11,860     (1,934     (305     (2,239

United States(e)

     (51,431     22,337        (29,094     (40,862     12,513        (28,349
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) from continuing operations

     (43,722     2,066        (41,656     11,730        (1,067     10,663   

Discontinued operations (Antelope Project)

     97,616        —          97,616        3,712        —          3,712   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to Harvest

   $ 53,894      $ 2,066      $ 55,960      $ 15,442      $ (1,067   $ 14,375   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) Relates to reclassification of noncontrolling interest from United States segment to Venezuela segment and elimination of intrasegment revenue erroneously reported gross of intrasegment expense.
(b) For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense of $1,505 thousand and elimination of intrasegment revenue erroneously reported gross of related intrasegment expense of $1,383 thousand. For 2010, relates to elimination of intrasegment revenue erroneously reported gross of related intrasegment expense.
(c) For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense of $415 thousand and elimination of intrasegment revenue erroneously reported gross of related intrasegment expense of $1,830 thousand. For 2010, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense of $313 thousand and elimination of intrasegment revenue erroneously reported gross of related intrasegment expense of $786 thousand.
(d) Relates to elimination of intrasegment revenue erroneously reported gross of related intrasegment expense.
(e) Relates to the impact of (a) through (d) above.

 

     December 31, 2011  
     As Previously
Reported
    Adjustment     As
RESTATED
 
    

(in thousands)

 

Operating Segment Assets

      

Venezuela

   $ 348,802      $ —        $ 348,802   

Indonesia(a)

     65,165        (50,572     14,593   

Gabon(a)

     119,273        (63,768     55,505   

Oman(a)

     20,980        (13,828     7,152   

United States(a)

     137,531        122,325        259,856   
  

 

 

   

 

 

   

 

 

 
     691,751        (5,843     685,908   

Intersegment eliminations

     (178,704     (1     (178,705
  

 

 

   

 

 

   

 

 

 

Total Assets

   $ 513,047      $ (5,844   $ 507,203   
  

 

 

   

 

 

   

 

 

 

 

(a) Relates to elimination of intrasegment receivables erroneously reported gross of related intrasegment payable.

Venezuela

Harvest Vinccler’s and Petrodelta’s functional and reporting currency is the U.S. Dollar. They do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”) (4.30 Bolivars per U.S. Dollar). However, during the year ended December 31, 2012, Harvest Vinccler exchanged approximately $1.5 million (2011: $1.2 million) through the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) and received an average exchange rate of 5.16 Bolivars (2011: 5.19 Bolivars) per U.S. Dollar. Harvest Vinccler currently does not have any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. Petrodelta does not have, and has not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate.

The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals

 

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and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. At December 31, 2012, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 6.2 million Bolivars and 5.7 million Bolivars, respectively. At December 31, 2012, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 277.2 million Bolivars and 2,646.2 million Bolivars, respectively.

On February 8, 2013, the Venezuelan government published in the Official Gazette the Exchange Agreement No. 14 which establishes new exchange rates for the Bolivar/U.S. Dollar currencies that became effective February 9, 2013. The exchange rate established in the Agreement is 6.30 Bolivars per U.S. Dollar. The Exchange Agreement also announced the elimination of SITME effective February 8, 2013. All exchanges of Bolivars must now transact through the Central Bank. As a result of the February 2013 devaluation, Harvest Vinccler estimates the impact of the devaluation to be approximately $0.1 million gain on revaluation of its assets and liabilities, and Petrodelta estimates the impact of the devaluation to be approximately $54.8 million gain on revaluation of its assets and liabilities.

On May 7, 2012, the Organic Law on Employment, Male and Female Workers (“Labor Law”) was published in the Official Gazette. The Labor Law has 554 Articles divided into ten Titles and heavily favors employees over employers. The Labor Law’s purpose is to regulate the relations between workers and employers. In August 2012, the labor contract between PDVSA and the labor union was signed. The new labor contract awarded salary increases to both union and non-union labor retroactive to December 2011. The new labor contract increased the effect of the Labor Law on Petrodelta by increasing the salaries on which the Labor Law benefits are calculated. Per the actuarial study that PDVSA commissioned, the effect of the Labor Law on Petrodelta’s business was $3.8 million ($1.2 million net to our 32 percent interest) for the year ended December 31, 2012. The Labor Law had no impact to Harvest Vinccler.

Petrodelta

See Item 1. Business, Operations, Petrodelta, Share Purchase Agreement (“SPA”).

Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Petrodelta’s 2012 capital budget was expected to be approximately $401.9 million with a significant portion of that total related to infrastructure costs to support the further development of the Temblador and El Salto fields.

Petrodelta began 2012 with three drilling rigs, but PDVSA relocated one rig to another operation. Currently, Petrodelta is operating three drilling rigs and two workover rigs and is continuing with infrastructure enhancement projects in the El Salto and Temblador fields. A pipeline is currently under construction between the Isleño field and the main production facility at Uracoa. Isleño production is currently being trucked to Uracoa. Petrodelta has received two new drilling rigs. The first drilling rig is currently waiting on repairs and is expected to start drilling operations in the Isleño field in the first quarter of 2013. The second drilling rig has been mobilized and is expected to start drilling operations in the Temblador field in the first quarter of 2013. Petrodelta was notified that it will relocate a current operating rig to another operation with the old rig being replaced with a new rig which arrived in February 2013. These rigs result in an expected five working drilling rigs in 2013.

During the year ended December 31, 2012, Petrodelta drilled and completed 12 development wells compared to 15 development wells, one successful appraisal well and two water injector wells in the year ended December 31, 2011. Petrodelta delivered approximately 13.2 MBls of oil and 2.2 billion cubic feet (“Bcf”) of natural gas, averaging 36,979 barrels of oil equivalent (“BOE”) per day during the year ended December 31, 2012 compared to deliveries of 11.4 MBls of oil and 2.3 Bcf of natural gas, averaging 32,240 BOE per day during the year ended December 31, 2011.

Petrodelta’s Proved reserves, net to our 32 percent interest, are 38.4 MMBOE at December 31, 2012. Petrodelta’s Probable reserves, net to our 32 percent interest, are 61.8 MMBOE at December 31, 2012. Petrodelta’s Possible reserves, net to our 32 percent interest, are 104.4 MMBOE. Proved plus Probable reserves at 100.2 MMBOE, after accounting for current year production, are virtually unchanged from last year. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies – Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve estimates.

 

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Certain operating statistics for the years ended December 31, 2012, 2011, and 2010 for the Petrodelta fields operated by Petrodelta are set forth below. This information is provided at 100 percent.

 

     December 31,  
     2012      2011      2010  

Thousand barrels of oil sold

     13,172         11,390         8,561   

Million cubic feet of gas sold

     2,171         2,266         2,204   

Total thousand barrels of oil equivalent

     13,534         11,768         8,928   

Average price per barrel

   $ 95.91       $ 98.52       $ 70.57   

Average price per thousand cubic feet

   $ 1.54       $ 1.54       $ 1.54   

Cash operating costs ($millions)(a)

   $ 121.0       $ 77.2       $ 44.7   

Capital expenditures ($millions)

   $ 184.2       $ 137.5       $ 98.7   

 

(a) 

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations, Years Ended December 31, 2012 and 2011, Equity in Earnings from Equity Affiliates.

Under Petrodelta’s Sales Contract, crude oil delivered from the Petrodelta fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices are quoted and sold in U.S. Dollars. Natural gas delivered from the Petrodelta Fields to PDVSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make payment to Petrodelta in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered. Natural gas deliveries are paid in Bolivars, but the pricing for natural gas is referenced to the U.S. Dollar.

Production from the Petrodelta fields, except the El Salto field, flows through Petrodelta’s pipelines into PDVSA’s EPT-1 storage facility. Prior to October 2011, El Salto production was trucked to the EPT-1 storage facility and combined with the other Petrodelta fields’ production. Beginning October 2011, production from the El Salto field flows through PDVSA’s EPM-1 transfer point at PDVSA Morichal. Currently, the El Salto production flows through COMOR transfer point, a new transfer point for Petrodelta, at PDVSA Morichal.

When the Sales Contract was executed, Petrodelta was producing only one type of crude, Merey 16. The official pricing formula applied to the Merey 16 by MENPET is used for the sales of Petrodelta crude oil with quality close to 16 degrees API to represent actual quality delivered. Beginning in October 2011, MENPET determined that Petrodelta’s production flowing through the COMOR transfer point was a heavier type of crude, Boscan. The official pricing formula applied to Boscan by MENPET is used for the sales of Petrodelta crude oil with quality close to 10 degrees API to represent actual quality delivered.

Since Petrodelta was producing only Merey 16 when the Sales Contract was executed, the Boscan gravity and sulphur correction factors and crude pricing formula are not included in the Sales Contract. However, under the Sales Contract, PPSA is obligated to receive all of Petrodelta’s production. All production deliveries for all of Petrodelta’s fields have been certified by MENPET and acknowledged by PPSA. All pricing factors to be used in the Merey 16 and Boscan pricing formulas have been provided by and certified by MENPET to Petrodelta.

Since the Sales Contract provides for only one crude pricing formula, the Sales Contract had to be amended to include the Boscan pricing formula to allow Petrodelta to invoice PPSA for El Salto crude oil deliveries. From October 1, 2011 through June 30, 2012, Petrodelta used the Boscan pricing formula as published in the Official Gazette on January 11, 2007 to record revenue from El Salto field deliveries. Petrodelta subsequently received from PDVSA Trade and Supply a draft amendment to the Sales Contract. The pricing formula in the draft amendment was used to record revenue for El Salto field deliveries from July 1, 2012 through December 31, 2012, and revenue for El Salto field deliveries for October 1, 2011 through June 30, 2012 was revised to reflect the pricing formula in the draft amendment. The only item included in the draft amendment is the Boscan pricing formula to be used in invoicing El Salto crude oil deliveries. All other terms and conditions of the Sales Contract remain in force. On January 28, 2013, Petrodelta’s board of directors endorsed the amendment to the Sales Contract. The amendment has to be approved by CVP’s board of directors and HNR Finance’s board of directors. Once these approvals are received, the amendment to the Sales Contract will be executed and PPSA will be invoiced for the deliveries.

At December 31, 2012, El Salto deliveries, net of royalties, covering the delivery months of October 2011 through December 2012 totaled approximately 4.0 MBls (1.3 MBls net to our 32 percent interest). The draft

 

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amendment to the Sales Contract pricing formula for Boscan based upon the deliveries and factors certified by MENPET, results in revenue for these deliveries of $352.7 million ($112.9 million net to our 32 percent interest). As of December 31, 2012, these deliveries for El Salto remain uninvoiced to PPSA.

In Item 1A. Risk Factors, we disclosed that PDVSA’s failure to timely pay contractors, including Petrodelta, was having an adverse effect on Petrodelta. We have advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, operations and seismic interpretation, and employee salaries and related benefits for Harvest employees seconded into Petrodelta. Currently, we have three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. We are considered a contractor to Petrodelta, and as such, we are also experiencing the slow payment of invoices. During the year ended December 31, 2012, we advanced Petrodelta $0.5 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advances. Advances to equity affiliate has increased $0.4 million, to a balance of $2.8 million, during the year ended December 31, 2012. During the year ended December 31, 2011, we advanced Petrodelta $0.8 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advances. Although payment is slow, payments continue to be received. Petrodelta and Petrodelta’s board have not indicated that the advances are not payable, nor that they will not be paid. As a Petrodelta contractor, Harvest Vinccler assessed the possibility of recording an allowance for doubtful accounts on its receivable from Petrodelta. After considering many factors, including the slow but continuous payments received from Petrodelta, Harvest Vinccler determined that an allowance for doubtful accounts is not required; however, at December 31, 2012, Harvest Vinccler reclassified $2.1 million of the Advances to Affiliate to a long-term receivable due to slow payment and age of the advances.

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

Petrodelta’s 2012 proposed capital expenditures were expected to be approximately $401.9 million and included a planned drilling program to utilize two rigs to drill both development and appraisal wells for maintaining production capacity, the continued appraisal of the substantial resource base in the El Salto field and further drilling in the Isleño field. It also included engineering work for production facilities required for the full development of the El Salto and Temblador fields. Due to insufficient monetary support and contractual adherence by PDVSA, Petrodelta incurred only $184.2 million of its 2012 proposed capital expenditures.

As of May 2, 2013, the 2013 budget for Petrodelta had not yet been approved by its shareholders. Since Petrodelta only executed approximately 45.8 percent of its 2012 planned capital expenditures primarily due to insufficient monetary support and contractual adherence by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2013 budget. Should PDVSA continue in insufficient monetary support and contractual adherence of Petrodelta, underinvestment in the development plan may lead to continued under-performance. However, Petrodelta’s 2013 proposed budget includes a planned drilling program to utilize five rigs to drill both development and appraisal wells for maintaining production capacity and the continued appraisal of the substantial resource base in the El Salto, Temblador and Isleño fields. It also includes engineering work for continued infrastructure enhancement projects in El Salto and Temblador.

In April 2011, the Venezuelan government published in the Official Gazette the amended 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 prices (under $80 per barrel) and exorbitant prices (over $100 per barrel), and levels in-between, to the Venezuelan government. The amended Windfall Profits Tax is deductible for Venezuelan income tax purposes. During the year ended December 31, 2012, Petrodelta recorded $291.4 million for the amended Windfall Profits Tax (2011: $237.6 million).

One section of the Windfall Profits Tax states that royalties paid to Venezuela are capped at $70 per barrel, but the cap on royalties has not been defined as being applicable to in-cash, in-kind, or both. In October 2011, Petrodelta received instructions from PDVSA that royalties, whether paid in-cash or in-kind, should be reported at $70 per barrel (royalty barrels x $70). The difference between the $70 royalty cap and the current oil price is to be reflected on the income statement as a reduction in oil sales. For the year ended December 31, 2012, the reduction to oil sales due to the $70 cap applied to all royalty barrels was $113.7 million ($36.4 million net to our 32 percent interest). For the year ended December 31, 2011, the reduction to oil sales due to the $70 cap applied to all royalty barrels was $85.0 million ($27.2 million net to our 32 percent interest).

 

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Per our interpretation of the Windfall Profits Tax, the $70 cap on royalty barrels should only be applied to the 3.33 percent royalty which Petrodelta pays in cash. With assistance from Petrodelta, we have recalculated Petrodelta’s oil sales and royalties to apply the current oil price to its total barrels produced and to the 30 percent royalty paid in-kind and applied the $70 cap to the 3.33 percent royalty paid in cash for the years ended December 31, 2012 and 2011. For the year ended December 30, 2012, net oil sales (oil sales less royalties) are slightly higher, $11.4 million ($3.6 million net to our 32 percent interest). For the year ended December 31, 2011, net oil sales are slightly higher, $8.5 million ($2.7 million net to our 32 percent interest) under this method than the method advised by PDVSA and the method of applying the current oil price to total barrels produced and to total royalty barrels.

Another section of the amended Windfall Profits Tax for which Petrodelta is waiting for clarity relates to an exemption of this tax that can be granted by the Ministry of the People’s Power for Petroleum and Mining (“MENPET”) for the incremental production of projects and grass root developments until the specific investments are recovered. This exemption has to be considered and approved in a case by case basis by MENPET. We believe several of the fields operated by Petrodelta may qualify for the exemption from the amended Windfall Profits Tax. We are waiting for clarification from MENPET on the definitions of incremental production and grass roots developments, as well as guidance on the process for applying for the exemption.

The Venezuelan government published in the Official Gazette an amendment to the Windfall Profits Tax with an effective date of February 20, 2013. The amended Windfall Profits Tax establishes new levels for contribution of extraordinary and exorbitant prices to the Venezuelan government. Extraordinary prices are considered to be equal to or lower than $80 per barrel, and exorbitant prices are considered to be over $80 per barrel. The amended Windfall Profits tax also sets a new royalty cap per barrel of $80. Contributions for extraordinary prices are 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $55 per barrel for 2013) and $80 per barrel. Contributions for exorbitant prices are (1) 80 percent when the average price of the VEB exceeds $80 per barrel but is less than $100 per barrel; (2) 90 percent when the average price of the VEB equals or exceeds $100 per barrel but is less than $110 per barrel; and (3) 95 percent when the average price of the VEB equals or exceeds $110 per barrel.

On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, as of May 2, 2013, this dividend has not been received, although it is due and payable. Petrodelta’s board of directors declared this dividend and has never indicated that the dividend is not payable, nor that it will not be paid. The dividend receivable is classified as a long-term receivable at December 31, 2012 due to the uncertainty in the timing of payment. There is uncertainty with respect to the timing of the receipt of this dividend and whether future dividends will be declared or paid. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable not be collected or facts and circumstances surrounding our investment change, our results of operations and investment in Petrodelta could be adversely impacted.

The Organic Law on Sports, Physical Activity and Physical Education (“Sports Law”) was published in the Official Gazette on August 23, 2011. The purpose of the Sports Law is to establish the public service nature of physical education and the promotion, organization and administration of sports and physical activity. Funding of the Sports Law is by contributions made by companies or other public or private organizations that perform economic activities for profit in Venezuela. The contribution is one percent of annual net or accounting profit and is not deductible for income tax purposes. Per the Sports Law, contributions are to be calculated on an after-tax basis. However, CVP has instructed Petrodelta to calculate the contribution on a before-tax basis contrary to the Sports Law. For the year ended December 31, 2012, this method of calculation overstates the liability for the Sports Law contribution by $2.5 million ($0.8 million net to our 32 percent interest). We have adjusted for the overaccrual of the Sports Law in the December 31, 2012 Net Income from Equity Affiliate.

Petrodelta’s results and operating information is more fully described in Item 15. Exhibits and Financial Statement Schedules, Notes to the Consolidated Financial Statements, Note 13 – Investment in Equity Affiliates – Petrodelta, S.A.

Diversification

We have broadened our strategy from our primary focus on Venezuela to identify, access and integrate hydrocarbon assets to include organic growth through exploration in basins globally with proven hydrocarbon systems. We seek to leverage our Venezuelan experience as well as our recently expanded business development and technical platform to create a diversified resource base. With the addition of technical resources through the

 

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opening of our London and Singapore offices, we have made significant investments to provide the necessary foundation and global reach required for an organic growth focus. Our organic growth is focused on undeveloped or underdeveloped fields, field redevelopments and exploration. While exploration has become a larger part of our overall portfolio, we generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles. Exploration will be technically driven with a low entry cost and high resource potential that provides sustainable growth.

Budong-Budong Project, Indonesia

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

The initial exploration term of the Budong PSC was due to expire on January 15, 2013. In September 2012, the operator of the Budong PSC, on behalf of us and the other co-venturer, submitted a request to BPMIGAS under the terms of the Budong PSC for a four-year extension of the initial six-year exploration term of the Budong PSC. In January 2013, we received written approval from SKK Migas of the four-year extension of the initial six-year exploration term.

In November 2012, the Indonesia constitutional court declared BPMIGAS, Indonesia’s oil and gas regulatory authority, to be unconstitutional. In January 2013, SKK Migas, the Special Task Force for oil and gas upstream sector, was formed to replace BPMIGAS. SKK Migas will supervise all oil and gas industry activities.

In December 2012, we signed a farmout agreement with the operator of the Budong PSC to acquire an additional 7.1 percent participating interest and to become operator of the Budong PSC. We assumed the role of interim operator effective January 16, 2013. Closing of this acquisition will increase our participating ownership interest in the Budong PSC to 71.5 percent with our cost sharing interest becoming 72 percent until first commercial production. The consideration for this transaction is that we will fund 100 percent of the costs of the first exploration well of the four-year extension to the Budong PSC. If the exploration well is not drilled within 18 months of the date of approval from the Government of Indonesia of this transaction, our partner has the right to give notice that the consideration be paid in cash, or $3.2 million. The transfer of operatorship was approved by SKK Migas on March 25, 2013. The acquisition of the additional participating interest was approved by the Government of Indonesia on April 9, 2013.

We have satisfied all work commitments for the current exploration phase of the Budong PSC. However, the extension of the initial exploration term includes an exploration well, which if not drilled by January 2016, results in the termination of the Budong PSC.

Pursuant to the request for extension of the initial exploration term, the contract area held by the Budong PSC at the beginning of the extension period should be reduced, per the terms of the Budong PSC, from the current 55 percent to 20 percent of the original contract area. In January 2013, our partner, on our behalf, submitted a relinquishment proposal of 10 percent to SKK Migas. The retained area will contain all the areas of geological interest to the Budong PSC partners.

Operational activities during the year ended 2012 included a review of geological and geophysical data obtained from the drilling of LG-1 and KD-1 wells to upgrade the prospectivity of the block and to define a prospect for potential drilling in 2013. Based on multiple oil and gas shows encountered in both LG-1 and KD-1, we are working on an exploration program targeting the Pliocene and Miocene sands encountered in the previous two wells. We have completed remapping of both the Lariang and Karama Basins with eight leads in the Lariang Basin and five leads in the Karama Basin having been identified in the Pliocene, Middle-Late Miocene and Eocene sands. The identification of these leads is the basis for the four-year extension request of the first six-year exploration term. The partners have technically recommended the drilling of the Madjene prospect in the Lariang Basin targeting stacked Pliocene and Miocene clastic reservoirs for an exploration well in late 2013. Preliminary well planning activities commenced in October 2012.

During the year ended December 31, 2012, we had cash capital expenditures of $5.8 million mainly for deepening and plugging and abandonment costs of KD-1ST (2011: $18.2 million for drilling, construction and plugging and abandonment costs and $3.7 million for the purchase of the additional 10 percent equity interest). The 2013 budget for the Budong PSC is $13.9 million.

 

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Dussafu Project – Gabon

See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon.

The Dussafu PSC partners and the Republic of Gabon, entered into the third exploration phase of the Dussafu PSC with an effective date of May 28, 2012. The DGH agreed to lengthen the third exploration phase to four years until May 27, 2016. The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period. This commitment was fulfilled with the drilling of DTM-1.

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

Well planning progressed to drill an exploration well in the fourth quarter of 2012 on the Tortue prospect to target stacked pre-salt Gamba and Dentale reservoirs as well as a secondary post-salt Madiela clastic reservoir. DTM-1 was spud on November 19, 2012. DTM-1 was drilled with the Scarabeo 3 semi-submersible drilling unit, and was drilled 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 Dental 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. Additional technical evaluation is on-going.

The first appraisal sidetrack of DTM-1 (“DTM-1ST1”) spud January 12, 2013. DTM-1ST1 was drilled to a Total Depth of 11,385 feet in the Dental 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 early before pressure data could be collected to confirm connectivity. The well can be re-entered, and the downhole tool has since been retrieved. DTM-1 and DTM-1ST1 were suspended pending future appraisal and development activities. The drilling rig was demobilized and released on February 21, 2013.

During the year ended December 31, 2012, we had cash capital expenditures of $11.7 million for seismic processing (2011: $40.1 million for well planning and drilling). The 2013 budget for the Dussafu PSC is $26.2 million.

Block 64 EPSA Project – Oman

See Item 1. Business, Operations, Block 64 EPSA, Oman.

Both the work and financial commitments on Block 64 EPSA have been fulfilled. Operational activities during the year ended December 31, 2012 included post well evaluation and review of geological and geophysical data obtained from the drilling of MFS-1 and AGN-1 wells. On March 12, 2013, we elected to not request an extension of the First Phase or enter the Second Phase of Block 64 EPSA and Block 64 will be relinquished effective June 30, 2013. The carrying value of Block 64 EPSA of $6.4 million was written off to impairment expense at December 31, 2012.

During the year ended December 31, 2012, we incurred $6.1 million for drilling and plugging and abandonment costs (2011: $10.2 million for well planning, drilling and plugging and abandonment costs). The 2013 budget for Block 64 EPSA is minimal, consisting of costs required to terminate operations and close the field office.

WAB-21 Project – China

See Item 1. Business, Operations, WAB-21, South China Sea.

 

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

Operational activities during 2012 include costs related to maintenance of the license. The 2013 budget for WAB 21 is minimal, consisting of costs required to maintain the license.

Other Exploration Projects

The 2013 budget for new business development is $2.7 million.

Business Strategy

In Item 1. Business and Item 1A. Risk Factors, we discuss the situation in Venezuela and how the actions of the Venezuelan government have and continue to adversely affect our operations. The expectation that dividends from Petrodelta will be minimal over the next two years has restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere.

We will use our available cash and future access to capital markets to expand our diversified strategy in a number of countries that fit our strategic investment criteria. In executing our business strategy, we will strive to:

 

   

maintain financial prudence and rigorous investment criteria;

 

   

access capital markets;

 

   

continue to create a diversified portfolio of assets;

 

   

preserve our financial flexibility;

 

   

use our experience and skills to acquire new projects; and

 

   

keep our organizational capabilities in line with our rate of growth.

To accomplish our strategy, we intend to:

 

   

Diversify our Political Risk: Acquire oil and natural gas fields in a number of countries to diversify and reduce the overall political risk of our investment portfolio.

 

   

Seek Operational and Financial Control: We desire control of major decisions for development, production, staffing and financing for each project for a period of time sufficient for us to ensure maximum returns on investments.

 

   

Establish a Presence Through Joint Venture Partners and the Use of Local Personnel: We seek to establish a presence in the countries and areas we operate through joint venture partners to facilitate stronger governmental and business relationships. In addition, we use local personnel to help us take advantage of local knowledge and experience and to minimize costs.

 

   

Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time: We are willing to agree to minimum capital expenditures or development commitments at the outset of new projects, but we endeavor to structure such commitments to fulfill them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure.

 

   

Provide Technical Expertise: We believe there is an advantage in being able to provide geological, geophysical and engineering expertise beyond what many companies or countries possess internally.

 

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Maintain a Prudent Financing Plan: We intend to maintain our financial flexibility by closely monitoring spending, holding sufficient cash reserves, minimizing the use of restricted cash, actively seeking opportunities to reduce our weighted average cost of capital and increase our access to debt and equity markets.

 

   

Manage Exploration Risks: We seek to manage the higher risk of exploration by diversifying our prospect portfolio, applying state-of-the-art technology for analyzing targets and focusing on opportunities in proven active hydrocarbon systems with infrastructure.

 

   

Establish Various Sources of Production: We seek to establish new production from our exploration and development efforts in a number of diverse markets and expect to monetize production through operations or the farm-down or possible sale of assets.

Results of Operations

The following discussion should be read with the results of operations for each of the years in the three-year period ended December 31, 2012 and the financial condition as of December 31, 2012 and 2011 in conjunction with our consolidated financial statements and related notes thereto.

Years Ended December 31, 2012 and 2011

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

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

 

     Year Ended
December 31,
       
     2012     2011
(RESTATED)
    Increase
(Decrease)
 

Depreciation and amortization

   $ 0.4      $ 0.5      $ (0.1

Exploration expense

     9.1        12.6        (3.5

Impairment expense

     9.3        3.3        6.0   

Dry hole costs

     5.6        49.7        (44.1

General and administrative

     27.1        22.5        4.6   

Investment earnings and other

     (0.3     (0.7     0.4   

Unrealized (gain) loss on warrant derivatives

     0.6        (9.8     10.4   

Interest expense

     1.6        7.2        (5.6

Debt conversion expense

     3.6        —          3.6   

Loss on extinguishment of debt

     5.4        13.1        (7.7

Other non-operating expense

     2.9        1.4        1.5   

Loss on exchange rates

     0.1        0.1        —     

Income tax expense (benefit)

     (0.6     1.1        (1.7

Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2012, we incurred $4.8 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations, $2.5 million related to other general business development activities, and $1.8 million related to lease maintenance. During the year ended December 31, 2011, we incurred $10.1 million of exploration costs for the acquisition, processing and reprocessing of seismic data related to ongoing operations, $0.3 million related to other general business development activities, and $2.2 million related to lease maintenance.

During the year ended December 31, 2012, we impaired $6.4 million related to the carrying value of Block 64 EPSA and $2.9 million related to the carrying value of WAB-21. During the year ended December 31, 2011, we impaired $3.3 million related to the carrying value of West Bay.

 

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During the year ended December 31, 2012, we expensed to dry hole costs $0.7 million related to the drilling of the KD-1 well on the Budong PSC and $4.9 million related to the drilling of the AGN-1 on Block 64 EPSA. During the year ended December 31, 2011, we expensed to dry hole costs $14.0 million related to the drilling of the LG-1 on Budong PSC, $26.0 million related to the drilling of the KD-1 and KD-1ST on the Budong PSC, $6.9 million related to the drilling of the MFS-1 on Block 64 ESPA and $2.8 million related to the drilling of the AGN-1 on Block 64 EPSA. See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia – Drilling and Development Activity and Block 64 EPSA, Oman – Drilling and Development Activity.

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

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

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

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

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

During the year ended December 31, 2012, we incurred a loss on extinguishment of debt of $5.4 million related to the early conversion of our 8.25 percent senior convertible notes. The loss on extinguishment of debt includes the difference between the carrying value of the 8.25 percent senior convertible notes and the amount received for the 11 percent senior unsecured notes ($5.0 million), expensing of deferred financing costs related to the 8.25 percent senior convertible notes ($0.1 million) and issuance of 30,000 shares of Harvest common stock issued in exchange for a waiver agreement ($0.3 million). During the year ended December 31, 2011, we incurred a loss on extinguishment of debt related to early payment of our $60 million term loan facility. The loss on extinguishment of debt includes the write off of the discount on debt ($10.6 million), prepayment premium of 3.5 percent of the amount outstanding ($2.1 million), expensing of financing costs related to the term loan facility ($0.4 million), and the cost to redeem 4.4 million unvested warrants issued in connection with the term loan facility.

The loss on exchange rates for the year ended December 31, 2012 was consistent with the year ended December 31, 2011.

The increase in other non-operating expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to costs incurred related to our strategic alternative process and evaluation which resulted in the SPA for the sale of our 32 percent interest in Petrodelta.

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

Equity in Earnings from Equity Affiliates

For the year ended December 31, 2012, net income from equity affiliates reflects an increase in Petrodelta’s revenue from oil sales due to higher sales volumes ($170.8 million) offset by lower prices ($29.6 million). Royalties, which is a function of revenue, increased $49.0 million due to the increase in revenue (net increase in revenue of $141.2 million at 30 percent royalty). Windfall Profits Tax, which is a function of volume and price received per barrel, increased $53.8 million due to an increase in volumes (2012: 13.2 MBls vs.

 

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2011: 11.4 MBls) offset by lower price received per barrel (2012: $95.91 per barrel vs. 2011: $98.52 per barrel). The increase in operating expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to increased oil production and also includes $3.8 million of additional expense related to the labor law which was recorded in December 2012. The decrease in workover expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to fewer workovers being performed. Petrodelta’s effective tax rate (inclusive of the adjustments to reconcile to reported net income from equity affiliate) for the year ended December 31, 2012 was not materially different with the effective tax rate for the year ended December 31, 2011.

Discontinued Operations

On May 17, 2011, we closed the transaction to sell the Antelope Project. The sale had an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale was reported in discontinued operations in the second quarter of 2011.

During the year ended December 31, 2012, we incurred $0.1 million of expense related to settlement of royalty payments to the Mineral Management Services and write-offs of $5.2 million of accounts and note receivable and $3.6 million of accounts payable and carry obligation related to the settlement of all outstanding claims with a private third party on the Antelope Project. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 3 – Summary of Significant Accounting Policies, Notes Receivable.

Revenue and net loss on the disposition of the Antelope Project are shown in the table below:

 

     December 31,  
     2012     2011  
     (in thousands)  

Revenues applicable to discontinued operations

   $ —        $ 6,488   

Net income (loss) from discontinued operations

     (1,699     97,616   

Years Ended December 31, 2011 and 2010

We reported net income attributable to Harvest of $56.0 million, or $1.64 diluted earnings per share, for the year ended December 31, 2011, compared with net income attributable to Harvest of $14.4 million, or $0.39 diluted earnings per share, for the year ended December 31, 2010.

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

 

     Year Ended December 31,        
     2011
(RESTATED)
    2010
(RESTATED)
    Increase
(Decrease)
 

Depreciation and amortization

   $ 0.5      $ 0.5      $ —     

Exploration expense

     12.6        8.3        4.3   

Impairment expense

     3.3        —          3.3   

Dry hole costs

     49.7        —          49.7   

General and administrative

     22.5        25.9        (3.4

Investment earnings and other

     (0.7     (0.6     (0.1

Unrealized gain on warrant derivatives

     (9.8     (0.3     (9.5

Interest expense

     7.2        3.8        3.4   

Loss on extinguishment of debt

     13.1        —          13.1   

Other non-operating expense

     1.4        4.0        (2.6

Loss on exchange rates

     0.1        1.6        (1.5

Income tax expense (benefit)

     1.1        (0.2     1.3   

 

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Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2011, we incurred $10.1 million of exploration costs for the acquisition, processing and reprocessing of seismic data related to ongoing operations, $0.3 million related to other general business development activities, and $2.2 million related to lease maintenance. During the year ended December 31, 2010, we incurred $6.4 million of exploration costs for seismic, geological and geophysical, $1.6 million related to other general business development activities and $0.3 million related to lease maintenance. Included in the $6.4 million of exploration costs is the one-time charge of $1.2 million for acquisition of seismic data for the Budong PSC related to our partner in the Budong PSC exercising their option to increase the carry obligation.

During the year ended December 31, 2011, we impaired $3.3 million related to the carrying value of West Bay. During the year ended December 31, 2010, we did not impair any oil and gas properties costs.

During the year ended December 31, 2011, we expensed to dry hole costs $14.0 million related to the drilling of the LG-1 on the Budong PSC, $26.0 million related to the drilling of the KD-1 and KD-1ST on the Budong PSC, $6.9 million related to the drilling of the MFS-1 on Block 64 ESPA and $2.8 million related to the drilling of the AGN-1 on Block 64 EPSA. See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia – Drilling and Development Activity and Block 64 EPSA, Oman – Drilling and Development Activity.

The decrease in general and administrative costs in the year ended December 31, 2011 from the year ended December 31, 2010 was primarily due to lower general office expense and overhead ($2.7 million), employee related costs ($0.9 million) and public relations ($0.3 million) offset by higher travel costs ($0.3 million) and contract services ($0.2 million). The employee related costs include $0.5 million of special consideration bonuses related to the sale of our Antelope Project.

The increase in investment earnings and other in the year ended December 31, 2011 from the year ended December 31, 2010 was due to income earned on transition services provided on the Antelope Project after closing of the sale.

The increase in unrealized gain on warrant derivative in the year ended December 31, 2011 from the year ended December 31, 2010 was due to the change in fair value for our warrant derivative liabilities: $3.04 per warrant at December 31, 2011 and $7.37 weighted average price per warrant at December 31, 2010.

The increase in interest expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to the interest associated with our $32 million convertible debt offering in February 2010, our $60 million term loan facility occurring in October 2010 and amortization of discount on the term loan facility related to the warrants issued in connection with the $60 million term loan facility offset by interest capitalized to oil and gas properties of $2.3 million.

During the year ended December 31, 2011, we incurred a loss on extinguishment of debt related to early payment of our $60 million term loan facility. The loss on extinguishment of debt includes the write off of the discount on debt ($10.6 million), prepayment premium of 3.5 percent of the amount outstanding ($2.1 million), expensing of financing costs related to the term loan facility ($0.4 million), and the cost to redeem 4.4 million unvested warrants issued in connection with the term loan facility.

The decrease in loss on exchange rates in the year ended December 31, 2011 from the year ended December 31, 2010 is due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. There was no Bolivar/U.S. Dollar exchange rate devaluations in the year ended December 31, 2011.

The decrease in other non-operating expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to costs incurred related to our strategic alternative process and evaluation which resulted in the sale of our Antelope Project.

The increase in income tax expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to higher income tax assessed in 2011 in the Netherlands offset by a U.S. tax refund received in 2010.

For the year ended December 31, 2011, net income from equity affiliates reflects an increase in Petrodelta’s revenue from oil sales due to higher sales volumes and prices which was partially offset by

 

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the amended Windfall Profits Tax. The increase in operating expense and workovers in the year ended December 31, 2011 from the year ended December 31, 2010 was due to increased oil production and having a workover rig on location for the full year of 2011. Petrodelta took possession of the workover rig in September 2010 and operated it for only four months in the year ending December 31, 2010. The decrease in gain on exchange rates in the year ended December 31, 2011 from the year ended December 31, 2010 was due to there not being a Bolivar/U.S. Dollar currency exchange rate devaluation during 2011. There was a Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. The decrease in Petrodelta’s effective tax rate (inclusive of the adjustments to reconcile to reported net income from equity affiliate) in the year ended December 31, 2011 from the year ended December 31, 2010 was primarily due to the tax effects of the currency devaluation in 2010 partially offset by an increase in current tax on increased earnings.

At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion. Accordingly, we did not record net losses incurred by Fusion of $0.2 million ($0.1 million net to our 49 percent interest) in the year ended December 31, 2011 (2010: $2.4 million [$1.2 million net to our 49 percent interest]), as doing so would have caused our equity investment to go into a negative position. However, we have recognized a $1.4 million gain on the sale of Fusion in the year ended December 31, 2011.

Discontinued Operations

On May 17, 2011, we closed the transaction to sell our Antelope Project. The sale had an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale was reported in the second quarter of 2011.

Revenue and net income on discontinued operations for the years ended December 31, 2011 and 2010 are shown in the table below:

 

     December 31,  
     2011      2010  
     (in thousands)  

Revenues applicable to discontinued operations

   $ 6,488       $ 10,696   

Net income (loss) from discontinued operations

     97,616         3,712   

Net income from discontinued operations for the year ended December 31, 2011 includes $106.0 million gain on the sale of our Antelope Project, $3.8 million for employee severance and special accomplishment bonuses, and $5.7 million of U.S. income tax related to the sale of our Antelope Project. Severance costs for key employees include 58,000 stock appreciation rights (“SAR”) granted at an exercise price of $4.595 per SAR. These SARs are exercisable by the key employee for up to one year after termination.

Risks, Uncertainties, Capital Resources and Liquidity

Our financial statements for the year ended December 31, 2012 have been prepared under the assumption that we will continue as a going concern. Our independent registered public accounting firm has included in their audit report an explanatory paragraph expressing substantial doubt about our ability to continue 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 2013. However, we believe certain cost reduction measures could be put into place which would not jeopardize our operations and future growth plans. In addition, we could delay the discretionary portion of our capital spending to future periods and/or sell or farm down assets 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 our assets.

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

 

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value of our unevaluated exploratory well costs. We believe that we will continue to be successful in securing any funds necessary to continue as a going concern. However, our current cash position and our ability to access additional capital may limit our available opportunities or not provide sufficient cash for operations.

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

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

The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. In Item 1A. Risk Factors, we discuss a number of variables and risks related to our exploration projects and our minority equity investment in Petrodelta that could significantly utilize our cash balances, affect our capital resources and liquidity.

The environments in which we operate are often difficult and the ability to operate successfully depends on a number of factors including our ability to control the pace of development, our ability to apply “best practices” in drilling and development, and the fostering of productive and transparent relationships with local partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, often the legal systems of certain countries are not mature and their reliability can be uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and natural gas projects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy depends on our ability to have significant influence over operations and financial control.

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

There are also a number of variables and risks related to our minority equity investment in Petrodelta that could significantly utilize our cash balances, and affect our capital resources and liquidity. Petrodelta’s capital commitments are determined by its business plan, and Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. The total capital required to develop the fields in Venezuela may exceed Petrodelta’s available cash and financing capabilities, and there may be operational or contractual consequences due to this inability. Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Due to PDVSA’s liquidity constraints, PDVSA has not been providing the necessary monetary support and contractual adherence required by Petrodelta. If we are called upon to fund our share of Petrodelta’s operations, our failure to do so could be considered a default under the Conversion Contract and cause the forfeiture of some or all our shares in Petrodelta.

Petrodelta currently represents our only source of earnings. Petrodelta also has a material impact on our results of operations for any quarter or annual reporting period. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 13 – Investment in Equity Affiliate – Petrodelta, S.A. Petrodelta operates under a business plan, the success of which relies heavily on the market price of oil. To the extent that market prices of oil decline, the business plan, and thus our equity investment and/or operations and/or profitability, could be adversely affected.

 

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Operations in Venezuela are subject to various risks inherent in foreign operations. It is possible the legal or fiscal framework for Petrodelta could change and the Venezuela government may not honor its commitments. Our ability to implement or influence Petrodelta’s business plan, assure quality control and set the timing and pace of development could also be adversely impacted. No assurance can be provided that events beyond our control will not adversely affect the value of our minority investment in Petrodelta.

Historically, our primary ongoing source of cash has been dividends from Petrodelta and the sale of oil and gas properties. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 5 – Dispositions – Discontinued Operations. Currently, our source of cash is expected to be generated by accessing debt and/or equity markets, farm-downs, or possible sales of assets.

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

Between Petrodelta’s formation in October 2007 and June 2010, Petrodelta declared and paid dividends of $105.5 million to HNR Finance, B.V. (“HNR Finance”), a wholly owned subsidiary of Harvest Holding ($84.4 million net to our 32 percent interest). On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend was ratified by Petrodelta’s shareholders on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, this dividend has not yet been received, although it is due and payable. Petrodelta’s board of directors declared this dividend and has never indicated that the dividend is not payable, nor that it will not be paid. The dividend receivable is classified as a long-term receivable at December 31, 2012 due to the uncertainty in the timing of payment. There is uncertainty whether Petrodelta will declare and/or pay additional dividends in the future. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 18 – Related Party Transactions for a discussion of our obligations to our non-controlling interest holder, Vinccler, for any dividend received from Petrodelta. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable not be collected, or facts and circumstances surrounding our investment change, our results of operations and our investment in Petrodelta could be adversely impacted.

Our cash is being used to fund oil and gas exploration projects, debt, interest, and general and administrative costs. We require capital principally to fund the exploration and development of new oil and gas properties. As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. We entered the third exploration phase of the Dussafu PSC on May 28, 2012. The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period. This commitment was fulfilled with the drilling of DTM-1. See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon – General. In January 2013, the Budong PSC partners were granted a four year extension of the initial six year exploration term of the Budong PSC to January 15, 2016. The extension of the initial exploration term includes an exploration well, which if not drilled by January 2016, results in the termination of the Budong PSC. Also, if this exploration well is not drilled within 18 months of the date of approval from the Government of Indonesia of this transaction, we will be required to pay our partner in the Budong PSC $3.2 million. See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia – General. The Budong PSC work commitments are discretionary, and we have the ability to control the pace of expenditures.

 

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In March 2012, we announced that we had entered into an equity distribution agreement with Knight Capital America, L.P., a subsidiary of Knight Capital Group, Inc., relating to an “at-the-market” (“ATM”) offering of shares of our common stock. Due to the late filing of our Annual Report on Form 10-K for the year ended December 31, 2012, we are not eligible to use a Form S-3 Registration Statement; therefore, we can no longer access our ATM.

Accumulated Undistributed Earnings of Foreign Subsidiaries

As of December 31, 2012, the book-tax outside basis difference in our foreign subsidiary that has been indefinitely reinvested was approximately $331 million. No U.S. taxes have been recorded on these earnings. In general, it is our practice and intention to reinvest the earnings of our non-U.S. subsidiaries in those operations. All of our current exploration activity is outside of the U.S. We currently intend to utilize our unremitted foreign earnings to fund international projects, including the development of our properties in Gabon, Indonesia and South America.

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

If we were to make a distribution of our foreign earnings in the form of dividends, we would likely be subject to U.S. income taxes. Pursuant to ASC 740-30-50-2, we have estimated that the potential U.S. tax cost if we were to repatriate all of our currently unremitted foreign earnings through a dividend would be approximately $113 million based upon our foreign tax credit position in the U.S.

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

 

     Year Ended December 31,  
     (in thousands except as indicated)  
     2012     2011
(RESTATED)
    2010
(RESTATED)
 

Net cash used in operating activities

   $ (26,405   $ (55,243   $ (8,126

Net cash provided by (used in) investing activities

     (23,789     112,216        (56,231

Net cash provided by (used in) financing activities

     63,875        (56,730     90,743   
  

 

 

   

 

 

   

 

 

 

Net increase in cash

   $ 13,681      $ 243      $ 26,386   
  

 

 

   

 

 

   

 

 

 

Working Capital

     40,537        62,618        133,015   

Current Ratio

     2.0        3.1        5.7   

Total Cash, including restricted cash

     73,627        60,146        58,703   

Total Debt

     74,839        31,535        78,291   

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

Cash Flow from Operating Activities. During the year ended December 31, 2012, net cash used in operating activities was approximately $26.4 million (2011: $55.2 million). The $28.8 million decrease in use of cash was primarily due to decreases in accounts payable and accrued interest and increases in accrued expenses offset by decreases in receivables.

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

 

     December 31,  
     2012      2011
(RESTATED)
 
     (in millions)  

Budong PSC

   $ 5.8       $ 21.9   

Dussafu PSC

     11.7         40.1   

Block 64 EPSA

     6.1         10.2   
  

 

 

    

 

 

 

Total additions of property and equipment – continuing operations

     23.6         72.2   

Assets Held for Sale – Antelope Project(1)

     —           33.9   
  

 

 

    

 

 

 

Total additions of property and equipment

   $ 23.6       $ 106.1   
  

 

 

    

 

 

 

 

(1) 

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

 

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During the year ended December 31, 2012, we:

 

 

Deposited with a U.S. bank $1.0 million as collateral for a Standby Letter of Credit issued in support of a performance bond for a joint study and had $1.2 million of restricted cash released to us; and

 

 

Advanced $0.5 million to Petrodelta for continuing operations costs, and Petrodelta repaid $0.1 million.

During the year ended December 31, 2011, we:

 

 

Received $217.8 million for the sale of our Antelope Project (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Notes to Consolidated Financial Statements, Note 5 – Dispositions, Discontinued Operations);

 

 

Received $1.0 million for the sale of pipe inventory associated with the Antelope Project;

 

 

Received $1.4 million from the sale of our equity investment in Fusion Geophysical, LLC;

 

 

Deposited with a U.S. bank $1.2 million as collateral for a Standby Letter of Credit issued as a payment guarantee for drilling activities on Block 64 EPSA; and

 

 

Advanced $0.8 million to Petrodelta for continuing operations costs, and Petrodelta repaid $0.1 million.

Petrodelta’s capital commitments will be determined by its business plan. Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. Our budgeted capital expenditures of $40.1 million for 2013, of which $33.7 million is non-discretionary, for U.S., Indonesia 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.

Cash Flow from Financing Activities. During the year ended December 31, 2012, we:

 

 

Received cash proceeds of $66.5 million from an offering of $79.8 million in aggregate principal amount of our 11.0 percent senior unsecured notes (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Long-Term Debt); and

 

 

Incurred $3.3 million in legal fees associated with financings.

During the year ended December 31, 2011, we:

 

 

Repaid $60.0 million of our term loan facility (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Long-Term Debt);

 

 

Recorded $2.5 million of tax benefits related to the difference between book and tax deductions allowed for equity compensation; and

 

 

Incurred $0.2 million in legal fees associated with financings.

Contractual Obligations

At December 31, 2012, we had the following lease commitments for office space in Houston, Texas, regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Indonesia; Port Gentil, Gabon; and Muscat, Oman that support field operations in those areas.

 

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Location

   Date Lease Signed    Term      Annual
Expense
 

Houston, Texas

   April 2004      10 years       $ 204,000   

Houston, Texas

   December 2008      5 years         160,800   

Caracas, Venezuela

   October 2012      1 year         224,400   

London, U.K.

   September 2010      5 years         108,000   

Singapore

   October 2012      2 years         84,000   

Jakarta, Indonesia

   April 2012      2 years         98,500   

Muscat, Oman

   September 2011      2 years         62,400   

Gabon, Port Gentil

   December 2012      2 years         61,200   

We have various contractual commitments pertaining to exploration, development and production activities. These contractual commitments are included in the Contractual Obligations table below under Oil and gas activities.

 

 

The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period. This commitment was fulfilled with the drilling of DTM-1.

 

     Payments (in thousands) Due by Period  

Contractual Obligations

   Total      Less than
1 Year
     1-2 Years      3-4 Years      After  4
Years
 

Debt:

              

11.0% Senior Unsecured Notes Due 2014

   $ 79,750       $ —         $ 79,750       $ —         $ —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Debt

     79,750         —           79,750         —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Other obligations:

              

Interest payments

     15,620         8,773         6,847         —           —     

Oil and gas activities

     8,200         112         8,088         —           —     

Office leases

     1,459         773         537         149         —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total other obligations

     25,279         9,658         15,472         149         —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual obligations

   $ 105,029       $ 9,658       $ 95,222       $ 149       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

The four-year extension of the initial exploration phase on the Budong PSC includes an exploration well, which if not drilled by January 2016, results in the termination of the Budong PSC. Also, if this exploration well is not drilled within 18 months of the date of approval from the Government of Indonesia of this transaction, we will be required to pay our partner in the Budong PSC $3.2 million. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 14 – Indonesia.

Senior Unsecured Notes

On October 11, 2012, we closed an offering of $79.8 million in aggregate principal amount of our 11.0 percent senior unsecured notes. Under the terms of the notes, interest is payable quarterly in arrears on January 1, April 1, July 1 and October 1, beginning January 1, 2013. The senior unsecured notes will mature on October 11, 2014. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risks, Uncertainties, Capital Resources and Liquidity.

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 losses attributable to our international operations were minimal for the years ended December 31, 2012 and 2011. There are many factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our control. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.

 

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Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004, March 2005, January 2010, January 2011 and February 2013. As a result of the February 2013 devaluation, Harvest Vinccler estimates the impact of the devaluation to be approximately $0.1 million gain on revaluation of its assets and liabilities, and Petrodelta estimates the impact of the devaluation to be approximately $54.8 million gain on revaluation of its assets and liabilities.

Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar for 2012). However, during the year ended December 31, 2012, Harvest Vinccler exchanged approximately $1.5 million through SITME and received an average exchange rate of 5.16 Bolivars per U.S. Dollar. The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Petrodelta does not have, and has not had, any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate. Harvest Vinccler currently does not have any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate.

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Venezuela for a more complete discussion of the exchange agreements and their effects on our Venezuelan operations.

Within the United States and other countries in which we conduct business, inflation has had a minimal effect on us, but it is potentially an important factor with respect to results of operations in Venezuela. The inflation rate in Venezuela was 22.2 percent, 26.0 percent and 28.5 percent for January 2013, 2012, and 2011, respectively.

Critical Accounting Policies

Reporting and Functional Currency

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

Investment in Equity Affiliates

We evaluate our investments in unconsolidated companies under ASC 323, “Investments – Equity Method and Joint Ventures.” Investments in which we have significant influence are accounted for under the equity method of accounting. Under the equity method, Investment in Equity Affiliates is increased by additional investments and earnings and decreased by dividends and losses. We review our Investment in Equity Affiliates for impairment whenever events and circumstances indicate a loss in investment value is other than a temporary decline.

There are many factors to consider when evaluating an equity investment for possible impairment. Currency devaluations, inflationary economies, and cash flow analysis are some of the factors we consider in our evaluation for possible impairment.

Capitalized Interest

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

 

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Property and Equipment

We follow the successful efforts method of accounting for our oil and 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. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and 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 test 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 in accordance with ASC 932. The basis for grouping is 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 and/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.

Reserves

In December 2009, we adopted the SEC’s Modernization of Oil and Gas Reporting and ASC 932. ASC 932 requires the unweighted average, first-day-of-the-month price during the 12-month period preceding the end of the year be used when estimating reserve quantities and permits the use of reliable technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes.

Proved reserves are those quantities of oil and gas which by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, government regulations, etc. Prices include consideration of changes in existing prices provided only by contractual arrangements and do not include adjustments based upon expected future conditions. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves which are less certain to be recovered than probable reserves and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

 

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The estimate of reserves is made using available geological and reservoir data as well as production performance data. These estimates are prepared by an independent third party petroleum engineering consulting firm and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits earlier. A material adverse change in the estimated volumes of proved reserves could have a negative impact on DD&A expense and could result in the recognition of an impairment.

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.

We do not provide deferred income taxes on undistributed earnings of our foreign subsidiaries for possible future remittances as all such earnings are permanently reinvested as part of our ongoing business.

New Accounting Pronouncements

In July 2012, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2012-02, which is included in ASC 350, “Intangibles – Goodwill and Other” (“ASC350”). This update gives an entity the option first to assess qualitative factors in assessing whether an asset is impaired. ASU No. 2012-02 is effective for annual and interim impairment test performed for fiscal years beginning after September 15, 2012. Early adoption is permitted. The adoption of ASU No. 2012-02 did not have a material impact on our consolidated financial position, results of operation or cash flows.

In January 2013, FASB issued ASU No. 2013-01, which is included in ASC 210, “Balance Sheet”, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“ASU No. 2013-01”). This update clarifies that the scope of ASU 2011-11: “Disclosures about Offsetting Assets and Liabilities” applies only to derivatives accounted for under ASC 815 “Derivatives and Hedging”, included bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. ASU No. 2013-01 is effective for fiscal years and interim periods within those years, beginning on or after January 1, 2013. Entities should provide the required disclosures retrospectively for all comparative periods presented. The adoption of this guidance impacts presentation disclosures only and will not have an impact on our consolidated financial position, results of operation or cash flows.

In February 2013, FASB issued ASU No. 2013-02, which is included in ASC 220, “Comprehensive Income”, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” (“ASU NO. 2013-02”). This update requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under USGAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under USGAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under USGAAP that provide additional detail about those amounts. The amendments of ASU No. 2013-02 do not change the current requirements for reporting net income or other comprehensive income in financial statements. ASU No. 2013-02 is effective for fiscal years and interim periods within those years, beginning on or after December 15, 2012. Early adoption is permitted. The adoption of this guidance impacts presentation disclosures only and will not have an impact on our consolidated financial position, results of operation or cash flows.

In February 2013, FASB issued ASU No. 2013-04, which is included in ASC 405, “Liabilities”, “Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date”. This update provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation with the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in USGAAP. Examples of obligations within the scope to ASU No. 2013-04 include debt arrangements, other contractual obligations, and settled litigation and judicial rulings. ASU No. 2013-04 is effective for fiscal years and interim periods within those years beginning after December 5, 2013. Entities should provide the required disclosures retrospectively for all comparative periods presented. The adoption of this guidance impacts presentation disclosures only and will not have an impact on our consolidated financial position, results of operation or cash flows.

In March 2013, FASB issued ASU No. 2013-05, which is included in ASC 830, “Foreign Currency Matters”, “Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity” (“ASU 2013-05”). This update resolves the diversity in practice regarding the release into net income of the cumulative translation adjustment upon derecognition of a subsidiary or group of assets within a foreign entity. ASU No. 2013-05 is effective for fiscal years and interim periods within those years beginning after December 5, 2013. ASU No. 2013-05 is not expected to have a material impact on our consolidated financial position, results of operation or cash flows.

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, 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 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.

 

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Interest Rates

Total long-term debt at December 31, 2012 consisted of $75.0 million of fixed-rate senior unsecured notes maturing in 2014. A hypothetical 10 percent adverse change in the prime rate would not have a material effect on our results of operations for the year ended December 31, 2012.

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 on pages S-1 through S-68.

 

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, 2012, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) were not effective because of the material weaknesses in our internal control over financial reporting described below. Notwithstanding this determination, our management concluded that the consolidated financial statements (as restated for 2010 and 2011) in this Annual Report on Form 10-K fairly present, in all material respects, our financial position and results of operations and cash flows as of the dates and for the periods presented, in conformity with accounting principles generally accepted in the United States of America (“USGAAP”).

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). Internal control over financial reporting is defined as a process designed by, or under the supervision of, the issuer’s principal executive and principal financial officer’s, or persons performing similar functions, and effected by the Company’s board of directors, management, and other personnel, to provide reasonable assurance regarding reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures which (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets of the Company, (b) 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 are being made only in accordance with authorizations of management and the board of directors, and (c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the financial statements. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

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 Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of The Treadway Commission. Based on our evaluation under the Internal Control Integrated Framework, our management concluded that our internal control over financial reporting was not effective as of December 31, 2012 as a result of material weaknesses described below.

 

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Sufficient Complement of Accounting and Financial Reporting Resources

In certain areas, we did not maintain a sufficient complement of resources with an appropriate level of accounting knowledge, experience and training commensurate with our financial reporting requirements. This limited our ability, in certain areas, to ensure the necessary consistent communication, reinforcement, and application of accounting policies to make appropriate accounting and disclosure decisions. This material weakness contributed to the material weaknesses set forth below.

Accounting for Certain Transactions for Oil and Gas Properties

We did not maintain effective internal control over the accuracy, valuation and application of USGAAP related to capitalization, classification, and impairment of certain costs related to oil and gas properties. Specifically, effective controls were not designed or effectively operating to review the nature and classification of costs to be capitalized to oil and gas properties which impacts the accurate calculation of oil and gas property impairments. This control deficiency resulted in the misstatement of oil and gas properties, exploration expense, and related financial statement disclosures.

Accounting for Income Taxes

We did not maintain effective controls over the completeness, accuracy, presentation and disclosure of our accounting for income taxes, including income tax expense and income tax assets and liabilities. Specifically, we did not maintain effective controls to (1) document our analysis, considerations and evaluation of relevant facts related to our accounting judgments for income taxes, (2) account for uncertain tax positions, and (3) ensure appropriate recording and presentation of our net operating losses and associated valuation allowance and related footnote disclosures. This control deficiency resulted in the misstatement of income tax expense, deferred tax assets, our valuation allowance, related financial statement disclosures, and our financial statement schedule.

Financial Reporting Process

We did not maintain effective internal control over certain of our financial close and reporting processes because of the following material weaknesses:

 

  (a) We did not maintain effective controls over segregation of duties related to certain system access rights and the recording and review of journal entries for validity, accuracy, and completeness for substantially all significant accounts. Specifically, certain individuals have incompatible access rights within key IT systems and certain accounting personnel have the ability to prepare and post journal entries without an independent review that is designed with sufficient rigor and precision to prevent or detect an error.

 

  (b) We did not maintain effective controls over the preparation and review of certain classification and disclosure matters impacting the financial statements and related notes. Specifically, controls are not designed and operating effectively to accumulate and review all information required to ensure complete, accurate, and proper presentation of the statement of cash flows and financial statement disclosures. This control deficiency resulted in the misstatement of cash provided by or used in investing and operating activities and related financial statement disclosures and the misstatement of segment information.

 

  (c) We did not maintain effective controls over significant and complex debt and equity transactions. Specifically, controls were not designed and operating effectively to ensure completeness and accuracy over the identification, evaluation, analysis and recording of significant and complex debt and equity transactions and the associated financial statement impact. This control deficiency resulted in the misstatement of debt, additional paid-in capital, debt conversion expense, interest expense, unrealized gain (loss) on warrant derivatives, loss on extinguishment of debt and related financial statement disclosures.

Additionally, each of the control deficiencies described above could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements and financial statement schedule that would not be prevented or detected. Certain of these material weaknesses resulted in errors which required the restatement of our annual consolidated financial statements for the years ended December 31, 2010 and 2011 and the unaudited interim consolidated financial statements for all quarters in 2011 and the first three quarters of 2012 and also resulted in recorded audit adjustments for the fourth quarter and annual period ended December 31, 2012.

The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Remediation Plan. In response to the identified material weaknesses, our management, with oversight from our Audit Committee will dedicate appropriate resources to remediate the material weaknesses described above. Until the remediation steps set forth below are fully implemented, the material weaknesses described above will continue to exist.

 

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Management is taking the following actions to remediate the material weakness related to oil and gas properties described above:

 

   

Formalize policies and procedures for the appropriate recording of oil and gas property transactions.

 

   

Train the accounting staff on the above policies and procedures.

 

   

Establish timely independent review and approval of oil and gas property transactions and schedules.

 

   

Redesign the controls for the evaluation, analysis, recording and review of oil and gas property transactions.

Management is taking the following actions to remediate the material weakness related to income tax accounting described above:

 

   

Formalize the policies and procedures for appropriate recording of income taxes.

 

   

Maintain and update memorandum to reflect the current status of income tax accounting positions and the relevant analysis, considerations and conclusions.

 

   

Redesign the controls for income taxes to ensure the level of precision and operating effectiveness required by management.

 

   

Redesign the controls for income taxes to ensure appropriate presentation and disclosure of the associated footnotes and financial statement schedule.

 

   

Supplement existing resources with additional personnel and additional training.

Management is taking the following actions to remediate the material weaknesses related to our Financial Reporting Process and complement of accounting and financial reporting resources:

 

   

Implement a sufficiently-designed control that is intended to ensure functions are appropriately segregated and that all journal entries are reviewed by an appropriate person.

 

   

Modify the system access of individuals with incompatible responsibilities and/or design compensating controls that operate at the appropriate level of precision to address the associated conflict.

 

   

Redesign the controls for the preparation, execution and review of the cash flow statement and financial statement disclosures.

 

   

Redesign certain entity-level monitoring controls and certain transaction level controls in order to achieve the level of precision and operating effectiveness required by management.

 

   

Redesign the controls over significant and complex debt and equity transactions to ensure appropriate identification, evaluation, analysis and recording of such transactions.

 

   

Supplement our accounting department with additional personnel and provide additional training to our personnel regarding the application of USGAAP.

Inherent Limitations of Internal Controls. Internal control over financial reporting has inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements will not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

Changes in Internal Control over Financial Reporting. There have been no changes in internal control over financial reporting during the quarter ended December 31, 2012 that have materially affected or are reasonably likely to materially affect that Company’s internal control over financial reporting.

 

Item 9B. Other Information

None.

 

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PART III

 

Item 10. Directors, Executive Officers and Corporate Governance

DIRECTORS

There are currently seven members of our Board of Directors (the “Board”), each of whom has been nominated for reelection to the Board this year and will stand for election at our annual meeting. Information regarding the business experience of each nominee is provided below. All directors are elected annually to serve until the next annual meeting and until their respective successors are elected.

When considering whether directors and nominees have the experience, qualifications, attributes and skills, taken as a whole, to enable the Board to satisfy its oversight responsibilities effectively in light of the Company’s business and structure, the Nominating and Corporate Governance Committee, which is a Committee of the Board responsible for recommending director candidates to be nominated by the Board, and the Board focused primarily on the information discussed in each of the directors’ individual biographies set forth below.

In particular, with regard to Messrs. Chesebro’, Edmiston, Irelan and Stinson and Dr. Effimoff, the Nominating and Corporate Governance Committee considered their strong backgrounds in the oil and gas sector, believing that their individual experiences at management levels with large multinational corporations engaged in oil and gas exploration and production are invaluable in evaluating the performance of management and other aspects of the Company. The Nominating and Corporate Governance Committee considered Mr. Murray’s individual experiences at management levels with large multinational corporations engaged in oil and gas services as a valuable complement to the experiences of the other directors. Additionally, the Nominating and Corporate Governance Committee considered the engineering education and experiences of Messrs. Chesebro’, Edmiston, Stinson and Irelan and Dr. Effimoff important to understand the goals and challenges of the Company and to effectively advise the direction of the Company in the oil and gas industry. With respect to Messrs. Hardee and Murray, the Nominating and Corporate Governance Committee considered their significant experience, expertise and background with regard to financials and financial and accounting matters and business management. The Nominating and Corporate Governance Committee also considered the broad perspective brought by Mr. Hardee’s and Dr. Effimoff’s experiences in consulting to clients and, with respect to Messrs. Hardee and Murray, serving in directorships in many diverse industries. The Nominating and Corporate Governance Committee also considered the many years of experience with the Company and in the industry represented by Mr. Edmiston, our Chief Executive Officer (“CEO”). Additionally, with respect to Messrs. Chesebro’, Edmiston, Irelan, Murray and Stinson and Dr. Effimoff, the Nominating and Corporate Governance Committee considered their experience in international business vital to the Company’s global strategy. With respect to Mr. Stinson, the Nominating and Corporate Governance Committee believes that his experience in governmental relations on an international level provides valuable insight to assist management in establishing and maintaining their relationships with foreign governments, which is a primary focus of the Company.

 

Stephen D. Chesebro’

Appointed Director in October 2000

Age 71

   Mr. Chesebro’ has served as the Chairman of the Board of Harvest since 2001. From December 1998 until he retired in 1999, he served as President and Chief 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

 

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   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. Since December 2005, he has served as the President of the Chesebro’ Foundation, Inc., a private charitable foundation incorporated in Delaware.

James A. Edmiston

Elected Director in May 2005

Age 53

   Mr. Edmiston was elected President and Chief Executive Officer of Harvest 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. Mr. Edmiston earned a Bachelor of Science degree in Petroleum Engineering from 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 Texas Tech College of Engineering in 2009. Mr. Edmiston is a Member of the Society of Petroleum Engineers.

Dr. Igor Effimoff

Appointed Director in February 2008

Age 67

   Dr. Igor Effimoff is founder and principal of a firm which provides upstream and midstream consulting services since 2005. From 2002 until 2005 he was Chief Operating Officer for Teton Petroleum

 

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   Company. Between 1996 and 2001, he was President of Pennzoil Caspian Corporation, managing their interests in the Caspian Region. Between 1994 and 1996 he was the Chief Executive Officer of Larmag Energy, NV, a privately held Dutch oil and gas production company with its primary assets in the Caspian Sea. He has served in senior executive roles with Ashland Exploration Inc., Zilkha Energy Company and Kriti Exploration, Inc. Dr. Effimoff has authored numerous technical and business articles. He is a member of American Association of Petroleum Geology, the Society of Petroleum Engineers, the Society of Exploration Geophysicists and the Geological Society of America. Dr. Effimoff served on the audit and compensation committees of TrueStar Petroleum Corporation in 2007. He currently serves on the board of IPC Oil and Gas Holdings Ltd. He has a Doctorate in Geology from the University of Cincinnati and completed the Harvard Advanced Management Program.

H. H. Hardee

Appointed Director in October 2000

Age 58

   Mr. Hardee is a Senior Vice President—Financial Advisor with RBC Wealth Management, since 1994. From 1991 through 1994, Mr. Hardee was a Senior Vice President with Kidder Peabody. From 1977 through 1991, Mr. Hardee was a Senior Vice President at Rotan Mosle/Paine Webber Inc. Mr. Hardee was named as one of America’s best financial advisors for 2009, 2010, 2011 and 2012 by Barron’s financial newspaper and by Reuters AdvicePoint. Furthermore, Mr. Hardee has been recognized by NABCAP, the National Association of Board Certified Advisory Practices, as a Premier Wealth Advisor. He currently advises/manages over $400 million in assets. Mr. Hardee’s expertise is advising high net worth individuals and small to mid-sized corporations. Mr. Hardee is a former director of the Bank of Almeda and Gamma Biologicals. He is also a former limited partner and advisory director of the Houston Rockets of the National Basketball Association. Mr. Hardee has a finance degree from the McCombs School of Business at the University of Texas. He has earned an Accredited Wealth Management designation through the Estate and Wealth Strategies Institute of Michigan State University. Mr. Hardee is a National Association of Corporate Directors (“NACD”) Board Leadership Fellow. He has demonstrated his commitment to boardroom excellence by completing NACD’s comprehensive program of study for corporate directors. He supplements his skill sets through ongoing engagement with the director community and access to leading practices.

 

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Robert E. Irelan

Appointed Director in February 2008

Age 66

   Mr. Irelan has over 37 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.

Patrick M. Murray

Appointed Director in October 2000

Age 70

   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 currently serves on the board and audit committee of Precision Drilling Corporation, a publicly-held contract drilling company. Mr. Murray is also on the board of the World Affairs Council of Dallas Fort Worth. He is on the board of advisors for White Deer Energy, 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 Bachelor of Science 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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J. Michael Stinson

Appointed Director in November 2005

Age 69

   From September 2006 to December 2011, Mr. Stinson was Chairman of TORP Terminal LP, the U.S. unit of a Norwegian LNG technology company. From 2004 until November of 2009, he served as a director of Enventure Global Technology, Inc., an oil equipment company, most recently as the Chairman of its Audit and Finance Committee. From January 2005 until November 2009, he was Chairman of the Board of Paulsson Geophysical Services, Inc., a vertical seismic profiling technology company. From February through August 2004, Mr. Stinson served with the U.S. Department of Defense and the Coalition Provisional Authority as Senior Advisor to the Iraqi Ministry of Oil. From 1965 to 2003, Mr. Stinson was with Conoco and ConocoPhillips in a number of assignments in operations and management. His last position at ConocoPhillips was as Senior Vice President, Government Affairs in which he was responsible for government relations with particular emphasis on developing and facilitating international business development opportunities in various countries. Previous positions included Senior Vice President – Business Development, Vice President – Exploration and Production, Chairman and Managing Director of Conoco (UK) Limited, Vice President/General Manager of International Production for Europe, Africa and the Far East and President and Managing Director of Conoco Norway, Inc. Mr. Stinson earned a Bachelor of Science degree in Industrial Engineering from Texas Tech University and a Master of Business Administration from Arizona State University. He is a member of the Society of Petroleum Engineers and the American Association of Petroleum Geologists.

EXECUTIVE OFFICERS

The following table provides information regarding each of our executive officers.

 

Name

   Age   

Position

James A. Edmiston *    53    President and Chief Executive Officer
Stephen C. Haynes    56    Vice President, Finance, Chief Financial Officer and Treasurer
Keith L. Head    55    Vice President, General Counsel and Corporate Secretary
Karl L. Nesselrode    55    Vice President, Engineering & Business Development
Robert Speirs    57    Senior Vice President, Eastern Operations

 

* See Mr. Edmiston’s biography under the section entitled “Directors” above.

Stephen C. Haynes has served as our Vice President, Chief Financial Officer and Treasurer since May 19, 2008. Mr. Haynes performed various financial consulting engagements from January 1, 2008 until his

 

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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 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 appointments 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 currently serves on two non-profit boards: MentorCONNECT and the Texas Accountants and Lawyers for the Arts. He is also a board member of the Houston chapter of The General Counsel Forum. Mr. Head holds a Bachelor of Science degree in Business Administration from the University of North Carolina. He received both a Juris Doctorate and Master of 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 the 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.

SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Exchange Act (“Section 16(a)”) requires our directors, executive officers and beneficial holders of more than 10% 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 2012, our officers, directors and 10% stockholders complied with all Section 16(a) filing requirements. In making this statement, we have relied upon the written representations of our directors and officers.

 

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CODE OF BUSINESS CONDUCT AND 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 2010. The Board has not granted any waivers to the Code of Business Conduct and Ethics.

The Code of Business Conduct and Ethics is accessible on our website under the Corporate Governance section at http://www.harvestnr.com. Any amendments to or waivers of the Code of Conduct and Business Ethics will also be posted on our website.

AUDIT COMMITTEE

The Board has a standing Audit Committee. 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 independent registered public accounting firm and to approve any non-audit relationship with the independent registered public accounting firm. Our internal auditor and the independent registered public accounting firm report directly to the Audit Committee.

Dr. Effimoff and Messrs. Hardee, Murray and Stinson are members of the Audit Committee. The Board has determined that each member of the Audit Committee meets the independence standards of the SEC’s requirements, the rules of the NYSE and the Company Guidelines for Corporate Governance, which is an internal policy that requires independent directors comprise a majority of the Board and that the Chairman of the Board be elected from the independent directors. 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 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 above under the section entitled “Directors.”

 

Item 11. Executive Compensation

COMPENSATION DISCUSSION AND ANALYSIS

Introduction

Harvest’s Compensation Discussion and Analysis describes the Company’s compensation program for the executive officers identified in the Summary Compensation Table. Throughout this proxy statement we refer to these individuals as “named executive officers.” They are James A. Edmiston, President and CEO; Stephen C. Haynes, Vice President, 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.

 

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Summary of Executive Compensation Decisions Made in 2012/2013

During 2012, our executive compensation decisions included:

 

   

Base salary increases of 1.8% for the CEO and averaging 3.3% for the other named executive officers were effective in March 2012;

 

   

In addition to individual performance objectives, the Human Resources Committee, which is a Committee of the Board that is responsible for establishing and recommending to the Board all elements of executive and Board compensation (the “HR Committee”), established Company annual incentive performance measures as follows:

 

   

Total Shareholder Return (weight 60%)

 

   

Reserve Additions/Production (weight 30%)

 

   

Social Responsibility and Governance (including safety) (weight 10%)

 

   

Annual cash incentive awards were paid in February 2013. The CEO received 137% of his target incentive and the other named executive officers also received an average of 137% of their target incentives. This reflects an increase in the annual incentive target for the named executives to 60% of base salary. Since 2008, we have been consistently low for this benchmark. This increase was approved at the February 2013 HR Committee meeting and effective for the 2012 incentive awards.

 

   

Long-term incentive awards were paid with approximately 30% restricted stock and 70% stock options valued at the closing stock price on May 17, 2012.

During 2013, our executive compensation decisions included:

 

   

Base salary increases of 3.5% for the CEO and averaging 3.5% for the other named executive officers were effective in March 2013.

Company Overview and Compensation Objectives

As a Company, our focus is on acquiring exploration, development, and producing properties in proven and active hydrocarbon systems. We operate from our Houston, Texas headquarters with regional/technical offices in the United Kingdom and Singapore and field offices in Jakarta, Indonesia; Port Gentil, Gabon; and Muscat, Oman.

In 2012, we achieved the following results:

 

   

Increased gross production in Venezuela to 13.2 million barrels of oil or an average of 36,979 barrels of oil per day, an increase of 14.7% over 2011;

 

   

Agreed third production phase with the Republic of Gabon to four years until May 2016.

 

   

Completed drilling of the Dussafu Tortue well in the fourth quarter of 2012 and announced an oil discovery of approximately 42 feet of pay in the Gamba formation and 123 feet of pay in the Dentale formation.

 

   

Received a four-year extension by the Indonesian government until January 2017 for the Budong Budong Block and agreed with our partner to assume operatorship of the block.

 

   

Maintained proved and probable (2P) reserve level from 2011, net of 2012 production.

 

   

Signed Sales Purchase Agreement with Pertamina, National Oil Company of Indonesia, which set the benchmark price for our Venezuelan Assets.

 

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The following graphs highlight the Company results for 2012:

 

LOGO

 

LOGO

Note: Annual Net Production and Net Proved and Probable Reserves for 2010 include production and reserves from the Utah asset which were sold in 2011. (MBOE = Thousand Barrels of Oil Equivalent)

The HR Committee has the discretion to exercise their judgment in weighing the achievement of specific performance measures. For 2012, it considered total shareholder return, reserves, social responsibility/governance and safety as well as strategic individual objectives for the named executive officers. Total shareholder return (“TSR”) was up 22.9% in 2012 and the Company remained in the top quartile of its Peer Group over a three-year period from 2010—2012. Proved and probable reserves were down slightly by 4% from the prior year. We calculate TSR as year-end share price minus beginning year share price divided by beginning year share price. Annual net production in 2012 was up 14% over the prior year. Companywide health and safety programs were implemented in 2012. There were no Foreign Corrupt Practices Act (“FCPA”) incidents in 2012. Ethics and compliance guidelines were revised in 2012, and there was one contractor lost time accident in 2012. Given the operational and technical challenges faced by the Company, the Committee determined that the management team effectively managed the exploration assets we controlled and operated during the year.

Compensation Philosophy

Our compensation philosophy is to offer a competitive total compensation package to enable us to attract, motivate and retain key executives. Our compensation objectives include:

 

   

Offering total compensation that is competitive with the select peer group of globally-focused oil and gas companies with which we compete for executive talent;

 

   

Providing annual cash incentive awards that take into account performance factors weighted by both corporate and individual goals;

 

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Aligning the interest of executive officers and directors with stockholder value creation by providing significant equity-based, long-term incentives; and

 

   

Providing incentives to executives for achieving challenging corporate goals.

The HR Committee oversees the development and execution of our compensation program. The HR Committee annually reviews our compensation philosophy and tests its ability to promote meeting the objectives stated above. The HR 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 for approval. Three independent directors comprise the HR Committee. The HR 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.

Setting Executive Compensation

Our compensation program consists of several forms of compensation: base salary, annual performance-based incentive awards, long-term incentives and personal benefits. Base salary and annual performance-based incentive awards are generally 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 for its approval.

The Role of the Compensation Consultant—Compensation Consultant Independence

In 2012, the HR Committee engaged Frost Human Resource Consulting (“Frost HR Consulting”), as the HR 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 HR Committee directly retained and has the authority to terminate Frost HR Consulting.

 

   

Frost HR Consulting reports directly to the HR Committee and its Chairperson.

 

   

Frost HR Consulting meets regularly in executive sessions with the HR Committee.

 

   

Frost HR Consulting has direct access to all members of the HR Committee during and between meetings.

 

   

Interactions between Frost HR Consulting and management generally are limited to data gathering and discussions regarding information that has or will be presented to the HR Committee.

 

   

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 HR Committee.

 

   

Frost HR Consulting consultants do not own any of our Company stock.

Peer Group and Compensation Surveys

The HR Committee considers market information from compensation surveys and peer company proxy statements when determining compensation for each of the executive officers. In May 2012, the HR Committee reviewed proxy statement data from a peer group of companies. The surveys used for benchmarking included:

 

   

Towers Watson 2011 Top Management Compensation Survey

 

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William M. Mercer 2011 Energy Industry Compensation Survey

 

   

Effective Compensation Inc.’s (“ECI”) 2011 Oil and Gas Industry Compensation Survey

Each year, the HR Committee reviews the composition of the peer group and the compensation paid at these companies, as well as their corporate performance and other comparative factors in determining the appropriate compensation levels for our executives. No company in our peer group shares our unique risk profile, which is a function of our portfolio of producing assets and exploratory prospects, as well as the regulatory and political environments in which we operate. Therefore, the HR Committee uses its judgment and business experience in addition to the peer group data in determining executive compensation.

The HR 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 peer companies ranges from $35 million to $423 million for 2012 versus $405 million for Harvest, which is our 32% interest of gross revenue from oil sales in our unconsolidated affiliate, Petrodelta, S.A. Our peer companies typically compete with us for executive talent. Our current industry peer group consists of the following companies:

 

•   BPZ Resources, Inc.

  

•   GeoResources, Inc. (later in 2012 acquired by Halcón Resources, LLC)

•   Carrizo Oil and Gas Inc.

  

•   Halcón Resources, LLC (formerly Ram Energy Resources, Inc.)

•   Crimson Exploration Inc.

  

•   Gulfport Energy, Corp.

•   Endeavour International Corp.

  

•   Petroleum Development Corp.

•   Energy Partners Ltd (now ELP Oil & Gas Inc.)

  

•   PetroQuest Energy, Inc.

•   FX Energy, Inc.

  

•   Toreador Resources, Corp. (later in 2012 acquired by ZaZa Energy Corp) and

•   Gastar Exploration Ltd

  

•   VAALCO Energy, Inc.

For 2012, Frost HR Consulting benchmarked the 25th, 50th and 75th percentiles for the data sources mentioned above to provide the HR Committee with an understanding of competitive pay practices. These surveys, equally weighted with the proxy data, consider each element of compensation and are collectively referred to as the “market data” throughout this Compensation Discussion and Analysis. Frost HR Consulting also provides the HR Committee with advice on equity incentive compensation trends, including types and value of awards being used by other public companies.

The Role of the Executives in Human Resources Committee Meetings

The HR Committee invites our CEO, Vice President, Administration and Human Resources and Vice President, General Counsel and Corporate Secretary to attend their meetings. The Vice President, Administration and Human Resources acts as the HR 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 HR 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.

 

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The CEO makes detailed recommendations to the HR 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 management are invited to participate in HR Committee meetings to provide information regarding our strategic objectives, financial performance and recommendations regarding compensation plans. Management may be asked to prepare information for any HR Committee meeting. Depending on the agenda for a particular meeting, these materials may include:

 

   

Reports on our strategic objectives;

 

   

Financial reports;

 

   

Reports on achievement of individual and corporate performance objectives;

 

   

Information regarding compensation programs and compensation levels for executive officers, directors and other employees at peer companies;

 

   

Information on the total compensation of the executive officers, including base salary, cash incentives, equity awards, and other compensation, and any amounts payable to the executive officers upon voluntary or involuntary termination or following a severance with or without a change in control; and

 

   

Information regarding all annual and equity incentive-based compensation and health and welfare plans.

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. It is essential that we recruit and retain executives that understand the risk and complexity of global operations and our unique business strategy. All of our executive officers are mid-to-late career executives who have worked for larger energy companies and have alternatives; they decided to join the Company for the challenge and potential reward of working for a small, entrepreneurial organization.

The principal components of compensation and their purpose for executive officers in 2012 are:

 

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 the Company’s share
price and for retaining executives
Personal benefits    Eligibility to participate in plans extends to all employees    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 HR 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 2011 market data, our base salaries were between 95.6% and 106.2% of the target market median.

For 2012, the HR Committee moved the Company’s salary management review to February from May to better address cash compensation decisions for both salaries and bonuses. Consequently, in March 2012 the CEO received an annualized salary increase for 2012 of 1.8% and the other named executive officers received an average annualized increase of 3.3%. In March 2013, the CEO received an annual salary increase of 3.5% and the other named executive officers each received an annualized increase of 3.5% as well.

 

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Base Salary-

Annualized

  

Mr. Edmiston

  

Mr. Speirs

  

Mr. Haynes

  

Mr. Nesselrode

  

Mr. Head

2012

   $550,000    $345,000    $295,000    $270,000    $265,000

2013

   $570,000    $360,000    $305,000    $280,000    $275,000

Annual Performance-Based Incentive Awards

Each year, in addition to individual performance objectives, the HR Committee establishes Company performance measures for determining annual incentive awards as follows:

 

   

Total Shareholder Return (weight 60%)

 

   

Reserve Additions/Production/Estimated Market Value (“EMV”) (weight 30%)

 

   

Social Responsibility and Governance (including safety) (weight 10%)

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 set by the CEO and reviewed and approved by the HR Committee. The HR 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%. In 2012, the Company realized a Total Shareholder Return of 22.9% placing it in the first quartile among its selected peer group.

Reserves/Production/EMV was weighted at 30%. The primary measurement for this target is year-over-year P2 reserve additions; although 3P and contingent resources are also taken into consideration. For 2012, proved and probable reserves remained essentially flat over 2011, net of 2012 production. However, production increased by 14.7% over 2011 at Petrodelta, our Venezuelan affiliate.

Social Responsibility and Governance was weighted at 10% and is used at the discretion of the CEO and the Committee in deciding the final corporate rating. As expected, there were no violations of our FCPA policies or our Code of Business Conduct and Ethics. One of our contractors did experience a lost time accident in 2012.

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 2012 performance, awarded in February 2013, the CEO received 137% of his bonus target as a performance-based incentive award. The other named executive officers individual awards ranged from 130% to 143% of their bonus targets.

The HR Committee and the Board each determined that management exceeded expectations in meeting the 2012 Company and individual performance targets.

We believe the Company should have the ability to recover compensation paid to executive officers and key employees under certain circumstances. As a result, the HR Committee adopted the following policy statement in 2011:

“In the event the Board of Directors determines that any fraud or intentional misconduct caused or was a substantial contributing factor to a restatement of our financial statements, the Board of Directors may require reimbursement of any annual incentive compensation paid to an executive officer or certain other key employees to the extent the bonus paid exceeded what would have been paid had the financial results been properly reported. This policy will apply to all annual incentives paid after January 2012.”

 

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Long-Term Incentive Compensation

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 that the Company deems was not warranted after any restatement of corporate performance.

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, 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 HR Committee is the administrator of our LTIPs and, subject to Board 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 HR Committee, and after review and discussion the HR Committee submits its recommendation to the Board for approval. The HR Committee’s policy is to grant awards on the date the Board approves them. Stock options and restricted stock 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 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% 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 HR 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 in the Company’s securities, including short sales and buying or selling puts or calls on the Company’s securities.

The long-term incentive awards for 2012 included stock options, stock appreciation rights (“SARs”), which can be settled as cash or equity, and restricted stock units (“RSUs”), which can be settled as cash or equity. This mix provides upside potential with the stock options and a more stable award in the form of restricted stock units. Of the total award value, 70% was allocated to options and 30% to restricted shares.

Mix of Long Term Incentives Awarded in 2012

 

     Options      SARS      RSU  

James A. Edmiston

     130,000         219,000         79,000   

Stephen C. Haynes

     37,000         61,000         23,000   

Keith L. Head

     34,000         53,500         21,000   

Karl L. Nesselrode

     34,000         56,000         21,000   

Robert Speirs

     43,000         72,000         27,000   

As of December 31, 2012, almost all of the total shares available for grant as options under the LTIPs approved by our stockholders have been granted:

 

Total available for grant as options

     85,006   
  

 

 

 

Total available for grants as restricted stock

     6   
  

 

 

 

 

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Personal Benefits

Our executive officers are covered under the same health and welfare 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% 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 $3,000 per individual and $9,000 per family.

 

   

Life and accidental death and dismemberment (“AD&D”) insurance equal to two times annual salary with a minimum of $200,000 and a cap of $300,000 (or $400,000 with evidence of insurability), and additional coverage equal to five times annual salary ($1.0 million maximum) while traveling outside their home country on Company business.

 

   

Long-term disability benefits provide a monthly benefit of 60% of base salary up to a maximum of $10,000 per month.

 

   

Participation in our Statutory Profit Sharing Plan 401(k). Eligibility is effective the first day of the month following the date of hire. We use a safe harbor matching formula for Company contributions (dollar for dollar match up to 3% of pay, $0.50 for every dollar on the next 2% of pay subject to the statutory maximum salary limits). Participant and Company contributions are 100% vested from the date of contribution. At termination of employment, employees are eligible to receive their account balance in a lump sum.

 

   

All employees and their dependents receive annual dental and vision care benefits of $1,500 and $250, respectively, per employee and dependent.

We do not offer a pension plan or a non-qualified deferred compensation plan for executive officers or employees. In 2012, we did not offer perquisites to executive officers or other employees. We offer relocation and Foreign Service premiums to employees serving in an international location. The amount of the premium will vary depending upon the living conditions, political situation and general safety conditions of the international location. Expatriate employees are also provided housing and utilities allowances where applicable. They also receive a cost of living allowance to cover the differential between normal living expenses in the host and home countries and will continue to participate in the employee benefit plans available to home country employees.

Total Direct Compensation

Executive Compensation Compared to Market Data

Compared to 2011 market data, total direct compensation ranged between 82% and 128% of the target market median for all named executive officers. In 2012, their compensation (after their March 2012 base salary increases) fell at the following percentiles:

 

2012 Actual Compensation in

Relationship to 2011 Actual Market Data

  

CEO

  

Other Named Executive Officers

Base Salary

   48th Percentile    48th to 58th percentile

Actual Total Cash

   53rd Percentile    48th to 57th percentile

Actual Total Direct Compensation

   63rd Percentile    51st to 84th percentile

 

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Executive Compensation Mix

The general mix of compensation for target-level performances in the annual incentive plan, plus the net annualized present value of long-term compensation grants, can range as follows, depending upon the executive officer. The Committee considered the following general percentage mix in establishing the total compensation for the Company’s executive officers for 2012 target performance. It is important to note that the influences on Company financial performance and stock price performance could significantly change the basic mix of compensation components as a percentage of total compensation:

 

LOGO LOGO

For the CEO, 73.6% of his total direct compensation is considered “at-risk.” The other named executive officers have 67% of their total direct compensation at risk.

 

LOGO

 

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LOGO

Note: Annual incentive (“AI”) for Messrs. Edmiston, Nesselrode and Head includes a special accomplishment award for the sale of Utah in 2011.

Tax and Accounting Implications of Executive Compensation

Deductibility of Executive Compensation

As part of its role, the HR Committee reviews and considers the deductibility of executive compensation under Section 162(m) of the Internal Revenue Code of 1986, as amended, which imposes a limit of $1.0 million on the amount that a publicly-held corporation may deduct in any year for the compensation paid or accrued with respect to its named executive officers unless the compensation is performance based. None of our executive officers currently receives compensation exceeding the limits imposed by Section 162(m). While we cannot predict with certainty how executive compensation might be affected in the future by Section 162(m) or applicable tax regulations issued, we intend to preserve the tax deductibility of all executive compensation while maintaining our executive compensation program as described in this Compensation Discussion and Analysis.