UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-K

 

(Mark One)

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

For the fiscal year ended December 31, 2014 

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)

 

 

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

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

 

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

 

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ◻ 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ◻ 

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

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

The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 2014 was: $ 210,047,738.  

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practical date. Class: Common Stock, par value $0.01 per share, on March 20, 2015, shares outstanding: 42,747,567.  

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement relating to its 2015 annual meeting of shareholders, or information to be included in an amendment to the Form 10-K, in either case which the Registrant intends will be filed with the Securities and Exchange Commission not later than 120 days after the end of the Registrant’s fiscal year, are incorporated by reference under Part III of this Form 10-K where indicated.  

 

 

---

 

HARVEST NATURAL RESOURCES, INC.

FORM 10-K

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 any forward-looking statements. These factors include our concentration of operations in Venezuela; political and economic risks associated with international operations (particularly those in Venezuela); anticipated future development costs for undeveloped reserves; drilling risks; risk that actual results may vary considerably from reserve estimates; the dependence on the abilities and continued participation of our key employees; risks normally incident to the exploration, operation and development of oil and natural gas properties; risks incumbent to being a noncontrolling interest shareholder in a corporation; permitting and drilling of oil and natural gas wells; availability of materials and supplies necessary to projects and operations; prices for oil and natural gas and related financial derivatives; changes in interest rates; our ability to acquire oil and natural gas properties that meet our objectives; availability and cost of drilling rigs and seismic crews; overall economic conditions; political stability; civil unrest; acts of terrorism; currency and exchange risks; currency controls; changes in existing or potential tariffs, duties or quotas; changes in taxes; changes in governmental policy; lack of liquidity; availability of sufficient financing; estimates of amounts and timing of sales of securities; changes in weather conditions; and ability to hire, retain and train management and personnel. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

 

---

 

 

Item  1.    Business

Executive Summary

Harvest Natural Resources, Inc. is a petroleum exploration and production company incorporated under Delaware law in 1988. Our focus is on acquiring exploration, development and producing properties in geological basins with proven active hydrocarbon systems. Our experienced technical, business development and operating personnel have identified low entry cost exploration opportunities in areas with large hydrocarbon resource potential. We acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). In addition to our interests in Venezuela, we hold exploration acreage mainly offshore of Republic of Gabon (“Gabon”). We operate from our Houston, Texas headquarters. We also have regional/technical offices in Singapore and Caracas, Venezuela and a field office in Gabon to support field operations in those areas.

Our Venezuelan interests are owned through our 51 percent ownership interest in Harvest-Vinccler Dutch Holding B.V., a Dutch private company with limited liability (“Harvest Holding”).  The remaining 49 percent ownership interest of Harvest Holding is owned by Oil & Gas Technology Consultants (Netherlands) Cooperatie U.A. (20 percent) and Petroandina Resources Corporation N.V. ("Petroandina") (29 percent); Petroandina is a wholly owned subsidiary of Pluspetrol Resources Corporation B.V.(“Pluspetrol”). Harvest Holding owns 100 percent of HNR Finance B.V. (“HNR Finance”), and HNR Finance owns a 40 percent interest in Petrodelta, S.A. (“Petrodelta”).  Petrodelta is the Venezuelan mixed company formed in 2007 for the purpose of owning and operating certain oil and gas interests in Venezuela.  The other 60 percent of Petrodelta is owned by CorporacionVenezolana del Petroleo A.S. (“CVP”) and PDVSA Social S.A., both companies owned and controlled by the Government of Venezuelan.  Thus we own an indirect 20.4 percent of Petrodelta (51 percent of 40 percent).

For several years we explored a broad range of strategic alternatives with respect to our Venezuelan interests.  In June 2012 we entered into an agreement with PT Pertamina (Persero), a state-owned limited liability company existing under the laws of the Republic of Indonesia (“Pertamina”), to sell all of our interests in Venezuela for a cash consideration of $725.0 million, subject to certain price adjustments. The sale to Pertamina was conditioned on, among other things, the approval of the Ministerio del Poder Popular de Petroleo y Mineria, representing the Government of Venezuela  and the approval of Pertamina’s shareholder, the Government of the Republic of Indonesia. After receiving notice from Pertamina in February 2013 that Pertamina’s shareholder had decided not to approve the transaction, we exercised our right to terminate the agreement in accordance with its terms.

After the termination of the Pertamina transaction, we continued to consider our strategic alternatives with respect to our Venezuelan assets. On December 16, 2013, we entered into a Share Purchase Agreement (the “SPA”) to sell all of our interests in Venezuela to Petroandina in two closings for an aggregate cash purchase price of $400.0 million.  At that time, we still had an 80 percent interest in Harvest Holding.  Under the SPA, we sold a 29 percent interest in Harvest Holding to Petroandina for $125.0 million on December 16, 2013, and agreed to sell the remaining 51 percent interest in Harvest Holding to Petroandina for $275.0 million at a future closing.  The closing was subject to, among other things, authorization by the holders of a majority of our outstanding common stock and approval of the Ministerio del Poder Popular de Petroleo y Mineria representing the Government of Venezuela.  Our shareholders approved the sale on May 7, 2014.  By January 1, 2015, we concluded that the parties would not be able to obtain the approval by the Government of Venezuela and so we terminated the SPA in accordance with its terms. When the SPA was terminated, a shareholders' agreement (the “Shareholders’ Agreement”) between the Company and Petroandina regarding their ownership shares in Harvest Holding became effective.

 

Through December 31, 2014, we included the results of Petrodelta in our consolidated financial statements using the equity method of accounting. We ceased recording earnings from Petrodelta in the second quarter due to the expected sales price of the second tranche purchase agreement approximating the recorded value of our investment in Petrodelta. 

 

Based upon numerous actions and inactions of the controlling partner, CVP, owned and controlled by the government of Venezuela, we have determined that we no longer have a significant degree of influence. As a result of these conditions, and in accordance with Accounting Standards Codification “ASC 823 – Investments - Equity Method”, we began reporting the results of our Venezuelan operations using the cost method of accounting. This change is effective December 31, 2014.

 

As a result of the termination of the purchase agreement and our review of the value of our investment in Petrodelta, we recorded in the fourth quarter 2014, a one-time pre-tax impairment charge of $355.7 million in Impairment – Investment Affiliate on our Consolidated Statements of Operations and Comprehensive Loss.  

 

In December 2014, we also impaired the carrying value of our property in Gabon by $50.3 million.  We recorded this impairment based on a qualitative analysis which considered our current liquidity needs, the recent decrease in oil and gas prices, the marketability of our property and the limited time we have to develop this project.

 

We expect that in 2015 we will not generate revenues and will continue to generate losses from operations and that our operating cash flows will not be sufficient to cover our operating expenses.  While we believe that we may be able to raise additional

---

 

capital through issuance of debt or equity or through sales of assets, our circumstances at such time raises substantial doubt about our ability to continue as a going concern.

As of December 31, 2014, we had total assets of $228.0 million, unrestricted cash of $6.6 million and notes payable to noncontrolling interest owners of $13.7 million. For the year ended December 31, 2014, we had no revenues from continuing operations and net cash used in operating activities of $39.2 million. As of December 31, 2013, we had total assets of $734.9 million, unrestricted cash of $120.9 million and debt and note payable to controlling interest owner of $83.6 million. For the year ended December 31, 2013, we had no revenues from continuing operations and net cash used in operating activities of $37.1 million.

At December 31, 2014, Petrodelta’s oil and gas reserves net to our 20.4 percent interest are: Proved reserves  16.7 million barrels of oil equivalent (“MMBOE”), Probable reserves  39.0 MMBOE, and Possible reserves  53.6 MMBOE. Proved plus Probable reserves at  55.7 MMBOE, a 10 percent reduction from last year. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies – Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve estimates. Barrels of oil equivalent is determined using the approximate heat content ratio of one barrel of crude oil or condensate to six thousand cubic feet (“Mcf”) of natural gas, which ratio does not necessarily reflect price equivalency.

Recent Events

On January 11, 2014, we used a portion of the $125.0 million in proceeds from the December 16, 2013 sale to Petroandina to redeem all of our 11% senior unsecured notes due in 2014 (“11% Senior Notes”). The notes were redeemed for $80.0 million, including principal and accrued and unpaid interest. As a result of the redemption, we recorded a loss on extinguishment of debt of approximately $3.6 million in January 2014. This loss primarily includes the expensing of the discount on debt ($2.3 million) and the expensing of the related financing costs ($1.3 million). The remaining $45.0 million of the proceeds from the first closing have been used for capital expenditures and for general operating expenses.

During the second quarter of 2014, we recorded an additional loss on extinguishment of debt of approximately $1.1 million related to a provision for early debt repayment; therefore, during the year ended December 31, 2014 we recorded a total loss on extinguishment of debt of $4.7 million.

On February 21, 2014, Tecnica Vial and Flamingo, our partners in Colombia on Blocks VSM14 and VSM15, respectively, filed for arbitration of claims related to the farm-out agreements for each block. We had received notices of default from our partners for failing to comply with certain terms of the farm-out agreements, followed by notices of termination on November 27, 2013. On December 14, 2014, we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed. 

 

On June 4, 2014, a Declaration of Commerciality (“DOC”) was signed with Gabon pertaining to the four discoveries on the Dussafu Project offshore Gabon.  Furthermore, on July 17, 2014, the Direction Generale Des Hydrocarbures (“DGH”) awarded an Exclusive Exploitation Authorization (“EEA”) for the development and exploitation of certain oil discoveries on the Dussafu Project and on October 10, 2014, the field development plan was approved. The Company is required to begin initial production within four years of the EEA approval.

 

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

 

On July 10, 2014, we filed a shelf registration statement on Form S-3 with the Securities and Exchange Commission.  Under the shelf registration statement, we could offer and sell up to $300.0 million of various types of securities, including unsecured debt securities, common stock, preferred stock, warrants and units.  Additionally, the shelf registration statement allows selling stockholders to resell up to an aggregate of 686,761 common shares upon the exercise of currently outstanding warrants. 

 

On September 4, 2014, we entered into a Distribution Agreement  with a sales agent (the “Agent”) to sell shares of the Company’s common stock (the “ATM Shares”), for up to $75.0 million aggregate gross sale proceeds, from  time to time in “at-the-market” offerings (the “ATM offering”). During the year ended December 31, 2014 we issued 653,832 shares under the ATM offering at a weighted average sale price of $3.10 per share resulting in proceeds to us of approximately $2.0 million, net of fees paid to the Agent and other costs associated with the Distribution Agreement. Under the terms of the ATM offering, sales were made primarily in transactions deemed to be “at-the-market” offerings, including sales made directly on the New York Stock Exchange (“NYSE”) at market prices or as otherwise agreed by the Company and the Agent.  On March 10, 2015 we received notice from the Agent terminating, effective immediately, the Distribution Agreement.

 

---

 

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

On January 26, 2015, Petroandina filed a complaint for breach of contract against the Company and its subsidiary HNR Energia in Delaware court.  The complaint states that HNR Energia breached provisions of the Shareholders Agreement between Petroandina and HNR Energia, which provisions require HNR Energia to provide advance notice of, and deposit $5 million into an escrow account, before bringing any claim against the Venezuelan government. Under those provisions, if Petroandina so requests, an appraisal of Petroandina's 29 percent interest in Harvest Holdings must be performed, and Petroandina has the right to require HNR Energia to purchase that 29 percent interest at the appraised value.  Petroandina's claim requests that, among other things, the court (a) declare that HNR Energia has breached the Shareholders' Agreement by submitting the Request for Arbitration against the Venezuelan government on January 15, 2015 (which Request for Arbitration was subsequently withdrawn without prejudice); (b) declare that the Company has breached its guaranty of HNR Energia's obligations under the Shareholders' Agreement; (c) direct the Company and HNR Energia to refrain from prosecuting any legal proceeding against the Venezuelan government (including the previously filed Request for Arbitration) until such time as they have complied with the relevant provisions of the Shareholders' Agreement; (d) award Petroandina costs and fees related to the lawsuit; and (e) award Petroandina such other relief as the court deems just and proper.  

 

On January 28, 2015, the Delaware court issued an injunction ordering the Company and HNR Energia to withdraw the Request for Arbitration and not take any action to pursue its claims against Venezuela until Harvest and HNR Energia have complied with the provisions of the Shareholders’ Agreement or otherwise reached an agreement with Petroandina.  Accordingly, on January 28, 2015, HNR Finance B.V. and Harvest Vinccler S.C.A., withdrew without prejudice the Request for Arbitration. In the Delaware proceeding, the Company and HNR Energia have until May 25, 2015 to respond to Petroandina’s complaint.

 

On February 13, 2015, the Company received notification from the NYSE that the Company had fallen below the NYSE's continued listing standards, which require a minimum average closing price of $1.00 per share over 30 consecutive trading days.    Under the NYSE's rules, Harvest has a period of six months from the date of the NYSE notice to bring its share price and 30 trading-day average share price back above $1.00.  During this period, Harvest's common stock will continue to be traded on the NYSE, subject to the Company's compliance with other NYSE continued listing requirements.  As required by the NYSE, in order to maintain its listing, Harvest has notified the NYSE that it intends to cure the price deficiency.

 

On January 1, 2015, we terminated the SPA to sell our remaining interest in Harvest Holding which owns our investment in Petrodelta.  We expect that in 2015 we will not generate revenues and will continue to generate losses from operations and that our operating cash flows will not be sufficient to cover our operating expenses.  While we believe that we may be able to raise additional capital through issuance of debt or equity or through sales of assets, our circumstances at such time raises substantial doubt about our ability to continue as a going concern.

 

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

---

 

Business Strategy

In Operations, Petrodelta below, Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, we discuss the situation in Venezuela and how the actions of the Venezuelan government have adversely affected and continue to adversely affect our operations. The expectation that dividends from Petrodelta will be minimal over the next few years have restricted our available cash and have had a significant adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere. See Note 16 – Operating Segments for further information on business segments.

Although we are currently marketing our non-Venezuelan assets and talking to potential buyers, we will continue to operate our business in the ordinary course and may ultimately decide to keep our non-Venezuelan assets and acquire additional assets. Since we no longer have any obligations under the 11% Senior Notes, and given that we do not currently have any operating cash flow, we may also decide to access additional capital through equity or debt sales.

Available Information

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

We also make available, free of charge on or through our Internet website (http://www.harvestnr.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Exchange Act are also available on our website. In addition, we have adopted a Code of Business Conduct and Ethics that applies to all of our employees, including our chief executive officer, 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 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”) related to our share of oil and gas reserves associated with our investment in Petrodelta.. 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 Science in Petroleum Engineering and more than 35 years of experience in petroleum engineering.

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 2014, Petrodelta drilled and completed 13 production wells and eight of the wells were previously identified as Proved Undeveloped (“PUD”) locations and five wells were previously classified as probable, possible or undefined locations. In 2014, an additional 26 PUD locations were identified through drilling activity, however 101 PUD locations which are scheduled to be drilled five years after the wells were originally identified have been reclassified as Probable reserves. At December 31, 2014, Petrodelta has 66 identified PUD locations.

Petrodelta’s 2014 business plan, as proposed by Petrodelta, contemplates sustained drilling activities through the year 2023 to fully develop the El Salto, Isleño and Temblador fields. The PUD locations which are now scheduled to be drilled five years after they were originally identified have been reclassified as Probable reserves.

---

 

As of December 31, 2014, proved undeveloped reserves of 7.5 MMBOE from 66 gross PUD locations are scheduled to be drilled within the period from 2015 to 2019 and within five years from when these locations were first identified. All above MMBOE represent our net 20.4 percent effective interest, net of a 33.33 percent royalty.

Probable undeveloped reserves of 39.0  MMBOE include17.6 MMBOE from 208 gross undeveloped locations that would otherwise meet the definition of proved undeveloped reserves, except that they are scheduled to be drilled at least five years after the date that they were originally identified. All of these 208 locations are scheduled to be drilled within five years from 2015 to 2019.

The following table shows a summary of our proved, probable and possible oil and gas reserves, all of which are located in Venezuela, as of December 31, 2014.

 

 

 

Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves as of December 31, 2014,  2013 and 2012 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) in our consolidated financial statements. 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, 2014, our operations include:

---

 

Petrodelta

General

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

Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Under the Conversion Contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. Petrodelta’s approved capital budget for 2014 was $518.8 million and included a drilling program to use six drilling rigs for both development and appraisal wells to maintain production capacity. Petrodelta’s actual capital expenditures for 2014  were $430.6 million or 83.0 percent of the capital budget.

Petroleos de Venezuela S.A. (“PDVSA”), as administrator of certain operating contracts for several mixed companies in Venezuela, has failed to pay on a timely basis certain amounts owed to contractors doing work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors, including Harvest Holding. As a result, Petrodelta has experienced, and is continuing to experience, difficulty in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis has an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.

Crude oil delivered from Uracoa, Bombal, Tucupita, Isleño and Temblador fields of Petrodelta to PDVSA Petroleo S.A. (“PPSA”), a wholly owned subsidiary of PDVSA, is priced with reference to Merey 16 published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices are quoted and sold in U.S. Dollars. The crude oil produced and delivered from El Salto field is priced with reference to Boscan, a heavier 10 degree API crude oil, published prices, also weighted for different markets and quality adjusted as described above. Boscan published prices are also quoted and sold in U.S. Dollars. An amendment to Petrodelta’s Contract for Sale and Purchase of Hydrocarbons with PPSA (the “Sales Contract”) has been approved by Petrodelta’s shareholders and was executed during the first quarter 2015. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Petrodelta for additional information on the sales contract. Natural gas delivered from the Petrodelta fields to PPSA is priced at $1.54 per Mcf. PPSA is obligated to make payment to Petrodelta in U.S. Dollars for crude oil and natural gas liquids delivered. Natural gas deliveries are paid in Venezuelan Bolivars (“Bolivars”), but the pricing for natural gas is referenced to the U.S. Dollar.

As a result of legislation enacted in December 2013 and January and February of 2014, Venezuela now has a multiple exchange rate system. Most of Petrodelta’s transactions are subject to a fixed official exchange rate of 6.3. The Venezuelan government modified the currency exchange system whereby the official exchange rate of 6.3 Bolivars per USD would only apply to certain economic sectors related to purchases of “essential goods and services” while other sectors of the economy would be subject to a new exchange rate, SICAD I, determined by an auction process conducted by Venezuela's Complimentary System of Foreign Currency Administration. Participation in the SICAD I mechanism is controlled by the Venezuelan government and is limited to certain companies that operate in designated economic sectors.  In March 2014, an additional currency exchange mechanism was established by the Venezuelan government that allows companies within other economic sectors to participate in an additional auction process (“SICAD II”).  The financial information for Petrodelta is prepared using the official fixed exchange rate (6.3 from February 2013 through December 2014). At December 31, 2014, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 1,590.4 million Bolivars ($0.3 million) and 3,506.3 million Bolivars ($0.6 million), respectively.

---

 

On February 10, 2015, the Ministry of Economy, Finance, and Public Banking, and the Central Bank of Venezuela (BCV) published in the Extraordinary Official Gazette No.6.171 Exchange Agreement No.33 with two Official Notices.  The first notice being that the SICAD II exchange rate would be no longer permitted.  Secondly, a new exchange rate called the Foreign Exchange Marginal System (“SIMADI”) has been created.  The SIMADI rate published on March 12, 2015 is 183.15 Bolivars per U.S. Dollars. The SIMADI’s marginal system is available in limited quantities for individuals and companies to purchase and sell foreign currency via banks and exchange houses.

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

On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance. Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, as of the date of this report, the dividend has not been received, although it is due and payable. Petrodelta’s board of directors declared this dividend and has never indicated that the dividend is not payable, or that it will not be paid. The dividend receivable is classified as a long-term receivable at December 31, 2014 due to the uncertainty in the timing of payment.  During the year ended December 31, 2014 we recorded an allowance of $12.2 million to fully reserve the dividend receivable due from Petrodelta.

Petroandina has the right to any dividends paid by Harvest Holding after December 16, 2013 that would attach with respect to its current 29 percent interest regardless of whether the dividends are paid in connection with dividends paid by Petrodelta that are declared before, on or after the date of the Share Purchase Agreement (“SPA”) dated December 16, 2013 between Harvest, HNR Energia, Petroandina and Pluspetrol and regardless of the record date therefor.  Petrodelta did not declare or pay any dividends during this period.

Petrodelta 2015 Capital Budget

The CVP proposed 2015 budget for Petrodelta is for $265.2 million in capital expenditures. Since Petrodelta has had insufficient monetary support and contractual adherence by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2015 budget. Should PDVSA continue in its insufficient monetary support and contractual adherence of Petrodelta, underinvestment in the development plan may lead to continued under-performance. This budget proposal has not yet been reviewed or approved by Petrodelta’s board.

Location and Geology

Uracoa Field

At December 31, 2014, there were 66 (compared to 76 at December 31, 2013) oil and natural gas producing wells and seven (compared to seven at December 31, 2013) water injection wells in the field. The current production facility has capacity to handle 30 thousand barrels (“MBbls”) of oil per day, 130 MBbls of water per day, and storage of up to 75 MBbls of crude oil. The oil produced from Uracoa is blended with the oil produced from Tucupita, Bombal and Isleño fields then transported through a 25-mile oil pipeline from the Uracoa plant facilities UM-2 to PDVSA’s EPT-1 storage and fiscalization facility. Substantially all natural gas currently being delivered by Petrodelta is produced from the Uracoa field and is delivered to PDVSA through a 64-mile pipeline to Mamo gas station and PDVSA Gas network.

Tucupita Field

At December 31, 2014, there were 17 (compared to 19 at December 31, 2013) oil producing wells and five (compared to five at December 31, 2013) water injection wells in the field. The Tucupita production facility has a capacity to process 30 MBbls of oil per day, 125 MBbls of water per day and storage for up to 60 MBbls of crude oil. The oil is transported through a 31-mile, 20-MBbls-of-oil-per-day pipeline from the Tucupita field to the Uracoa plant facilities UM-2. See “Uracoa Field” above.

Bombal Field

At December 31, 2014, there were four (compared to three at December 31, 2013) 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, 2014, there were eight (compared to three at December 31, 2013) oil producing wells in the field. The oil

---

 

is transported through a pipeline to the Uracoa plant facilities UM-2. See “Uracoa Field” above. A 16-inch, 6.2-mile, 20-MBbls-per-day transfer line capacity was completed and is operational from the Isleño field to Uracoa to transport the oil produced.

Temblador Field

At December 31, 2014, there were 31 (compared to 28 at December 31, 2013) oil producing wells in the field, and eight (compared to eight at December 31, 2013) water injection wells in the field. The oil is transported through two pipelines: a 5.6-mile, 40-MBbls-of-oil-per-day trunkline from the TY-8 flow station (east end of the field) to the TY-23 flow station; and a 4.3-mile, 20 MBbls-of-oil-per-day gathering system from the west end of the field to the TY-23 flow station. The total crude oil is then delivered from the TY-23 flow station into PDVSA’s EPT-1 storage facility.

El Salto Field

At December 31, 2014, there were 23 (compared to 23 at December 31, 2013) oil producing wells and one (compared to one at December 31, 2013) water injection well in the El Salto field. The oil is transported through an 18.1-mile, 40-MBbls-of-oil-per-day pipeline to PDVSA’s EPM-1 storage facility.

Infrastructure and Facilities

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

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

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

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

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

Drilling and Development Activity

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

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

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

Risk Factors

We face significant risks in holding a minority investment in Petrodelta. These risks and other risk factors are discussed in Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. As of December 31, 2014, the Company changed its accounting for its investment in Petrodelta from the equity interest method to the cost method.

Dussafu Marin, Offshore Gabon

General

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

---

 

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

Location and Geology

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

Drilling and Development Activity

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

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

 

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

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

 

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

 

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

 

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

 

In December 2014, we also impaired the carrying value of our property in Gabon by $50.3 million.  We recorded this impairment based on a qualitative analysis which considered our current liquidity needs, the recent decrease in oil and gas prices, the marketability of our property and the limited time we have to develop this project.

Budong-Budong, Onshore Indonesia

General

 

In December 2007, Harvest entered into a farm-out agreement with a partner to acquire a 47 percent equity interest in the Budong-Budong Production Sharing Contract (“Budong PSC”). During 2010 and 2011 certain options within the Budong PSC were exercised by Harvest that increased its participating equity interest to 64.4 percent.

 

During 2011 two exploratory wells were spud and drilled.  Both wells were plugged and abandoned, due to either safety concerns or lack of commercially viable oil and gas reserves.

---

 

 

On December 5, 2012, we entered into a third farm-out agreement with our partner to acquire an additional 7.1 percent equity interest and to become operator of the Budong PSC.  Closing of this agreement increased our participating equity interest to 71.5 percent. The consideration for the additional 7.1 percent equity interest was for Harvest to fund 100 percent of the costs of the first exploration well under a four-year extension to the Budong PSC that was granted in January 2013.  In the instance that this well was not drilled within 18 months of the date of the Government of Indonesia’s approval to this transaction (by October 9, 2014), our partner would have the right to give notice that the consideration be paid in cash.  The value of this obligation was calculated to be $3.2 million.

 

During 2013 management began marketing our interests in the Budong PSC.  In December 2013 we signed an agreement with an outside third party to enter into exclusive negotiations for the possible sale of our interest in the Budong PSC.  The indicated purchase price was $4.6 million. Based on the indicated fair value from these negotiations, we recognized an impairment expense of $0.6 million against property assets of $5.2 million and a $2.8 million charge in general and administrative expenses related to a valuation allowance on value-added tax (“VAT”) that we do not expect to recover.  By recognizing these charges in December 2013, our Budong investment was consistent with the $4.6 million implied value.

 

During the first quarter of 2014, the third party terminated the negotiations.  Additional inquiries into our interest in the Budong PSC did not lead to any other prospective buyer; therefore we fully impaired our remaining property value of $4.4 million as of March 31, 2014. 

 

In parallel with the activities to find a prospective buyer, we approached our partner with a proposal for them to acquire Harvest’s participating interest and operatorship in the joint venture and Budong PSC. This was reviewed by their senior management and declined.  In June 2014, Harvest and our partner adopted a resolution to terminate the Budong PSC; therefore no further drilling will occur.  Harvest advised the Indonesian government of this decision on June 4, 2014, and is now in the process of finalizing the relinquishment of the interest.  As a result of these decisions, Harvest accrued a $3.2 million liability as of June 30, 2014 related to the December 5, 2012 farm-out agreement discussed above, thereby creating a total impairment expense of $7.7 million in the year ended December 31, 2014.  Harvest paid this $3.2 million liability in October 2014. 

 

Harvest has elected an early adoption of FASB Accounting Standards Update No. 2014-08, which amended ASC 360 with regards to the definition of discontinued operations, and has determined that the above actions surrounding the Budong PSC do not qualify as discontinued operations and therefore has accounted for all 2014, 2013 and 2012 financial activity within current operations. 

WAB-21, South China Sea

General

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

On July 2, 2014, we completed the sale of our rights under the petroleum contract with CNOOC for the WAB-21 area for net proceeds of $2.9 million and recorded that amount as a gain of sale of oil and gas properties. 

Colombia-Discontinued Operations

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

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

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

---

 

To date, there have been two exploration wells drilled on block VSM14, both of which were plugged and abandoned. There have been no wells drilled on block VSM15.

We received notices of default from our partners for failing to comply with certain terms of the farm-out agreements for Block VSM14 and Block VSM15, followed by notices of termination on November 27, 2013. As discussed further in Item 3. Legal Proceedings, our partners have filed for arbitration of claims related to these agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests, and we recorded an impairment charge of $3.2 million during the year ended December 31, 2013, which included an accrual of $2.0 million related to this matter.  On December 14, 2014 we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed. We are in the process of closing and exiting our Colombia venture. As we no longer have any interests in Colombia, we reflected the results in discontinued operations. 

Block 64 EPSA, Oman-Discontinued Operations

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

The first phase of Block 64 EPSA had a minimum work obligation of $22.0 million to reprocess 375 square kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup. In 2011, two exploratory wells were drilled, Mafraq South-1 (“MFS-1”) and Al Ghubar North-1 (“AGN-1”). Both wells were plugged and abandoned in the fourth quarter of 2011 and first quarter of 2012. Operational activities during 2012 included post-well evaluation and review of geological and geophysical data obtained from the drilling of the MFS-1 and AGN-1 wells.

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

---

 

Production, Prices and Lifting Cost Summary

In the following table we have set forth, for Venezuela, our net production, average sales prices and average operating expenses for the years ended December 31, 2014,  2013 and 2012. The presentation for Venezuela shows our net ownership interest in Petrodelta which was 32 percent through December 15, 2013 and 20.4 percent thereafter.

Drilling and Undeveloped Acreage

For acquisitions of leases, development and exploratory drilling, we spent approximately (excluding our share of capital expenditures incurred by investment affiliate) $4.4 million in 2014 ($43.9 million in 2013,  $23.6 million in 2012). These numbers do not include any costs for the development of proved undeveloped reserves in 2014,  2013 or 2012.

We have participated in the drilling of wells as follows:

 

 

 

 

 

---

 

In Gabon, following the success in both the pre-salt Gamba and Dentale reservoirs in the two Harvest exploration wells, a new seismic survey commenced in October 2013 and we received the first high quality seismic products during the second quarter of 2014 and interpretation was completed in early 2015. The new 3D seismic data was extended over the two Harvest discoveries and should also enhance the placement of future development wells in the Ruche and Tortue development program. We continue to evaluate our prospects, but we have not drilled any additional wells.

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

Acreage

The following table summarizes the developed and undeveloped acreage that we own, lease or hold under concession as of December 31, 2014:

 

 

 

Regulation

General

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

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

Environmental Regulations

Our operations are subject to various federal, state, local and international laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The cost of compliance could be significant. Failure

---

 

to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial and damage payment obligations, or the issuance of injunctive relief (including orders to cease operations). Environmental laws and regulations are complex and have tended to become more stringent over time. We also are subject to various environmental permit requirements. Some environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties. To the extent laws are enacted or other governmental action is taken that prohibits or restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected.

Competition

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

Employees

At December 31, 2014, full-time employees in our various offices were: Houston - 16; Caracas - 10; and Singapore - 4.  We augment our employees from time to time with independent consultants, as required.

Item 1A.  Risk Factors

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

Risks Related to Our Business

 

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

 

Our cash position and limited ability to access additional capital may limit our growth opportunities. We have no recurring cash flows, and our available cash may not be sufficient to meet capital and operational commitments for the next twelve months. Our future cash position is impacted by farm-out, or possible sale or otherwise monetization of assets as necessary to maintain the liquidity required to run our operations and capital spending requirements. 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.

 

During 2014 we have impaired the carrying value of our investment in Petrodelta and our offshore project in Gabon and may need to record additional impairments in the future.  The Company was not able to complete the sale of the second tranche of its investment in Petrodelta and terminated the SPA.  Due to our liquidity needs we have not been able to commit to the development of our property in Gabon.    If oil prices do not improve, if the economic environment in Venezuela does not improve, and we cannot obtain the capital to develop Gabon within the development period we may be required to record additional impairments relating to these assets.

 

Our cash position and limited ability to access additional capital may limit our growth and development opportunities.  We have no recurring cash flows, and our available cash may not be sufficient to meet capital and operational commitments for the next twelve months.  Our future cash flow position will be impacted by farm-out, or possible sale or otherwise monetization of our asset in Gabon as necessary to maintain the liquidity required to run our operations and capital spending requirements.   These factors could have a material adverse effect on our financial condition and liquidity and may limit our ability to grow through acquisition or exploration of additional oil and gas properties and projects.

 

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

 

---

 

Our common stock may not remain listed for trading on the NYSE.  The NYSE has established certain quantitative and qualitative standards that companies must meet in order to remain listed for trading on these markets.  We may not be able to maintain necessary requirements for listing; therefore, our common stock may not remain listed for trading on the NYSE or any similar market.  On February 13, 2015, the Company received notification from the NYSE that the Company had fallen below the NYSE's continued listing standards, which require a minimum average closing price of $1.00 per share over 30 consecutive trading days.    Under the NYSE's rules, Harvest has a period of six months from the date of the NYSE notice to bring its share price and 30 trading-day average share price back above $1.00.  During this period, Harvest's common stock will continue to be traded on the NYSE, subject to the Company's compliance with other NYSE continued listing requirements.  As required by the NYSE, in order to maintain its listing, Harvest has notified the NYSE that it intends to cure the price deficiency.     If we are unable to cure the deficiency, the NYSE could delist our common stock and we may seek to be listed on an alternative exchange.

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

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

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

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

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

We hold a minority investment in Petrodelta. We are no longer able to exercise significant influence as a minority investor in Petrodelta and our control of Petrodelta is limited to our rights under the Conversion Contract and its annexes and Petrodelta’s charter and bylaws. As a result, our ability to implement or influence Petrodelta’s business plan, assure quality control, and set the timing and pace of development may be adversely affected. In addition, the majority partner, CVP, has initiated and undertaken numerous unilateral decisions that can impact our minority investment.

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

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

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:

---

 

An increase in oil prices could result in increased tax liability in Venezuela affecting Petrodelta’s operations and profitability, which in turn could affect our dividends and profitability. Prices for oil fluctuate widely. In April 2011, the Venezuelan government published the Windfall Profits Tax which establishes a special contribution for extraordinary prices to the Venezuelan government of 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $60 per barrel for 2014) and $80 per barrel. The Windfall Profits Tax also establishes a special contribution for exorbitant prices to the Venezuelan government of (1) 80 percent when the average price of the Venezuelan Export Basket (“VEB”) exceeds $80 per barrel but is less than $100 per barrel; (2) 90 percent when the average price of the VEB exceeds $100 per barrel but is less than $110 per barrel; and (3) 95 percent when the average price of the VEB exceeds $110 per barrel. Any increase in the taxes payable by Petrodelta, including the Windfall Profits Tax, as a result of increased oil prices will reduce cash available for dividends to us and our partner, CVP.

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 investment. If we are called upon to fund our share of Petrodelta’s operations, our failure to do so could be considered a default under the Conversion Contract and cause the forfeiture of some or all our shares in Petrodelta. In addition, CVP may be unable or unwilling to fund its share of capital requirements and our ability to require them to do so is limited. Should PDVSA continue in insufficient monetary support and contractual adherence of Petrodelta, underinvestment in the development plan may lead to continued under-performance.

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

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

Risks Related to Our Industry

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

The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are

---

 

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

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

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

Our future operations and our investment in Petrodelta 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:

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.

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

---

 

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

We operate in international jurisdictions and we could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar worldwide anti-corruption laws. The U.S. Foreign Corrupt Practices Act (“FCPA”) and similar worldwide anti-corruption laws, 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. Any additional expansion outside the U.S., including in developing countries, could increase the risk of such violations in the future. Violations of these laws, or allegations of such violations, could disrupt our business and result in a material adverse effect on our financial condition, results of operations and cash flows.

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

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

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

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

---

 

subject us to administrative, civil and criminal penalties as well as the imposition of corrective action orders. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition, results of operations or cash flows.

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

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

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

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

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

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

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

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

---

 

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

Item 1B.  Unresolved Staff Comments

None.

Item 2.  Properties

We have a regional office in Singapore and a field office in Port Gentil, Gabon to support field operations in those areas. The Singapore office lease expires March 31, 2015 and we expect the office will close at that time.  At December 31, 2014, we had the following lease commitments for office space:

 

 

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

Item  3.  Legal Proceedings

 

 

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

On January 26, 2015, Petroandina filed a complaint for breach of contract against the Company and its subsidiary HNR Energia in Delaware court.  The complaint states that HNR Energia breached provisions of the Shareholders Agreement between Petroandina and HNR Energia, which provisions require HNR Energia to provide advance notice of, and deposit $5 million into an escrow account, before bringing any claim against the Venezuelan government. Under those provisions, if Petroandina so requests, an appraisal of Petroandina's 29 percent interest in Harvest Holdings must be performed, and Petroandina has the right to require HNR Energia to purchase that 29 percent interest at the appraised value.  Petroandina's claim requests that, among other things, the court (a) declare that HNR Energia has breached the Shareholders' Agreement by submitting the Request for Arbitration against the Venezuelan government on January 15, 2015 (which Request for Arbitration was subsequently withdrawn without prejudice); (b) declare that the Company has breached its guaranty of HNR Energia's obligations under the Shareholders' Agreement; (c) direct the Company and

---

 

HNR Energia to refrain from prosecuting any legal proceeding against the Venezuelan government (including the previously filed Request for Arbitration) until such time as they have complied with the relevant provisions of the Shareholders' Agreement; (d) award Petroandina costs and fees related to the lawsuit; and (e) award Petroandina such other relief as the court deems just and proper.  

 

On January 28, 2015, the Delaware court issued an injunction ordering the Company and HNR Energia to withdraw the Request for Arbitration and not take any action to pursue its claims against Venezuela until Harvest and HNR Energia have complied with the provisions of the Shareholders’ Agreement or otherwise reached an agreement with Petroandina.  Accordingly, on January 28, 2015, HNR Finance B.V. and Harvest Vinccler S.C.A., withdrew without prejudice the Request for Arbitration. In the Delaware proceeding, the Company and HNR Energia have until May 25, 2015 to respond to Petroandina’s complaint.

 

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

Kensho Sone, et al. v. Harvest Natural Resources, Inc., in the United States Court of Appeals for the Fifth Circuit. On July 24, 2013, 70 individuals, all alleged to be citizens of Taiwan, filed an original complaint and application for injunctive relief in federal district court in Houston, Texas, relating to the Company’s interest in the WAB-21 area of the South China Sea.  The complaint was later amended, with some plaintiffs dropping out of the suit, and additional individuals, also alleged to be citizens of Taiwan, joining as plaintiffs.  In total, there were 141 plaintiffs.  These plaintiffs alleged in the operative complaint that the WAB-21 area belongs to the people of Taiwan and sought damages in excess of $2.0 million and preliminary and permanent injunctions to prevent the Company from exploring, developing plans to extract hydrocarbons from, conducting future operations in, and extracting hydrocarbons from, the WAB-21 area.  The Company filed a motion to dismiss the suit, which was granted by the district court in August 2014.  The plaintiffs appealed the dismissal.  The appeal has been fully briefed and is awaiting decision by the appellate court.  The Company intends to continue to vigorously defend these allegations.

The following related class action lawsuits were filed on the dates specified in the United States District Court, Southern District of Texas: John Phillips v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (March 22, 2013) (“Phillips case”); Sang Kim v. Harvest Natural Resources, Inc., James A. Edmiston, Stephen C. Haynes, Stephen D. Chesebro’, Igor Effimoff, H. H. Hardee, Robert E. Irelan, Patrick M. Murray and J. Michael Stinson (April 3, 2013); Chris Kean v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 11, 2013); Prastitis v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 17, 2013); Alan Myers v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 22, 2013); and Edward W. Walbridge and the Edward W. Walbridge Trust v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 26, 2013). The complaints allege that the Company made certain false or misleading public statements and demand that the defendants pay unspecified damages to the class action plaintiffs based on stock price declines. All of these actions have been consolidated into the Phillips case. The Company and the other named defendants have filed a motion to dismiss and intend to vigorously defend the consolidated lawsuits.

In June 2012, the operator of the Budong PSC received notice of a claim related to the ownership of part of the land comprising the Karama-1 drilling site. The claim asserted 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 has been seeking compensation of 16 billion Indonesia Rupiah (approximately $1.4 million, $1.0 million net to our 71.61 percent cost sharing interest) for land that was purchased at a cost of $4,100 in January 2010. On March 8, 2013, the District Court of Jakarta ruled to dismiss the claim because the claim had not been filed against the proper parties to the claim. On March 19, 2013, the claimant filed an appeal against the judgment. On September 16, 2014, the High Court of Jakarta upheld the judgment of the District Court of Jakarta. The claimant did not file an appeal and the case has been terminated.

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

---

 

On May 31, 2011, the United Kingdom branch of our subsidiary, Harvest Natural Resources, Inc. (UK), initiated a wire transfer of approximately $1.1 million ($0.7 million net to our 66.667 percent interest) intending to pay Libya Oil Gabon S.A. (“LOGSA”) for fuel that LOGSA supplied to our subsidiary in the Netherlands, Harvest Dussafu, B.V., for the company’s drilling operations in Gabon. On June 1, 2011, our bank notified us that it had been required to block the payment in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by OFAC, because the payee, LOGSA, may be a blocked party under the sanctions. The bank further advised us that it could not release the funds to the payee or return the funds to us unless we obtain authorization from OFAC. On October 26, 2011, we filed an application with OFAC for return of the blocked funds to us. Until that application is approved, the funds will remain in the blocked account, and we can give no assurance when OFAC will permit the funds to be released. Our October 26, 2011 application for the return of the blocked funds remains pending with OFAC.  On April 23, 2014, we received a notice that OFAC had denied our October 26, 2011 application for the return of the blocked funds. We intend to request that OFAC reconsider its decision, and we continue to believe that the funds will ultimately be released to the Company.

Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc., Branta Exploration & Production, LLC, Ute Energy LLC, Cameron Cuch, Paula Black, Johnna Blackhair, and Elton Blackhair in the United States District Court for the District of Utah. This suit was served in April 2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the defendants, among other things, intentionally interfered with plaintiffs’ employment agreement with the Ute Indian Tribe – Energy & Minerals Department and intentionally interfered with plaintiffs’ prospective economic relationships. Plaintiffs seek actual damages, punitive damages, costs and attorney’s fees. The court administratively closed the case in 2013. The case was reopened in 2014 as a result of the Circuit Court of Appeals’ ruling. We dispute Plaintiffs’ claims and plan to vigorously defend against them.

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

Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions based on the interpretation of the tax code by SENIAT (the Venezuelan income tax authority), as it applies to operating service agreements, Harvest Holding has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.

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

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

---

 

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

We received notices of default from our partners in Colombia for failing to comply with certain terms of the farm-out agreements for Block VSM14 and Block VSM15, followed by notices of termination on November 27, 2013. Our Colombian partners filed for arbitration of claims related to these agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests, and we recorded an impairment charge of $3.2 million during the year ended December 31, 2013 which included an accrual of $2.0 million related to this matter.  On December 14, 2014 we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed. As we no longer have any interests in Colombia, we reflected the results in discontinued operations.

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

Item  4.  Mine Safety Disclosures

Not applicable.

---

 

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, 2014, there were  42,747,567 shares of common stock outstanding, with approximately 403 stockholders of record. The following table sets forth the high and low sales prices for our common stock reported by the NYSE.

 

 

On March 20, 2015, the last sales price for the common stock as reported by the NYSE was $0.44 per share.

Historically, our policy has been to retain earnings to support the growth of our business, and accordingly, our Board of Directors has never declared a cash dividend on our common stock. See Item 1 Business, Business Strategy for further discussion.

On February 13, 2015, the Company received notification from the NYSE that the Company had fallen below the NYSE's continued listing standards, which require a minimum average closing price of $1.00 per share over 30 consecutive trading days.    Under the NYSE's rules, Harvest has a period of six months from the date of the NYSE notice to bring its share price and 30 trading-day average share price back above $1.00.  During this period, Harvest's common stock will continue to be traded on the NYSE, subject to the Company's compliance with other NYSE continued listing requirements.  As required by the NYSE, in order to maintain its listing, Harvest has notified the NYSE that it intends to cure the price deficiency.  However, there can be no assurance that the Company will be able to do so.

Stock Performance Graph

The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2014, assuming an investment of $100 on December 31, 2009 in each of Harvest’s common stock, the Dow Jones U.S. Select Oil Exploration & Production Index and the S&P Composite 500 Stock Index. 

This graph assumes that the value of the investment in Harvest stock and each index was $100 at December 31, 2009 and all dividends were reinvested.

---

 

 

 

PLOT POINTS

(December 31 of each year)

 

Total Return Data provided by S&P’s Institutional Market Services, Dow Jones & Company, Inc. is composed of companies that are classified as domestic oil companies under Standard Industrial Classification codes (1300-1399, 2900-2949, 5170-5179 and 5980-5989). The Dow Jones US Select Oil Exploration & Production Index data is accessible for download at http://us.ishares.com/tools/index_tracker.htm under the Sector/Industry selection.

 

---

 

Item 6.  Selected Financial Data

SELECTED CONSOLIDATED FINANCIAL DATA

The following tables set forth our selected consolidated financial data for each of the years in the five-year period ended December 31, 2014.

 

 

 

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

---

 

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

Operations

We had a net loss attributable to Harvest of $193.5 million, or $4.60 per diluted share, for the year ended December 31, 2014 compared to a net loss attributable to Harvest of $89.1 million, or $2.25 per diluted share, for the year ended December 31, 2013. Net loss attributable to Harvest for the year ended December 31, 2014 includes $6.3 million of exploration expense, $58.0 million of impairment expense – unproved property costs, impairment expense – investment affiliate $355.7 million,  $1.6 million of loss on sale of interest in affiliate, $2.9 million of gain on sale of oil and gas properties,  $2.0 million of gain on warrant derivatives, $4.7 million loss on extinguishment of debt, $58.3 million of income tax benefit, net equity income from Petrodelta’s operations of $34.9 million and a loss from discontinued operations of $0.6 million. Net loss attributable to Harvest for the year ended December 31, 2013 includes $15.2 million of exploration expense, $0.6 million of impairment expense, $23.0 million of loss on sale of interest in affiliate, $3.5 million of gain on warrant derivative, $4.5 million of interest expense, $1.8 million in other non-operating expenses, $73.1 million of income tax expense (including $89.9 million of accrued income tax expense related to previously unrecognized income tax on undistributed earnings for foreign subsidiaries), equity income from Petrodelta’s operations of $72.6 million and a loss from discontinued operations of $5.2 million.

Petrodelta

See Item 1. Business, Operations, Petrodelta.

The Company had a 32 percent effective interest in Petrodelta and accounted for its interest under the equity method until December 16, 2013 when we sold a portion of its interest to Petroandina which reduced our effective interest to 20.4 percent.  Through December 31, 2014, we included the results of Petrodelta in our financial statements under the equity method.  We ceased recording earnings from Petrodelta in the second quarter due to the expected sales price of the second tranche purchase agreement approximating the recorded value of our investment in Petrodelta.  Based on numerous actions of the controlling partner, CVP, owned and controlled by the government of Venezuela, we have determined that we no longer have a significant degree of influence.  As a result of these conditions, we began reporting the results of our operations in Venezuela using the cost method of accounting effective December 31, 2014.  As a result of the termination of the purchase agreement and our review of the value of our investment in Petrodelta, we recorded a one-time impairment charge of $355.7 million in the fourth quarter of 2014.

Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Petrodelta’s 2014 approved capital budget was $518.8 million and included a drilling program to use six drilling rigs for both development and appraisal wells to maintain production capacity. Actual capital expenditures were $430.6 million in 2014 or 83.0 percent of the approved budget.

Petrodelta began 2014 with six drilling rigs and one workover rig and projects in progress to enhance the infrastructure in the El Salto and Temblador fields.  Currently, Petrodelta is operating six drilling rigs and one workover rig and is continuing the construction on the infrastructure enhancements in the El Salto and Temblador fields. Construction of a pipeline between the Isleño field and the main production facility at Uracoa was completed in March 2013.

During the year ended December 31, 2014, Petrodelta drilled and completed 13 development wells compared to 13 development wells in the year ended December 31, 2013. Petrodelta delivered approximately 15.6 MBls of oil and 3.0 Bcf of natural gas, averaging 43,994 BOE per day during the year ended December 31, 2014 compared to deliveries of 14.5 MBls of oil and 2.6 Bcf of natural gas, averaging 41,014 BOE per day during the year ended December 31, 2013.

Petrodelta’s proved reserves, net to our 20.4 percent interest, are 16.7 MMBOE at December 31, 2014. Petrodelta’s probable reserves, net to our 20.4 percent interest, are 39.0 MMBOE at December 31, 2014. Petrodelta’s possible reserves, net to our 20.4 percent interest, are 53.6 MMBOE. Proved plus probable reserves at 55.7 MMBOE, a 10 percent reduction 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.

---

 

Certain operating statistics for the years ended December 31, 2014,  2013 and 2012 for the fields operated by Petrodelta are set forth below. This information is provided at 100 percent.

 

 

Sales Contract

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

Beginning in October 2011, Ministry of the People’s Power for Petroleum and Mining (“MENPET”)  determined that Petrodelta’s production flowing through the COMOR transfer point which comes from the El Salto field was a heavier type of crude, Boscan. The official pricing formula applied to Boscan by MENPET is used for the sales of Petrodelta crude oil with quality close to 10 degrees API to represent actual quality delivered. PPSA and Petrodelta are in the process of amending the contract to provide pricing under the Boscan pricing formulas. As of December 31, 2014,  $1,207.2 million ($756.7 million as of December 31, 2013) for El Salto remained uninvoiced to PPSA pending execution of the amendment.  The amendment was signed in November 2014 and during the first quarter of 2015, Petrodelta completed billing PPSA for invoices for deliveries through November 2014.

Payments to Contractors

In Item 1A. Risk Factors, we discussed that PDVSA’s failure to timely pay contractors, including Petrodelta, was having an adverse effect on Petrodelta. We have advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, operations and seismic interpretation, and employee salaries and related benefits for Harvest employees seconded into Petrodelta. Currently, we have three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. We are considered a contractor to Petrodelta, and as such, we are also experiencing the slow payment of invoices. As of December 31, 2014, we had $1.6 million outstanding for unpaid advances to Petrodelta for continuing operations costs. Although payment is slow, payments continue to be received. Petrodelta and Petrodelta’s board have not indicated that the advances are not payable, nor that they will not be paid. During 2014 we received $0.2 million in payments.  At December 31, 2014, Harvest elected to fully reserve the receivable of $1.6 million as a part of the valuation of our investment in Petrodelta.

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.

In the past, there has been insufficient monetary support and contractual adherence by PDVSA, and it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2015 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 2015 budget proposal has not been reviewed by Petrodelta’s board yet.

---

 

Windfall Profits Tax

In April 2011, the Venezuelan government published in the Official Gazette the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (“Windfall Profits Tax”). In February 2013, the Venezuelan government published in the Official Gazette an amendment to the Windfall Profits Tax which established new levels for contribution to the Venezuelan government. Extraordinary prices are considered to be equal to or lower than $80 per barrel, and exorbitant prices are considered to be over $80 per barrel. See Item 15. Exhibits and Financial Statement Schedules, Notes to the Consolidated Financial Statements,  Note 6 – Investment in Affiliate for further discussion of the Windfall Profits Tax rates. Windfall Profits Tax is deductible for Venezuelan income tax purposes.

The April 2011 Windfall Profits Tax included a provision wherein it considered that an exemption of the Windfall Profits Tax could be granted for the incremental production of projects and grass root developments until the specific investments are recovered. The projects deemed to qualify for the exemption have to be considered and approved on a case by case basis by MENPET. In March 2013, PDVSA requested an exemption from MENPET for the Windfall Profits Tax under the provision in the April 2011 Windfall Profits Tax law. PDVSA issued to Petrodelta its share of the exemption credit for 2012 of $55.2 million ($36.4 million net of tax) ($11.3 million net to our 20.4 percent interest, $7.4 million net of tax net to our 20.4 percent interest) based on PDVSA’s calculation and projects PDVSA deemed to qualify for the exemption. Petrodelta has not been provided with supporting documentation indicating the properties have been appropriately qualified by MENPET, the specific details for the exemption credit, such as which fields, production period or production, or the supporting calculations. In July 2014, Petrodelta received confirmation that MENPET had denied PDVSA’s application for the exemption, and Petrodelta reversed its estimated share of the credit.  We determined that until MENPET either issues guidance on the exemption provisions in the law or issues payment forms including the exemption credit, or written approval from MENPET for this exemption credit is received by Petrodelta or us, we would exclude the exemption credit from our equity earnings in Petrodelta under U.S. GAAP.  In March 2013, we included an adjustment for the differences between IFRS and U.S. GAAP which reversed Petrodelta’s accrual for the Windfall Profits Tax credit, and in June 2014 we recorded an adjustment to Petrodelta’s reversal of the Windfall Profits Tax credit.

Royalty Cap

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

Sports Law

The Organic Law on Sports, Physical Activity and Physical Education (“Sports Law”) was published in the Official Gazette on August 23, 2011 and is effective beginning January 1, 2012. Per the Sports Law, contributions are to be calculated on an after-tax basis. However, CVP has instructed Petrodelta to calculate the contribution on a before-tax basis contrary to the Sports Law resulting in an overstatement of the liability. We have adjusted for the over-accrual of the Sports Law in the years ended December 31, 2014 and 2012 Earnings from Investment Affiliate. As of December 31, 2014, the cumulative amount of this adjustment is $1.3 million ($0.3 million net to our 20.4 percent interest).

Functional Currency

 

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

 

As a result of legislation enacted in December 2013 and January and February of 2014, Venezuela now has a multiple exchange rate system. Most of Petrodelta’s transactions are subject to a fixed official exchange rate of 6.3. The Venezuelan government modified the currency exchange system whereby the official exchange rate of 6.3 Bolivars per USD would only apply to certain economic sectors related to purchases of “essential goods and services” while other sectors of the economy would be subject to a new exchange rate, SICAD I, determined by an auction process conducted by Venezuela's Complimentary System of Foreign Currency

---

 

Administration. Participation in the SICAD I mechanism is controlled by the Venezuelan government and is limited to certain companies that operate in designated economic sectors.  In March 2014, an additional currency exchange mechanism was established by the Venezuelan government that allows companies within other economic sectors to participate in an additional auction process (“SICAD II”). The financial information is prepared using the official fixed exchange rate (6.3 from February 2013 through December 2014). At December 31, 2014, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 1,590.4 million Bolivars ($0.3 million) and 3,506.3 million Bolivars ($0.6 million), respectively.

 

On February 10, 2015 the Ministry of Economy, Finance, and Public Banking, and the Central Bank of Venezuela (BCV) published in the Extraordinary Official Gazette No.6.171 Exchange Agreement No.33 with two Official Notices.  The first notice being that the SICAD II exchange rate would be no longer permitted.  Secondly, a new exchange rate called the Foreign Exchange Marginal System (“SIMADI”) has been created.  The SIMADI rate published on March 12, 2015 is 183.15 Bolivars per U.S. Dollars. The SIMADI’s marginal system is available in limited quantities for individuals and companies to purchase and sell foreign currency via banks and exchange houses.  Currently, Petrodelta does not have access to the SIMADI marginal exchange system.

Petrodelta’s results were also impacted by PDVSA changing its policy with respect to invoicing for disbursements made in Bolivars on behalf of Petrodelta to require that such invoices be denominated in U.S. dollars rather than Bolivars. This change was implemented in the fourth quarter of 2013 with retroactive application to certain transactions occurring in 2011 and thereafter. As a result of this change, Petrodelta recorded a $14.2 million foreign currency loss in the three months ended December 31, 2013. Petrodelta recorded an additional $0.3 million foreign currency loss during the year ended December 31, 2014.

Collective Labor Agreement

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

Dividends

 

On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance. Petrodelta shareholder approval of the dividend was received on March 14, 2011. Petrodelta had working capital of $21.7 million as of December 31, 2014; however, due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, this dividend has not yet been received, although it is due and payable, and dividends for subsequent periods have not been declared or paid. Petrodelta’s board of directors declared this dividend and has neither indicated that the dividend is not payable, nor that it will not be paid. Petrodelta consistently earned an annual profit from 2007 through 2014; however, dividends of profits since 2010 have not been declared. There is uncertainty with respect to the timing of the receipt of the dividend declared in November 2010 or whether future dividends will be declared or paid. During the year ended December 31, 2014, we recorded an allowance of $12.2 million to fully reserve the dividend receivable due from Petrodelta.

Petrodelta’s results and operating information is more fully described in Item  15.  Exhibits and Financial Statement Schedules, Note 6 – Investment in Affiliate.

Dussafu Project – Gabon

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

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

During the fourth quarter of 2012, our second exploration well on the Tortue prospect to target stacked pre-salt Gamba and Dentale reservoirs commenced. DTM-1 was spud on November 19, 2012 in a water depth of 380 feet. On January 4, 2013, we announced that DTM-1 had reached a vertical depth of 11,260 feet within the Dentale Formation. Log evaluation and pressure data indicate that we have an oil discovery of approximately 42 feet of pay in a 72-foot column within the Gamba Formation and 123 feet of pay in stacked reservoirs within the Dentale Formation. The first appraisal sidetrack of DTM-1 (“DTM-1ST1”) was spud in January 12, 2013. DTM-1ST1 was drilled to a total depth of 11,385 feet in the Dentale Formation, approximately 1,800 feet from DTM-1 wellbore and found 65 feet of pay in the primary Dentale reservoir. Several other stacked sands with oil shows were encountered; however, due to a stuck downhole tool, logging operations were terminated before pressure data could be collected to

---

 

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

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

 

On June 4, 2014, a Declaration of Commerciality (“DOC”) was signed with Gabon pertaining to the four discoveries on the Dussafu Project offshore Gabon.  Furthermore, on July 17, 2014, the Direction Generale Des Hydrocarbures (“DGH”) awarded an Exclusive Exploitation Authorization (“EEA”) for the development and exploitation of certain oil discoveries on the Dussafu Project and on October 10, 2014, the field development plan was approved. The Company is required to begin initial production within four years of the EEA approval.

During the year ended December 31, 2014, we had cash capital expenditures of $1.2 million for well costs and facilities ($42.5 million for well costs during the year ended December 31, 2013). The 2015 budget for the Dussafu PSC is $3.2  million. See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon for further information on the Dussafu Project.

 

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

 

In December 2014, we impaired the carrying value of our property in Gabon by $50.3 million.  We recorded this impairment based on a qualitative analysis which considered our current liquidity needs, the recent decrease in oil and gas prices, the marketability of our property and the limited time we have to develop this project.

Budong-Budong Project, Indonesia

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

In January 2013, the Budong PSC partners were granted a four year extension of the initial six year exploration term of the Budong PSC to January 15, 2017. The extension of the initial exploration term includes an exploration well, which if not drilled by January 2016, results in the obligation of the Joint Venture to return the entire Budong PSC to the Government of Indonesia.

In December 2012, we signed a farm-out agreement with the operator of the Budong PSC to acquire an additional 7.1 percent participating interest and to become operator of the Budong PSC. We assumed the role of operator effective March 25, 2013. Closing of this acquisition on April 22, 2013 increased our participating ownership interest in the Budong PSC to 71.5 percent with our cost sharing interest becoming 72 percent until first commercial production. As consideration for this transaction, we agreed to fund 100 percent of the costs of the first exploration well of the four-year extension to the Budong PSC.  The exploration well was not drilled by October 2014 (within 18 months of the date of approval from the Government of Indonesia of this transaction); consequently, our partner had the right to give us notice that the consideration for the additional 7.1 percent participating interest must be paid in cash for $3.2 million, which was paid in October 2014.

Operational activities during the year ended December 31, 2014 included continued work on an exploration program targeting the Pliocene and Miocene targets encountered in the two exploratory wells drilled in 2011. Land access and acquisition; environmental studies; construction and upgrades to access roads, bridges, and well site; permitting; and tender prequalification and procurement were on-going.

We were actively discussing the sale of our interests in Budong, and based on indications of interest received in December 2013, we determined that is it was appropriate to recognize and impairment expense of $0.6 million and a charge included in general and administrative expenses related to a valuation allowance on VAT we do not expect to recover of $2.8 million.  The Budong PSC represents $4.6 million of unproved oil and gas properties including inventory on our December 31, 2013 balance sheet.

 

During the first quarter of 2014, the potential buyer terminated the negotiations.  Additional inquiries into our interest in the Budong PSC did not lead to any other prospective buyer; therefore we fully impaired our remaining property value of $4.4 million as of March 31, 2014. 

 

In parallel with the activities to find a prospective buyer, we approached our partner with a proposal for them to acquire Harvest’s participating interest and operatorship in the joint venture and Budong PSC. This was reviewed by their senior management and declined.  In June 2014, Harvest and our partner adopted a resolution to terminate the Budong PSC; therefore no further drilling will occur.  Harvest advised the Indonesian government of this decision on June 4, 2014, and is now in the process of finalizing the relinquishment of the interest.  As a result of these decisions, Harvest accrued a $3.2 million liability as of June 30, 2014 related to the

---

 

December 5, 2012 farm-out agreement discussed above, thereby creating a total impairment expense of $7.7 million during the year ended December 31, 2014.  Harvest paid this $3.2 million liability in October 2014. 

During the year ended December 31, 2014, we had cash capital expenditures of $3.2 million ($0.2 million during the year ended December 31, 2013) for consideration for the additional 7.1 percent participating interest, which was impaired upon the decision to relinquish our interest. 

WAB-21 Project – China

In March 2011, CNOOC granted us an extension to May 2013 of Phase One of the Exploration Period for the WAB-21 contract area. The Joint Management Committee had approved an extension of the license until May 31, 2015. We believed we could continue to receive contract extensions so long as the border disputes with Vietnam persisted. Even though there continued to be increasing activity on the Vietnamese blocks which we believed confirmed 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.

Operational activities during 2014 included costs related to maintenance of the license.  On July 2, 2014, we completed the sale of our rights under the petroleum contract with CNOOC for the WAB-21 area for net proceeds of  $2.9 million and recorded that amount as a gain of sale of oil and gas properties. See Item 1. Business, Operations, WAB-21, South China Sea for further information on the WAB-21 Project.

Colombia – Discontinued Operations

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

For both blocks, phase one of the contract began on December 15, 2012 and expires on December 15, 2015. We have received notices of default from our partners for failing to comply with certain terms of the farm-out agreements for Block VSM14 and Block VSM15, followed by notices of termination on November 27, 2013. As discussed further in Item 3. Legal Proceedings, our partners had filed for arbitration of claims related to these agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests, and we recorded an impairment charge of $3.2 million during the year ended December 31, 2013 which included an accrual of $2.0 million related to this matter.  On December 14, 2014 we paid our partners $2.0 million to settle the arbitration. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations. We are in the process of closing and exiting our Colombia venture. During the year ended December 31, 2013 we had capital expenditures of $1.2 million for leasehold acquisition costs. See Item 1. Business, Operations, Colombia for further information on this project.

Block 64 EPSA Project – Oman – Discontinued Operations

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

Results of Operations

The following discussion on results of operations for each of the years in the three-year period ended December 31, 2014 should be read in conjunction with our consolidated financial statements and related notes thereto.

Years Ended December 31, 2014 and 2013

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

Loss From Continuing Operations

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

---

 

 

Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2014, we incurred $5.7 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations and $0.6 million related to other general business development activities. During the year ended December 31, 2013, we incurred $13.7 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations and $1.5 million related to other general business development activities.

During the year ended December 31, 2014, we impaired $7.7 million related to our Budong Project in Indonesia and $50.3 million related to the Dussafu Project.  During the year ended December 31, 2013, we impaired $0.6 million related to our Budong Project in Indonesia.

 

Through December 31, 2014, we included the results of Petrodelta in our financial statements under the equity method.  We ceased recording earnings from Petrodelta in the second quarter 2014 due to the expected sales price of the second closing purchase agreement approximating the recorded value of our investment in Petrodelta.  The Company was not able to obtain approval from the government of Venezuela during 2014 and on January 1, 2015 we terminated the SPA.  As a result of numerous actions and inactions of Petrodelta’s controlling shareholder (the government of Venezuela) and our inability to obtain approval for the second closing, we have determined that we no longer have any significant of influence within our investment in Petrodelta and in accordance with Accounting Standards Codification “ASC 823 – Investments – Equity Method”, we have decided to account for our investment in Petrodelta under the cost method (“ASC 320 – Investments – Debt and Investments Securities”), effective December 31, 2014.  Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.   In connection with the change in the method of accounting, we performed an impairment analysis of the carrying value of our investment.  Based on this assessment we recorded a one-time pre-tax impairment charge of $355.7 million against the carrying value of our investment.

The decrease in general and administrative costs in the year ended December 31, 2014 from the year ended December 31, 2013, was primarily due to lower employee related costs ($8.2 million), professional fees and contract services ($2.9 million), travel ($0.5 million) and public relations ($0.1 million), offset by higher general operations and overhead ($11.8 million) and  taxes other than income ($0.2 million).  Employee related costs are lower primarily due to lower employee headcount and the impact of the reduction in HNR’s stock price on stock-based compensation.  General operations and overhead is higher primarily due to recording an allowance on doubtful accounts for dividend and accounts receivables from investment affiliate of $13.8 million in 2014 and lower billings to our joint venture partners offset by  the expensing of $2.8 million of Budong PSC value added tax receivable in 2013.  Professional fees are lower due to higher litigation and consulting costs in 2013 compared to 2014.

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

 

The gain on sale of oil and gas properties during the year ended December 31, 2014 relates to the sale of our rights under a petroleum contract with China National Offshore Oil Corporation.  The Company expensed costs related to this property in 2012.  See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 10 – China.

---

 

The decrease in gain on warrant derivative in the year ended December 31, 2014 from the year ended December 31, 2013 was due to a decrease in the estimated fair value for our warrant derivative liability from $1.07 per warrant to zero.  The valuation for the warrants is based primarily on our stock price of $1.81 as December 31, 2014, their remaining life of 0.83 years and their strike price of $12.81 at December 31, 2014.  See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 12 – Warrant Derivative Liability.    

The decrease in interest expense in the year ended December 31, 2014 from the year ended December 31, 2013 was due to the repayment of the 11% Senior Notes on January 11, 2014 offset by interest capitalized to oil and gas properties in the year ended December 31, 2014 of $0.5 million (year ended December 31, 2013:  $8.3 million).

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

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

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

We had an income tax benefit in the year ended December 31, 2014 of $58.3 million as compared to an income tax expense of $73.1 million in the year ended December 31, 2013.  The income tax benefit in 2014 is primarily due to a decrease in the deferred tax liability related to the unremitted earnings of our foreign subsidiary as a result of the impairment of our investment in Petrodelta partially offset by the reinstatement of a valuation allowance against Harvest’s U.S. deferred tax assets.  The income tax expense in 2013 included $89.9 million of deferred income tax related to previously unrecognized income tax on undistributed earnings of foreign subsidiaries (which were considered permanently invested in previous periods), $2.1 million of expense related to the sale of the interest in Harvest Holding offset by the benefit of $8.8 million from the reversal of valuation allowances, the benefit from losses in 2012 and a benefit of $2.2 million from the favorable resolution of certain tax contingencies.

Through December 31, 2014, we included the results of Petrodelta in our financial statements under the equity method.  We ceased recording earnings from Petrodelta in the second quarter due to the expected sales price of the second tranche purchase agreement approximating the recorded value of our investment in Petrodelta.  During the year ended December 31, 2014 we recognized $34.9 million of equity in earnings from our investment in Petrodelta compared to $72.6 million in 2013.  Based on numerous actions of the controlling partner, CVP, owned and controlled by the government of Venezuela, we have determined that we no longer have a significant degree of influence.  As a result of these conditions, we began reporting the results of our operations in Venezuela using the cost method of accounting effective December 31, 2014.

Earnings from Investment Affiliate

Our 40 percent investment in Petrodelta’s financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”) which we have adjusted to conform to U.S. GAAP. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Investment in Affliate.  The following tables summarize revenue and operational results associated with our investment affiliate for the presented years, as well as analysis of the reported variances:

---

 

 

 

 

 

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

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

 

For the year ended December 31, 2014 compared to the year ended December 31, 2013, royalties, which is a function of revenue, decreased due to the decrease in crude oil prices offset by an increase in sales volumes discussed above (net  increase in revenue of $17.9 million at 30 percent royalty). The increase in operating expense is due to higher personnel costs as a result of new labor contract, higher maintenance costs and increased chemical costs. Workover expense is lower for the year ended December 31, 2014 than the year ended December 31, 2013 due to running one workover rig in 2014 versus between one and two workovers rigs in 2013.  Depletion, depreciation and amortization increased as a result of higher capitalized costs, including wells and infrastructure placed in service during 2014. Windfall profits tax expense decreased from declining Venezuela crude basket prices in line with declining world oil prices in 2014.  The foreign currency transaction gain in 2013 is due to the Bolivar devaluation in February 2013 from 4.30 Bolivars/U.S. Dollar to 6.30 Bolivars/U.S. Dollar and Petrodelta having more Bolivar denominated liabilities than Bolivar denominated assets.  Interest expense is due to increase in adjustments to the fair value of VAT credits ($47.7 million) offset by decrease accretion expense ($18.2 million).  Income tax expense decreased between the years primarily due to a revision to inflation adjustments to fixed assets and by the decrease in pre-tax income.

Net Income (Loss) Attributable to Noncontrolling Interests 

Net loss attributable to noncontrolling interest was $165.2 million for the year ended December 31, 2014 compared to net income attributable to noncontrolling interest of $11.6 million for year ended December 31, 2013.  The net loss attributable to

---

 

noncontrolling interest in 2014 was related to the impairment of our investment in Petrodelta and our decision to cease recording earnings from Petrodelta in the second quarter due to the expected sales price of the second tranche purchase agreement approximating the recorded value of our investment in Petrodelta.  During 2013 the net income attributable to noncontrolling interest was impacted by the sale of a portion of our interest in Harvest Holding which occurred in December.

Discontinued Operations

As a result of the decision to not request an extension of the first phase or enter the second phase of the EPSA A1 Ghubar / Qarn Alam license (“Block 64 EPSA”), Block 64 was relinquished effective May 23, 2013. The carrying value of Block 64 EPSA of $6.4 million was written off to impairment expense at December 31, 2012.  Operations in Oman were terminated, and the field office was closed May 31, 2013. We have no continuing involvement in Oman. The nominal loss from discontinued operations for Oman for the year ended December 31, 2014 included general and administrative expenses for legal and other professional fees. The loss from discontinued operations for Oman of $0.7 million for the year ended December 31, 2013 included $0.2 million of exploration expense and $0.5 million of general and administrative expenses and other expenses.

We received notices of default from our partners for failing to comply with certain terms of the farm-out agreements for Block VSM14 and Block VSM15 in Colombia, followed by notices of termination on November 27, 2013. As discussed further in Item 3. Legal Proceedings, our partners filed for arbitration of claims related to these agreements. We accrued $2.0 million as of December 31, 2013 related to obligations under the farm-out agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests.  On December 14, 2014 we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations. We are in the process of closing and exiting our Colombia venture. The loss from discontinued operations included $0.5 million in general and administrative expenses during the year ended December 31, 2014.  The loss from discontinued operations included $3.2 million in impairment expense, $0.7 million of exploration expense and $0.6 million in general and administrative expenses during the year ended December 31, 2013.

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

Years Ended December 31, 2013 and 2012

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

---

 

Loss From Continuing Operations

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

 

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

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

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

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

The gain on warrant derivative in the year ended December 31, 2013 as compared to a loss for the year ended December 31, 2012 was due to a reduction in the estimated fair value for our warrant derivative liability. As discussed further in Notes to Consolidated Financial Statements, Note 12 – Warrant Derivative Liability, the decrease in value reflects the impact of the increased likelihood of an event which would trigger certain early settlement provisions.

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

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

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

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

---

 

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

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

During the year ended December 31, 2013 we recognized equity in earnings from Petrodelta of $72.6 million compared to $67.8 million during the year ended December 31, 2012.  The increase is primarily due to increased production offset by decreases in crude prices.

Earnings from Investment Affiliate

Our 40 percent investment in Petrodelta’s financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”) which we have adjusted to conform to U.S. GAAP. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Investment in Affliate. The following tables summarize revenue and operational results associated with our investment affiliate for the presented years, as well as analysis of the reported variances:

 

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

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

 

 

---

 

For the year ended December 31, 2013 compared to the year ended December 31, 2012, royalties, which is a function of revenue, increased due to the increase in revenues discussed above (net increase in revenue of $63.5 million at 30 percent royalty). The increase in operating expense is due to increased oil production as well as operating inefficiencies. Workover expense is higher for the year ended December 31, 2013 than the year ended December 31, 2012 due to running between one and two workovers rigs in 2013 versus one workover rig in 2012. Windfall Profits Tax, which is a function of volume and price received per barrel as well as pricing levels set for determining Windfall Profits Tax, decreased due to an increase in the pricing levels under the Windfall Profits Tax Law (See Operations – Petrodelta, S.A. above. The foreign currency transaction gain is due to the Bolivar devaluation in February 2013 from 4.30 Bolivars/U.S. Dollar to 6.30 Bolivars/U.S. Dollar and Petrodelta having more Bolivar denominated liabilities than Bolivar denominated assets. Interest expense is due to increases in adjustments to the fair value of VAT credits ($15.3 million) offset by decrease in accretion expense ($0.6 million).  Petrodelta’s effective tax rate (inclusive of the adjustments to reconcile to reported earnings from unconsolidated investment affiliate) for the year ended December 31, 2013 was higher than the effective tax rate for the year ended December 31, 2012 primarily because the foreign currency transaction gain is not included in taxable income.

Net Income Attributable to Noncontrolling Interests

Net income attributable to noncontrolling interest was $11.6 million for the year ended December 31, 2013 compared to $13.4 million for year ended December 31, 2012.  The decrease in net income attributable to noncontrolling interest is primarily a result of lower earnings from Petrodelta during the period in which the noncontrolling interest increased from 20 percent to 49 percent..

Discontinued Operations

As a result of the decision to not request an extension of the first phase or enter the second phase of the EPSA A1 Ghubar / Qarn Alam license (“Block 64 EPSA”), Block 64 was relinquished effective May 23, 2013. The carrying value of Block 64 EPSA of $6.4 million was written off to impairment expense at December 31, 2012. Operations in Oman were terminated, and the field office was closed May 31, 2013. We have no continuing involvement in Oman. The loss from discontinued operations for Oman of $0.7 million for the year ended December 31, 2013 included $0.2 million of exploration expense and $0.5 million of general and administrative expenses and other expenses. The loss from discontinued operations for Oman of $12.7 million for the year ended December 31, 2012 included $0.2 million of exploration expense, $6.4 million of impairment expense, $4.9 million related to dry hole costs and $1.2 million of general and administrative and other expenses.

We received notices of default from our partners for failing to comply with certain terms of the farm-out agreements for Block VSM14 and Block VSM15 in Colombia, followed by notices of termination on November 27, 2013. As discussed further in Item 3. Legal Proceedings, our partners filed for arbitration of claims related to these agreements. We accrued $2.0 million as of December 31, 2013 related to obligations under the farm-out agreements. After evaluating these circumstances, we determined that it was appropriate to fully impair the costs associated with these interests.  On December 14, 2014 we settled all arbitration claims for a payment of $2.0 million and the arbitration was dismissed. As we no longer have any interests in Colombia, we have reflected the results in discontinued operations. We are in the process of closing and exiting our Colombia venture. The loss from discontinued operations included $0.5 million in general and administrative expenses during the year ended December 31, 2014.  The loss from discontinued operations included $3.2 million in impairment expense, $0.7 million of exploration expense and $0.6 million in general and administrative expenses during the year ended December 31, 2013.

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 expensing of $5.2 million

---

 

of accounts and note receivable and $3.6 million of accounts payable and carry obligation related to the settlement of all outstanding claims with a private third party on the Antelope Project.

Oman and Colombia operations and the Antelope Project have been classified as discontinued operations. There were no revenues applicable to discontinued operations during the years ended December 31, 2013 and 2012. Loss from discontinued operations was:

 

Risks, Uncertainties, Capital Resources and Liquidity

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

 

Liquidity

 

Our financial statements for the year ended December 31, 2014 have been prepared under the assumption that we will continue as a going concern. We expect that in 2015 we will not generate revenues, we will continue to generate losses from operations, and that our operating cash flows will not be sufficient to cover our operating expenses. While we believe that we may be able to raise additional capital through issuances of debt or equity or through sales of assets, our circumstances at such time raise substantial doubt about our ability to continue to operate as a going concern. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

Our current capital resources may not be sufficient to support our liquidity requirements through 2015.  However, we believe certain cost reduction measures could be put into place which would not jeopardize our operations and future growth plans.  In addition, we could delay the discretionary portion of our capital spending to future periods or sell or farm down our Gabon asset as necessary to maintain the liquidity required to run our operations, as warranted.  There are no assurances that we will be successful in selling or farming-down this asset.

 

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

 

The long-term continuation of our business plan through 2015 and beyond is dependent upon the generation of sufficient cash flow to offset expenses.  We will be required to obtain additional funding through public or private financing, farm-downs, further reduce operating costs, or possible sales of assets.  Failure to generate sufficient cash flow by raising additional capital through debt or equity financings, reducing operating costs, or by farm-downs or selling of assets further could have a material adverse effect on our ability to meet our short- and long-term liquidity needs and achieve our intended long-term business objectives.

Accumulated Undistributed Earnings of Foreign Subsidiaries

As of December 31, 2014, the book-tax outside basis difference in our foreign subsidiary, HNR Energia B.V., resulting from unremitted earnings was approximately $158.6 million. Prior to 2013, no U.S. taxes had been recorded on these earnings as it was our practice and intention to reinvest the earnings of our non-U.S. subsidiaries in those operations.

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

---

 

During the fourth quarter of 2013, management evaluated numerous factors related to the timing and amounts of possible future distribution of these earnings to the parent company, with consideration of the sale of non-U.S. assets. While we will continue, to the extent possible, to operate the Company’s business in the normal course, management is also considering distributions to the Company’s shareholders which could include the distribution of proceeds from the sales of assets by the Company’s foreign subsidiaries to the U.S. parent company possibly resulting in U.S. taxable income. Because management is pursuing various alternatives, a determination was made that it was appropriate to record a deferred tax liability associated with the unremitted earnings of our foreign subsidiaries of $89.9 million in the fourth quarter of 2013. However, primarily due to the recognition of the $355.7 million pre-tax impairment of our investment in Petrodelta in 2014, the balance decreased by $75.2 million to $14.7 million as of December 31, 2014.  As the sale of the remaining interest in Harvest Holding was terminated, the deferred tax liability is now considered long term.

Working Capital and Cash Flows

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

 

 

 

Working Capital

The increase in working capital of $18.7 million between December 31, 2013 and December 31, 2014 was primarily due to cash used to fund our loss from operations, interest payments as well as the extinguishment of certain debt in January 2014.  The long-term deferred tax liability of $14.7 million as of December 31, 2014 is primarily related to the deferred tax liability on undistributed earnings of foreign subsidiaries. With the termination of the sale of the remaining interest in Harvest Holdings, the deferred tax liability related to the foreign unremitted earnings at December 31, 2014 was classified as long-term.

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

Cash Flow from Operating Activities

During the year ended December 31, 2014, net cash used in operating activities was approximately $39.2 million ($37.1 million during the year ended December 31, 2013). The $2.1 million increase in use of cash was primarily due to decreases in accounts payable, accrued liabilities and income taxes payable offset by decreases in accounts receivable.

Cash Flow from Investing Activities

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

 

 

---

 

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

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

Petrodelta’s capital commitments will be determined by its business plan. Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. Our budgeted capital expenditures of $3.5 million for 2015, of which $1.3  million is non-discretionary, for U.S. and Gabon operations will be funded through our existing cash balances, accessing equity and debt markets, and cost reductions. In addition, we could delay the discretionary portion of our capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, as warranted.

Cash Flow from Financing Activities

During the year ended December 31, 2014, we:

During the year ended December 31, 2013, we:

---

 

Contractual Obligations

At December 31, 2014, we had the following lease commitments for office space in Houston, Texas, regional/technical offices in Singapore and Caracas and a field office in Port Gentil, Gabon that support field operations in those areas.

 

 

 

 

At December 31, 2014, we had the following contractual obligations:

 

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

Senior Unsecured Notes

On October 11, 2012, we closed an offering of $79.8 million in aggregate principal amount of our 11% Senior Notes. We used a portion of the proceeds from the sale of the 29 percent interest in Harvest Holding to redeem all of the 11% Senior Notes. The notes were redeemed on January 11, 2014, for $80.0 million, including principal and accrued and unpaid interest. As a result of the redemption, we recorded a loss on extinguishment of debt of approximately $3.6 million during the year ended December 31, 2014. This loss primarily includes the expensing of the discount on debt ($2.3 million) and the expensing of financing costs related to the term loan facility ($1.3 million).  During the second quarter of 2014, we recorded an additional loss on extinguishment of debt of approximately $1.1 million related to a provision for early debt repayment; therefore, during the year ended December 31, 2014 we recorded a total loss on extinguishment of debt of $4.7 million.   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, 2014,  2013 and 2012. 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.

Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004, March 2005, January 2010, January 2011, February 2013 and December 2013. As a result of the December 2013 devaluation, Harvest Vinccler recorded a $0.1 million gain on revaluation of its assets and liabilities, and Petrodelta recorded a gain of approximately $169.6 million gain on revaluation of its assets and liabilities.

---

 

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”) (11.3 Bolivars per U.S. Dollar). However, during the year ended December 31, 2014, Harvest Vinccler exchanged approximately $0.4 million through the Central Bank and received an average exchange rate of 34.4  Bolivars per U.S. Dollar. See 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 an important factor with respect to certain aspects of the results of operations in Venezuela. The inflation rate in Venezuela was 68.5 percent for the year ended December 31, 2014 (year ended December 31, 2013:  56.2 percent).

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 loss. There are many factors that affect foreign exchange rates and the resulting exchange gains and losses, many of which are beyond our influence.

Investment in Affiliate

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

Through December 31, 2014, we included the results of Petrodelta in our financial statements under the equity method.  We ceased recording earnings from Petrodelta in the second quarter 2014 due to the expected sales price of the second closing purchase agreement approximating the recorded value of our investment in Petrodelta.  The Company was not able to obtain approval from the government of Venezuela during 2014 and on January 1, 2015 we terminated the SPA.  As a result of numerous actions and inactions of Petrodelta’s controlling shareholder (the government of Venezuela) and our inability to obtain approval for the second closing, we have determined that we no longer have any significant of influence within our investment in Petrodelta and in accordance with Accounting Standards Codification “ASC 823 – Investments – Equity Method”, we have decided to account for our investment in Petrodelta under the cost method (“ASC 320 – Investments – Debt and Investments Securities”), effective December 31, 2014.  Under the cost method we will not recognize any equity in earnings from our investment in Petrodelta in our results of operations, but will recognize any cash dividends in the period they are received.   In connection with the change in the method of accounting, we performed an impairment analysis of the carrying value of our investment.  Based on this assessment we recorded a one-time pre-tax impairment charge of $355.7 million against the carrying value of our investment. 

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.

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 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. 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.

Since December of 2013 we  have provided deferred income taxes on undistributed earnings of our foreign subsidiaries where we are not able to assert that such earnings were permanently reinvested, or otherwise could be repatriated in a tax free manner, as part of our ongoing business.

 

New Accounting Pronouncements

 

In April 2014, FASB issued ASU No. 2014-08 “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” which is included in ASC 205 “Presentation of Financial Statements” and ASC 360 “Property, Plant, and Equipment.” This update changes the criteria for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. Under the revised standard, a discontinued operation is (1) a component of an entity or group of components that has been disposed of or is classified as held for sale that represents a strategic shift that has or will have a major effect on an entity’s operations and financial results or (2) an acquired business or nonprofit activity that is classified as held for sale on the date of the acquisition. Under current U.S. GAAP, an entity is prohibited from reporting a discontinued operation if it has certain continuing cash flows or involvement with the component after the disposal. The new guidance eliminates these criteria. The guidance does not change the presentation requirements for

---

 

discontinued operations in the statement where net income is presented. Also, the new guidance requires the reclassification of assets and liabilities of a discontinued operation in the statement of financial position for all prior periods presented. The standard expands the disclosures for discontinued operations and requires new disclosures related to individually material disposals that do not meet the definition of a discontinued operation, an entity’s continuing involvement with a discontinued operation following the disposal date and retained equity method investments in a discontinued operation. The amendment should be applied prospectively; however, early adoption is permitted but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issue. The amendment is effective for annual periods beginning on or after December 15, 2014 and interim periods within annual periods beginning on or after December 15, 2015. This guidance will not impact disposals (or classifications as held for sale) in periods prior to the period of adoption. We have elected an early adoption of this guidance, which we have applied to our treatment of our Indonesia interests.  See Note 9 – Indonesia for further information.

 

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

 

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

 

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

For public entities such as the Company, the amendments in the update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted.  An entity should apply the amendments either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of initial application. We are currently evaluating the impact of this guidance.  During the period from May 2011, the date we disposed of our interest in the Antelope Project, to date, we have not had any revenues as our oil and gas properties have not had any production.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Item  7A.  Quantitative and Qualitative Disclosures About Market Risk

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

Oil Prices

Oil and natural gas prices historically have been volatile, and this volatility is expected to continue. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control. Being primarily a crude oil producer, we are more significantly impacted by changes in crude oil prices than by changes in natural gas prices. As an independent oil producer, our revenue, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas.

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

---

 

Interest Rates

Total debt at December 31, 2014 consisted of $13.7 million in notes payable to noncontrolling interest owners. We used a portion of the proceeds from the sale of the 29 percent interest in Harvest Holding to redeem all of our 11% Senior Notes. The notes were redeemed on January 11, 2014, for $80.0 million, including principal and accrued and unpaid interest. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risks, Uncertainties, Capital Resources and Liquidity. Interest on the note payable to the Vinccler accrues at US dollar based three month LIBOR plus 0.5% and interest is due and payable on December 31, 2015. On March 6, 2015 Vinccler foregave the note plus accrued interest.   Interest on note payable to Petroandina accrues at 11% and is paid quarterly. 

Foreign Exchange

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

Item  8.  Financial Statements and Supplementary Data

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

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

On December 1, 2014, UHY LLP ("UHY") informed Harvest that, effective on that date, UHY’s Texas practice had been acquired by BDO USA, LLP ("BDO") (the "UHY Acquisition"). As a result of the UHY Acquisition, effective December 1, 2014, UHY resigned as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2014. UHY previously served as independent registered public accounting firm to audit the financial statements and internal control over financial reporting of the Company for the fiscal year ended December 31, 2013. The Audit Committee of the Board of Directors of the Company had selected UHY to serve as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2014. 

The audit reports of UHY on the Company’s consolidated financial statements for the year ended December 31, 2013 did not contain an adverse opinion or disclaimer of opinion, and these statements were not qualified or modified as to uncertainty, audit scope or accounting principles. 

During the fiscal year ended December 31, 2013, and the subsequent interim period through December 1, 2014, there were no disagreements with UHY on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreement, had it not been resolved to the satisfaction of UHY, would have caused UHY to make reference thereto in its reports on the financial statements for such periods. During this time, there have been no "reportable events," as that term is described in Item 304(a)(1)(v) of Regulation S-K, promulgated under the Securities Act of 1933.

As a result of the UHY Acquisition, the Audit Committee appointed BDO as the successor independent registered public accounting firm on December 3, 2014. Prior to such appointment, the Company had not consulted with BDO with respect to the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company’s consolidated financial statements, or any other matter or reportable events listed in Items 304(a)(2)(i) and (ii) of Regulation S-K.

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, 2014, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) were effective.

Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial

---

 

officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the 2013 Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of The Treadway Commission. Based on our evaluation under the 2013 Internal Control Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2014. The effectiveness of our internal control over financial reporting as of December 31, 2014, has been audited by BDO USA, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Changes in Internal Control over Financial Reporting. There have been no changes in internal control over financial reporting during the quarter ended December 31, 2014 that have materially affected or are reasonably likely to materially affect that Company’s internal control over financial reporting.

Item  9B.  Other Information

None.

 

 

---

 

PART III

Item  10.  Directors, Executive Officers and Corporate Governance

 

The information required by this item is, or the Company intends that the information required by this item will be, set forth in the definitive proxy statement relating to the 2015 Annual Meeting of Stockholders of Harvest Natural Resources, Inc. (the Proxy Statement”) or an amendment to this report.  Such information is incorporated by reference into this item pursuant to General Instruction G(3) to Form 10-K.

 

Item 11.  Executive Compensation

 

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

 

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

 

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

 

 

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

 

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

 

 

Item  14.  Principal Accountant Fees and Services

 

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

 

---

 

PART IV

Item  15.  Exhibits and Financial Statement Schedules

 

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

(b)3. Exhibits:

 

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