HARVEST NATURAL RESOURCES, INC.

FORM 10-K

(Annual Report)

Filed 05/02/13 for the Period Ending 12/31/12

 

Address 1177 ENCLAVE PARKWAY

STE 300

HOUSTON, TX 77077

Telephone 281-899-5700

CIK 0000845289

Symbol HNR

SIC Code 1311 - Crude Petroleum and Natural Gas

Industry Oil & Gas Operations

Sector Energy

Fiscal Year 12/31

http://www.edgar-online.com

© Copyright 2013, EDGAR Online, Inc. All Rights Reserved.

Distribution and use of this document restricted under EDGAR Online, Inc. Terms of Use.
Table of Contents 

 

UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION 

WASHINGTON, DC 20549 

 

FORM 10-K 

 

(Mark One) 

For the fiscal year ended December 31, 2012 

or 

 

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 (§ 232.405 of this chapter) during the preceding 12 months (or 

for such shorter period that the registrant was required to submit and post such files). Yes  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.  

 

 

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

OF 1934 

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

ACT OF 1934 

 

 

Delaware 77-0196707 

(State or other jurisdiction of 

incorporation or organization) 

(I.R.S. Employer 

Identification Number) 

1177 Enclave Parkway, Suite 300 

Houston, Texas 77077 

(Address of principal executive offices) (Zip Code) 

Title of each class Name of each exchange on which registered 

Common Stock, $.01 Par Value NYSE 

 
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, 2012 was: $319,236,984. 

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practical date. Class: Common 

Stock, par value $0.01 per share, on May 2, 2013, shares outstanding: 39,454,279. 

DOCUMENTS INCORPORATED BY REFERENCE 

Portions of the registrant’s Proxy Statement for the 2013 Annual Meeting of Stockholders to be filed with the Securities and Exchange 

Commission, not later than 120 days after the close of the registrant’s fiscal year, pursuant to Regulation 14A, are incorporated by reference 

into Items 10, 11, 12, 13 and 14 of Part III of this annual report. 

 

 

 

Large Accelerated Filer  Accelerated Filer  

Non-Accelerated Filer  Smaller Reporting Company  
Table of Contents 

HARVEST NATURAL RESOURCES, INC. 

FORM 10-K 

TABLE OF CONTENTS 

 

 Page 

Part I 

Item 1. Business 1 

Item 1A. Risk Factors 16 

Item 1B. Unresolved Staff Comments 22 

Item 2. Properties 22 

Item 3. Legal Proceedings 22 

Item 4. Mine Safety Disclosures 24 

Part II 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 25 

Item 6. Selected Financial Data 27 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 27 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk 49 

Item 8. Financial Statements and Supplementary Data 50 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 50 

Item 9A. Controls and Procedures 50 

Item 9B. Other Information 52 

Part III 

Item 10. Directors, Executive Officers and Corporate Governance 53 

Item 11. Executive Compensation 59 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 83 

Item 13. Certain Relationships and Related Transactions, and Director Independence 85 

Item 14. Principal Accountant Fees and Services 86 

Part IV 

Item 15. Exhibits and Financial Statement Schedules 87 

Financial Statements S-2 

Signatures S-65 
Table of Contents 

PART I 

Harvest Natural Resources, Inc. (“Harvest” or the “Company”) cautions that any forward-looking statements as such term is defined in 

Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as 

amended (the “Exchange Act”) contained in this report or made by management of the Company involve risks and uncertainties and are 

subject to change based on various important factors. When used in this report, the words “budget”, “forecast”, “expect”, “believes”, 

“goals”, “projects”, “plans”, “anticipates”, “estimates”, “should”, “could”, “assume” and similar expressions are intended to identify 

forward-looking statements. In accordance with the provisions of the Securities Act and the Exchange Act, we caution you that important 

factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include our concentration of 

operations in Venezuela, the political and economic risks associated with international operations (particularly those in Venezuela), the 

anticipated future development costs for undeveloped reserves, drilling risks, the risk that actual results may vary considerably from reserve 

estimates, the dependence upon the abilities and continued participation of certain of our key employees, the risks normally incident to the 

exploration, operation and development of oil and natural gas properties, risks incumbent to being a noncontrolling interest shareholder in a 

corporation, the permitting and the drilling of oil and natural gas wells, the availability of materials and supplies necessary to projects and 

operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, the Company’s ability to acquire oil 

and natural gas properties that meet its objectives, availability and cost of drilling rigs and seismic crews, overall economic conditions, 

political stability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties 

or quotas, changes in taxes, changes in governmental policy, lack of liquidity, availability of sufficient financing, estimates of amounts and 

timing of sales of securities, changes in weather conditions, and ability to hire, retain and train management and personnel. See Item 1A. Risk 

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

 

Executive Summary 

Harvest Natural Resources, Inc. is a petroleum exploration and production company incorporated under Delaware law in 1989. Our 

focus is on acquiring exploration, development and producing properties in geological basins with proven active hydrocarbon systems. Our 

experienced technical, business development and operating personnel have identified low entry cost exploration opportunities in areas with 

large hydrocarbon resource potential. We operate from our Houston, Texas headquarters. We also have regional/technical offices in the United 

Kingdom and Singapore, and field offices in Jakarta, Republic of Indonesia (“Indonesia”); Port Gentil, Republic of Gabon (“Gabon”); and 

Muscat, Sultanate of Oman (“Oman”) to support field operations in those areas. 

We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan 

interests are owned through Harvest-Vinccler Dutch Holding, B.V., a Dutch private company with limited liability (“Harvest Holding”). Our 

ownership of Harvest Holding is through HNR Energia, B.V. (“HNR Energia”) in which we have a direct controlling interest. Through HNR 

Energia, we indirectly own 80 percent of Harvest Holding and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., 

a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining 20 percent 

interest of Harvest Holding. Harvest Holding owns, indirectly through wholly owned subsidiaries, a 40 percent of Petrodelta, S.A. 

(“Petrodelta”). As we indirectly own 80 percent of Harvest Holding, we indirectly own a net 32 percent interest in Petrodelta, and Vinccler 

indirectly owns eight percent. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petroleos de 

Venezuela S.A. (“PDVSA”) owns 100 percent of CVP. Harvest Holding has a direct controlling interest in Harvest Vinccler S.C.A. (“Harvest 

Vinccler”). Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with PDVSA. We 

do not have a business relationship with Vinccler outside of Venezuela. 

Through the pursuit of technically-based strategies, we are building a portfolio of exploration prospects to complement the low-risk 

production, development and exploration prospects we hold in Venezuela. In addition to our interests in Venezuela, we hold exploration 

acreage mainly onshore West Sulawesi in Indonesia, offshore of Gabon, onshore in Oman, and offshore of the People’s Republic of China 

(“China”). 

 

1 

Item 1. Business 
Table of Contents 

From time to time we learn of possible third party interests in acquiring ownership in certain assets within our property portfolio. 

We evaluate these potential opportunities taking into consideration our overall property mix, our operational and liquidity requirements, our 

strategic focus and our commitment to long-term shareholder value. 

During the last two years, we have been exploring a broad range of strategic alternatives for enhancing stockholder value. On 

September 24, 2010, we retained Merrill Lynch, Pierce, Fenner & Smith (“Merrill Lynch”) to provide advisory services to assist us in 

exploring those strategic alternatives, including, among others, a sale of assets. Since that time, we have received several indications of interest 

from third parties, provided due diligence materials to third parties under confidentiality agreements and had preliminary discussions with third 

parties regarding a sale of our interest in Venezuela, but until March 6, 2012, we had not determined that any of the transactions discussed were 

in our best interests. On March 6, 2012, we announced that we had commenced exclusive negotiations with a third party for the possible sale of 

our 32 percent interest in Petrodelta. See Share Purchase Agreement (“SPA”) below. 

As of December 31, 2012, we had total assets of $596.8 million, unrestricted cash of $72.6 million and long-term debt of $74.8 

million. For the year ended December 31, 2012, we had no revenues from continuing operations and net cash used in operating activities of 

$26.4 million. As of December 31, 2011, we had total assets of $507.2 million, unrestricted cash of $58.9 million and long-term debt of $31.5 

million. For the year ended December 31, 2011, we had no revenues from continuing operations and net cash used in operating activities of 

$55.2 million. 

At December 31, 2012, Petrodelta’s reserves net to our 32 percent interest are: Proved reserves 38.4 MMBOE, Probable reserves 

61.8 MMBOE, and Possible reserves 104.4 MMBOE. Proved plus Probable reserves at 100.2 MMBOE, after accounting for current year 

production, are virtually unchanged from last year. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of 

Operations, Critical Accounting Policies – Reserves for a definition of proved, probable and possible reserves and a discussion of the 

uncertainty related to such reserve estimates. 

In March 2012, we entered into exchange agreements with certain holders of our 8.25 percent senior convertible notes. We issued 

2.9 million shares of common stock at an effective exchange price of $5.56 per share in exchange for $16.0 million in aggregate principal 

amount of 8.25 percent senior convertible notes and associated interest. See Item 15. Exhibits and Financial Statement Schedules, Notes to 

Consolidated Financial Statements, Note 6 – Long-Term Debt . 

In May 2012, we entered the third exploration phase of the Dussafu Marin Permit (“Dussafu PSC”). The third exploration phase has 

been lengthened to four years. See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon – General . 

In June 2012, we and our wholly owned subsidiary HNR Energia entered into a Share Purchase Agreement (“SPA”) with PT 

Pertamina (Persero), a state-owned limited liability company existing under the laws of Indonesia (“Buyer”). On February 20, 2013, we 

announced that the SPA was terminated. See Item 1. Business, Operations, Petrodelta, Share Purchase Agreement (“SPA”) . 

In August 2012, we entered into exchange agreements with certain holders of our 8.25 percent senior convertible notes. We issued 

1.2 million shares of common stock at an effective exchange price of $5.60 per share in exchange for $6.5 million in aggregate principal 

amount of 8.25 percent senior convertible notes and associated interest. See Item 15. Exhibits and Financial Statement Schedules, Notes to 

Consolidated Financial Statements, Note 6 – Long-Term Debt . 

In October 2012, we announced the sale of $79.8 million aggregate principal amount of 11 percent senior unsecured notes due 

October 11, 2014, and warrants to purchase up to 0.8 million shares of our common stock with an exercise price of $10.00 per share. The net 

cash proceeds of the offering were approximately $63.5 million after deducting the issuance discount, placement fees, and other transaction 

costs. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Long-Term Debt . 

 

2 
Table of Contents 

In October 2012, we extinguished the remaining 8.25 percent senior convertible notes. See Item 15. Exhibits and Financial 

Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Long-Term Debt . 

In November 2012, we announced the commencement of drilling operations on Dussafu Tortue Marin-1 (“DTM-1”) exploration 

well in the Dussafu PSC. See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon – Drilling and Development Activity . 

In December 2012, we received approval for a four year extension of the initial six-year exploration term of the Budong-Budong 

Production Sharing Contract (“Budong PSC”). See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia – General . 

In January 2013, we announced that we had encountered oil in DTM-1. See Item 1. Business, Operations, Dussafu Marin, Offshore 

Gabon – Drilling and Development Activity . 

In January 2013, we acquired an additional 7.1 percent participating interest in the Budong PSC and became interim operator of the 

Budong PSC effective January 16, 2013. See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia – General . 

See Item 1. Business, Operations, Item 1A. Risk Factors, and Item 7. Management’s Discussion and Analysis of Financial 

Condition and Results of Operations for a more detailed description of these and other events during 2012. 

Our strategy has broadened from our primary focus on Venezuela to identify, access and integrate organic growth hydrocarbon 

assets through exploration in basins with proven hydrocarbon systems globally as an alternative to purchasing proved producing assets. We 

seek to leverage our Venezuelan experience as well as our expanded business development and technical platform to create a diversified 

resource base. We have made significant investments to provide the foundation and global reach required for an organic growth focus. While 

exploration has become a larger part of our overall portfolio, we generally restrict ourselves to basins with known hydrocarbon systems and 

favorable risk-reward profiles. 

We intend to use our available cash to pursue additional growth opportunities in Indonesia, Gabon, China and other countries that 

meet our strategy. However, the execution of this strategy may be limited by factors including, among other things, access to additional capital 

and the receipt of dividends from Petrodelta as well as the need to preserve adequate development capital in the interim. 

The ability to successfully execute our strategy is subject to significant risks including, among other things, receipt of dividends 

from Petrodelta, exploration, operating, political, legal and financial risks. See Item 1A. Risk Factors , Item 7. Management’s Discussion and 

Analysis of Financial Condition and Results of Operations and other information set forth elsewhere in this Annual Report on Form 10-K for a 

description of these and other risk factors. 

Available Information 

We file annual, quarterly and current reports, proxy statements and other documents with the Securities and Exchange Commission 

(“SEC”) under the Securities Exchange Act of 1934 (“Exchange Act”). The public may read and copy any materials that we file with the SEC 

at the SEC’s Public Reference Room at 100 F Street NE, Washington, DC 20549-0213. The public may obtain information on the operation of 

the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy 

and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain 

any documents that we file with the SEC at http://www.sec.gov. 

We also make available, free of charge on or through our Internet website (http://www.harvestnr.com), our Annual Report on Form 

10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and if applicable, amendments to those reports filed or furnished 

pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, 

the SEC. Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Exchange Act are also available on our website. 

In 

 

3 
Table of Contents 

addition, we have adopted a Code of Business Conduct and Ethics that applies to all of our employees, including our chief executive officer, 

principal financial officer and principal accounting officer. The text of the Code of Business Conduct and Ethics has been posted on the 

Corporate Governance section of our website. We post on our website any amendments to, or waivers from, our Code of Business Conduct and 

Ethics applicable to our senior officers. Additionally, the Code of Business Conduct and Ethics is available in print to any person who requests 

the information. Individuals wishing to obtain this printed material should submit a request to Harvest Natural Resources, Inc., 1177 Enclave 

Parkway, Suite 300, Houston, Texas 77077, Attention: Investor Relations. 

Reserves 

We measure and disclose our oil and gas reserves in accordance with the provisions of the SEC’s Modernization of Oil and Gas 

Reporting and ASC 932, “Extractive Activities – Oil and Gas” (“ASC 932”). See Item 7. Management’s Discussion and Analysis of Financial 

Condition and Results of Operations, Critical Accounting Policies – Reserves for a definition of proved, probable and possible reserves and a 

discussion of the uncertainty related to such reserve estimates. 

The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control 

procedures, which include verification of data provided, management reviews and review of the independent third party reserves report. The 

technical employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Arts in Engineering 

Science, a Master of Science in Petroleum Engineering, more than 28 years of experience in reservoir engineering, and is a member of the 

Society of Petroleum Engineers. 

All reserve information in this report is based on estimates prepared by Ryder Scott Company L.P. (“Ryder Scott”), independent 

petroleum engineers. The technical personnel responsible for preparing the reserve estimates at Ryder Scott meet the requirements regarding 

qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas 

Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is an independent firm of petroleum engineers, 

geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis. 

In Venezuela during 2012, Petrodelta drilled and completed 12 production wells. Six of the wells were previously identified Proved 

Undeveloped (“PUD”) locations and six wells were previously classified as probable, possible or undefined locations. In 2012, an additional 

ten PUD locations were identified through drilling activity, however ten PUD locations which are scheduled to be drilled five years after the 

wells were originally identified have been reclassified as Probable reserves. At December 31, 2012, Petrodelta has a total of 157 identified 

PUD locations. 

Petrodelta’s 2012 business plan, as proposed by Petrodelta, contemplates sustained drilling activities through the year 2023 to fully 

develop the El Salto, Isleño and Temblador fields. As a noncontrolling interest shareholder in Petrodelta, HNR Finance, B.V. (“HNR 

Finance”), a wholly owned subsidiary of Harvest Holding, has limited ability to control the development plans that are periodically prepared 

and/or approved by the Venezuelan government. The PUD locations which are now scheduled to be drilled five years after they were originally 

identified have been reclassified as Probable reserves. 

Proved undeveloped reserves of 22.9 MMBOE from 157 gross PUD locations are scheduled to be drilled within the period from 

2013 to 2016 and within five years from when these locations were first identified. All above MMBOE represent our net 32 percent interest, 

net of a 33.33 percent royalty. 

Probable undeveloped reserves of 61.8 MMBOE include 17.5 MMBOE from 79 gross undeveloped locations that would otherwise 

meet the definition of proved undeveloped reserves, except that they are scheduled to be drilled at least five years after the date that they were 

originally identified. Of these 79 locations, 72 are scheduled to be drilled within five years from 2013 to 2018. 

 

4 
Table of Contents 

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

of December 31, 2012. 

 

 

Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves as of December 31, 2012, 2011 and 

2010 and changes in proved reserves during the last three years are contained in Item 15. Supplemental Information on Oil and Natural Gas 

Producing Activities (unaudited) . See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation, 

Critical Accounting Policies – Reserves for additional information on our reserves. 

Operations 

As of December 31, 2012, our operations include: 

 

 

 

 

5 

 

Oil and 

NGLs 

Natural 

Gas Total 

 (MBls) (MMcf) (MBOE) 

Proved Developed Reserves: 

International – Venezuela 12,486 17,906 15,470 

 

Total Proved Developed 12,486 17,906 15,470 

 

 

 

 

 

 

Proved Undeveloped Reserves: 

International – Venezuela 22,043 5,304 22,927 

 

Total Proved Undeveloped 22,043 5,304 22,927 

 

 

 

 

 

 

Total Proved Reserves 34,529 23,210 38,397 

 

 

 

 

 

 

Probable Developed Reserves: 

International – Venezuela 8 — 8 

 

Total Probable Developed 8 — 8 

 

 

 

 

 

 

Probable Undeveloped Reserves: 

International – Venezuela 54,668 42,924 61,822 

 

Total Probable Undeveloped 54,668 42,924 61,822 

 

 

 

 

 

 

Total Probable Reserves 54,676 42,924 61,830 

 

 

 

 

 

 

Possible Developed Reserves: 

International – Venezuela — — — 

 

Total Possible Developed — — — 

 

 

 

 

 

 

Possible Undeveloped Reserves: 

International – Venezuela 99,463 29,444 104,370 

 

Total Possible Undeveloped 99,463 29,444 104,370 

 

 

 

 

 

 

Total Possible Reserves 99,463 29,444 104,370 

 

 

 

 

 

 

 Thousand barrels of oil equivalent (“MBOE”) is determined using the approximate heat content ratio of one barrel of crude oil or 

condensate to six thousand cubic feet (“Mcf”) of natural gas, which ratio does not necessarily reflect price equivalency. 

 Information represents our net 32 percent ownership interest in Petrodelta. 

 

• Venezuela . Operations are through our equity affiliate Petrodelta which is governed by the Contract of Conversion (“Conversion 

Contract”) signed on September 11, 2007. Our ownership of Petrodelta is through Harvest Holding which indirectly, through 

wholly owned subsidiaries, owns 40 percent of Petrodelta. As we indirectly own 80 percent of Harvest Holding, we indirectly own 

a net 32 percent interest in Petrodelta. 

 

• Republic of Indonesia (“Indonesia”) . Operations are mainly onshore in West Sulawesi in Indonesia through the Budong PSC. We 

own a 64.51 percent cost sharing interest in the Budong PSC. We became the interim operator in January 2013. Transfer of 

operatorship is subject to regulatory approval. 

 

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

the Dussafu PSC. We are the operator. 

(a) 

(b) 

(b) 

(b) 

(b) 

(b) 

(b) 

(a) 

(b) 
Table of Contents 

 

Petrodelta 

General 

On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Petrodelta Fields 

subject to the conditions of the Conversion Contract was published in the Official Gazette, the official government publication where laws, 

decrees, resolutions, instructions, and other regulations of general interest issued by the central government of Venezuela are published in order 

to make those acts valid and official. Petrodelta is to undertake the exploration, production, gathering, transportation and storage of 

hydrocarbons from the Petrodelta Fields for a maximum of 20 years from that date. Petrodelta is governed by its own charter and bylaws. 

Petrodelta’s portfolio of properties in eastern Venezuela includes large proven oil fields as well as properties with very substantial opportunities 

for both development and exploration. We have seconded key technical and managerial personnel into Petrodelta and participate on 

Petrodelta’s board of directors. 

Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. 

Under its conversion contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. 

Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. 

Petrodelta’s 2012 proposed capital expenditures were expected to be approximately $401.9 million and included a planned drilling program to 

utilize three rigs to drill both development and appraisal wells for maintaining production capacity and the continued appraisal of the 

substantial resource base in the El Salto and Isleño fields. It also included engineering work for the additional infrastructure enhancement 

projects in El Salto and Temblador. Due to insufficient monetary support and contractual adherence by PDVSA, Petrodelta incurred only 

$184.2 million of its 2012 proposed capital expenditures. 

As discussed in previous filings, PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has 

contracted to do work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in 

meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment 

obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind 

in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors, including Harvest 

Vinccler. As a result, Petrodelta has experienced, and is continuing to experience, difficulty in retaining contractors who provide services for 

Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. 

Inability to retain contractors or to pay them on a timely basis is having an adverse effect on Petrodelta’s operations and on Petrodelta’s ability 

to carry out its business plan. 

Crude oil delivered from the Petrodelta fields to PDVSA Petroleo S.A. (“PPSA”), a wholly owned subsidiary of PDVSA, is priced 

with reference to Merey 16 published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, 

commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices 

are quoted and sold in U.S. Dollars. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, 

Operations, Petrodelta for additional information on Petrodelta’s Contract for Sale and Purchase of Hydrocarbons with PPSA (the “Sales 

Contract”). Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per Mcf. PPSA is obligated to make payment to 

Petrodelta in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered. Natural gas deliveries are paid in Venezuelan 

Bolivars (“Bolivars”), but the pricing for natural gas is referenced to the U.S. Dollar. 

In April 2011, the Venezuelan government published in the Official Gazette the Law Creating a Special Contribution on 

Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (the “amended Windfall Profits Tax”). See Item 7. 

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Venezuela – Petrodelta for a discussion 

of the effects of the amended Windfall Profits Tax on Petrodelta’s business. 

 

6 

 

• Sultanate of Oman (“Oman”) . Operations are onshore in Oman through the Exploration and Production Sharing Agreement 

(“EPSA”) Al Ghubar / Qarn Alam license (“Block 64 EPSA”). We have an 80 percent interest in Block 64 EPSA. We are the 

operator. 

 

• People’s Republic of China (“China”) . Exploration acreage is offshore of China in the South China Sea through the Wab-21 

Petroleum Contract (“Wab-21”). We have a 100 percent interest in the WAB-21 petroleum contract. We are the operator. 
Table of Contents 

On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance 

($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to 

Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, as of May 2, 2013, this 

dividend has not been received, although it is due and payable. Petrodelta’s board of directors declared this dividend and has never indicated 

that the dividend is not payable, nor that it will not be paid. The dividend receivable is classified as a long-term receivable at December 31, 

2012 due to the uncertainty in the timing of payment. There is uncertainty with respect to the timing of the receipt of this dividend and whether 

future dividends will be declared or paid. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable 

not be collected or facts and circumstances surrounding our investment change, our results of operations and investment in Petrodelta could be 

adversely impacted. 

Share Purchase Agreement (“SPA”) 

On June 21, 2012, we announced that we and our wholly owned subsidiary HNR Energia had entered into a SPA with PT Pertamina 

(Persero), a state-owned limited liability company existing under the laws of Indonesia (“Buyer”) under which HNR Energia agreed to sell, 

indirectly through subsidiaries, all of its interests in Venezuela for a cash purchase price of $725.0 million, subject to adjustment as described 

in the SPA. 

The closing of the transaction was subject to receipt of three approvals, in addition to satisfaction of other conditions standard in 

transactions of this type: (a) approval by the Ministerio del Poder Popular de Petroleo y Mineria representing the Government of the Bolivarian 

Republic of Venezuela (which indirectly owns the other 60 percent interest in Petrodelta); (b) approval by the Government of the Republic of 

Indonesia in its capacity as Buyer’s sole shareholder; and (c) approval by the holders of a majority of Harvest’s common stock. 

After receiving notice from Buyer that Buyer’s sole shareholder, the Government of Indonesia, had decided not to approve the 

transaction described in the SPA, on February 19, 2013, HNR Energia exercised its right to terminate the agreement in accordance with its 

terms. 

Petrodelta 2013 Capital Budget 

As of May 2, 2013, the 2013 budget for Petrodelta had not yet been approved by its shareholders. Since Petrodelta only executed 

approximately 45.8 percent of its 2012 proposed capital expenditures primarily due to insufficient monetary support and contractual adherence 

by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2013 budget. Should PDVSA 

continue in insufficient monetary support and contractual adherence of Petrodelta, underinvestment in the development plan may lead to 

continued under-performance. However, Petrodelta’s 2013 proposed budget includes a planned drilling program to utilize five rigs to drill both 

development and appraisal wells for maintaining production capacity and the continued appraisal of the substantial resource base in the El 

Salto, Temblador and Isleño fields. It also includes engineering work for continued infrastructure enhancement projects in El Salto and 

Temblador. 

Location and Geology 

Petrodelta Fields 

Uracoa Field 

At December 31, 2012, there were 86 (2011: 86) oil and natural gas producing wells and seven (2011: seven) water injection wells 

in the field. The current production facility has capacity to handle 30 thousand barrels (“MBbls”) of oil per day (down from 60 MBls of oil per 

day in 2011 due to the relocation of treaters to the El Salto and Temblador fields), 130 MBbls of water per day, and storage of up to 75 MBbls 

of crude oil. The oil produced from Uracoa is blended with the oil produced from Tucupita, Bombal and Isleño fields then transported through 

a 25-mile oil pipeline from the Uracoa plant facilities UM-2 to PDVSA’s EPT-1 storage and fiscalization facility. All natural gas presently 

being delivered by Petrodelta is produced from the Uracoa field and is delivered to PDVSA through a 64-mile pipeline to Mamo gas station 

and PDVSA Gas network. 

 

7 
Table of Contents 

Tucupita Field 

At December 31, 2012, there were 15 (2011: 17) oil producing wells and four (2011: four) water injection wells in the field. The 

Tucupita production facility has a capacity to process 30 MBbls of oil per day, 125 MBbls of water per day and storage for up to 60 MBbls of 

crude oil. The oil is transported through a 31-mile, 20 MBbls of oil per day pipeline from the Tucupita field to the Uracoa plant facilities UM-2. 

See Uracoa Field above. 

Bombal Field 

East Bombal was drilled in 1992, and currently remains underdeveloped with only one production well (2011: one). In West 

Bombal, at December 31, 2012, there were three (2011: three) oil producing wells. The oil is transported through a five-mile, ten MBbls of oil 

per day pipeline from the Bombal field to the Uracoa plant facilities UM-2. See Uracoa Field above. 

Isleño Field 

The Isleño field was discovered in 1953. Seven oil appraisal wells were drilled by PDVSA prior to the field being contributed to 

Petrodelta. At December 31, 2012, there were two (2011: no wells) oil producing wells in the field. The oil is transported via vacuum trucks to 

the Uracoa plant facilities UM-2. See Uracoa Field above. Currently, a 16 inch, 6.2 mile, 20 MBbls per day transfer line capacity is being 

constructed from Isleño field to Uracoa to transport the fluids produced. 

Temblador Field 

At December 31, 2012, there were 28 (2011: 27) oil producing wells in the field. The oil is transported through two pipelines: a 5.6-

mile, 40 MBbls of oil per day trunkline from TY-8 flow station (east end of the field) to TY-23 flow station; and a 4.3 mile, 20 MBbls of oil 

per day gathering system from the west end of the field to TY-23 flow station. The total crude oil is then delivered from TY-23 flow station 

into PDVSA’s EPT-1 storage facility. 

El Salto Field 

At December 31, 2012, there were 17 (2011: nine) oil producing wells and one (2011: one) water injection well in the El Salto field. 

In October 2011, Petrodelta completed the pipeline to connect the El Salto field to PDVSA’s COMOR EPM-1 storage facility. The oil is now 

transported through an 18.1-mile, 40 MBbls of oil per day pipeline to PDVSA’s EPM-1 storage facility. 

Infrastructure and Facilities 

Petrodelta has a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA’s EPT-1 storage facility, the custody 

transfer point. The pipeline has a nominal capacity of 30 MBls of oil per day and a design capacity of 60 MBls of oil per day. 

Petrodelta has a 64-mile pipeline from Uracoa to Mamo gas station and PDVSA Gas network with a nominal capacity of 70 million 

cubic feet (“MMcf”) of natural gas per day and a design capacity of 90 MMcf of natural gas per day. 

Petrodelta has at Temblador Field two main gathering systems, one in the East side of the field, a 5.6-mile trunkline from the TY-8 

Flow Station to TY-23 flow station which is next to PDVSA’s EPT-1 storage facility. The trunkline has an operational capacity of 40 MBls of 

fluid per day and a design capacity of 60 MBls of oil per day. The second one, on the West side of the field, a 4.3 mile, 20 MBbls of total fluid 

per day gathering system from the end of the field to TY-23 flow station. The total crude oil, on specification, is then delivered from TY-23 

flow station into PDVSA’s EPT-1 storage facility (the custody transfer point). 

Petrodelta has an 18.1-mile pipeline from El Salto to PDVSA’s COMOR EPM-1 storage facility, the custody transfer point. The 

pipeline has a nominal capacity of 30 MBls of oil per day and a design capacity of 40 MBls of oil per day. Petrodelta is executing additional 

infrastructure enhancement projects in El Salto and Temblador. 

 

8 
Table of Contents 

Petrodelta has long term agreements in place with PDVSA Gas affiliate for purchase of power for the electrical needs, leasing of 

compression, and operation and maintenance of the gas treatment and compression facilities at the Uracoa and Tucupita fields. 

Drilling and Development Activity 

During the year ended December 31, 2012, Petrodelta drilled and completed 12 development wells. Petrodelta delivered 

approximately 13.2 MBls of oil and 2.2 billion cubic feet (“Bcf”) of natural gas, averaging 36,979 barrels of oil equivalent (“BOE”) per day 

during the year ended December 31, 2012. During the year ended December 31, 2011, Petrodelta drilled and completed 15 development wells, 

one successful appraisal well and two water injector wells. Petrodelta delivered approximately 11.4 MBls of oil and 2.3 Bcf of natural gas, 

averaging 32,240 BOE per day during the year ended December 31, 2011. 

Petrodelta began 2012 with three drilling rigs, but PDVSA relocated one rig to another operation. Currently, Petrodelta is operating 

three drilling rigs and two workover rigs and is continuing with infrastructure enhancement projects in the El Salto and Temblador fields. A 

pipeline is currently under construction between the Isleño field and the main production facility at Uracoa. Isleño production is currently being 

trucked to Uracoa. Petrodelta has received two new drilling rigs. The first drilling rig is currently waiting on repairs and is expected to start 

drilling operations in the Isleño field in the first quarter of 2013. The second drilling rig has been mobilized and is expected to start drilling 

operations in the Temblador field in the first quarter of 2013. Petrodelta was notified that it will relocate a current operating rig to another 

operation with the old rig being replaced with a new rig which arrived in February 2013. These rigs result in an expected five working drilling 

rigs in 2013. 

Risk Factors 

We face significant risks in holding a minority equity investment in Petrodelta. These risks and other risk factors are discussed in 

Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 

Budong-Budong, Onshore Indonesia 

General 

In 2007, we entered into a Farmout Agreement to acquire a 47 percent interest in the Budong PSC located mostly onshore West 

Sulawesi, Indonesia. In April 2008, the Government of Indonesia approved the assignment to us of the 47 percent interest in the Budong PSC. 

Our partner is the operator through the exploration phase as required by the terms of the Budong PSC, and we have an option to become 

operator, if approved by the Government of Indonesia and SKK Migas in any subsequent development and production phase. 

We acquired our original 47 percent interest in the Budong PSC by committing to fund the first phase of the exploration program up 

to a cap of $17.2 million, including the acquisition of 2-D seismic and drilling of the first two exploration wells under a Farmout Agreement 

with our partner in the Budong PSC. Prior to drilling the first exploration well, our partner had a one-time option to increase the level of the 

carried interest to a maximum of $20.0 million. On September 15, 2010, our partner exercised their option to increase their carried interest by 

$2.7 million to a total of $19.9 million. The additional carry increased our ownership by 7.4 percent to 54.4 percent. On March 3, 2011, the 

Government of Indonesia approved this change in ownership interest. 

On January 14, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator to a third party, which 

allowed us to acquire an additional 10 percent ownership in the Budong PSC at a cost of $3.7 million payable ten business days after 

completion of the first exploration well. The $3.7 million was paid on April 18, 2011. Closing of this acquisition increased our participating 

ownership interest in the Budong PSC to 64.4 percent with our cost sharing interest becoming 64.51 percent until first commercial production. 

On August 11, 2011, the Government of Indonesia approved this change in ownership interest. 

The initial exploration term of the Budong PSC was due to expire on January 15, 2013. In September 2012, the operator of the 

Budong PSC, on behalf of us and the other co-venturer, submitted a request to BPMIGAS under the terms of the Budong PSC for a four-year 

extension of the initial six-year exploration term of the Budong PSC. In January 2013, we received written approval from SKK Migas of the 

four-year extension of the initial six-year exploration term. 

 

9 
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In November 2012, the Indonesia constitutional court declared BPMIGAS, Indonesia’s oil and gas regulatory authority, to be 

unconstitutional. In January 2013, SKK Migas, the Special Task Force for oil and gas upstream sector, was formed to replace BPMIGAS. SKK 

Migas will supervise all oil and gas industry activities. 

In December 2012, we signed a farmout agreement with the operator of the Budong PSC to acquire an additional 7.1 percent 

participating interest and to become operator of the Budong PSC. We assumed the role of interim operator effective January 16, 2013. Closing 

of this acquisition will increase our participating ownership interest in the Budong PSC to 71.5 percent with our cost sharing interest becoming 

72 percent until first commercial production. The consideration for this transaction is that we will fund 100 percent of the costs of the first 

exploration well of the four-year extension to the Budong PSC. If the exploration well is not drilled within 18 months of the date of approval 

from the Government of Indonesia of this transaction, our partner has the right to give notice that the consideration be paid in cash, or $3.2 

million. The acquisition of the additional participating interest and the transfer of operatorship are dependent on approval by the Government of 

Indonesia. 

We have satisfied all work commitments for the current exploration phase of the Budong PSC. However, the extension of the initial 

exploration term includes an exploration well, which if not drilled by January 2016, results in the termination of the Budong PSC. 

Location and Geology 

During the initial exploration period, the Budong PSC covered 1.35 million acres. The Budong PSC includes a ten-year exploration 

period and a 20-year development phase. Pursuant to the terms of the Budong PSC, at the end of the first three-year exploration phase, 45 

percent of the original area was to be relinquished to BPMIGAS. In January 2010, 35 percent of the original area was relinquished and ten 

percent of the required relinquishment was deferred until 2011. In January 2011, the deferred ten percent of the original total contract area was 

relinquished. The Budong PSC currently covers 0.75 million acres. However, pursuant to the request for extension of the initial exploration 

term, the contract area held by the Budong PSC at the beginning of the extension period should be reduced, per the terms of the Budong PSC, 

from the current 55 percent to 20 percent of the original contract area. In January 2013, our partner, on our behalf, submitted a relinquishment 

proposal of 10 percent to SKK Migas. The retained area will contain all the areas of geological interest to the Budong PSC partners. 

The Budong PSC includes the Lariang and Karama sub-basins, which are the eastern onshore extension of the West Sulawesi 

foldbelt (“WSFB”). Field work performed has confirmed the presence of Eocene source and reservoir potential. Offshore seismic surveys have 

greatly improved the understanding of the geology and enhanced the prospectivity of the offshore WSFB and, by analogy, the sparsely 

explored onshore area. 

Drilling and Development Activity 

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

in 2011. 

Operational activities during 2012 focused on a review of geological and geophysical data obtained from the drilling of LG-1 and 

KD-1 wells to upgrade the prospectivity of the block and to define a prospect for potential drilling in 2013. We have completed remapping of 

both the Lariang and Karama Basins with eight leads in the Lariang Basin and five leads in the Karama Basin having been identified. The 

identification of these leads is the basis for the four-year extension request of the first six-year exploration term. 

Dussafu Marin, Offshore Gabon 

General 

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

The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic 

Resources (“Republic of Gabon”), entered into the third exploration phase of the Dussafu PSC with an effective date of May 28, 2012. The 

Direction Generale Des Hydrocarbures (“DGH”) agreed to lengthen the third exploration phase to four years until May 27, 2016. 

 

10 
Table of Contents 

The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work 

commitment over a four year period. This commitment was fulfilled with the drilling of DTM-1. 

Location and Geology 

The Dussafu PSC contract area is located offshore Gabon, adjacent to the border with the Republic of Congo. It contains 680,000 

acres with water depths to 1,650 feet. Production and infrastructure exists in the blocks contiguous to the Dussafu PSC. 

Drilling and Development Activity 

During 2011, we drilled our first exploratory well, Dussafu Ruche Marin-1 (“DRM-1”), and two appraisal sidetracks. DRM-1 and 

sidetracks discovered oil of approximately 149 feet of pay within the Gamba, Middle Dentale and Upper Dentale Formations. DRM-1 and 

sidetracks are currently suspended pending further exploration and development activities. 

Operational activities during 2012 included completion of the time processing of 545 square kilometers of seismic which was 

acquired in the fourth quarter of 2011 and well planning. The 3-D Pre-Stack Time Migration was completed in July 2012. Pre-Stack Depth 

processing and reprocessing of the 2005 Inboard 3-D seismic of approximately 1,300 square kilometers commenced in June 2012 with the time 

reprocessing and merging of the various 3-D surveys completed in September 2012. Initial velocity model building for the Pre-Stack Depth 

migration commenced and the Pre-Stack Depth processing project is expected to be completed in the second quarter of 2013. 

Well planning progressed to drill an exploration well in the fourth quarter of 2012 on the Tortue prospect to target stacked pre-salt 

Gamba and Dentale reservoirs as well as a secondary post-salt Madiela clastic reservoir. DTM-1 was spud on November 19, 2012. DTM-1 was 

drilled with the Scarabeo 3 semi-submersible drilling unit, and was drilled in a water depth of 380 feet. On January 4, 2013, we announced that 

DTM-1 had reached a vertical depth of 11,260 feet within the Dental Formation. Log evaluation and pressure data indicate that we have an oil 

discovery of approximately 42 feet of pay in a 72 foot column within the Gamba Formation and 123 feet of pay in stacked reservoirs within the 

Dentale Formation. Additional technical evaluation is on-going. 

The first appraisal sidetrack of DTM-1 (“DTM-1ST1”) spud January 12, 2013. DTM-1ST1 was drilled to a Total Depth of 11,385 

feet in the Dental Formation, approximately 1,800 feet from DTM-1 wellbore and found 65 feet of pay in the primary Dentale reservoir. 

Several other stacked sands with oil shows were encountered; however, due to a stuck downhole tool, logging operations were terminated early 

before pressure data could be collected to confirm connectivity. The well can be re-entered, and the downhole tool has since been retrieved. 

DTM-1 and DTM-1ST1 were suspended pending future appraisal and development activities. The drilling rig was demobilized and released on 

February 21, 2013. 

Block 64 EPSA, Oman 

General 

In 2009, we signed an EPSA with Oman for Block 64 EPSA. We have an 80 percent working interest and our partner, Oman Oil 

Company, has a 20 percent carried interest in Block 64 EPSA during the initial period. 

The First Phase of Block 64 EPSA had a minimum work obligation over a three-year period of $22 million to reprocess 375 square 

kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup. In 

order to complete drilling activities of the two exploratory wells, on August 24, 2011, Oman’s Ministry of Oil and Gas approved a one-year 

extension to May 23, 2013 of the First Phase of the EPSA. Both the work and financial commitments for the First Phase on Block 64 EPSA 

have been fulfilled. 

 

11 
Table of Contents 

Location and Geology 

Block 64 EPSA was a block designated for exploration and production of non-associated gas and condensate which the Oman 

Ministry of Oil and Gas awarded over part of the area of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). PDO 

has the rights to the oil and associated gas on Block 64 EPSA and has continued to produce oil from several shallow oil fields within Block 64 

EPSA area. The 955,600 acre block is located in the gas and condensate rich Ghaba Salt Basin in close proximity to the producing Barik, Saih 

Rawl and Saih Nihayda gas and condensate fields. 

Drilling and Development Activity 

In 2011, two exploratory wells were drilled, Mafraq South-1 (“MFS-1”) and Al Ghubar North-1 (“AGN-1”). Both wells were 

plugged and abandoned in the fourth quarter of 2011 and first quarter of 2012, respectively. 

Operational activities during 2012 include post well evaluation and review of geological and geophysical data obtained from the 

drilling of MFS-1and AGN-1 wells. 

On March 12, 2013, we elected to not request an extension of the First Phase or enter the Second Phase of Block 64 EPSA and 

Block 64 will be relinquished effective June 30, 2013. The carrying value of Block 64 EPSA of $6.4 million was written off to impairment 

expense at December 31, 2012. During the first half of 2013, we will terminate operations and close the field office. 

WAB-21, South China Sea 

General 

In 1996, we acquired a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. The 

WAB-21 petroleum contract area lies within an area which is the subject of a border dispute between China and Socialist Republic of Vietnam 

(“Vietnam”). Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The border dispute has 

lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the dispute. Although it 

is uncertain when or how this dispute will be resolved and under what terms the various countries and parties to the agreements may participate 

in the resolution, there has been a small increase in exploration activity in the area starting in 2009. 

Location and Geology 

The WAB-21 contract area covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres 

under certain circumstances, and is located in the West Wan’ an Bei Basin (Nam Con Son) of the South China Sea. Its western edge lies 

approximately 20 miles to the east of significant producing natural gas fields, Lan Tay and Lan Do, which are reported to contain two trillion 

cubic feet (“Tcf”) of natural gas and commenced production in November 2002. Also located to the west of WAB-21 are the Dua and Chim 

Sao discoveries that commenced oil production in 2011 and the oil and gas discovery in 2009 of Ca’ Rong Doh. The WAB-21 contract area 

covers a large unexplored area of the Wan’ an Bei Basin where the same successful Lower Miocene through to Upper Miocene plays to the 

west are present. Exploration success in the basin to date has resulted in discoveries estimated to total in excess of 500 MBls of oil and 7.5 Tcf 

of natural gas. Several similar structural trends and geological formations, each with significant potential for hydrocarbon reserves in traps with 

multiple pay zones similar to the known fields and discoveries to the west are present within WAB-21. 

Drilling and Development Activity 

Due to the border dispute between China and Vietnam, we have been unable to pursue an exploration program during Phase One of 

the contract. As a result, we have obtained license extensions, with the current extension in effect until May 31, 2013. The Joint Management 

Committee has approved an extension of the license until May 31, 2015. We are meeting with CNOOC in April 2013 to discuss the ratification 

of the extension. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes 

persist. 

 

12 
Table of Contents 

Even though there continues to be increasing activity on the Vietnamese blocks which we believe confirms our view of WAB-21’s 

prospectivity, we impaired the carrying value of WAB-21 at December 31, 2012 due to our continued inability to pursue an exploration 

program. However, we continue to seek permission to acquire regional 2-D seismic and localized 3-D seismic. 

Production, Prices and Lifting Cost Summary 

In the following table we have set forth, by country, our net production, average sales prices and average operating expenses for the 

years ended December 31, 2012, 2011 and 2010. The presentation for Venezuela is presented at our net 32 percent ownership interest in 

Petrodelta. The United States is presented at our ownership interest. 

 

 

Drilling and Undeveloped Acreage 

For acquisitions of leases, development and exploratory drilling, we spent approximately (excluding our share of capital 

expenditures incurred by equity affiliates) $23.6 million in 2012 (2011: $106.1 million, 2010: $59.5 million). These numbers do not include 

any costs for the development of proved undeveloped reserves in 2012, 2011 or 2010. 

 

13 

 Year Ended December 31, 

 2012 2011 2010 

Venezuela 

Crude Oil Production (MBbls) 2,810 2,430 1,826 

Natural Gas Production (MMcf) 463 483 470 

Average Crude Oil Sales Price ($ per Bbl) $ 95.91 $ 98.52 $ 70.57 

Average Natural Gas Sales Price ($ per Mcf) $ 1.54 $ 1.54 $ 1.54 

Average Operating Expenses ($ per BOE) $ 10.22 $ 8.99 $ 6.01 

United States 

Monument Butte 

Net Crude Oil Production (MBbls) — 21 106 

Natural Gas Production (MMcf) — 324 417 

Average Crude Oil Sales Price ($ per Bbl) $ — $ 77.91 $ 64.85 

Average Natural Gas Sales Price ($ per Mcf) $ — $ 3.73 $ 3.43 

Average Operating Expenses ($ per BOE) $ — $ 10.34 $ 4.26 

Lower Green River/Upper Wasatch 

Net Crude Oil Production (MBbls) — 40 34 

Natural Gas Production (MMcf) — 13 6 

Average Crude Oil Sales Price ($ per Bbl) $ — $ 89.60 $ 69.63 

Average Natural Gas Sales Price ($ per Mcf) $ — $ 4.62 $ 3.97 

Average Operating Expenses ($ per BOE) $ — $ 56.86 $ 25.41 

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

1,015 MMcf). 

 Crude oil sales net to our 32 percent interest after deduction of royalty. Crude oil sales for Petrodelta at 100 percent were 13,172 MBbls 

for 2012 (2011: 11,390 MBbls, 2010: 8,561 MBbls). 

 Natural gas sales net to our 32 percent interest after deduction of royalty. Natural gas sales for Petrodelta at 100 percent were 2,171 

MMcf for 2012 (2011: 2,266 MMcf, 2010: 2,204 MMcf).

 Petrodelta is not subject to ad valorem or severance taxes. Average operating expenses per BOE net of royalties and workovers were 

$13.41 for 2012 (2011: $9.84 per BOE, 2010: $7.52 per BOE). See Item 7. Management’s Discussion and Analysis of Financial 

Condition and Results of Operations, Results of Operations, Years Ended December 31, 2012 and 2011, Equity in Earnings from Equity 

Affiliates . 

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

(b) 

(a) (c) 

(d) 

(e) 

(e) 

(e) 

(a) 

(b) 

(c) 

(d) 

(e) 
Table of Contents 

We have participated in the drilling of wells as follows: 

 

 

At December 31, 2012, we were completing drilling activities on the DTM-1 on the Dussafu PSC. The DTM-1 was drilled to a 

depth of 11,260 feet. On January 12, 2013, we spud the DTM-1ST1. The DTM-1ST1 was drilled to a depth of 11,385 feet. We have 66.667 

percent net interest in the DTM-1 and DTM-1ST1. 

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

drilling equipment. 

 

14 

 Year Ended December 31, 

 2012 2011 2010 

 Gross Net Gross Net Gross Net 

Wells Drilled Productive: 

Venezuela (Petrodelta) 

Development 12 3.8 15 4.8 16 5.1 

Appraisal — — 1 0.3 — — 

Gabon 

Exploration — — 1 0.7 — — 

United States 

Development — — 1 0.7 8 2.6 

Exploration — — 2 0.7 3 1.0 

Wells Drilled Dry: 

Indonesia 

Exploration — — 2 1.3 — — 

Oman 

Exploration 1 0.8 1 0.8 — — 

Average Depth of Wells (Feet) 

Venezuela (Petrodelta) 

Crude Oil 7,905 — 7,298 — 6,839 — 

Indonesia 

Crude Oil — — 9,874 — — — 

Gabon 

Crude Oil — — 11,355 — — — 

Oman 

Natural Gas 10,482 — 10,348 — — — 

United States 

Crude Oil — — 10,021 — 7,938 — 

Natural Gas — — — — — — 

Producing Wells : 

Venezuela (Petrodelta) 

Crude Oil 152 48.6 143 45.8 127 40.6 

United States 

Crude Oil — — — — 16 8.3 

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

(1) 

(1) 
Table of Contents 

Acreage 

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

December 31, 2012: 

 

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. 

Competition 

We encounter substantial competition from major, national and independent oil and natural gas companies in acquiring properties 

and leases for the exploration and development of crude oil and natural gas. The principal competitive factors in the acquisition of such oil and 

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

acquire and develop such properties, and access to local partners and governmental entities. Many of our competitors have influence, financial 

resources, staffs, data resources and facilities substantially greater than ours. 

Environmental Regulations 

Our operations are subject to various federal, state, local and international laws and regulations governing the discharge of materials 

into the environment or otherwise relating to environmental protection. The cost of compliance could be significant. Failure to comply with 

these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial and damage 

payment obligations, or the issuance of injunctive relief (including orders to cease operations). Environmental laws and regulations are 

complex, and have tended to become more stringent over time. We also are subject to various environmental permit requirements. Some 

environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it 

occurred or conduct or conditions caused by prior operators or third parties. To the extent laws are enacted or other governmental action is 

taken that prohibits or restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and gas 

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

 

15 

 Developed Undeveloped 

 Gross Net Gross Net 

Venezuela – Petrodelta 26,460 8,467 220,653 70,609 

China — — 7,470,080 7,470,080 

Indonesia — — 747,862 481,623 

Gabon — — 685,470 456,982 

Oman — — 955,600 764,480 

 

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

 

 

 

 

 

 

 

 

 • change in governments; 

 • civil unrest; 

 • price and currency controls; 

 • limitations on oil and natural gas production; 

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

 • changes in laws relating to the petroleum industry;

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

 • changes in contract interpretation and policies of contract adherence. 
Table of Contents 

Employees 

At December 31, 2012, full-time employees in our various offices were: Houston – 19; Caracas – 12; London – 9; Singapore – 2; 

Jakarta – 4; and Muscat – 6. We augment our employees from time to time with independent consultants, as required. 

 

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

considered when evaluating us. 

Our financial condition raises substantial doubt as to our ability to continue as a going concern. The audit opinion on our 

financial statements as of and for the year ended December 31, 2012 includes an explanatory paragraph expressing substantial doubt regarding 

our ability to continue as a going concern. Our current capital resources may not be sufficient to support our liquidity requirements through 

2013. Our financial statements have been prepared assuming we will continue to operate as a going concern, which contemplates the realization 

of assets and the satisfaction of liabilities in the normal course of business. If we become unable to continue as a going concern, we may have 

to liquidate our assets and the values we receive for our assets in liquidation or dissolution could be significantly lower than the values reflected 

in our financial statements. Our financial statements do not include any adjustments that might result from the outcome of this uncertainty. 

Our cash position and limited ability to access additional capital may limit our growth opportunities. At April 25, 2013, we 

had $30.7 million (December 31,2012: $72.6 million) of available cash and, until Petrodelta pays a dividend, our available cash may not be 

sufficient to meet capital and operational commitments for the next twelve months. We have no recurring cash flows. Having Petrodelta 

dividends as our primary source of cash flow limits our access to additional capital, and our concentration of political risk in Venezuela may 

limit our ability to leverage our assets. In addition, our future cash position depends upon the payment of dividends by Petrodelta, success with 

our exploration program, possible delay of discretionary capital spending to future periods, farm-out, or possible sale, or otherwise 

monetization of assets as necessary to maintain the liquidity required to run our operations. While we believe that Petrodelta will reinvest any 

excess cash into Petrodelta in 2013 and 2014 which might otherwise be available for payment of dividends, there is no assurance this will be 

the case, nor that if the cash is not reinvested that it will be paid as dividends. These factors could have a material adverse effect on our 

financial condition and liquidity and may limit our ability to grow through the acquisition or exploration of additional oil and gas properties 

and projects. 

Our business strategy may be sensitive to market prices for oil and gas. We have made significant investments to provide the

foundation and global reach required for an organic growth focus. While exploration has become a larger part of our overall portfolio, to the 

extent market values of oil and gas decline, our continued investments in exploration projects may be adversely affected. 

We have incurred long-term indebtedness obligations, which significantly increased our leverage. On October 11, 2012, we 

closed a debt offering of $79.8 million in aggregate principal amount of 11.0 percent senior unsecured notes due October 11, 2014. The degree 

to which we are leveraged could, among other things: 

 

 

 

 

Our ability to meet our debt service obligation will depend upon our future performance, which will be subject to financial, business 

and other factors affecting our operations, many of which are beyond our control. 

Global market and economic conditions, including those related to the credit markets, could have a material adverse effect 

on our business, financial condition and results of operations . A general slowdown in economic activity could adversely affect our 

business by impacting our ability to access additional capital as well as the need to preserve adequate development capital in the interim. 

 

16 

Item 1A. Risk Factors 

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

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

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

 • limit our flexibility in planning for, or reacting to, changes in our business. 
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We may not be able to meet the requirements of the global expansion of our business strategy. We have added a significant 

global exploration component to diversify our overall portfolio. In many locations, we may be required to post performance bonds in support of 

a work program or the work program may include minimum funding requirements to keep the contract. We may not have the funds available to 

meet the minimum funding requirements when they come due and be required to forfeit the contracts. 

Our strategy to identify, access and integrate hydrocarbon assets in known hydrocarbon basins globally carries greater deal 

execution, operating, financial, legal and political risks. The environments in which we operate are often difficult and the ability to operate 

successfully will depend on a number of factors, including our ability to control the pace of development, our ability to apply “best practices” 

in drilling and development, and the fostering of productive and transparent relationships with local partners, the local community and 

governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, often the legal 

systems of these countries are not mature and their reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty 

in our rights to develop and operate oil and natural gas projects, as well as our ability to obtain adequate compensation for any resulting losses. 

Our strategy depends on our ability to have significant influence over operations and financial control. 

We do not directly manage operations of Petrodelta. PDVSA, through CVP, exercises substantial control over Petrodelta’s 

operations, making Petrodelta subject to some internal policies and procedures of PDVSA as well as being subject to constraints in skilled 

personnel available to Petrodelta. These issues may have an adverse effect on the efficiency and effectiveness of Petrodelta’s operations. 

We hold a minority equity investment in Petrodelta. Even though we are able to exercise significant influence as a minority 

equity investor in Petrodelta, our control of Petrodelta is limited to our rights under the Conversion Contract and its annexes and Petrodelta’s 

charter and bylaws. As a result, our ability to implement or influence Petrodelta’s business plan, assure quality control, and set the timing and 

pace of development may be adversely affected. In addition, the majority partner, CVP, has initiated and undertaken numerous unilateral 

decisions that can impact our minority equity investment. 

Petrodelta’s business plan will be sensitive to market prices for oil. Petrodelta operates under a business plan, the success of 

which will rely heavily on the market price of oil. To the extent that market values of oil decline, the business plan of Petrodelta may be 

adversely affected. 

A decline in the market price of crude oil could uniquely affect the financial condition of Petrodelta. Under the terms of the 

Conversion Contract and other governmental documents, Petrodelta is subject to a special advantage tax (“ventajas especiales”) which requires 

that if in any year the aggregate amount of royalties, taxes and certain other contributions is less than 50 percent of the value of the 

hydrocarbons produced, Petrodelta must pay the government of Venezuela the difference. In the event of a significant decline in crude prices, 

the ventajas especiales could force Petrodelta to operate at a loss. Moreover, our ability to control those losses by modifying Petrodelta’s 

business plan or restricting the budget is limited under the Conversion Contract. 

An increase in oil prices could result in increased tax liability in Venezuela affecting Petrodelta’s operations and 

profitability, which in turn could affect our dividends and profitability . Prices for oil fluctuate widely. In April 2011, the Venezuelan 

government published the amended Windfall Profits Tax which establishes a special contribution for extraordinary prices to the Venezuelan 

government of 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $50 

per barrel for 2012 [$55 per barrel for 2013]) and $70 per barrel. The amended Windfall Profits Tax also establishes a special contribution for 

exorbitant prices to the Venezuelan government of (1) 80 percent when the average price of the Venezuelan Export Basket (“VEB”) exceeds 

$70 per barrel but is less than $90 per barrel; (2) 90 percent when the average price of the VEB exceeds $90 per barrel but is less that $100 per 

barrel; and (3) 95 percent when the average price of the VEB exceeds $100 per barrel. Any increase in the taxes payable by Petrodelta, 

including the Windfall Profits Tax, as a result of increased oil prices will reduce cash available for dividends to us and our partner, CVP. 

Oil price declines and volatility could adversely affect Petrodelta’s operations and profitability, which in turn could affect 

our dividends and profitability. Prices for oil also affect the amount of cash flow available for capital expenditures and dividends from 

Petrodelta. Lower prices may also reduce the amount of oil that we can produce economically and lower oil production could affect the amount 

of natural gas we can produce. We cannot predict future oil prices. Factors that can cause fluctuations in oil prices include: 

 

 

17 

 • relatively minor changes in the global supply and demand for oil; 
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The total capital required for development of Petrodelta’s assets may exceed the ability of Petrodelta to finance such 

developments. Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Petrodelta’s future capital 

requirements for the development of its assets may exceed the cash available from existing cash flow. Petrodelta’s ability to secure financing is 

currently limited and uncertain, and has been, and may be, affected by numerous factors beyond its control, including the risks associated with 

operating in Venezuela. Because of this financial risk, Petrodelta may not be able to secure either the equity or debt financing necessary to meet 

its future cash needs for investment, which may limit its ability to fully develop the properties, cause delays with their development or require 

early divestment of all or a portion of those projects. This could negatively impact our minority equity investment. If we are called upon to fund 

our share of Petrodelta’s operations, our failure to do so could be considered a default under the Conversion Contract and cause the forfeiture of 

some or all our shares in Petrodelta. In addition, CVP may be unable or unwilling to fund its share of capital requirements and our ability to 

require them to do so is limited. Since Petrodelta only executed approximately 45.8 percent its 2012 proposed capital expenditures primarily 

due to insufficient monetary support and contractual adherence by PDVSA, it is possible that PDVSA will not provide the support required to 

execute Petrodelta’s proposed 2013 budget. Should PDVSA continue in insufficient monetary support and contractual adherence of Petrodelta, 

underinvestment in the development plan may lead to continued under-performance. 

The legal or fiscal framework for Petrodelta may change and the Venezuelan government may not honor its commitments. 

While we believe that the Conversion Contract and Petrodelta provide a basis for a more durable arrangement in Venezuela, the value of the 

investment necessarily depends upon Venezuela’s maintenance of legal, tax, royalty and contractual stability. Our experiences in Venezuela 

demonstrate that such stability cannot be assured. While we have and will continue to take measures to mitigate our risks, no assurance can be 

provided that we will be successful in doing so or that events beyond our control will not adversely affect the value of our minority equity 

investment in Petrodelta. 

PDVSA’s failure to timely pay contractors could have an adverse effect on Petrodelta. PDVSA has failed to pay on a timely 

basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA purchases all of Petrodelta’s oil 

production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital 

expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to 

provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments 

Petrodelta would otherwise use to pay its contractors, including Harvest Vinccler. As a result, Petrodelta is continuing to experience difficulty 

in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will 

become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is continuing to have an adverse 

effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan. 

Estimates of oil and natural gas reserves are uncertain and inherently imprecise . This Annual Report on Form 10-K contains 

estimates of our oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC 

relating to oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. 

The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation 

of available geological, geophysical, engineering and economic data for each 

 

18 

 • export quotas; 

 • market uncertainty; 

 • the level of consumer product demand; 

 • weather conditions; 

 • domestic and foreign governmental regulations and policies; 

 • the price and availability of alternative fuels; 

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

 • overall economic conditions. 
Table of Contents 

reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development 

expenditures, operating expenses and quantities of recoverable oil and natural gas reserves likely will vary from those estimated. Any 

significant variance could materially affect the estimated quantities and present value of reserves set forth. Actual production, revenue, taxes, 

development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used, and these variances 

may be material. 

You should not assume that the present value of future net revenues referred to in Item 15. Additional Supplemental Information on 

Oil and Natural Gas Producing Activities (unaudited) for Petrodelta S.A., TABLE V – Standardized Measure of Discounted Future Net Cash 

Flows Related to Proved Oil and Natural Gas Reserve Quantities is the current market value of our estimated oil and natural gas reserves. In 

accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on the unweighted 

average price of the first day of the month during the 12-month period before the ending date of the period covered by the reserve report and 

costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of 

the estimate. Any changes in demand, changes in our ability to produce or changes in governmental regulations, policies or taxation will also 

affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and natural 

gas properties will affect the timing of actual future net cash flows from estimated proved reserves and their present value. In addition, the 10 

percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not 

necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with the oil and natural gas 

industry in general will affect the accuracy of the 10 percent discount factor. 

We may not be able to replace production with new reserves . In general, production rates and remaining reserves from oil and 

natural gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. Our future oil and natural gas 

production is highly dependent upon our level of success in finding or acquiring additional reserves. The business of exploring for, developing 

or acquiring reserves is capital intensive and uncertain. We may be unable to make the necessary capital investment to maintain or expand our 

oil and natural gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot 

give any assurance that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be 

able to drill productive wells at acceptable costs. 

Our future operations and our investments in equity affiliates are subject to numerous risks of oil and natural gas drilling 

and production activities. Oil and natural gas exploration and development drilling and production activities are subject to numerous risks, 

including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is often 

uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many 

of which are beyond our control. These factors include: 

 

 

 

 

 

 

 

 

 

 

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. 

 

19 

 • shortages or delays in the delivery of equipment; 

 • shortages in experienced labor; 

 • pressure or irregularities in formations; 

 • unexpected drilling conditions; 

 • equipment or facilities failures or accidents; 

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

 • government actions or changes in regulations; 

 • delays in receiving necessary governmental permits;

 • delays in receiving partner approvals; and 

 • weather conditions. 
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We operate in many different jurisdictions and we could be adversely affected by violations of the U.S. Foreign Corrupt 

Practices Act and similar worldwide anti-corruption laws. The U.S. Foreign Corrupt Practices Act (“FCPA”) and similar worldwide anticorruption laws, including the U.K. Bribery Act 2010, which is broader in scope than the FCPA, generally prohibit companies and their 

intermediaries from making improper payments to government and other officials for the purpose of obtaining or retaining business. Our 

internal policies mandate compliance with these anti-corruption laws. Despite our training and compliance programs, we cannot be assured that 

our internal control policies and procedures will always protect us from acts of corruption committed by our employees or agents. Our 

continued expansion outside the U.S., including in developing countries, could increase the risk of such violations in the future. Violations of 

these laws, or allegations of such violations, could disrupt our business and result in a material adverse effect on our financial condition, results 

of operations and cash flows. 

Operations in areas outside the United States are subject to various risks inherent in foreign operations. Our operations are 

subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as 

a result of hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and 

governmental royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts or tribunals, renegotiation 

of contracts with governmental entities, changes in laws and policies, including taxes, governing operations of foreign-based companies, 

currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over our international 

operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign policy, 

foreign trade, taxation and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States. 

Our oil and natural gas operations are subject to various governmental regulations that materially affect our operations . 

Our oil and natural gas operations are subject to various governmental regulations. These regulations may be changed in response to economic 

or political conditions. Matters regulated may include permits for discharges of wastewaters and other substances generated in connection with 

drilling operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment 

costs, reports concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. At various times, regulatory 

agencies have imposed price controls and limitations on oil and natural gas production. In order to conserve or limit supplies of oil and natural 

gas, these agencies have restricted the rates of the flow of oil and natural gas wells below actual production capacity. We cannot predict the 

ultimate cost of compliance with these requirements or their effect on our operations. 

We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Exploration and development 

and the production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required 

to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include: 

 

 

 

 

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: 

 

 

20 

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

 • response to unexpected releases to the environment;

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

 • taxation. 

 • fires and explosions; 
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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 

 

21 

 • blow-outs; 

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

 • adverse weather conditions or natural disasters; 

 • pipe or cement failures and casing collapses; 

 • pipeline ruptures; 

 • discharges of toxic gases; 

 • build up of naturally occurring radioactive materials; and 

 • vandalism. 

 • injury or loss of life; 

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

 • pollution and other environmental damage; 

 • investigatory and clean-up responsibilities; 

 • regulatory investigation and penalties; 

 • suspension of our operations; and 

 • repairs to resume operations. 
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processes and information systems need to be sufficiently scalable to support the future growth of our business and may require modifications 

or upgrades that expose us to a number of operational risks. Our information technology systems, and those of third party providers, may also 

be vulnerable to damage or disruption caused by circumstances beyond our control. These include catastrophic events, power anomalies or 

outages, natural disasters, computer system or network failures, viruses or malware, physical or electronic break-ins, unauthorized access and 

cyber attacks. Any material disruption, malfunction or similar challenges with our business processes or information systems, or disruptions or 

challenges relating to the transition to new processes, systems or providers, could have a material adverse effect on our financial condition, 

results of operations and cash flows. 

We have identified material weaknesses in our internal control over financial reporting. We have concluded we did not 

maintain effective internal controls over financial reporting because material weaknesses in internal control over financial reporting related to 

(1) a sufficient complement of accounting and financial reporting resources; (2). accounting for certain transactions for oil and gas properties; 

(3) accounting for income taxes; (4) appropriate segregation of duties related to certain system access rights and the recording and review of 

journal entries; (5) preparation and review of certain classification and disclosure matters impacting the financial statements and related notes; 

and (6) significant and complex debt and equity transactions existed as of December 31, 2012. A material weakness is a deficiency, or 

combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement 

in our annual or interim financial statements will not be prevented or detected and corrected on a timely basis. 

Although we intend to take appropriate steps to remediate these material weaknesses, we cannot assure you that we will be able to 

do so in a timely manner, that our initiatives will prove to be successful or that additional material weaknesses will not be identified in the 

future. Failure to identify material weaknesses in our internal controls in a timely manner, or the identification of material weaknesses in the 

future, will impair our ability to record, process, summarize and report financial information accurately, timely and in accordance with SEC 

rules. The failure could also cause investors to lose confidence in our reported financial information, subject us to litigation and regulatory 

enforcement actions, and adversely impact our business and financial condition. 

 

None. 

 

We have regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Indonesia; Port Gentil, 

Gabon; and Muscat, Oman to support field operations in those areas. At December 31, 2012, we had the following lease commitments for 

office space: 

 

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

 

The following related class action lawsuits were filed on the dates specified in the United States District Court, Southern District of 

Texas: John Phillips v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (March 22, 2013); Sang Kim v. Harvest 

Natural Resources, Inc., James A. Edmiston, Stephen C. Haynes, Stephen D. Chesebro’, Igor Effimoff, H. H. Hardee, Robert E. Irelan, Patrick 

M. Murray and J. Michael Stinson (April 3, 2013); Chris Kean v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes 

(April 11, 2013); Prastitis v. Harvest Natural Resources, Inc. , James A. Edmiston and Stephen C. Haynes (April 17, 2013); Alan Myers v. 

Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 22, 2013); and Edward W. Walbridge and the Edward W. 

Walbridge Trust v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 26, 2013). The complaints allege that 

the Company made certain false or misleading public statements and demand that the defendants pay unspecified damages to the class action 

plaintiffs based on stock price declines. On April 18, 2013, the second, third and fourth listed actions were consolidated into the Phillips 

case. The Company and the other named defendants intend to vigorously defend the consolidated and other listed lawsuits. 

On March 25, 2013, the Securities and Exchange Commission, notified the Company that it is conducting an inquiry related to 

certain matters disclosed in the Company’s Form 12B-25 announcing that it would be unable to file on a timely basis its 2012 Annual Report 

on Form 10-K, including certain errors in the Company’s financial statements and weaknesses in the Company’s internal controls. The 

Company is engaged in discussions with the Commission concerning these matters. 

Item 1B. Unresolved Staff Comments 

Item 2. Properties 

Location 

Date 

Lease Signed Term 

Annual 

Expense 

Houston, Texas April 2004 10 years $ 204,000 

Houston, Texas December 2008 5 years 160,800 

Caracas, Venezuela October 2012 1 year 224,400 

London, U.K. September 2010 5 years 108,000 

Singapore October 2012 2 years 84,000 

Jakarta, Indonesia April 2012 2 years 98,500 

Muscat, Oman September 2011 2 years 62,400 

Gabon, Port Gentil December 2012 2 years 61,200 

Item 3. Legal Proceedings 
In June 2012, the operator of the Budong PSC received notice of a claim related to the ownership of part of the land comprising the 

Karama-1 (“KD-1”) drilling site. The claim asserts that the land on which the drill site is located is partly owned by the claimant. The operator 

purchased the site from local landowners in January 2010, and the purchase was approved by BPMIGAS, Indonesia’s oil and gas regulatory 

authority. The claimant is seeking compensation of 16 billion Indonesia Rupiah (approximately $1.7 million, $1.2 million net to our 71.61 

percent cost sharing interest) for land that was purchased at a cost of $4,100 in January 2010. On or about March 8, 2013, the operator learned 

that the court has ruled to dismiss the claim because the claim had not been filed against the proper parties to the claim. The claimant can 

appeal the dismissal once the ruling has been issued in writing. 

In May 2012, Newfield Production Company (“Newfield”) filed notice pursuant to the Purchase and Sale Agreement between 

Harvest (US) Holdings, Inc. (“Harvest US”), a wholly owned subsidiary of Harvest, and Newfield dated March 21, 2011 (the “PSA”) of a 

potential environmental claim involving certain wells drilled on the Antelope Project. The claim asserts that locations constructed by Harvest 

US were built on, within, or otherwise impact or potentially impact wetlands and other water bodies. The notice asserts that to the extent of 

potential penalties or other obligations that might result from potential violations that Harvest US indemnifies Newfield pursuant to the PSA. In 

June 2012, we provided Newfield with notice pursuant to the PSA (1) denying that Newfield has any right to indemnification from us, 

(2) alleging that any potential environmental claim related to Newfield’s notice would be an assumed liability under the PSA and (3) asserting 

that Newfield indemnify us pursuant to the PSA. We dispute Newfield’s claims and plan to vigorously defend against them. We are unable to 

estimate the amount or range of any possible loss. 

 

22 
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On May 31, 2011, the United Kingdom branch of our subsidiary, Harvest Natural Resources, Inc. (UK), initiated a wire transfer of 

approximately $1.1 million ($0.7 million net to our 66.667 percent interest) intending to pay Libya Oil Gabon S.A. (“LOGSA”) for fuel that 

LOGSA supplied to our subsidiary in the Netherlands, Harvest Dussafu, B.V., for the company’s drilling operations in Gabon. On June 1, 

2011, our bank notified us that it had been required to block the payment in accordance with the U.S. sanctions against Libya as set forth in 

Executive Order 13566 of February 25, 2011, and administered by OFAC, because the payee, LOGSA, may be a blocked party under the 

sanctions. The bank further advised us that it could not release the funds to the payee or return the funds to us unless we obtain authorization 

from OFAC. On October 26, 2011, we filed an application with OFAC for return of the blocked funds to us. Until that application is approved, 

the funds will remain in the blocked account, and we can give no assurance when OFAC will permit the funds to be released. As of May 2, 

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

Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc., Branta Exploration & Production, LLC, Ute 

Energy LLC, Cameron Cuch, Paula Black, Johnna Blackhair, and Elton Blackhair in the United States District Court for the District of 

Utah . This suit was served in April 2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the defendants, among other 

things, intentionally interfered with Plaintiffs’ employment agreement with the Ute Indian Tribe – Energy & Minerals Department and 

intentionally interfered with Plaintiffs’ prospective economic relationships. Plaintiffs seek actual damages, punitive damages, costs and 

attorney’s fees. We dispute Plaintiffs’ claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any 

possible loss. 

Uracoa Municipality Tax Assessments . Our Venezuelan subsidiary, Harvest Vinccler, has received nine assessments from a tax 

inspector for the Uracoa municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows: 

 

 

 

 

Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is unable to 

estimate the amount or range of any possible loss. As a result of the SENIAT’s, the Venezuelan income tax authority, interpretation of the tax 

code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa 

Municipality for the refund of all municipal taxes paid since 1997. 

Libertador Municipality Tax Assessments . Harvest Vinccler has received five assessments from a tax inspector for the Libertador 

municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows: 

 

 

23 

 

• Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes 

on the capital fee reimbursement and related interest paid by PDVSA under the Operating Service Agreement (“OSA”). 

Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and 

has protested with the municipality the remaining claims. 

 

• Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler 

has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims. 

 

• Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 

and a withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in 

Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim. 

 

• Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters 

of 2006. Harvest Vinccler has filed a protest with the municipality on these claims. 

 

• One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has 

filed a protest with the Mayor’s Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the 

claim. On April 10, 2008, the Tax Court suspended the case pending a response from the Mayor’s Office to the protest. If the 

municipality’s response is to confirm the assessment, Harvest Vinccler will defer to the competent Tax Court to enjoin and 

dismiss the claim. 
Table of Contents 

 

Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest 

Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies 

to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the 

refund of all municipal taxes paid since 2002. 

On May 4, 2012, Harvest Vinccler learned that the Political Administrative Chamber of the Supreme Court of Justice has issued a 

decision dismissing one of Harvest Vinccler’s claims against the Libertador Municipality. Harvest Vinccler continues to believe that it has 

sufficient arguments to maintain its position in accordance with the Venezuelan Constitution. Harvest Vinccler plans to present a request of 

Constitutional Revision to the Constitutional Chamber of the Supreme Court of Justice once it is notified officially of the decision. As of May 

2, 2013, Harvest Vinccler has not received official notification of the decision. Harvest Vinccler is unable to predict the impact of this decision 

on the remaining outstanding municipality claims and assessments. 

We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no 

such litigation which will have a material adverse impact on our financial condition, results of operations and cash flows. 

 

Not applicable. 

 

24 

 

• Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest 

paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and 

fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and 

dismiss both claims. 

 

• Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest 

Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims. 

Item 4. Mine Safety Disclosures 
Table of Contents 

PART II 

 

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY 

Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HNR”. As of December 31, 2012, 

there were 39,434,279 shares of common stock outstanding, with approximately 433 stockholders of record. The following table sets forth the 

high and low sales prices for our Common Stock reported by the NYSE. 

 

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

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

cash dividend on our common stock. 

STOCK PERFORMANCE GRAPH 

The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2012, assuming an 

investment of $100 on December 31, 2007 in each of Harvest’s common stock, the Dow Jones U.S. Exploration & Production Index and the 

S&P Composite 500 Stock Index. 

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

dividends were reinvested. 

 

25 

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

Year Quarter High Low 

2011 First quarter 16.75 10.59 

 Second quarter 15.71 10.51 

 Third quarter 13.81 8.57 

 Fourth quarter 12.04 6.58 

2012 First quarter 8.27 6.14 

 Second quarter 9.12 4.88 

 Third quarter 9.85 7.72 

 Fourth quarter 9.50 8.38 
Table of Contents 

 

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 Exploration & Production Index is accessible at http://www.djindexes.com/mdsidx/index.cfm?event=showTotalMarket . 

 

26 

 2007 2008 2009 2010 2011 2012 

Harvest Natural Resources, Inc. $ 100 $ 34 $ 42 $ 97 $ 59 $ 73 

Dow Jones US E&P Index $ 100 $ 58 $ 82 $ 98 $ 96 $ 100 

S&P 500 Index $ 100 $ 63 $ 80 $ 92 $ 94 $ 109 
Table of Contents 

SELECTED CONSOLIDATED FINANCIAL DATA 

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

December 31, 2012. 

 

 

 

 

Operations 

We had a net loss attributable to Harvest of $12.2 million, or $(0.33) per diluted share, for the year ended December 31, 2012 

compared to net income attributable to Harvest of $56.0 million, or $1.64 per diluted share, for the year ended December 31, 2011. Net loss 

attributable to Harvest for the year ended December 31, 2012 includes $9.1 million of exploration expense, $9.3 of impairment expense, $5.6 

million of dry hole costs and net equity income from Petrodelta’s operations of $67.8 million. Net income attributable to Harvest for the year 

ended December 31, 2011 includes $12.6 million of exploration expense, $3.3 million of impairment expense, $49.7 million of dry hole costs 

and net equity income from Petrodelta’s operations of $73.5 million. 

Restatement of Prior Period Financial Statements 

 In connection with the preparation of our Annual Report on Form 10-K for the year ended December 31, 2012, we concluded that 

there were errors in previously filed financial statements. In the course of our review, management determined that (a) certain warrants issued 

in 2010 in connection with our $60 million term loan facility (the “Warrants”) were improperly valued at inception and improperly classified as 

equity instruments rather than liability instruments. As a result of the improper classification of the Warrants, (b) the debt discount and 

associated interest expense related to the amortization of the debt discount was understated for all periods in which the associated debt was 

outstanding, and (c) the consolidated statement of operations and comprehensive income (loss) for each reporting period was misstated by the 

omission of the changes in fair value of the Warrants as a liability instrument. Additionally, (d) certain exploration overhead was incorrectly 

capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed, and (e) certain 

leasehold maintenance and other costs were improperly capitalized to oil and gas properties, which under the successful efforts method of 

accounting should have been expensed. Finally, (f) advances to equity affiliate were improperly classified as an operating activity rather than 

an investing activity and (g) certain costs were improperly classified as an investing activity rather than an operating activity on the 

Item 6. Selected Financial Data 

 Year Ended December 31, 

 2012 

2011 

(RESTATED) 

2010 

(RESTATED) 

2009 

(RESTATED) 

2008 

(RESTATED) 

 (in thousands, except per share data) 

Consolidated Statements of Operations and Comprehensive Income 

(Loss): 

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

Net income from Equity Affiliates 67,769 73,451 66,291 35,253 33,226 

Net income (loss) from continuing operations (10,512 ) (41,656 ) 10,663 (3,326 ) (22,883 ) 

Net income (loss) attributable to Harvest (12,211 ) 55,960 14,375 (3,568 ) (23,179 ) 

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

common share: 

Basic $ (0.28 ) $ (1.22 ) $ 0.32 $ (0.10 ) $ (0.68 ) 

 

 

 

 

 

 

 

 

 

 

Diluted $ (0.28 ) $ (1.22 ) $ 0.29 $ (0.10 ) $ (0.68 ) 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding 

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

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

 As of December 31, 

 2012 

2011 

(RESTATED) 

2010 

(RESTATED) 

2009 

(RESTATED) 

2008 

(RESTATED) 

 (in thousands) 

Balance Sheet Data: 

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

Long-term debt, net of current maturities 74,839 31,535 78,291 — — 

Total Harvest’s Stockholders’ equity 379,337 355,691 291,727 271,603 270,713 

 Includes net income attributable to noncontrolling interest. 

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

For 2009, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties 

rather than expensed as exploration expense of $58 thousand. For 2008, relates to lease maintenance costs that were erroneously 

capitalized as oil and gas properties rather than as exploration expense of $635 thousand. 

 Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense of $693 thousand in 2009 and $635 thousand in 2008. 

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

(3) (3) 

(1) 

(1) 

(1) 

(4) (4) 

(2) 

(1) 

(2) 

(3) 

(4) 
consolidated statement of cash flows. Such errors impacted annual periods ended December 31, 2010 and 2011 and quarterly periods ended 

March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012, and September 30, 2012. 

As a result of the errors related to the Warrants described above, loss on extinguishment of debt was understated for the year ended 

December 31, 2011 and the quarters ended June 30, 2011, September 30, 2011 and December 31, 2011. 

Additionally, an error was identified in the calculation of earnings (loss) per diluted share for the year ended December 31, 2011 

and the three and six months ended June 30, 2011, and an additional error was identified related to the improper expensing of costs associated 

with debt conversions that should have been recorded to equity for the quarters ended March 31, 2012 and September 30, 2012. 

We have restated our segment footnote information to reflect the applicable errors stated above and (a) reclassify noncontrolling 

interest from United States segment to Venezuela segment, (b) eliminate intrasegment receivables erroneously reported gross of related 

intrasegment payable, and (c) eliminate intrasegment revenue erroneously reported gross of related intrasegment expense. Such errors impacted 

annual periods ended December 31, 2010 and 2011 and quarterly periods ended March 31, 2011, June 30, 2011, September 30, 2011, 

December 31, 2011, March 31, 2012, June 30, 2012 and September 30, 2012. We also restated our financial statement schedule to reflect 

adjustments to the balance sheet related to income taxes for the years ended December 31, 2010 and 2011. 

In assessing the severity of the errors, management determined that the errors were material to the consolidated financial statements 

for the years ended December 31, 2011 and 2010 and quarterly information for all quarters in 2011 and the first, second and third quarters of 

2012. In addition to the errors described above, we made corrections for previously identified immaterial errors and errors affecting 

classification within the consolidated statement of operations and comprehensive income (loss) related to impairment of oil and gas properties 

and income taxes and the consolidated balance sheets related to income taxes. 

The audited financial statements, related notes and analyses for the years ended December 31, 2011 and 2010 have been 

retrospectively restated in this Annual Report on Form 10-K for the year ended December 31, 2012. We will amend our Quarterly Reports on 

Form 10-Q/A for each of the quarterly periods shortly after the filing of this Annual Report on Form 10-K. 

The following tables set forth the effect of the adjustments described above on the consolidated statements of operations and 

comprehensive income (loss), the consolidated statements of cash flows and the consolidated statements of stockholders’ equity for the years 

ended December 31, 2011 and 2010, and the consolidated balance sheet as of December 31, 2011. 

 

27 
Table of Contents 

Consolidated Statements of Operations and Comprehensive Income (Loss) 

 

 

 December 31, 2011 December 31, 2010 

 As Previously As As Previously As 

 Reported Adjustment RESTATED Reported Adjustment RESTATED 

 (in thousands) 

Expenses 

Depreciation and amortization $ 462 $ — $ 462 $ 484 $ — $ 484 

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

Impairment of oil and gas properties — 3,335 3,335 — — — 

Dry hole costs 49,676 — 49,676 — — — 

General and administrative 22,474 — 22,474 25,903 — 25,903 

 

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

 

Loss from operations (86,302 ) (2,210 ) (88,512 ) (34,403 ) (313 ) (34,716 ) 

Other non-operating income (expense) 

Investment earnings and other 665 — 665 557 — 557 

Unrealized gain (loss) on warrant derivatives — 9,786 9,786 — 344 344 

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

Loss on extinguishment of debt (9,682 ) (3,450 ) (13,132 ) — — — 

Other non-operating expense (1,375 ) — (1,375 ) (3,952 ) — (3,952 ) 

Loss on exchange rates (146 ) — (146 ) (1,588 ) — (1,588 ) 

 

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

 

Loss from Continuing Operations Before Income 

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

Income tax expense (benefit) 820 237 1,057 (184 ) — (184 ) 

 

Loss from Continuing Operations (102,996 ) 2,066 (100,930 ) (41,891 ) (1,067 ) (42,958 ) 

Net Income from Equity Affiliate 73,451 — 73,451 66,291 — 66,291 

 

Net Income (Loss) from Continuing Operations (29,545 ) 2,066 (27,479 ) 24,400 (1,067 ) 23,333 

Income (Loss) from Discontinued Operations 97,616 — 97,616 3,712 — 3,712 

 

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

Less: Net Income Attributable to Noncontrolling 

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

 

Net Income (Loss) Attributable To Harvest $ 53,894 $ 2,066 $ 55,960 $ 15,442 $ (1,067 ) $ 14,375 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Attributable to Harvest Per 

Common Share: 

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

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss) $ 53,894 $ 2,066 $ 55,960 $ 15,442 $ (1,067 ) $ 14,375 

 

 

 

 

 

 

 

 

 

 

 

 

(a) For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties 

rather than expensed as exploration expense of $2,210 thousand offset by a reclassification from exploration expense to impairment of oil 

and gas properties of $3,335 thousand for amounts that were erroneously classified as exploration expense. For 2010, relates to lease 

maintenance costs that were erroneously capitalized as oil and gas properties rather than as exploration expense. 

(b) Represents change in fair value of the Warrants for the period. Such Warrants were previously erroneously classified as equity and were, 

therefore, not marked to market at the end of each reporting period. 

(c) The fair value of the Warrants was not appropriately determined at inception because certain features of the Warrants were not originally 

considered in the fair value calculation. The corrected fair value of the Warrants at inception exceeds the original valuation by $3,878 

thousand. As a result of this change in the fair value of the Warrants, the original discount allocated to the debt was understated by 

approximately $3,878 thousand; therefore, the additional amortization of the discount on debt, which is a component of interest expense, 

was understated for each period the debt was outstanding. For 2011, income tax expense of $237 thousand was improperly classified as 

interest expense. 

(d) As noted in (c) above, the correction in the fair value of the Warrants and its classification as a liability resulted in an increased discount 

on debt which also impacted the resulting loss on extinguishment of debt originally recorded in May 2011 when the debt was retired. 

(e) In addition to the impact on EPS related to the adjustments described in (a) through (d) above and (f) and (g) below, diluted EPS has been 

adjusted to reflect an error in the calculation of the weighted average common shares outstanding for dilutive EPS as of December 31, 

2011. The weighted average common shares utilized for the calculation of diluted EPS was erroneously 39,339 thousand rather than 

34,117 thousand. 

(f) Reclassification of impairment of oil and gas properties expense in 2011 of $3,335 thousand that was previously erroneously presented as 

exploration expense. 

(g) Represents income tax improperly classified as interest expense. 

(a) 

(f) 

(b) 

(c) 

(d) 

(g) 

(e) 
Consolidated Balance Sheets 

 

 

 

28 

 December 31, 2011 

 

As 

Previously 

Reported Adjustment 

As 

RESTATED 

 (in thousands) 

Deferred income taxes $ 2,628 $ (2,628 ) $ — 

Oil and gas properties 65,671 (3,216 ) 62,455 

Total assets 513,047 (5,844 ) 507,203 

Accrued interest payable 1,372 (396 ) 976 

Other current liabilities 4,835 (2,203 ) 2,632 

Income taxes payable 718 (29 ) 689 

Warrant derivative liability — 4,870 4,870 

Total liabilities 65,592 2,242 67,834 

Additional paid in capital 236,192 (8,392 ) 227,800 

Retained earnings 193,283 306 193,589 

Total Harvest shareholders’ equity 363,777 (8,086 ) 355,691 

Total equity 447,455 (8,086 ) 439,369 

(a) Relates to a deferred tax asset that was erroneously reported gross of the related liability. 

(b) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. 

(c) Relates to the reclassification of the Warrants out of additional paid in capital to warrant derivative liabilities. The fair value of the 

Warrants was not appropriately determined at inception because certain features of the Warrants were not originally considered in the fair 

value calculation. Thus, the correction of the error to record the Warrants as a liability does not agree to the correction of the error 

removing the Warrants from equity. Additionally, the Warrants were not properly marked to market at the end of each period. The 

warrant derivative liability was valued at $15,000 thousand at inception with subsequent reductions in fair value of $344 thousand in 

2010 and $9,786 thousand in 2011. 

(d) Relates to the reversal of the amount recorded to equity at inception for the Warrants of $11,122 thousand and the reversal of the amount 

removed from additional paid in capital of $2,730 thousand when a portion of the Warrants were redeemed by the Company. In May 

2011, additional paid in capital was debited for $2,730 thousand for the reversal of the original fair value of such warrants which was an 

error as they did not qualify for equity classification. 

(e) Relates to (a) net increase in expense in 2010 and 2011 related to exploration expense of $2,523 thousand (inclusive of the 

reclassification of exploration expense to impairment of oil and gas properties of $3,335 thousand), (b) net increase in unrealized gain on 

warrant derivatives of $10,130 thousand for cumulative 2010 and 2011, (c) net increase in interest expense of $2,921 thousand 

cumulative for 2010 and 2011, (d) net increase in loss on extinguishment of debt of $3,450 thousand for 2011 (e) net increase in income 

tax expense of $237 thousand for income taxes improperly classified as interest expense, offset by a reduction to retained earnings of 

$693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than 

expensed prior to January 1, 2010. 

(f) Relates to reclassification of the Warrants as described in (d) above plus the impact of retained earnings described in (e) above. 

(g) Represents other current liabilities that were improperly classified as interest payable and income taxes payable. 

(a) 

(b) 

(a)(b) 

(g) 

(a)(g) 

(g) 

(c) 

(a)(c)(g) 

(d) 

(e) 

(f) 

(f) 
Table of Contents 

Consolidated Statements of Cash Flows 

 

 

In addition to the above, we have restated the Consolidated Statements of Stockholder’s Equity to reflect the reclassification of the 

Warrants from equity to warrant derivative liability and to restate the January 1, 2010 beginning balances to reflect cumulative adjustments 

related to the previously described errors that affect periods prior to the year ended December 31, 2010 as follows: 

 

 

 

 

 

 

 December 31, 2011 December 31, 2010 

 As Previously As As Previously As 

 Reported Adjustment RESTATED Reported Adjustment RESTATED 

 (in thousands) 

Net cash used in operating activities $ (52,737 ) $ (2,506 ) $ (55,243 ) $ (5,296 ) $ (2,830 ) $ (8,126 ) 

Net cash provided by (used in) investing activities

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

Net cash provided by (used in) financing activities (56,730 ) — (56,730 ) 90,743 — 90,743 

 

Net increase in cash and cash equivalents 243 — 243 26,386 — 26,386 

Cash and cash equivalents at beginning of year 58,703 — 58,703 32,317 — 32,317 

 

Cash and cash equivalents at end of year $ 58,946 $ — $ 58,946 $ 58,703 $ — $ 58,703 

 

 

 

 

 

 

 

 

 

 

 

 

(a) For 2011, relates to the $2,288 thousand of lease maintenance costs, exploration overhead and $900 thousand of certain investment costs 

that were improperly classified as an investing activity rather than an operating activity. In addition, Advances to Equity Affiliates of 

$(682) thousand were previously erroneously classified as an operating activity rather than an investing activity. 

(b) For 2010, relates to $167 thousand of lease maintenance costs and $(558) thousand of certain investment costs that were improperly 

classified as an investing activity rather than an operating activity. In addition, Advances to Equity Affiliates of $3,221 thousand were 

improperly classified as an operating activity rather than an investing activity. 

 

Common 

Shares 

Issued 

Common 

Stock 

Additional 

Paid-in 

Capital 

Retained 

Earnings 

Treasury 

Stock 

NonControlling 

Interest 

Total 

Equity 

Balance at January 1, 2010 as originally reported 39,495 $ 395 $ 213,337 $ 123,947 $ (65,383 ) $ 56,831 $ 329,127 

Adjustments — — — (693 ) — — (693 ) 

 

Balance at January 1, 2010 as RESTATED 39,495 $ 395 $ 213,337 $ 123,254 $ (65,383 ) $ 56,831 $ 328,434 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Relates to lease maintenance costs that were erroneously capitalized as oil and gas properties rather than expensed prior to January 1, 

2010 (the “Beginning Retained Earnings Adjustment”). 

 

Common 

Shares 

Issued 

Common 

Stock 

Additional 

Paid-in 

Capital 

Retained 

Earnings 

Treasury 

Stock 

NonControlling 

Interest 

Total 

Equity 

Balance at December 31, 2010 as originally reported 40,103 $ 401 $ 230,362 $ 139,389 $ (65,543 ) $ 69,501 $ 374,110 

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

 

Balance at December 31, 2010 as RESTATED 40,103 $ 401 $ 219,240 $ 137,629 $ (65,543 ) $ 69,501 $ 361,228 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) The adjustment to additional paid-in capital relates to the reclassification of the Warrants from equity to warrant derivative liability. 

(b) The adjustment to retained earnings relates to (a) lease maintenance costs of $313 thousand that were erroneously capitalized as oil and 

gas properties rather than expensed as exploration expense, (b) the reduction in the fair value of the Warrants for the year ended 

December 31, 2010 of $344 thousand, additional amortization of debt of $1,098 thousand resulting from the increased discount allocated 

to the debt, offset by a reduction to retained earnings of $693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance 

costs that were improperly capitalized to oil and gas properties rather than expensed to exploration expenses prior to January 1, 2010. 

 

Common 

Shares 

Issued 

Common 

Stock 

Additional 

Paid-in 

Capital 

Retained 

Earnings 

Treasury 

Stock 

NonControlling 

Interest 

Total 

Equity 

Balance at December 31, 2011 as originally reported 40,625 $ 406 $ 236,192 $ 193,283 $ (66,104 ) $ 83,678 $ 447,455 

Adjustments — — (8,392 ) 306 — — (8,086 ) 

 

Balance at December 31, 2011 as RESTATED 40,625 $ 406 $ 227,800 $ 193,589 $ (66,104 ) $ 83,678 $ 439,369 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) The adjustment to additional paid-in capital relates to the reclassification of the Warrants from equity to warrant derivative liability of 

$11,122 thousand offset by an error recorded in 2011 for $2,730 thousand for the reversal of the original fair value of certain Warrants 

that did not qualify for equity classification. 

(b) The adjustment to retained earnings relates to (a) net increase in 2010 and 2011 expense related to exploration expense of $2,523 

thousand that was erroneously capitalized as oil and gas properties rather than expensed as exploration expense (includes consideration of 

reclassification between exploration expense and impairment of oil and gas properties), (b) net increase in unrealized gain on warrant 

derivatives of $10,130 thousand for cumulative 2010 and 2011, (c) net increase in interest expense of $2,921 thousand cumulative for 

(a)(b) 

(a) 

(b) 

(a) 

(a)(b) 

(a)(b) 
In addition to the above, we have restated Operating Segments to reflect the errors stated above and (a) reclassify noncontrolling 

interest from United States segment to Venezuela segment, (b) eliminate intrasegment receivables erroneously reported gross of related 

intrasegment payable, and (c) eliminate intrasegment revenue erroneously reported gross of related intrasegment expense. 

 

 

 

 

Venezuela 

Harvest Vinccler’s and Petrodelta’s functional and reporting currency is the U.S. Dollar. They do not have currency exchange risk 

other than the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”) (4.30 

Bolivars per U.S. Dollar). However, during the year ended December 31, 2012, Harvest Vinccler exchanged approximately $1.5 million (2011: 

$1.2 million) through the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) and received an average exchange rate of 

5.16 Bolivars (2011: 5.19 Bolivars) per U.S. Dollar. Harvest Vinccler currently does not have any Bolivars pending government approval for 

settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. Petrodelta does not have, and has not had, any Bolivars 

pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. 

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

monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals 

 

29 

2010 and 2011, (d) net increase in loss on extinguishment of debt of $3,450 thousand for 2011, (e) net increase in income tax expense of 

$237 thousand for income taxes improperly classified as interest expense, offset by a reduction to retained earnings of $693 thousand 

prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than expensed prior to 

January 1, 2010. 

 December 31, 2011 December 31, 2010 

 

As Previously 

Reported Adjustments 

As 

Restated 

As Previously 

Reported Adjustments 

As 

Restated 

Segment Income (Loss) Attributable to Harvest 

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

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

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

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

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

 

Net income (loss) from continuing operations (43,722 ) 2,066 (41,656 ) 11,730 (1,067 ) 10,663 

Discontinued operations (Antelope Project) 97,616 — 97,616 3,712 — 3,712 

 

Net income (loss) attributable to Harvest $ 53,894 $ 2,066 $ 55,960 $ 15,442 $ (1,067 ) $ 14,375 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Relates to reclassification of noncontrolling interest from United States segment to Venezuela segment and elimination of intrasegment 

revenue erroneously reported gross of intrasegment expense. 

(b) For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties 

rather than expensed as exploration expense of $1,505 thousand and elimination of intrasegment revenue erroneously reported gross of 

related intrasegment expense of $1,383 thousand. For 2010, relates to elimination of intrasegment revenue erroneously reported gross of 

related intrasegment expense. 

(c) For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties 

rather than expensed as exploration expense of $415 thousand and elimination of intrasegment revenue erroneously reported gross of 

related intrasegment expense of $1,830 thousand. For 2010, relates to lease maintenance costs and exploration overhead costs that were 

erroneously capitalized as oil and gas properties rather than expensed as exploration expense of $313 thousand and elimination of 

intrasegment revenue erroneously reported gross of related intrasegment expense of $786 thousand. 

(d) Relates to elimination of intrasegment revenue erroneously reported gross of related intrasegment expense. 

(e) Relates to the impact of (a) through (d) above. 

 December 31, 2011 

 

As Previously 

Reported Adjustment 

As 

RESTATED 

 (in thousands) 

Operating Segment Assets 

Venezuela $ 348,802 $ — $ 348,802 

Indonesia 65,165 (50,572 ) 14,593 

Gabon 119,273 (63,768 ) 55,505 

Oman 20,980 (13,828 ) 7,152 

United States 137,531 122,325 259,856 

 

 691,751 (5,843 ) 685,908 

Intersegment eliminations (178,704 ) (1 ) (178,705 ) 

 

Total Assets $ 513,047 $ (5,844 ) $ 507,203 

 

 

 

 

 

 

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

(a) 

(b) 

(c) 

(d) 

(e) 

(a) 

(a) 

(a) 

(a) 
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and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar 

exchange rate. At December 31, 2012, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are 

exposed to exchange rate changes are 6.2 million Bolivars and 5.7 million Bolivars, respectively. At December 31, 2012, the balances in 

Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 277.2 million Bolivars 

and 2,646.2 million Bolivars, respectively. 

On February 8, 2013, the Venezuelan government published in the Official Gazette the Exchange Agreement No. 14 which 

establishes new exchange rates for the Bolivar/U.S. Dollar currencies that became effective February 9, 2013. The exchange rate established in 

the Agreement is 6.30 Bolivars per U.S. Dollar. The Exchange Agreement also announced the elimination of SITME effective February 8, 

2013. All exchanges of Bolivars must now transact through the Central Bank. As a result of the February 2013 devaluation, Harvest Vinccler 

estimates the impact of the devaluation to be approximately $0.1 million gain on revaluation of its assets and liabilities, and Petrodelta 

estimates the impact of the devaluation to be approximately $54.8 million gain on revaluation of its assets and liabilities. 

On May 7, 2012, the Organic Law on Employment, Male and Female Workers (“Labor Law”) was published in the Official 

Gazette. The Labor Law has 554 Articles divided into ten Titles and heavily favors employees over employers. The Labor Law’s purpose is to 

regulate the relations between workers and employers. In August 2012, the labor contract between PDVSA and the labor union was signed. The 

new labor contract awarded salary increases to both union and non-union labor retroactive to December 2011. The new labor contract increased 

the effect of the Labor Law on Petrodelta by increasing the salaries on which the Labor Law benefits are calculated. Per the actuarial study that 

PDVSA commissioned, the effect of the Labor Law on Petrodelta’s business was $3.8 million ($1.2 million net to our 32 percent interest) for 

the year ended December 31, 2012. The Labor Law had no impact to Harvest Vinccler. 

Petrodelta 

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

Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. 

Petrodelta’s 2012 capital budget was expected to be approximately $401.9 million with a significant portion of that total related to 

infrastructure costs to support the further development of the Temblador and El Salto fields. 

Petrodelta began 2012 with three drilling rigs, but PDVSA relocated one rig to another operation. Currently, Petrodelta is operating 

three drilling rigs and two workover rigs and is continuing with infrastructure enhancement projects in the El Salto and Temblador fields. A 

pipeline is currently under construction between the Isleño field and the main production facility at Uracoa. Isleño production is currently being 

trucked to Uracoa. Petrodelta has received two new drilling rigs. The first drilling rig is currently waiting on repairs and is expected to start 

drilling operations in the Isleño field in the first quarter of 2013. The second drilling rig has been mobilized and is expected to start drilling 

operations in the Temblador field in the first quarter of 2013. Petrodelta was notified that it will relocate a current operating rig to another 

operation with the old rig being replaced with a new rig which arrived in February 2013. These rigs result in an expected five working drilling 

rigs in 2013. 

During the year ended December 31, 2012, Petrodelta drilled and completed 12 development wells compared to 15 development 

wells, one successful appraisal well and two water injector wells in the year ended December 31, 2011. Petrodelta delivered approximately 13.2 

MBls of oil and 2.2 billion cubic feet (“Bcf”) of natural gas, averaging 36,979 barrels of oil equivalent (“BOE”) per day during the year ended 

December 31, 2012 compared to deliveries of 11.4 MBls of oil and 2.3 Bcf of natural gas, averaging 32,240 BOE per day during the year ended 

December 31, 2011. 

Petrodelta’s Proved reserves, net to our 32 percent interest, are 38.4 MMBOE at December 31, 2012. Petrodelta’s Probable 

reserves, net to our 32 percent interest, are 61.8 MMBOE at December 31, 2012. Petrodelta’s Possible reserves, net to our 32 percent interest, 

are 104.4 MMBOE. Proved plus Probable reserves at 100.2 MMBOE, after accounting for current year production, are virtually unchanged 

from last year. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting 

Policies – Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve 

estimates. 

 

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Certain operating statistics for the years ended December 31, 2012, 2011, and 2010 for the Petrodelta fields operated by Petrodelta 

are set forth below. This information is provided at 100 percent. 

 

 

Under Petrodelta’s Sales Contract, crude oil delivered from the Petrodelta fields to PPSA is priced with reference to Merey 16 

published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, commercialization costs and 

distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices are quoted and sold in U.S. 

Dollars. Natural gas delivered from the Petrodelta Fields to PDVSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make 

payment to Petrodelta in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered. Natural gas deliveries are paid in 

Bolivars, but the pricing for natural gas is referenced to the U.S. Dollar. 

Production from the Petrodelta fields, except the El Salto field, flows through Petrodelta’s pipelines into PDVSA’s EPT-1 storage 

facility. Prior to October 2011, El Salto production was trucked to the EPT-1 storage facility and combined with the other Petrodelta fields’ 

production. Beginning October 2011, production from the El Salto field flows through PDVSA’s EPM-1 transfer point at PDVSA Morichal. 

Currently, the El Salto production flows through COMOR transfer point, a new transfer point for Petrodelta, at PDVSA Morichal. 

When the Sales Contract was executed, Petrodelta was producing only one type of crude, Merey 16. The official pricing formula 

applied to the Merey 16 by MENPET is used for the sales of Petrodelta crude oil with quality close to 16 degrees API to represent actual 

quality delivered. Beginning in October 2011, MENPET determined that Petrodelta’s production flowing through the COMOR transfer point 

was a heavier type of crude, Boscan. The official pricing formula applied to Boscan by MENPET is used for the sales of Petrodelta crude oil 

with quality close to 10 degrees API to represent actual quality delivered. 

Since Petrodelta was producing only Merey 16 when the Sales Contract was executed, the Boscan gravity and sulphur correction 

factors and crude pricing formula are not included in the Sales Contract. However, under the Sales Contract, PPSA is obligated to receive all of 

Petrodelta’s production. All production deliveries for all of Petrodelta’s fields have been certified by MENPET and acknowledged by PPSA. 

All pricing factors to be used in the Merey 16 and Boscan pricing formulas have been provided by and certified by MENPET to Petrodelta. 

Since the Sales Contract provides for only one crude pricing formula, the Sales Contract had to be amended to include the Boscan 

pricing formula to allow Petrodelta to invoice PPSA for El Salto crude oil deliveries. From October 1, 2011 through June 30, 2012, Petrodelta 

used the Boscan pricing formula as published in the Official Gazette on January 11, 2007 to record revenue from El Salto field deliveries. 

Petrodelta subsequently received from PDVSA Trade and Supply a draft amendment to the Sales Contract. The pricing formula in the draft 

amendment was used to record revenue for El Salto field deliveries from July 1, 2012 through December 31, 2012, and revenue for El Salto 

field deliveries for October 1, 2011 through June 30, 2012 was revised to reflect the pricing formula in the draft amendment. The only item 

included in the draft amendment is the Boscan pricing formula to be used in invoicing El Salto crude oil deliveries. All other terms and 

conditions of the Sales Contract remain in force. On January 28, 2013, Petrodelta’s board of directors endorsed the amendment to the Sales 

Contract. The amendment has to be approved by CVP’s board of directors and HNR Finance’s board of directors. Once these approvals are 

received, the amendment to the Sales Contract will be executed and PPSA will be invoiced for the deliveries. 

At December 31, 2012, El Salto deliveries, net of royalties, covering the delivery months of October 2011 through December 2012 

totaled approximately 4.0 MBls (1.3 MBls net to our 32 percent interest). The draft 

 

31 

 December 31, 

 2012 2011 2010 

Thousand barrels of oil sold 13,172 11,390 8,561 

Million cubic feet of gas sold 2,171 2,266 2,204 

Total thousand barrels of oil equivalent 13,534 11,768 8,928 

Average price per barrel $ 95.91 $ 98.52 $ 70.57 

Average price per thousand cubic feet $ 1.54 $ 1.54 $ 1.54 

Cash operating costs ($millions) $ 121.0 $ 77.2 $ 44.7 

Capital expenditures ($millions) $ 184.2 $ 137.5 $ 98.7 

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

Ended December 31, 2012 and 2011, Equity in Earnings from Equity Affiliates . 

(a) 

(a) 
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amendment to the Sales Contract pricing formula for Boscan based upon the deliveries and factors certified by MENPET, results in revenue for 

these deliveries of $352.7 million ($112.9 million net to our 32 percent interest). As of December 31, 2012, these deliveries for El Salto remain 

uninvoiced to PPSA. 

In Item 1A. Risk Factors , we disclosed that PDVSA’s failure to timely pay contractors, including Petrodelta, was having an adverse 

effect on Petrodelta. We have advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, 

operations and seismic interpretation, and employee salaries and related benefits for Harvest employees seconded into Petrodelta. Currently, we 

have three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. We are considered a contractor 

to Petrodelta, and as such, we are also experiencing the slow payment of invoices. During the year ended December 31, 2012, we advanced 

Petrodelta $0.5 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advances. Advances to equity affiliate has 

increased $0.4 million, to a balance of $2.8 million, during the year ended December 31, 2012. During the year ended December 31, 2011, we 

advanced Petrodelta $0.8 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advances. Although payment is 

slow, payments continue to be received. Petrodelta and Petrodelta’s board have not indicated that the advances are not payable, nor that they 

will not be paid. As a Petrodelta contractor, Harvest Vinccler assessed the possibility of recording an allowance for doubtful accounts on its 

receivable from Petrodelta. After considering many factors, including the slow but continuous payments received from Petrodelta, Harvest 

Vinccler determined that an allowance for doubtful accounts is not required; however, at December 31, 2012, Harvest Vinccler reclassified 

$2.1 million of the Advances to Affiliate to a long-term receivable due to slow payment and age of the advances. 

We are unable to provide an indication of when PDVSA will become and remain current in its payment obligations. However, we 

believe that PDVSA’s debt will not disappear completely in the short term, but the risk of contractor work stoppage is minimal due to PDVSA 

guaranteeing payments as publicly stated by top officials. Increased costs due to PDVSA’s debt financing are already imbedded in current 

contractor’s rates. 

Petrodelta’s 2012 proposed capital expenditures were expected to be approximately $401.9 million and included a planned drilling 

program to utilize two rigs to drill both development and appraisal wells for maintaining production capacity, the continued appraisal of the 

substantial resource base in the El Salto field and further drilling in the Isleño field. It also included engineering work for production facilities 

required for the full development of the El Salto and Temblador fields. Due to insufficient monetary support and contractual adherence by 

PDVSA, Petrodelta incurred only $184.2 million of its 2012 proposed capital expenditures. 

As of May 2, 2013, the 2013 budget for Petrodelta had not yet been approved by its shareholders. Since Petrodelta only executed 

approximately 45.8 percent of its 2012 planned capital expenditures primarily due to insufficient monetary support and contractual adherence 

by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2013 budget. Should PDVSA 

continue in insufficient monetary support and contractual adherence of Petrodelta, underinvestment in the development plan may lead to 

continued under-performance. However, Petrodelta’s 2013 proposed budget includes a planned drilling program to utilize five rigs to drill both 

development and appraisal wells for maintaining production capacity and the continued appraisal of the substantial resource base in the El 

Salto, Temblador and Isleño fields. It also includes engineering work for continued infrastructure enhancement projects in El Salto and 

Temblador. 

In April 2011, the Venezuelan government published in the Official Gazette the amended Windfall Profits Tax. In February 2013, 

the Venezuelan government published in the Official Gazette an amendment to the Windfall Profits Tax. The amended Windfall Profits Tax 

establishes new levels for contribution of extraordinary prices (under $80 per barrel) and exorbitant prices (over $100 per barrel), and levels inbetween, to the Venezuelan government. The amended Windfall Profits Tax is deductible for Venezuelan income tax purposes. During the year 

ended December 31, 2012, Petrodelta recorded $291.4 million for the amended Windfall Profits Tax (2011: $237.6 million). 

One section of the Windfall Profits Tax states that royalties paid to Venezuela are capped at $70 per barrel, but the cap on royalties 

has not been defined as being applicable to in-cash, in-kind, or both. In October 2011, Petrodelta received instructions from PDVSA that 

royalties, whether paid in-cash or in-kind, should be reported at $70 per barrel (royalty barrels x $70). The difference between the $70 royalty 

cap and the current oil price is to be reflected on the income statement as a reduction in oil sales. For the year ended December 31, 2012, the 

reduction to oil sales due to the $70 cap applied to all royalty barrels was $113.7 million ($36.4 million net to our 32 percent interest). For the 

year ended December 31, 2011, the reduction to oil sales due to the $70 cap applied to all royalty barrels was $85.0 million ($27.2 million net 

to our 32 percent interest). 

 

32 
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Per our interpretation of the Windfall Profits Tax, the $70 cap on royalty barrels should only be applied to the 3.33 percent royalty 

which Petrodelta pays in cash. With assistance from Petrodelta, we have recalculated Petrodelta’s oil sales and royalties to apply the current oil 

price to its total barrels produced and to the 30 percent royalty paid in-kind and applied the $70 cap to the 3.33 percent royalty paid in cash for 

the years ended December 31, 2012 and 2011. For the year ended December 30, 2012, net oil sales (oil sales less royalties) are slightly higher, 

$11.4 million ($3.6 million net to our 32 percent interest). For the year ended December 31, 2011, net oil sales are slightly higher, $8.5 million 

($2.7 million net to our 32 percent interest) under this method than the method advised by PDVSA and the method of applying the current oil 

price to total barrels produced and to total royalty barrels. 

Another section of the amended Windfall Profits Tax for which Petrodelta is waiting for clarity relates to an exemption of this tax 

that can be granted by the Ministry of the People’s Power for Petroleum and Mining (“MENPET”) for the incremental production of projects 

and grass root developments until the specific investments are recovered. This exemption has to be considered and approved in a case by case 

basis by MENPET. We believe several of the fields operated by Petrodelta may qualify for the exemption from the amended Windfall Profits 

Tax. We are waiting for clarification from MENPET on the definitions of incremental production and grass roots developments, as well as 

guidance on the process for applying for the exemption. 

The Venezuelan government published in the Official Gazette an amendment to the Windfall Profits Tax with an effective date of 

February 20, 2013. The amended Windfall Profits Tax establishes new levels for contribution of extraordinary and exorbitant prices to the 

Venezuelan government. Extraordinary prices are considered to be equal to or lower than $80 per barrel, and exorbitant prices are considered to 

be over $80 per barrel. The amended Windfall Profits tax also sets a new royalty cap per barrel of $80. Contributions for extraordinary prices 

are 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $55 per barrel 

for 2013) and $80 per barrel. Contributions for exorbitant prices are (1) 80 percent when the average price of the VEB exceeds $80 per barrel 

but is less than $100 per barrel; (2) 90 percent when the average price of the VEB equals or exceeds $100 per barrel but is less than $110 per 

barrel; and (3) 95 percent when the average price of the VEB equals or exceeds $110 per barrel. 

On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance 

($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to 

Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, as of May 2, 2013, this 

dividend has not been received, although it is due and payable. Petrodelta’s board of directors declared this dividend and has never indicated 

that the dividend is not payable, nor that it will not be paid. The dividend receivable is classified as a long-term receivable at December 31, 

2012 due to the uncertainty in the timing of payment. There is uncertainty with respect to the timing of the receipt of this dividend and whether 

future dividends will be declared or paid. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable 

not be collected or facts and circumstances surrounding our investment change, our results of operations and investment in Petrodelta could be 

adversely impacted. 

The Organic Law on Sports, Physical Activity and Physical Education (“Sports Law”) was published in the Official Gazette on 

August 23, 2011. The purpose of the Sports Law is to establish the public service nature of physical education and the promotion, organization 

and administration of sports and physical activity. Funding of the Sports Law is by contributions made by companies or other public or private 

organizations that perform economic activities for profit in Venezuela. The contribution is one percent of annual net or accounting profit and is 

not deductible for income tax purposes. Per the Sports Law, contributions are to be calculated on an after-tax basis. However, CVP has 

instructed Petrodelta to calculate the contribution on a before-tax basis contrary to the Sports Law. For the year ended December 31, 2012, this 

method of calculation overstates the liability for the Sports Law contribution by $2.5 million ($0.8 million net to our 32 percent interest). We 

have adjusted for the overaccrual of the Sports Law in the December 31, 2012 Net Income from Equity Affiliate. 

Petrodelta’s results and operating information is more fully described in I tem 15. Exhibits and Financial Statement Schedules, 

Notes to the Consolidated Financial Statements, Note 13 – Investment in Equity Affiliates – Petrodelta, S.A. 

Diversification 

We have broadened our strategy from our primary focus on Venezuela to identify, access and integrate hydrocarbon assets to 

include organic growth through exploration in basins globally with proven hydrocarbon systems. We seek to leverage our Venezuelan 

experience as well as our recently expanded business development and technical platform to create a diversified resource base. With the 

addition of technical resources through the 

 

33 
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opening of our London and Singapore offices, we have made significant investments to provide the necessary foundation and global reach 

required for an organic growth focus. Our organic growth is focused on undeveloped or underdeveloped fields, field redevelopments and 

exploration. While exploration has become a larger part of our overall portfolio, we generally restrict ourselves to basins with known 

hydrocarbon systems and favorable risk-reward profiles. Exploration will be technically driven with a low entry cost and high resource 

potential that provides sustainable growth. 

Budong-Budong Project, Indonesia 

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

The initial exploration term of the Budong PSC was due to expire on January 15, 2013. In September 2012, the operator of the 

Budong PSC, on behalf of us and the other co-venturer, submitted a request to BPMIGAS under the terms of the Budong PSC for a four-year 

extension of the initial six-year exploration term of the Budong PSC. In January 2013, we received written approval from SKK Migas of the 

four-year extension of the initial six-year exploration term. 

In November 2012, the Indonesia constitutional court declared BPMIGAS, Indonesia’s oil and gas regulatory authority, to be 

unconstitutional. In January 2013, SKK Migas, the Special Task Force for oil and gas upstream sector, was formed to replace BPMIGAS. SKK 

Migas will supervise all oil and gas industry activities. 

In December 2012, we signed a farmout agreement with the operator of the Budong PSC to acquire an additional 7.1 percent 

participating interest and to become operator of the Budong PSC. We assumed the role of interim operator effective January 16, 2013. Closing 

of this acquisition will increase our participating ownership interest in the Budong PSC to 71.5 percent with our cost sharing interest becoming 

72 percent until first commercial production. The consideration for this transaction is that we will fund 100 percent of the costs of the first 

exploration well of the four-year extension to the Budong PSC. If the exploration well is not drilled within 18 months of the date of approval 

from the Government of Indonesia of this transaction, our partner has the right to give notice that the consideration be paid in cash, or $3.2 

million. The transfer of operatorship was approved by SKK Migas on March 25, 2013. The acquisition of the additional participating interest 

was approved by the Government of Indonesia on April 9, 2013. 

We have satisfied all work commitments for the current exploration phase of the Budong PSC. However, the extension of the initial 

exploration term includes an exploration well, which if not drilled by January 2016, results in the termination of the Budong PSC. 

Pursuant to the request for extension of the initial exploration term, the contract area held by the Budong PSC at the beginning of 

the extension period should be reduced, per the terms of the Budong PSC, from the current 55 percent to 20 percent of the original contract 

area. In January 2013, our partner, on our behalf, submitted a relinquishment proposal of 10 percent to SKK Migas. The retained area will 

contain all the areas of geological interest to the Budong PSC partners. 

Operational activities during the year ended 2012 included a review of geological and geophysical data obtained from the drilling of 

LG-1 and KD-1 wells to upgrade the prospectivity of the block and to define a prospect for potential drilling in 2013. Based on multiple oil and 

gas shows encountered in both LG-1 and KD-1, we are working on an exploration program targeting the Pliocene and Miocene sands 

encountered in the previous two wells. We have completed remapping of both the Lariang and Karama Basins with eight leads in the Lariang 

Basin and five leads in the Karama Basin having been identified in the Pliocene, Middle-Late Miocene and Eocene sands. The identification of 

these leads is the basis for the four-year extension request of the first six-year exploration term. The partners have technically recommended the 

drilling of the Madjene prospect in the Lariang Basin targeting stacked Pliocene and Miocene clastic reservoirs for an exploration well in late 

2013. Preliminary well planning activities commenced in October 2012. 

During the year ended December 31, 2012, we had cash capital expenditures of $5.8 million mainly for deepening and plugging and 

abandonment costs of KD-1ST (2011: $18.2 million for drilling, construction and plugging and abandonment costs and $3.7 million for the 

purchase of the additional 10 percent equity interest). The 2013 budget for the Budong PSC is $13.9 million. 

 

34 
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Dussafu Project – Gabon 

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

The Dussafu PSC partners and the Republic of Gabon, entered into the third exploration phase of the Dussafu PSC with an effective 

date of May 28, 2012. The DGH agreed to lengthen the third exploration phase to four years until May 27, 2016. The third exploration phase of 

the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period. This 

commitment was fulfilled with the drilling of DTM-1. 

Operational activities during 2012 included completion of the time processing of 545 square kilometers of seismic which was 

acquired in the fourth quarter of 2011 and well planning. The 3-D Pre-Stack Time Migration was completed in July 2012. Pre-Stack Depth 

processing and reprocessing of the 2005 Inboard 3-D seismic of approximately 1,300 square kilometers commenced in June 2012 with the time 

reprocessing and merging of the various 3-D surveys completed in September 2012. Initial velocity model building for the Pre-Stack Depth 

migration commenced and the Pre-Stack Depth processing project is expected to be completed in the second quarter of 2013. 

Well planning progressed to drill an exploration well in the fourth quarter of 2012 on the Tortue prospect to target stacked pre-salt 

Gamba and Dentale reservoirs as well as a secondary post-salt Madiela clastic reservoir. DTM-1 was spud on November 19, 2012. DTM-1 was 

drilled with the Scarabeo 3 semi-submersible drilling unit, and was drilled in a water depth of 380 feet. On January 4, 2013, we announced that 

DTM-1 had reached a vertical depth of 11,260 feet within the Dental Formation. Log evaluation and pressure data indicate that we have an oil 

discovery of approximately 42 feet of pay in a 72 foot column within the Gamba Formation and 123 feet of pay in stacked reservoirs within the 

Dentale Formation. Additional technical evaluation is on-going. 

The first appraisal sidetrack of DTM-1 (“DTM-1ST1”) spud January 12, 2013. DTM-1ST1 was drilled to a Total Depth of 11,385 

feet in the Dental Formation, approximately 1,800 feet from DTM-1 wellbore and found 65 feet of pay in the primary Dentale reservoir. 

Several other stacked sands with oil shows were encountered; however, due to a stuck downhole tool, logging operations were terminated early 

before pressure data could be collected to confirm connectivity. The well can be re-entered, and the downhole tool has since been retrieved. 

DTM-1 and DTM-1ST1 were suspended pending future appraisal and development activities. The drilling rig was demobilized and released on 

February 21, 2013. 

During the year ended December 31, 2012, we had cash capital expenditures of $11.7 million for seismic processing (2011: $40.1 

million for well planning and drilling). The 2013 budget for the Dussafu PSC is $26.2 million. 

Block 64 EPSA Project – Oman 

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

Both the work and financial commitments on Block 64 EPSA have been fulfilled. Operational activities during the year ended 

December 31, 2012 included post well evaluation and review of geological and geophysical data obtained from the drilling of MFS-1 and 

AGN-1 wells. On March 12, 2013, we elected to not request an extension of the First Phase or enter the Second Phase of Block 64 EPSA and 

Block 64 will be relinquished effective June 30, 2013. The carrying value of Block 64 EPSA of $6.4 million was written off to impairment 

expense at December 31, 2012. 

During the year ended December 31, 2012, we incurred $6.1 million for drilling and plugging and abandonment costs (2011: $10.2 

million for well planning, drilling and plugging and abandonment costs). The 2013 budget for Block 64 EPSA is minimal, consisting of costs 

required to terminate operations and close the field office. 

WAB-21 Project – China 

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

 

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In March 2011, CNOOC granted us an extension to May 2013 of Phase One of the Exploration Period for the WAB-21 contract 

area. The Joint Management Committee has approved an extension of the license until May 31, 2015. We are meeting with CNOOC in April 

2013 to discuss the ratification of the extension. While no assurance can be given, we believe we will continue to receive contract extensions so 

long as the border disputes with Vietnam persist. Even though there continues to be increasing activity on the Vietnamese blocks which we 

believe confirms our view of WAB-21’s prospectivity, we impaired the carrying value of WAB-21 of $2.9 million at December 31, 2012 due 

to our continued inability to pursue an exploration program. However, we continue to seek permission to acquire regional 2-D seismic and 

localized 3-D seismic. 

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

consisting of costs required to maintain the license. 

Other Exploration Projects 

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

Business Strategy 

In Item 1. Business and Item 1A. Risk Factors, we discuss the situation in Venezuela and how the actions of the Venezuelan 

government have and continue to adversely affect our operations. The expectation that dividends from Petrodelta will be minimal over the next 

two years has restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and develop growth 

opportunities elsewhere. 

We will use our available cash and future access to capital markets to expand our diversified strategy in a number of countries that 

fit our strategic investment criteria. In executing our business strategy, we will strive to: 

 

 

 

 

 

 

To accomplish our strategy, we intend to: 

 

 

 

 

 

 

36 

 • maintain financial prudence and rigorous investment criteria; 

 • access capital markets; 

 • continue to create a diversified portfolio of assets; 

 • preserve our financial flexibility; 

 • use our experience and skills to acquire new projects; and 

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

 

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

risk of our investment portfolio. 

 

• Seek Operational and Financial Control : We desire control of major decisions for development, production, staffing and financing 

for each project for a period of time sufficient for us to ensure maximum returns on investments. 

 

• Establish a Presence Through Joint Venture Partners and the Use of Local Personnel: We seek to establish a presence in the 

countries and areas we operate through joint venture partners to facilitate stronger governmental and business relationships. In 

addition, we use local personnel to help us take advantage of local knowledge and experience and to minimize costs. 

 

• Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time: We are willing to agree to minimum capital 

expenditures or development commitments at the outset of new projects, but we endeavor to structure such commitments to fulfill 

them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, 

thereby limiting our maximum cash exposure. We also seek to maximize available local financing capacity to develop the 

hydrocarbons and associated infrastructure. 

 

• Provide Technical Expertise: We believe there is an advantage in being able to provide geological, geophysical and engineering 

expertise beyond what many companies or countries possess internally. 
Table of Contents 

 

 

Results of Operations 

The following discussion should be read with the results of operations for each of the years in the three-year period ended 

December 31, 2012 and the financial condition as of December 31, 2012 and 2011 in conjunction with our consolidated financial statements 

and related notes thereto. 

Years Ended December 31, 2012 and 2011 

We reported a net loss attributable to Harvest of $12.2 million, or $(0.33) diluted earnings per share, for the year ended 

December 31, 2012, compared with net income attributable to Harvest of $56.0 million, or $1.64 diluted earnings per share, for the year ended 

December 31, 2011. 

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

 

Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2012, we 

incurred $4.8 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations, $2.5 million related 

to other general business development activities, and $1.8 million related to lease maintenance. During the year ended December 31, 2011, we 

incurred $10.1 million of exploration costs for the acquisition, processing and reprocessing of seismic data related to ongoing operations, $0.3 

million related to other general business development activities, and $2.2 million related to lease maintenance. 

During the year ended December 31, 2012, we impaired $6.4 million related to the carrying value of Block 64 EPSA and $2.9 

million related to the carrying value of WAB-21. During the year ended December 31, 2011, we impaired $3.3 million related to the carrying 

value of West Bay. 

 

37 

 

• Maintain a Prudent Financing Plan : We intend to maintain our financial flexibility by closely monitoring spending, holding 

sufficient cash reserves, minimizing the use of restricted cash, actively seeking opportunities to reduce our weighted average cost of 

capital and increase our access to debt and equity markets. 

 

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

 

• Establish Various Sources of Production : We seek to establish new production from our exploration and development efforts in a 

number of diverse markets and expect to monetize production through operations or the farm-down or possible sale of assets. 

 

Year Ended 

December 31, 

 2012 

2011 

(RESTATED) 

Increase 

(Decrease) 

Depreciation and amortization $ 0.4 $ 0.5 $ (0.1 ) 

Exploration expense 9.1 12.6 (3.5 ) 

Impairment expense 9.3 3.3 6.0 

Dry hole costs 5.6 49.7 (44.1 ) 

General and administrative 27.1 22.5 4.6 

Investment earnings and other (0.3 ) (0.7 ) 0.4 

Unrealized (gain) loss on warrant derivatives 0.6 (9.8 ) 10.4 

Interest expense 1.6 7.2 (5.6 ) 

Debt conversion expense 3.6 — 3.6 

Loss on extinguishment of debt 5.4 13.1 (7.7 ) 

Other non-operating expense 2.9 1.4 1.5 

Loss on exchange rates 0.1 0.1 — 

Income tax expense (benefit) (0.6 ) 1.1 (1.7 ) 
Table of Contents 

During the year ended December 31, 2012, we expensed to dry hole costs $0.7 million related to the drilling of the KD-1 well on 

the Budong PSC and $4.9 million related to the drilling of the AGN-1 on Block 64 EPSA. During the year ended December 31, 2011, we 

expensed to dry hole costs $14.0 million related to the drilling of the LG-1 on Budong PSC, $26.0 million related to the drilling of the KD-1 

and KD-1ST on the Budong PSC, $6.9 million related to the drilling of the MFS-1 on Block 64 ESPA and $2.8 million related to the drilling of 

the AGN-1 on Block 64 EPSA. See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia – Drilling and Development Activity 

and Block 64 EPSA, Oman – Drilling and Development Activity . 

The increase in general and administrative costs in the year ended December 31, 2012 from the year ended December 31, 2011, was 

primarily due to increases in employee related costs ($3.3 million, of which $2.2 million was non-cash related to equity compensation), public 

relations ($0.1 million) and audit fees ($2.0 million) offset by a decrease in general office expense and overhead ($0.4 million), contract 

services ($0.2 million) and travel costs ($0.2 million). 

The decrease in investment earnings and other in the year ended December 31, 2012 from the year ended December 31, 2011 was 

due to the receipt during the year ended December 31, 2011 of payment for transition services provided on the Antelope Project after closing of 

the sale. 

The decrease in unrealized gain on warrant derivatives in the year ended December 31, 2012 from the year ended December 31, 

2011 was due to the change in fair value for our warrant derivative liabilities: $3.18 per warrant at December 31, 2012 and $3.04 per warrant at 

December 31, 2011. 

The decrease in interest expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to the 

conversion of $31.5 million of our 8.25 percent senior convertible notes in the year ended December 31, 2012, offset by our $79.8 million 

senior unsecure note offering in October 2012, repayment in May 2011 of our $60 million term loan facility, and interest capitalized to oil and 

gas properties of $3.0 million. 

During the year ended December 31, 2012, we incurred debt conversion expense of $2.9 million related to the issuance of 

0.4 million common shares issued as an inducement for completing the exchange and legal and other professional fees ($0.7 million). 

During the year ended December 31, 2012, we incurred a loss on extinguishment of debt of $5.4 million related to the early 

conversion of our 8.25 percent senior convertible notes. The loss on extinguishment of debt includes the difference between the carrying value 

of the 8.25 percent senior convertible notes and the amount received for the 11 percent senior unsecured notes ($5.0 million), expensing of 

deferred financing costs related to the 8.25 percent senior convertible notes ($0.1 million) and issuance of 30,000 shares of Harvest common 

stock issued in exchange for a waiver agreement ($0.3 million). During the year ended December 31, 2011, we incurred a loss on 

extinguishment of debt related to early payment of our $60 million term loan facility. The loss on extinguishment of debt includes the write off 

of the discount on debt ($10.6 million), prepayment premium of 3.5 percent of the amount outstanding ($2.1 million), expensing of financing 

costs related to the term loan facility ($0.4 million), and the cost to redeem 4.4 million unvested warrants issued in connection with the term 

loan facility. 

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

The increase in other non-operating expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due 

to costs incurred related to our strategic alternative process and evaluation which resulted in the SPA for the sale of our 32 percent interest in 

Petrodelta. 

The change in income tax expense in the year ended December 31, 2012 from the year ended December 31, 2011 is due to a net 

operating loss incurred in 2012 while we had taxable income in 2011 as a result of the sale of interest in the Antelope Project. 

Equity in Earnings from Equity Affiliates 

For the year ended December 31, 2012, net income from equity affiliates reflects an increase in Petrodelta’s revenue from oil sales 

due to higher sales volumes ($170.8 million) offset by lower prices ($29.6 million). Royalties, which is a function of revenue, increased $49.0 

million due to the increase in revenue (net increase in revenue of $141.2 million at 30 percent royalty). Windfall Profits Tax, which is a 

function of volume and price received per barrel, increased $53.8 million due to an increase in volumes (2012: 13.2 MBls vs. 

 

38 
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2011: 11.4 MBls) offset by lower price received per barrel (2012: $95.91 per barrel vs. 2011: $98.52 per barrel). The increase in operating 

expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to increased oil production and also includes 

$3.8 million of additional expense related to the labor law which was recorded in December 2012. The decrease in workover expense in the 

year ended December 31, 2012 from the year ended December 31, 2011 was due to fewer workovers being performed. Petrodelta’s effective 

tax rate (inclusive of the adjustments to reconcile to reported net income from equity affiliate) for the year ended December 31, 2012 was not 

materially different with the effective tax rate for the year ended December 31, 2011. 

Discontinued Operations 

On May 17, 2011, we closed the transaction to sell the Antelope Project. The sale had an effective date of March 1, 2011. We 

received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and 

deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale 

was reported in discontinued operations in the second quarter of 2011. 

During the year ended December 31, 2012, we incurred $0.1 million of expense related to settlement of royalty payments to the 

Mineral Management Services and write-offs of $5.2 million of accounts and note receivable and $3.6 million of accounts payable and carry 

obligation related to the settlement of all outstanding claims with a private third party on the Antelope Project. See Item 15. Exhibits and 

Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 3 – Summary of Significant Accounting Policies, Notes

Receivable . 

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

 

Years Ended December 31, 2011 and 2010 

We reported net income attributable to Harvest of $56.0 million, or $1.64 diluted earnings per share, for the year ended 

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

December 31, 2010. 

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

 

 

39 

 December 31, 

 2012 2011 

 (in thousands) 

Revenues applicable to discontinued operations $ — $ 6,488 

Net income (loss) from discontinued operations (1,699 ) 97,616 

 Year Ended December 31, 

 

2011 

(RESTATED) 

2010 

(RESTATED) 

Increase 

(Decrease) 

Depreciation and amortization $ 0.5 $ 0.5 $ — 

Exploration expense 12.6 8.3 4.3 

Impairment expense 3.3 — 3.3 

Dry hole costs 49.7 — 49.7 

General and administrative 22.5 25.9 (3.4 ) 

Investment earnings and other (0.7 ) (0.6 ) (0.1 ) 

Unrealized gain on warrant derivatives (9.8 ) (0.3 ) (9.5 ) 

Interest expense 7.2 3.8 3.4 

Loss on extinguishment of debt 13.1 — 13.1 

Other non-operating expense 1.4 4.0 (2.6 ) 

Loss on exchange rates 0.1 1.6 (1.5 ) 

Income tax expense (benefit) 1.1 (0.2 ) 1.3 
Table of Contents 

Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2011, we 

incurred $10.1 million of exploration costs for the acquisition, processing and reprocessing of seismic data related to ongoing operations, $0.3 

million related to other general business development activities, and $2.2 million related to lease maintenance. During the year ended 

December 31, 2010, we incurred $6.4 million of exploration costs for seismic, geological and geophysical, $1.6 million related to other general 

business development activities and $0.3 million related to lease maintenance. Included in the $6.4 million of exploration costs is the one-time 

charge of $1.2 million for acquisition of seismic data for the Budong PSC related to our partner in the Budong PSC exercising their option to 

increase the carry obligation. 

During the year ended December 31, 2011, we impaired $3.3 million related to the carrying value of West Bay. During the year 

ended December 31, 2010, we did not impair any oil and gas properties costs. 

During the year ended December 31, 2011, we expensed to dry hole costs $14.0 million related to the drilling of the LG-1 on the 

Budong PSC, $26.0 million related to the drilling of the KD-1 and KD-1ST on the Budong PSC, $6.9 million related to the drilling of the MFS1 on Block 64 ESPA and $2.8 million related to the drilling of the AGN-1 on Block 64 EPSA. See Item 1. Business, Operations, BudongBudong, Onshore Indonesia – Drilling and Development Activity and Block 64 EPSA, Oman – Drilling and Development Activity . 

The decrease in general and administrative costs in the year ended December 31, 2011 from the year ended December 31, 2010 was 

primarily due to lower general office expense and overhead ($2.7 million), employee related costs ($0.9 million) and public relations ($0.3 

million) offset by higher travel costs ($0.3 million) and contract services ($0.2 million). The employee related costs include $0.5 million of 

special consideration bonuses related to the sale of our Antelope Project. 

The increase in investment earnings and other in the year ended December 31, 2011 from the year ended December 31, 2010 was 

due to income earned on transition services provided on the Antelope Project after closing of the sale. 

The increase in unrealized gain on warrant derivative in the year ended December 31, 2011 from the year ended December 31, 2010 

was due to the change in fair value for our warrant derivative liabilities: $3.04 per warrant at December 31, 2011 and $7.37 weighted average 

price per warrant at December 31, 2010. 

The increase in interest expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to the 

interest associated with our $32 million convertible debt offering in February 2010, our $60 million term loan facility occurring in October 

2010 and amortization of discount on the term loan facility related to the warrants issued in connection with the $60 million term loan facility 

offset by interest capitalized to oil and gas properties of $2.3 million. 

During the year ended December 31, 2011, we incurred a loss on extinguishment of debt related to early payment of our $60 million 

term loan facility. The loss on extinguishment of debt includes the write off of the discount on debt ($10.6 million), prepayment premium of 

3.5 percent of the amount outstanding ($2.1 million), expensing of financing costs related to the term loan facility ($0.4 million), and the cost 

to redeem 4.4 million unvested warrants issued in connection with the term loan facility. 

The decrease in loss on exchange rates in the year ended December 31, 2011 from the year ended December 31, 2010 is due to the 

Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. There was no Bolivar/U.S. Dollar exchange rate 

devaluations in the year ended December 31, 2011. 

The decrease in other non-operating expense in the year ended December 31, 2011 from the year ended December 31, 2010 was 

due to costs incurred related to our strategic alternative process and evaluation which resulted in the sale of our Antelope Project. 

The increase in income tax expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to 

higher income tax assessed in 2011 in the Netherlands offset by a U.S. tax refund received in 2010. 

For the year ended December 31, 2011, net income from equity affiliates reflects an increase in Petrodelta’s revenue from oil sales 

due to higher sales volumes and prices which was partially offset by 

 

40 
Table of Contents 

the amended Windfall Profits Tax. The increase in operating expense and workovers in the year ended December 31, 2011 from the year ended 

December 31, 2010 was due to increased oil production and having a workover rig on location for the full year of 2011. Petrodelta took 

possession of the workover rig in September 2010 and operated it for only four months in the year ending December 31, 2010. The decrease in 

gain on exchange rates in the year ended December 31, 2011 from the year ended December 31, 2010 was due to there not being a Bolivar/U.S. 

Dollar currency exchange rate devaluation during 2011. There was a Bolivar/U.S. Dollar currency exchange rate devaluation announced on 

January 8, 2010. The decrease in Petrodelta’s effective tax rate (inclusive of the adjustments to reconcile to reported net income from equity 

affiliate) in the year ended December 31, 2011 from the year ended December 31, 2010 was primarily due to the tax effects of the currency 

devaluation in 2010 partially offset by an increase in current tax on increased earnings. 

At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion. Accordingly, we did not record net 

losses incurred by Fusion of $0.2 million ($0.1 million net to our 49 percent interest) in the year ended December 31, 2011 (2010: $2.4 million 

[$1.2 million net to our 49 percent interest]), as doing so would have caused our equity investment to go into a negative position. However, we 

have recognized a $1.4 million gain on the sale of Fusion in the year ended December 31, 2011. 

Discontinued Operations 

On May 17, 2011, we closed the transaction to sell our Antelope Project. The sale had an effective date of March 1, 2011. We 

received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and 

deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale 

was reported in the second quarter of 2011. 

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

 

Net income from discontinued operations for the year ended December 31, 2011 includes $106.0 million gain on the sale of our 

Antelope Project, $3.8 million for employee severance and special accomplishment bonuses, and $5.7 million of U.S. income tax related to the 

sale of our Antelope Project. Severance costs for key employees include 58,000 stock appreciation rights (“SAR”) granted at an exercise price 

of $4.595 per SAR. These SARs are exercisable by the key employee for up to one year after termination. 

Risks, Uncertainties, Capital Resources and Liquidity 

Our financial statements for the year ended December 31, 2012 have been prepared under the assumption that we will continue as a 

going concern. Our independent registered public accounting firm has included in their audit report an explanatory paragraph expressing 

substantial doubt about our ability to continue as a going concern. The accompanying financial statements do not include any adjustments that 

might result from the outcome of this uncertainty. 

Our current capital resources may not be sufficient to support our liquidity requirements through 2013. However, we believe certain 

cost reduction measures could be put into place which would not jeopardize our operations and future growth plans. In addition, we could delay 

the discretionary portion of our capital spending to future periods and/or sell or farm down assets as necessary to maintain the liquidity required 

to run our operations, as warranted. There are no assurances that we will be successful in selling or farming-down our assets. 

Our ability to continue as a going concern depends upon the success of our planned exploration and development activities and the 

ability to secure additional financing as needed to fund our current operations. There can be no guarantee of future capital acquisition, 

fundraising or exploration success or that we will realize the 

 

41 

 December 31, 

 2011 2010 

 (in thousands) 

Revenues applicable to discontinued operations $ 6,488 $ 10,696 

Net income (loss) from discontinued operations 97,616 3,712 
Table of Contents 

value of our unevaluated exploratory well costs. We believe that we will continue to be successful in securing any funds necessary to continue 

as a going concern. However, our current cash position and our ability to access additional capital may limit our available opportunities or not 

provide sufficient cash for operations. 

We may be able to meet future liquidity needs through the issuance of additional equity securities, and/or short or long-term debt 

financing, although there can be no assurance that such financing will be available to us or on terms that are acceptable to us, farm-downs or 

possible sales of assets. 

The long-term continuation of our business plan through 2013 and beyond is dependent upon the generation of sufficient cash flow 

to offset expenses. We will be required to obtain additional funding through public or private financing, farm-downs, further reduce operating 

costs, and/or possible sales of assets. Failure to generate sufficient cash flow by raising additional capital through debt or equity financings, 

reducing operating costs, or by farm-downs and/or selling of assets further could have a material adverse effect on our ability to meet our shortand long-term liquidity needs and achieve our intended long-term business objectives. 

The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. In Item 1A. 

Risk Factors , we discuss a number of variables and risks related to our exploration projects and our minority equity investment in Petrodelta 

that could significantly utilize our cash balances, affect our capital resources and liquidity. 

The environments in which we operate are often difficult and the ability to operate successfully depends on a number of factors 

including our ability to control the pace of development, our ability to apply “best practices” in drilling and development, and the fostering of 

productive and transparent relationships with local partners, the local community and governmental authorities. Financial risks include our 

ability to control costs and attract financing for our projects. In addition, often the legal systems of certain countries are not mature and their 

reliability can be uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and 

natural gas projects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy depends on our ability to have 

significant influence over operations and financial control. 

Our operations are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of 

revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other 

political risks, increases in taxes and governmental royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of 

foreign courts or tribunals, renegotiation of contracts with governmental entities, changes in laws and policies, including taxes, governing 

operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign 

government sovereignty over our international operations. Our international operations may also be adversely affected by the U.S. Foreign 

Corrupt Practices Act and similar worldwide anti-corruption laws, laws and policies of the United States affecting foreign policy, foreign trade, 

taxation and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States. 

There are also a number of variables and risks related to our minority equity investment in Petrodelta that could significantly utilize 

our cash balances, and affect our capital resources and liquidity. Petrodelta’s capital commitments are determined by its business plan, and 

Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. The total capital required to develop the fields in 

Venezuela may exceed Petrodelta’s available cash and financing capabilities, and there may be operational or contractual consequences due to 

this inability. Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Due to PDVSA’s liquidity 

constraints, PDVSA has not been providing the necessary monetary support and contractual adherence required by Petrodelta. If we are called 

upon to fund our share of Petrodelta’s operations, our failure to do so could be considered a default under the Conversion Contract and cause 

the forfeiture of some or all our shares in Petrodelta. 

Petrodelta currently represents our only source of earnings. Petrodelta also has a material impact on our results of operations for any 

quarter or annual reporting period. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 

13 – Investment in Equity Affiliate – Petrodelta, S.A . Petrodelta operates under a business plan, the success of which relies heavily on the 

market price of oil. To the extent that market prices of oil decline, the business plan, and thus our equity investment and/or operations and/or 

profitability, could be adversely affected. 

 

42 
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Operations in Venezuela are subject to various risks inherent in foreign operations. It is possible the legal or fiscal framework for 

Petrodelta could change and the Venezuela government may not honor its commitments. Our ability to implement or influence Petrodelta’s 

business plan, assure quality control and set the timing and pace of development could also be adversely impacted. No assurance can be 

provided that events beyond our control will not adversely affect the value of our minority investment in Petrodelta. 

Historically, our primary ongoing source of cash has been dividends from Petrodelta and the sale of oil and gas properties. See 

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

Operations . Currently, our source of cash is expected to be generated by accessing debt and/or equity markets, farm-downs, or possible sales 

of assets. 

In the event that a sale of assets (farm-outs are not included in the definition of a sale of assets in the indenture) for more than $5.0 

million in the aggregate occurs, we are required to offer to all noteholders of our 11 percent senior unsecured notes to purchase the maximum 

principal amount of our 11 percent senior unsecured notes that may be purchased out of the sale proceeds at an offer price in cash in an amount 

equal to 105.5 percent of the principal amount plus accrued and unpaid interest, if any. In the event of a change in control or a sale of 

Petrodelta, the noteholders of our 11 percent senior unsecured notes have the right to require us to repurchase all or any part of the 11 percent 

senior unsecured notes at a repurchase price equal to 101 percent in the case of a change in control or 105.5 percent in the case of a sale of 

Petrodelta plus accrued interest. We assessed the prepayment requirements and concluded they qualified as an embedded derivative. We 

considered the probabilities of these events occurring and determined that the derivative had an immaterial value at December 31, 2012. 

Between Petrodelta’s formation in October 2007 and June 2010, Petrodelta declared and paid dividends of $105.5 million to HNR 

Finance, B.V. (“HNR Finance”), a wholly owned subsidiary of Harvest Holding ($84.4 million net to our 32 percent interest). On 

November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to 

our 32 percent interest). The dividend was ratified by Petrodelta’s shareholders on March 14, 2011. Due to Petrodelta’s liquidity constraints 

caused by PDVSA’s insufficient monetary support and contractual adherence, this dividend has not yet been received, although it is due and 

payable. Petrodelta’s board of directors declared this dividend and has never indicated that the dividend is not payable, nor that it will not be 

paid. The dividend receivable is classified as a long-term receivable at December 31, 2012 due to the uncertainty in the timing of payment. 

There is uncertainty whether Petrodelta will declare and/or pay additional dividends in the future. See Item 15. Exhibits and Financial 

Statement Schedules, Notes to Consolidated Financial Statements, Note 18 – Related Party Transactions for a discussion of our obligations to 

our non-controlling interest holder, Vinccler, for any dividend received from Petrodelta. We have and will continue to monitor our investment 

in Petrodelta. Should the dividend receivable not be collected, or facts and circumstances surrounding our investment change, our results of 

operations and our investment in Petrodelta could be adversely impacted. 

Our cash is being used to fund oil and gas exploration projects, debt, interest, and general and administrative costs. We require 

capital principally to fund the exploration and development of new oil and gas properties. As is common in the oil and gas industry, we have 

various contractual commitments pertaining to exploration, development and production activities. We entered the third exploration phase of 

the Dussafu PSC on May 28, 2012. The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent 

interest) work commitment over a four year period. This commitment was fulfilled with the drilling of DTM-1. See Item 1. Business, 

Operations, Dussafu Marin, Offshore Gabon – General . In January 2013, the Budong PSC partners were granted a four year extension of the 

initial six year exploration term of the Budong PSC to January 15, 2016. The extension of the initial exploration term includes an exploration 

well, which if not drilled by January 2016, results in the termination of the Budong PSC. Also, if this exploration well is not drilled within 18 

months of the date of approval from the Government of Indonesia of this transaction, we will be required to pay our partner in the Budong PSC 

$3.2 million. See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia – General . The Budong PSC work commitments are 

discretionary, and we have the ability to control the pace of expenditures. 

 

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In March 2012, we announced that we had entered into an equity distribution agreement with Knight Capital America, L.P., a 

subsidiary of Knight Capital Group, Inc., relating to an “at-the-market” (“ATM”) offering of shares of our common stock. Due to the late filing 

of our Annual Report on Form 10-K for the year ended December 31, 2012, we are not eligible to use a Form S-3 Registration Statement; 

therefore, we can no longer access our ATM. 

Accumulated Undistributed Earnings of Foreign Subsidiaries 

As of December 31, 2012, the book-tax outside basis difference in our foreign subsidiary that has been indefinitely reinvested was 

approximately $331 million. No U.S. taxes have been recorded on these earnings. In general, it is our practice and intention to reinvest the 

earnings of our non-U.S. subsidiaries in those operations. All of our current exploration activity is outside of the U.S. We currently intend to 

utilize our unremitted foreign earnings to fund international projects, including the development of our properties in Gabon, Indonesia and 

South America. 

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

will invest the undistributed earnings or that the earnings will be remitted in a tax-free manner. Management must consider numerous factors in 

determining timing and amounts of possible future distribution of these earnings to the parent company and whether a U.S. deferred tax 

liability should be recorded for these earnings. These factors include the future operating and capital requirements of both the parent company 

and the subsidiaries, remittance restrictions imposed by foreign governments or financial agreements and tax consequences of the remittance, 

including possible application of U.S. foreign tax credits and limitations on foreign tax credits that may be imposed by the Internal Revenue 

Service (“IRS”) or IRS regulations. 

If we were to make a distribution of our foreign earnings in the form of dividends, we would likely be subject to U.S. income taxes. 

Pursuant to ASC 740-30-50-2, we have estimated that the potential U.S. tax cost if we were to repatriate all of our currently unremitted foreign 

earnings through a dividend would be approximately $113 million based upon our foreign tax credit position in the U.S. 

Working Capital. The net funds raised and/or used in each of the operating, investing and financing activities are summarized in the 

following table and discussed in further detail below: 

 

The decrease in working capital of $22.1 million at December 31, 2012 from December 31, 2011 was primarily due to decreases in 

receivables, increases in cash payments for capital expenditures and accrued expenses and decreases in accounts payable. 

Cash Flow from Operating Activities . During the year ended December 31, 2012, net cash used in operating activities was 

approximately $26.4 million (2011: $55.2 million). The $28.8 million decrease in use of cash was primarily due to decreases in accounts 

payable and accrued interest and increases in accrued expenses offset by decreases in receivables. 

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

table: 

 

 

 

 Year Ended December 31, 

 (in thousands except as indicated) 

 2012 

2011 

(RESTATED) 

2010 

(RESTATED) 

Net cash used in operating activities $ (26,405 ) $ (55,243 ) $ (8,126 ) 

Net cash provided by (used in) investing activities (23,789 ) 112,216 (56,231 ) 

Net cash provided by (used in) financing activities 63,875 (56,730 ) 90,743 

 

Net increase in cash $ 13,681 $ 243 $ 26,386 

 

 

 

 

 

 

Working Capital 40,537 62,618 133,015 

Current Ratio 2.0 3.1 5.7 

Total Cash, including restricted cash 73,627 60,146 58,703 

Total Debt 74,839 31,535 78,291 

 December 31, 

 2012 

2011 

(RESTATED) 

 (in millions) 

Budong PSC $ 5.8 $ 21.9 

Dussafu PSC 11.7 40.1 

Block 64 EPSA 6.1 10.2 

 

Total additions of property and equipment – continuing operations 23.6 72.2 

Assets Held for Sale – Antelope Project — 33.9 

 

Total additions of property and equipment $ 23.6 $ 106.1 

 

 

 

 

 See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Notes to Consolidated Financial 

Statements, Note 5 – Dispositions, Discontinued Operations . 

(1) 

(1) 
44 
Table of Contents 

During the year ended December 31, 2012, we: 

 

 

During the year ended December 31, 2011, 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 $40.1 million for 2013, of which $33.7 million is nondiscretionary, for U.S., Indonesia and Gabon operations will be funded through our existing cash balances, accessing equity and debt markets, 

and cost reductions. In addition, we could delay the discretionary portion of our capital spending to future periods or sell assets as necessary to 

maintain the liquidity required to run our operations, as warranted. 

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

 

 

During the year ended December 31, 2011, we: 

 

 

 

Contractual Obligations 

At December 31, 2012, we had the following lease commitments for office space in Houston, Texas, regional/technical offices in the 

United Kingdom and Singapore, and field offices in Jakarta, Indonesia; Port Gentil, Gabon; and Muscat, Oman that support field operations in 

those areas. 

 

45 

• Deposited with a U.S. bank $1.0 million as collateral for a Standby Letter of Credit issued in support of a performance bond for a joint 

study and had $1.2 million of restricted cash released to us; and 

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

• Received $217.8 million for the sale of our Antelope Project (see Item 15. Exhibits and Financial Statement Schedules, Notes to 

Consolidated Financial Statements, Notes to Consolidated Financial Statements, Note 5 – Dispositions, Discontinued Operations ); 

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

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

• Deposited with a U.S. bank $1.2 million as collateral for a Standby Letter of Credit issued as a payment guarantee for drilling activities 

on Block 64 EPSA; and 

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

• Received cash proceeds of $66.5 million from an offering of $79.8 million in aggregate principal amount of our 11.0 percent senior 

unsecured notes (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – LongTerm Debt ); and 

• Incurred $3.3 million in legal fees associated with financings. 

• Repaid $60.0 million of our term loan facility (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial 

Statements, Note 6 – Long-Term Debt ); 

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

• Incurred $0.2 million in legal fees associated with financings. 
Table of Contents 

We have various contractual commitments pertaining to exploration, development and production activities. These contractual 

commitments are included in the Contractual Obligations table below under Oil and gas activities. 

 

 

The four-year extension of the initial exploration phase on the Budong PSC includes an exploration well, which if not drilled by 

January 2016, results in the termination of the Budong PSC. Also, if this exploration well is not drilled within 18 months of the date of 

approval from the Government of Indonesia of this transaction, we will be required to pay our partner in the Budong PSC $3.2 million. See 

Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 14 – Indonesia . 

Senior Unsecured Notes 

On October 11, 2012, we closed an offering of $79.8 million in aggregate principal amount of our 11.0 percent senior unsecured 

notes. Under the terms of the notes, interest is payable quarterly in arrears on January 1, April 1, July 1 and October 1, beginning January 1, 

2013. The senior unsecured notes will mature on October 11, 2014. See Item 7. Management’s Discussion and Analysis of Financial Condition 

and Results of Operations – Risks, Uncertainties, Capital Resources and Liquidity . 

Effects of Changing Prices, Foreign Exchange Rates and Inflation 

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

development activities and capital expenditure program. 

Our net foreign exchange losses attributable to our international operations were minimal for the years ended December 31, 2012 

and 2011. There are many factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our 

control. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls. 

 

46 

Location Date Lease Signed Term 

Annual 

Expense 

Houston, Texas April 2004 10 years $ 204,000 

Houston, Texas December 2008 5 years 160,800 

Caracas, Venezuela October 2012 1 year 224,400 

London, U.K. September 2010 5 years 108,000 

Singapore October 2012 2 years 84,000 

Jakarta, Indonesia April 2012 2 years 98,500 

Muscat, Oman September 2011 2 years 62,400 

Gabon, Port Gentil December 2012 2 years 61,200 

• The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment 

over a four year period. This commitment was fulfilled with the drilling of DTM-1. 

 Payments (in thousands) Due by Period 

Contractual Obligations Total 

Less than 

1 Year 1-2 Years 3-4 Years 

After 4 

Years 

Debt: 

11.0% Senior Unsecured Notes Due 2014 $ 79,750 $ — $ 79,750 $ — $ — 

 

Total Debt 79,750 — 79,750 — — 

 

Other obligations: 

Interest payments 15,620 8,773 6,847 — — 

Oil and gas activities 8,200 112 8,088 — — 

Office leases 1,459 773 537 149 — 

 

Total other obligations 25,279 9,658 15,472 149 — 

 

Total contractual obligations $ 105,029 $ 9,658 $ 95,222 $ 149 $ — 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 

2004, March 2005, January 2010, January 2011 and February 2013. As a result of the February 2013 devaluation, Harvest Vinccler estimates 

the impact of the devaluation to be approximately $0.1 million gain on revaluation of its assets and liabilities, and Petrodelta estimates the 

impact of the devaluation to be approximately $54.8 million gain on revaluation of its assets and liabilities. 

Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official prevailing exchange rate that applies to 

their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar for 2012). However, during the year ended December 31, 2012, 

Harvest Vinccler exchanged approximately $1.5 million through SITME and received an average exchange rate of 5.16 Bolivars per U.S. 

Dollar. The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current 

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

monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Petrodelta does not 

have, and has not had, any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME 

exchange rate. Harvest Vinccler currently does not have any U.S. Dollars pending government approval for settlement for Bolivars at the 

official exchange rate or the SITME exchange rate. 

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Venezuela for a 

more complete discussion of the exchange agreements and their effects on our Venezuelan operations. 

Within the United States and other countries in which we conduct business, inflation has had a minimal effect on us, but it is 

potentially an important factor with respect to results of operations in Venezuela. The inflation rate in Venezuela was 22.2 percent, 26.0 percent 

and 28.5 percent for January 2013, 2012, and 2011, respectively. 

Critical Accounting Policies 

Reporting and Functional Currency 

The United States Dollar (“U.S. Dollar”) is the reporting and functional currency for all of our controlled subsidiaries and 

Petrodelta. Amounts denominated in non-U.S. Dollar currencies are re-measured into U.S. Dollars, and all currency gains or losses are 

recorded in the consolidated statements of operations and comprehensive income (loss). There are many factors that affect foreign exchange 

rates and the resulting exchange gains and losses, many of which are beyond our influence. 

Investment in Equity Affiliates 

We evaluate our investments in unconsolidated companies under ASC 323, “Investments – Equity Method and Joint Ventures.” 

Investments in which we have significant influence are accounted for under the equity method of accounting. Under the equity method, 

Investment in Equity Affiliates is increased by additional investments and earnings and decreased by dividends and losses. We review our 

Investment in Equity Affiliates for impairment whenever events and circumstances indicate a loss in investment value is other than a temporary 

decline. 

There are many factors to consider when evaluating an equity investment for possible impairment. Currency devaluations, 

inflationary economies, and cash flow analysis are some of the factors we consider in our evaluation for possible impairment. 

Capitalized Interest 

We capitalize interest costs for qualifying oil and gas properties. The capitalization period begins when expenditures are incurred on 

qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The 

capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization 

calculation. 

 

47 
Table of Contents 

Property and Equipment 

We follow the successful efforts method of accounting for our oil and gas properties. Under this method, oil and natural gas lease 

acquisition costs are capitalized when incurred. Unproved properties are assessed quarterly on a property-by-property basis, and any 

impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to 

proved oil and gas properties. Lease rentals are expensed as incurred. 

Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs 

of drilling exploratory wells are capitalized pending determination of whether the wells have discovered proved reserves. Exploratory drilling 

costs are capitalized when drilling is completed if it is determined that there is economic producibility supported by either actual production, 

conclusive formation test or by certain technical data. If proved reserves are not discovered, such drilling costs are expensed. Costs to develop 

proved reserves, including the costs of all development wells and related equipment used in production of crude oil and natural gas, are 

capitalized. 

Depletion, depreciation, and amortization (“DD&A”) of the cost of proved oil and natural gas properties are calculated using the 

unit of production method. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is 

proved reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the 

reserve base is proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken 

into account. Certain other assets are depreciated on a straight-line basis. 

Assets are grouped in accordance with ASC 932. The basis for grouping is reasonable aggregation of properties with a common 

geological structural feature or stratigraphic condition, such as a reservoir or field. 

Amortization rates are updated to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and 

additions, 3) property acquisitions and/or property dispositions and 4) impairments. 

We account for impairments of proved properties under the provisions of ASC 360, “Property, Plant, and Equipment”. When 

circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field level to the 

amortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future crude oil and natural gas prices, 

operating costs, anticipated production from proved reserves and other relevant data, are lower than the amortized capitalized cost, the 

capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount 

rate. 

Reserves 

In December 2009, we adopted the SEC’s Modernization of Oil and Gas Reporting and ASC 932. ASC 932 requires the unweighted 

average, first-day-of-the-month price during the 12-month period preceding the end of the year be used when estimating reserve quantities and 

permits the use of reliable technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable 

conclusions about reserves volumes. 

Proved reserves are those quantities of oil and gas which by analysis of geoscience and engineering data can be estimated with 

reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, 

operating methods, government regulations, etc. Prices include consideration of changes in existing prices provided only by contractual 

arrangements and do not include adjustments based upon expected future conditions. Probable reserves are those additional reserves that are 

less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible 

reserves are those additional reserves which are less certain to be recovered than probable reserves and thus the probability of achieving or 

exceeding the proved plus probable plus possible reserves is low. 

The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the 

deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based 

on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of 

oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories 

that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable. 

 

48 
Table of Contents 

The estimate of reserves is made using available geological and reservoir data as well as production performance data. These 

estimates are prepared by an independent third party petroleum engineering consulting firm and revised, either upward or downward, as 

warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic 

conditions and governmental restrictions, as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for 

example, may cause a reduction in some proved reserves due to reaching economic limits earlier. A material adverse change in the estimated 

volumes of proved reserves could have a negative impact on DD&A expense and could result in the recognition of an impairment. 

Income Taxes 

Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts 

attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss 

and tax credit carry forwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the 

deferred tax asset will not be realized. 

We do not provide deferred income taxes on undistributed earnings of our foreign subsidiaries for possible future remittances as all 

such earnings are permanently reinvested as part of our ongoing business. 

New Accounting Pronouncements 

In July 2012, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2012-02, 

which is included in ASC 350, “Intangibles – Goodwill and Other” (“ASC350”). This update gives an entity the option first to assess 

qualitative factors in assessing whether an asset is impaired. ASU No. 2012-02 is effective for annual and interim impairment test performed 

for fiscal years beginning after September 15, 2012. Early adoption is permitted. The adoption of ASU No. 2012-02 did not have a material 

impact on our consolidated financial position, results of operation or cash flows. 

In January 2013, FASB issued ASU No. 2013-01, which is included in ASC 210, “Balance Sheet”, “Clarifying the Scope of Disclosures 

about Offsetting Assets and Liabilities” (“ASU No. 2013-01”). This update clarifies that the scope of ASU 2011-11: “Disclosures about 

Offsetting Assets and Liabilities” applies only to derivatives accounted for under ASC 815 “Derivatives and Hedging”, included bifurcated 

embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities lending transactions that are either offset in 

accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. ASU No. 

2013-01 is effective for fiscal years and interim periods within those years, beginning on or after January 1, 2013. Entities should provide the 

required disclosures retrospectively for all comparative periods presented. The adoption of this guidance impacts presentation disclosures only 

and will not have an impact on our consolidated financial position, results of operation or cash flows. 

In February 2013, FASB issued ASU No. 2013-02, which is included in ASC 220, “Comprehensive Income”, “Reporting of Amounts 

Reclassified Out of Accumulated Other Comprehensive Income” (“ASU NO. 2013-02”). This update requires an entity to provide information 

about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, 

either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other 

comprehensive income by the respective line items of net income but only if the amount reclassified is required under USGAAP to be 

reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under USGAAP to be reclassified 

in their entirety to net income, an entity is required to cross-reference to other disclosures required under USGAAP that provide additional 

detail about those amounts. The amendments of ASU No. 2013-02 do not change the current requirements for reporting net income or other 

comprehensive income in financial statements. ASU No. 2013-02 is effective for fiscal years and interim periods within those years, beginning 

on or after December 15, 2012. Early adoption is permitted. The adoption of this guidance impacts presentation disclosures only and will not 

have an impact on our consolidated financial position, results of operation or cash flows. 

In February 2013, FASB issued ASU No. 2013-04, which is included in ASC 405, “Liabilities”, “Obligations Resulting from Joint and 

Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date”. This update provides guidance 

for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total 

amount of the obligation with the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance 

in USGAAP. Examples of obligations within the scope to ASU No. 2013-04 include debt arrangements, other contractual obligations, and 

settled litigation and judicial rulings. ASU No. 2013-04 is effective for fiscal years and interim periods within those years beginning after 

December 5, 2013. Entities should provide the required disclosures retrospectively for all comparative periods presented. The adoption of this 

guidance impacts presentation disclosures only and will not have an impact on our consolidated financial position, results of operation or cash 

flows. 

In March 2013, FASB issued ASU No. 2013-05, which is included in ASC 830, “Foreign Currency Matters”, “Parent’s Accounting for 

the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an 

Investment in a Foreign Entity” (“ASU 2013-05”). This update resolves the diversity in practice regarding the release into net income of the 

cumulative translation adjustment upon derecognition of a subsidiary or group of assets within a foreign entity. ASU No. 2013-05 is effective 

for fiscal years and interim periods within those years beginning after December 5, 2013. ASU No. 2013-05 is not expected to have a material 

impact on our consolidated financial position, results of operation or cash flows. 

Off-Balance Sheet Arrangements 
We do not have any off-balance sheet arrangements. 

 

We are exposed to market risk from adverse changes in oil and natural gas prices and foreign exchange risk, as discussed below. 

Oil Prices 

Oil and natural gas prices historically have been volatile, and this volatility is expected to continue. Prevailing prices for such 

commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors 

beyond our control. Being primarily a crude oil producer, we are more significantly impacted by changes in crude oil prices than by changes in 

natural gas prices. As an independent oil producer, our revenue, other income and profitability, reserve values, access to capital and future rate 

of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. 

We currently do not have any oil production that is hedged. While hedging limits the downside risk of adverse price movements, it 

may also limit future revenues from favorable price movements. 

 

49 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk 
Table of Contents 

Interest Rates 

Total long-term debt at December 31, 2012 consisted of $75.0 million of fixed-rate senior unsecured notes maturing in 2014. A 

hypothetical 10 percent adverse change in the prime rate would not have a material effect on our results of operations for the year ended 

December 31, 2012. 

Foreign Exchange 

The Bolivar is not readily convertible into the U.S. Dollar. We have not utilized currency hedging programs to mitigate any risks 

associated with operations in Venezuela, and, therefore, our financial results are subject to favorable or unfavorable fluctuations in exchange 

rates and inflation in that country. Venezuela has imposed currency exchange controls. See Item 7. Management’s Discussion and Analysis of 

Financial Condition and Results of Operations, Effects of Changing Prices, Foreign Exchange Rates and Inflation above. 

 

The information required by this item is included herein on pages S-1 through S-68. 

 

None. 

 

Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures that are designed to 

ensure the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, 

summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and 

communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely 

decisions regarding required disclosure. 

Management of the Company, with the participation of our principal executive officer and principal financial officer, evaluated the 

effectiveness of the Company’s disclosure controls and procedures. Based on their evaluation as of December 31, 2012, our principal executive 

officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) 

under the Exchange Act) were not effective because of the material weaknesses in our internal control over financial reporting described below. 

Notwithstanding this determination, our management concluded that the consolidated financial statements (as restated for 2010 and 2011) in 

this Annual Report on Form 10-K fairly present, in all material respects, our financial position and results of operations and cash flows as of the 

dates and for the periods presented, in conformity with accounting principles generally accepted in the United States of America (“USGAAP”). 

Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and 

maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). Internal 

control over financial reporting is defined as a process designed by, or under the supervision of, the issuer’s principal executive and principal 

financial officer’s, or persons performing similar functions, and effected by the Company’s board of directors, management, and other 

personnel, to provide reasonable assurance regarding reliability of financial reporting and the preparation of financial statements for external 

purposes in accordance with generally accepted accounting principles and includes those policies and procedures which (a) pertain to the 

maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets of the Company, 

(b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with 

generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of 

management and the board of directors, and (c) provide reasonable assurance regarding prevention or timely detection of unauthorized 

acquisition, use or disposition of assets that could have a material effect on the financial statements. A material weakness is a deficiency, or a 

combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement 

of the annual or interim financial statements will not be prevented or detected on a timely basis. 

Under the supervision and with the participation of our management, including our principal executive officer and principal 

financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control 

Integrated Framework issued by the Committee of Sponsoring Organizations of The Treadway Commission. Based on our evaluation under the 

Internal Control Integrated Framework, our management concluded that our internal control over financial reporting was not effective as of 

December 31, 2012 as a result of material weaknesses described below. 

 

50 

Item 8. Financial Statements and Supplementary Data 

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

Item 9A. Controls and Procedures 
Table of Contents 

Sufficient Complement of Accounting and Financial Reporting Resources 

In certain areas, we did not maintain a sufficient complement of resources with an appropriate level of accounting knowledge, 

experience and training commensurate with our financial reporting requirements. This limited our ability, in certain areas, to ensure the 

necessary consistent communication, reinforcement, and application of accounting policies to make appropriate accounting and disclosure 

decisions. This material weakness contributed to the material weaknesses set forth below. 

Accounting for Certain Transactions for Oil and Gas Properties 

We did not maintain effective internal control over the accuracy, valuation and application of USGAAP related to capitalization, 

classification, and impairment of certain costs related to oil and gas properties. Specifically, effective controls were not designed or effectively 

operating to review the nature and classification of costs to be capitalized to oil and gas properties which impacts the accurate calculation of oil 

and gas property impairments. This control deficiency resulted in the misstatement of oil and gas properties, exploration expense, and related 

financial statement disclosures. 

Accounting for Income Taxes 

We did not maintain effective controls over the completeness, accuracy, presentation and disclosure of our accounting for income 

taxes, including income tax expense and income tax assets and liabilities. Specifically, we did not maintain effective controls to (1) document 

our analysis, considerations and evaluation of relevant facts related to our accounting judgments for income taxes, (2) account for uncertain tax 

positions, and (3) ensure appropriate recording and presentation of our net operating losses and associated valuation allowance and related 

footnote disclosures. This control deficiency resulted in the misstatement of income tax expense, deferred tax assets, our valuation allowance, 

related financial statement disclosures, and our financial statement schedule. 

Financial Reporting Process 

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

material weaknesses: 

 

 

 

Additionally, each of the control deficiencies described above could result in a misstatement of the aforementioned account 

balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements and financial 

statement schedule that would not be prevented or detected. Certain of these material weaknesses resulted in errors which required the 

restatement of our annual consolidated financial statements for the years ended December 31, 2010 and 2011 and the unaudited interim 

consolidated financial statements for all quarters in 2011 and the first three quarters of 2012 and also resulted in recorded audit adjustments for 

the fourth quarter and annual period ended December 31, 2012. 

The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by 

PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. 

Remediation Plan. In response to the identified material weaknesses, our management, with oversight from our Audit Committee 

will dedicate appropriate resources to remediate the material weaknesses described above. Until the remediation steps set forth below are fully 

implemented, the material weaknesses described above will continue to exist. 

 

51 

 

(a) We did not maintain effective controls over segregation of duties related to certain system access rights and the recording and 

review of journal entries for validity, accuracy, and completeness for substantially all significant accounts. Specifically, certain 

individuals have incompatible access rights within key IT systems and certain accounting personnel have the ability to prepare and 

post journal entries without an independent review that is designed with sufficient rigor and precision to prevent or detect an error. 

 

(b) We did not maintain effective controls over the preparation and review of certain classification and disclosure matters impacting the 

financial statements and related notes. Specifically, controls are not designed and operating effectively to accumulate and review all 

information required to ensure complete, accurate, and proper presentation of the statement of cash flows and financial statement 

disclosures. This control deficiency resulted in the misstatement of cash provided by or used in investing and operating activities 

and related financial statement disclosures and the misstatement of segment information. 

 

(c) We did not maintain effective controls over significant and complex debt and equity transactions. Specifically, controls were not 

designed and operating effectively to ensure completeness and accuracy over the identification, evaluation, analysis and recording 

of significant and complex debt and equity transactions and the associated financial statement impact. This control deficiency 

resulted in the misstatement of debt, additional paid-in capital, debt conversion expense, interest expense, unrealized gain (loss) on 

warrant derivatives, loss on extinguishment of debt and related financial statement disclosures. 
Table of Contents 

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

 

 

 

 

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

 

 

 

 

 

Management is taking the following actions to remediate the material weaknesses related to our Financial Reporting Process and 

complement of accounting and financial reporting resources: 

 

 

 

 

 

 

Inherent Limitations of Internal Controls. Internal control over financial reporting has inherent limitations. Internal control over 

financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting 

from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. 

Because of such limitations, there is a risk that material misstatements will not be prevented or detected on a timely basis by internal control 

over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to 

design into the process safeguards to reduce, though not eliminate, this risk. 

Changes in Internal Control over Financial Reporting. There have been no changes in internal control over financial reporting 

during the quarter ended December 31, 2012 that have materially affected or are reasonably likely to materially affect that Company’s internal 

control over financial reporting. 

 

None. 

 

52 

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

 • Train the accounting staff on the above policies and procedures. 

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

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

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

 

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

considerations and conclusions. 

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

 

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

statement schedule. 

 • Supplement existing resources with additional personnel and additional training. 

 

• Implement a sufficiently-designed control that is intended to ensure functions are appropriately segregated and that all journal 

entries are reviewed by an appropriate person. 

 

• Modify the system access of individuals with incompatible responsibilities and/or design compensating controls that operate at the 

appropriate level of precision to address the associated conflict. 

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

 

• Redesign certain entity-level monitoring controls and certain transaction level controls in order to achieve the level of precision and 

operating effectiveness required by management. 

 

• Redesign the controls over significant and complex debt and equity transactions to ensure appropriate identification, evaluation, 

analysis and recording of such transactions. 

 

• Supplement our accounting department with additional personnel and provide additional training to our personnel regarding the 

application of USGAAP. 

Item 9B. Other Information 
Table of Contents 

PART III 

 

DIRECTORS 

There are currently seven members of our Board of Directors (the “Board”), each of whom has been nominated for reelection to the 

Board this year and will stand for election at our annual meeting. Information regarding the business experience of each nominee is provided 

below. All directors are elected annually to serve until the next annual meeting and until their respective successors are elected. 

When considering whether directors and nominees have the experience, qualifications, attributes and skills, taken as a whole, to enable 

the Board to satisfy its oversight responsibilities effectively in light of the Company’s business and structure, the Nominating and Corporate 

Governance Committee, which is a Committee of the Board responsible for recommending director candidates to be nominated by the Board, 

and the Board focused primarily on the information discussed in each of the directors’ individual biographies set forth below. 

In particular, with regard to Messrs. Chesebro’, Edmiston, Irelan and Stinson and Dr. Effimoff, the Nominating and Corporate 

Governance Committee considered their strong backgrounds in the oil and gas sector, believing that their individual experiences at 

management levels with large multinational corporations engaged in oil and gas exploration and production are invaluable in evaluating the 

performance of management and other aspects of the Company. The Nominating and Corporate Governance Committee considered 

Mr. Murray’s individual experiences at management levels with large multinational corporations engaged in oil and gas services as a valuable 

complement to the experiences of the other directors. Additionally, the Nominating and Corporate Governance Committee considered the 

engineering education and experiences of Messrs. Chesebro’, Edmiston, Stinson and Irelan and Dr. Effimoff important to understand the goals 

and challenges of the Company and to effectively advise the direction of the Company in the oil and gas industry. With respect to Messrs. 

Hardee and Murray, the Nominating and Corporate Governance Committee considered their significant experience, expertise and background 

with regard to financials and financial and accounting matters and business management. The Nominating and Corporate Governance 

Committee also considered the broad perspective brought by Mr. Hardee’s and Dr. Effimoff’s experiences in consulting to clients and, with 

respect to Messrs. Hardee and Murray, serving in directorships in many diverse industries. The Nominating and Corporate Governance 

Committee also considered the many years of experience with the Company and in the industry represented by Mr. Edmiston, our Chief 

Executive Officer (“CEO”). Additionally, with respect to Messrs. Chesebro’, Edmiston, Irelan, Murray and Stinson and Dr. Effimoff, the 

Nominating and Corporate Governance Committee considered their experience in international business vital to the Company’s global strategy. 

With respect to Mr. Stinson, the Nominating and Corporate Governance Committee believes that his experience in governmental relations on 

an international level provides valuable insight to assist management in establishing and maintaining their relationships with foreign 

governments, which is a primary focus of the Company. 

 

 

53 

Item 10. Directors, Executive Officers and Corporate Governance 

Stephen D. Chesebro’

Appointed Director in October 2000 

Age 71 

 

Mr. Chesebro’ has served as the Chairman of the Board of Harvest 

since 2001. From December 1998 until he retired in 1999, he 

served as President and Chief exploration and production company 

that was formerly a business unit of Pennzoil Company. From 

February 1997 to December 1997, Mr. Chesebro’ served as Group 

Vice President – Oil and Gas and from December 1997 until 

December 1998 he served as 
Table of Contents 

 

54 

 

President and Chief Operating Officer of Pennzoil Company, an 

integrated oil and gas company. From 1993 to 1996, Mr. Chesebro’

was Chairman and Chief Executive Officer of Tenneco Energy. 

Tenneco Energy was part of Tenneco, Inc., a worldwide 

corporation that owned diversified holdings in six major industries. 

Mr. Chesebro’ is an advisory director to Preng & Associates, an 

executive search consulting firm. In 1964, Mr. Chesebro’ 

graduated from the Colorado School of Mines. He was awarded the 

school’s Distinguished Achievement Medal in 1991 and received 

his honorary doctorate from the institution in 1998. He currently 

serves on the school’s visiting committee for petroleum 

engineering and is a member of the Colorado School of Mines 

Foundation Board of Governors. In 1994, Mr. Chesebro’ was the 

first American awarded the H. E. Jones London Medal by the 

Institution of Gas Engineers, a British professional association. 

Since December 2005, he has served as the President of the 

Chesebro’ Foundation, Inc., a private charitable foundation 

incorporated in Delaware. 

James A. Edmiston 

Elected Director in May 2005 

Age 53 

 

Mr. Edmiston was elected President and Chief Executive Officer of 

Harvest on October 1, 2005. He joined the Company as Executive 

Vice President and Chief Operating Officer on September 1, 2004. 

Prior to joining Harvest, Mr. Edmiston was with Conoco and 

ConocoPhillips for 22 years in various management positions 

including President, Dubai Petroleum Company (2002—2004), a 

ConocoPhillips affiliate company in the United Arab Emirates, and 

General Manager, Petrozuata, C.A., in Puerto La Cruz, Venezuela 

(1999—2001). Prior to 1999, Mr. Edmiston also served as Vice 

President and General Manager of Conoco Russia and then as 

Asset Manager of Conoco’s South Texas Lobo Trend gas 

operations. Mr. Edmiston earned a Bachelor of Science degree in 

Petroleum Engineering from Texas Tech University and a Masters 

of Business Administration from the Fuqua School of Business at 

Duke University. Mr. Edmiston was inducted into the Petroleum 

Engineering Academy and was recognized as a Distinguished 

Engineer by Texas Tech College of Engineering in 2009. Mr. 

Edmiston is a Member of the Society of Petroleum Engineers. 

Dr. Igor Effimoff 

Appointed Director in February 2008 

Age 67 

 

Dr. Igor Effimoff is founder and principal of a firm which provides 

upstream and midstream consulting services since 2005. From 

2002 until 2005 he was Chief Operating Officer for Teton 

Petroleum 
Table of Contents 

 

55 

 

Company. Between 1996 and 2001, he was President of Pennzoil 

Caspian Corporation, managing their interests in the Caspian 

Region. Between 1994 and 1996 he was the Chief Executive 

Officer of Larmag Energy, NV, a privately held Dutch oil and gas 

production company with its primary assets in the Caspian Sea. He 

has served in senior executive roles with Ashland Exploration Inc., 

Zilkha Energy Company and Kriti Exploration, Inc. Dr. Effimoff 

has authored numerous technical and business articles. He is a 

member of American Association of Petroleum Geology, the 

Society of Petroleum Engineers, the Society of Exploration 

Geophysicists and the Geological Society of America. Dr. Effimoff 

served on the audit and compensation committees of TrueStar 

Petroleum Corporation in 2007. He currently serves on the board 

of IPC Oil and Gas Holdings Ltd. He has a Doctorate in Geology 

from the University of Cincinnati and completed the Harvard 

Advanced Management Program. 

H. H. Hardee 

Appointed Director in October 2000 

Age 58 

 

Mr. Hardee is a Senior Vice President—Financial Advisor with 

RBC Wealth Management, since 1994. From 1991 through 1994, 

Mr. Hardee was a Senior Vice President with Kidder Peabody. 

From 1977 through 1991, Mr. Hardee was a Senior Vice President 

at Rotan Mosle/Paine Webber Inc. Mr. Hardee was named as one 

of America’s best financial advisors for 2009, 2010, 2011 and 2012 

by Barron’s financial newspaper and by Reuters AdvicePoint. 

Furthermore, Mr. Hardee has been recognized by NABCAP, the 

National Association of Board Certified Advisory Practices, as a 

Premier Wealth Advisor. He currently advises/manages over $400 

million in assets. Mr. Hardee’s expertise is advising high net worth 

individuals and small to mid-sized corporations. Mr. Hardee is a 

former director of the Bank of Almeda and Gamma Biologicals. He 

is also a former limited partner and advisory director of the 

Houston Rockets of the National Basketball Association. Mr. 

Hardee has a finance degree from the McCombs School of 

Business at the University of Texas. He has earned an Accredited 

Wealth Management designation through the Estate and Wealth 

Strategies Institute of Michigan State University. Mr. Hardee is a 

National Association of Corporate Directors (“NACD”) Board 

Leadership Fellow. He has demonstrated his commitment to 

boardroom excellence by completing NACD’s comprehensive 

program of study for corporate directors. He supplements his skill 

sets through ongoing engagement with the director community and 

access to leading practices. 
Table of Contents 

 

56 

Robert E. Irelan 

Appointed Director in February 2008 

Age 66 

 

Mr. Irelan has over 37 years of experience in the oil and gas 

industry. He retired from Occidental Petroleum as Executive Vice 

President of Worldwide Operations in April 2004, having started 

there in 1998. Prior to Occidental Petroleum, Mr. Irelan held 

various positions at Conoco, Inc. from 1967 until 1998. Upon his 

retirement he opened his own company, Naleri Investments LLC. 

He also partnered in several entrepreneurial ventures including 

Rapid Retail Solutions LLC, BISS Product Development LLC and 

All About Baby LLC. Mr. Irelan earned his Professional 

Engineering degree in Petroleum Engineering from Colorado 

School of Mines. He also has advanced studies in Mineral 

Economics. He was awarded the Distinguished Achievement 

Award from the school in 1998. 

Patrick M. Murray 

Appointed Director in October 2000 

Age 70 

 

In 2007, Mr. Murray retired from Dresser, Inc. He had been the 

Chairman of the Board and Chief Executive Officer since 2004. 

Dresser, Inc. is an energy infrastructure and oilfield products and 

services company. From 2000 until becoming Chairman of the 

Board, Mr. Murray served as President and Chief Executive 

Officer of Dresser, Inc. Mr. Murray was President of Halliburton 

Company’s Dresser Equipment Group, Inc., Vice President, 

Strategic Initiatives of Dresser Industries, Inc. and Vice President, 

Operations of Dresser, Inc. from 1996 to 2000. Mr. Murray has 

also served as the President of Sperry-Sun Drilling Services from 

1988 through 1996. Mr. Murray joined NL Industries in 1973 as a 

Systems Application Consultant and served in a variety of 

increasingly senior management positions. Mr. Murray currently 

serves on the board and audit committee of Precision Drilling 

Corporation, a publicly-held contract drilling company. Mr. 

Murray is also on the board of the World Affairs Council of Dallas 

Fort Worth. He is on the board of advisors for White Deer Energy, 

the Maguire Energy Institute at the Edwin L. Cox School of 

Business, Southern Methodist University and a member of the 

Board of Regents of Seton Hall University. Mr. Murray holds a 

Bachelor of Science degree in Accounting and a Master of 

Business Administration from Seton Hall University. He served for 

two years in the U.S. Army as a commissioned officer. 
Table of Contents 

EXECUTIVE OFFICERS 

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

 

 

Stephen C. Haynes has served as our Vice President, Chief Financial Officer and Treasurer since May 19, 2008. Mr. Haynes performed 

various financial consulting engagements from January 1, 2008 until his 

 

57 

J. Michael Stinson 

Appointed Director in November 2005 

Age 69 

 

From September 2006 to December 2011, Mr. Stinson was 

Chairman of TORP Terminal LP, the U.S. unit of a Norwegian 

LNG technology company. From 2004 until November of 2009, he 

served as a director of Enventure Global Technology, Inc., an oil 

equipment company, most recently as the Chairman of its Audit 

and Finance Committee. From January 2005 until November 2009, 

he was Chairman of the Board of Paulsson Geophysical Services, 

Inc., a vertical seismic profiling technology company. From 

February through August 2004, Mr. Stinson served with the U.S. 

Department of Defense and the Coalition Provisional Authority as 

Senior Advisor to the Iraqi Ministry of Oil. From 1965 to 2003, 

Mr. Stinson was with Conoco and ConocoPhillips in a number of 

assignments in operations and management. His last position at 

ConocoPhillips was as Senior Vice President, Government Affairs 

in which he was responsible for government relations with 

particular emphasis on developing and facilitating international 

business development opportunities in various countries. Previous 

positions included Senior Vice President – Business Development, 

Vice President – Exploration and Production, Chairman and 

Managing Director of Conoco (UK) Limited, Vice 

President/General Manager of International Production for Europe, 

Africa and the Far East and President and Managing Director of 

Conoco Norway, Inc. Mr. Stinson earned a Bachelor of Science 

degree in Industrial Engineering from Texas Tech University and a 

Master of Business Administration from Arizona State University. 

He is a member of the Society of Petroleum Engineers and the 

American Association of Petroleum Geologists. 

Name Age Position 

James A. Edmiston * 53 President and Chief Executive Officer 

Stephen C. Haynes 56 Vice President, Finance, Chief Financial Officer and Treasurer 

Keith L. Head 55 Vice President, General Counsel and Corporate Secretary 

Karl L. Nesselrode 55 Vice President, Engineering & Business Development 

Robert Speirs 57 Senior Vice President, Eastern Operations 

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

appointment with Harvest. Previously, he served as Chief Financial Officer for Cygnus Oil and Gas Corporation for the period February 1, 

2006 through December 31, 2007. Before joining Cygnus, Mr. Haynes was the Corporate Controller with Carrizo Oil and Gas for the period 

January 1, 2005 through January 31, 2006. Mr. Haynes served as an independent consultant from March 2001 through end of 2004. From 

March 1990 through December 2000, Mr. Haynes served in a series of increasing responsibilities in international managerial and executive 

positions with British Gas, culminating in his appointments as Vice President—Finance of Atlantic LNG, a joint venture of British Gas and 

several industry partners in Trinidad and Tobago. Mr. Haynes is a Certified Public Accountant, holds a Master of Business Administration 

degree with a concentration in Finance from the University of Houston and a Bachelor of Business Administration degree in Accounting from 

Sam Houston State University. He also attended the Executive Development Program at Harvard University. 

Keith L. Head has served as our Vice President, General Counsel and Corporate Secretary since May 7, 2007. He joined Texas Eastern 

upon graduation from law school and remained with the same organization through mergers with Panhandle Eastern, Duke Energy Corporation 

and Cinergy Corp. Mr. Head held various business development positions with Duke Energy Corporation from 1995 to 2001. His corporate 

development work included the identification, evaluation and negotiation of acquisitions in Latin America, North America and the United 

Kingdom. Mr. Head was Senior Vice President and General Counsel at Duke Energy North America from 2001 to 2004 and Associate General 

Counsel of Duke Energy Corporation from 2004 through December 2006. After leaving Duke Energy, Mr. Head joined Harvest in May 2007. 

He currently serves on two non-profit boards: MentorCONNECT and the Texas Accountants and Lawyers for the Arts. He is also a board 

member of the Houston chapter of The General Counsel Forum. Mr. Head holds a Bachelor of Science degree in Business Administration from 

the University of North Carolina. He received both a Juris Doctorate and Master of Business Administration from the University of Texas in 

1983. 

Karl L. Nesselrode has served as Vice President, Engineering and Business Development of the Company since November 17, 2003. 

From August 9, 2007 to August 2, 2010, he accepted a long-term secondment to Petrodelta as its Operations and Technical Manager while 

remaining an officer of Harvest. From February 2002 until November 2003, Mr. Nesselrode was President of Reserve Insights, LLC, a strategy 

and management consulting company for oil and gas. He was employed with Anadarko Petroleum Corporation as Manager Minerals and 

Special Projects from July 2000 to February 2002. Mr. Nesselrode served in various managerial positions with Union Pacific Resources 

Company from August 1979 to July 2000. Mr. Nesselrode earned a Bachelor of Science in Petroleum Engineering from the University of Tulsa 

in 1979 and completed the Harvard Business School Program for Management Development in 1995. 

Robert Speirs has served as Senior Vice President, Eastern Operations since July of 2011. Prior to his promotion, his title had been Vice 

President, Eastern Operations since December 6, 2007. He joined Harvest in June 2006 as President and General Manager, Russia. Previously 

Mr. Speirs was President of Marathon Petroleum Russia and General Director of their wholly-owned subsidiary, KhantyMansciskNefte Gas 

Geologia from March 2004 through May 2006. Prior to joining Marathon, Mr. Speirs was Executive Vice President of YUKOS EP responsible 

for engineering and construction from June 2001. During both these periods, Mr. Speirs spent considerable time in West Siberia where he 

oversaw substantial increases in production at both companies. From November 1997 until March 2001, Mr. Speirs resided in Jakarta where he 

served as President of Premier Oil Indonesia. During this period, Premier was active in all phases of the Upstream business, culminating in the 

commissioning of the West Natuna Gas Project. Prior to 1997, Mr. Speirs was with Conoco for 21 years in various leadership positions in the 

US, UK, Russia, Indonesia, Singapore and Dubai, UAE. Mr. Speirs earned a Bachelor of Science degree with Honors in Engineering Science 

from the University of Edinburgh. He also attended the Executive Management Program at INSEAD. 

SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE 

Section 16(a) of the Exchange Act (“Section 16(a)”) requires our directors, executive officers and beneficial holders of more than 10% of 

our common stock to file reports with the SEC regarding their ownership and changes in ownership of our stock. Based solely upon our review 

of SEC Forms 3, 4 and 5 and any amendments thereto furnished to us, to our knowledge, during fiscal year 2012, our officers, directors and 

10% stockholders complied with all Section 16(a) filing requirements. In making this statement, we have relied upon the written 

representations of our directors and officers. 

 

58 
Table of Contents 

 

CODE OF BUSINESS CONDUCT AND ETHICS 

The Board has adopted a Code of Business Conduct and Ethics, which applies to all of our directors, officers and employees. The Board 

last amended the Code of Business Conduct and Ethics in December 2010. The Board has not granted any waivers to the Code of Business 

Conduct and Ethics. 

The Code of Business Conduct and Ethics is accessible on our website under the Corporate Governance section at 

http://www.harvestnr.com . Any amendments to or waivers of the Code of Conduct and Business Ethics will also be posted on our website. 

AUDIT COMMITTEE 

The Board has a standing Audit Committee. The Audit Committee assists the Board in its oversight of: our accounting and financial 

reporting policies and practices; the integrity of our financial statements; the independent registered public accounting firm’s qualifications, 

independence and objectivity; the performance of our internal audit function and our independent registered public accounting firm; and our 

compliance with legal and regulatory requirements. The Audit Committee acts as a liaison between our independent registered public 

accounting firm and the Board, and it has the sole authority to appoint or replace the independent registered public accounting firm and to 

approve any non-audit relationship with the independent registered public accounting firm. Our internal auditor and the independent registered 

public accounting firm report directly to the Audit Committee. 

Dr. Effimoff and Messrs. Hardee, Murray and Stinson are members of the Audit Committee. The Board has determined that each member 

of the Audit Committee meets the independence standards of the SEC’s requirements, the rules of the NYSE and the Company Guidelines for 

Corporate Governance, which is an internal policy that requires independent directors comprise a majority of the Board and that the Chairman 

of the Board be elected from the independent directors. No member of the Audit Committee serves on the audit committee of more than three 

public companies. The Board has further determined that each member of the Audit Committee is financially literate and that Mr. Murray 

qualifies as an audit committee financial expert, as defined in Item 407(d)(5) of SEC Regulation S-K. Information on the relevant experience of 

Mr. Murray is set forth above under the section entitled “Directors.” 

 

COMPENSATION DISCUSSION AND ANALYSIS 

Introduction 

Harvest’s Compensation Discussion and Analysis describes the Company’s compensation program for the executive officers identified in 

the Summary Compensation Table. Throughout this proxy statement we refer to these individuals as “named executive officers.” They are 

James A. Edmiston, President and CEO; Stephen C. Haynes, Vice President, Chief Financial Officer and Treasurer; Robert Speirs, Senior Vice 

President – Eastern Operations; Karl L. Nesselrode, Vice President – Engineering & Business Development; and Keith L. Head, Vice President 

– General Counsel and Corporate Secretary. 

 

59 

Item 11. Executive Compensation 
Table of Contents 

Summary of Executive Compensation Decisions Made in 2012/2013 

During 2012, our executive compensation decisions included: 

 

 

 

 

 

 

 

During 2013, our executive compensation decisions included: 

 

Company Overview and Compensation Objectives 

As a Company, our focus is on acquiring exploration, development, and producing properties in proven and active hydrocarbon systems. 

We operate from our Houston, Texas headquarters with regional/technical offices in the United Kingdom and Singapore and field offices in 

Jakarta, Indonesia; Port Gentil, Gabon; and Muscat, Oman. 

In 2012, we achieved the following results: 

 

 

 

 

 

 

 

60 

 

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

2012; 

 

• In addition to individual performance objectives, the Human Resources Committee, which is a Committee of the Board that is 

responsible for establishing and recommending to the Board all elements of executive and Board compensation (the “HR 

Committee”), established Company annual incentive performance measures as follows: 

 • Total Shareholder Return (weight 60%) 

 • Reserve Additions/Production (weight 30%) 

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

 

• Annual cash incentive awards were paid in February 2013. The CEO received 137% of his target incentive and the other named 

executive officers also received an average of 137% of their target incentives. This reflects an increase in the annual incentive target 

for the named executives to 60% of base salary. Since 2008, we have been consistently low for this benchmark. This increase was 

approved at the February 2013 HR Committee meeting and effective for the 2012 incentive awards. 

 

• Long-term incentive awards were paid with approximately 30% restricted stock and 70% stock options valued at the closing stock 

price on May 17, 2012. 

 

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

2013. 

 

• Increased gross production in Venezuela to 13.2 million barrels of oil or an average of 36,979 barrels of oil per day, an increase of 

14.7% over 2011; 

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

 

• Completed drilling of the Dussafu Tortue well in the fourth quarter of 2012 and announced an oil discovery of approximately 42 

feet of pay in the Gamba formation and 123 feet of pay in the Dentale formation. 

 

• Received a four-year extension by the Indonesian government until January 2017 for the Budong Budong Block and agreed with 

our partner to assume operatorship of the block. 

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

 

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

Venezuelan Assets. 
Table of Contents 

The following graphs highlight the Company results for 2012: 

 

 

 

 

Note: Annual Net Production and Net Proved and Probable Reserves for 2010 include production and reserves from the Utah asset which were 

sold in 2011. (MBOE = Thousand Barrels of Oil Equivalent) 

The HR Committee has the discretion to exercise their judgment in weighing the achievement of specific performance measures. For 

2012, it considered total shareholder return, reserves, social responsibility/governance and safety as well as strategic individual objectives for 

the named executive officers. Total shareholder return (“TSR”) was up 22.9% in 2012 and the Company remained in the top quartile of its Peer 

Group over a three-year period from 2010—2012. Proved and probable reserves were down slightly by 4% from the prior year. We calculate 

TSR as year-end share price minus beginning year share price divided by beginning year share price. Annual net production in 2012 was up 

14% over the prior year. Companywide health and safety programs were implemented in 2012. There were no Foreign Corrupt Practices Act 

(“FCPA”) incidents in 2012. Ethics and compliance guidelines were revised in 2012, and there was one contractor lost time accident in 2012. 

Given the operational and technical challenges faced by the Company, the Committee determined that the management team effectively 

managed the exploration assets we controlled and operated during the year. 

Compensation Philosophy 

Our compensation philosophy is to offer a competitive total compensation package to enable us to attract, motivate and retain key 

executives. Our compensation objectives include: 

 

 

 

61 

 

• Offering total compensation that is competitive with the select peer group of globally-focused oil and gas companies with which we 

compete for executive talent; 

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

 

The HR Committee oversees the development and execution of our compensation program. The HR Committee annually reviews our 

compensation philosophy and tests its ability to promote meeting the objectives stated above. The HR Committee recommends compensation 

for the named executive officers, short-term cash bonuses, long-term cash and non-cash compensation and submits its recommendations to the 

Board for approval. Three independent directors comprise the HR Committee. The HR Committee meets as needed, but no less than quarterly 

to review compensation and benefit programs with management. It subsequently approves any changes. Our Human Resources, Accounting 

and Legal Department employees handle the day-to-day design and administration of employee compensation and benefit programs available 

to our employees. 

Setting Executive Compensation 

Our compensation program consists of several forms of compensation: base salary, annual performance-based incentive awards, longterm incentives and personal benefits. Base salary and annual performance-based incentive awards are generally cash-based. Long-term 

incentives typically consist of stock options, stock appreciation rights, restricted stock units and/or restricted stock awards. The Committee 

reviews the compensation recommendations from the CEO and our independent consultants’ advice on competitive trends regarding base 

salary, annual incentive awards and long-term incentives. The Committee exercises its collective judgment in establishing executive 

compensation based on performance, compensation history and market information. The recommendations are then made to the full Board for 

its approval. 

The Role of the Compensation Consultant—Compensation Consultant Independence 

In 2012, the HR Committee engaged Frost Human Resource Consulting (“Frost HR Consulting”), as the HR Committee’s independent 

compensation consultant, to benchmark our executive officer compensation levels with similar positions in our industry peer group. The 

Committee reviews the relationship annually for any conflicts of interest. To ensure Frost HR Consulting’s independence: 

 

 

 

 

 

 

 

 

Peer Group and Compensation Surveys 

The HR Committee considers market information from compensation surveys and peer company proxy statements when determining 

compensation for each of the executive officers. In May 2012, the HR Committee reviewed proxy statement data from a peer group of 

companies. The surveys used for benchmarking included: 

 

 

62 

 

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

incentives; and 

 • Providing incentives to executives for achieving challenging corporate goals. 

 • The HR Committee directly retained and has the authority to terminate Frost HR Consulting. 

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

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

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

 

• Interactions between Frost HR Consulting and management generally are limited to data gathering and discussions regarding 

information that has or will be presented to the HR Committee. 

 • Frost HR Consulting has procedures in place to prevent conflicts of interest. 

 • Frost HR Consulting does not have any business or personal relationship with any member of management or the HR Committee. 

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

 • Towers Watson 2011 Top Management Compensation Survey 
Table of Contents 

 

Each year, the HR Committee reviews the composition of the peer group and the compensation paid at these companies, as well as their 

corporate performance and other comparative factors in determining the appropriate compensation levels for our executives. No company in 

our peer group shares our unique risk profile, which is a function of our portfolio of producing assets and exploratory prospects, as well as the 

regulatory and political environments in which we operate. Therefore, the HR Committee uses its judgment and business experience in addition 

to the peer group data in determining executive compensation. 

The HR Committee selects peer companies for their shared similarities, including a common industry oil exploration focus, assets, market 

capitalization and enterprise value, among other factors. Revenue at the peer companies ranges from $35 million to $423 million for 2012 

versus $405 million for Harvest, which is our 32% interest of gross revenue from oil sales in our unconsolidated affiliate, Petrodelta, S.A. Our 

peer companies typically compete with us for executive talent. Our current industry peer group consists of the following companies: 

 

For 2012, Frost HR Consulting benchmarked the 25th, 50th and 75th percentiles for the data sources mentioned above to provide the HR 

Committee with an understanding of competitive pay practices. These surveys, equally weighted with the proxy data, consider each element of 

compensation and are collectively referred to as the “market data” throughout this Compensation Discussion and Analysis. Frost HR 

Consulting also provides the HR Committee with advice on equity incentive compensation trends, including types and value of awards being 

used by other public companies. 

The Role of the Executives in Human Resources Committee Meetings 

The HR Committee invites our CEO, Vice President, Administration and Human Resources and Vice President, General Counsel and 

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

and provides reports on plan administration and human resources policies and programs. The Vice President, General Counsel and Corporate 

Secretary provides legal advice on human resource matters. The CEO makes recommendations with respect to specific compensation decisions. 

The HR Committee, without management present, regularly meets in executive session and with its compensation consultant to review 

executive compensation matters including market data as well as peer group information. 

 

63 

 • William M. Mercer 2011 Energy Industry Compensation Survey 

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

• BPZ Resources, Inc. 

 

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

Resources, LLC) 

• Carrizo Oil and Gas Inc. 

 

• Halcón Resources, LLC (formerly Ram Energy Resources, 

Inc.) 

• Crimson Exploration Inc. • Gulfport Energy, Corp. 

• Endeavour International Corp. • Petroleum Development Corp. 

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

• FX Energy, Inc. 

 

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

Energy Corp) and 

• Gastar Exploration Ltd • VAALCO Energy, Inc. 
Table of Contents 

The CEO makes detailed recommendations to the HR Committee on performance evaluations, base salary changes, and both equity and 

annual incentive-based compensation for executive officers and senior management (other than the CEO). From time to time, the CEO and 

members of management are invited to participate in HR Committee meetings to provide information regarding our strategic objectives, 

financial performance and recommendations regarding compensation plans. Management may be asked to prepare information for any HR 

Committee meeting. Depending on the agenda for a particular meeting, these materials may include: 

 

 

 

 

 

 

Executive Compensation Components 

Our compensation program components are designed to reward executive officers’ contributions, while considering our specific operating 

situation and how they manage this situation consistent with our strategy. Factors considered in compensating our executives include individual 

experience, skill sets that are required for multi-national oil and gas operations and their proven record of performance. It is essential that we 

recruit and retain executives that understand the risk and complexity of global operations and our unique business strategy. All of our executive 

officers are mid-to-late career executives who have worked for larger energy companies and have alternatives; they decided to join the 

Company for the challenge and potential reward of working for a small, entrepreneurial organization. 

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

 

Base Salary 

We pay base salaries to our executive officers to compensate them for specific job responsibilities during the calendar year. In 

determining base salaries for our executive officers, the HR Committee considers market and competitive benchmark data for the executive’s 

level of responsibility targeting between the 50th and 75th percentile of executive officers in comparable companies, with variation based on 

individual executive skill sets. Compared to 2011 market data, our base salaries were between 95.6% and 106.2% of the target market median. 

For 2012, the HR Committee moved the Company’s salary management review to February from May to better address cash 

 • Reports on our strategic objectives; 

 • Financial reports; 

 • Reports on achievement of individual and corporate performance objectives; 

 

• Information regarding compensation programs and compensation levels for executive officers, directors and other employees at 

peer companies; 

 

• Information on the total compensation of the executive officers, including base salary, cash incentives, equity awards, and other 

compensation, and any amounts payable to the executive officers upon voluntary or involuntary termination or following a 

severance with or without a change in control; and 

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

Element Form of Compensation Purpose 

Base salary 

 

Cash 

 

Provide competitive, 

fixed 

compensation to 

attract and retain 

executive talent 

Annual performance based incentive awards 

 

Cash 

 

Create strong financial 

incentive for 

achieving financial 

and strategic 

successes 

Long-term incentive compensation 

 

Stock Options, Stock Appreciation Rights 

(SARs), Restricted Stock Units (RSU) and 

Restricted Stock Grants 

 

Provides alignment 

between executive 

and shareholder 

interests by rewarding 

executives for 

performance based on 

appreciation in the 

Company’s share 

price and for retaining 

executives 

Personal benefits 

 

Eligibility to participate in plans extends to 

all employees 

 

Broad-based employee 

benefits for 

health and welfare and 

retirement 
compensation decisions for both salaries and bonuses. Consequently, in March 2012 the CEO received an annualized salary increase for 

2012 of 1.8% and the other named executive officers received an average annualized increase of 3.3%. In March 2013, the CEO received an 

annual salary increase of 3.5% and the other named executive officers each received an annualized increase of 3.5% as well. 

 

64 
Table of Contents 

Annual Performance-Based Incentive Awards 

Each year, in addition to individual performance objectives, the HR Committee establishes Company performance measures for 

determining annual incentive awards as follows: 

 

 

 

These measures and their weightings are reviewed and modified, if appropriate, in light of changing Company priorities and strategic 

objectives. The corporate targets and weightings are set by the CEO and reviewed and approved by the HR Committee. The HR Committee 

focuses on these corporate goals in evaluating Company performance for the purpose of compensation. Individual performance results of the 

named executive officers are measured and assessed by the CEO. 

Among these corporate goals, Total Shareholder Return was weighted at 60%. In 2012, the Company realized a Total Shareholder Return 

of 22.9% placing it in the first quartile among its selected peer group. 

Reserves/Production/EMV was weighted at 30%. The primary measurement for this target is year-over-year P2 reserve additions; 

although 3P and contingent resources are also taken into consideration. For 2012, proved and probable reserves remained essentially flat over 

2011, net of 2012 production. However, production increased by 14.7% over 2011 at Petrodelta, our Venezuelan affiliate. 

Social Responsibility and Governance was weighted at 10% and is used at the discretion of the CEO and the Committee in deciding the 

final corporate rating. As expected, there were no violations of our FCPA policies or our Code of Business Conduct and Ethics. One of our 

contractors did experience a lost time accident in 2012. 

Individual performance and operational results were combined with the Company performance results and weighted equally to determine 

each executive’s final annual incentive award. Target award levels for annual incentives are set at 100% of base salary for the CEO and 60% of 

base salary for the other named executive officers. For 2012 performance, awarded in February 2013, the CEO received 137% of his bonus 

target as a performance-based incentive award. The other named executive officers individual awards ranged from 130% to 143% of their 

bonus targets. 

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

performance targets. 

We believe the Company should have the ability to recover compensation paid to executive officers and key employees under certain 

circumstances. As a result, the HR Committee adopted the following policy statement in 2011: 

“In the event the Board of Directors determines that any fraud or intentional misconduct caused or was a substantial contributing factor to 

a restatement of our financial statements, the Board of Directors may require reimbursement of any annual incentive compensation paid 

to an executive officer or certain other key employees to the extent the bonus paid exceeded what would have been paid had the financial 

results been properly reported. This policy will apply to all annual incentives paid after January 2012.” 

 

65 

Base SalaryAnnualized Mr. Edmiston Mr. Speirs Mr. Haynes Mr. Nesselrode Mr. Head 

2012 $550,000 $345,000 $295,000 $270,000 $265,000 

2013 $570,000 $360,000 $305,000 $280,000 $275,000 

 • Total Shareholder Return (weight 60%) 

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

 • Social Responsibility and Governance (including safety) (weight 10%) 
Table of Contents 

Long-Term Incentive Compensation 

On May 20, 2010, our stockholders approved the 2010 Long-Term Incentive Plan (the “2010 Plan”). This 2010 Plan allows us to recover 

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

Long-term incentive awards have been granted under our 2001, 2004, 2006 and 2010 Long Term Incentive Plans (“LTIPs”) and the 

awards are granted to our executive officers to align their personal financial interests with our stockholders. The LTIPs include provisions for 

stock options, stock appreciation rights, restricted stock, restricted stock units and cash awards. 

Our policy on stock awards is focused on determining the right mix of retention and ownership requirements to drive and motivate our 

executive officers’ behavior consistent with long-term interests of stockholders. The HR Committee is the administrator of our LTIPs and, 

subject to Board approval, has full power to determine the size of awards to our executives, to determine the terms and conditions of grants in a 

manner consistent with the LTIPs and to amend the terms and conditions of any outstanding award. 

The CEO presents individual stock award recommendations for executive officers to the HR Committee, and after review and discussion 

the HR Committee submits its recommendation to the Board for approval. The HR Committee’s policy is to grant awards on the date the Board 

approves them. Stock options and restricted stock will be granted once each calendar year on a predetermined date or at the effective date of a 

new hire or promotion, but not within six months of a previous award to the same individual. The price of options and the value of a restricted 

stock award issued to a new employee will be set at the closing price on the employee’s effective start date. The price of options and the value 

of a restricted stock award issued to an employee as a result of a promotion will be set at the closing price on the effective date of that 

promotion. Under no circumstances will a grant date be set retroactively. 

The Board has adopted stock retention guidelines as an additional means to promote ownership of stock by executive officers and 

directors. The guidelines apply to any award of restricted stock or options to purchase our stock granted to executive officers and directors after 

February 2004. Under these guidelines, an executive officer or director must retain at least 50% of the shares of restricted stock for at least 

three years after the restriction lapses. Consequences for failure to adhere to these guidelines shall be determined by the HR Committee in its 

discretion including, without limitation, actions with respect to future compensation and future grants of stock options or restricted stock and 

performance measures. Under our Insider Trading Policy, executive officers and directors are strictly prohibited from speculative trading in the 

Company’s securities, including short sales and buying or selling puts or calls on the Company’s securities. 

The long-term incentive awards for 2012 included stock options, stock appreciation rights (“SARs”), which can be settled as cash or 

equity, and restricted stock units (“RSUs”), which can be settled as cash or equity. This mix provides upside potential with the stock options 

and a more stable award in the form of restricted stock units. Of the total award value, 70% was allocated to options and 30% to restricted 

shares. 

Mix of Long Term Incentives A warded in 2012 

 

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

been granted: 

 

 

66 

 Options SARS RSU 

James A. Edmiston 130,000 219,000 79,000 

Stephen C. Haynes 37,000 61,000 23,000 

Keith L. Head 34,000 53,500 21,000 

Karl L. Nesselrode 34,000 56,000 21,000 

Robert Speirs 43,000 72,000 27,000 

Total available for grant as options 85,006 

 

 

Total available for grants as restricted stock 6 

 

 
Table of Contents 

Personal Benefits 

Our executive officers are covered under the same health and welfare plans, including our 401(k) plan, as all employees. The executive 

officers also receive supplemental life insurance to cover the risks of extensive travel required in conducting our global business. We pay 100% 

of all premiums for the following benefits for employees and their eligible dependents: 

 

 

 

 

 

We do not offer a pension plan or a non-qualified deferred compensation plan for executive officers or employees. In 2012, we did not 

offer perquisites to executive officers or other employees. We offer relocation and Foreign Service premiums to employees serving in an 

international location. The amount of the premium will vary depending upon the living conditions, political situation and general safety 

conditions of the international location. Expatriate employees are also provided housing and utilities allowances where applicable. They also 

receive a cost of living allowance to cover the differential between normal living expenses in the host and home countries and will continue to 

participate in the employee benefit plans available to home country employees. 

Total Direct Compensation 

Executive Compensation Compared to Market Data 

Compared to 2011 market data, total direct compensation ranged between 82% and 128% of the target market median for all named 

executive officers. In 2012, their compensation (after their March 2012 base salary increases) fell at the following percentiles: 

 

 

67 

 

• All employees are entitled to a medical benefit with unlimited maximum lifetime benefits, with an annual out-of-pocket deductible 

of $3,000 per individual and $9,000 per family. 

 

• Life and accidental death and dismemberment (“AD&D”) insurance equal to two times annual salary with a minimum of $200,000 

and a cap of $300,000 (or $400,000 with evidence of insurability), and additional coverage equal to five times annual salary 

($1.0 million maximum) while traveling outside their home country on Company business. 

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

 

• Participation in our Statutory Profit Sharing Plan 401(k). Eligibility is effective the first day of the month following the date of hire. 

We use a safe harbor matching formula for Company contributions (dollar for dollar match up to 3% of pay, $0.50 for every dollar 

on the next 2% of pay subject to the statutory maximum salary limits). Participant and Company contributions are 100% vested 

from the date of contribution. At termination of employment, employees are eligible to receive their account balance in a lump sum. 

 

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

and dependent. 

2012 Actual Compensation in 

Relationship to 2011 Actual Market Data CEO Other Named Executive Officers 

Base Salary 48 Percentile 48 to 58 percentile 

Actual Total Cash 53 Percentile 48 to 57 percentile 

Actual Total Direct Compensation 63 Percentile 51 to 84 percentile 

th th th 

rd th th 

rd st th 
Table of Contents 

Executive Compensation Mix 

The general mix of compensation for target-level performances in the annual incentive plan, plus the net annualized present value of 

long-term compensation grants, can range as follows, depending upon the executive officer. The Committee considered the following general 

percentage mix in establishing the total compensation for the Company’s executive officers for 2012 target performance. It is important to note 

that the influences on Company financial performance and stock price performance could significantly change the basic mix of compensation 

components as a percentage of total compensation: 

 

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

direct compensation at risk. 

 

 

 

68 
Table of Contents 

 

 

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

2011. 

Tax and Accounting Implications of Executive Compensation 

Deductibility of Executive Compensation 

As part of its role, the HR Committee reviews and considers the deductibility of executive compensation under Section 162(m) of the 

Internal Revenue Code of 1986, as amended, which imposes a limit of $1.0 million on the amount that a publicly-held corporation may deduct 

in any year for the compensation paid or accrued with respect to its named executive officers unless the compensation is performance based. 

None of our executive officers currently receives compensation exceeding the limits imposed by Section 162(m). While we cannot predict with 

certainty how executive compensation might be affected in the future by Section 162(m) or applicable tax regulations issued, we intend to 

preserve the tax deductibility of all executive compensation while maintaining our executive compensation program as described in this 

Compensation Discussion and Analysis. 

Employment Agreements 

We have entered into Executive Employee Agreements with our current named executive officers: Messrs. Edmiston, Haynes, Speirs, 

Nesselrode and Head. Two other executive officers who are not named also have executive employment agreements. The contracts have an 

initial term, which automatically extends for one year upon each anniversary unless a one-year notice not to extend is given by the executive. 

The current term of the Executive Employment Agreements is through May 31, 2013. 

 

69 
Table of Contents 

See the table titled “Potential Payments under Termination or Change of Control” in the Compensation of Executive Officers section below for 

details on the above information. 

The HR Committee believes the termination payment included in these Executive Employment Agreements is needed to attract and retain 

the executives necessary to achieve our business objectives. However, the HR Committee also believes termination payments should not be 

guaranteed. Accordingly, a termination payment will not be paid if a termination occurs after notice and lapse of the notice period to terminate 

the Executive Employment Agreement. Also, a termination payment will not be made if the executive officer resigns other than for good 

reason. Good reason under the employment contracts includes: (1) a material breach of the employment agreement by the Company; (2) failure 

to maintain or reelect the executive officer to his position; (3) a significant reduction of the executive officer’s duties, position or 

responsibilities; (4) a substantial reduction, without good business reasons, of the facilities and perquisites available to the executive officer; 

(5) a reduction by the Company of the executive officer’s monthly base salary; (6) failure of the Company to continue the executive officer’s 

participation in any bonus, incentive, profit sharing, performance, savings, retirement or pension policy, plan, program or arrangement on 

substantially the same or better basis relative to other participants; or (7) the relocation of the executive officer more than fifty miles from the 

location of the Company’s principal office. 

Change of Control 

Since it is in our best interest to retain executive officers during uncertain times who will act in the best interests of the stockholders 

without concern for personal outcome, our Executive Employment Agreements provide benefits in the event of loss of employment for 

employees in good standing due to a change of control. Change of control is defined as the acquisition of 50% or more of our voting stock, the 

cessation of the incumbent board of directors to constitute a majority of the board of directors, or the reorganization, merger, or sale or 

disposition of at least 50% of our assets where we are not the surviving entity. Change of control severance benefits apply to terminations 

taking place between 240 days before a change of control and 730 days after a change of control. 

 

70 

Entitlements based on Terms in Executive 

Employment Agreements if we terminate the 

employment without cause or notice (not 

related to Change of Control) OR the 

executive terminates employment for good 

reason 

Mr. 

Edmiston Mr. Haynes Mr. Speirs Mr. Nesselrode Mr. Head 

A lump sum amount equal to a certain multiple of base salary 3 times 2 times 2 times 2 times 2 times 

An amount equal to a certain number of years times the maximum annual employer 

contributions made under out 401(k) plan 3 years 2 years 2 years 2 years 2 years 

Vesting of all stock options Yes Yes Yes Yes Yes 

Vesting of all restricted stock awards Yes Yes Yes Yes Yes 

Reimbursement of Outplacement Services Yes Yes Yes Yes Yes 

Restrictions on ability to compete with the Company after termination of employment 2 years 2 years 2 years 2 years 2 years 
Table of Contents 

The change of control benefits in the Executive Employment Agreements contain a double trigger in that both a change of control must 

occur and the executive officer must be terminated without cause or resign for good reason within a specified period of time after the change of 

control. The HR Committee believes that the double trigger avoids unnecessarily rewarding an executive officer when a change of control 

occurs and the executive officer’s status is not changed as a result. However, because of the significant uncertainty that can arise during a 

period of a potential or actual change of control, the Committee has provided greater benefits to the executive officer in the event of a 

termination resulting from a change of control. Change of control benefits are detailed in the “Potential Payments under Termination or Change 

of Control” table in the Compensation of Executive Officers section below. 

HUMAN RESOURCES COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION 

None of the members of the Board’s HR Committee is or has been an officer or employee of the Company or has a relationship requiring 

disclosure under Item 404(a) of SEC Regulation S-K. No executive officer of the Company serves on the compensation committee or serves as 

a director of another entity where an executive officer of that entity also serves on the HR Committee or on the Board. 

HUMAN RESOURCES COMMITTEE REPORT 

The HR Committee has reviewed and discussed with management the Compensation Discussion and Analysis filed in this document. 

Based on such review and discussions, the HR Committee recommended to the Board that the Compensation Discussion and Analysis be 

included in this Annual Report on Form 10-K. 

 

71 

Entitlements based on Terms in 

Executive Employment Agreements if 

we terminate the employment without 

cause or notice related to a Change of 

Control 

Mr. 

Edmiston 

Mr. 

Haynes Mr. Speirs 

Mr. 

Nesselrode Mr. Head 

A lump sum amount equal to a certain multiple of base salary 3 times 2 times 2 times 2 times 2 times 

A lump sum amount equal to a certain multiple of the highest annual bonus over the past 3 

years or target bonus, whichever is higher 3 times 2 times 2 times 2 times 2 times 

An amount equal to a certain number of years times the maximum annual employer 

contributions made under out 401(k) plan 3 years 2 years 2 years 2 years 2 years 

Continuation of accident, life, disability, dental and health benefits for a certain number of 

years 3 years 2 years 2 years 2 years 2 years 

Excise tax reimbursement and gross up on the reimbursement Yes Yes Yes Yes Yes 

Vesting of all stock options Yes Yes Yes Yes Yes 

Vesting of all restricted stock awards Yes Yes Yes Yes Yes 

Reimbursement of Outplacement Services Yes Yes Yes Yes Yes 

Restrictions on ability to compete with the Company after termination of employment 2 years 2 years 2 years 2 years 2 years 
Table of Contents 

R. E. Irelan, Committee Chairman 

Igor Effimoff 

J. Michael Stinson 

 

72 
Table of Contents 

COMPENSATION OF EXECUTIVE OFFICERS 

Summary Compensation Table 

The following table summarizes the compensation of the Company’s named executive officers for the three most recently completed 

fiscal years ended December 31, 2012, 2011 and 2010. 

 

Notes: 

 

 

 

73 

Name & Principal Position Year Salary 

Bonus 

(1) 

Stock 

Awards 

($) (2) 

Option 

Awards 

($) (2) 

Non-Equity 

Incentive 

Plan 

Compensation 

(3) 

All Other 

Compensation 

($) (4) Total 

James A. Edmiston 2012 $ 548,077 $ 750,750 — $ 349,175 $ 1,052,982 $ 17,965 $ 2,718,949 

President and Chief 2011 507,000 413,100 326,748 637,382 — 217,835 2,102,065 

Executive Officer 2010 456,923 509,000 332,990 640,884 — 18,388 1,958,185 

Stephen C. Haynes 2012 292,885 241,605 — 99,380 298,393 18,331 950,594 

Vice President, 2011 278,077 120,700 146,589 285,203 — 14,148 844,717 

Chief Financial Officer 2010 255,192 179,000 93,720 142,994 — 14,634 685,540 

Robert Speirs 2012 343,333 296,010 — 115,496 351,446 365,319 1,471,604 

Vice President, 2011 326,667 149,494 189,111 370,039 — 350,128 1,385,439 

Eastern Operations 2010 308,750 191,000 124,250 190,393 — 315,604 1,129,997 

Karl L. Nesselrode 2012 267,692 221,130 — 91,323 273,347 17,714 871,206 

Vice President, Engineering 2011 254,615 115,133 135,399 264,553 — 214,791 984,491 

and Business Development 2010 242,596 152,000 78,100 119,095 — 339,526 931,317 

Keith L. Head 2012 262,115 206,700 — 91,323 265,944 20,184 846,266 

Vice President and General 2011 246,192 106,250 87,282 170,229 — 40,083 650,036 

Counsel 2010 238,462 126,000 46,860 71,696 — 15,568 498,586 

(1) Harvest pays bonuses one year in arrears but reflects the bonus in the table above in the year to which it related. Harvest deferred the 

payment of bonuses to key employees for 2010 until later in 2011. These bonuses have been included in the above table as 2010 bonuses. 

Bonuses related to 2011 were paid February 24, 2012 and are reflected in the table above as 2011 bonuses. Bonuses related to 2012 were 

paid March 1, 2013 and are reflected in the table above as 2012 bonuses. 

(2) Harvest uses the Black-Scholes option pricing model to determine the value of each option grant on the date of grant. Harvest does not 

advocate or necessarily agree that the Black-Scholes option pricing model can properly determine the value of an option. The 2012 

calculations for the named executive officers are based on a weighted average expected life of five years, expected volatility of 67.32%, 

risk-free interest rate of 0.74%, expected dividend yield of 0% and expected annual forfeitures of 3% for stock options and 0% for 

restricted stock. 

(3) In May 2012, Harvest issued stock appreciation rights (SAR) and restricted stock units (RSU) as long-term incentive compensation. 

These instruments can be settled in cash or equity. Currently, no plan has been approved by the shareholders for equity settlement and 

Harvest is recording the liability and expense associated with the awards based on the fair market value of the stock at $5.12 on May 17, 

2012. The number of awards for each executive that equals the amount above is shown in the following table: 

Non-Equity Incentive 

Compensation Table 

 

2012 Grants 

# of units 

Fair Value 

at Grant date 5/17/2012 

 SAR RSU SAR RSU Total 

James A. Edmiston 219,000 79,000 $ 648,502 $ 404,480 $ 1,052,982 

Stephen C. Haynes 61,000 23,000 180,633 117,760 298,393 

Robert Speirs 72,000 27,000 213,206 138,240 351,446 

Karl L. Nesselrode 56,000 21,000 165,827 107,520 273,347 

Keith L. Head 53,500 21,000 158,424 107,520 265,944 
Table of Contents 

 

 

74 

(4) Detail of all other compensation paid: 

Name and Principal 

Position Year 

Group 

Term 

Life 

Company 

401(K) 

Match 

Other 

NonCash 

Special 

Accomplishment 

Bonus Severance 

Foreign 

Housing and 

Living Expense 

Cost of 

Living 

Adjustment 

Vacation 

Allowance 

Transportation 

Allowance 

Foreign 

Service 

Premium 

Foreign 

Taxes Total ($) 

James A. Edmiston 2012 $ 7,965 $ 10,000 $ — $ — $ — $ — $ — $ — $ 17,965 

President and Chief 

Executive 

Officer 

 2011 $ 8,035 $ 9,800 $ — $ 200,000 $ — $ — $ — $ — $ — $ — $ 217,835 

 2010 $ 7,866 $ 9,800 $ 722 $ — $ — $ — $ — $ — $ — $ — $ 18,388 

 

 

Stephen C. Haynes 2012 $ 8,331 $ 10,000 $ — $ — $ — $ — $ — $ — $ 18,331 

Vice President, 

Chief Financial 

Officer 

 2011 $ 4,348 $ 9,800 $ — $ — $ — $ — $ — $ — $ — $ — $ 14,148 

 2010 $ 4,184 $ 9,800 $ 650 $ — $ — $ — $ — $ — $ — $ — $ 14,634 

 

 

 

Robert Speirs 2012 $ 1,290 $ 157,699 $ 81,041 $ 43,795 $ 34,000 $ 28,500 $ 18,994 $ 365,319 

Vice President, 

Eastern 

Operations 

 2011 $ 1,376 $ — $ — $ — $ 173,308 $ 81,699 $ 40,450 $ 34,000 $ 28,500 $ (9,205 ) $ 350,128 

 2010 $ 1,376 $ — $ 661 $ — $ 157,678 $ 65,329 $ 34,115 $ 34,000 $ 28,500 $ (6,055 ) $ 315,604 

 

 

Karl L. Nesselrode 2012 $ 7,714 $ 10,000 $ — $ — $ — $ — $ — $ — $ 17,714 

Vice President, 

Engineering and 

Business 

Development 

 2011 $ 4,037 $ 9,800 $ — $ 100,000 $ — $ — $ — $ — $ — $ 100,954 $ 214,791 

 2010 $ 3,871 $ 9,800 $ 687 $ — $ 93,559 $ 39,346 $ 11,059 $ — $ 45,308 $ 135,896 $ 339,526 

 

 

 

 

Keith L. Head 2012 $ 10,184 $ 10,000 $ — $ — $ — $ — $ — $ — $ 20,184 

Vice President, 

General Counsel 

 2011 $ 5,283 $ 9,800 $ — $ 25,000 $ — $ — $ — $ — $ — $ — $ 40,083 

 2010 $ 5,118 $ 9,800 $ 650 $ — $ — $ — $ — $ — $ — $ — $ 15,568 

 

 
Table of Contents 

Grants of Plan-Based Awards 

The following table shows information concerning options to purchase Common Stock granted to each of the named executive officers 

during 2012 . 

 

Notes: 

 

 

75 

Name 

 Grant 

Date 

 

All Other 

Stock 

Awards: 

Number 

of 

Shares of 

Stock 

or Units 

All Other 

Option 

Awards: 

Number of 

Securities 

Underlying 

Options(1) 

Exercise 

or Base 

Price of 

Option 

Awards 

Fair Value of Stock 

Based Awards 

 (#) (#) ($/Sh) ($)(2) 

James A. Edmiston 5/17/2012 130,000 $ 5.12 349,175 

Stephen C. Haynes 5/17/2012 37,000 $ 5.12 99,380 

Robert Speirs 5/17/2012 43,000 $ 5.12 115,496 

Karl L. Nesselrode 5/17/2012 34,000 $ 5.12 91,323 

Keith L. Head 5/17/2012 34,000 $ 5.12 91,323 

(1) Options granted May 17, 2012 vest 1/3 each year over a three year period. 

(2) Harvest granted options representing 436,298 shares to employees in 2012. 
Table of Contents 

Outstanding Equity Awards at Fiscal Year End 

The following table shows information concerning outstanding equity awards as of December 31, 2012 held by the named executive 

officers. 

 

 

76 

Name 

 Option Awards Stock Awards 

 

Number of Securities 

Underlying 

Unexercised 

Options 

(#) 

Equity 

Incentive 

Plan 

Number of 

Securities 

Underlying 

Unexercised 

Unearned 

Options 

Option 

Exercise 

Price 

Option 

Expiration 

Number 

of Shares 

Or Units 

of Stock 

That 

Have 

Not 

Vested 

Market 

Value of 

Shares or 

Units of 

Stock 

That 

Have 

Not 

Vested 

(1) 

Equity 

Incentive 

Plan Awards: 

Number of 

Unearned 

Shares, Units 

or Other 

Rights 

That Have 

Not Vested 

 Exercisable 

Not 

Exercisable (#) ($) (Date) (#) ($) (#) 

James A. Edmiston 100,000 $ 13.585 9/1/2014 

 75,000 $ 12.795 3/4/2015 

 85,000 $ 10.800 9/15/2015 

 165,000 $ 10.800 9/15/2015 

 250,000 (2) 

 17,000 $ 9.605 3/2/2016 

 24,334 $ 9.605 3/2/2016 

 250,000 $ 9.625 2/27/2014 

 120,000 — $ 10.175 5/15/2015 

 65,000 — $ 4.595 6/18/2016 

 107,267 53,633 $ 7.100 5/20/2015 46,900 414,596 

 38,067 76,133 $ 11.190 5/20/2016 29,200 258,128 

 130,000 $ 5.120 5/17/2017 

Stephen C. Haynes 50,000 — $ 10.245 5/19/2015 

 12,000 — $ 4.595 6/18/2016 

 23,933 11,967 $ 7.100 5/20/2015 13,200 116,688 

 17,033 34,067 $ 11.190 5/20/2016 13,100 115,804 

 37,000 $ 5.120 5/17/2017 

Robert Speirs 80,000 — $ 13.690 6/1/2016 

 80,000 — $ 9.625 2/27/2014 

 40,000 — $ 10.175 5/15/2015 

 12,500 — $ 4.595 6/18/2016 

 31,867 15,933 $ 7.100 5/20/2015 17,500 154,700 

 22,100 44,200 $ 11.190 5/20/2016 16,900 149,396 

 43,000 $ 5.120 5/17/2017 

Karl L. Nesselrode 36,000 $ 7.100 11/17/2013 

 8,000 $ 13.010 5/26/2014 

 20,000 $ 12.795 3/4/2015 

 13,334 $ 9.605 3/2/2016 

 70,000 — $ 9.625 2/27/2014 

 40,000 — $ 10.175 5/15/2015 

 19,933 9,967 $ 7.100 5/20/2015 11,000 97,240 

 15,800 31,600 $ 11.190 5/20/2016 12,100 106,964 

 34,000 $ 5.120 5/17/2017 

Keith L. Head 50,000 — $ 10.065 5/7/2014 

 20,000 — $ 10.175 5/15/2015 

 12,000 6,000 $ 7.100 5/20/2015 6,600 58,344 

 10,167 20,333 $ 11.190 5/20/2016 7,800 68,952 

 34,000 $ 5.120 5/17/2017 
Table of Contents 

 

77 

(1) The market value of shares is $8.840 per share, based upon the average of the high and low market prices on December 31, 2012. 

(2) This stock unit is a right to receive, after vesting, a cash amount equal to the difference between the closing price of the stock on 

September 15, 2005 and the price of the stock on the date the payment is distributed. Vesting is 1/3 on the last to occur of September 15, 

2006 and the date on which the average of the stock price for 10 consecutive trading days is greater than $25 per share. Vesting of 1/3 on 

September 2007 and 2008 is subject to the same $25 per share condition. 
Table of Contents 

Options Exercised and Stock Vested 

The following table provides information regarding the exercise of stock options during 2012 by the named executive officers. 

 

 

78 

Name 

 Option Awards Stock Awards 

 

Number of 

Shares 

Acquired on 

Exercise 

Value 

Realized on 

Exercise 

Number of 

Shares 

Acquired on 

Vesting 

Value 

Realized on 

Vesting 

James A. Edmiston — — 51,666 $ 293,463 

Stephen Haynes — — 17,333 $ 98,451 

Robert Speirs — — 19,333 $ 93,611 

Karl L. Nesselrode — — 6,666 $ 37,863 

Keith L. Head — — 8,333 $ 47,331 
Table of Contents 

Potential Payments under Termination or Change of Control 

The tables below reflect the additional compensation paid to the named executive officers of the Company under the terms of their 

Executive Employment Agreements in the event of termination without cause or without proper notice, termination following change of 

control, or termination for disability or death. (See Compensation Discussion and Analysis — Employment Agreements and Change of Control 

above for a description of the terms of the Executive Employment Agreements.) The amounts shown in the tables assume that such termination 

was effective as of December 31, 2012, and thus include estimated amounts earned through that date that would be paid out to the named 

executive officers. The actual amounts can only be determined at the time of separation from the Company. 

 

 

 

 

 

79 

Executive Compensation and BenefitsJames Edmiston 

Voluntary 

Termination 

on 

12/31/2012 

Voluntary 

Termination 

Without 

Cause or 

Notice on 

12/31/2012 

Termination 

For Good 

Reason or 

Termination 

Due to 

Change in 

Control on 

12/31/2012 

For Cause 

Termination 

On 

12/31/2012 

Death on 

12/31/2012 

Disability 

On 

12/31/2012 

Compensation: 

Base Salary — $ 1,650,000 $ 1,650,000 — $ 1,650,000 $ 1,650,000 

Short-term Incentive (100% of base salary) — — 2,252,250 — — — 

Long-term Incentives 

Stock Options/SARs (Intrinsic Value) — 1,752,707 1,752,707 — 1,752,707 1,752,707 

Restricted Shares/RSUs — 1,528,295 1,528,295 — 1,528,295 1,528,295 

Benefits and Perquisites: 

Outplacement — 20,000 20,000 — — — 

Life Insurance Proceeds — — — — 300,000 — 

Excise Tax Gross Up — — 1,879,165 — — — 

Disability Benefits per year * — — — — — 120,000 

Medical, Dental, Life, Disability and Accident 

Insurance — — 98,127 — — — 

401(k) Employer Match — 30,000 30,000 — 30,000 30,000 

Total 0 $ 4,981,002 $ 9,210,544 0 $ 5,261,002 $ 5,081,002 

* Until no longer disabled or Social Security Retirement Age 

Executive Compensation and BenefitsStephen Haynes 

Voluntary 

Termination 

on 

12/31/2012 

Voluntary 

Termination 

Without 

Cause or 

Notice on 

12/31/2012 

Termination 

For Good 

Reason or 

Termination 

Due to 

Change in 

Control on 

12/31/2012 

For Cause 

Termination 

On 

12/31/2012 

Death on 

12/31/2012 

Disability 

On 

12/31/2012 

Compensation: 

Base Salary — $ 590,000 $ 590,000 — $ 590,000 $ 590,000 

Short-term Incentive (50% of base salary) — — 483,210 — — — 

Long-term Incentives 

Stock Options/SARs (Intrinsic Value) — 461,395 461,395 — 461,395 461,395 

Restricted Shares/RSUs — 507,920 507,920 — 507,920 507,920 

Benefits and Perquisites: 

Outplacement — 20,000 20,000 — — — 

Life Insurance Proceeds — — — — 300,000 — 

Excise Tax Gross Up — — 431,496 — — — 

Disability Benefits per year * — — — — — 120,000 

Medical, Dental, Life, Disability and Accident 

Insurance — — 60,040 — — — 

401(k) Employer Match — 20,000 20,000 — 20,000 20,000 

Total 0 $ 1,599,315 $ 2,574,061 0 $ 1,879,315 $ 1,699,315 

* Until no longer disabled or Social Security Retirement Age 
Table of Contents 

 

 

 

 

80 

Executive Compensation and BenefitsRobert Speirs 

Voluntary 

Termination 

on 

12/31/2012 

Voluntary 

Termination 

Without 

Cause or 

Notice on 

12/31/2012 

Termination 

For Good 

Reason or 

Termination 

Due to 

Change in 

Control on 

12/31/2012 

For Cause 

Termination 

On 

12/31/2012 

Death on 

12/31/2012 

Disability 

On 

12/31/2012 

Compensation: 

Base Salary — $ 690,000 $ 690,000 — $ 690,000 $ 690,000 

Short-term Incentive (50% of base salary) — — 592,020 — — — 

Long-term Incentives 

Stock Options/SARs (Intrinsic Value) — 485,638 485,638 485,638 485,638 

Restricted Shares/RSUs — 556,898 556,898 556,898 556,898 

Benefits and Perquisites: 

Outplacement — 20,000 20,000 — — — 

Life Insurance Proceeds — — — — 300,000 — 

Excise Tax Gross Up — — — — — — 

Disability Benefits per year * — — — — — 120,000 

Medical, Dental, Life, Disability and Accident 

Insurance — — 44,994 — — — 

401(k) Employer Match — — — — — — 

Total 0 $ 1,752,536 $ 2,389,550 0 $ 2,032,536 $ 1,852,536 

* Until no longer disabled or Social Security Retirement Age 

Executive Compensation and BenefitsKarl Nesselrode 

Voluntary 

Termination 

on 

12/31/2012 

Voluntary 

Termination 

Without 

Cause or 

Notice on 

12/31/2012 

Termination 

For Good 

Reason or 

Termination 

Due to 

Change in 

Control on 

12/31/2012 

For Cause 

Termination 

On 

12/31/2012 

Death on 

12/31/2012 

Disability 

On 

12/31/2012 

Compensation: 

Base Salary — $ 540,000 $ 540,000 — $ 540,000 $ 540,000 

Short-term Incentive (50% of base salary) — — 442,260 — — — 

Long-term Incentives 

Stock Options/SARs (Intrinsic Value) — 458,665 458,665 — 458,665 458,665 

Restricted Shares/RSUs — 339,987 339,987 — 339,987 339,987 

Benefits and Perquisites: 

Outplacement — 20,000 20,000 — — — 

Life Insurance Proceeds — — — — 300,000 — 

Excise Tax Gross Up — — — — — — 

Disability Benefits per year * — — — — — 120,000 

Medical, Dental, Life, Disability and Accident 

Insurance — — 62,656 — — — 

401(k) Employer Match — 20,000 20,000 — 20,000 20,000 

Total 0 $ 1,378,652 $ 1,883,568 0 $ 1,658,652 $ 1,478,652 

* Until no longer disabled or Social Security Retirement Age 
Table of Contents 

 

DIRECTOR COMPENSATION 

Our philosophy in determining director compensation is to align compensation with the long-term interests of the stockholders, 

adequately compensate the directors for their time and effort and establish an overall compensation package that will attract and retain qualified 

directors. In determining overall director compensation, we seek to strike the right balance between the cash and stock components of director 

compensation. The Board’s policy is that the directors should hold equity ownership in the Company and that a portion of the director fees 

should consist of Company equity in the form of restricted stock and stock grants. The Board also believes that directors should develop a 

meaningful equity position over time and has adopted stock retention guidelines applicable to all directors. These guidelines state directors 

must retain (i) at least 50% of the shares of restricted stock granted to them for at least three years after the restriction lapses and (ii) at least 

50% of the net shares of stock received through the exercise of an option or SAR must be retained by a director for at least three years after the 

exercise date. 

Our retainer and meeting fee schedule remained the same in 2012 as it was in 2011, 2010 and 2009. Each non-employee director of the 

Company received cash compensation as follows: 

 

 

 

 

Our director compensation includes additional compensation for the non-executive Chairman of the Board in recognition of the 

significant added responsibilities and time commitments of that position. In addition to his compensation as a director, he receives a retainer of 

$120,000 a year; this 2012 retainer remained the same as the retainer in 2011 and 2010. 

Under the 2010 Plan, directors are eligible to receive restricted stock, RSUs, stock options and SAR grants. In May 2012, the Board 

approved a RSU award of $100,000 in value for each director. 

 

81 

Executive Compensation and BenefitsKeith Head 

Voluntary 

Termination 

on 

12/31/2012 

Voluntary 

Termination 

Without 

Cause or 

Notice on 

12/31/2012 

Termination 

For Good 

Reason or 

Termination 

Due to 

Change in 

Control on 

12/31/2012 

For Cause 

Termination 

On 

12/31/2012 

Death on 

12/31/2012 

Disability 

On 

12/31/2012 

Compensation: 

Base Salary — $ 530,000 $ 530,000 — $ 530,000 $ 530,000 

Short-term Incentive (50% of base salary) — — 413,400 — — — 

Long-term Incentives 

Stock Options/SARs (Intrinsic Value) — 417,115 417,115 — 417,115 417,115 

Restricted Shares/RSUs — 473,001 473,001 — 473,001 473,001 

Benefits and Perquisites: 

Outplacement — 20,000 20,000 — — — 

Life Insurance Proceeds — — — — 300,000 — 

Excise Tax Gross Up — — 371,828 — — — 

Disability Benefits per year * — — — — — 120,000 

Medical, Dental, Life, Disability and Accident 

Insurance — — 54,040 — — — 

401(k) Employer Match — 20,000 20,000 — 20,000 20,000 

Total 0 $ 1,460,116 $ 2,299,384 0 $ 1,740,116 $ 1,560,116 

* Until no longer disabled or Social Security Retirement Age 

 • An annual Board retainer of $40,000, plus travel and related expenses; 

 • A meeting fee of $1,500 for each board or committee meeting attended; 

 

• An annual committee retainer of $20,000 for serving as committee chair of the Audit Committee, $15,000 for serving as committee 

chair of the Human Resources Committee and $10,000 for serving as committee chair of the Nominating and Corporate 

Governance Committee; and 

 

• A fee of $1,500 per day for attending business meetings on our behalf in the member’s capacity as a director that requires out of 

town travel or a substantial commitment of time. 
Table of Contents 

The following table sets forth the cash and other compensation paid to the non-employee members of our Board of Directors in 2012. 

 

 

 

82 

Name 

Fees 

Earned 

or Paid in 

Cash ($) 

Non-Equity 

Incentive Plan 

Compensation 

($) Total ($) 

Stephen D. Chesebro’ $ 203,750 $ 99,840 $ 303,950 

Igor Effimoff 79,000 99,840 178,840 

H. H. Hardee 82,000 99,840 181,840 

Robert E. Irelan 89,500 99,840 189,340 

Patrick M. Murray 105,000 99,840 204,840 

J. Michael Stinson 82,000 99,840 181,840 

(1) Includes $4,500 in business meeting fees and $6,000 for travel days. 

(2) Includes $1,500 for travel days. 

(3) Includes $4,500 in business meeting fees and $1,500 for travel days. 

(4) Includes $1,500 in business meeting fees and $4,500 for travel days. 

(5) Includes $3,000 in business meeting fees and $4,500 for travel days. 

(6) Includes $1,500 for travel days. 

(7) The amounts included in this column represent the aggregate grant date fair value of the grant of 19,500 deferred shares granted to each 

of our non-employee directors on May 17, 2012. As of December 31, 2012, each of the non-employee directors had aggregate 

outstanding deferred shares as follows: Mr. Chesebro’ — 19,500; Dr. Effimoff — 19,500; Mr. Hardee — 19,500; Mr. Irelan — 19,500; 

Mr. Murray — 19,500 and Mr. Stinson — 19,500. 

(7) 

(1) 

(2) 

(3) 

(4) 

(5) 

(6) 
Table of Contents 

EQUITY COMPENSATION PLAN INFORMATION 

As of December 31, 2012 

 

A description of our equity compensation plans is included in this Annual Report on Form 10-K, Part IV, Item 15, Notes to the Consolidated 

Financial Statements, Note 9 – Stock-Based Compensation and Stock Purchase Plans. 

 

 

83 

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

 (a) (b) (c) (d) 

 

# Of Securities To 

Be Issued Upon 

Exercise Of 

Outstanding 

Options And 

Rights 

Weighted 

Average 

Exercise Price 

Of Outstanding 

Options And 

Rights 

Weighted 

Average 

Remaining 

Life 

# Of Securities 

Remaining 

Available For 

Future Issuance 

Under Equity 

Compensation Plans 

(Excluding 

Securities Reflected 

In Column (a) 

 (3) (4) 

Equity compensation plans approved by Security Holders 3,771,632 $ 9.63 2.6 85,006 

Equity compensation plans not approved by Security Holders 

(1) 125,000 $ 9.41 2.2 — 

Stock Appreciation Right (“SAR”) (2) 932,202 $ 4.99 4.2 — 

TOTAL 4,828,834 85,006 

(1) Options were issued to new hire employees as employment inducement grants under a NYSE exception. These options were granted from 

2007 through 2012 between $5.85 and $10.25 and vest ratably over three years from the grant date. At December 31, 2012, a total of 

125,000 options were issued and outstanding as inducement grants, which are included in the table above, and 106,667 of these options 

were exercisable. This compensation plan was not approved by security holders. 

(2) A SAR is a right to receive on the Exercise Date, after vesting thereof, for each share of Company stock underlying the SAR with respect 

to which the SAR is exercised, an amount equal to the excess of (a) the Fair Market Value of one share of the Company stock on the 

Exercise Date over (b) 100 percent of the Fair Market Value of one share of the Stock determined as of the Grant Date (the “SAR 

Exercise Price”). The grant date for the 2009 SARs was June 18, 2009 and the SAR Exercise Price is $4.595 per share of Company stock. 

The 2009 SARs vest one-third each year beginning on June 18, 2012 and expire after seven years on June 18, 2016. The grant date for the 

2012 SARs was May 17, 2012 and the SAR Exercise Price is $5.12 per share of Company stock. The 2012 SARs vest one-third each year 

beginning on May 17, 2013 and expire after five years on May 17, 2017. At the sole discretion of the company, a SAR may be settled in 

cash or with shares of the underlying Company stock from an approved plan that allows the payment of a SAR in the medium of 

Company stock. This compensation plan was not approved by security holders. 
Table of Contents 

 

In addition to the outstanding options and SARs listed above, there are a total of 284,750 shares of restricted stock awards that were 

granted under all plans that are outstanding as of December 31, 2012. Of these full value awards, 280,750 shares were granted under 

equity plans approved by security holders. There were 4,000 shares awarded as inducement grants and not approved by security holders. 

A “ Stock Unit ” is a right to receive on the Payment Date, after vesting thereof, a cash amount equal to the Fair Market Value of one 

share of Company stock on the Payment Date. At December 31, 2012, the Company had 530,006 Stock Units outstanding. Stock Units 

were granted on June 18, 2009 and vest one-third each year beginning June 18, 2012. Stock Units were also granted to employees on 

May 17, 2012 and vest on May 17, 2015. Stock Units granted to directors on May 17, 2012 vest on May 17, 2013. At the sole discretion 

of the Company, a Stock Unit may be settled in cash or with shares of the underlying Company stock from an approved plan that allows 

the payment of the stock unit in the medium of Company stock. This compensation plan was not approved by security holders. 

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 

Directors and Named Executive Officers 

The following table shows the amount of our common stock beneficially owned (unless otherwise indicated) by our directors and 

nominees for director, each named executive officer and our directors and named executive officers as a group. Except as otherwise indicated, 

all information is as of April 24, 2013. 

The number of shares of our common stock beneficially owned by each director or named executive officer is determined under 

rules of the SEC, and the information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial 

ownership includes any shares as to which the individual has the sole or shared voting power or investment power and also any shares which 

the individual has the right to acquire within 60 days after April 24, 2013 through the exercise of stock options or other rights. Unless otherwise 

indicated, each person has sole investment and voting power (or shares such powers with his spouse) with respect to the shares set forth in the 

following table. 

 

 

84 

(3) This reflects the weighted average exercise of the stock options and SARs listed in column (a). 

(4) Securities remaining available for future issuances from the following plans are: 

2004 Long-Term Incentive Plan 45,000 Issuable only as Options 

2006 Long-Term Incentive Plan 40,000 Issuable only as Options 

2010 Long-Term Incentive Plan 6 Issuable as Options or Full Value Award 

 

 85,006 

 

Amount and Nature of 

Beneficial Ownership 

Name of Beneficial 

Owner 

Number of 

Shares 

Beneficially 

Owned 

Shares 

Acquirable 

Within 60 Days 

Total 

Beneficial 

Ownership 

Percent of 

Shares 

Outstanding 

James A. Edmiston 293,766 931,700 1,225,466 3.11 % 

Stephen C. Haynes 58,258 144,300 202,558 * 

Keith L. Head 44,099 119,666 163,765 * 

Karl L. Nesselrode 65,487 260,167 325,654 * 

Robert Speirs 187,483 318,833 506,316 1.28 % 

Stephen D. Chesebro’ 332,854 15,000 347,854 * 

Igor Effimoff 44,000 10,000 54,000 * 

H. H. Hardee 199,783 15,000 214,783 * 

Robert E. Irelan 56,000 10,000 66,000 * 

Patrick M. Murray 195,854 15,000 210,854 * 

J. Michael Stinson 82,000 15,000 97,000 * 

 

All current directors and executive officers as a group of eleven persons 1,559,584 1,854,666 3,414,250 8.65 % 

(1) (2) 
Table of Contents 

Certain Beneficial Owners 

The following table shows the beneficial owners of more than five percent of the Company’s common stock as of April 24, 2013: 

 

 

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 

Our Code of Business Conduct and Ethics (the “Code”) applies to all of our directors, officers and employees. Under the Code, 

individuals subject to the Code and their family members must knowingly avoid owning any interest (other than nominal amounts of stock in 

publicly-traded companies) in any supplier or customer; consulting with, or being an employee of, any customer, lessor, lessee, contractor, 

supplier or competitor; purchasing from, or selling to us, assets, goods or services; or serving on the board of directors of any customer, lessor, 

lessee, contractor, supplier or competitor, except where full disclosure of all facts is made known to us in advance to permit us to protect our 

interests. Each year we require our executive officers to certify their compliance with the Code. Our Audit Committee has oversight 

compliance responsibilities for the Code. Exceptions to the Code are reported to the Audit Committee. Waivers of the Code for officers and 

directors may only be granted by the 

 

85 

* Represents less than one percent of the Company’s outstanding common stock. 

(1) This number does not include common stock that our directors or named executive officers have a right to acquire within 60 days of 

April 24, 2013. 

(2) Percentages are based upon 39,454,279 shares of common stock outstanding on April 24, 2013. 

(3) Percentage should be calculated assuming that the vested options have been exercised by the individual for whom the percent is being 

calculated. 

Name & Address 

Aggregate Number 

of 

Shares Beneficially 

Owned 

Percent of Shares 

Outstanding 

Report 

Date Source 

Jet Capital Investors LP 

667 Madison Avenue, 9 Floor 

New York, New York 10021 3,633,212 9.2087 % 2/14/2013 Form SC 13G/A 

Amici Capital, LLC 

(formerly Porter Orlin LLC) 

666 Fifth Avenue, Suite 3403 

New York, New York 10103 3,621,632 9.1793 % 2/14/2013 Form SC 13G/A 

MSDC Management LP 

645 Fifth Avenue, 21 Floor 

New York, New York 10022 3,343,786 8.4751 % 2/14/2013 Form SC 13G/A 

Dimensional Fund Advisors, Inc. 

Palisades West, Building One 

6300 Bee Cave Road 

Austin, Texas 78746 3,124,709 7.9198 % 2/11/2013 Form SC 13G/A 

BlackRock Fund Advisors 

40 East 42 Street 

New York, New York 10022 2,301,530 5.8334 % 2/8/2013 Form SC 13G/A 

Glenhill Advisors LLC 

600 Fifth Avenue, 11th Floor 

New York, NY 10020 2,049,723 5.1952 % 3/29/2013 Form SC 13G 

The Vanguard Group, Inc. 

100 Vanguard Blvd. 

Malvern, Pennsylvania 19355 2,022,205 5.1254 % 2/12/2013 Form SC 13G/A 

(1) The stockholder has sole voting and dispositive power over the shares indicated unless otherwise disclosed. 

(2) The Company’s outstanding common shares as of April 24, 2013 were 39,454,279. 

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

1 2 

th 

st 

nd 
Table of Contents 

Board and waivers for employees may only be granted by the CEO and reported to the Audit Committee. No waivers of the Code were granted 

in 2012. In addition to the Code, each year we require our directors and executive officers to disclose in writing certain transactions and 

relationships and this information is used in preparing the proxy statement and in making independence determinations for directors. 

For the purposes of this Annual Report on Form 10-K, the Company has no transactions to describe pursuant to SEC Regulation S-K 

Item 404(a). 

DIRECTOR INDEPENDENCE 

Of our seven directors standing for re-election, six have been affirmatively determined by the Board to be independent, including our 

non-executive Chairman of the Board. The directors our Board has determined to be independent are Stephen D. Chesebro’, Dr. Igor Effimoff, 

H. H. Hardee, Robert E. Irelan, Patrick M. Murray and J. Michael Stinson. The Board’s determination of independence is based upon the 

standards set forth in our Guidelines for Corporate Governance, which may be found under the Corporate Governance section on our website at 

http://www.harvestnr.com . The Guidelines for Corporate Governance include the NYSE independence standards. In making its determination 

of independence, the Board took into account responses of the directors to questions concerning their employment history, compensation, 

affiliations and family and other relationships. 

 

During 2012, PricewaterhouseCoopers LLP served as our independent registered public accounting firm and provided certain tax and 

consulting services to us. Representatives of PricewaterhouseCoopers LLP are expected to attend the annual meeting of stockholders where 

they will be available to respond to questions and, if they desire, to make a statement. 

Audit Fees. The aggregate fees billed by PricewaterhouseCoopers LLP for each of the last two fiscal years for professional services 

rendered by it for the audit of our annual financial statements and review of financial statements included in our quarterly reports and services 

that are normally provided by it in connection with statutory and regulatory filings or engagements in those years were $1,190,000 for the year 

ended December 31, 2011, and $3,327,212 for the year ended December 31, 2012. 

Audit Related Fees. The aggregate fees billed by PricewaterhouseCoopers LLP for each of the last two fiscal years for assurance and 

related services by it that are reasonably related to the performance of the audit or review of our financial statements that are not included as 

“Audit Fees” above were $0 for the year ended December 31, 2011, and $0 for the year ended December 31, 2012. 

Tax Fees. The aggregate fees billed by PricewaterhouseCoopers LLP for each of the last two fiscal years for professional services 

rendered by it for tax compliance, tax advice and tax planning were $34,870 for the year ended December 31, 2011, and $32,274 for the year 

ended December 31, 2012. 

All Other Fees. The aggregate fees billed by PricewaterhouseCoopers LLP for each of the last two fiscal years for all other products and 

services provided by it were $0 for the year ended December 31, 2011, and $0 for the year ended December 31, 2012. 

All of the foregoing fees were approved by the Audit Committee. 

Audit Committee Pre-Approval Policies and Procedures. The Audit Committee’s Charter provides that our independent registered public 

accounting firm may provide only those services pre-approved by the Audit Committee, subject to de minimus exceptions for non-audit 

services described in the rules and regulations of the SEC, which are subsequently ratified by the Audit Committee prior to completion of the 

audit. The Audit Committee annually reviews and pre-approves the audit, review, attestation and permitted non-audit services to be provided 

during the next audit cycle by the independent registered public accounting firm. To the extent practicable, at the same meeting the Audit 

Committee also reviews and approves a budget for each of such services. 

The Audit Committee may delegate to a member(s) the authority to grant pre-approvals under its policy with respect to audit and 

permitted non-audit services, provided that any such grant of pre-approval shall be reported to the full Audit Committee no later than its next 

scheduled meeting. 

The Audit Committee has concluded that the provision of non-audit services is compatible with maintaining the registered public 

accounting firm’s independence. 

 

86 

Item 14. Principal Accountant Fees and Services 
Table of Contents 

PART IV 

 

 

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

notes thereto. 

Separate financial statements of Petrodelta, S.A. required pursuant to Rule 3-09 of Regulation S-X are filed as Exhibit 99.1. 

 

 

 

87 

Item 15. Exhibits and Financial Statement Schedules 

 

 

 Page 

(a) 1. Index to Financial Statements: 

 Report of Independent Registered Public Accounting Firm S-1 

 Consolidated Balance Sheets at December 31, 2012 and 2011 S-2 

 

Consolidated Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2012, 2011 and 

2010 S-3 

 Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010 S-4 

 Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010 S-5 

 Notes to Consolidated Financial Statements S-7 

 2. Consolidated Financial Statement Schedules and Other: 

 Schedule II – Valuation and Qualifying Accounts S-68 

(b) 3. Exhibits: 

 3.1 

 

Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1 to our Form 

10-Q filed on November 9, 2010, File No. 1-10762.) 

 3.2 

 

Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on

May 23, 2007, File No. 1-10762.) 

 4.1 

 

Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.1 to our Form 10-K filed on 

March 17, 2008, File No. 1-10762.) 

 4.2 

 

Certificate of Designation, Rights and Preferences of the Series B Preferred Stock of Benton Oil and Gas 

Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.2 to our Form 10- Q filed on 

November 9, 2010, File No. 1-10762.) 

 4.3 

 

Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural 

Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A12G 

filed on October 23, 2007, File No. 1-10762.) 

 4.4 

 

Amendment to Third Amended and Restated Rights Agreement, dated as of October 28, 2010, between 

Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.1 to 

our Form 8-K filed on October 29, 2010, File No. 1-10762.) 

 4.5 

 

Warrant Purchase Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and 

MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.2 to our Form 8-K filed 

on October 29, 2010, File No. 1-10762.) 
Table of Contents 

 

88 

 

 4.9 

 

 

Common Stock Purchase Warrant No. W-1, dated as of October 28, 2010, between Harvest Natural 

Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.3 to 

our Form 8-K filed on October 29, 2010, File No. 1-10762.) 

 4.10 

 

Common Stock Purchase Warrant No. W-2, dated as of October 28, 2010, between Harvest Natural 

Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 4.4 to 

our Form 8-K filed on October 29, 2010, File No. 1-10762.) 

 4.11 

 

Indenture, dated as of October 11, 2012, between the Company and U.S. Bank National Association, as 

Trustee. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on October 15, 2012, File No. 1-

10762). 

 4.12 

 

Form of Note. (Included as Exhibit 1 to the Indenture filed as Exhibit 4.1 to our Form 8-K filed on 

October 15, 2012, File No. 1-10762). 

 4.13 

 

Warrant Agreement, dated as of October 11, 2012, between the Company and U.S. Bank National 

Association, as Warrant Agent. (Incorporated by reference to Exhibit 4.3 to our Form 8-K filed on 

October 15, 2012, File No. 1-10762). 

 4.14 

 

Form of Warrant. (Included as Exhibit A to the Warrant Agreement filed as Exhibit 4.3 to our Form 8-K 

filed on October 15, 2012, File No. 1-10762). 

 4.15 

 

Second Amendment to Third Amended and Restated Rights Agreement, dated as of February 1, 2013, 

between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A., as Rights Agent. (Incorporated by 

reference to Exhibit 4.1 to our Form 8-K filed on February 4, 2013, File No. 1-10762.) 

 10.1 

 

2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our Registration 

Statement on Form S-8 filed on April 9, 2002 (Registration Statement No. 333-85900).) 

 10.2 

 

Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our 

Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).) 

 10.3 

 

Form of Indemnification Agreement between Harvest Natural Resources, Inc. and each Director and 

Executive Officer of the Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on 

February 23, 2005, File No. 1-10762.) 

 10.4 

 

Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement. (Incorporated by reference to 

Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) 

 10.5 

 

Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement. (Incorporated by 

reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) 

 10.6 

 

Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement. (Incorporated by 

reference to Exhibit 10.22 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) 

 10.7 

 

Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. 

Edmiston. (Incorporated by reference to Exhibit 10.24 to our Form 10-K filed on February 27, 2006, File 

No. 1-10762.) 

 10.8 

 

Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. 

Edmiston. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on February 27, 2006, File 

No. 1-10762.) 

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Table of Contents 

 

89 

 

 10.9 

 

 

Stock Option Agreement dated September 26, 2005, between Harvest Natural Resources, Inc. and Byron 

A. Dunn. (Incorporated by reference to Exhibit 10.26 to our Form 10-K filed on February 27, 2006, File

No. 1-10762.) 

 10.10 

 

Harvest Natural Resources 2006 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to 

our Registration Statement on Form S-8 filed on June 1, 2006 [Registration Statement No. 333-134630].) 

 10.11 

 

Form of 2006 Long Term Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 

10.2 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) 

 10.12 

 

Form of 2006 Long Term Incentive Plan Director Restricted Stock Agreement. (Incorporated by 

reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) 

 10.13 

 

Form of 2006 Long Term Incentive Plan Employee Restricted Stock Agreement. (Incorporated by 

reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) 

 10.14 

 

Stock Unit Award Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and 

James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on August 9, 2006, 

File No. 1-10762.) 

 10.15 

 

Stock Unit Award Agreement dated March 2, 2006 between Harvest Natural Resources, Inc. and 

James A. Edmiston. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 9, 2006, 

File No. 1-10762.) 

 10.16 

 

Form of 2006 Long Term Incentive Plan Stock Option Agreement – Five Year Vesting, Seven Year 

Term. (Incorporated by reference to Exhibit 10.33 to our Form 10-K filed on March 13, 2007, File No. 1-

10762.) 

 10.17 

 

Amendment to Harvest Natural Resources 2006 Long Term Incentive Plan adopted July 19, 2006. 

(Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on May 3, 2007, File No. 1-10762.) 

 10.18 

 

Stock Option Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. 

(Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) 

 10.19 

 

Contract for Conversion to a Mixed Company between Corporación Venezolana del Petróleo, S.A., 

Harvest-Vinccler, S.C.A. and HNR Finance B.V. (Incorporated by reference to Exhibit 10.1 to our Form 

10-Q filed on November 1, 2007, File No. 1-10762.) 

 10.20 

 

Stock Option Agreement dated May 19, 2008 between Harvest Natural Resources, Inc. and Stephen C. 

Haynes. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 7, 2008, File No. 1-

10762.) 

 10.21 

 

2010 Long Term Incentive Plan. (Incorporated by reference to Appendix A to the Company’s Definitive 

Proxy Statement on Schedule 14A filed with the Securities and Exchange Commission on April 9, 2010, 

File No. 1-10762.) 

 10.22 

 

Form of 2010 Long Term Incentive Plan Employee Restricted Stock Award Agreement. (Incorporated by 

reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2010, File No. 1-10762.) 

 10.23 

 

Form of 2010 Long Term Incentive Plan Stock Option Award Agreement. (Incorporated by reference to 

Exhibit 10.3 to our Form 10-Q filed on August 9, 2010, File No. 1-10762.) 

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Table of Contents 

 

90 

 

 10.24 

 

 

Form of 2010 Long Term Incentive Plan Director Restricted Stock Award Agreement. (Incorporated by 

reference to Exhibit 10.30 to our Form 10-K filed on March 15, 2012 File No. 1-10762.) 

 10.25 

 

Employment Agreement dated January 1, 2009 between Harvest Natural Resources, Inc. and Karl L. 

Nesselrode. (Incorporated by reference to Exhibit 10.30 to our Form 10-K filed on March 15, 2012, File 

No. 1-10762.) 

 10.26 

 

Employment Agreement dated January 1, 2009 between Harvest Natural Resources, Inc. and James A. 

Edmiston. (Incorporated by reference to Exhibit 10.31 to our Form 10-K filed on March 15, 2012, File 

No. 1-10762.) 

 10.27 

 

Employment Agreement dated January 1, 2009 between Harvest Natural Resources, Inc. and Keith L. 

Head. (Incorporated by reference to Exhibit 10.32 to our Form 10-K filed on March 15, 2012, File No. 1-

10762.) 

 10.28 

 

Employment Agreement dated January 1, 2009 between Harvest Natural Resources, Inc. and Stephen C. 

Haynes. (Incorporated by reference to Exhibit 10.33 to our Form 10-K filed on March 15, 2012, File No.

1-10762.) 

 10.29 

 

Employment Agreement dated May 31, 2008 between Harvest Natural Resources, Inc. and Robert Speirs. 

(Incorporated by reference to Exhibit 10.34 to our Form 10-K filed on March 15, 2012, File No. 1-

10762.) 

 10.30 

 

Form of Stock Appreciation Right Award Agreement. (Incorporated by reference to Exhibit 10.1 to our 

Form 10-Q filed on August 4, 2009, File No. 1-10762.) 

 10.31 

 

Form of Stock Unit Award Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed 

on August 4, 2009, File No. 1-10762.) 

 10.32 

 

Form of Director Stock Unit Award Agreement. (Incorporated by reference to Exhibit 10.3 to our Form 

10-Q filed on August 9, 2012, File No. 1-10762.) 

 10.33 

 

Form of Employee Stock Unit Award Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 

10-Q filed on August 9, 2012, File No. 1-10762.) 

 10.34 

 

Form of Employee Stock Appreciation Right Award Agreement. (Incorporated by reference to Exhibit 

10.5 to our Form 10-Q filed on August 9, 2012, File No. 1-10762.) 

 10.35 

 

Equity Distribution Agreement, dated March 30, 2012 by and between the Company and Knight Capital 

Americas, L.P. (Incorporated by reference to Exhibit 1.1 to our Form 8-K filed on March 30, 2012, File

No. 1-10762.) 

 10.36 

 

Share Purchase Agreement dated June 21, 2012, by and among HNR Energia BV, Harvest Natural 

Resources, Inc. and PT Pertamina (Persero). (Incorporated by reference to Exhibit 2.1 to our Form 8-K 

filed on June 21, 2012, file No. 1-10762.) 

 10.37 

 

Guarantee of Harvest Natural Resources, Inc. dated June 21, 2012. (Incorporated by reference to Exhibit 

2.2 to our Form 8-K filed on June 21, 2012, file No. 1-10762.) 

 10.38 

 

Securities Purchase Agreement, dated as of October 11, 2012, among Harvest Natural Resources, Inc. and

the purchasers named therein. (Incorporated by reference to Exhibit 10.1 to our Form 8-K filed on 

October 15, 2012, File No. 1-10762). 

 21.1 List of subsidiaries. 

 23.1 Consent of PricewaterhouseCoopers LLP. 

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Table of Contents 

 

 

91 

 

 23.2 

 

Consent of Ryder Scott Company, LP. 

 23.3 Consent of HLB PGFA Perales, Pistone & Asociados – Caracas, Venezuela. 

 31.1 

 

Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 executed by James A. Edmiston,

President and Chief Executive Officer. 

 31.2 

 

Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 executed by Stephen C. Haynes,

Vice President, Chief Financial Officer and Treasurer. 

 32.1 

 

Certification accompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) 

and 18 U.S.C. Section 1350 executed by James A. Edmiston, President and Chief Executive Officer. 

 32.2 

 

Certification accompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) 

and 18 U.S.C. Section 1350 executed by Stephen C. Haynes, Vice President, Chief Financial Officer and 

Treasurer. 

 99.1 Financial statements of Petrodelta, S.A. for the years ended December 31, 2012 and 2011. 

 99.2 Reserve report dated February 15, 2013 between HNR Finance B.V. and Ryder Scott Company. 

101.INS XBRL Instance Document 

101.SCH XBRL Schema Document 

101.CAL XBRL Calculation Linkbase Document 

101.LAB XBRL Label Linkbase Document 

101.PRE XBRL Presentation Linkbase Document 

101.DEF XBRL Definition Linkbase Document 

 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. 

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Table of Contents 

Report of Independent Registered Public Accounting Firm 

To the Board of Directors and Stockholders of Harvest Natural Resources, Inc. 

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)1 present fairly, in all material respects, the 

financial position of Harvest Natural Resources, Inc. and its subsidiaries at December 31, 2012 and December 31, 2011, and the results of their 

operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles 

generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule, Schedule II—Valuation and 

Qualifying Accounts, listed in the index appearing under Item 15(a)2 presents fairly, in all material respects, the information set forth therein 

when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company did not maintain, in all material 

respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—

Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because material

weaknesses in internal control over financial reporting related to (1) a sufficient complement of accounting and financial reporting resources; 

(2) accounting for certain transactions for oil and gas properties; (3) accounting for income taxes; (4) appropriate segregation of duties related 

to certain system access rights and the recording and review of journal entries; (5) preparation and review of certain classification and 

disclosure matters impacting the financial statements and related notes; and (6) accounting for significant and complex debt and equity 

transactions existed as of that date. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial 

reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be 

prevented or detected on a timely basis. The material weaknesses referred to above are described in Management’s Report on Internal Control 

Over Financial Reporting appearing under Item 9A. We considered these material weaknesses in determining the nature, timing, and extent of 

audit tests applied in our audit of the 2012 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s 

internal control over financial reporting does not affect our opinion on those consolidated financial statements. The Company’s management is 

responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting 

and for its assessment of the effectiveness of internal control over financial reporting included in management’s report referred to above. Our 

responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control 

over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company 

Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about 

whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was 

maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts 

and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and 

evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an 

understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the 

design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as 

we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As 

discussed in Note 2 to the consolidated financial statements, the Company has not generated revenue and has incurred recurring losses and 

negative cash flows from operations that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard 

to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the 

outcome of this uncertainty. 

As discussed in Note 3, the Company restated its 2011 and 2010 consolidated financial statements and financial statement schedule to correct 

errors. 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of 

financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting 

principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of 

records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide 

reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally 

accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of 

management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized 

acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any 

evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or 

that the degree of compliance with the policies or procedures may deteriorate. 

/s/PricewaterhouseCoopers LLP 

Houston, Texas 

May 2, 2013 

 

S-1 
Table of Contents 

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

CONSOLIDATED BALANCE SHEETS 

 

See accompanying notes to consolidated financial statements. 

 

S-2 

 December 31, 

 2012 2011 

 

(in thousands, except per 

share data) 

 

(RESTATEDSEE NOTE 3) 

ASSETS 

CURRENT ASSETS: 

Cash and cash equivalents $ 72,627 $ 58,946 

Restricted cash 1,000 1,200 

Accounts and notes receivable, net 

Joint interest and other 2,955 14,342 

Note receivable — 3,335 

Advances to and receivables from equity affiliate 656 14,588 

Deferred income taxes 821 — 

Prepaid expenses and other 1,460 728 

 

TOTAL CURRENT ASSETS 79,519 93,139 

OTHER ASSETS 7,613 5,427 

LONG-TERM RECEIVABLE – EQUITY AFFILIATE 14,346 — 

INVESTMENT IN EQUITY AFFILIATE 412,823 345,054 

PROPERTY AND EQUIPMENT: 

Oil and gas properties (successful efforts method) 81,792 62,455 

Other administrative property, net 744 1,128 

 

TOTAL PROPERTY AND EQUIPMENT, NET 82,536 63,583 

 

TOTAL ASSETS $ 596,837 $ 507,203 

 

 

 

 

LIABILITIES AND EQUITY 

CURRENT LIABILITIES: 

Accounts payable, trade and other $ 3,970 $ 7,381 

Accounts payable – carry obligation — 3,596 

Accrued expenses 30,748 15,247 

Accrued interest 624 976 

Other current liabilities 3,538 2,632 

Income taxes payable 102 689 

 

TOTAL CURRENT LIABILITIES 38,982 30,521 

OTHER LONG TERM LIABILITIES 1,108 908 

WARRANT DERIVATIVE LIABILITY 5,470 4,870 

LONG TERM DEBT 74,839 31,535 

COMMITMENTS AND CONTINGENCIES (See Note 7) 

EQUITY 

STOCKHOLDERS’ EQUITY: 

Preferred stock, par value $0.01 a share; authorized 5,000 shares; outstanding, none — — 

Common stock, par value $0.01 a share; authorized 80,000 shares at December 31, 2012 (2011: 80,000 

shares); issued 45,882 shares at December 31, 2012 (2011: 40,625 shares) 458 406 

Additional paid-in capital 263,646 227,800 

Retained earnings 181,378 193,589 

Treasury stock, at cost, 6,527 shares at December 31, 2012 (2011: 6,521 shares) (66,145 ) (66,104 ) 

 

TOTAL HARVEST STOCKHOLDERS’ EQUITY 379,337 355,691 

NONCONTROLLING INTEREST 97,101 83,678 

 

TOTAL EQUITY 476,438 439,369 

 

TOTAL LIABILITIES AND EQUITY $ 596,837 $ 507,203 

 

 

 

 
Table of Contents 

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) 

 

See accompanying notes to consolidated financial statements. 

 

S-3 

 Years Ended December 31, 

 2012 2011 2010 

 (in thousands, except per share data) 

 

(RESTATEDSEE NOTE 3) (RESTATEDSEE NOTE 3) 

Expenses 

Depreciation and amortization 423 462 484 

Exploration expense 9,068 12,565 8,329 

Impairment of oil and gas properties 9,312 3,335 — 

Dry hole costs 5,617 49,676 — 

General and administrative 27,097 22,474 25,903 

 

 51,517 88,512 34,716 

 

Loss from Operations (51,517 ) (88,512 ) (34,716 ) 

Other Non-Operating Income (Expense) 

Investment earnings and other 348 665 557 

Unrealized gain (loss) on warrant derivatives (600 ) 9,786 344 

Interest expense (1,590 ) (7,159 ) (3,787 ) 

Debt conversion expense (3,645 ) — — 

Loss on extinguishment of debt (5,425 ) (13,132 ) — 

Other non-operating expense (2,905 ) (1,375 ) (3,952 ) 

Foreign currency transaction loss (133 ) (146 ) (1,588 ) 

 

 (13,950 ) (11,361 ) (8,426 ) 

 

Loss from Continuing Operations Before Income Taxes (65,467 ) (99,873 ) (43,142 ) 

Income Tax Expense (Benefit) (609 ) 1,057 (184 ) 

 

Loss from Continuing Operations (64,858 ) (100,930 ) (42,958 ) 

Net Income from Equity Affiliates 67,769 73,451 66,291 

 

Net Income (Loss) from Continuing Operations 2,911 (27,479 ) 23,333 

Discontinued Operations: 

Income (loss) from discontinued operations (1,699 ) (2,636 ) 3,712 

Gain on sale of assets — 106,000 — 

Income tax expense on discontinued operations — (5,748 ) — 

 

Income (loss) from discontinued operations (1,699 ) 97,616 3,712 

 

Net Income 1,212 70,137 27,045 

Less: Net Income Attributable to Noncontrolling Interest 13,423 14,177 12,670 

 

Net Income (Loss) Attributable to Harvest $ (12,211 ) $ 55,960 $ 14,375 

 

 

 

 

 

 

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

(See Note 4 – Earnings Per Share ): 

Basic $ (0.33 ) $ 1.64 $ 0.43 

 

 

 

 

 

 

Diluted $ (0.33 ) $ 1.64 $ 0.39 

 

 

 

 

 

 

Comprehensive Income (Loss) $ (12,211 ) $ 55,960 $ 14,375 

 

 

 

 

 

 
Table of Contents 

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 

(in thousands) 

 

See accompanying notes to consolidated financial statements. 

 

S-4 

 

Common 

Shares 

Issued 

Common 

Stock 

Additional 

Paid-in 

Capital 

Retained 

Earnings 

Treasury 

Stock 

NonControlling 

Interest 

Total 

Equity 

Balance at January 1, 2010 as 

RESTATED (see Note 3) 39,495 $ 395 $ 213,337 $ 123,254 $ (65,383 ) $ 56,831 $ 328,434 

Issuance of common shares: 

Exercise of stock options 419 4 1,670 — — — 1,674 

Restricted stock awards 189 2 1,837 — — — 1,839 

Employee stock-based compensation — — 2,396 — — — 2,396 

Purchase of Treasury Shares — — — — (160 ) — (160 ) 

Net Income — — — 14,375 — 12,670 27,045 

 

Balance at December 31, 2010 as 

RESTATED (see Note 3) 40,103 401 219,240 137,629 (65,543 ) 69,501 361,228 

Issuance of common shares: 

Exercise of stock options 167 2 922 — — — 924 

Restricted stock awards 273 2 2,028 — — — 2,030 

Employee stock-based compensation — — 2,611 — — — 2,611 

Conversion of 8.25% senior convertible notes 82 1 464 — — — 465 

Purchase of treasury shares — — — — (561 ) — (561 ) 

Tax benefits related to equity compensation — — 2,535 — — — 2,535 

Net Income — — — 55,960 — 14,177 70,137 

 

Balance at December 31, 2011 as 

RESTATED (see Note 3) 40,625 406 227,800 193,589 (66,104 ) 83,678 439,369 

Issuance of common shares: 

Exercise of stock options 122 1 718 — — — 719 

Restricted stock awards 203 2 1,564 — — — 1,566 

Employee stock-based compensation — — 1,934 — — — 1,934 

Conversion of 8.25% senior convertible notes 4,932 49 29,058 — — — 29,107 

Warrants issued — — 2,572 — — — 2,572 

Purchase of treasury shares — — — — (41 ) — (41 ) 

Net Income (Loss) — — — (12,211 ) — 13,423 1,212 

 

Balance at December 31, 2012 45,882 $ 458 $ 263,646 $ 181,378 $ (66,145 ) $ 97,101 $ 476,438 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF CASH FLOWS 

(in thousands) 

 

 Years Ended December 31, 

 2012 2011 2010 

 (in thousands) 

 

(RESTATEDSEE NOTE 3) (RESTATEDSEE NOTE 3) 

Cash Flows From Operating Activities: 

Net income $ 1,212 $ 70,137 $ 27,045 

Adjustments to reconcile net income to net cash used in operating activities: 

Depletion, depreciation and amortization 423 1,272 3,817 

Impairment of oil and gas properties costs 9,312 3,335 — 

Dry hole costs 5,617 40,467 — 

Impairment of long-lived assets — 1,440 — 

Amortization of debt financing costs 690 975 793 

Amortization of discount on debt 543 2,876 1,308 

Write off of deferred financing costs — — 2,795 

Gain on sale of assets — (106,225 ) — 

Debt conversion expense 2,915 — — 

Allowance for account and notes receivable 5,180 — — 

Write off of accounts payable, carry obligation (3,596 ) — — 

Loss on early extinguishment of debt 5,425 10,983 — 

Net income from equity affiliates (67,769 ) (73,451 ) (66,291 ) 

Share-based compensation-related charges 3,500 4,642 4,234 

Dividend received from affiliate — — 12,220 

Unrealized (gain) loss on warrant derivative 600 (9,786 ) (344 ) 

Deferred tax asset (821 ) — — 

Other current liabilities 906 2,632 — 

Changes in operating assets and liabilities: 

Accounts and notes receivable 9,542 (10,025 ) 3,826 

Prepaid expenses and other (718 ) 4,065 (2,579 ) 

Other assets (87 ) (4,180 ) 558 

Accounts payable (3,411 ) (623 ) 10,905 

Accrued expenses 4,757 7,475 (2,657 ) 

Accrued interest (238 ) (942 ) (4,239 ) 

Other long term liabilities 200 (927 ) 1,501 

Income taxes payable (587 ) 617 (1,018 ) 

 

Net Cash Used In Operating Activities (26,405 ) (55,243 ) (8,126 ) 

 

Cash Flows from Investing Activities: 

Proceeds from sale of assets — 218,823 — 

Additions of property and equipment (23,575 ) (72,180 ) (14,386 ) 

Additions to assets held for sale — (33,930 ) (45,066 ) 

Advances (to) from equity affiliate (414 ) (682 ) 3,221 

Proceeds from sale of equity affiliates — 1,385 — 

(Increase) decrease in restricted cash 200 (1,200 ) — 

 

Net Cash Provided By (Used In) Investing Activities (23,789 ) 112,216 (56,231 ) 

 

Cash Flows from Financing Activities: 

Net proceeds from issuances of common stock 719 924 1,674 

Tax benefits related to equity compensation — 2,535 — 

Proceeds from issuance of long-term debt 66,480 — 92,000 

Payments of long-term debt — (60,000 ) — 

Financing costs (3,324 ) (189 ) (2,931 ) 

 

Net Cash Provided By (Used In) Financing Activities 63,875 (56,730 ) 90,743 

 

Net Increase in Cash and Cash Equivalents 13,681 243 26,386 

Cash and Cash Equivalents at Beginning of Year 58,946 58,703 32,317 

 

Cash and Cash Equivalents at End of Year $ 72,627 $ 58,946 $ 58,703 

 

 

 

 

 

 

Supplemental Disclosures of Cash Flow Information: 

Cash paid during the year for interest expense (net of capitalization) $ 640 $ 2,685 $ 1,380 

 

 

 

 

 

 
See accompanying notes to consolidated financial statements. 

 

S-5 

Cash paid during the year for income taxes $ 216 $ 8,241 $ 834 

 

 

 

 

 

 
Table of Contents 

Supplemental Schedule of Noncash Investing and Financing Activities: 

During the year ended December 31, 2012, we settled 70,994 restricted stock units with Harvest common stock valued at $0.4 million. 

Also, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 7,789 shares being 

added to treasury stock at cost. During the year ended December 31, 2012, capital expenditures of $10.5 million were financed through current 

liabilities. See Note 3 – Summary of Significant Accounting Policies, Other Assets for a discussion of certain non-cash asset transactions and 

Note 6 – Long-Term Debt for a discussion of other non-cash equity transactions. 

During the year ended December 31, 2011, we issued 0.2 million shares of restricted stock valued at $2.0 million. Also, some of our 

employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 45,532 shares being added to treasury 

stock at cost. During the year ended December 31, 2011, capital expenditures of $3.4 million were financed through current liabilities. 

During the year ended December 31, 2010, we issued 0.3 million shares of restricted stock valued at $1.8 million. Also some of our 

employees elected to pay withholding tax on restricted stock grants on a cashless basis, which resulted in 26,260 shares being added to treasury 

stock at cost; and 1,000 shares held in treasury that had been reissued as restricted stock were forfeited and returned to treasury. During the year 

ended December 31, 2010, capital expenditures of $7.6 million were financed through current liabilities. During the year ended December 31, 

2010, the fair value of our warrant derivative liability of $15.0 million was offset through long-term debt. 

See accompanying notes to consolidated financial statements. 

 

S-6 
Table of Contents 

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

Notes to Consolidated Financial Statements 

Note 1 – Organization 

Harvest Natural Resources, Inc. (“Harvest”) is an independent energy company engaged in the acquisition, exploration, development, 

production and disposition of oil and natural gas properties since 1989, when it was incorporated under Delaware law. 

We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests 

are owned through Harvest-Vinccler Dutch Holding, B.V., a Dutch private company with limited liability (“Harvest Holding”). Our ownership 

of Harvest Holding is through HNR Energia, B.V. (“HNR Energia”) in which we have a direct controlling interest. Through HNR Energia, we 

indirectly own 80 percent of Harvest Holding and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled 

affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining 20 percent interest of 

Harvest Holding. Harvest Holding owns, indirectly through wholly owned subsidiaries, a 40 percent of Petrodelta, S.A. (“Petrodelta”). As we 

indirectly own 80 percent of Harvest Holding, we indirectly own a net 32 percent interest in Petrodelta, and Vinccler indirectly owns eight 

percent. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. Petroleos de Venezuela S.A. 

(“PDVSA”) owns 100 percent of CVP. Harvest Holding has a direct controlling interest in Harvest Vinccler S.C.A. (“Harvest Vinccler”). 

Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with PDVSA. We do not have a 

business relationship with Vinccler outside of Venezuela. 

In addition to our interests in Venezuela, we hold exploration acreage in four projects: 

 

 

 

 

Note 2 – Liquidity and Going Concern 

Historically, our primary ongoing source of cash has been dividends from Petrodelta and the sale of oil and gas properties. See Note 5 – 

Dispositions – Discontinued Operations . Currently, our source of cash is expected to be generated by accessing debt and/or equity markets, 

and/or farm-downs. 

Our primary ongoing use of cash has been to fund oil and gas exploration projects, debt, interest, and general and administrative costs. 

We require capital principally to fund the exploration and development of new oil and gas properties. As is common in the oil and gas industry, 

we have various contractual commitments pertaining to exploration, development and production activities. See Note 14 – Indonesia and Note 

15 – Gabon for our contractual commitments. 

 

S-7 

 

• Mainly onshore in West Sulawesi in the Republic of Indonesia (“Indonesia”) through the Budong-Budong Production Sharing Contract 

(“Budong PSC”) (see Note 14 – Indonesia ), 

 • Offshore of the Republic of Gabon (“Gabon”) through the Dussafu Marin Permit (“Dussafu PSC”) (see Note 15 – Gabon ), 

 

• Onshore in the Sultanate of Oman (“Oman”) through the Oman Exploration and Production Sharing Agreement (“EPSA”) Al Ghubar / 

Qarn Alam license (“Block 64 EPSA”) (see Note 16 – Oman ), and 

 • Offshore of the People’s Republic of China (“China”) through the Wab-21 Petroleum Contract (see Note 17 – China ). 
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The environments in which we operate are often difficult and the ability to operate successfully depends on a number of factors including 

our ability to control the pace of development, our ability to apply “best practices” in drilling and development, and the fostering of productive 

and transparent relationships with local partners, the local community and governmental authorities. Financial risks include our ability to 

control costs and attract financing for our projects. In addition, often the legal systems of certain countries are not mature and their reliability 

can be uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and natural gas 

projects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy depends on our ability to have significant 

influence over operations and financial control. 

Our operations are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, 

property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other political 

risks, increases in taxes and governmental royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts 

or tribunals, renegotiation of contracts with governmental entities, changes in laws and policies, including taxes, governing operations of 

foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government 

sovereignty over our international operations. Our international operations may also be adversely affected by the U.S. Foreign Corrupt 

Practices Act and similar worldwide anti-corruption laws, laws and policies of the United States affecting foreign policy, foreign trade, taxation 

and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States. 

There are also a number of variables and risks related to our minority equity investment in Petrodelta that could significantly utilize our 

cash balances, and affect our capital resources and liquidity. Petrodelta’s capital commitments are determined by its business plan, and 

Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. The total capital required to develop the fields in 

Venezuela may exceed Petrodelta’s available cash and financing capabilities, and there may be operational or contractual consequences due to 

this inability. Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Due to PDVSA’s liquidity 

constraints, PDVSA has not been providing the necessary monetary support and contractual adherence required by Petrodelta. If we are called 

upon to fund our share of Petrodelta’s operations, our failure to do so could be considered a default under the Conversion Contract and cause 

the forfeiture of some or all our shares in Petrodelta. 

Petrodelta currently represents our only source of earnings. Petrodelta also has a material impact on our results of operations for any 

quarter or annual reporting period. See Note 13 – Investment in Equity Affiliate – Petrodelta, S.A . Petrodelta operates under a business plan, the 

success of which relies heavily on the market price of oil. To the extent that market prices of oil decline, the business plan, and thus our equity 

investment and/or operations and/or profitability, could be adversely affected. 

Operations in Venezuela are subject to various risks inherent in foreign operations. It is possible the legal or fiscal framework for 

Petrodelta could change and the Venezuela government may not honor its commitments. Our ability to implement or influence Petrodelta’s 

business plan, assure quality control and set the timing and pace of development could also be adversely impacted. No assurance can be 

provided that events beyond our control will not adversely affect the value of our minority investment in Petrodelta. 

Between Petrodelta’s formation in October 2007 and June 2010, Petrodelta declared and paid dividends of $105.5 million to HNR 

Finance, B.V. (“HNR Finance”), a wholly owned subsidiary of Harvest Holding ($84.4 million net to our 32 percent interest). See Note 18 – 

Related Party Transactions for a discussion of our obligations to our non-controlling interest holder, Vinccler, for any dividend received from 

Petrodelta. As discussed below, on November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million; however, such 

dividend has not been received. There is uncertainty with respect to the timing of the receipt of such dividend or whether future dividends will 

be declared and/or paid. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable not be collected, or 

facts and circumstances surrounding our investment change, our results of operations and our investment in Petrodelta could be adversely 

impacted. 

We have incurred losses from continuing operations since 2007 and negative cash flows since 2009 and have utilized the proceeds from 

the sale of property and debt to fund our operations. For the year ended December 31, 2012, we incurred a net loss attributable to Harvest of 

approximately $12.2 million and negative cash flows from operations of approximately $26.4 million. At December 31, 2012, we had retained 

earnings of approximately $181.4 million and working capital of approximately $40.5 million. We currently do not have any revenue or 

operating cash inflow and, as indicated above, historically our main source of cash has been dividends 

 

S-8 
Table of Contents 

from Petrodelta. On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR 

Finance ($9.8 million net to our 32 percent interest). The dividend was ratified by Petrodelta’s shareholders on March 14, 2011. Due to 

Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, this dividend has not yet been 

received, although it is due and payable. Our other main source of cash is the sale of assets. As discussed in Note 5 – Dispositions , on June 21, 

2012, we announced entering into an agreement for the sale of our investment in Petrodelta. However, the buyer’s sole shareholder did not 

approve the transaction, and on February 19, 2013, we exercised our right to terminate the agreement. 

We expect that for 2013 we will not generate revenue, will continue to generate losses from operations, and our cash flows will not be 

sufficient to cover our operating expense; therefore, expected continued losses from operations and use of cash will be funded through debt or 

equity financings, farm-downs, delay of the discretionary portion of our capital spending to future periods and/or operating cost reductions. To 

meet our capital needs, we are considering multiple alternatives, including, but not limited to, additional debt and/or equity financing, farmdown, delay of the discretionary portion of our capital spending to future periods and/or operating cost reductions. Our ability to continue as a 

going concern also depends upon the success of our planned exploration and development activities. There can be no guarantee of future capital 

acquisition, fundraising or explorations 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. 

Failure to generate sufficient cash flow, raise additional capital through debt or equity financings, farm-downs, and/or further reduce 

operating costs could have a material adverse effect on our ability to meet our short- and long-term liquidity needs and achieve our intended 

long-term business objectives. 

While we believe the issuance of additional equity securities, short- or long-term debt financing, farm-downs, delay of the discretionary 

portion of our capital spending to future periods and/or operating cost reductions could be put into place which would not jeopardize our 

operations and future growth plans, these circumstances raise substantial doubt about our ability to continue to operate as a going concern. 

The audit opinion on our financial statements as of and for the year ended December 31, 2012 includes an explanatory paragraph 

expressing substantial doubt regarding our ability to continue as a going concern. Our financial statements have been prepared under the 

assumption that we will continue as a going concern, which contemplates that we will continue in operation for the foreseeable future and will 

be able to realize assets and settle liabilities and commitments in the normal course of business. The accompanying consolidated financial 

statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or amounts and 

classification of liabilities that could result should we be unable to continue as a going concern. 

Note 3 – Summary of Significant Accounting Policies

Restatement of Prior Period Financial Statements 

In connection with the preparation of our Annual Report on Form 10-K for the year ended December 31, 2012, we concluded that there 

were errors in previously filed financial statements. In the course of our review, management determined that (a) certain warrants issued in 

2010 in connection with our $60 million term loan facility (the “Warrants”) were improperly valued at inception and improperly classified as 

equity instruments rather than liability instruments. As a result of the improper classification of the Warrants, (b) the debt discount and 

associated interest expense related to the amortization of the debt discount was understated for all periods in which the associated debt was 

outstanding, and (c) the consolidated statement of operations and comprehensive income (loss) for each reporting period was misstated by the 

omission of the changes in fair value of the Warrants as a liability instrument. Additionally, (d) certain exploration overhead was incorrectly 

capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed, and (e) certain 

leasehold maintenance and other costs were improperly capitalized to oil and gas properties, which under the successful efforts method of 

accounting should have been expensed. Finally, (f) advances to equity affiliate were improperly classified as an operating activity rather than 

an investing activity and (g) certain costs were improperly classified as an investing activity rather than an operating activity on the 

consolidated statement of cash flows. Such errors impacted annual periods ended December 31, 2010 and 2011 and quarterly periods ended 

March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012, and September 30, 2012. 

As a result of the errors related to the Warrants described above, loss on extinguishment of debt was understated for the year ended 

December 31, 2011 and the quarters ended June 30, 2011, September 30, 2011 and December 31, 2011. 

Additionally, an error was identified in the calculation of earnings (loss) per diluted share for the year ended December 31, 2011 and the 

three and six months ended June 30, 2011, and an additional error was identified related to the improper expensing of costs associated with 

debt conversions that should have been recorded to equity for the quarters ended March 31, 2012 and September 30, 2012. 

 We have restated our segment footnote information to reflect the applicable errors stated above and (a) reclassify noncontrolling interest 

from United States segment to Venezuela segment, (b) eliminate intrasegment receivables erroneously reported gross of related intrasegment 

payable, and (c) eliminate intrasegment revenue erroneously reported gross of related intrasegment expense. Such errors impacted annual 

periods ended December 31, 2010 and 2011 and quarterly periods ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 

2011, March 31, 2012, June 30, 2012 and September 30, 2012. We also restated our financial statement schedule to reflect adjustments to the 

balance sheet related to income taxes for the years ended December 31, 2010 and 2011. 

 In assessing the severity of the errors, management determined that the errors were material to the consolidated financial statements for 

the years ended December 31, 2011 and 2010 and quarterly information for all quarters in 2011 and the first, second and third quarters of 2012. 
In addition to the errors described above, we made corrections for previously identified immaterial errors and errors affecting classification 

within the consolidated statement of operations and comprehensive income (loss) related to impairment of oil and gas properties and income 

taxes and the consolidated balance sheets related to income taxes. 

The audited financial statements, related notes and analyses for the years ended December 31, 2011 and 2010 have been retrospectively 

restated in this Annual Report on Form 10-K for the year ended December 31, 2012. We will amend our Quarterly Reports on Form 10-Q/A for 

each of the quarterly periods shortly after the filing of this Annual Report on Form 10-K. 

The following tables set forth the effect of the adjustments described above on the consolidated statements of operations and 

comprehensive income (loss), the consolidated statements of cash flows and the consolidated statements of stockholders’ equity for the years 

ended December 31, 2011 and 2010, and the consolidated balance sheet as of December 31, 2011. 

 

S-9 
Table of Contents 

Consolidated Statements of Operations and Comprehensive Income (Loss) 

 

 

 

S-10 

 December 31, 2011 December 31, 2010 

 As Previously As As Previously As 

 Reported Adjustment RESTATED Reported Adjustment RESTATED 

 (in thousands) 

Expenses 

Depreciation and amortization $ 462 $ — $ 462 $ 484 $ — $ 484 

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

Impairment of oil and gas properties — 3,335 3,335 — — — 

Dry hole costs 49,676 — 49,676 — — — 

General and administrative 22,474 — 22,474 25,903 — 25,903 

 

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

 

Loss from operations (86,302 ) (2,210 ) (88,512 ) (34,403 ) (313 ) (34,716 ) 

Other non-operating income (expense) 

Investment earnings and other 665 — 665 557 — 557 

Unrealized gain (loss) on warrant derivatives — 9,786 9,786 — 344 344 

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

Loss on extinguishment of debt (9,682 ) (3,450 ) (13,132 ) — — — 

Other non-operating expense (1,375 ) — (1,375 ) (3,952 ) — (3,952 ) 

Loss on exchange rates (146 ) — (146 ) (1,588 ) — (1,588 ) 

 

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

 

Loss from Continuing Operations Before Income 

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

Income tax expense (benefit) 820 237 1,057 (184 ) — (184 ) 

 

Loss from Continuing Operations (102,996 ) 2,066 (100,930 ) (41,891 ) (1,067 ) (42,958 ) 

Net Income from Equity Affiliate 73,451 — 73,451 66,291 — 66,291 

 

Net Income (Loss) from Continuing Operations (29,545 ) 2,066 (27,479 ) 24,400 (1,067 ) 23,333 

Income (Loss) from Discontinued Operations 97,616 — 97,616 3,712 — 3,712 

 

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

Less: Net Income Attributable to Noncontrolling 

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

 

Net Income (Loss) Attributable To Harvest $ 53,894 $ 2,066 $ 55,960 $ 15,442 $ (1,067 ) $ 14,375 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Attributable to Harvest Per 

Common Share: 

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

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss) $ 53,894 $ 2,066 $ 55,960 $ 15,442 $ (1,067 ) $ 14,375 

 

 

 

 

 

 

 

 

 

 

 

 

(a) For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties 

rather than expensed as exploration expense of $2,210 thousand offset by a reclassification from exploration expense to impairment of oil 

and gas properties of $3,335 thousand for amounts that were erroneously classified as exploration expense. For 2010, relates to lease 

maintenance costs that were erroneously capitalized as oil and gas properties rather than as exploration expense. 

(b) Represents change in fair value of the Warrants for the period. Such Warrants were previously erroneously classified as equity and were, 

therefore, not marked to market at the end of each reporting period. 

(c) The fair value of the Warrants was not appropriately determined at inception because certain features of the Warrants were not originally 

considered in the fair value calculation. The corrected fair value of the Warrants at inception exceeds the original valuation by $3,878 

thousand. As a result of this change in the fair value of the Warrants, the original discount allocated to the debt was understated by 

approximately $3,878 thousand; therefore, the additional amortization of the discount on debt, which is a component of interest expense, 

was understated for each period the debt was outstanding. For 2011, income tax expense of $237 thousand was improperly classified as 

interest expense. 

(a) 

(f) 

(b) 

(c) 

(d) 

(g) 

(e) 
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Consolidated Balance Sheets 

 

 

 

S-11 

(d) As noted in (c) above, the correction in the fair value of the Warrants and its classification as a liability resulted in an increased discount 

on debt which also impacted the resulting loss on extinguishment of debt originally recorded in May 2011 when the debt was retired. 

(e) In addition to the impact on EPS related to the adjustments described in (a) through (d) above and (f) and (g) below, diluted EPS has been 

adjusted to reflect an error in the calculation of the weighted average common shares outstanding for dilutive EPS as of December 31, 

2011. The weighted average common shares utilized for the calculation of diluted EPS was erroneously 39,339 thousand rather than 

34,117 thousand. 

(f) Reclassification of impairment of oil and gas properties expense in 2011 of $3,335 thousand that was previously erroneously presented as 

exploration expense. 

(g) Represents income tax improperly classified as interest expense. 

 December 31, 2011 

 

As 

Previously 

Reported Adjustment 

As 

RESTATED 

 (in thousands) 

Deferred income taxes $ 2,628 $ (2,628 ) $ — 

Oil and gas properties 65,671 (3,216 ) 62,455 

Total assets 513,047 (5,844 ) 507,203 

Accrued interest payable 1,372 (396 ) 976 

Other current liabilities 4,835 (2,203 ) 2,632 

Income taxes payable 718 (29 ) 689 

Warrant derivative liability — 4,870 4,870 

Total liabilities 65,592 2,242 67,834 

Additional paid in capital 236,192 (8,392 ) 227,800 

Retained earnings 193,283 306 193,589 

Total Harvest shareholders’ equity 363,777 (8,086 ) 355,691 

Total equity 447,455 (8,086 ) 439,369 

(a) Relates to a deferred tax asset that was erroneously reported gross of the related liability. 

(b) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. 

(c) Relates to the reclassification of the Warrants out of additional paid in capital to warrant derivative liabilities. The fair value of the 

Warrants was not appropriately determined at inception because certain features of the Warrants were not originally considered in the fair 

value calculation. Thus, the correction of the error to record the Warrants as a liability does not agree to the correction of the error 

removing the Warrants from equity. Additionally, the Warrants were not properly marked to market at the end of each period. The 

warrant derivative liability was valued at $15,000 thousand at inception with subsequent reductions in fair value of $344 thousand in 

2010 and $9,786 thousand in 2011. 

(d) Relates to the reversal of the amount recorded to equity at inception for the Warrants of $11,122 thousand and the reversal of the amount 

removed from additional paid in capital of $2,730 thousand when a portion of the Warrants were redeemed by the Company. In May 

2011, additional paid in capital was debited for $2,730 thousand for the reversal of the original fair value of such warrants which was an 

error as they did not qualify for equity classification. 

(e) Relates to (a) net increase in expense in 2010 and 2011 related to exploration expense of $2,523 thousand (inclusive of the 

reclassification of exploration expense to impairment of oil and gas properties of $3,335 thousand), (b) net increase in unrealized gain on 

warrant derivatives of $10,130 thousand for cumulative 2010 and 2011, (c) net increase in interest expense of $2,921 thousand 

cumulative for 2010 and 2011, (d) net increase in loss on extinguishment of debt of $3,450 thousand for 2011 (e) net increase in income 

tax expense of $237 thousand for income taxes improperly classified as interest expense, offset by a reduction to retained earnings of 

$693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than 

expensed prior to January 1, 2010. 

(f) Relates to reclassification of the Warrants as described in (d) above plus the impact of retained earnings described in (e) above. 

(g) Represents other current liabilities that were improperly classified as interest payable and income taxes payable. 

(a) 

(b) 

(a)(b) 

(g) 

(a)(g) 

(g) 

(c) 

(a)(c)(g) 

(d) 

(e) 

(f) 

(f) 
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Consolidated Statements of Cash Flows 

 

 

In addition to the above, we have restated the Consolidated Statements of Stockholder’s Equity to reflect the reclassification of the 

Warrants from equity to warrant derivative liability and to restate the January 1, 2010 beginning balances to reflect cumulative adjustments 

related to the previously described errors that affect periods prior to the year ended December 31, 2010 as follows: 

 

 

 

 

 

S-12 

 December 31, 2011 December 31, 2010 

 

As 

Previously 

Reported Adjustment 

As 

RESTATED 

As 

Previously 

Reported Adjustment 

As 

RESTATED 

 (in thousands) 

Net cash used in operating activities $ (52,737 ) $ (2,506 ) $ (55,243 ) $ (5,296 ) $ (2,830 ) $ (8,126 ) 

Net cash provided by (used in) investing activities 109,710 2,506 112,216 (59,061 ) 2,830 (56,231 ) 

Net cash provided by (used in) financing activities (56,730 ) — (56,730 ) 90,743 — 90,743 

 

Net increase in cash and cash equivalents 243 — 243 26,386 — 26,386 

Cash and cash equivalents at beginning of year 58,703 — 58,703 32,317 — 32,317 

 

Cash and cash equivalents at end of year $ 58,946 $ — $ 58,946 $ 58,703 $ — $ 58,703 

 

 

 

 

 

 

 

 

 

 

 

 

(a) For 2011, relates to the $2,288 thousand of lease maintenance costs, exploration overhead and $900 thousand of certain investment costs 

that were improperly classified as an investing activity rather than an operating activity. In addition, Advances to Equity Affiliates of 

$(682) thousand were previously erroneously classified as an operating activity rather than an investing activity. 

(b) For 2010, relates to $167 thousand of lease maintenance costs and $(558) thousand of certain investment costs that were improperly 

classified as an investing activity rather than an operating activity. In addition, Advances to Equity Affiliates of $3,221 thousand were 

improperly classified as an operating activity rather than an investing activity. 

 

Common 

Shares 

Issued 

Common 

Stock 

Additional 

Paid-in 

Capital 

Retained 

Earnings 

Treasury 

Stock 

NonControlling 

Interest 

Total 

Equity 

Balance at January 1, 2010 as originally reported 39,495 $ 395 $ 213,337 $ 123,947 $ (65,383 ) $ 56,831 $ 329,127 

Adjustments — — — (693 ) — — (693 ) 

 

Balance at January 1, 2010 as RESTATED 39,495 $ 395 $ 213,337 $ 123,254 $ (65,383 ) $ 56,831 $ 328,434 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Relates to lease maintenance costs that were erroneously capitalized as oil and gas properties rather than expensed prior to January 1, 

2010 (the “Beginning Retained Earnings Adjustment”). 

 

Common 

Shares 

Issued 

Common 

Stock 

Additional 

Paid-in 

Capital 

Retained 

Earnings 

Treasury 

Stock 

NonControlling 

Interest 

Total 

Equity 

Balance at December 31, 2010 as originally reported 40,103 $ 401 $ 230,362 $ 139,389 $ (65,543 ) $ 69,501 $ 374,110 

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

 

Balance at December 31, 2010 as RESTATED 40,103 $ 401 $ 219,240 $ 137,629 $ (65,543 ) $ 69,501 $ 361,228 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) The adjustment to additional paid-in capital relates to the reclassification of the Warrants from equity to warrant derivative liability. 

(b) The adjustment to retained earnings relates to (a) lease maintenance costs of $313 thousand that were erroneously capitalized as oil and 

gas properties rather than expensed as exploration expense, (b) the reduction in the fair value of the Warrants for the year ended 

December 31, 2010 of $344 thousand, additional amortization of debt of $1,098 thousand resulting from the increased discount allocated 

to the debt, offset by a reduction to retained earnings of $693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance 

costs that were improperly capitalized as oil and gas properties rather than expensed to exploration expense prior to January 1, 2010. 

(a)(b) 

(a)(b) 

(a) 

(a)(b) 
Table of Contents 

 

In addition to the above, we have restated Operating Segments to reflect the errors stated above and (a) reclassify noncontrolling 

interest from United States segment to Venezuela segment, (b) eliminate intrasegment receivables erroneously reported gross of related 

intrasegment payable, and (c) eliminate intrasegment revenue erroneously reported gross of related intrasegment expense. 

 

 

 

Common 

Shares 

Issued 

Common 

Stock 

Additional 

Paid-in 

Capital 

Retained 

Earnings 

Treasury 

Stock 

NonControlling 

Interest 

Total 

Equity 

Balance at December 31, 2011 as originally reported 40,625 $ 406 $ 236,192 $ 193,283 $ (66,104 ) $ 83,678 $ 447,455 

Adjustments — — (8,392 ) 306 — — (8,086 ) 

 

Balance at December 31, 2011 as RESTATED 40,625 $ 406 $ 227,800 $ 193,589 $ (66,104 ) $ 83,678 $ 439,369 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) The adjustment to additional paid-in capital relates to the reclassification of the Warrants from equity to warrant derivative liability of 

$11,122 thousand offset by an error recorded in 2011 for $2,730 thousand for the reversal of the original fair value of certain Warrants 

that did not qualify for equity classification. 

(b) The adjustment to retained earnings relates to (a) net increase in 2010 and 2011 expense related to exploration expense of $2,523 

thousand that was erroneously capitalized as oil and gas properties rather than expensed as exploration expense (includes consideration of 

reclassification between exploration expense and impairment of oil and gas properties), (b) net increase in unrealized gain on warrant 

derivatives of $10,130 thousand for cumulative 2010 and 2011, (c) net increase in interest expense of $2,921 thousand cumulative for 

2010 and 2011, (d) net increase in loss on extinguishment of debt of $3,450 thousand for 2011, (e) net increase in income tax expense of 

$237 thousand for income taxes improperly classified as interest expense, offset by a reduction to retained earnings of $693 thousand 

prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than expensed prior to 

January 1, 2010. 

 December 31, 2011 December 31, 2010 

 

As Previously 

Reported Adjustments 

As 

Restated 

As Previously 

Reported Adjustments 

As 

Restated 

Segment Income (Loss) Attributable to Harvest 

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

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

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

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

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

 

Net income (loss) from continuing operations (43,722 ) 2,066 (41,656 ) 11,730 (1,067 ) 10,663 

Discontinued operations (Antelope Project) 97,616 — 97,616 3,712 — 3,712 

 

Net income (loss) attributable to Harvest $ 53,894 $ 2,066 $ 55,960 $ 15,442 $ (1,067 ) $ 14,375 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Relates to reclassification of noncontrolling interest from United States segment to Venezuela segment and elimination of intrasegment 

revenue erroneously reported gross of intrasegment expense. 

(b) For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties 

rather than expensed as exploration expense of $1,505 thousand and elimination of intrasegment revenue erroneously reported gross of 

related intrasegment expense of $1,383 thousand. For 2010, relates to elimination of intrasegment revenue erroneously reported gross of 

related intrasegment expense. 

(c) For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties 

rather than expensed as exploration expense of $415 thousand and elimination of intrasegment revenue erroneously reported gross of 

related intrasegment expense of $1,830 thousand. For 2010, relates to lease maintenance costs and exploration overhead costs that were 

erroneously capitalized as oil and gas properties rather than expensed as exploration expense of $313 thousand and elimination of 

intrasegment revenue erroneously reported gross of related intrasegment expense of $786 thousand. 

(d) Relates to elimination of intrasegment revenue erroneously reported gross of related intrasegment expense. 

(e) Relates to the impact of (a) through (d) above. 

(a)(b) 

(a) 

(b) 

(c) 

(d) 

(e) 
 

 

Principles of Consolidation 

The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. All intercompany 

profits, transactions and balances have been eliminated. Third-party interests in our majority-owned subsidiaries are presented as 

noncontrolling interests. 

Presentation of Comprehensive Income (Loss) 

We adopted ASU No. 2011-05 (ASU 2011-05), which is included in ASC 220, “Comprehensive Income”, effective January 1, 2012 and 

have elected to utilize the “single continuous statement” for presentation of all nonowner changes in stockholders’ equity. 

 

S-13 

 December 31, 2011 

 

As Previously 

Reported Adjustment 

As 

RESTATED 

 (in thousands) 

Operating Segment Assets 

Venezuela $ 348,802 $ — $ 348,802 

Indonesia 65,165 (50,572 ) 14,593 

Gabon 119,273 (63,768 ) 55,505 

Oman 20,980 (13,828 ) 7,152 

United States 137,531 122,325 259,856 

 

 691,751 (5,843 ) 685,908 

Intersegment eliminations (178,704 ) (1 ) (178,705 ) 

 

Total Assets $ 513,047 $ (5,844 ) $ 507,203 

 

 

 

 

 

 

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

(a) 

(a) 

(a) 

(a) 
Table of Contents 

Reporting and Functional Currency 

The United States Dollar (“U.S. Dollar”) is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. 

Amounts denominated in non-U.S. Dollar currencies are re-measured into U.S. Dollars, and all currency gains or losses are recorded in the 

consolidated statements of operations and comprehensive income (loss). There are many factors that affect foreign exchange rates and the 

resulting exchange gains and losses, many of which are beyond our influence. 

See Note 12 – Venezuela for a discussion of currency exchange rates and currency exchange risk on Harvest Vinccler’s and Petrodelta’s 

businesses. 

Cash and Cash Equivalents 

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

Restricted Cash 

Restricted cash is classified as current or non-current based on the terms of the agreement. Restricted cash at December 31, 2012 

represents cash held in a U.S. bank used as collateral for a standby letter of credit issued in support of a performance bond for a joint study. 

Restricted cash at December 31, 2011 represents cash held in a U.S. bank used as collateral for a standby letter of credit issued as a payment 

guarantee for electric wireline services to be provided during the drilling of the two exploratory wells on Block 64 EPSA. The restricted cash 

was returned to us on April 18, 2012. 

Financial Instruments 

Financial instruments, which potentially subject us to concentrations of credit risk, are primarily cash and cash equivalents, accounts 

receivable, dividend receivable, notes payable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit 

accounts with commercial banks with high credit ratings, which, at times may exceed the federally insured limits. We have not experienced any 

losses from such investments. Concentrations of credit risk with respect to accounts receivable are limited due the nature of our receivables, 

which include primarily income tax receivables. In the normal course of business, collateral is not required for financial instruments with credit 

risk. 

Notes Receivable 

Notes receivable bear interest and can have due dates that are less than one year or more than one year. Amounts outstanding under the 

notes bear interest at a rate based on the current prime rate and are recorded at face value. Interest income is recognized over the life of the 

note. 

Each note is analyzed to determine if it is impaired pursuant to ASU 2010-20, which is included in ASC 310, “Receivables”. A note is 

impaired if it is probable that we will not collect all principal and interest contractually due. We do not accrue interest when a note is 

considered impaired. All cash receipts on impaired notes are applied to reduce the accrued interest on the note until the interest is made current 

and, thereafter, applied to reduce the principal amount of such notes. 

Other Assets 

Other assets consist of business development acquisition costs associated with new business development projects, prepaid expenses 

which are expected to be realized in the next 12 to 24 months deferred financing costs and a long-term receivable for value added tax (“VAT”) 

credits related to the Budong PSC. New business development acquisition costs are reclassified to oil and gas properties or expensed depending 

on management’s assessment of the project under ASC 932-360-35-19 “Sufficient Progress Assessment”. Deferred financing costs relate to 

specific financing and are amortized over the life of the financing to which the costs relate. See Note 6 – Long-Term Debt . The VAT 

receivable is reimbursed through the sale of hydrocarbons. See Note 14 – Indonesia for development plans for the Budong PSC. 

At December 31, 2012, other assets included $0.2 million of long-term prepaid expenses, $3.2 million of deferred financing costs and 

$3.5 million of long-term VAT receivable. At December 31, 2011, other assets consisted of $0.4 million of new business development costs, 

$1.0 million of deferred financing costs and $3.3 million of long-term VAT receivable. 

 

S-14 
Table of Contents 

Other Assets at December 30, 2012 also includes a blocked payment of $0.7 million (2011: $0.7 million) net to our 66.667 percent 

interest related to our drilling operations in Gabon in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of 

February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”). See Note 7 – 

Commitments and Contingencies . 

Investment in Equity Affiliates 

We evaluate our investments in unconsolidated companies under ASC 323, “Investments – Equity Method and Joint Ventures.” 

Investments in which we have significant influence are accounted for under the equity method of accounting. Under the equity method, 

Investment in Equity Affiliates is increased by additional investments and earnings and decreased by dividends and losses. 

We review our Investment in Equity Affiliates for impairment whenever events and circumstances indicate a loss in investment value is 

other than a temporary decline. At December 31, 2012, we reviewed our investment in Petrodelta under the terms of the share purchase 

agreement (see Note 6 – Dispositions, Share Purchase Agreement (“SPA”) ). The SPA purchase price, subject to adjustment as described in the 

SPA, exceeded the carrying value of our equity investment, the dividend receivable and advances to equity affiliate. As such, we concluded 

that there was no impairment to our equity investment as of December 31, 2012. 

There are many factors to consider when evaluating an equity investment for possible impairment. Currency devaluations, inflationary 

economies, and cash flow analysis are some of the factors we consider in our evaluation for possible impairment. At December 31, 2012, there 

were no events that would indicate that our equity investment in Petrodelta had sustained a loss in value that is other than temporary. 

The SPA was terminated on February 19, 2013 and a devaluation of the Bolivar occurred on February 8, 2013. We do not believe either 

of these events impact our conclusion regarding the value of our equity investment at December 31, 2012. 

We measure and disclose our noncontrolling interests in accordance with the provisions of ASC 810 “Consolidation”. Our noncontrolling 

interest relates to Vinccler’s indirectly owned 20 percent interest in Harvest Holding (see Note 1 – Organization ). 

Oil and Gas Properties 

The major components of property and equipment at December 31 are as follows (in thousands): 

 

Property and equipment are stated at cost less accumulated depletion, depreciation and amortization (“DD&A”). Costs of improvements 

that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and 

repairs are expensed as incurred. Upon retirement or sale, the cost of property and equipment, net of the related accumulated DD&A, is 

removed and, if appropriate, gains or losses are recognized in investment earnings and other. We did not record any depletion expense in the 

years ended December 31, 2012, 2011, or 2010. 

We follow the successful efforts method of accounting for our oil and gas properties. Under this method, exploration costs such as 

exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling 

exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. 

If management determines that proved reserves, as that term is defined in Securities and Exchange Commission (“SEC”) regulations, have not 

been 

 

S-15 

 2012 2011 

 

(RESTATEDSEE NOTE 3) 

Unproved property costs $ 78,453 $ 59,626 

Oilfield inventories 3,339 2,829 

Other administrative property 2,954 3,176 

 

Total property and equipment 84,746 65,631 

Accumulated depreciation (2,210 ) (2,048 ) 

 

Total property and equipment, net $ 82,536 $ 63,583 

 

 

 

 
Table of Contents 

discovered, capitalized costs associated with the drilling of the exploratory well are charged to expense. Costs of drilling successful exploratory 

wells, all development wells, and related production equipment and facilities are capitalized and depleted or depreciated using the unit-ofproduction method as oil and gas is produced. At December 31, 2012, we expensed to dry hole costs $0.7 million related to the drilling of 

Karama-1 (“KD-1”) and first sidetrack, KD-1ST, on the Budong PSC and $4.9 million related to the drilling of Al Ghubar North-A (“AGN-1”) 

on Block 64 EPSA. At December 31, 2011, we expensed to dry hole costs $14.0 million related to the drilling of Lariang-1 (“LG-1”) on the 

Budong PSC, $26.0 million related to the drilling of KD-1 and KD-1ST on the Budong PSC, $6.9 million related to the drilling of Mafraq 

South-A (“MFS-1”) on Block 64 EPSA, and $2.8 million related to the drilling of AGN-1 on Block 64 EPSA. See Note 14 – Indonesia and 

Note 16 – Oman . 

Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the 

holding period. Costs of maintaining and retaining unproved leaseholds, as well as impairment of unsuccessful leases, are included in 

exploration expense. Impairment is based on specific identification of the lease. Costs of expired or abandoned leases are charged to 

exploration expense, while costs of productive leases are transferred to proved oil and gas properties. 

Proved oil and gas properties are reviewed for impairment at a level for which identifiable cash flows are independent of cash flows of 

other assets when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net 

cash flows are determined based on estimated future oil and gas sales revenues less future expenditures necessary to develop and produce the 

reserves. If the sum of these undiscounted estimated future net cash flows is less than the carrying amount of the property, an impairment loss 

is recognized for the excess of the property’s carrying amount over its estimated fair value, which is generally based on discounted future net 

cash flows. We did not have any proved oil and gas properties in 2012, 2011 or 2010. 

Costs of drilling and equipping successful exploratory wells, development wells, asset retirement liabilities and costs to construct or 

acquire offshore platforms and other facilities, are depleted using the unit-of-production method based on total estimated proved developed 

reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved leaseholds, are depleted using 

the unit-of-production method based on total estimated proved reserves. All other properties are stated at historical acquisition cost, net of 

allowance for impairment, and depreciated using the straight-line method over the useful lives of the assets. 

Unproved property costs, excluding oilfield inventories, consist of (in millions): 

 

At December 31, 2012, we impaired the carrying value of Block 64 EPSA, $6.4 million, and WAB -21, $2.9 million. At December 31, 

2011, we impaired the carrying value of West Bay, $3.3 million. 

Other Administrative Property 

Furniture, fixtures and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives, 

which range from three to five years. Leasehold improvements are recorded at cost and amortized using the straight-line method over the life of 

the applicable lease. For the year ended December 31, 2012, depreciation expense was $0.4 million (2011: $0.5 million, 2010: $0.5 million). 

Reserves 

We measure and disclose our oil and gas reserves in accordance with the provisions of the SEC’s Modernization of Oil and Gas 

Reporting and ASC 932, “Extractive Activities – Oil and Gas” (“ASC 932”). All of our reserves are owned through our equity investment in 

Petrodelta. We do not have any wholly owned reserves at December 31, 2012. 

 

S-16 

 2012 2011 

 

(RESTATEDSEE NOTE 3) 

Budong PSC $ 5.2 $ 5.2 

Dussafu PSC 73.3 46.4 

Block 64 EPSA — 5.1 

WAB-21 — 2.9 

 

Total unproved property costs $ 78.5 $ 59.6 

 

 

 

 
Table of Contents 

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. During the year ended December 31, 2012, we capitalized interest costs for qualifying oil and gas property additions of $3.0 

million (2011: $2.3 million, 2010: $1.8 million). 

Derivative Financial Instruments 

Under ASC 480 “Distinguishing Liabilities from Equity”, certain of our financial instruments with anti-dilution protection features do not 

meet the conditions to obtain equity classification, as there are conditions which may require settlement by transferring assets, and are required 

to be carried as derivative liabilities, at fair value, with changes in fair value reflected in our consolidated statements of operations and 

comprehensive income (loss). See Note 10 – Warrant Derivative Liabilities for additional disclosures. In the occurrence of a fundamental 

change, we are required to repurchase the Warrants at the higher of (1) the fair market value of the warrant and (2) a valuation based on a 

computation of the option value of the Warrant using the Black-Scholes calculation method using the assumptions described in the Warrant 

Agreement. A fundamental change is defined as “the occurrence of one of the following events: a) a person or group becomes the direct or 

indirect owner of more than 50% of the voting power of the outstanding common stock, b) a merger event or similar transaction in which the 

majority owners before the transaction fail to own a majority of the voting power of the Company after the transaction, and c) approval of a 

plan of liquidation or dissolution of the Company or sale of all or substantially all of the Company’s assets.” 

Fair Value Measurements 

We measure and disclose our fair values in accordance with the provisions of ASC 820 “Fair Value Measurements and 

Disclosures” (“ASC 820”). ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an 

orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes 

the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active 

markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs 

that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. We utilize market data 

or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the 

inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. 

Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and 

are likely to, change over the duration of the instrument with related changes in internal and external market factors. In addition, option-based 

techniques (such the Monte Carlo model) are highly volatile and sensitive to changes in the trading market price of our common stock. Since 

derivative financial instruments are initially and subsequently carried at fair value, our (income) loss will reflect the volatility in these estimate 

and assumption changes. 

Inherent in the Monte Carlo valuation model are assumptions related to expected stock price volatility, expected life, risk-free interest rate 

and dividend yield. We estimate the volatility of our common stock based on historical volatility that matched the expected remaining life of 

the warrants. The risk-free interest rate is based on the U.S. Treasury yield curve as of the valuation dates for a maturity similar to the expected 

remaining life of the warrants. The expected life of the warrants is assumed to be equivalent to their remaining contractual term. The dividend 

rate is based on the historical rate, which we anticipate to remain at zero. 

As part of our overall valuation process, management employs processes to evaluate and validate the methodologies, techniques and 

inputs, including review and approval of valuation judgments, methods, models, process controls, and results. These processes are designed to 

help ensure that the fair value measurements and disclosures are appropriate, consistently applied, and reliable. 

The Monte Carlo model is used on the warrants to appropriately value the potential future exercise price adjustments triggered by the 

anti-dilution provisions. See Note 10 – Warrant Derivative Liability . This requires Level 3 inputs which are based on our estimates of the 

probability and timing of potential future financings and fundamental transactions. The assumptions we used are summarized in the following 

tables for warrants that were outstanding as of any of the balance sheet dates presented on our consolidated balance sheets: 

 

The following tables set forth by level within the fair value hierarchy our financial liabilities that were accounted for at fair value as of 

December 31, 2012 and 2011. As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest 

level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value 

 December 31, 

 2012 2011 

Significant assumptions (or ranges): 

Stock price Level 1 input $ 9.07 $ 7.38 

Term (years) 2.83 3.83 

Volatility Level 2 input 70 % 70 % 

Risk-free rate Level 1 input 0.33 % 0.55 % 

Dividend yield Level 2 input 0.0 % 0.0 % 

Scenario probability debt/equity raise Level 3 input 80% / 20 % 80% / 20 % 
measurement requires judgment, and may affect the valuation of fair value liabilities and their placement within the fair value hierarchy 

levels. 

 

We record the net change in the fair value of the derivative positions listed above in unrealized gain (loss) on warrant derivative liabilities 

in our consolidated statements of operations and comprehensive income (loss). During the year ended December 31, 2012, an unrealized loss of 

$0.6 million was recorded to reflect the change in fair value of the warrants (2011: $9.8 million unrealized gain, 2010: $0.3 million unrealized 

gain). 

 

S-17 

 December 31, 2012 

 Level 1 Level 2 Level 3 Total 

 (in thousands) 

Liabilities 

Warrant derivative liabilities $ — $ — $ 5,470 $ 5,470 

 

Total liabilities $ — $ — $ 5,470 $ 5,470 

 

 

 

 

 

 

 

 

 December 31, 2011 

 Level 1 Level 2 Level 3 Total 

 (in thousands) 

Liabilities 

Warrant derivative liabilities $ — $ — $ 4,870 $ 4,870 

 

Total liabilities $ — $ — $ 4,870 $ 4,870 

 

 

 

 

 

 

 

 
Table of Contents 

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, 

Financial Instruments . The estimated fair value amounts have been determined at discrete points in time based on relevant market information. 

These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and 

accounts payable approximates their carrying value due to their short-term nature. The following table presents the estimated fair values of our 

fixed interest rate, long-term debt instrument (Level 3) as of December 31, 2012. 

 

The fair value of our fixed interest debt instruments (Level 3) was calculated using a pricing model which incorporates transaction details 

such as contractual terms, maturity and, in certain instances, timing and amount of future cash flows, as well as assumptions related to liquidity 

and credit valuation adjustments of marketplace participants. 

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

The following table provides a reconciliation of financial liabilities measured at fair value on a recurring basis using significant unobservable 

inputs (Level 3). 

 

During the year ended December 31, 2012, there were no transfers between Level 1, Level 2 and Level 3 liabilities. 

Share-Based Compensation 

We use a fair value based method of accounting for stock-based compensation. We utilize the Black-Scholes option pricing model to 

measure the fair value of stock options and stock appreciation rights (“SARs”). Restricted stock and restricted stock units (“RSUs”) are 

measured at their intrinsic values. See Note 9 – Stock-Based Compensations and Stock Purchase Plans . 

Income Taxes 

Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts 

attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss 

and tax credit carryforwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the 

deferred tax asset will not be realized. 

We classify interest related to income tax liabilities as interest expense, and if applicable, penalties are recognized as a component of 

interest expense. 

We do not provide deferred income taxes on undistributed earnings of our foreign subsidiaries for possible future remittances as all such 

earnings are permanently reinvested as part of our ongoing business. 

 

S-18 

 December 31, 2012 

 

Carrying 

Value 

Fair 

Value 

 (in thousands) 

11% senior unsecured notes (Level 3) $ 74,839 $ 74,800 

 

December 31, 

2012 

December 31, 

2011 

 (in thousands) 

Financial liabilities: 

Beginning balance $ 4,870 $ 14,656 

Unrealized change in fair value 600 (9,786 ) 

 

Ending balance $ 5,470 $ 4,870 

 

 

 

 
Table of Contents 

New Accounting Pronouncements 

In July 2012, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2012-02, which is included in ASC 350, “Intangibles 

– Goodwill and Other”. This update gives an entity the option first to assess qualitative factors in assessing whether an asset is impaired. ASU 

No. 2012-02 is effective for annual and interim impairment test performed for fiscal years beginning after September 15, 2012. Early adoption 

is permitted. The adoption of ASU No. 2012-02 did not have a material impact on our consolidated financial position, results of operation or 

cash flows. 

In January 2013, FASB issued ASU No. 2013-01, which is included in ASC 210, “Balance Sheet”, “Clarifying the Scope of Disclosures 

about Offsetting Assets and Liabilities” (“ASU No. 2013-01”). This update clarifies that the scope of ASU 2011-11: “Disclosures about 

Offsetting Assets and Liabilities” applies only to derivatives accounted for under ASC 815 “Derivatives and Hedging”, included bifurcated 

embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities lending transactions that are either offset in 

accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. ASU No. 

2013-01 is effective for fiscal years and interim periods within those years, beginning on or after January 1, 2013. Entities should provide the 

required disclosures retrospectively for all comparative periods presented. The adoption of this guidance impacts presentation disclosures only 

and will not have an impact on our consolidated financial position, results of operation or cash flows. 

In February 2013, FASB issued ASU No. 2013-02, which is included in ASC 220, “Comprehensive Income”, “Reporting of Amounts 

Reclassified Out of Accumulated Other Comprehensive Income” (“ASU NO. 2013-02”). This update requires an entity to provide information 

about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, 

either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other 

comprehensive income by the respective line items of net income but only if the amount reclassified is required under USGAAP to be 

reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under USGAAP to be reclassified 

in their entirety to net income, an entity is required to cross-reference to other disclosures required under USGAAP that provide additional 

detail about those amounts. The amendments of ASU No. 2013-02 do not change the current requirements for reporting net income or other 

comprehensive income in financial statements. ASU No. 2013-02 is effective for fiscal years and interim periods within those years, beginning 

on or after December 15, 2012. Early adoption is permitted. The adoption of this guidance impacts presentation disclosures only and will not 

have an impact on our consolidated financial position, results of operation or cash flows. 

In February 2013, FASB issued ASU No. 2013-04, which is included in ASC 405, “Liabilities”, “Obligations Resulting from Joint and 

Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date”. This update provides guidance 

for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total 

amount of the obligation with the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance 

in USGAAP. Examples of obligations within the scope to ASU No. 2013-04 include debt arrangements, other contractual obligations, and 

settled litigation and judicial rulings. ASU No. 2013-04 is effective for fiscal years and interim periods within those years beginning after 

December 5, 2013. Entities should provide the required disclosures retrospectively for all comparative periods presented. The adoption of this 

guidance impacts presentation disclosures only and will not have an impact on our consolidated financial position, results of operation or cash 

flows. 

In March 2013, FASB issued ASU No. 2013-05, which is included in ASC 830, “Foreign Currency Matters”, “Parent’s Accounting for 

the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an 

Investment in a Foreign Entity” (“ASU 2013-05”). This update resolves the diversity in practice regarding the release into net income of the 

cumulative translation adjustment upon derecognition of a subsidiary or group of assets within a foreign entity. ASU No. 2013-05 is effective 

for fiscal years and interim periods within those years beginning after December 5, 2013. ASU No. 2013-05 is not expected to have a material 

impact on our consolidated financial position, results of operation or cash flows. 

Use of Estimates 

The preparation of financial statements in conformity with USGAAP requires management to make estimates and assumptions that affect 

the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the 

reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas 

reserve volumes and future development costs. Actual results could differ from those estimates. 

Note 4 – Earnings Per Share 

Basic earnings per common share (“EPS”) are computed by dividing income available to common stockholders by the weighted-average 

number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that would occur if securities or other contracts 

to issue common stock were exercised or converted into common stock. 

 

 2012 2011 2010 

 

(RESTATEDSEE NOTE 3) (RESTATEDSEE NOTE 3) 

Income (loss) from continuing operations $ (10,512 ) $ (41,656 ) $ 10,663 

Income (loss) from discontinued operations (1,699 ) 97,616 3,712 

 

Net income (loss) attributable to Harvest $ (12,211 ) $ 55,960 $ 14,375 

 

 

 

 

 

 

(a) 
 

The year ended December 31, 2012 per share calculations above exclude 3.9 million options and 2.4 million warrants because they were 

anti-dilutive. The year ended December 31, 2011 per share calculations above exclude 3.7 million options and 1.6 million warrants because 

they were anti-dilutive. The year ended December 31, 2010 per share calculations above exclude 2.9 million options and 1.6 million warrants 

because they were anti-dilutive. 

 

S-19 

Weighted average common shares outstanding 37,424 34,117 33,541 

Effect of dilutive securities — — 3,226 

 

Weighted average common shares, diluted 37,424 34,117 36,767 

 

 

 

 

 

 

Basic Earnings (Loss) Per Share: 

Income (loss) from continuing operations $ (0.28 ) $ (1.22 ) $ 0.32 

Income (loss) from discontinued operations (0.05 ) 2.86 0.11 

 

Basic earnings (loss) per share $ (0.33 ) $ 1.64 $ 0.43 

 

 

 

 

 

 

Diluted Earnings (Loss) Per Share: 

Income (loss) from continuing operations $ (0.28 ) $ (1.22 ) $ 0.29 

Income (loss) from discontinued operations (0.05 ) 2.86 0.10 

 

Diluted earnings (loss) per share $ (0.33 ) $ 1.64 $ 0.39 

 

 

 

 

 

 

 Includes net income attributable to noncontrolling interest. (a) 
Table of Contents 

Note 5 – Dispositions 

Share Purchase Agreement (“SPA”) 

On June 21, 2012, we announced that we and our wholly owned subsidiary HNR Energia had entered into a SPA with PT Pertamina 

(Persero), a state-owned limited liability company existing under the laws of Indonesia (“Buyer”) under which HNR Energia agreed to sell, 

indirectly through subsidiaries, all of its interests in Venezuela for a cash purchase price of $725.0 million, subject to adjustment as described 

in the SPA. 

The closing of the transaction was subject to receipt of three approvals, in addition to satisfaction of other conditions standard in 

transactions of this type: (a) approval by the Ministerio del Poder Popular de Petroleo y Mineria representing the Government of the Bolivarian 

Republic of Venezuela (which indirectly owns the other 60 percent interest in Petrodelta); (b) approval by the Government of the Republic of 

Indonesia in its capacity as Buyer’s sole shareholder; and (c) approval by the holders of a majority of Harvest’s common stock. 

After receiving notice from Buyer that Buyer’s sole shareholder, the Government of Indonesia, had decided not to approve the transaction 

described in the SPA, on February 19, 2013, HNR Energia exercised its right to terminate the agreement in accordance with its terms. 

Discontinued Operations 

On May 17, 2011, we closed the transaction to sell the Antelope Project. The sale had an effective date of March 1, 2011. We received 

cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for 

transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale was reported in 

discontinued operations in the second quarter of 2011. 

During the year ended December 31, 2012, we incurred $0.1 million of expense related to settlement of royalty payments to the Mineral 

Management Services, write-offs of $5.2 million of accounts and note receivable and $3.6 million of accounts payable, carry obligation related 

to the settlement of all outstanding claims with a private third party on the Antelope Project. The note receivable related to a prospect leasing 

cost financing arrangement. The note receivable plus accrued interest was approximately $3.3 million at December 31, 2011, and was secured 

by a portion of the production from the Bar F #1-20-3-2 in Utah. 

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

 

Note 6 – Long-Term Debt 

Long-term debt consists of the following (in thousands): 

 

On October 11, 2012, we closed the sale of $79.8 million aggregate principal amount of 11 percent senior unsecured notes due 

October 11, 2014. Under the terms of the notes, interest is payable quarterly in arrears on January 1, April 1, July 1 and October 1, beginning 

January 1, 2013. The purchase price of the notes was paid in 

 

S-20 

 December 31, 

 2012 2011 2010 

 (in thousands) 

Revenue applicable to discontinued operations $ — $ 6,488 $ 10,696 

Net income (loss) from discontinued operations $ (1,699 ) $ 97,616 $ 3,712 

 

December 31, 

2012 

December 31, 

2011 

Senior notes, unsecured, with interest at 11% $ 79,750 $ — 

Senior convertible notes, unsecured, with interest at 8.25% — 31,535 

 

 79,750 31,535 

Discount on 11% senior unsecured notes (4,911 ) — 

Less current portion — — 

 

 $ 74,839 $ 31,535 

 

 

 

 
Table of Contents 

cash, except for approximately $10.5 million in principal amount, which was exchanged by a single purchaser in exchange for approximately 

$6.0 million in face value of that purchaser’s existing 8.25 percent unsecured senior convertible notes issued by Harvest in 2010. The 11 

percent senior unsecured notes are general unsecured obligations, ranking equally in right of payment with all our future senior unsecured 

indebtedness. The senior unsecured notes are effectively subordinated to our secured indebtedness and are structurally subordinated to 

indebtedness and other liabilities of our subsidiaries. The net cash proceeds of the offering were approximately $63.5 million after deducting 

the issuance discount (approximately $2.8 million), placement fees, and other transaction costs (approximately $3.0 million). 

The 11 percent senior unsecured notes were issued at a price of 96 percent of principal amount, or $3.2 million of original issue discount 

(“OID”). The OID is recorded as a discount on debt. Warrants to purchase up to 0.8 million share of our common stock with an exercise price 

of $10.00 per share were issued in connection with the 11 percent senior unsecured notes. See Note 9 – Stock-Based Compensation and Stock 

Purchase Plans, Common Stock Warrants . The fair value of the warrants, $2.8 million, is classified as Discount on Debt with a corresponding

credit to additional paid in capital on our consolidated balance sheet at December 31, 2012. The OID is being amortized over the life of the 

debt. The discount on debt is amortized over the life of the debt. 

If the event that a sale of assets (farm-outs are not included in the definition of a sale of assets in the indenture) for more than $5.0 million 

in the aggregate occurs, we are required to offer to all noteholders of our 11 percent senior unsecured notes to purchase the maximum principal 

amount of our 11 percent senior unsecured notes that may be purchased out of the sale proceeds at an offer price in cash in an amount equal to 

105.5 percent of the principal amount plus accrued and unpaid interest, if any. In the event of a change in control or a sale of Petrodelta, the 

noteholders of our 11 percent senior unsecured notes have the right to require us to repurchase all or any part of the 11 percent senior unsecured 

notes at a repurchase price equal to 101 percent in the case of a change in control or 105.5 percent in the case of a sale of Petrodelta plus 

accrued interest. We assessed the prepayment requirements and concluded they qualified as an embedded derivative. We considered the 

probabilities of these events occurring and determined that the derivative had an immaterial value at December 31, 2012. 

The indenture relating to the notes includes various additional covenants, including a covenant that we file annual reports on Form 10-K 

with the Securities and Exchange Commission, post the report on our web site and provide the report to the note holders within the time periods 

specified in the Commission’s rules and regulations. Because we did not timely file our annual report for the year ended December 31, 2012, 

we are in breach of this covenant. The indenture states that failure to comply with this covenant will be an event of default if the breach 

continues for a period of 60 days. Therefore, our failure to timely file our annual report for the year ended December 31, 2012, is not currently 

an event of default for purposes of the indenture, and if we are able to file our annual report within that 60-day period, there will be no event of 

default as a result of our late filing. 

Financing costs associated with the 11 percent senior unsecured notes are being amortized over the life of the notes and are recorded in 

other assets. The balance for financing costs was $3.2 million at December 31, 2012. 

On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. 

Under the terms of the notes, interest was payable semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 

2010. The senior convertible notes matured on March 1, 2013 unless earlier redeemed, repurchased or converted. The notes were convertible 

into shares of our common stock at a conversion rate of 175.2234 shares of common stock per $1,000 principal amount of senior convertible 

notes, equivalent to a conversion price of approximately $5.71 per share of common stock. The 8.25 percent senior convertible notes were 

general unsecured obligations, ranking equally with all of our other unsecured senior indebtedness, if any, and senior in right of payment to any 

of our subordinated indebtedness, if any. 

Non-cash payment of debt during the year ended December 31, 2011 was $0.5 million of senior convertible notes converted into 0.1 

million share of common stock at a conversion rate of $5.71 per share. Non-cash payment of debt during the year ended December 31, 2012 

was $25.5 million of the senior convertible notes exchanged for 4.6 million shares of common stock at an effective exchange price of $5.59 per 

share. The difference between the exchange price and the market price on the date of the transaction is recorded as debt conversion expense on 

our consolidated statements of operations and comprehensive income (loss). The remaining balance of the senior convertible notes, $6.0 

million, was repaid by way of a non-cash exchange for approximately $10.5 million of the 11 percent senior unsecured notes, the value of 

which was agreed to by us and the noteholder that the noteholder would have otherwise attained had the noteholder converted the note into 

shares of common stock. The difference between the value of the senior convertible notes exchanged and the senior unsecured notes received is 

recorded as a loss on extinguishment of debt on our consolidated statements of operations and comprehensive income (loss). 

Financing costs associated with the 8.25 percent senior convertible notes were amortized over the life of the notes and were recorded in 

other assets. In connection with the exchange of convertible notes into our common stock, we reclassified $0.6 million of deferred financing 

costs to additional paid in capital. Financing costs for the convertible notes were fully amortized or reclassified at December 31, 2012 (2011: 

$1.0 million). 

On October 29, 2010, we closed a $60.0 million term loan facility with MSD Energy Investments Private II, LLC (“MSD Energy”), an 

affiliate of MSD Capital, L.P., as the sole lender under the term loan facility. Under the terms of the term loan facility, interest was paid on a 

monthly basis at the initial rate of 10 percent and had a maturity of October 28, 2012. The initial rate of interest was scheduled to increase to 15 

percent on July 28, 2011, the Bridge Date. Financing costs associated with the term loan facility were being amortized over the remaining life 

of the loan and were recorded in other assets. See Note 9 – Stock-Based Compensation and Stock Purchase Plans – Common Stock Warrants 

for a discussion of the warrants that were issued in connection with the $60.0 million term loan facility. 

In May 2011, we prepaid our $60 million term loan facility. The early repayment resulted in a loss on extinguishment of debt of $13.1 
million (Restated). The loss on extinguishment of debt includes the write off of the discount on debt ($10.6 million), a prepayment 

premium of 3.5 percent of the amount outstanding ($2.1 million), and expensing of financing costs related to the term loan facility ($0.4 

million). 

 

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Table of Contents 

The principal payment requirements for our long-term debt outstanding at December 31, 2012 are as follows (in thousands): 

 

Note 7 – Commitments and Contingencies 

We have employment contracts with five executive officers which provide for annual base salaries, eligibility for bonus compensation 

and various benefits. The contracts provide for a lump sum payment as a multiple of base salary in the event of termination of employment 

without cause. In addition, these contracts provide for payments as a multiple of base salary and bonus, excise tax reimbursement, 

outplacement services and a continuation of benefits in the event of termination without cause following a change in control. By providing one 

year notice, these agreements may be terminated by either party on or after May 31, 2013. 

We have regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Indonesia; Port Gentil, Gabon; and 

Muscat, Oman to support field operations in those areas. At December 31, 2012, we had the following lease commitments for office space: 

 

We have various contractual commitments pertaining to exploration, development and production activities. We entered the third 

exploration phase of the Dussafu PSC on May 28, 2012. The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to 

our 66.667 percent interest) work commitment over a four year period. This commitment was fulfilled with the drilling of DTM-1. 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 termination 

of the Budong PSC. Also, if this exploration well is not drilled within 18 months of the date of the Government of Indonesia approval of this 

transaction, we will be required to pay our partner in the Budong PSC $3.2 million. See Note 14 – Indonesia . These work commitments are 

non-discretionary; however, we do have the ability to control the pace of expenditures. 

The following related class action lawsuits were filed on the dates specified in the United States District Court, Southern District of 

Texas: John Phillips v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (March 22, 2013); Sang Kim v. Harvest 

Natural Resources, Inc., James A. Edmiston, Stephen C. Haynes, Stephen D. Chesebro’, Igor Effimoff, H. H. Hardee, Robert E. Irelan, Patrick 

M. Murray and J. Michael Stinson (April 3, 2013); Chris Kean v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes 

(April 11, 2013); Prastitis v. Harvest Natural Resources, Inc. , James A. Edmiston and Stephen C. Haynes (April 17, 2013); Alan Myers v. 

Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 22, 2013); and Edward W. Walbridge and the Edward W. 

Walbridge Trust v. Harvest Natural Resources, Inc., James A. Edmiston and Stephen C. Haynes (April 26, 2013). The complaints allege that 

the Company made certain false or misleading public statements and demand that the defendants pay unspecified damages to the class action 

plaintiffs based on stock price declines. On April 18, 2013, the second, third and fourth listed actions were consolidated into the Phillips 

case. The Company and the other named defendants intend to vigorously defend the consolidated and other listed lawsuits. 

On March 25, 2013, the Securities and Exchange Commission, notified the Company that it is conducting an inquiry related to certain 

matters disclosed in the Company’s Form 12B-25 announcing that it would be unable to file on a timely basis its 2012 Annual Report on Form 

10-K, including certain errors in the Company’s financial statements and weaknesses in the Company’s internal controls. The Company is 

engaged in discussions with the Commission concerning these matters. 

In June 2012, the operator of the Budong PSC received notice of a claim related to the ownership of part of the land comprising the 

Karama-1 (“KD-1”) drilling site. The claim asserts that the land on which the drill site is located is partly owned by the claimant. The operator 

purchased the site from local landowners in January 2010, and the purchase was approved by BPMIGAS, Indonesia’s oil and gas regulatory 

authority. The claimant is seeking compensation of 16 billion Indonesia Rupiah (approximately $1.7 million, $1.2 million net to our 71.61 

percent cost sharing interest) for land that was purchased at a cost of $4,100 in January 2010. On or about March 8, 2013, the operator learned 

that the court has ruled to dismiss the claim because the claim had not been filed against the proper parties to the claim. The claimant can 

appeal the dismissal once the ruling has been issued in writing. 

In May 2012, Newfield Production Company (“Newfield”) filed notice pursuant to the Purchase and Sale Agreement between Harvest 

(US) Holdings, Inc. (“Harvest US”), a wholly owned subsidiary of Harvest, and Newfield dated March 21, 2011 (the “PSA”) of a potential 

environmental claim involving certain wells drilled on the Antelope Project. The claim asserts that locations constructed by Harvest US were 

built on, within, or otherwise impact or potentially impact wetlands and other water bodies. The notice asserts that to the extent of potential 

penalties or other obligations that might result from potential violations that Harvest US indemnifies Newfield pursuant to the PSA. In June 

2012, we provided Newfield with notice pursuant to the PSA (1) denying that Newfield has any right to indemnification from us, (2) alleging 

that any potential environmental claim related to Newfield’s notice would be an assumed liability under the PSA and (3) asserting that 

Newfield indemnify us pursuant to the PSA. We dispute Newfield’s claims and plan to vigorously defend against them. We are unable to 

estimate the amount or range of any possible loss. 

2013 $ — 

2014 79,750 

 

 $ 79,750 

 

 

 Payments (in thousands) Due by Period 

 Total 

Less than 

1 Year 1-2 Years 3-4 Years 

After 4 

Years 

Office leases $ 1,459 $ 773 $ 537 $ 149 $ — 

 

 

 

 

 

 

 

 

 

 
 

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On May 31, 2011, the United Kingdom branch of our subsidiary, Harvest Natural Resources, Inc. (UK), initiated a wire transfer of 

approximately $1.1 million ($0.7 million net to our 66.667 percent interest) intending to pay Libya Oil Gabon S.A. (“LOGSA”) for fuel that 

LOGSA supplied to our subsidiary in the Netherlands, Harvest Dussafu, B.V., for the company’s drilling operations in Gabon. On June 1, 

2011, our bank notified us that it had been required to block the payment in accordance with the U.S. sanctions against Libya as set forth in 

Executive Order 13566 of February 25, 2011, and administered by OFAC, because the payee, LOGSA, may be a blocked party under the 

sanctions. The bank further advised us that it could not release the funds to the payee or return the funds to us unless we obtain authorization 

from OFAC. On October 26, 2011, we filed an application with OFAC for return of the blocked funds to us. Unless that application is 

approved, the funds will remain in the blocked account, and we can give no assurance when, or if, OFAC will permit the funds to be released. 

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

Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc., Branta Exploration & Production, LLC, Ute Energy 

LLC, Cameron Cuch, Paula Black, Johnna Blackhair, and Elton Blackhair in the United States District Court for the District of Utah . This suit 

was served in April 2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the defendants, among other things, intentionally 

interfered with Plaintiffs’ employment agreement with the Ute Indian Tribe – Energy & Minerals Department and intentionally interfered with 

Plaintiffs’ prospective economic relationships. Plaintiffs seek actual damages, punitive damages, costs and attorney’s fees. We dispute 

Plaintiffs’ claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss. 

Uracoa Municipality Tax Assessments . Our Venezuelan subsidiary, Harvest Vinccler, has received nine assessments from a tax inspector 

for the Uracoa municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows: 

 

 

 

 

Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is unable to 

estimate the amount or range of any possible loss. As a result of the SENIAT’s, the Venezuelan income tax authority, interpretation of the tax 

code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa 

Municipality for the refund of all municipal taxes paid since 1997. 

Libertador Municipality Tax Assessments . Harvest Vinccler has received five assessments from a tax inspector for the Libertador 

municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows: 

 

 

S-23 

 

• Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the 

capital fee reimbursement and related interest paid by PDVSA under the Operating Service Agreement (“OSA”). Harvest Vinccler 

has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the 

municipality the remaining claims. 

 

• Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed 

a protest with the Tax Court in Barcelona, Venezuela, on these claims. 

 

• Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a 

withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, 

Venezuela, on one claim and filed a protest with the municipality on the other claim. 

 

• Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. 

Harvest Vinccler has filed a protest with the municipality on these claims. 

 

• One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a 

protest with the Mayor’s Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. On 

April 10, 2008, the Tax Court 
Table of Contents 

 

 

Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest 

Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies 

to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the 

refund of all municipal taxes paid since 2002. 

On May 4, 2012, Harvest Vinccler learned that the Political Administrative Chamber of the Supreme Court of Justice has issued a 

decision dismissing one of Harvest Vinccler’s claims against the Libertador Municipality. Harvest Vinccler continues to believe that it has 

sufficient arguments to maintain its position in accordance with the Venezuelan Constitution. Harvest Vinccler plans to present a request of 

Constitutional Revision to the Constitutional Chamber of the Supreme Court of Justice once it is notified officially of the decision. As of May 

2, 2013, Harvest Vinccler has not received official notification of the decision. Harvest Vinccler is unable to predict the impact of this decision 

on the remaining outstanding municipality claims and assessments. 

We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such 

litigation which will have a material adverse impact on our financial condition, results of operations and cash flows. 

 

S-24 

 

suspended the case pending a response from the Mayor’s Office to the protest. If the municipality’s response is to confirm the 

assessment, Harvest Vinccler will defer to the competent Tax Court to enjoin and dismiss the claim. 

 

• Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid 

by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters 

of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims. 

 

• Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has 

filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims. 
Table of Contents 

Note 8 – Taxes 

Taxes on Income 

The tax effects of significant items comprising our net deferred income taxes as of December 31, 2012, are as follows: 

 

Management assesses the available positive and negative evidence to estimate if sufficient future taxable income will be generated to use 

the existing deferred tax assets (“DTAs”). A significant piece of objective negative evidence evaluated was the cumulative losses incurred in 

our foreign operating entities over the three-year period ended December 31, 2012. Such objective evidence limits the ability to consider other 

subjective evidence such as our projections for future growth. We have therefore placed a valuation allowance (“VA”) on all of our foreign 

DTAs with the exception of $0.8 million related to NOL carryforwards in Venezuela which would be realized upon settlement of uncertain tax 

positions. 

Management also reviewed the earnings history of our U.S. operations and determined that, with the exception of 2010 and 2011 when 

we had domestic production from our Utah assets and subsequently sold those assets, we have a history of domestic losses and are not currently 

involved in any domestic exploration and production activity. We have therefore placed a VA on our domestic DTAs, with the exception of 

$22 thousand that we expect to be realized by our UK branch. 

The components of loss from continuing operations before income taxes are as follows: 

 

 

S-25 

 2012 2011 

 Foreign 

United States 

And Other Foreign 

United States 

And Other 

 (in thousands) 

 

(RESTATEDSEE NOTE 3) (RESTATEDSEE NOTE 3) 

Deferred tax assets: 

Operating loss carryforwards $ 54,231 $ 4,498 $ 45,067 $ 259 

Restricted stock — 222 — 229 

Stock options — 7,869 — 6,941 

Deferred compensation — 739 — 627 

Alternative minimum tax credit — 2,261 — — 

Other — 861 — 167 

 

Total deferred tax assets 54,231 16,450 45,067 8,223 

 

Deferred tax liabilities: 

Accrued income (1,005 ) 

Prepaids — (373 ) — (145 ) 

Debt instrument — (35 ) — — 

Fixed assets — (28 ) — (29 ) 

 

Total deferred tax liabilities (1,005 ) (436 ) — (174 ) 

 

Net deferred tax asset 53,226 16,014 45,067 8,049 

Valuation allowance (52,427 ) (15,992 ) (45,067 ) (8,049 ) 

 

Net deferred tax asset after valuation allowance $ 799 $ 22 $ — $ — 

 

 

 

 

 

 

 

 

 2012 2011 2010 

 (in thousands) 

 

(RESTATEDSEE NOTE 3) (RESTATEDSEE NOTE 3) 

Loss before income taxes 

United States $ (33,841 ) $ (30,309 ) $ (29,209 ) 

Foreign (31,626 ) (69,564 ) (13,933 ) 

 

Total $ (65,467 ) $ (99,873 ) $ (43,142 ) 

 

 

 

 

 

 
Table of Contents 

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

 

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

is as follows: 

 

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

We do not provide deferred income taxes on undistributed earnings of our foreign subsidiaries for possible future remittances as all such 

earnings are permanently reinvested as part of our ongoing business. Any dividends that are repatriated in the future would come out future 

earnings from our foreign subsidiaries. At December 31, 2012, we have the following net operating losses available for carryforward (in 

thousands): 

 

If the U.S. operating loss carryforwards are ultimately realized, approximately $1.5 million will be credited to additional paid in capital for tax 

benefits associated with deductions for income tax purposes related to stock options and convertible debt. 

Accumulated Undistributed Earnings of Foreign Subsidiaries 

 As of December 31, 2012, the book-tax outside basis difference in our foreign subsidiary that has been indefinitely reinvested was 

approximately $331 million. No U.S. taxes have been recorded on these earnings. In general, it is our practice and intention to reinvest the 

earnings of our non-U.S. subsidiaries in those operations. All of our current exploration activity is outside of the U.S. We currently intend to 

utilize our unremitted foreign earnings to fund international projects, including the development of our properties in Gabon, Indonesia and 

South America. 

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

invest the undistributed earnings or that the earnings will be remitted in a tax-free manner. Management must consider numerous factors in 

 2012 2011 2010 

 (in thousands) 

 

(RESTATEDSEE NOTE 3) (RESTATEDSEE NOTE 3) 

Current: 

United States $ (717 ) $ — $ (1,210 ) 

Foreign 929 3,693 1,042 

 

 212 3,693 (168 ) 

Deferred: 

United States $ (22 ) $ — $ — 

Foreign (799 ) (2,636 ) (16 ) 

 

 $ (609 ) $ 1,057 $ (184 ) 

 

 

 

 

 

 

 2012 2011 2010 

 (in thousands) 

 

(RESTATEDSEE NOTE 3) (RESTATEDSEE NOTE 3) 

Income tax expense (benefit) from continuing operations: 

Tax expense (benefit) at U.S. statutory rate $ (22,259 ) $ (34,955 ) $ (15,100 ) 

Effect of foreign source income and rate differentials on foreign income 789 5,521 454 

Change in valuation allowance 14,723 31,699 16,932 

Permanent differences 1,431 — 2,440 

Return to accrual and other true-ups 831 — (4,372 ) 

Debt exchange 2,758 — — 

Income tax refund — — (1,210 ) 

Warrant derivative — (1,445 ) 207 

Liability for uncertain tax positions 799 237 — 

Other 319 — 465 

 

Total income tax expense – continuing operations (609 ) 1,057 (184 ) 

Income tax expense (benefit) from discontinued operations: 

Total income tax expense (benefit) – discontinued operations — 5,748 — 

 

Total income tax expense (benefit) $ (609 ) $ 6,805 $ (184 ) 

 

 

 

 

 

 

United States $ 12,941 Available for up to 20 years from 2012 

Indonesia 49,767 Available for up to 5 years from 2011 

Gabon 10,405 Available for up to 3 years from 2010 

Oman 24,536 Available for up to 5 years from 2009 

The Netherlands 109,442 Available for up to 9 years from 2007 

Venezuela 10,079 Available for up to 3 years from 2010 
determining timing and amounts of possible future distribution of these earnings to the parent company and whether a U.S. deferred tax 

liability should be recorded for these earnings. These factors include the future operating and capital requirements of both the parent company 

and the subsidiaries, remittance restrictions imposed by foreign governments or financial agreements and tax consequences of the remittance, 

including possible application of U.S. foreign tax credits and limitations on foreign tax credits that may be imposed by the Internal Revenue 

Service (“IRS”) or IRS regulations. 

If we were to make a distribution of our foreign earnings in the form of dividends, we would likely be subject to U.S. income taxes. 

Pursuant to ASC 740-30-50-2, we have estimated that the potential U.S. tax cost if we were to repatriate all of our currently unremitted foreign 

earnings through a dividend would be approximately $113 million based upon our foreign tax credit position in the U.S. 

Accounting for Uncertainty in Income Taxes 

The FASB issued ASC 740-10 (prior authoritative literature: Financial Interpretation No. [“FIN”] 48, “Accounting for Uncertainty in 

Income Taxes – An Interpretation of FASB Statement No. 109 [“FIN 48”]) to create 

 

S-26 
Table of Contents 

a single model to address accounting for uncertainty in tax positions. FIN 48 clarifies the accounting for income taxes, by prescribing a 

minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides 

guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. 

We or one of our subsidiaries file income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions. With 

few exceptions, we are no longer subject to U.S. federal, state and local tax examinations by tax authorities for years before 2008. Our primary 

income tax jurisdictions and their respective open audit years are: 

 

A reconciliation of the beginning amount, and current year additions, of unrecognized tax benefits follows: 

 

If the above tax benefits were recognized, the full amount would affect the effective tax rate. We have accrued interest of $0.1 million, 

and penalty of $0.3 million, a deduction for which has been recorded in pretax income. We believe that it is likely that $5.0 million of the 

uncertain tax position will be resolved within the next twelve months, and the amount of unrecognized tax benefits will significantly decrease. 

Note 9 – Stock-Based Compensation and Stock Purchase Plans 

Total share-based compensation expense, which includes stock options, restricted stock, stock appreciation rights (“SARs”), and 

restricted stock units (“RSUs”), totaled $5.2 million for the year ended December 31, 2012 (2011: $4.8 million, 2010: $5.7 million). All awards 

utilize the straight line method of amortization over vesting terms. RSUs and SARs can be cash settled and are accounted for as liability 

instruments. 

The cash flows resulting from tax deductions in excess of the compensation cost recognized for share-based awards (excess tax 

benefits) are classified as financing cash flows. The actual tax benefit realized from share-based awards during the year ended December 31, 

2011 was $2.5 million. We did not realize tax benefits from share-based awards during the years ended December 31, 2012 or 2010. 

Long Term Incentive Plans 

As of December 31, 2012, we had several long term incentive plans under which stock options, restricted stock, SARs and RSUs can be 

granted to eligible participants including employees, non-employee directors and consultants of our Company or subsidiaries: 

 

 

 

 

Tax Jurisdiction Open Audit Years 

United States 2009 – 2012 

The Netherlands 2009 – 2012 

Singapore 2008 – 2012 

United Kingdom 2012 

Venezuela 2008 – 2012 

 2012 2011 

 (in thousands) 

Balance at beginning of year $ 5,072 $ — 

Additions for tax positions of prior years 799 5,072 

 

Balance at end of year $ 5,871 $ 5,072 

 

 

 

 

 

• 2010 Long Term Incentive Plan (“2010 Plan”) – Provides for the issuance of up to 1,700,000 shares of our common stock in 

satisfaction of stock options, SARs, restricted stock, RSUs and other stock-based awards. No more than 500,000 shares may be 

granted as restricted stock and no individual may be granted more than 1,000,000 stock options or SARs. In the event of a change in 

control, all outstanding stock options and SARs become immediately exercisable to the extent permitted by the plan, and any 

restrictions on restricted stock and RSUs lapse. 

 

• 2006 Long Term Incentive Plan (“2006 Plan”) – Provides for the issuance of up to 1,825,000 shares of our common stock in 

satisfaction of stock options, SARs and restricted stock. No more than 325,000 shares may be granted as restricted stock, and no 

individual may be granted more than 900,000 options or SARs and not more than 175,000 share of restricted stock during any 

period of three consecutive calendar years. The 2006 Plan also permits the granting of performance awards to eligible employees 

and consultants. In the event of a change in control, all outstanding stock options and SARs become immediately exercisable to the 

extent permitted by the plan, and any restrictions on restricted stock lapse. 

 

• 2004 Long Term Incentive Plan (“2004 Plan”) – Provides for the issuance of up to 1,750,000 shares of our common stock in 

satisfaction of stock options, SARs and restricted stock. No more than 438,000 shares may be granted as restricted stock, and no 

individual may be granted more than 438,000 options and not more than 110,000 share of restricted stock over the life of the plan. 

The 2004 Plan also permits the granting of performance awards to eligible employees and consultants. In the event of a change in 

control, all outstanding stock options and SARs become immediately exercisable to the extent permitted by the plan, and any 

restrictions on restricted stock lapse. 

 

• 2001 Long Term Stock Incentive Plan (“2001 Plan”) – Provides for the issuance of up to 1,697,000 shares of our common stock in 

the form of Incentive Stock Options and Non-Qualified Stock Options. No officer may be granted more than 500,000 stock options 

during any one fiscal year, as adjusted for any changes in capitalization, such as stock splits. In the event of a change in control, all 

outstanding options become immediately exercisable to the extent permitted by the plan. 
Stock Options 

Stock options granted under the plans must be no less than the fair market value of our common stock on the date of grant. Stock 

options granted under the plans generally are exercisable in varying cumulative periodic installments after one year. Stock options granted 

under the plans expire five to ten years from the date of grant. Stock options to purchase 85,006 common shares remained available for grant as 

of December 31, 2012 (2011: 507,298). Of the common shares available for grant as of December 31, 2012, all of these shares are also 

available for issuance in the form of restricted shares. 

The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option-pricing model which uses 

assumptions for the risk-free interest rate, volatility, dividend yield and the expected term of the options. The risk-free interest rate is based on 

the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the option. Expected volatility is based on 

historical volatilities of our stock. We do not assume any dividend yield since we do not pay dividends. The expected term of options granted is 

the weighted average life of stock options and represents the period of time that options are expected to be outstanding. 

We also consider an estimated forfeiture rate for these stock option awards, and we recognize compensation cost only for those 

shares that are expected to vest, on a straight-line basis over the requisite service period of the award, which is generally the vesting term of 

three to five years. The forfeiture rate is based on historical experience. 

Stock option transactions under our various stock-based employee compensation plans are presented below: 

 

Of the options outstanding, 2.5 million were exercisable at weighted-average exercise price of $10.12 as of December 31, 2012 

(2011: 2.2 million at $10.15; 2010: 1.8 million at $10.27). 

 

S-27 

Options Shares 

WeightedAverage 

Exercise 

Price 

WeightedAverage 

Remaining 

Contractual 

Term 

Aggregate 

Intrinsic 

Value 

 (in thousands, except exercise price) 

Options outstanding as of December 31, 2011 3,907 $ 10.19 

Granted 451 5.14 

Exercised (122 ) (6.26 ) 

Cancelled (339 ) (11.45 ) 

 

Options outstanding as of December 31, 2012 3,897 $ 9.62 2.6 years $ 3,064 

 

 

 

Options exercisable as of December 31, 2012 2,516 $ 10.12 2.2 years $ 1,040 

 

 

 
Table of Contents 

During the year ended December 31, 2012, we awarded stock options vesting over three years to purchase 451,298 of our common 

shares to our employees and executive officers (2011: 498,500 stock options; 2010: 477,000 stock options). 

The value of each stock option grant is estimated on the date of grant using the Black-Scholes option pricing model with the 

following weighted-average assumptions: 

 

 

A summary of our unvested stock option awards as of December 31, 2012, and the changes during the year then ended is presented 

below: 

 

The total intrinsic value of stock options exercised during the year ended December 31, 2012 was $0.3 million (2011: $1.4 million; 

2010: $2.5 million). The total fair value of stock options that vested during the year ended December 31, 2012, was $1.9 million (2011: $2.7 

million; 2010: $2.6 million). 

As of December 31, 2012, there was $2.4 million of total future compensation cost related to unvested stock option awards that are 

expected to vest. That cost is expected to be recognized over a weighted average period of 2.6 years. 

Restricted Stock 

Restricted stock is issued on the grant date, but cannot be sold or transferred. Restricted stock granted to directors vest one year 

after date of grant. Restricted stock granted to employees vest at the third year after date of grant. Vesting of the restricted stock is dependent 

upon the employee’s continued service to Harvest. 

A summary of our restricted stock awards as of December 31, 2012, and the changes during the year then ended is presented below: 

 

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For options granted during: 2012 2011 2010 

Weighted average fair value $ 2.85 $ 5.92 $ 4.23 

Weighted average expected life 5 years 5 years 7 years 

Expected volatility 67.3 % 61.3 % 57.6 % 

Risk-free interest rate 0.7 % 1.8 % 2.7 % 

Dividend yield 0 % 0 % 0 % 

Expected volatilities are based on historical volatilities of our stock. 

Unvested Stock Options Outstanding 

WeightedAverage 

Grant-Date 

Fair Value 

 (in thousands, except fair value) 

Unvested as of December 31, 2011 1,394 $ 5.56 

Granted 451 2.86 

Vested (465 ) (4.95 ) 

Forfeited — — 

 

Unvested as of December 31, 2012 1,380 4.88 

 

 

 

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Table of Contents 

 

During 2012, we awarded 2,000 shares of restricted stock to new hire employees as employment inducement grants under a New 

York Stock Exchange (“NYSE”) exception (2011: 181,050 shares to employees and directors). These awards had an aggregate fair value at 

their date of grant of $11,700 (2011: $2.0 million). The restricted stock is schedule to vest at the third year after date of grant for employees and 

one year after date of grant for directors. The value of the restricted stock that vested during the year ended December 31, 2012 was $0.8 

million (2011: $3.4 million; 2010: $1.4 million). The weighted average grant date fair value of awards granted in 2011 was $11.21 and 2010 

was $7.10. 

As of December 31, 2012 there was $0.8 million of total future compensation cost related to unvested restricted stock awards that 

are expected to vest. That cost is expected to be recognized over a weighted average period of 1.2 years. 

Stock Appreciation Rights (“SARs”) 

All SAR awards granted to date have been granted outside of active long-term incentive plans and are held by Harvest employees. 

SARs granted in 2009 vest ratably over three years beginning with the third year of grant. SARs granted in 2012 vest ratably over three years 

beginning in the first year of grant. Vesting of SARs is dependent upon the employee’s continued service to Harvest. SAR awards are settled 

either in cash or Harvest common stock if available through an equity compensation plan. For recording of compensation, we assume the SAR 

award will be cash-settled and record compensation expense based on the fair value of the SAR awards at the end of each period. 

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

 

Of the SAR awards outstanding, 74,997 were exercisable at weighted-average exercise price of $4.60 as of December 31, 2012 

(2011: 83,000 at $4.60; 2010: none). 

During the year ended December 31, 2012, we awarded 707,202 SARs vesting over three years to our employees and executive 

officers (2011: none; 2010: none). 

The value of each SAR award is estimated on the date of grant using the Black-Scholes option pricing model using the assumptions 

discussed above. 

 

S-29 

Restricted Stock Outstanding 

WeightedAverage 

Grant-Date 

Fair Value 

Unvested as of December 31, 2011 430,754 $ 8.28 

Granted 2,000 5.85 

Vested (148,004 ) (7.00 ) 

Forfeited — — 

 

Unvested as of December 31, 2012 284,750 8.93 

 

 

 

Stock Appreciation Rights SARs 

WeightedAverage 

Exercise 

Price 

WeightedAverage 

Remaining 

Contractual 

Term 

Aggregate 

Intrinsic 

Value 

 (in thousands) 

SARs outstanding as of December 31, 2011 308,000 $ 4.60 

Granted 707,202 5.12 

Exercised (83,000 ) (4.60 ) 

Cancelled — — 

 

SARs outstanding as of December 31, 2012 932,202 $ 4.99 4.2 years $ 3,800 

 

 

 

SARs exercisable as of December 31, 2012 74,997 $ 4.60 3.5 years $ 336 

 

 

 
Table of Contents 

A summary of our unvested SAR awards as of December 31, 2012, and the changes during the year then ended is presented below: 

 

The total intrinsic value of SAR awards exercised during the year ended December 31, 2012 was $0.3 million. No SAR awards 

were exercised during the years ended December 31, 2011 or 2010. The total fair value of SAR awards that vested during the year ended 

December 31, 2012, was $0.3 million (2011: $0.2 million; 2010: none). 

As of December 31, 2012, there was $3.7 million of total future compensation cost related to unvested SAR awards that are 

expected to vest. That cost is expected to be recognized over a weighted average period of 2.3 years. 

Restricted Stock Units (“RSUs”) 

All RSU awards granted to date have been granted outside of active long-term incentive plans, are held by Harvest employees and 

directors, and are settled either in cash or Harvest common stock if available through an equity compensation plan. RSU awards granted in 

2009 vest ratably over three years beginning with the third year of grant. RSU awards granted in 2012 to employees vest at the third year after 

date of grant. RSU awards granted in 2012 to directors vest one year after date of grant. Vesting of the RSU awards is dependent upon the 

employee’s and director’s continued service to Harvest. 

A summary of our RSU awards as of December 31, 2012, and the changes during the year then ended is presented below: 

 

During 2012, we awarded 388,000 RSUs to employees (2011: none, 2010: none). These RSU awards had an aggregate fair value at 

their date of grant of $2.0 million (2011: none, 2010: none). The 70,994 RSU awards which vested in 2012 were settled with Harvest common 

stock. The value of the RSU awards that vested during the year ended December 31, 2012 was $0.4 million (2011: $0.6 million; 2010: none). 

As of December 31, 2012 there was $2.7 million of total future compensation cost related to unvested RSU awards that are 

expected to vest. That cost is expected to be recognized over a weighted average period of 2.0 years. 

 

S-30 

Unvested Stock Appreciation Rights Outstanding 

WeightedAverage 

Fair Value 

Unvested as of December 31, 2011 225,000 $ 5.93 

Granted 707,202 6.23 

Vested (74,997 ) (5.93 ) 

Forfeited — — 

 

Unvested as of December 31, 2012 857,205 6.18 

 

 

 

Restricted Stock Units Outstanding 

WeightedAverage 

Fair Value 

Unvested as of December 31, 2011 213,000 $ 7.38 

Granted 388,000 5.12 

Vested (70,994 ) (5.68 ) 

Forfeited — — 

 

Unvested as of December 31, 2012 530,006 9.07 

 

 

 
Table of Contents 

Common Stock Warrants 

In connection with a $60 million term loan facility issued in November 2010, we issued (1) 1.2 million warrants exercisable at any time 

on or after the closing date of the term loan facility for a period of five years from the closing date on a cashless exercise basis at $15 per share 

until July 28, 2011, the Bridge Date, at which time the exercise price per share would be repriced to equal the lower of $15 or 120 percent of 

the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date (“Tranche A”); (2) 0.4 

million warrants exercisable at any time on or after the closing date of the term loan facility for a period of five years from the closing date on a 

cashless exercise basis at $20 per share until the Bridge Date, at which time the exercise price per share would be repriced to equal the lower of 

$15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date 

(“Tranche B”); and (3) 4.4 million warrants exercisable at any time on or after the Bridge Date for a period of five years from the Bridge Date 

on a cashless exercise basis at the lower of $15 per share or 120 percent of the average closing price of Harvest’s common stock for the 20 

trading days immediately preceding the Bridge Date (“Tranche C”) (“collectively “the Warrants”). Tranche C was redeemable by Harvest for 

$0.01 per share at any time prior to the Bridge Date in conjunction with the repayment of the loan prior to the Bridge Date. 

On May 17, 2011, in connection with the payment of the term loan facility, we redeemed all of Tranche C at $0.01 per share. The cost to 

redeem Tranche C ($44,000) was expensed to loss on extinguishment of debt in the six months ended June 30, 2011. 

On July 28, 2011, the Bridge Date, Tranche A and Tranche B were repriced to $14.78 per warrant which is the lower of $15 or 120 

percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date. 

The Warrants include anti-dilution provisions which adjust the number of warrants and the exercise price per warrant based on the 

issuance of additional shares. The induced conversions related to the $32 million senior convertible notes triggered the anti-dilution provision 

which resulted in the issuance of 118,327 additional warrants in the year ended December 31, 2012 (2011: 2,007 additional warrants). In 

addition, the exercise price per share for all Warrants was repriced to $13.75 per warrant. The Warrants are classified as a liability on our 

consolidated balance sheets and marked to market. See Note 3 – Summary of Significant Accounting Policies, Restatement of Prior Period 

Financial Statements. 

In the occurrence of a fundamental change, we are required to repurchase the Warrants at the higher of (1) the fair market value of the 

warrant and (2) a valuation based on a computation of the option value of the Warrant using the Black-Scholes calculation method using the 

assumptions described in the Warrant Agreement. A fundamental change is defined as “the occurrence of one of the following events: a) a 

person or group becomes the direct or indirect owner of more than 50% of the voting power of the outstanding common stock, b) a merger 

event or similar transaction in which the majority owners before the transaction fail to own a majority of the voting power of the Company after 

the transaction, and c) approval of a plan of liquidation or dissolution of the Company or sale of all or substantially all of the Company’s 

assets.” 

In connection with the 11 percent senior unsecured notes issued October 11, 2012, we issued warrants to purchase up to 0.7 million share 

of our common stock with an exercise price of $10.00 per share. The warrants can be exercised at any time up until the three-year anniversary 

of the closing. The Black-Scholes option pricing model was used in pricing the warrants. The fair value of the warrants, $2.8 million, is 

classified as a discount on debt with a corresponding credit to additional paid in capital on our consolidated balance sheet at December 31, 

2012. 

The dates the warrants were issued, the expiration dates, the exercise prices and the number of warrants issued and outstanding at 

December 31, 2012 were: 

 

 

S-31 

 Warrants 

Date Issued Expiration Date 

Exercise 

Price Issued Outstanding 

 (warrants in thousands) 

November 2010 November 2015 $ 13.75 1,600 1,600 

October 2011 November 2015 13.75 2 2 

March 2012 November 2015 13.75 73 73 

August 2012 November 2015 13.75 30 30 

October 2012 November 2015 13.75 15 15 

October 2012 October 2015 10.00 687 687 

 

 2,407 2,407 

 

 

 

 
Table of Contents 

Note 10 – Warrant Derivative Liabilities 

As of December 31, 2012, warrant derivative financial instruments consisted of 1,720,334 warrants (2011: 1,602,007 warrants) issued 

under the warrant agreements dated November 2010 in connection with a $60 million term loan facility (see Note 9 – Stock-Based 

Compensation and Stock Purchase Plans, Common Stock Warrants ). The fair value of the warrants as of December 31, 2012 was $3.18 per 

warrant (2011: $3.04 per warrant). 

These warrant agreements include provisions wherein we may be required to settle the warrant agreement by transferring assets. 

Consequently, under ASC 480-10-25-8, these warrants must be treated as a derivative liability, bifurcated from the host instrument, and 

recorded at fair value at each reporting date. In the occurrence of a fundamental change, we are required to repurchase the Warrants at the 

higher of (1) the fair market value of the warrant and (2) a valuation based on a computation of the option value of the Warrant using the 

Black-Scholes calculation method using the assumptions described in the Warrant Agreement. A fundamental change is defined as “the 

occurrence of one of the following events: a) a person or group becomes the direct or indirect owner of more than 50% of the voting power of 

the outstanding common stock, b) a merger event or similar transaction in which the majority owners before the transaction fail to own a 

majority of the voting power of the Company after the transaction, and c) approval of a plan of liquidation or dissolution of the Company or 

sale of all or substantially all of the Company’s assets.” 

All our warrant derivative contracts are recorded at fair value and are located in the balance sheet as warrant derivative liability. The 

following table summarizes the effect on our income (loss) associated with changes in the fair values of our derivative financial instruments: 

 

Note 11 – Operating Segments 

We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and 

operating characteristics. The segments are organized in order to manage 

 

S-32 

 December 31, 

 2012 2011 

 (in thousands) 

Unrealized gain (loss) on warrant derivatives $ (600 ) $ 9,786 

 

 

 

 
Table of Contents 

regional business, currency and tax related risks and opportunities. Operations included under the heading “United States” include corporate 

management, cash management, business development and financing activities performed in the United States and other countries, which do 

not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are 

eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the United 

States segment and are not allocated to other operating segments. 

 

 

 

Note 12 – Venezuela 

Harvest Vinccler’s and Petrodelta’s functional and reporting currency is the U.S. Dollar. They do not have currency exchange risk other 

than the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”) (4.30 Bolivars 

per U.S. Dollar). However, during the year ended December 31, 2012, Harvest Vinccler exchanged approximately $1.5 million (2011: $1.2 

million) through the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) and received an average exchange rate of 5.16 

Bolivars (2011: 5.19 Bolivars) per U.S. Dollar. Petrodelta does not have, and has not had, any Bolivars pending government approval for 

settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. 

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

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

liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. At December 31, 2012, the balances in 

Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 6.2 million 

Bolivars and 5.7 million Bolivars, respectively. At December 31, 2012, the balances in Petrodelta’s Bolivar denominated monetary assets and 

liabilities accounts that are exposed to exchange rate changes are 277.2 million Bolivars and 2,646.2 million Bolivars, respectively. 

 

S-33 

 2012 2011 2010 

 (in thousands) 

 

(RESTATEDSEE NOTE 3) (RESTATEDSEE NOTE 3) 

Segment Income (Loss) Attributable to Harvest 

Venezuela $ 51,584 $ 54,974 $ 49,158 

Indonesia (7,984 ) (47,688 ) (6,265 ) 

Gabon (6,842 ) (7,988 ) (1,642 ) 

Oman (14,071 ) (11,860 ) (2,239 ) 

United States (33,199 ) (29,094 ) (28,349 ) 

 

Net income (loss) from continuing operations (10,512 ) (41,656 ) 10,663 

Discontinued operations (Antelope Project) (1,699 ) 97,616 3,712 

 

Net income (loss) attributable to Harvest $ (12,211 ) $ 55,960 $ 14,375 

 

 

 

 

 

 

 Includes net income attributable to noncontrolling interest. 

 December 31, 

 2012 2011 

 (in thousands) 

 

(RESTATEDSEE NOTE 3) 

Operating Segment Assets 

Venezuela $ 416,792 $ 348,802 

Indonesia 10,959 14,593 

Gabon 80,908 55,505 

Oman 313 7,152 

United States 307,703 259,856 

 

 816,675 685,908 

Intersegment eliminations (219,838 ) (178,705 ) 

 

Total Assets $ 596,837 $ 507,203 

 

 

 

 

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On February 8, 2013, the Venezuelan government published in the Official Gazette the Exchange Agreement No. 14 which establishes 

new exchange rates for the Bolivar/U.S. Dollar currencies that became effective February 9, 2013. The exchange rate established in the 

Agreement is 6.30 Bolivars per U.S. Dollar. The Exchange Agreement also announced the elimination of SITME effective February 8, 2013. 

All exchanges of Bolivars must now transact through the Central Bank. As a result of the February 2013 devaluation, Harvest Vinccler 

estimates the impact of the devaluation to be approximately $0.1 million gain on revaluation of its assets and liabilities, and Petrodelta 

estimates the impact of the devaluation to be approximately $54.8 million gain on revaluation of its assets and liabilities. 

On May 7, 2012, the Organic Law on Employment, Male and Female Workers (“Labor Law”) was published in the Official Gazette, the 

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. The Labor Law’s purpose is to regulate the relations 

between workers and employers. In August 2012, the labor contract between PDVSA and the labor union was signed. The new labor contract 

awarded salary increases to both union and non-union labor retroactive to December 2011. The new labor contract increased the effect of the 

Labor Law on Petrodelta by increasing the salaries on which the Labor Law benefits are calculated. Per the actuarial study that PDVSA 

commissioned, the effect of the Labor Law on Petrodelta’s business was $3.8 million ($1.2 million net to our 32 percent interest) for the year 

ended December 31, 2012. The Labor Law had no impact to Harvest Vinccler. 

Note 13 – Investment in Equity Affiliates – Petrodelta, S.A. 

See Note 5 – Dispositions, Share Purchase Agreement (“SPA”). 

On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Petrodelta Fields 

subject to the conditions of the Conversion Contract was published in the Official Gazette. Petrodelta is governed by its own charter and 

bylaws and will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a 

maximum of 20 years from that date. Petrodelta operates a portfolio of properties in eastern Venezuela including large proven oil fields as well 

as properties with substantial opportunities for both development and exploration. Petrodelta is to undertake its operations in accordance with 

Petrodelta’s business plan as set forth in its conversion contract. Under its conversion contract, work programs and annual budgets adopted by 

Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the 

shareholders owning at least 75 percent of the shares of Petrodelta. 

The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with 

PDVSA Petroleo S.A. (“PPSA”) signed on January 17, 2008. The form of the agreement is set forth in the Conversion Contract. Crude oil 

delivered from the Petrodelta Fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets, and 

adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and 

prevailing market conditions. Merey 16 published prices are quoted and sold in U.S. Dollars. Natural gas delivered from the Petrodelta Fields 

to PPSA is priced at $1.54 per thousand cubic feet. Natural gas deliveries are paid in Bolivars, but the pricing for natural gas is referenced to 

the U.S. Dollar. PPSA is obligated to make payment to Petrodelta of each invoice within 60 days of the end of the invoiced production month 

by wire transfer, in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered, and in Bolivars in the case of payment 

for natural gas delivered, in immediately available funds to the bank accounts designated by Petrodelta. Major contracts for capital 

expenditures and lease operating expenditures are denominated in U.S. Dollars. Any dividend paid by Petrodelta will be made in U.S. Dollars. 

When the Sales Contract was executed, Petrodelta was producing only one type of crude, Merey 16. Beginning in October 2011, the 

Ministry of the People’s Power for Petroleum and Mining (“MENPET”) determined that Petrodelta’s production flowing through the COMOR 

transfer point was a heavier type of crude, Boscan. Since Petrodelta was producing only Merey 16 when the Sales Contract was executed, the 

Boscan gravity and sulphur correction factors and crude pricing formula are not included in the Sales Contract. However, under the Sales 

Contract, PPSA is obligated to receive all of Petrodelta’s production. All production deliveries for all of Petrodelta’s fields have been certified 

by MENPET and acknowledged by PPSA. All pricing factors to be used in the Merey 16 and Boscan pricing formulas have been provided by 

and certified by MENPET to Petrodelta. 

 

S-34 
Table of Contents 

Since the Sales Contract provides for only one crude pricing formula, the Sales Contract had to be amended to include the Boscan pricing 

formula to allow Petrodelta to invoice PPSA for El Salto crude oil deliveries. From October 1, 2011 through June 30, 2012, Petrodelta used the 

Boscan pricing formula as published in the Official Gazette on January 11, 2007 to record revenue from El Salto deliveries. Petrodelta 

subsequently received from PDVSA Trade and Supply a draft amendment to the Sales Contract. The pricing formula in the draft amendment 

was used to record revenue for El Salto field deliveries from July 1, 2012 through December 31, 2012, and revenue for El Salto deliveries for 

October 1, 2011 through June 30, 2012 was revised to reflect the pricing formula in the draft amendment. The only item included in the draft 

amendment is the Boscan pricing formula to be used in invoicing El Salto crude oil deliveries. All other terms and conditions of the Sales 

Contract remain in force. On January 28, 2013, Petrodelta’s board of directors endorsed the amendment to the Sales Contract. The amendment 

has to be approved by CVP’s board of directors and HNR Finance’s board of directors. Once these approvals are received, the amendment to 

the Sales Contract will be executed and PPSA will be invoiced for the deliveries. 

At December 31, 2012, El Salto deliveries, net of royalties, covering the delivery months of October 2011 through December 2012 

totaled approximately 4.0 MBls (1.3 MBls net to our 32 percent interest). The draft amendment to the Sales Contract pricing formula for 

Boscan based upon the deliveries and factors certified by MENPET, results in revenue for these deliveries of $352.7 million ($112.9 million 

net to our 32 percent interest). As of December 31, 2012, these deliveries for El Salto remain uninvoiced to PPSA. 

As discussed in previous filings, PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has 

contracted to do work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in 

meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment 

obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind 

in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors, including Harvest 

Vinccler. As a result, Petrodelta has experienced, and is continuing to experience, difficulty in retaining contractors who provide services for 

Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. 

Inability to retain contractors or to pay them on a timely basis is having an adverse effect on Petrodelta’s operations and on Petrodelta’s ability 

to carry out its business plan. 

Harvest Vinccler has advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, operations, 

seismic interpretation, and employee salaries and related benefits for Harvest Vinccler employees seconded into Petrodelta. Currently, we have 

three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. Harvest Vinccler is considered a 

contractor to Petrodelta, and as such, Harvest Vinccler is also experiencing the slow payment of invoices. During the year ended December 31, 

2012, Harvest Vinccler advanced to Petrodelta $0.5 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advance. 

Petrodelta and Petrodelta’s board have not indicated that the advances are not payable, nor that they will not be paid. At December 31, 2012, 

we reclassified $2.1 million of the Advances to Affiliate to a long-term receivable due to slow payment and age of the advances. During the 

year ended December 31, 2011, we advanced Petrodelta $0.8 million for continuing operations costs, and Petrodelta repaid $0.1 million of the 

advances. Although payment is slow and the balance is increasing, payments continue to be received. 

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”). Windfall Profits Tax is deductible for 

Venezuelan income tax purposes. In February 2013, the Venezuelan government published in the Official Gazette an amendment to the 

Windfall Profits Tax. The amended Windfall Profits Tax establishes new levels for contribution of extraordinary prices (under $80 per barrel) 

and exorbitant prices (over $100 per barrel), and levels in-between, to the Venezuelan government. During the year ended December 31, 2012, 

Petrodelta recorded $291.4 million for Windfall Profits Tax (2011: $237.6 million). 

One section of the Windfall Profits Tax states that royalties paid to Venezuela are capped at $70 per barrel, but the cap on royalties has 

not been defined as being applicable to in-cash, in-kind, or both. Per instructions received from PDVSA, Petrodelta reports royalties, whether 

paid in-cash or in-kind, at $70 per barrel (royalty barrels x $70). The difference between the $70 royalty cap and the current oil price is to be 

reflected on the income statement as a reduction in oil sales. For the year ended December 31, 2012, the reduction to oil sales due to the $70 

cap applied to all royalty barrels was $113.7 million ($36.4 million net to our 32 percent interest) (2011: $85.0 million [$27.2 million net to our 

32 percent interest]). 

Per our interpretation of the Windfall Profits Tax, the $70 cap on royalty barrels should only be applied to the 3.33 percent royalty which 

Petrodelta pays in cash. We have applied the $70 cap to only the 3.33 percent royalty 

 

S-35 
Table of Contents 

paid in cash and the current oil sales price to the 30 percent royalty paid in-kind for the year months ended December 31, 2012. With assistance 

from Petrodelta, we have recalculated Petrodelta’s oil sales and royalties to apply the current oil price to its total barrels produced and to the 30 

percent royalty paid in-kind and applied the $70 cap to the 3.33 percent royalty paid in cash for the year ended December 31, 2012. For the 

year ended December 31, 2012, net oil sales (oil sales less royalties) are slightly higher, $11.4 million ($3.6 million net to our 32 percent 

interest) (2011: $8.5 million [$2.7 net to our 32 percent interest]) under this method than the method advised by PDVSA and the method of 

applying the current oil price to total barrels produced and to total royalty barrels. We have reported revenues and royalties for Petrodelta under 

this method. 

On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 

million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s 

liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, as of May 2, 2012, this dividend has not 

been received, although it is due and payable. Petrodelta’s board of directors declared this dividend and has never indicated that the dividend is 

not payable, nor that it will not be paid. The dividend receivable is classified as a long-term receivable at December 31, 2012 due to the 

uncertainty in the timing of payment. There is uncertainty with respect to the timing of the receipt of this dividend and whether future dividends 

will be declared or paid. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable not be collected or 

facts and circumstances surrounding our investment change, our results of operations and investment in Petrodelta could be adversely 

impacted. 

The Organic Law on Sports, Physical Activity and Physical Education (“Sports Law”) was published in the Official Gazette on 

August 23, 2011. The purpose of the Sports Law is to establish the public service nature of physical education and the promotion, organization 

and administration of sports and physical activity. Funding of the Sports Law is by contributions made by companies or other public or private 

organizations that perform economic activities for profit in Venezuela. The contribution is one percent of annual net or accounting profit and is 

not deductible for income tax purposes. Per the Sports Law, contributions are to be calculated on an after-tax basis. However, in March 2012, 

CVP has instructed Petrodelta to calculate the contribution on a before-tax basis contrary to the Sports Law. For the year ended December 31, 

2012, this method of calculation overstates the liability for the Sports Law contribution by $2.5 million ($0.8 million net to our 32 percent 

interest). We have adjusted for the overaccrual of the Sports Law in the December 31, 2012 Net Income from Equity Affiliate. 

Petrodelta’s reporting and functional currency is the U.S. Dollar. HNR Finance owns a 40 percent interest in Petrodelta. Petrodelta’s 

financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”) which we have adjusted to conform 

to USGAAP. The two major differences between IFRS and USGAAP, for which we adjust, are deferred taxes and depletion expense. 

 

 

 

S-36 

 

• Deferred tax. IFRS allows the inclusion of monetary temporary differences impacted by inflationary adjustments. USGAAP does not. Net 

Income Equity Affiliate is increased or decreased by the deferred tax benefit created by the monetary temporary differences impacted by 

inflationary adjustments. 

 

• Depletion expense. Oil and gas reserves used by Petrodelta in calculating depletion expense under IFRS are provided by MENPET. 

MENPET reserves are not prepared using the guidance on extractive activities for oil and gas (ASC 932). At least annually, we prepare 

reserve reports for Petrodelta using ASC 932. Petrodelta depletion is recalculated using the USGAAP compliant reserves. 
Table of Contents 

All amounts through Net Income Equity Affiliate represent 100 percent of Petrodelta. Summary financial information has been presented 

below at December 31, 2012 and 2011, and for the years ended December 31, 2012, 2011 and 2010: 

 

 

Fusion Geophysical, LLC (“Fusion”) 

On January 28, 2011, Fusion Geophysical, LLC’s (“Fusion”) 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private 

purchaser pursuant to an Agreement and Plan of Merger. We received $1.4 million for our equity investment. 

At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion. Accordingly, we did not record net 

losses incurred by Fusion in the year ended December 31, 2011 of $0.2 million ($0.1 million net to our 49 percent interest) or (2010: $2.4 

million [$1.2 million net to our 49 percent interest]) as doing so would have caused our equity investment to go into a negative position. 

Note 14 – Indonesia 

In 2007, we entered into a Farmout Agreement to acquire a 47 percent interest in the Budong PSC located mostly onshore West Sulawesi, 

Indonesia. In April 2008, the Government of Indonesia approved the assignment to 

 

S-37 

 Year Ended December 31, 

 2012 2011 2010 

 (in thousands) 

Revenues: 

Oil sales $ 1,263,264 $ 1,122,191 $ 604,173 

Gas sales 3,350 3,497 3,398 

Royalty (423,069 ) (374,135 ) (204,688 ) 

 

 843,545 751,553 402,883 

Expenses: 

Operating expenses 121,023 77,236 44,749 

Workovers 17,302 28,508 8,910 

Depletion, depreciation and amortization 86,004 58,376 40,429 

General and administrative 31,753 11,297 15,508 

Windfall profits tax 291,355 237,632 14,116 

 

 547,437 413,049 123,712 

 

Income from Operations 296,108 338,504 279,171 

Gain on exchange rate — — 84,448 

Investment earnings and other 13 610 3,179 

Interest expense (7,017 ) (10,699 ) (26,767 ) 

 

Income before Income Tax 289,104 328,415 340,031 

Current income tax expense 127,080 190,577 189,780 

Deferred income tax expense (benefit) 76,030 (94,622 ) 72,568 

 

Net Income 85,994 232,460 77,683 

Adjustment to reconcile to reported Net Income from Equity 

Affiliate: 

Deferred income tax expense (benefit) (78,968 ) 49,545 (92,195 ) 

Sports law over accrual (2,536 ) — — 

 

Net Income Equity Affiliate 167,498 182,915 169,878 

Equity interest in equity affiliate 40 % 40 % 40 % 

 

Income before amortization of excess basis in equity affiliate 66,999 73,166 67,951 

Amortization of excess basis in equity affiliate (2,143 ) (1,863 ) (1,414 ) 

Conform depletion expense to USGAAP 2,913 763 (246 ) 

 

Net income from equity affiliate $ 67,769 $ 72,066 $ 66,291 

 

 

 

 

 

 

 

December 31, 

2012 

December 31, 

2011 

 (in thousands) 

Current assets $ 1,425,115 $ 979,868 

Property and equipment 538,351 409,941 

Other assets 70,468 146,499 

Current liabilities 1,180,559 808,955 

Other liabilities 93,101 53,073 

Net equity 760,274 674,280 
Table of Contents 

us of the 47 percent interest in the Budong PSC. Our partner is the operator through the exploration phase as required by the terms of the 

Budong PSC, and we have an option to become operator, if approved by the Government of Indonesia and SKK Migas in any subsequent 

development and production phase. 

We acquired our original 47 percent interest in the Budong PSC by committing to fund the first phase of the exploration program up to a 

cap of $17.2 million, including the acquisition of 2-D seismic and drilling of the first two exploration wells under a Farmout Agreement with 

our partner in the Budong PSC. Prior to drilling the first exploration well, our partner had a one-time option to increase the level of the carried 

interest to a maximum of $20.0 million. On September 15, 2010, our partner exercised their option to increase the carry obligation by $2.7 

million to a total of $19.9 million. The additional carry increased our ownership by 7.4 percent to 54.4 percent. On March 3, 2011, the 

Government of Indonesia approved this change in ownership interest. 

On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator to a third party, which allowed us 

to acquire an additional 10 percent ownership in the Budong PSC at a cost of $3.7 million payable ten business days after completion of the 

first exploration well. The $3.7 million was paid on April 18, 2011. Closing of this acquisition increased our participating ownership interest in 

the Budong PSC to 64.4 percent with our cost sharing interest becoming 64.51 percent until first commercial production. On August 11, 2011, 

the Government of Indonesia approved this change in ownership interest. 

The initial exploration term of the Budong PSC was due to expire on January 15, 2013. In September 2012, the operator of the Budong 

PSC, on behalf of us and the other co-venturer, submitted a request to BPMIGAS under the terms of the Budong PSC for a four-year extension 

of the initial six-year exploration term of the Budong PSC. In January 2013, we received written approval from SKK Migas of the four-year 

extension of the initial six-year exploration term. 

In November 2012, the Indonesia constitutional court declared BPMIGAS, Indonesia’s oil and gas regulatory authority, to be 

unconstitutional. In January 2013, SKK Migas, the Special Task Force for oil and gas upstream sector, was formed to replace BPMIGAS. 

In December 2012, we signed a farmout agreement with the operator of the Budong PSC to acquire an additional 7.1 percent participating 

interest and to become operator of the Budong PSC. We assumed the role of interim operator effective January 16, 2013. Closing of this 

acquisition will increase our participating ownership interest in the Budong PSC to 71.5 percent with our cost sharing interest becoming 72 

percent until first commercial production. The consideration for this transaction is that we will fund 100 percent of the costs of the first 

exploration well of the four-year extension to the Budong PSC. If the exploration well is not drilled within 18 months of the date of approval 

from the Government of Indonesia of this transaction, our partner has the right to give notice that the consideration be paid in cash, or $3.2 

million. The acquisition of the additional participating interest and the transfer of operatorship are dependent on approval by the Government of 

Indonesia. 

We have satisfied all work commitments for the current exploration phase of the Budong PSC. However, the extension of the initial 

exploration term includes an exploration well, which if not drilled by January 2016, results in the termination of the Budong PSC. 

During the initial exploration period, the Budong PSC covered 1.35 million acres. The Budong PSC includes a ten-year exploration 

period and a 20-year development phase. Pursuant to the terms of the Budong PSC, at the end of the first three-year exploration phase, 45 

percent of the original area was to be relinquished to SKK Migas. In January 2010, 35 percent of the original area was relinquished and ten 

percent of the required relinquishment was deferred until 2011. In January 2011, the deferred ten percent of the original total contract area was 

relinquished to SKK Migas. The Budong PSC currently covers 0.75 million acres. However, pursuant to the request for extension of the initial 

exploration term, the contract area held by the Budong PSC at the beginning of the extension period should be reduced, per the terms of the 

Budong PSC, from the current 55 percent to 20 percent of the original contract area. If the full amount of the required relinquishment is 

required, 0.3 million acres would remain in the Budong PSC contract area. In January 2013, our partner, on our behalf, submitted a 

relinquishment proposal of 10 percent to SKK Migas. The retained area will contain all the areas of geological interest to the Budong PSC 

partners. 

 

S-38 
Table of Contents 

Operational activities during 2012 focused on a review of geological and geophysical data obtained from the drilling of LG-1 and KD-1 

wells to upgrade the prospectivity of the block and to define a prospect for potential drilling in 2013. We have completed remapping of both the 

Lariang and Karama Basins with eight leads in the Lariang Basin and five leads in the Karama Basin having been identified. The identification 

of these leads is the basis for the four-year extension request of the first six-year exploration term. 

The Budong PSC represents $5.3 million of unproved oil and gas properties on our December 31, 2012 balance sheet (2011: $5.3 

million). 

Note 15 – Gabon 

We are the operator of the Dussafu PSC with a 66.667 percent ownership interest. Located offshore Gabon, adjacent to the border with 

the Republic of Congo, the Dussafu PSC covers an area of 680,000 acres with water depths up to 1,650 feet. 

The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic 

Resources, entered into the third exploration phase of the Dussafu PSC with an effective date of May 28, 2012. The Direction Generale Des 

Hydrocarbures (“DGH”) agreed to lengthen the third exploration phase to four years until May 27, 2016. The third exploration phase of the 

Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period. This commitment 

was fulfilled with the drilling of DTM-1. 

Operational activities during the year ended December 31, 2012 included completion of the processing of 545 square kilometers of 

seismic which was acquired in the fourth quarter of 2011 and well planning. The 3-D Pre-Stack Time Migration (“PSTM”) was completed in 

July 2012. 

Well planning progressed to drill an exploration well in the fourth quarter of 2012 on the Tortue prospect. DTM-1 well was spud 

November 19, 2012. DTM-1 was drilled with the Scarabeo 3 semi-submersible drilling unit. On January 4, 2013, we announced that DTM-1 

had reached the Dental Formation and discovered oil in both the Gamba and Dentale formations. Additional technical evaluation is on-going 

and is expected to take several months. 

See Note 7 – Commitments and Contingencies for a discussion of legal matters related to our Gabon operations. 

The Dussafu PSC represents $76.4 million of unproved oil and gas properties on our December 31, 2012 balance sheet (2011: $48.9 

million). 

Note 16 – Oman 

In 2009, we signed an EPSA with Oman for Block 64 EPSA. We have an 80 percent working interest and our partner, Oman Oil 

Company, has a 20 percent carried interest in Block 64 EPSA during the initial period. Block 64 EPSA was a block designated for exploration 

and production of non-associated gas and condensate, which the Oman Ministry of Oil and Gas carved out of the Block 6 Concession operated 

by Petroleum Development of Oman (“PDO”). PDO has continued to produce oil from several shallow oil fields within Block 64 EPSA area. 

All work commitments for the First Phase exploration period on Block 64 EPSA have been completed. Operational activities during 2012 

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

March 12, 2013, we elected to not request an extension of the First Phase or enter the Second Phase of Block 64 EPSA and Block 64 will be 

relinquished effective June 30, 2013. The carrying value of Block 64 EPSA of $6.4 million was written off to impairment expense at 

December 31, 2012. During the first half of 2013, we will terminate operations and close the field office. 

Block 64 EPSA represented $5.3 million of unproved oil and gas properties on our December 31, 2011 balance sheet. 

 

S-39 
Table of Contents 

Note 17 – China 

In December 1996, we acquired a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. 

The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under 

certain circumstances, and lies within an area which is the subject of a border dispute between China and Socialist Republic of Vietnam 

(“Vietnam”). Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The border dispute has 

lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the dispute. Due to the 

border dispute between China and Vietnam, we have been unable to pursue an exploration program during Phase One of the contract. As a 

result, we have obtained license extensions, with the current extension in effect until May 31, 2013. The Joint Management Committee has 

approved an extension of the license until May 31, 2015. We are meeting with CNOOC in April 2013 to discuss the ratification of the 

extension. Regular meetings are held with CNOOC with contingent work programs being planned and annual budgets being set. While no 

assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist. Even though there 

continues to be increasing activity on the Vietnamese blocks which we believe confirms our view of WAB-21’s prospectivity, we impaired the 

carrying value of WAB-21 of $2.9 million at December 31, 2012 due to our continued inability to pursue an exploration program. However, we 

continue to seek permission to acquire regional 2-D seismic and localized 3-D seismic. 

WAB-21 represented $2.9 million of unproved oil and gas properties on our December 31, 2011 balance sheet. 

Note 18 – Related Party Transactions 

Dividends declared and paid by Petrodelta are paid to HNR Finance. HNR Finance must declare a dividend in order for the partners, 

Harvest and Vinccler, to receive their respective shares of Petrodelta’s dividend. Between 2008 and 2010, Petrodelta declared three dividends, 

totaling $105.5 million, which have been received by HNR Finance and one dividend, totaling $12.2 million, which has not yet been received 

by HNR Finance. HNR Finance declared a dividend in 2008 in the amount of $72.5 million. HNR Finance has not declared a dividend for the 

remaining $33.0 million. At December 31, 2012, Vinccler’s share of the undistributed dividends is $9.0 million. 

Note 19 – Subsequent Events 

On February 20, 2013, we announced that the SPA had been termination as a result of the Government of Indonesia voting not to approve 

the transaction. See Note 5 – Dispositions, Share Purchase Agreement (“SPA”) . 

On March 25, 2013, SKK Migas approved the transfer of operatorship of the Budong PSC to us. 

On April 9, 2013, the Government of Indonesia approved the acquisition of the additional 7.1 percent participating interest in the Budong 

PSC. 

We conducted our subsequent events review up through the date of the issuance of this Annual Report on Form 10-K. 

 

S-40 
Table of Contents 

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

 

Quarterly Financial Data (unaudited) 

Summarized quarterly financial data is as follows: 

 

 

 

S-41 

 Quarter Ended 

 March 31 June 30 September 30 December 31 

 (amounts in thousands, except per share data) 

 RESTATED RESTATED RESTATED 

Year ended December 31, 2012 

Expenses $ (13,428 ) $ (8,412 ) $ (7,039 ) $ (22,638 ) 

Non-operating loss (2,291 ) (3,090 ) (1,736 ) (6,833 ) 

 

Loss from continuing operations before income taxes (15,719 ) (11,502 ) (8,775 ) (29,471 ) 

Income tax expense (benefit) (1,220 ) (1,022 ) 1,723 (90 ) 

 

Loss from continuing operations (14,499 ) (10,480 ) (10,498 ) (29,381 ) 

Net income from equity affiliate 16,896 22,829 20,299 7,745 

 

Net income (loss) from continuing operations 2,397 12,349 9,801 (21,636 ) 

Loss from discontinued operations (115 ) (1,584 ) — — 

 

Net income (loss) 2,282 10,765 9,801 (21,636 ) 

Less: Net income attributable to noncontrolling interest 3,322 4,540 4,050 1,511 

 

Net income (loss) attributable to Harvest $ (1,040 ) $ 6,225 $ 5,751 $ (23,147 ) 

 

 

 

 

 

 

 

 

Basic Earnings (Loss) per Share: 

Income (loss) from continuing operations $ (0.03 ) $ 0.21 $ 0.15 $ (0.59 ) 

Discontinued operations $ — $ (0.04 ) $ — $ — 

Net income (loss) attributable to Harvest $ (0.03 ) $ 0.17 $ 0.15 $ (0.59 ) 

Diluted Earnings (Loss) per Share: 

Income (loss) from continuing operations $ (0.03 ) $ 0.19 $ 0.15 $ (0.59 ) 

Discontinued operations $ — $ (0.04 ) $ — $ — 

Net income (loss) attributable to Harvest $ (0.03 ) $ 0.15 $ 0.15 $ (0.59 ) 

 Quarter Ended 

 March 31 June 30 September 30 December 31 

 (amounts in thousands, except per share data) 

 RESTATED RESTATED RESTATED RESTATED 

Year ended December 31, 2011 

Expenses $ (8,098 ) $ (11,943 ) $ (7,352 ) $ (61,119 ) 

Non-operating loss (6,366 ) (8,294 ) 3,250 49 

 

Loss from continuing operations before income taxes (14,464 ) (20,237 ) (4,102 ) (61,070 ) 

Income tax expense 459 260 214 124 

 

Loss from continuing operations (14,923 ) (20,497 ) (4,316 ) (61,194 ) 

Net income from equity affiliates 18,456 18,284 18,476 18,235 

 

Net income (loss) from continuing operations 3,533 (2,213 ) 14,160 (42,959 ) 

Income (loss) from discontinued operations (3,266 ) 98,665 36 2,181 

 

Net income (loss) 267 96,452 14,196 (40,778 ) 

Less: Net income attributable to noncontrolling interest 3,419 3,639 3,592 3,527 

 

Net income (loss) attributable to Harvest $ (3,152 ) $ 92,813 $ 10,604 $ (44,305 ) 

 

 

 

 

 

 

 

 

Basic Earnings (Loss) per Share: 

Income (loss) from continuing operations $ — $ (0.17 ) $ 0.31 $ (1.36 ) 

Discontinued operations $ (0.10 ) $ 2.90 $ — $ 0.06 

Net income (loss) attributable to Harvest $ (0.10 ) $ 2.73 $ 0.31 $ (1.30 ) 

Diluted Earnings (Loss) per Share: 

Income (loss) from continuing operations $ — $ (0.17 ) $ 0.28 $ (1.36 ) 

Discontinued operations $ (0.10 ) $ 2.90 $ — $ 0.06 

Net income (loss) attributable to Harvest $ (0.10 ) $ 2.73 $ 0.28 $ (1.30 ) 
Table of Contents 

As noted above, the amounts per quarter were restated. Presented below are restated quarterly financial statements for each of the three 

quarters of 2012 and all quarters of 2011. 

During 2012, we identified accounting errors subsequent to filing our Quarterly Reports on Form 10-Q for the periods ended March 31, 

2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012 and September 30, 2012. As discussed in Note 

3, in the course of management’s ongoing review and analysis and management’s review of the design and operating effectiveness of internal 

control over financial reporting, we concluded that there were errors in previously filed financial statements. In the course of our review, 

management determined that (a) certain warrants issued in 2010 in connection with our $60 million term loan facility (the “Warrants”) were 

improperly valued at inception and improperly classified as equity instruments rather than liability instruments. As a result of the improper 

classification of the Warrants, (b) the debt discount and associated interest expense related to the amortization of the debt discount was 

understated for all periods in which the associated debt was outstanding, and (c) the consolidated statement of operations and comprehensive 

income (loss) for each reporting period was misstated by the omission of the changes in fair value of the Warrants as a liability instrument. 

Additionally, (d) certain exploration overhead was incorrectly capitalized to oil and gas properties, which under the successful efforts method 

of accounting should have been expensed, and (e) certain leasehold maintenance and other costs were improperly capitalized to oil and gas 

properties, which under the successful efforts method of accounting should have been expensed. Finally, (f) advances to equity affiliate were 

improperly classified as an operating activity rather than an investing activity and (g) certain costs were improperly classified as an investing 

activity rather than an operating activity on the consolidated statement of cash flows. As a result of the errors related to the Warrants described 

above, loss on extinguishment of debt was understated for the quarters ended June 30, 2011, September 30, 2011 and December 31, 2011. 

Additionally, an error was identified in the calculation of earnings (loss) per diluted share for the three and six months ended June 30, 2011, 

and an additional error was identified related to the improper expensing of costs associated with debt conversions that should have been 

recorded to equity for the quarters ended March 31, 2012 and September 30, 2012. 

We have restated our segment footnote information to reflect the applicable errors stated above and (a) reclassify noncontrolling interest 

from United States segment to Venezuela segment, (b) eliminate intrasegment receivables erroneously reported gross of related intrasegment 

payable, and (c) eliminate intrasegment revenue erroneously reported gross of related intrasegment expense. Such errors impacted the quarterly 

periods ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012, and September 30, 

2012. 

In assessing the severity of the corrections, management determined that the errors were material to the consolidated financial statements 

as of and for the quarters ended March 31, 2011 June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012 and 

September 30, 2012. In addition to the errors described above, we have also made corrections for previously identified immaterial errors and 

errors affecting classification within the consolidated statement of operations and comprehensive income (loss) related to impairment of oil and 

gas properties and income taxes and the consolidated balance sheets related to income taxes. Management concluded that we should restate our 

financial statements included in our Quarterly Report on Form 10-Q for the periods ending March 31, 2012, June 30, 2012, and September 30, 

2012, and recommended that the Audit Committee authorize such restatement. 

Set forth below is a summary of the nature of the errors. Correction explanations are provided following each of the financial statements 

affected. 

 

 

 For the Quarters Ended 

 

March 31 

2012 

June 30 

2012 

September 30 

2012 

 (amounts in thousands, except per share data) 

Exploration expense $ (492 ) $ (430 ) $ (378 ) 

Unrealized gain (loss) on warrant derivative 432 (1,641 ) 249 

Interest expense 302 — — 

Debt conversion expense — — 12 

Income tax (expense) benefit — 596 (597 ) 

Net income from equity affiliate 138 168 67 

Loss from discontinued operations — (595 ) 595 

Non controlling interest (28 ) (33 ) (14 ) 

 

Net income attributable to Harvest $ 352 $ (1,935 ) $ (66 ) 

 

 

 

 

 

 

Basic earnings (loss) per share $ 0.01 $ (0.05 ) $ — 

Diluted earnings (loss) per share $ 0.01 $ (0.05 ) $ — 

 For the Quarters Ended 

 

March 31 

2011 

June 30 

2011 

September 30 

2011 

December 31 

2011 

 (amounts in thousands, except per share data) 

Exploration expense $ (110 ) $ 3,210 $ (1,375 ) $ (600 ) 

Impairment expense — (3,335 ) — — 

Unrealized gain (loss) on warrant derivative (2,516 ) 7,060 4,256 986 

Interest expense (1,341 ) (482 ) — — 

Loss on early extinguishment of debt — (3,450 ) — — 
 

S-42 

Income tax (expense) benefit (237 ) — 12 (12 ) 

Net income from equity affiliate (38 ) 38 — — 

Non controlling interest 8 (8 ) — — 

 

Net income attributable to Harvest $ (4,234 ) $ 3,033 $ 2,893 $ 374 

 

 

 

 

 

 

 

 

Basic earnings (loss) per share $ (0.13 ) $ 0.09 $ 0.08 $ 0.01 

Diluted earnings (loss) per share $ (0.12 ) $ 0.50 $ 0.08 $ 0.01 
Table of Contents 

CONSOLIDATED BALANCE SHEETS (UNAUDITED) 

(dollars in thousands, except per share data) 

 

“As Previously Reported” reflects balances reported in the March 31, 2012, June 30, 2012 and September 30, 2012 Quarterly Report on Form 

10-Q. “As Restated” reflects the final restated balances. 

 

S-43 

 At September 30, 2012 At June 30, 2012 At March 31, 2012 

 As Previously As As Previously As As Previously As 

 Reported Restated Reported Restated Reported Restated 

ASSETS 

CURRENT ASSETS: 

Cash and cash equivalents $ 20,419 $ 20,419 $ 28,746 $ 28,746 $ 33,552 $ 33,552 

Restricted cash — — — — 1,200 1,200 

Accounts and notes receivable, net 

Dividend receivable — — 12,200 12,200 12,200 12,200 

Joint interest and other 3,411 3,411 6,315 6,315 12,740 12,740 

Notes receivable — — — — 3,335 3,335 

Advances to and receivable from equity affiliate 2,690 2,690 2,538 2,538 2,384 2,384 

Deferred income tax 2,628 — 2,628 — 2,628 — 

Prepaid expenses and other 2,435 2,435 1,692 1,692 1,261 1,261 

 

TOTAL CURRENT ASSETS 31,583 28,955 54,119 51,491 69,300 66,672 

OTHER ASSETS 5,730 5,730 5,555 5,555 5,186 5,186 

LONG-TERM RECEIVABLE, EQUITY AFFILIATE 12,200 12,200 — — — — 

INVESTMENT IN EQUITY AFFILIATE 404,705 405,078 384,473 384,779 361,812 361,950 

PROPERTY AND EQUIPMENT: 

Oil and gas properties 72,181 67,446 70,292 66,017 67,784 63,939 

Other administrative property, net 883 883 934 934 1,027 1,027 

 

Net property and equipment 73,064 68,329 71,226 66,951 68,811 64,966 

 

TOTAL ASSETS $ 527,282 $ 520,292 $ 515,373 $ 508,776 $ 505,109 $ 498,774 

 

 

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND EQUITY 

CURRENT LIABILITIES: 

Accounts payable-trade $ 952 $ 952 $ 1,044 $ 1,044 $ 2,548 $ 2,548 

Accounts payable-carry obligation — — — — 3,596 3,596 

Accrued expense 9,164 8,896 8,896 8,896 8,177 8,177 

Accrued interest payable 679 283 1,008 612 653 257 

Other current liabilities 4,835 2,632 4,835 2,632 4,835 2,632 

Income taxes payable 1,579 1,551 1,251 1,221 979 950 

Current portion – long term debt 9,000 9,000 15,551 15,551 15,551 15,551 

 

TOTAL CURRENT LIABILITIES 26,209 23,314 32,585 29,956 36,339 33,711 

OTHER LIABILITIES 1,054 1,054 956 956 949 949 

WARRANT DERIVATIVE LIABILITY — 5,830 — 6,079 — 4,438 

COMMITMENTS AND CONTINGENCIES 

EQUITY 

STOCKHOLDERS’ EQUITY 

Common stock 452 452 438 438 437 437 

Additional paid-in capital 264,329 255,672 256,009 247,178 254,625 245,794 

Retained earnings 205,868 204,525 200,051 198,774 191,891 192,549 

Treasury stock (66,145 ) (66,145 ) (66,145 ) (66,145 ) (66,104 ) (66,104 ) 

 

TOTAL HARVEST 

STOCKHOLDERS’ EQUITY 404,504 394,504 390,353 380,245 380,849 372,676 

NONCONTROLLING INTEREST 95,515 95,590 91,479 91,540 86,972 87,000 

 

TOTAL EQUITY 500,019 490,094 481,832 471,785 467,821 459,676 

 

TOTAL LIABILITIES AND EQUITY $ 527,282 $ 520,292 $ 515,373 $ 508,776 $ 505,109 $ 498,774 

 

 

 

 

 

 

 

 

 

 

 

 

(g) 

(a) 

(b) 

(f) 

(h) 

(g) 

(c) 

(d) 

(e) 

(a) 
Table of Contents 

2012 Consolidated Balance Sheet Corrections: 

 

 

S-44 

(a) Represents a previously identified immaterial error. 

(b) Relates to lease maintenance costs and exploration overhead that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. 

(c) Income tax effect of the adjustments and income taxes improperly classified as interest payable in 2011. 

(d) Represents the fair value of the Warrants at the reporting date. 

(e) For the three months ended March 31, 2012 and six months ended June 30, 2012, the adjustment to additional paid-in capital relates to (a) 

the reclassification of the Warrants from equity to warrant derivative liability of $11,122 thousand offset by an error recorded in 2011 for 

$2,730 thousand for the for the reversal of the original fair value of certain Warrants that did not qualify for equity classification and (b) 

deferred financing costs of $439 thousand that were erroneously expensed rather than capitalized to additional paid-in capital. For the 

nine months ended September 30, 2012, the adjustment to additional paid-in capital relates to (a) the reclassification of the Warrants from 

equity to warrant derivative liability of $11,122 thousand offset by an error recorded in 2011 for $2,730 thousand for the for the reversal 

of the original fair value of certain Warrants that did not qualify for equity classification and (b) deferred financing costs of $265 

thousand that were erroneously expensed rather than capitalized to additional paid-in capital. 

(f) Relates to the improper expensing of costs associated with debt conversion. 

(g) Relates to a deferred tax asset that was erroneously reported gross of the related liability. 

(h) Represents other current liabilities that were improperly classified as interest payable and income taxes payable. 
Table of Contents 

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED) 

(dollars in thousands, except per share data) 

 

“As Previously Reported” reflects balances reported in the March 31, 2012, June 30, 2012 and September 30, 2012 Quarterly Report on Form 

10-Q. “As Restated” reflects the final restated balances. 

 

S-45 

 

Nine Months Ended 

September 30, 2012 

Six Months Ended 

June 30, 2012 

Three Months Ended 

March 31, 2012 

 As Previously As As Previously As As Previously As 

 Reported Adjustments Restated Reported Adjustments Restated Reported Adjustments Restated 

Expenses: 

Depreciation and amortization $ 316 $ — $ 316 $ 210 $ — $ 210 $ 105 $ — $ 105 

Exploration expense 4,200 1,300 5,500 2,725 922 3,647 1,443 492 1,935 

Dry hole costs 5,617 — 5,617 5,617 — 5,617 5,546 — 5,546 

General and administrative 17,446 — 17,446 12,366 — 12,366 5,842 — 5,842 

 

 27,579 1,300 28,879 20,918 922 21,840 12,936 492 13,428 

 

Loss From Operations (27,579 ) (1,300 ) (28,879 ) (20,918 ) (922 ) (21,840 ) (12,936 ) (492 ) (13,428 ) 

Other Non-Operation Income (Expense) 

Investment earnings and other 231 — 231 149 — 149 69 — 69 

Unrealized gain (loss) on warrant 

derivative — (960 ) (960 ) — (1,209 ) (1,209 ) — 432 432 

Interest expense (447 ) 302 (145 ) (428 ) 302 (126 ) (394 ) 302 (92 ) 

Debt conversion expense (3,360 ) 12 (3,348 ) (2,402 ) — (2,402 ) (2,422 ) — (2,422 ) 

Other non-operating expense (2,801 ) — (2,801 ) (1,723 ) — (1,723 ) (256 ) — (256 ) 

Loss on exchange rates (94 ) — (94 ) (70 ) — (70 ) (22 ) — (22 ) 

 

 (6,471 ) (646 ) (7,117 ) (4,474 ) (907 ) (5,381 ) (3,025 ) 734 (2,291 ) 

Income (Loss) From Continuing Operations Before Income 

Taxes (34,050 ) (1,946 ) (35,996 ) (25,392 ) (1,829 ) (27,221 ) (15,961 ) 242 (15,719 ) 

Income Tax Expense (Benefit) (520 ) 1 (519 ) (1,646 ) (596 ) (2,242 ) (1,220 ) — (1,220 ) 

 

Income (Loss) From Continuing Operations (33,530 ) (1,947 ) (35,477 ) (23,746 ) (1,233 ) (24,979 ) (14,741 ) 242 (14,499 ) 

Net Income From Equity Affiliate 59,651 373 60,024 39,419 306 39,725 16,758 138 16,896 

 

Net Income (Loss) From Continuing Operations 26,121 (1,574 ) 24,547 15,673 (927 ) 14,746 2,017 380 2,397 

Discontinued Operations 

Loss from discontinued operations (1,699 ) — (1,699 ) (1,699 ) — (1,699 ) (115 ) — (115 ) 

Income tax (expense) benefit — — — 595 (595 ) — — — — 

 

Loss from discontinued operations (1,699 ) — (1,699 ) (1,104 ) (595 ) (1,699 ) (115 ) — (115 ) 

 

Net Income (Loss) 24,422 (1,574 ) 22,848 14,569 (1,522 ) 13,047 1,902 380 2,282 

Less: Net Income (Loss) Attributable To Non-Controlling 

Interest 11,837 75 11,912 7,801 61 7,862 3,294 28 3,322 

 

Net Income (Loss) Attributable to Harvest $ 12,585 $ (1,649 ) $ 10,936 $ 6,768 $ (1,583 ) $ 5,185 $ (1,392 ) $ 352 $ (1,040 ) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Loss Attributable to Harvest Per Common Share: 

Basic earnings (loss) per share 

Income (loss) from continuing operations $ 0.39 $ (0.04 ) $ 0.35 $ 0.22 $ (0.03 ) $ 0.19 $ (0.04 ) $ 0.01 $ (0.03 ) 

Discontinued operations (0.05 ) — (0.05 ) (0.03 ) (0.02 ) (0.05 ) — — — 

 

Net income (loss) attributable to Harvest $ 0.34 $ (0.04 ) $ 0.30 $ 0.19 $ (0.05 ) $ 0.14 $ (0.04 ) $ 0.01 $ (0.03 ) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted earnings (loss) per share 

Income (loss) from continuing operations $ 0.39 $ (0.04 ) $ 0.35 $ 0.21 $ (0.03 ) $ 0.18 $ (0.04 ) $ 0.01 $ (0.03 ) 

Discontinued operations (0.05 ) — (0.05 ) (0.03 ) (0.01 ) (0.04 ) — — — 

 

Net income (loss) attributable to Harvest $ 0.34 $ (0.04 ) $ 0.30 $ 0.18 $ (0.04 ) $ 0.14 $ (0.04 ) $ 0.01 $ (0.03 ) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive Income (Loss) $ 12,585 $ (1,649 ) $ 10,936 $ 6,768 $ (1,583 ) $ 5,185 $ (1,392 ) $ 352 $ (1,040 ) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) 

(b) 

(c) 

(d) 

(f) 

(e) 

(g) 

(e) 
Table of Contents 

YTD 2012 Consolidated Statements of Operations and Comprehensive Income (Loss) Corrections: 

 

 

S-46 

(a) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. 

(b) Represents changes in fair value of Warrants for the period. Such Warrants were previously classified as equity and were, therefore, not 

marked to market at the end of each reporting period. 

(c) Relates to the improper expensing of accrued interest associated with debt conversions. 

(d) Relates to the improper expensing of costs associated with debt conversions. 

(e) Represents a previously identified immaterial error. 

(f) Income tax effects of adjustments. 

(g) Represents a previously identified classification error between income tax on discontinued operations and income tax on continuing 

operations. 
Table of Contents 

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED) 

(dollars in thousands, except per share data) 

 

“As Previously Reported” reflects balances reported in the June 30, 2012 and September 30, 2012 Quarterly Report on Form 10-Q. “As 

Restated” reflects the final restated balances. 

 

S-47 

 Three Months Ended September 30, 2012 Three Months Ended June 30, 2012 

 As Previously As As Previously As 

 Reported Adjustments Restated Reported Adjustments Restated 

Expenses 

Depreciation and amortization $ 106 $ — $ 106 $ 105 $ — $ 105 

Exploration expense 1,475 378 1,853 1,282 430 1,712 

Dry hole costs — — — 71 — 71 

General and administrative 5,080 — 5,080 6,524 — 6,524 

 

 6,661 378 7,039 7,982 430 8,412 

Loss From Operations (6,661 ) (378 ) (7,039 ) (7,982 ) (430 ) (8,412 ) 

Other Non-Operation Income (Expense) 

Investment earnings and other 82 — 82 80 — 80 

Unrealized gain (loss) on warrant derivative — 249 249 — (1,641 ) (1,641 ) 

Interest expense (19 ) — (19 ) (34 ) — (34 ) 

Debt conversion expense (958 ) 12 (946 ) 20 — 20 

Other non-operating expense (1,078 ) — (1,078 ) (1,467 ) — (1,467 ) 

Loss on exchange rates (24 ) — (24 ) (48 ) — (48 ) 

 

 (1,997 ) 261 (1,736 ) (1,449 ) (1,641 ) (3,090 ) 

 

Loss From Companies Continuing Operations Before 

Income Taxes (8,658 ) (117 ) (8,775 ) (9,431 ) (2,071 ) (11,502 ) 

Income Tax Expense (Benefit) 1,126 597 1,723 (426 ) (596 ) (1,022 ) 

 

Loss From Companies Continuing Operations (9,784 ) (714 ) (10,498 ) (9,005 ) (1,475 ) (10,480 ) 

Net Income (Loss) From Equity Affiliate 20,232 67 20,299 22,661 168 22,829 

 

Net Income (Loss) From Continuing Operations 10,448 (647 ) 9,801 13,656 (1,307 ) 12,349 

Discontinued Operations 

Loss from discontinued operations — — — (1,584 ) — (1,584 ) 

Income tax (expense) benefit (595 ) 595 — 595 (595 ) — 

 

Loss from discontinued operations (595 ) 595 — (989 ) (595 ) (1,584 ) 

 

Net Income (Loss) 9,853 (52 ) 9,801 12,667 (1,902 ) 10,765 

Less: Net Income (Loss) Attributable to 

Noncontrolling Interest 4,036 14 4,050 4,507 33 4,540 

 

Net Income (Loss) Attributable to Harvest $ 5,817 $ (66 ) $ 5,751 $ 8,160 $ (1,935 ) $ 6,225 

 

 

 

 

 

 

 

 

 

 

 

 

Net Loss Attributable to Harvest Per Common Share: 

Basic earnings (loss) per share 

Income (loss) from continuing operations $ 0.17 $ (0.02 ) $ 0.15 $ 0.25 $ (0.04 ) $ 0.21 

Discontinued operations (0.02 ) 0.02 — (0.03 ) (0.01 ) (0.04 ) 

 

Net income (loss) attributable to Harvest $ 0.15 $ — $ 0.15 $ 0.22 $ (0.05 ) $ 0.17 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted earnings (loss) per share 

Income (loss) from continuing operations $ 0.17 $ (0.02 ) $ 0.15 $ 0.22 $ (0.03 ) $ 0.19 

Discontinued operations (0.02 ) 0.02 — (0.02 ) (0.02 ) (0.04 ) 

 

Net income (loss) attributable to Harvest $ 0.15 $ — $ 0.15 $ 0.20 $ (0.05 ) $ 0.15 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive Income (Loss) $ 5,817 $ (66 ) $ 5,751 $ 8,160 $ (1,935 ) $ 6,225 

 

 

 

 

 

 

 

 

 

 

 

 

(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

(e) 
Table of Contents 

Quarter 2012 Consolidated Statements of Operations and Comprehensive Income (Loss) Corrections: 

 

 

S-48 

(a) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. 

(b) Represents changes in fair value of the Warrants for the period. Such Warrants were previously classified as equity and were, therefore, 

not marked to market at the end of each reporting period. 

(c) Relates to the improper expensing of deferred financing costs associated with the debt conversions. 

(d) Income tax effect of adjustments. 

(e) Represents a previously identified immaterial error. 

(f) Represents a previously identified classification error between income tax on discontinued operations and income tax on continuing 

operations. 
Table of Contents 

CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED) 

(dollars in millions, except per share data) 

 

“As Previously Reported” reflects balances reported in the March 31, 2012, June 30, 2012 and September 30, 2012 Quarterly Report on Form 

10-Q. “As Restated” reflects the final restated balances. 

2012 Consolidated Statements of Cash Flows Corrections: 

 

In addition to the above, we have restated the Consolidated Statements of Stockholder’s Equity for the nine months ended September 30, 

 

Nine Months Ended 

September 30, 2012 

Six Months Ended 

June 30, 2012 

Three Months Ended 

March 31, 2012 

 As Previously As As Previously As As Previously As 

 Reported Restated Reported Restated Reported Restated 

Cash Flows From Operating Activities: 

Net income $ 24,422 $ 22,848 $ 14,569 $ 13,047 $ 1,902 $ 2,282 

Adjustments to reconcile net income to net cash used in 

operating activities: 

Depletion, depreciation and amortization 316 316 210 210 105 105 

Dry hole costs 5,617 5,617 5,617 5,617 5,546 5,546 

Amortization of debt financing costs 898 377 726 287 622 183 

Debt conversion expense 2,502 2,758 1,939 1,939 1,939 1,939 

Allowance for account and note receivable 5,180 5,180 5,180 5,180 — — 

Write-off of accounts payable, carry obligation (3,596 ) (3,596 ) (3,596 ) (3,596 ) — — 

Net income from equity affiliate (59,651 ) (60,024 ) (39,419 ) (39,725 ) (16,758 ) (16,896 ) 

Share-based compensation charges 2,809 2,809 2,124 2,124 886 886 

Unrealized (gain) loss on warrant derivative — 960 — 1,209 — (432 ) 

Changes in operating assets and liabilities: 

Accounts and notes receivables 9,086 9,086 6,182 6,182 1,602 1,602 

Advances to equity affiliate (302 ) — (150 ) — 4 — 

Prepaid expenses and other (1,693 ) (1,693 ) (950 ) (950 ) (533 ) (533 ) 

Other assets — (984 ) — (829 ) — (378 ) 

Accounts payable – trade (6,429 ) (6,429 ) (6,337 ) (6,337 ) (4,833 ) (4,833 ) 

Accrued expenses (1,562 ) (1,830 ) (2,177 ) (2,177 ) (2,225 ) (2,225 ) 

Accrued interest (1,329 ) (1,329 ) (971 ) (971 ) (902 ) (902 ) 

Other long-term liabilities 146 146 48 48 41 41 

Income taxes payable 861 862 533 532 261 261 

 

Net Cash Used In Operating Activities (22,725 ) (24,926 ) (16,472 ) (18,210 ) (12,343 ) (13,354 ) 

 

Cash Flows From Investing Activities: 

Additions of property and equipment (16,252 ) (14,733 ) (14,205 ) (13,146 ) (12,607 ) (11,978 ) 

Advances to equity affiliate — (302 ) — (150 ) — 4 

Increase (decrease) in restricted cash 1,200 1,200 1,200 1,200 — — 

Investment costs (984 ) — (829 ) — (378 ) — 

 

Net Cash Used In Investing Activities (16,036 ) (13,835 ) (13,834 ) (12,096 ) (12,985 ) (11,974 ) 

 

Cash Flows From Financing Activities: 

Net proceeds from issuances of common Stock 700 700 273 273 — — 

Financing costs (466 ) (466 ) (167 ) (167 ) (66 ) (66 ) 

 

Net Cash Provided By (Used In) Financing Activities 234 234 106 106 (66 ) (66 ) 

 

Net Decrease in Cash and Cash Equivalents (38,527 ) (38,527 ) (30,200 ) (30,200 ) (25,394 ) (25,394 ) 

Cash and Cash Equivalents at Beginning of Period 58,946 58,946 58,946 58,946 58,946 58,946 

 

Cash and Cash Equivalents at End of Period $ 20,419 $ 20,419 $ 28,746 $ 28,746 $ 33,552 $ 33,552 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Relates to certain costs improperly classified as an investing activity rather than an operating activity. 

(b) Relates to the improper classification of Advances to Equity Affiliate as an operating activity rather than an investing activity. 

(c) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. 

(d) Relates to the improper expensing of deferred financing costs associated with the debt conversions that should have been recorded to 

equity. 

(e) Represents changes in fair value of Warrants for the period. Such Warrants were previously classified as equity and were, therefore, not 

marked to market at the end of each reporting period. 

(f) Represents a previously identified immaterial error. 

(g) Income tax effects of the adjustments. 

(h) Relates to the previously identified improper expensing of costs associated with debt conversion. 

(i) Relates to the improper expensing of accrued interest associated with the debt conversions that should have been recorded to equity. 

(d) 

(i) 

(f) 

(e) 

(b) 

(a) 

(h) 

(g) 

(c) 

(b) 

(a) 
2012 to reflect the reclassification of the Warrants from equity to warrant derivative liability and to restate the January 1, 2011 beginning 

balances to reflect cumulative adjustments related to the previously described errors as follows: 

 

 

 

 

 

 

In addition to the above, we have restated Operating Segments to reflect the errors stated above and (a) reclassify noncontrolling 

interest from United States segment to Venezuela segment, (b) eliminate intrasegment receivables erroneously reported gross of related 

intrasegment payable, and (c) eliminate intrasegment revenue erroneously reported gross of related intrasegment expense. 

 

 

Common 

Shares 

Issued 

Common 

Stock 

Additional 

Paid-in 

Capital 

Retained 

Earnings 

Treasury 

Stock 

NonControlling 

Interest 

Total 

Equity 

Balance at January 1, 2011 as originally reported 40,103 $ 401 $ 230,362 $ 139,389 $ (65,543 ) $ 69,501 $ 374,110 

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

 

Balance at January 1, 2011 as RESTATED 40,103 $ 401 $ 219,240 $ 137,629 $ (65,543 ) $ 69,501 $ 361,228 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) The adjustment to additional paid-in capital relates to the reclassification of the Warrants from equity to warrant derivative liability. 

(b) The adjustment to retained earnings relates to (a) lease maintenance costs of $313 thousand that were erroneously capitalized as oil and 

gas properties rather than expensed as exploration expense, (b) the reduction in the fair value of the Warrants for the year ended 

December 31, 2010 of $344 thousand, additional amortization of debt of $1,098 thousand resulting from the increased discount allocated 

to the debt, offset by a reduction to retained earnings of $693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance 

costs that were improperly capitalized rather than expensed prior to January 1, 2010. 

 

Common 

Shares 

Issued 

Common 

Stock 

Additional 

Paid-in 

Capital 

Retained 

Earnings 

Treasury 

Stock 

NonControlling 

Interest 

Total 

Equity 

Balance at December 31, 2011 as originally reported 40,625 $ 406 $ 236,192 $ 193,283 $ (66,104 ) $ 83,678 $ 447,455 

Adjustments — — (8,392 ) 306 — — (8,086 ) 

 

Balance at December 31, 2011 as RESTATED 40,625 $ 406 $ 227,800 $ 193,589 $ (66,104 ) $ 83,678 $ 439,369 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) The adjustment to additional paid-in capital relates to the reclassification of the Warrants from equity to warrant derivative liability of 

$11,122 thousand offset by an error recorded in 2011 for $2,730 thousand for the for the reversal of the original fair value of certain 

Warrants that did not qualify for equity classification. 

(b) The adjustment to retained earnings relates to (a) net increase in 2010 and 2011 expense related to exploration expense of $2,523 

thousand that was erroneously capitalized as oil and gas properties rather than expensed as exploration expense (includes consideration of 

reclassification between exploration expense and impairment of oil and gas properties), (b) net increase in unrealized gain on warrant 

derivatives of $10,130 thousand for cumulative 2010 and 2011, (c) net increase in interest expense of $2,921 thousand cumulative for 

2010 and 2011, (d) net increase in loss on extinguishment of debt of $3,450 thousand for 2011, (e) net increase in income tax expense of 

$237 thousand for income taxes improperly classified as interest expense, offset by a reduction to retained earnings of $693 thousand 

prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than expensed prior to 

January 1, 2010. 

 

Common 

Shares 

Issued 

Common 

Stock 

Additional 

Paid-in 

Capital 

Retained 

Earnings 

Treasury 

Stock 

NonControlling 

Interest 

Total 

Equity 

Balance at September 30, 2012 as originally reported 45,181 $ 452 $ 264,329 $ 205,868 $ (66,145 ) $ 95,515 $ 500,019 

Adjustments — — (8,657 ) (1,343 ) — 75 (9,925 ) 

 

Balance at September 30, 2012 as RESTATED 45,181 $ 452 $ 255,672 $ 204,525 $ (66,145 ) $ 95,590 $ 490,094 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) The adjustment to additional paid-in capital relates to (a) the reclassification of the Warrants from equity to warrant derivative liability of 

$11,122 thousand offset by an error recorded in 2011 for $2,730 thousand for the for the reversal of the original fair value of certain 

Warrants that did not qualify for equity classification and (b) deferred financing costs of $265 thousand that were erroneously expensed 

rather than capitalized to additional paid-in capital. 

(b) The adjustment to retained earnings relates to (a) net increase in 2010, 2011 and nine months 2012 expense related to exploration expense 

of $3,823 thousand that was erroneously capitalized as oil and gas properties rather than expensed as exploration expense (includes 

consideration of reclassification between exploration expense and impairment of oil and gas properties), (b) net increase in unrealized 

gain on warrant derivatives of $9,170 thousand for cumulative 2010, 2011 and nine months 2012, (c) net increase in interest expense of 

$2,619 thousand cumulative for 2010, 2011, and nine months 2012, (d) net increase in loss on extinguishment of debt of $3,450 thousand 

for 2011, (e) increase in net income from equity affiliate of $373 thousand less noncontrolling interest of $75 thousand due to a 

previously identified immaterial error, (f) net increase in income tax expense of $238 thousand for income taxes improperly classified as 

interest expense, (g) net decrease in debt conversion expense of $12 thousand for the improper expensing of deferred financing costs 

associated with the debt conversions that should have been recorded in equity, offset by a reduction to retained earnings of $693 thousand 

prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than expensed prior to 

January 1, 2010. 

(c) The adjustment to noncontrolling interest relates to the net increase in net income from equity affiliated due to a previously identified 

immaterial error. 

(a)(b) 

(a)(b) 

(a)(b)(c) 
 

 

 

 At September 30, 2012 At June 30, 2012 At March 31, 2012 

 

As Previously 

Reported As Restated 

As Previously 

Reported As Restated 

As Previously 

Reported As Restated 

Operating Segment Assets 

Venezuela $ 408,550 $ 408,923 $ 388,311 $ 388,617 $ 365,497 $ 365,635 

Indonesia 13,005 10,494 12,862 10,622 14,388 12,503 

Gabon 57,420 55,606 56,211 54,492 56,567 54,899 

Oman 6,669 6,669 6,535 6,535 6,586 6,586 

United States 251,054 248,016 253,594 250,650 259,404 256,484 

 

 736,698 729,708 717,513 710,916 702,442 696,107 

Intersegment eliminations (209,416 ) (209,416 ) (202,140 ) (202,140 ) (197,333 ) (197,333 ) 

 

Total Assets $ 527,282 $ 520,292 $ 515,373 $ 508,776 $ 505,109 $ 498,774 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Represents a previously identified immaterial error. 

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

(c) Relates to elimination of intrasegment receivables erroneously reported gross of related intrasegment payable and a deferred tax asset that 

was erroneously reported gross of the related liability. 

 

Nine Months Ended 

September 30, 2012 

Six Months Ended 

June 30, 2012 

Three Months Ended 

March 31, 2012 

 

As Previously 

Reported Adjustments 

As 

Restated 

As Previously 

Reported Adjustments 

As 

Restated 

As Previously 

Reported Adjustments 

As 

Restated 

Segment Income (Loss) Attributable to 

Harvest 

Venezuela $ 45,820 $ 298 $ 46,118 $ 30,448 $ 245 $ 30,693 $ 12,715 $ 241 $ 12,956 

Indonesia (4,992 ) (1,006 ) (5,998 ) (3,701 ) (733 ) (4,434 ) (2,476 ) (380 ) (2,856 ) 

Gabon (4,717 ) (255 ) (4,972 ) (2,985 ) (162 ) (3,147 ) (1,315 ) (110 ) (1,425 ) 

Oman (7,235 ) — (7,235 ) (6,531 ) — (6,531 ) (5,608 ) — (5,608 ) 

United States (14,592 ) (686 ) (15,278 ) (9,359 ) (338 ) (9,697 ) (4,593 ) 601 (3,992 ) 

 

Net income (loss) from 

continuing operations 14,284 (1,649 ) 12,635 7,872 (988 ) 6,884 (1,277 ) 352 (925 ) 

Discontinued operations 

(Antelope Project) (1,699 ) — (1,699 ) (1,104 ) (595 ) (1,699 ) (115 ) — (115 ) 

 

Net income (loss) 

attributable to Harvest $ 12,585 $ (1,649 ) $ 10,936 $ 6,768 $ (1,583 ) $ 5,185 $ (1,392 ) $ 352 $ (1,040 ) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Represents a previously identified immaterial error. 

(b) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. 

(c) Represents change in the fair value of the Warrants for the reporting period and improper expensing of debt conversion costs and lease 

maintenance costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense. 

(d) Represents a previously identified classification error between income tax on discontinued operations and income tax on continuing 

operations. 

(a) 

(b) 

(b) 

(b) 

(c) 

(a) 

(b) 

(b) 

(c) 

(d) 
 

 

 

S-49 

 Three Months Ended September 30, 2012 Three Months Ended June 30, 2012 

 

As Previously 

Reported Adjustments 

As 

Restated 

As Previously 

Reported Adjustments 

As 

Restated 

Segment Income (Loss) Attributable to Harvest 

Venezuela $ 15,372 $ 53 $ 15,425 $ 17,733 $ 4 $ 17,737 

Indonesia (1,291 ) (273 ) (1,564 ) (1,225 ) (353 ) (1,578 ) 

Gabon (1,732 ) (93 ) (1,825 ) (1,670 ) (52 ) (1,722 ) 

Oman (704 ) — (704 ) (923 ) — (923 ) 

United States (5,233 ) (348 ) (5,581 ) (4,766 ) (939 ) (5,705 ) 

 

Net income (loss) from continuing 

operations 6,412 (661 ) 5,751 9,149 (1,340 ) 7,809 

Discontinued operations (Antelope Project) (595 ) 595 — (989 ) (595 ) (1,584 ) 

 

Net income (loss) attributable to Harvest $ 5,817 $ (66 ) $ 5,751 $ 8,160 $ (1,935 ) $ 6,225 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Represents a previously identified immaterial error. 

(b) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. 

(c) Represents change in the fair value of the Warrants for the reporting period and improper expensing of debt conversion costs and lease 

maintenance costs that were erroneously capitalized as oil and gas properties rather than expensed to exploration expense. 

(d) Represents a previously identified classification error between income tax on discontinued operations and income tax on continuing 

operations. 

(a) 

(b) 

(b) 

(c) 

(d) 
Table of Contents 

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED) 

(dollars in thousands, except per share data) 

 

“As Previously Reported” reflects balances reported in the March 31, 2011, June 30, 2011 and September 30, 2011 Quarterly Report on Form 

10-Q. “As Restated” reflects the final restated balances. 

 

S-50 

 

Nine Months Ended 

September 30, 2011 

Six Months Ended 

June 30, 2011 

Three Months Ended 

March 31, 2011 

 

As 

Previously As 

As 

Previously As 

As 

Previously As 

 Reported Adjustments Restated Reported Adjustments Restated Reported Adjustments Restated 

Expenses: 

Depreciation and amortization $ 354 $ — $ 354 $ 243 $ — $ 243 $ 124 $ — $ 124 

Exploration expense 7,414 (1,725 ) 5,689 5,839 (3,100 ) 2,739 1,189 110 1,299 

Impairment expense — 3,335 3,335 — 3,335 3,335 — — — 

General and administrative 18,015 — 18,015 13,724 — 13,724 6,675 — 6,675 

 

 25,783 1,610 27,393 19,806 235 20,041 7,988 110 8,098 

 

Income (Loss) From Operations (25,783 ) (1,610 ) (27,393 ) (19,806 ) (235 ) (20,041 ) (7,988 ) (110 ) (8,098 ) 

Other Non-operating Income (Expense) 

Investment earnings and other 544 — 544 385 — 385 145 — 145 

Unrealized gain (loss) on warrant derivative — 8,800 8,800 — 4,544 4,544 — (2,516 ) (2,516 ) 

Interest expense (4,722 ) (1,823 ) (6,545 ) (3,916 ) (1,823 ) (5,739 ) (2,212 ) (1,341 ) (3,553 ) 

Loss on early extinguishment of debt (9,682 ) (3,450 ) (13,132 ) (9,682 ) (3,450 ) (13,132 ) — — — 

Other non-operating expense (991 ) — (991 ) (675 ) — (675 ) (431 ) — (431 ) 

Loss on exchange rates (86 ) — (86 ) (43 ) — (43 ) (11 ) — (11 ) 

 

 (14,937 ) 3,527 (11,410 ) (13,931 ) (729 ) (14,660 ) (2,509 ) (3,857 ) (6,366 ) 

Income (Loss) From Continuing Operations Before 

Income Taxes (40,720 ) 1,917 (38,803 ) (33,737 ) (964 ) (34,701 ) (10,497 ) (3,967 ) (14,464 ) 

Income Tax Expense (Benefit) 708 225 933 482 237 719 222 237 459 

 

Income (Loss) From Continuing Operations (41,428 ) 1,692 (39,736 ) (34,219 ) (1,201 ) (35,420 ) (10,719 ) (4,204 ) (14,923 ) 

Net Income (Loss) From Equity Affiliate 55,216 — 55,216 36,740 — 36,740 18,494 (38 ) 18,456 

 

Net Income (Loss) From continuing Operations 13,788 1,692 15,480 2,521 (1,201 ) 1,320 7,775 (4,242 ) 3,533 

Discontinued Operations 

Loss from discontinued operations (2,786 ) — (2,786 ) (2,786 ) — (2,786 ) (3,266 ) — (3,266 ) 

Gain on sale of oil and gas properties 103,969 — 103,969 103,933 — 103,933 — — — 

Income tax expense (5,748 ) — (5,748 ) (5,748 ) — (5,748 ) — — — 

 

Loss from discontinued operations 95,435 — 95,435 95,399 — 95,399 (3,266 ) — (3,266 ) 

 

Net Income (Loss) 109,223 1,692 110,915 97,920 (1,201 ) 96,719 4,509 (4,242 ) 267 

Less: Net Income (Loss) Attributable To NonControlling Interest 10,650 — 10,650 7,058 — 7,058 3,427 (8 ) 3,419 

 

Net Income (Loss) Attributable to Harvest $ 98,573 $ 1,692 $ 100,265 $ 90,862 $ (1,201 ) $ 89,661 $ 1,082 $ (4,234 ) $ (3,152 ) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Attributable To Harvest Per Common 

Share: 

Basic earnings (loss) per share 

Income (loss) from continuing operations $ 0.09 $ 0.05 $ 0.14 $ (0.13 ) $ (0.03 ) $ (0.16 ) $ 0.13 $ (0.13 ) $ — 

Discontinued operations 2.80 — 2.80 2.80 — 2.80 (0.10 ) — (0.10 ) 

 

Net loss attributable to Harvest $ 2.89 $ 0.05 $ 2.94 $ 2.67 $ (0.03 ) $ 2.64 $ 0.03 $ (0.13 ) $ (0.10 ) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted earnings (loss) per share 

Income (loss) from continuing operations $ 0.08 $ 0.04 $ 0.12 $ (0.11 ) $ (0.05 ) $ (0.16 ) $ 0.12 $ (0.12 ) $ — 

Discontinued operations 2.40 — 2.40 2.38 0.42 2.80 (0.10 ) — (0.10 ) 

 

Net loss attributable to Harvest $ 2.48 $ 0.04 $ 2.52 $ 2.27 0.37 $ 2.64 $ 0.02 $ (0.12 ) $ (0.10 ) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive Income (Loss) $ 98,573 $ 1,692 $ 100,265 $ 90,862 $ (1,201 ) $ 89,661 $ 1,082 $ (4,234 ) $ (3,152 ) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

(g) 

(g) 

(h) 
Table of Contents 

YTD 2011 Consolidated Statements of Operations and Comprehensive Income (Loss) Corrections: 

 

 

S-51 

(a) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. This amount was offset by a reclassification from exploration expense to impairment of oil and gas 

properties of $3,335 thousand in the six months ended June 30, 2011 and nine months ended September 30, 2011, respectively, for 

amounts that were erroneously classified as exploration expense. 

(b) Represents the reclassification from exploration expense to impairment of oil and gas properties for amounts that were erroneously 

classified as exploration expense. 

(c) Represents changes in fair value of Warrants for the period. Such Warrants were previously classified as equity and were, therefore, not 

marked to market at the end of each reporting period. 

(d) As a result of the change in the fair value of the Warrants, the original discount allocated to the debt was understated; therefore, the 

additional amortization of the discount on debt, which is a component of interest expense, was understated for each period the debt was 

outstanding and income tax improperly classified as interest expense. 

(e) The correction in the fair value of the Warrants and its classification as a liability resulted in an increase discount on debt which also 

impacted the resulting loss on extinguishment of debt originally recorded in May 2011 when the debt was retired. 

(f) Relates to income tax improperly classified as interest expense. 

(g) Relates to previously identified immaterial error. 

(h) Diluted EPS has been adjusted to reflect an error in the calculation of the weighted average common shares outstanding for dilutive EPS 

for the six months ended June 30, 2011. The weighted average common shares utilized for the calculation of diluted EPS was erroneously 

40,027 thousand rather than 33,992 thousand. 
Table of Contents 

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED) 

(dollars in thousands, except per share data) 

 

“As Previously Reported” reflects balances reported in the March 31, 2011, June 30, 2011 and September 30, 2011 Quarterly Report on Form 

10-Q. “As Restated” reflects the final restated balances. 

Quarter 2011 Consolidated Statements of Operations and Comprehensive Income (Loss) Corrections: 

 

 Three Months Ended September 30, 2011 Three Months Ended June 30, 2011 

 As Previously As As Previously As 

 Reported Adjustments Restated Reported Adjustments Restated 

Expenses 

Depreciation and amortization $ 111 $ — $ 111 $ 119 $ — $ 119 

Exploration expense 1,575 1,375 2,950 4,650 (3,210 ) 1,440 

Impairment expense — — — — 3,335 3,335 

General and administrative 4,291 — 4,291 7,049 — 7,049 

 

 5,977 1,375 7,352 11,818 125 11,943 

 

Loss From Operations (5,977 ) (1,375 ) (7,352 ) (11,818 ) (125 ) (11,943 ) 

Other Non-Operating Income (Expense) 

Investment earnings and other 159 — 159 240 — 240 

Unrealized gain (loss) on warrant derivative — 4,256 4,256 — 7,060 7,060 

Interest expense (806 ) — (806 ) (1,704 ) (482 ) (2,186 ) 

Loss on early extinguishment of debt — — — (9,682 ) (3,450 ) (13,132 ) 

Other non-operating expense (316 ) — (316 ) (244 ) — (244 ) 

Loss on exchange rates (43 ) — (43 ) (32 ) — (32 ) 

 

 (1,006 ) 4,256 3,250 (11,422 ) 3,128 (8,294 ) 

 

Income (Loss) From Continuing Operations Before 

Income Taxes (6,983 ) 2,881 (4,102 ) (23,240 ) 3,003 (20,237 ) 

Income Tax Expense (Benefit) 226 (12 ) 214 260 — 260 

 

Income (Loss) From Continuing Operations (7,209 ) 2,893 (4,316 ) (23,500 ) 3,003 (20,497 ) 

Net Income (Loss) From Equity Affiliate 18,476 — 18,476 18,246 38 18,284 

 

Net Income (Loss) From Continuing Operations 11,267 2,893 14,160 (5,254 ) 3,041 (2,213 ) 

Discontinued Operations 

Income from discontinued operations — — — 480 — 480 

Gain on sale of oil and gas properties 36 — 36 103,933 — 103,933 

Income tax expense — — — (5,748 ) — (5,748 ) 

 

Gain from discontinued operations 36 — 36 98,665 — 98,665 

 

Net Income 11,303 2,893 14,196 93,411 3,041 96,452 

Less: Net Income (Loss) Attributable to 

Noncontrolling Interest 3,592 — 3,592 3,631 8 3,639 

 

Net Income Attributable To Harvest $ 7,711 $ 2,893 $ 10,604 $ 89,780 $ 3,033 $ 92,813 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Attributable to Harvest Per 

Common Share: 

Basic earnings (loss) per share 

Income (loss) from continuing 

operations $ 0.23 $ 0.08 $ 0.31 $ (0.26 ) $ 0.09 $ (0.17 ) 

Discontinued operations — — — 2.90 — 2.90 

 

Net loss attributable to Harvest $ 0.23 $ 0.08 $ 0.31 $ 2.64 $ 0.09 $ 2.73 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted earnings (loss) per share 

Income (loss) from continuing 

operations $ 0.20 $ 0.08 $ 0.28 $ (0.22 ) $ 0.05 $ (0.17 ) 

Discontinued operations — — — 2.45 0.45 2.90 

 

Net loss attributable to Harvest $ 0.20 $ 0.08 $ 0.28 $ 2.23 $ 0.50 $ 2.73 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive Income $ 7,711 $ 2,893 $ 10,604 $ 89,780 $ 3,033 $ 92,813 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. For the three months ended June 30, 2011, this amount was offset by a reclassification from exploration 

expense to impairment of oil and gas properties of $3,335 thousand for amounts that were erroneously classified as exploration expense. 

(b) Represents the reclassification from exploration expense to impairment of oil and gas properties for amounts that were erroneously 

classified as exploration expense. 

(c) Represents changes in fair value of Warrants for the period. Such Warrants were previously classified as equity and were, therefore, not 

marked to market at the end of each reporting period. 

(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

(g) 

(g) 

(h) 
 

S-52 

(d) As a result of the change in fair value of the Warrants, the original discount allocated to the debt was understated; therefore, the additional 

amortization of the discount on debt, which is a component of interest expense, was understated for each period the debt was outstanding. 

(e) The correction in the fair value of the Warrants and its classification as a liability resulted in an increase discount on debt which also 

impacted the resulting loss on extinguishment of debt originally recorded in May 2011 when the debt was retired. 

(f) Income tax effects of the adjustments. 

(g) Relates to previously identified immaterial error. 

(h) Diluted EPS has been adjusted to reflect an error in the calculation of the weighted average common shares outstanding for dilutive EPS 

for the three months ended June 30, 2011. The weighted average common shares utilized for the calculation of diluted EPS was 

erroneously 40,260 thousand rather than 34,039 thousand. 
Table of Contents 

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) 

(dollars in thousands, except per share data) 

 

“As Previously Reported” reflects balances reported in the March 31, 2011, June 30, 2011 and September 30, 2011 Quarterly Report on Form 

10-Q. “As Restated” reflects the final restated balances. 

 

S-53 

 

Nine Months Ended 

September 30, 2011 

Six Months Ended 

June 30, 2011 

Three Months Ended 

March 31, 2011 

 As Previously As As Previously As As Previously As 

 Reported Restated Reported Restated Reported Restated 

Cash Flows From Operating Activities: 

Net income $ 109,223 $ 110,915 $ 97,920 $ 96,719 $ 4,509 $ 267 

Adjustments to reconcile net income to net cash used in operating activities: 

Depletion, depreciation and amortization 1,164 1,164 1,053 1,053 934 934 

Impairment of long-lived assets 4,707 1,440 4,707 1,440 1,440 1,440 

Impairment of oil and gas properties costs — 3,335 — 3,335 — — 

Amortization of debt financing costs 753 753 530 530 270 270 

Amortization of discount on debt 816 2,876 816 2,876 538 2,116 

Gain on sale of assets (103,969 ) (103,969 ) (103,933 ) (103,933 ) — — 

Loss on early extinguishment of debt 7,533 10,983 7,533 10,983 — — 

Net income from unconsolidated equity affiliate (55,216 ) (55,216 ) (36,740 ) (36,740 ) (18,494 ) (18,456 ) 

Share-based compensation charges 3,659 3,659 2,673 2,673 1,114 1,114 

Unrealized (gain) loss on warrant derivative — (8,800 ) — (4,544 ) — 2,516 

Other current liabilities — 425 — 425 — 425 

Changes in operating assets and liabilities: 

Accounts and notes receivables (5,971 ) (5,971 ) (2,887 ) (2,887 ) (3,696 ) (3,696 ) 

Advances to equity affiliate (582 ) — (296 ) — (146 ) — 

Prepaid expenses and other 2,330 2,330 3,061 3,061 2,600 2,600 

Other assets — (876 ) — (62 ) — (34 ) 

Accounts payable – trade 6,558 6,558 8,168 8,168 2,119 2,119 

Accrued expenses (1,533 ) (1,533 ) (2,469 ) (2,469 ) 2,071 2,071 

Accrued interest (1,269 ) (1,665 ) (418 ) (814 ) (925 ) (1,158 ) 

Other long-term liabilities (877 ) (877 ) (701 ) (701 ) 434 434 

Income taxes payable 2,834 2,793 6,061 6,032 211 182 

 

Net Cash Used In Operating 

Activities (29,840 ) (31,676 ) (14,922 ) (14,855 ) (7,021 ) (6,856 ) 

 

Cash Flows From Investing Activities: 

Proceeds from sale of assets 217,833 217,833 217,833 217,833 — — 

Additions of property and equipment (58,474 ) (56,932 ) (28,067 ) (27,900 ) (8,361 ) (8,414 ) 

Additions to assets held for sale (31,422 ) (31,422 ) (31,742 ) (31,742 ) (15,633 ) (15,633 ) 

Proceeds from sale of equity affiliate 1,385 1,385 1,385 1,385 1,273 1,273 

Advances to equity affiliate — (582 ) — (296 ) — (146 ) 

Increase (decrease) in restricted cash — — (7,323 ) (7,323 ) (4,490 ) (4,490 ) 

Investment costs (876 ) — (62 ) — (34 ) — 

 

Net Cash Provided By (Used In) Investing Activities 128,446 130,282 152,024 151,957 (27,245 ) (27,410 ) 

 

Cash Flows From Financing Activities: 

Net proceeds from issuances of common Stock 924 924 416 416 416 416 

Proceeds from long term debt (60,000 ) (60,000 ) (60,000 ) (60,000 ) — — 

Financing costs (189 ) (189 ) (189 ) (189 ) (189 ) (189 ) 

 

Net Cash Provided By (Used In) Financing Activities (59,265 ) (59,265 ) (59,773 ) (59,773 ) 227 227 

 

Net Increase (Decrease) In Cash and Cash Equivalents 39,341 39,341 77,329 77,329 (34,039 ) (34,039 ) 

Cash and Cash Equivalents at Beginning of Period 58,703 58,703 58,703 58,703 58,703 58,703 

 

Cash and Cash Equivalents at End of Period $ 98,044 $ 98,044 $ 136,032 $ 136,032 $ 24,664 $ 24,664 

 

 

 

 

 

 

 

 

 

 

 

 

(a) 

(a) 

(b) 

(c) 

(d) 

(e) 

(i) 

(h) 

(f) 

(i) 

(j) 

(g) 

(h) 

(f) 
Table of Contents 

2011 Consolidated Statements of Cash Flows Corrections: 

 

In addition to the above, we have restated Operating Segments to reflect the errors stated above and (a) reclassify noncontrolling interest 

from United States segment to Venezuela segment, (b) eliminate intrasegment receivables erroneously reported gross of related intrasegment 

payable, and (c) eliminate intrasegment revenues erroneously reported gross of related intrasegment expense. 

 

 

(a) Represents the reclassification from impairment of long-lived assets to impairment of oil and gas properties for amounts that were 

erroneously classified as impairment of long-lived assets. 

(b) As a result of the change in the fair value of the Warrants, the original discount allocated to the debt was understated; therefore, the 

additional amortization of the discount on debt was understated for each period the debt was outstanding. 

(c) The correction in the fair value of the Warrants and its classification as a liability resulted in an increased discount on debt which also 

impacted the resulting loss on extinguishment of debt originally recorded in May 2011 when the debt was retired. 

(d) Relates to previously identified immaterial error. 

(e) Represents changes in fair value of Warrants for the period. Such Warrants were previously classified as equity and were, therefore, not 

marked to market at the end of each reporting period. 

(f) Relates to certain costs improperly classified as an investing activity rather than an operating activity. 

(g) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. 

(h) Relates to the improper classification of Advances to Equity Affiliate as an operating activity rather than an investing activity. 

(i) Relates to income tax payable improperly classified as interest payable. 

(j) Income tax effect of the adjustments and income tax payable improperly classified as interest payable.

 

Nine Months Ended 

September 30, 2011 

Six Months Ended 

June 30, 2011 

Three Months Ended 

March 31, 2011 

 

As Previously 

Reported Adjustments 

As 

Restated 

As Previously 

Reported Adjustments 

As 

Restated 

As Previously 

Reported Adjustments 

As 

Restated 

Segment Income (Loss) Attributable 

to Harvest 

Venezuela $ 41,247 $ — $ 41,247 $ 27,329 $ — $ 27,329 $ 13,214 $ 74 $ 13,288 

Indonesia (4,571 ) (1,097 ) (5,668 ) (3,014 ) — (3,014 ) (1,418 ) — (1,418 ) 

Gabon (1,679 ) (290 ) (1,969 ) (1,059 ) (235 ) (1,294 ) (342 ) (110 ) (452 ) 

Oman (1,589 ) — (1,589 ) (1,045 ) — (1,045 ) (556 ) — (556 ) 

United States (30,270 ) 3,079 (27,191 ) (26,748 ) (966 ) (27,714 ) (6,550 ) (4,198 ) (10,748 ) 

 

Net income (loss) from 

continuing operations 3,138 1,692 4,830 (4,537 ) (1,201 ) (5,738 ) 4,348 (4,234 ) 114 

Discontinued operations 

(Antelope Project) 95,435 — 95,435 95,399 — 95,399 (3,266 ) — (3,266 ) 

 

Net income (loss) 

attributable to Harvest $ 98,573 $ 1,692 $ 100,265 $ 90,862 $ (1,201 ) $ 89,661 $ 1,082 $ (4,234 ) $ (3,152 ) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Relates to a previously identified immaterial error. 

(b) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense and elimination of intrasegment revenue erroneously reported gross of related intrasegment expense. 

(c) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. 

(d) Represents (a) change in fair value of the Warrants for the reporting period, (b) understatement of interest expense and debt discount 

which resulted from the improper classification of the Warrants, (c) lease maintenance costs erroneously capitalized as oil and gas 

properties rather than expensed to exploration expense, and (d) for the periods ended June 30, 2011 and September 30, 2011, changes in 

the loss on extinguishment of debt due to the correction in discount on debt related to the improper classification of the Warrants. 

(a) 

(b) 

(c) 

(d) 
 

 

 

S-54 

 Three Months Ended September 30, 2011 Three Months Ended June 30, 2011 

 

As Previously 

Reported Adjustments 

As 

Restated 

As Previously 

Reported Adjustments 

As 

Restated 

Segment Income (Loss) Attributable to Harvest 

Venezuela $ 13,918 $ — $ 13,918 $ 14,115 $ (74 ) $ 14,041 

Indonesia (1,557 ) (1,097 ) (2,654 ) (1,596 ) — (1,596 ) 

Gabon (620 ) (55 ) (675 ) (717 ) (125) (842 ) 

Oman (544 ) — (544 ) (489 ) — (489 ) 

United States (3,522 ) 4,045 523 (20,198 ) 3,232 (16,966 ) 

 

Net income (loss) from continuing 

operations 7,675 2,893 10,568 (8,885 ) 3,033 (5,852 ) 

Discontinued operations (Antelope Project) 36 — 36 98,665 — 98,665 

 

Net income (loss) attributable to Harvest $ 7,711 $ 2,893 $ 10,604 $ 89,780 $ 3,033 $ 92,813 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Relates to a previously identified immaterial error. 

(b) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense and elimination of intrasegment revenue erroneously reported gross of related intrasegment expense. 

(c) Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than 

expensed as exploration expense. 

(d) Represents (a) changes in fair value of the Warrants for the reporting period, (b) understatement of interest expense and debt discount 

which resulted from the improper classification of the Warrants, (c) lease maintenance costs erroneously capitalized as oil and gas 

properties rather than expensed to exploration expense, and (d) for the periods ended June 30, 2011 and September 30, 2011, changes in 

the loss on extinguishment of debt due to the correction in discount on debt related to the improper classification of the Warrants. 

(a) 

(b) 

(c) 

(d) 
Table of Contents 

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

The following tables summarize our proved reserves, drilling and production activity, and financial operating data at the end of each year. 

Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; 

capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized 

measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. 

 

 

 

 

 

 

 

S-55 

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

 Oman Gabon Indonesia 

United States 

and Other Total 

Year Ended December 31, 2012 

Unproved exploration costs $ 6,741 $ 30,386 $ 4,078 $ — $ 41,205 

 

 $ 6,741 $ 30,386 $ 4,078 $ — $ 41,205 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2011 Restated* 

Unproved acquisition costs $ — $ — $ 3,660 $ — $ 3,660 

Unproved exploration costs 10,901 46,107 34,596 — 91,604 

 

 $ 10,901 $ 46,107 $ 38,256 $ — $ 95,264 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2010 Restated* 

Unproved acquisition costs $ — $ — $ 2,703 $ — $ 2,703 

Unproved exploration costs 1,698 2,450 10,468 2,890 17,506 

 

 $ 1,698 $ 2,450 $ 13,171 $ 2,890 $ 20,209 

 

 

 

 

 

 

 

 

 

 

* See Note 3 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements for additional information. 

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

 Oman Gabon Indonesia 

United States 

and Other Total 

Year Ended December 31, 2012 

Unproved property costs $ — $ 73,233 $ 5,220 $ — $ 78,453 

Oilfield Inventories — 3,209 130 — 3,339 

 

 $ — $ 76,442 $ 5,350 $ — $ 81,792 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2011 Restated* 

Unproved property costs $ 5,084 $ 46,447 $ 5,195 $ 2,900 $ 59,626 

Oilfield Inventories 209 2,480 140 — 2,829 

 

 $ 5,293 $ 48,927 $ 5,335 $ 2,900 $ 62,455 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2010 Restated* 

Unproved property costs $ 4,216 $ 8,171 $ 9,605 $ 6,427 $ 28,419 

Oilfield Inventories — — 1,435 3,965 5,400 

 

 $ 4,216 $ 8,171 $ 11,040 $ 10,392 $ 33,819 

 

 

 

 

 

 

 

 

 

 

(a) Drilling activities were completed in September 2011 for Dussafu Ruche Marin-1 (“DRM-1”) exploratory well on the Dussafu PSC. 

DRM-1 well costs of $39.2 million were suspended pending further exploration and development activities. Exploration activities 

continued in 2012 with the acquisition of additional seismic and the spud of our second exploration well, DTM-1, on November 19, 2012. 

* See Note 3 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements for additional information. 

(a) 
Table of Contents 

We regularly evaluate our unproved properties to determine whether impairment has occurred. We have excluded from amortization our 

interest in unproved properties and the cost of uncompleted exploratory activities. The principal portion of such costs is expected to be included 

in amortizable costs during the next two to three years. 

Unproved property costs at December 31, 2012 relates to two on-going projects. Costs incurred by year are as follows (in thousands): 

 

 

 

 

 

Estimating oil and gas reserves is a very complex process requiring significant subjective decisions in the evaluation of all available 

geological, engineering and economic data for each reservoir. This data may change substantially over time as a result of numerous factors 

such as production history, additional development activity and continual reassessment of the viability of production under various economic 

and political conditions. Consequently, material upward or downward revisions to existing reserve estimates may occur from time to time; 

although, every reasonable efforts is made to ensure that reported results are the most accurate assessment available. We ensure that the data 

provided to our external independent experts, and their interpretation of that data, corresponds with our development plans and management’s 

assessment of each reservoir. The significance of subjective decisions required and variances in available data make estimates generally less 

precise than other estimates presented in connection with financial statement disclosures. 

We measure and disclose our oil and gas reserves in accordance with the provisions of the SEC’s Modernization of Oil and Gas 

Reporting and ASC 932, “Extractive Activities – Oil and Gas” (“ASC 932”). 

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 for, management reviews and review of the independent third party reserves report. The 

technical employee responsible for overseeing the 

 

S-56 

 Total 2012 2011 2010 Prior 

 (RESTATED) (RESTATED) (RESTATED) (RESTATED) 

Property acquisition costs $ 12,463 $ — $ 3,660 $ 2,703 $ 6,100 

Exploration costs 65,990 27,416 34,576 3,694 304 

 

Total unproved property costs $ 78,453 $ 27,416 $ 38,236 $ 6,397 $ 6,404 

 

 

 

 

 

 

 

 

 

 

* See Note 3 – Summary of Significant Accounting Policies – Restatement of Prior Period Financial Statements for additional information. 

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

 Year Ended December 31, 

 2012 

2011 

(RESTATED) 

Revenue: 

Oil and natural gas revenues $ — $ 6,488 

Expenses: 

Operating, selling and distribution expenses and taxes other 

than on income — 3,154 

Exploration expense 9,068 12,565 

Impairment of oil and gas properties costs 9,312 3,335 

Dry hole costs 5,617 49,676 

Depletion — 811 

 

Total expenses 23,997 69,541 

 

Results of operations from oil and natural gas producing activities $ (23,997 ) $ (63,053 ) 

 

 

 

 

TABLE IV – Quantities of Oil and Natural Gas Reserves 
Table of Contents 

process for preparation of the reserves estimates has a Bachelor of Arts in Engineering Science, a Master of Science in Petroleum Engineering, 

has more than 25 years of experience in reservoir engineering and is a member of the Society of Petroleum Engineers. 

All reserve information in this report is based on estimates prepared by Ryder Scott Company L.P. (“Ryder Scott”), independent 

petroleum engineers. The technical personnel responsible for preparing the reserve estimates at Ryder Scott meet the requirements regarding 

qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas 

Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is an independent firm of petroleum engineers, 

geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis. 

See the following section Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela 

Equity Affiliate as of December 31, 2012, 2011 and 2010, TABLE IV – Quantities of Oil and Natural Gas Reserves for Petrodelta’s reserves. 

The table shown below represents our interests in the United States. On May 17, 2011, we closed the transaction to sell our Antelope 

Project. The sale had an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflected 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. The Antelope Project 

has been classified as discontinued operations. 

 

 

The standardized measure of discounted future net cash flows is presented in accordance with the provisions of the accounting standard 

on disclosures about oil and gas producing activities. In preparing this data, assumptions and estimates have been used, and we caution against 

viewing this information as a forecast of future economic conditions. 

Future cash inflows are estimated by applying the average price during the 12-month period, determined as an unweighted arithmetic 

average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the 

contract, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and 

development costs to 

 

S-57 

 2011 2010 

 

Oil 

and NGL 

(MBbls) 

Gas 

(MMcf) 

Oil 

and 

NGL 

(MBbls) 

Gas 

(MMcf) 

Proved Reserves 

United States 

Proved Reserves at January 1 3,515 6,492 226 1,126 

Revisions — — 147 914 

Acquisitions — — 15 12 

Sales of reserves in place (3,454 ) (6,155 ) — — 

Extensions — — 3,267 4,863 

Production (61 ) (337 ) (140 ) (423 ) 

 

Proved Reserves at December 31 — — 3,515 6,492 

 

 

 

 

 

 

 

 

As of December 31 

United States 

Proved 

Developed — — 659 2,476 

Undeveloped — — 2,856 4,016 

 

Total Proved — — 3,515 6,492 

 

 

 

 

 

 

 

 

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

Quantities 
Table of Contents 

determine pre-tax cash inflows. Future income taxes are estimated by applying the year-end statutory tax rates to the future pre-tax cash 

inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant 

future net cash inflows are discounted using a ten percent discount rate. 

The table shown below represents our net interest at December 31, 2011 and 2010. 

 

 

 

 

S-58 

 United States 

 December 31, 

 2011 2010 

 (in thousands) 

Future cash inflows from sales of oil and gas $ — $ 250,712 

Future production costs — (75,602 ) 

Future development costs — (62,246 ) 

Future income tax expenses — (37,262 ) 

 

Future net cash flows — 75,602 

Effect of discounting net cash flows at 10% — (45,632 ) 

 

Standardized measure of discounted future net cash flows $ — $ 29,970 

 

 

 

 

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

 United States 

 December 31, 

 2011 2010 

 (in thousands) 

Standardized Measure at January 1 $ 29,970 $ 4,723 

Sales of oil and natural gas, net of related costs (3,334 ) (8,850 ) 

Revisions to estimates of proved reserves: 

Net changes in prices, net of production costs 26,140 2,766 

Quantities — 3,734 

Purchase and sale of reserves in place (45,627 ) 387 

Extensions, discoveries and improved recovery, net of future costs — 36,211 

Accretion of discount — 535 

Development costs incurred 2,784 2,427 

Changes in estimated development costs — (1,256 ) 

Net change in income taxes (9,933 ) (10,707 ) 

 

Standardized Measure at December 31 $ — $ 29,970 

 

 

 

 
Table of Contents 

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

The following tables summarize the proved reserves, drilling and production activity, and financial operating data at the end of each year 

for our net 32 percent interest in Petrodelta. Tables I through III provide historical cost information pertaining to costs incurred in exploration, 

property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated 

proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in 

estimated discounted future net cash flows. 

Petrodelta (32 percent ownership) is accounted for under the equity method, and has been included at its ownership interest in the 

consolidated financial statements and the following Tables based on a year ending December 31 and, accordingly, results of operations for oil 

and natural gas producing activities in Venezuela reflect the year ended December 31, 2012, 2011 and 2010. 

 

 

 

 

 

 

 

 

S-59 

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

 Year ended December 31, 

 2012 2011 2010 

Development costs $ 66,342 $ 45,364 $ 29,976 

 

 

 

 

 

 

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

 Year ended December 31, 

 2012 2011 2010 

Proved property costs $ 250,259 $ 184,640 $ 139,702 

Unproved property costs — 1,434 1,365 

Oilfield inventories 28,992 13,764 9,630 

Less accumulated depletion and impairment (81,629 ) (57,346 ) (43,856 ) 

 

 $ 197,622 $ 142,492 $ 106,841 

 

 

 

 

 

 

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

 Year Ended December 31, 

 2012 2011 2010 

Revenue: 

Oil and natural gas revenues $ 404,577 $ 360,222 $ 194,423 

Royalty (132,802 ) (118,339 ) (65,500 ) 

 

 271,775 241,883 128,923 

Expenses: 

Operating, selling and distribution expenses and taxes 

other than on income 149,082 114,835 22,359 

Depletion 24,284 17,531 12,387 

Income tax expense 49,205 54,759 47,089 

 

Total expenses 222,571 187,125 81,835 

 

Results of operations from oil and natural gas producing 

activities $ 49,204 $ 54,758 $ 47,088 

 

 

 

 

 

 

(1) Expenses include operating expenses, production taxes and Windfall Profits Tax. Net to our 32 percent interest, Windfall Profits Tax for 

December 31, 2012 was $93.2 million (2011: $76.0 million, 2010: $4.5 million). 

(1) 
Table of Contents 

We measure and disclose our oil and gas reserves in accordance with the provisions of the SEC’s Modernization of Oil and Gas 

Reporting and ASC 932, “Extractive Activities – Oil and Gas” (“ASC 932”). 

Petrodelta is producing from, and continuing to develop, the Petrodelta Fields. Petrodelta has both developed and undeveloped oil and gas 

reserves identified in all six fields. Petrodelta produces the fields in accordance with a business plan originally defined by its Conversion 

Contract executed in late 2007. Proved Undeveloped (“PUD”) oil and gas reserves are drilled in accordance with Petrodelta’s business plan, but 

can be revised where drilling results indicate a change is warranted. 

During 2012, Petrodelta drilled and completed 12 production wells. Six of the wells were previously identified Proved Undeveloped 

(“PUD”) locations and six wells were previously classified Probable, Possible or undefined locations. In 2012, an additional ten PUD locations 

were identified through drilling activity; however, ten PUD locations which are scheduled to be drilled five years after the wells were originally 

identified have been reclassified as Probable reserves. At December 31, 2012, Petrodelta had a total of 157 PUD (22.9 MMBOE) locations 

identified. Since the implementation of its 2007 business plan, Petrodelta has drilled 67 gross production wells (2008 nine wells [1.4 

MMBOE], 2009 15 wells [2.0 MMBOE], 2010 16 wells [2.0 MMBOE], 2011 15 wells [2.1 MMBOE], and 2012 12 wells [2.2 MMBOE]) 

which have moved to the proved developed producing (“PDP”) category. Of these 67 locations drilled since 2008, 33 (5.9 MMBOE) represent 

the movements of PUD locations to PDP locations. The other 34 new producing wells (3.8 MMBOE) were previously classified Probable, 

Possible or un-defined. 

Petrodelta has a track record of identifying, executing and converting its PUD locations to PDP locations in accordance with the business 

plan defined by the conversion contract executed in 2007 and subsequent updates. However, the timing and pace of the development is 

controlled by the majority owner, PDVSA through CVP, although we have substantial negative control provisions as a noncontrolling interest 

shareholder. In 2010, Petrodelta submitted a revised business plan to PDVSA which substantially increases the total projected drilling activity 

and production volumes compared to the 2007 business plan, but which is otherwise consistent with the 2007 business plan. The 2010 business 

plan, as approved by PDVSA, contemplates sustained drilling activities through the year 2024 to fully develop the El Salto and Temblador 

fields. As a noncontrolling interest shareholder in Petrodelta, HNR Finance has limited ability to control the development plans that are 

periodically prepared and/or approved by the Venezuelan government. Since this constraint represents a hindrance to development not 

experienced by typical operations, the PUD locations which are now scheduled to be drilled five years after they were originally identified have 

been reclassified as Probable reserves. 

Proved undeveloped reserves of 22.9 MMBOE from 157 gross PUD locations are all scheduled to be drilled within the period from 2013 

to 2016 and within five years from when these locations were first identified. 

All above MMBOE represent our net 32 percent interest, net of a 33.33 percent royalty. 

 

S-60 

TABLE IV – Quantities of Oil and Natural Gas Reserves 
Table of Contents 

The tables shown below represent HNR Finance’s 40 percent ownership interest and our net 32 percent ownership interest, both net of a 

33.33 percent royalty, in Venezuela in each of the years. 

 

 

S-61 

 HNR Finance 

Minority 

Interest in 

Venezuela 

32% 

Net Total 

Proved Reserves-Crude oil, condensate, and natural gas liquids 

(MBbls) 

As of December 31, 2012 

Proved Reserves at January 1, 2012 48,332 (9,667 ) 38,665 

Revisions (3,941 ) 788 (3,153 ) 

Extensions 2,283 (456 ) 1,827 

Production (3,513 ) 703 (2,810 ) 

 

Proved Reserves at end of the year 43,161 (8,632 ) 34,529 

 

 

 

 

 

 

As of December 31, 2012 

Proved 

Developed 15,607 (3,121 ) 12,486 

Undeveloped 27,554 (5,511 ) 22,043 

 

Total Proved 43,161 (8,632 ) 34,529 

 

 

 

 

 

 

As of December 31, 2011 

Proved Reserves at January 1, 2011 52,105 (10,421 ) 41,684 

Revisions (10,829 ) 2,166 (8,663 ) 

Extensions 10,093 (2,019 ) 8,074 

Production (3,037 ) 607 (2,430 ) 

 

Proved Reserves at end of the year 48,332 (9,667 ) 38,665 

 

 

 

 

 

 

As of December 31, 2011 

Proved 

Developed 17,147 (3,430 ) 13,717 

Undeveloped 31,185 (6,237 ) 24,948 

 

Total Proved 48,332 (9,667 ) 38,665 

 

 

 

 

 

 

As of December 31, 2010 

Proved Reserves at January 1, 2010 47,419 (9,483 ) 37,936 

Revisions (230 ) 45 (185 ) 

Extensions 7,199 (1,440 ) 5,759 

Production (2,283 ) 457 (1,826 ) 

 

Proved Reserves at end of the year 52,105 (10,421 ) 41,684 

 

 

 

 

 

 

As of December 31, 2010 

Proved 

Developed 16,342 (3,268 ) 13,074 

Undeveloped 35,763 (7,153 ) 28,610 

 

Total Proved 52,105 (10,421 ) 41,684 

 

 

 

 

 

 
Table of Contents 

 

The standardized measure of discounted future net cash flows is presented in accordance with the provisions of the accounting standard 

on disclosures about oil and gas producing activities. In preparing this data, assumptions and estimates have been used, and we caution against 

viewing this information as a forecast of future economic conditions. 

Future cash inflows are estimated by an applying the average price during the 12-month period, determined as an unweighted arithmetic 

average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the 

contract, to the estimated future production of year-end proved reserves. Our average prices used were $89.77 per barrel for oil for the El Salto 

field and $100.41 per barrel 

 

S-62 

 HNR Finance 

Minority 

Interest in 

Venezuela 

32% 

Net Total 

Proved Reserves-Natural gas (MMcf) 

As of December 31, 2012 

Proved Reserves at January 1, 2012 34,800 (6,960 ) 27,840 

Revisions (4,952 ) 991 (3,961 ) 

Extensions 391 (78 ) 313 

Production (1,227 ) 245 (982 ) 

 

Proved Reserves at end of the year 29,012 (5,802 ) 23,210 

 

 

 

 

 

 

As of December 31, 2012 

Proved 

Developed 22,383 (4,477 ) 17,906 

Undeveloped 6,629 (1,325 ) 5,304 

 

Total Proved 29,012 (5,802 ) 23,210 

 

 

 

 

 

 

As of December 31, 2011 

Proved Reserves at January 1, 2011 62,568 (12,513 ) 50,055 

Revisions (29,111 ) 5,822 (23,289 ) 

Extensions 2,627 (526 ) 2,101 

Production (1,284 ) 257 (1,027 ) 

 

Proved Reserves at end of the year 34,800 (6,960 ) 27,840 

 

 

 

 

 

 

As of December 31, 2011 

Proved 

Developed 25,364 (5,073 ) 20,291 

Undeveloped 9,436 (1,887 ) 7,549 

 

Total Proved 34,800 (6,960 ) 27,840 

 

 

 

 

 

 

As of December 31, 2010 

Proved Reserves at January 1, 2010 62,710 (12,542 ) 50,168 

Revisions (843 ) 169 (674 ) 

Extensions 2,192 (438 ) 1,754 

Production (1,491 ) 298 (1,193 ) 

 

Proved Reserves at end of the year 62,568 (12,513 ) 50,055 

 

 

 

 

 

 

As of December 31, 2010 

Proved 

Developed 22,850 (4,569 ) 18,281 

Undeveloped 39,718 (7,944 ) 31,774 

 

Total Proved 62,568 (12,513 ) 50,055 

 

 

 

 

 

 

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

Quantities 
Table of Contents 

for the other fields, and $1.54 per Mcf for gas. Future cash inflows were reduced by estimated future production and development costs to 

determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash 

inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant 

future net cash inflows are discounted using a ten percent discount rate. 

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

 

 

 

S-63 

 HNR Finance 

Minority 

Interest in 

Venezuela Net Total 

 (in thousands) 

December 31, 2012 

Future cash inflows from sales of oil and gas $ 4,104,602 $ (820,920 ) $ 3,283,682 

Future production costs (1,992,109 ) 398,421 (1,593,688 ) 

Future development costs (364,986 ) 72,997 (291,989 ) 

Future income tax expenses (769,578 ) 153,916 (615,662 ) 

 

Future net cash flows 977,929 (195,586 ) 782,343 

Effect of discounting net cash flows at 10% (415,711 ) 83,142 (332,569 ) 

 

Standardized measure of discounted future net cash flows $ 562,218 $ (112,444 ) $ 449,774 

 

 

 

 

 

 

December 31, 2011 

Future cash inflows from sales of oil and gas $ 4,862,351 $ (972,470 ) $ 3,889,881 

Future production costs (2,400,980 ) 480,196 (1,920,784 ) 

Future development costs (260,896 ) 52,179 (208,717 ) 

Future income tax expenses (1,025,295 ) 205,059 (820,236 ) 

 

Future net cash flows 1,175,180 (235,036 ) 940,144 

Effect of discounting net cash flows at 10% (496,127 ) 99,225 (396,902 ) 

 

Standardized measure of discounted future net cash flows $ 679,053 $ (135,811 ) $ 543,242 

 

 

 

 

 

 

December 31, 2010 

Future cash inflows from sales of oil and gas $ 3,748,419 $ (749,684 ) $ 2,998,735 

Future production costs (870,498 ) 174,100 (696,398 ) 

Future development costs (296,744 ) 59,349 (237,395 ) 

Future income tax expenses (1,241,452 ) 248,290 (993,162 ) 

 

Future net cash flows 1,339,725 (267,945 ) 1,071,780 

Effect of discounting net cash flows at 10% (608,526 ) 121,705 (486,821 ) 

 

Standardized measure of discounted future net cash flows $ 731,199 $ (146,240 ) $ 584,959 

 

 

 

 

 

 

(1) Future production costs include operating costs, production taxes and Windfall Profits Tax. For 2012, Windfall Profits Tax equates to 

$1.5 million, or 74 percent, of the $2.0 million of discounted future production costs. 

(2) Future production costs include operating costs, production taxes and Windfall Profits Tax. For 2011, Windfall Profits Tax equates to 

$1.6 million, or 68 percent, of the $2.4 million of discounted future production costs. 

(1) 

(2) 
Table of Contents 

 

 

S-64 

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

 2012 

Net Venezuela 

2011 2010 

Standardized Measure at January 1 $ 543,242 $ 584,959 $ 400,295 

Sales of oil and natural gas, net of related costs (122,693 ) (127,049 ) (107,689 ) 

Revisions to estimates of proved reserves: 

Net changes in prices, net of production taxes (44,084 ) (108,785 ) 190,119 

Quantities (91,770 ) (221,510 ) (18,284 ) 

Extensions, discoveries and improved recovery, net of future costs 52,535 201,203 248,917 

Accretion of discount 100,028 113,310 78,403 

Net change in income taxes 86,445 77,006 (181,186 ) 

Development costs incurred 66,342 45,364 29,965 

Changes in estimated development costs (131,356 ) (13,564 ) (29,465 ) 

Timing differences and other (8,915 ) (7,692 ) (26,116 ) 

 

Standardized Measure at December 31 $ 449,774 $ 543,242 $ 584,959 

 

 

 

 

 

 
Table of Contents 

SIGNATURES 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to 

be signed on its behalf by the undersigned, thereunto duly authorized. 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the 2 of 

May 2013, on behalf of the registrant and in the capacities indicated: 

 

 

S-65 

 HARVEST NATURAL RESOURCES, INC. 

 (Registrant) 

Date: May 2, 2013 By: /s/ James A. Edmiston 

 James A. Edmiston 

 Chief Executive Officer 

Signature Title 

/s/ James A. Edmiston Director, President and Chief Executive Officer (Principal 

James A. Edmiston Executive Officer) 

/s/ Stephen C. Haynes Vice President – Finance, Chief Financial Officer and 

Treasurer (Principal Financial Officer and Principal 

Accounting Officer) 

Stephen C. Haynes 

 

 

/s/ Stephen D. Chesebro’ Chairman of the Board and Director 

Stephen D. Chesebro’ 

/s/ Igor Effimoff Director 

Igor Effimoff 

/s/ H. H. Hardee Director 

H. H. Hardee 

/s/ R. E. Irelan Director 

R. E. Irelan 

/s/ Patrick M. Murray Director 

Patrick M. Murray 

/s/ J. Michael Stinson Director 

J. Michael Stinson 

nd 
Table of Contents 

SCHEDULE II 

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES 

Valuation and Qualifying Accounts 

(in thousands) 

 

 

 

S-66 

 Additions 

 

Balance at 

Beginning 

of Year 

Charged to 

Income 

Charged to 

Other 

Accounts* 

Deductions 

From 

Reserves 

Balance at 

End of 

Year 

At December 31, 2012 

Amounts deducted from applicable assets 

Deferred tax valuation allowance $ 53,116 $ 15,303 $ — $ — $ 68,419 

Investment valuation allowance 1,350 — — — 1,350 

At December 31, 2011 (as RESTATED) 

Amounts deducted from applicable assets 

Deferred tax valuation allowance $ 46,905 $ 6,211 $ — $ — $ 53,116 

Investment valuation allowance 1,350 — — — 1,350 

At December 31, 2010 (as RESTATED) 

Amounts deducted from applicable assets 

Deferred tax valuation allowance $ 25,763 $ 21,142 $ — $ — $ 46,905 

Investment valuation allowance 1,350 — — — 1,350 

* Amounts charged to other accounts include net operating losses and income tax credits. 
EXHIBIT 21.1 

HARVEST NATURAL RESOURCES, INC. 

LIST OF SUBSIDIARIES 

 

The names of certain subsidiaries have been omitted in reliance upon Item 601(b)(21)(ii) of Regulation S-K. 

 

Name 

Jurisdiction 

of Incorporation 

Harvest-Vinccler Dutch Holding B.V.* The Netherlands 

HNR Energia B.V. The Netherlands 

* All subsidiaries are wholly-owned by Harvest Natural Resources, Inc., except Harvest-Vinccler Dutch Holding B.V. which is indirectly 

owned 80 percent by Harvest Natural Resources, Inc.
EXHIBIT 23.1 

HARVEST NATURAL RESOURCES, INC. 

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-167887, 333-134630, 333-115841, 

and 333-85900) of Harvest Natural Resources, Inc. of our report dated May 2, 2013 relating to the financial statements, financial statement 

schedule and the effectiveness of internal control over financial reporting, which appears in this Annual Report on Form 10-K. 

/s/ PricewaterhouseCoopers LLP 

Houston, Texas 

May 2, 2013 
EXHIBIT 23.2 

HARVEST NATURAL RESOURCES, INC. 

INDEPENDENT PETROLEUM ENGINEERS’ CONSENT 

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-167887, 333-134630, 333-115841, 

and 333-85900) of Harvest Natural Resources, Inc. of our reports dated February 15, 2013 relating to the reserve reports, which appears in this 

Annual Report on Form 10-K. 

/s/ Ryder Scott Company, L.P. 

Denver, Colorado 

May 2, 2013 
EXHIBIT 23.3 

HARVEST NATURAL RESOURCES, INC. 

CONSENT OF INDEPENDENT ACCOUNTANTS 

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-167887, 333-134630, 333-115841, 

and 333-85900) of Harvest Natural Resources, Inc. of our report dated March 1, 2013 relating to the financial statements of Petrodelta, S. A. at 

December 31, 2012 presented in accordance with International Reporting Standards, which appears in this Annual Report on Form 10-K. 

/s/ PGFA Perales, Pistone & Asociados 

Caracas, Venezuela 

May 2, 2013 
EXHIBIT 31.1 

I, James A. Edmiston, certify that: 

 

 

 

 

 

 

 

 

 

 

 

Date: May 2, 2013 

 

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

 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact 

necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with 

respect to the period covered by this report; 

 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all 

material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in 

this report; 

 

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures 

(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange 

Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: 

 

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed 

under our supervision, to ensure that material information relating to the registrant, including its consolidated 

subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is 

being prepared; 

 

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be 

designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the 

preparation of financial statements for external purposes in accordance with generally accepted accounting principles; 

 

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our 

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by 

this report based on such evaluation; and 

 

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the 

registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has 

materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; 

and 

 

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over 

financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing 

the equivalent functions): 

 

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial 

reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and 

report financial information; and 

 

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the 

registrant’s internal control over financial reporting. 

/s/ James A. Edmiston 

James A. Edmiston 

President and Chief Executive Officer 
EXHIBIT 31.2 

I, Stephen C. Haynes, certify that: 

 

 

 

 

 

 

 

 

 

 

 

Date: May 2, 2013 

 

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

 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact 

necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with 

respect to the period covered by this report; 

 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all 

material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in 

this report; 

 

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures 

(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange 

Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: 

 

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed 

under our supervision, to ensure that material information relating to the registrant, including its consolidated 

subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is 

being prepared; 

 

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be 

designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the 

preparation of financial statements for external purposes in accordance with generally accepted accounting principles; 

 

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our 

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by 

this report based on such evaluation; and 

 

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the 

registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has 

materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; 

and 

 

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over 

financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing 

the equivalent functions): 

 

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial 

reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and 

report financial information; and 

 

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the 

registrant’s internal control over financial reporting. 

/s/ Stephen C. Haynes 

Stephen C. Haynes 

Vice President – Finance, Chief Financial Officer and 

Treasurer 
EXHIBIT 32.1 

Accompanying Certificate 

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

and 18 U.S.C. Section 1350 

Not Filed Pursuant to the Securities Exchange Act of 1934 

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

This report on Form 10-K of Harvest Natural Resources, Inc. for the period ended December 31, 2012 and filed with the Securities and 

Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities 

Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of 

operations of the Company. 

 

Date: May 2, 2013 By: /s/ James A. Edmiston 

 James A. Edmiston 

 President and Chief Executive Officer 
EXHIBIT 32.2 

Accompanying Certificate 

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

and 18 U.S.C. Section 1350 

Not Filed Pursuant to the Securities Exchange Act of 1934 

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

This report on Form 10-K of Harvest Natural Resources, Inc. for the period ended December 31, 2012 and filed with the Securities and 

Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities 

Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of 

operations of the Company. 

 

Date: May 2, 2013 /s/ Stephen C. Haynes 

 Stephen C. Haynes 

 Vice President – Finance, Chief Financial Officer and Treasurer 

 
Exhibit 99.1 

PETRODELTA, S.A. 

(SUBSIDIARY OF CORPORACIÓN 

VENEZOLANA DEL PETRÓLEO, S.A—CVP) 

FINANCIAL STATEMENTS 

FOR THE YEARS ENDED 

DECEMBER 31, 2012, 2011 AND 2010 

AND 

INDEPENDENT AUDITOR’S REPORT 
PETRODELTA, S.A. 

(Subsidiary of Corporación Venezolana del Petróleo, S.A.—CVP) 

Index 

 

 Pages 

Independent Auditor’s Report 1-2 

Statements of financial position 3 

Statements of comprehensive income 4 

Statements of changes in equity 5-6 

Statements of cash flow 7 

Notes to the financial statements 

(1) Reporting entity 8 

(2) Basis of preparation 10 

(3) Summary of significant accounting policies 12 

(4) Exchange agreement with the Central Bank of Venezuela (BCV) 26 

(5) Determination of fair values 28 

(6) Financial risk management 29 

(7) Taxes and Royalties 30 

(8) Property, plant and equipment, net 38 

(9) Prepaid expenses and other assets 40 

(10) Inventories 40 

(11) Accounts receivable 41 

(12) Cash and cash equivalents 41 

(13) Equity 42 

(14) Provisions 45 

(15) Accruals and other Liabilities 48 

(16) Accounts payable 48 

(17) Operational expenses 49 

(18) Financial income and expenses 49 

(19) Financial instruments 50 

(20) Commitments and contingencies 52 

(21) Related party transactions 53 

(22) Collective labor agreement 56 

(23) Laws, resolutions and legal contributions 58 

(24) Subsequent events 63 

(25) Supplementary Information on Oil and Gas Exploration and Production Activities (unaudited) 64 
I NDEPENDENT A UDITOR ’ S R EPORT 

To the Stockholders and Board of Director of 

P ETRODELTA , S.A. 

R EPORT ON THE F INANCIAL S TATEMENTS 

We have audited the accompanying financial statements of P ETRODELTA , S.A. (a subsidiary 60% owned by Corporacion Venezolana del 

Petróleo, S.A. CVP), which comprise the statements of financial position as at December 31, 2012, 2011, and 2010, and the statements of 

comprehensive income, statements of changes in equity, and statements of cash flows for the years then ended, and a summary of significant 

accounting policies and other explanatory information. 

M ANAGEMENT ’ S R ESPONSIBILITY FOR THE F INANCIAL S TATEMENTS 

Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial 

Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of financial statements that 

are free from material misstatement, whether due to fraud or error. 

A UDITOR ’ S R ESPONSIBILITY 

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with 

auditing standards generally accepted in the United States of America. Those standards require that we comply with ethical requirements and 

plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement. 

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The 

procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial 

statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s 

preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but 

not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the 

appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the 

overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a 

basis for our audit opinion. 
O PINION 

In our opinion, the financial statements present fairly, in all material respects, the financial position of Petrodelta, S.A. as at December 31, 

2012, 2011, and 2010, and its financial performance and its cash flows for the year then ended in accordance with International Financial 

Reporting Standards. 

E MPHASIS OF MATTER 

Without qualifying our opinion as indicated in Note 21 to the financial statements, the Company belongs to a group of related companies and 

conducts transactions and maintains balances for significant amounts with other members of the group, with significant effects on the results of 

its operations and financial position. Because of those relationships, these transactions may have taken place on terms other than those that 

would characterize transactions between unrelated companies. 

Without qualifying our opinion, as explained in Note 21, during the years ended December 31, 2012 and 2011, the Company recorded 

revenues, unbilled, for the sale of crude oil in the amount of US$.404,619 thousands (Bs.1,739,862 thousands) and US$.67,092 thousands 

(Bs.288,496 thousands), respectively, corresponding to the production of crude of the Campo El Salto, whose price indexed to crude Boscan 

type is not contemplated in the Agreement of Purchase and Sale of Oil originally signed between the Company and PDVSA Petroleo, S.A. As 

of December 31, 2012 and 2011, the Company has accounts receivable of US$.352,721 thousands and US$.50,772 thousands (Bs.1,516,704 

thousands and Bs.218,319 thousands), respectively, for the delivery of such crude. The Company and PDVSA Petroleo, S.A. are in the process 

of approval to include the pricing formula established and agreed to this crude, amend the contract, and start the billing process. 

Without qualifying our opinion, as indicated in Note 21, from April 2011 the Company set the price of US$.70 as a maximum price for the 

calculation and accounting of the royalties instead of the sale price of barrel of oil as had been calculated and recorded in previous accounting 

periods, based on the Decree No.8163 dated 18 April 2011 which creates the Special Tax on Extraordinary Prices and Exorbitant Prices in the 

International oil Market. Have registered in accordance with the procedures followed in previous years, revenues from crude sales and royalty 

expense for the year ended December 31, 2011, have increased in thousands US$.76,966 (Bs.330,952). This accounting procedure has no effect 

on Company net income. 

Por PGFA PERALES, PISTONE & ASOCIADOS 

José G. Perales S. 

C.P.C. No 9.578 

March 1, 2013 

Valencia, Venezuela. 

 

2 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Statements of Financial Position 

(Expressed in thousands) 

 

The accompanying notes (1 to 25) are an integral part of these financial statements. 

 

3 

 December 31, 

 Note 2012 2011 2010 2012 2011 2010 

 (U.S. Dollars) (Bolivars) 

Assets 

Property, plant and equipment, net 8 538,351 410,165 321,816 2,314,912 1,763,709 1,383,809 

Deferred income tax 7 - f 138,492 155,062 60,205 595,516 666,767 258,881 

Recoverable tax credits 7 - k 29,721 17,239 8,072 127,801 74,129 34,710 

 

Total non-current assets 706,564 582,466 390,093 3,038,229 2,504,605 1,677,400 

 

Prepaid expenses and other assets 9 1,161 523 407 4,993 2,248 1,750 

Inventories 10 77,637 36,794 24,997 333,839 158,214 107,487 

Accounts receivable 11 1,313,302 922,788 506,356 5,647,202 3,967,991 2,177,331 

Cash and cash equivalents 12 3,335 2,342 3,465 14,336 10,071 14,900 

 

Total current assets 1,395,435 962,447 535,225 6,000,370 4,138,524 2,301,468 

 

Total assets 2,101,999 1,544,913 925,318 9,038,599 6,643,129 3,978,868 

 

 

 

 

 

 

 

 

 

 

 

 

Total equity 13 760,274 674,281 472,371 3,269,176 2,899,407 2,031,195 

 

Liabilities 

Provision for asset retirement costs 14 70,425 41,518 29,798 302,828 178,527 128,131 

Provision for retirement and other benefits 14 22,671 11,550 8,439 97,486 49,666 36,288 

Deferred income tax 7 - f 68,066 8,606 8,371 292,684 37,006 35,995 

 

Total non-current liabilities 161,162 61,674 46,608 692,998 265,199 200,414 

 

Dividends payable 13 30,550 30,550 18,330 131,365 131,365 78,819 

Provisions 14 1,569 1,805 2,098 6,744 7,761 9,021 

Accruals and other liabilities 15 510,548 262,971 169,317 2,195,363 1,130,776 728,064 

Accounts payable 16 544,931 340,753 52,095 2,343,203 1,465,241 224,009 

Income tax payable 7 92,965 172,879 164,499 399,750 743,380 707,346 

 

Total current liabilities 1,180,563 808,958 406,339 5,076,425 3,478,523 1,747,259 

 

Total liabilities 1,341,725 870,632 452,947 5,769,423 3,743,722 1,947,673 

 

Total equity and liabilities 2,101,999 1,544,913 925,318 9,038,599 6,643,129 3,978,868 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Statements of Comprehensive Income 

(Expressed in thousands) 

 

The accompanying notes (1 to 25) are an integral part of these financial statements. 

 

4 

 Years ended December 31, 

 Note 2012 2011 2010 2012 2011 2010 

 (U.S. Dollars) (Bolivars) 

Income 

Sale of crude oil 1,157,293 1,045,224 604,173 4,976,360 4,494,463 2,597,945 

Sale of natural gas 3,360 3,504 3,413 14,448 15,067 14,676 

 

 21 1,160,653 1,048,728 607,586 4,990,808 4,509,530 2,612,621 

 

Costs and expenses: 

Operational expenses 17 (138,605 ) (105,750 ) (53,659 ) (596,002 ) (454,725 ) (230,734 ) 

Depletion, depreciation and amortization 8 (86,005 ) (58,375 ) (40,429 ) (369,821 ) (251,013 ) (173,847 ) 

Sales, general and administrative expenses (20,282 ) (8,235 ) (6,147 ) (87,213 ) (35,412 ) (26,428 ) 

Royalties and other taxes 7 - g (604,003 ) (530,476 ) (217,760 ) (2,597,213 ) (2,281,047 ) (936,367 ) 

Contributions and fundings for social 

development (14,889 ) (7,241 ) (9,863 ) (64,023 ) (31,137 ) (42,414 ) 

Financial income 18 — 7 84,448 — 30 363,126 

Financial expenses 18 (7,023 ) (10,702 ) (26,767 ) (30,199 ) (46,017 ) (115,098 ) 

Other income (expenses), net (743 ) 459 2,622 (3,195 ) 1,974 11,274 

 

Total costs and expenses (871,550 ) (720,313 ) (267,555 ) 3,747,666 ) (3,097,347 ) (1,150,488 ) 

 

Income before tax 289,103 328,415 340,031 1,243,142 1,412,183 1,462,133 

Income tax 7 - a (203,110 ) (95,955 ) (262,031 ) (873,373 ) (412,606 ) (1,126,733 ) 

 

Net income 85,993 232,460 78,000 369,769 999,577 335,400 

 

Other comprehensive income 13 — — — — — 913,580 

 

Total comprehensive income for the 

year 85,993 232,460 78,000 369,769 999,577 1,248,980 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Statements of changes in equity 

Years ended December 31, 2012, 2011 and 2010 

(Expressed in Thousands of U.S. Dollars) 

 

The accompanying notes (1 to 25) are an integral part of these financial statements. 

 

5 

 Retained earning 

 Note 

Capital 

Stock 

Share 

premiun 

Legal 

Reserve and 

Other 

Reserves Undistributed Total equity 

Balances at December 31, 2009 6,977 212,451 134,764 70,729 424,921 

Total comprehensive income for the year — — — 78,000 78,000 

Release from other reserves 13 — — (82,232 ) 82,232 — 

Dividends declared 13 — — — (30,550 ) (30,550 ) 

 

Balances at December 31, 2010 6,977 212,451 52,532 200,411 472,371 

Total comprehensive income for the year — — — 232,460 232,460 

Appropriation to other reserves 13 — — 94,622 (94,622 ) — 

Dividends declared 13 — — — (30,550 ) (30,550 ) 

 

Balances at December 31, 2011 6,977 212,451 147,154 307,699 674,281 

Total comprehensive income for the year — — — 85,993 85,993 

Release from other reserves 13 — — (76,030 ) 76,030 — 

 

Balances at December 31, 2012 6,977 212,451 71,124 469,722 760,274 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Statements of changes in equity 

Years ended December 31, 2012, 2011 and 2010 

(Expressed in Thousands of Bolivars) 

 

The accompanying notes (1 to 25) are an integral part of these financial statements. 

 

6 

 Retained earning 

 Note 

Capital 

Stock 

Share 

premiun 

Legal 

Reserve 

and Other 

Reserves Undistributed 

Accumulated 

translation 

adjustment 

Total 

equity 

Balances at December 31, 2009 15,000 456,770 289,741 152,068 — 913,580 

Total comprehensive income for the year 13 — — — 335,400 913,580 1,248,980 

Release from other reserves 13 — — (65,356 ) 65,356 — — 

Dividends declared 13 — — — (131,365 ) — (131,365 ) 

 

Balances at December 31, 2010 15,000 456,770 224,385 421,460 913,580 2,031,195 

Total comprehensive income for the year — — — 999,577 — 999,577 

Appropriation to other reserves 13 — — 406,875 (406,875 ) — — 

Dividends declared 13 — — — (131,365 ) — (131,365 ) 

 

Balances at December 31, 2011 15,000 456,770 631,260 882,797 913,580 2,899,407 

Total comprehensive income for the year — — — 369,769 — 369,769 

Release from other reserves 13 — — (326,928 ) 326,928 — — 

 

Balances at December 31, 2012 15,000 456,770 304,332 1,579,494 913,580 3,269,176 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Statements of Cash Flow 

(Expressed in thousands) 

 

The accompanying notes (1 to 25) are an integral part of these financial statements. 

 

7 

 Years ended December 31, 

 2012 2011 2010 2012 2011 2010 

 (U.S. Dollars) (Bolivars) 

Cash flow from operating activities: 

Net income 85,993 232,460 78,000 369,769 999,577 335,400 

 

Adjustments to reconcile net income to net cash (used 

in) provided by operating activities - 

Depletion, depreciation and amortization 86,005 58,375 40,429 369,821 251,013 173,845 

Change in estimation of provision for asset 

retirement costs (23,229 ) (7,644 ) (2,043 ) (99,886 ) (32,869 ) (8,785 ) 

Asset retirement profit, net — — (2,892 ) — — (12,436 ) 

Provision for income tax 127,080 190,577 189,780 546,444 819,481 816,054 

Deferred income tax provision 76,030 (94,622 ) 72,251 326,929 (406,875 ) 310,679 

Financial cost on provision for asset retirement 

obligation 5,678 4,076 3,339 24,415 17,527 14,358 

Financial income from variation in the 

exchange rate — — (84,439 ) — — (363,088 ) 

Tax credit financial cost 1,339 6,623 3,951 5,759 28,477 16,989 

Cost financial assistance — — 19,475 — — 83,743 

Changes in operating assets - 

Prepaid expenses and other assets (638 ) (117 ) 152 (2,745 ) (498 ) 654 

Material and supplies inventories (47,585 ) (12,921 ) 3,493 (204,616 ) (55,560 ) 15,020 

Accounts receivable (404,335 ) (432,222 ) (154,936 ) (1,738,642 ) (1,858,556 ) (666,225 ) 

Changes in operating liabilities - 

Provisions 39,792 14,538 15,919 171,104 62,514 68,452 

Accruals and other liabilities 241,899 89,578 53,856 1,040,172 385,188 231,584 

Accounts payable 204,178 288,659 (38,033 ) 877,962 1,241,229 (163,542 ) 

Income tax payable (206,994 ) (182,197 ) (52,526 ) (890,074 ) (783,447 ) (225,863 ) 

 

Total adjustments 99,220 (77,297 ) 67,776 426,643 (332,376 ) 291,439 

 

Net cash provided by operating activities 185,213 155,163 145,776 796,412 667,201 626,839 

 

Cash flow (used in) provided by investing activities: 

Acquisition of property, plant and equipments (184,220 ) (137,956 ) (101,799 ) (792,147 ) (593,211 ) (437,737 ) 

Asset retirement — — 21 — — 91 

 

Net cash used in investing activities (184,220 ) (137,956 ) (101,778 ) (792,147 ) (593,211 ) (437,646 ) 

Cash flow used in financing activities: 

Dividends paid — (18,330 ) (43,346 ) — (78,819 ) (186,388 ) 

 

Net cash used in financing activities — (18,330 ) (43,346 ) — (78,819 ) (186,388 ) 

 

Effect for variation in the exchange rate in cash and cash 

equivalents — — (249 ) — — (1,071 ) 

Effect for variation in the exchange rate in the foreign currency — — — — — 6,583 

 

Net cash (decrease) increase 993 (1,123 ) 403 4,265 (4,829 ) 8,317 

Cash and cash equivalents at the beginning of the year 2,342 3,465 3,062 10,071 14,900 6,583 

 

Cash and cash equivalents at the end of the year 3,335 2,342 3,465 14,336 10,071 14,900 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Petrodelta, S.A. was incorporated and is domiciled in the Bolivarian Republic of Venezuela and its main offices are located at Avenida 

Alirio Ugarte Pelayo, Edificio Petrodelta, Ala Norte, Planta Baja in Maturín, Monagas State. Its legal address is: Avenida Veracruz con 

Calle Cali, Urbanización Las Mercedes, Edificio Pawa, Piso 5, Caracas, Distrito Capital. 

Petrodelta, S.A. (the Company) was incorporated in October 2007, as published in Official Gazette No. 38,786. Its business objective is 

primary exploration to discover oil reserves, extraction of oil in its natural state, and its subsequent collection, transportation and storage 

pursuant to Article No. 9 of the Venezuelan Hydrocarbon Law (LOH). The Company operates within an area of approximately 1,000 

square kilometers in the Uracoa, Bombal, and Tucupita fields (formerly the Monagas Sur Unit) and in the El Salto, El Isleño, and 

Temblador fields in the Monagas and Delta Amacuro states in Venezuela (the assigned operating area). 

The Company was created as a result of the process for conversion into a mixed-capital company of the Operating Agreement signed on 

July, 1992 between PDVSA Petróleo, S.A. (PDVSA Petróleo) (formerly Lagoven, S.A.), Harvest Natural Resources, Inc. (Harvest) 

(formerly Benton Oil and Gas Company) and Venezolana de Inversiones y Construcciones Clérico, C.A. (Vinccler). As part of this 

process, on March 31, 2006, PDVSA Petróleo, S.A., Corporación Venezolana del Petróleo, S.A. (CVP) and Harvest Vinccler, S.C.A. 

(HVSCA), the agreement operator and a related company of Harvest and Vinccler, signed a memorandum of understanding for 

conversion into a mixed company. In June 2007, the National Assembly of the Bolivarian Republic of Venezuela approved the 

incorporation of the mixed company Petrodelta, S.A. In August 2006, the National Assembly approved the inclusion of the Temblador, El 

Isleño and El Salto areas into the Monagas Sur Unit for further development of the Company’s primary activities. An agreement for 

conversion into a mixed company was signed between CVP and HNR Finance B.V. (HNR Finance) in September 2007. The Company 

will operate for 20 years as from October 2007 when the decree for transfer of field operations was published in the Official Gazette. 

The capital stock of the Company is 60%-owned by Corporación Venezolana del Petróleo (CVP), a wholly owned subsidiary of Petróleos 

de Venezuela, S.A. (PDVSA), and the remaining 40%-owned by HNR Finance. 

Company management considers that it operates in a single business segment (hydrocarbons) and in one country, the Bolivarian Republic 

of Venezuela, in conformity with its social statutes. 

During the transition period from April 1, 2006 to December 31, 2007, Harvest Vinccler, S.C.A. (HVSCA) was in charge of managing 

and developing the Company’s activities and provided its financial and operational structure for this purpose. The Company’s operating 

costs during this period were paid by HVSCA and CVP and subsequently charged to PDVSA, which, in turn, billed the Company. These 

costs were recognized in the statements of comprehensive income for the respective periods. These costs include, but are not limited to, 

general, administrative, operating and capital expenses required to continue activities in the assigned operating area. 

At December 31, 2012, 2011 and 2010 the Company had not received information regarding production from Temblador field from the 

period starting October 23, 2007, official date of the decree of transferring field operations to the Company, and ending February 1, 2008. 

Because production was handled during this period by PDVSA as well as related operational expenses, investments, tributes and 

contributions by law associated, the Company started discussions to obtain information and evaluate if merits exists for an eventual 

reconciliation of actual crude produced during the period mentioned. 

 

8 

(1) Reporting Entity 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

During the years ended December 31, 2012, 2011 and 2010, the Company has operated with employees assigned by its shareholders or 

their related companies since it has no direct employees. At December 31, 2012, 2011 and 2010, the Company has 635, 527 and 432 

employees, respectively, assigned by its shareholders or their related companies. 

During the year ended December 31, the Company drilled 12 (2012), 15 (2011) and 16 (2010) development wells, produced 

approximately 13.2 (2012), 11.4 (2011) and 8.6 (2010) million barrels of oil and sold 2.1 (2012), 2.3 (2011) and 2.2 (2010) billion cubic 

feet of natural gas. 

Regulations 

The Company’s main activities are regulated by the Venezuelan Hydrocarbon Law (LOH), effective from January 2002 and its partial 

reform of May 2006. Gas-related operations are regulated by the Venezuelan Gaseous Hydrocarbon Law effective since September 1999 

and its Regulation of June 2000, by the provisions of the bylaws and common rights norms applicable. 

Below are the main regulations included in the LOH: 

 

 

 

 

Hydrocarbon Purchase Sale Agreement 

On January 17, 2008, the Company signed a hydrocarbon purchase sale agreement with PDVSA Petróleo, whereby the Company 

undertakes to sell to the latter all hydrocarbons produced within the delimited operating area that are not being used in its operations. The 

Company may assign or transfer this agreement, or any rights and obligations thereunder, to another company in accordance with Article 

No. 27 of the LOH. This agreement is for 20 years. 

 

9 

 a) A 30% royalty on volumes of hydrocarbon extracted (see Note 7-g). 

 

b) A Partial Reform of the Extraction Tax was enacted and published in Official Gazette No. 38,443 of May 24, 2006, establishing a 

rate equivalent to one-third of the value of all liquid hydrocarbons extracted from any reservoir, calculated on the same basis set out 

in the Law for royalty calculation. The taxpayer has the right to deduct from the extraction tax any sum payable as royalties (30%), 

including the additional royalty paid for special advantages (3.33%). 

 

c) A surface tax equivalent to 100 tax units for each square kilometer or fraction thereof per year for licensed areas that are not under 

production. This tax will increase by 2% during the first five years, and by 5% during all subsequent years. 

 

d) An internal consumption tax equivalent to 10% of the value of each cubic meter of hydrocarbon derivatives produced and 

consumed as fuel in internal operations, calculated on the final selling price. Company management considers that, other than 

associated gas, no hydrocarbon derivatives are consumed (see Note 7-j). All of this tax was recorded against income for the year 

2012. 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

In October 2011, the Company began to deliver production from El Salto field to the COMOR transfer point, EPM-1 storage facility at 

PDVSA Morichal which serves as a reception and dispatch of crude for its proximity to El Salto field. Since that date, MPPPM 

determined that Petrodelta’s production flowing through the COMOR transfer point was of lower gravity and higher sulphur content, and 

instructed the Company that invoicing of crude from El Salto field from October 2011 must be made in reference to a similar gravity 

crude and not using the crude currently in the purchase sale contract. On December 17, 2012 the Company received from PDVSA 

Marketing and Supply a proposal to amend the purchase sale agreement with PDVSA Petróleo to invoice the production from El Salto 

field. This amendment includes a change in the pricing formula which currently uses Merey 16 to bill the volumes produced by the 

Company and include Boscán crude as a reference adjusting the transportation and commercialization costs to invoice that production 

with lower density and higher sulphur content coming from El Salto field. The Company has agreed to amend the purchase sale 

agreement which will permit to bill the production delivered from El Salto field that since October 2011 has not being able to invoice. 

The amendment has been approved by the Board of Directors of the Company (see Note 24-a) and is in process of approval by PDVSA 

Petroleo in order to endorse it to the Company Shareholder ́s approval. 

 

 

The financial statements as of December 31, 2012, 2011 and 2010 are prepared in accordance with International Financial 

Reporting Standards (IFRS) adopted by the International Accounting Standards Board (IASB) and their interpretations, issued by 

the International Financial Reporting Interpretations Committee (IFRIC) of the IASB. 

On March 1, 2013 the Board of Directors of the Company approved the issuance of the financial statements as of December 31, 

2012 in accordance with International Financial Reporting Standards (IFRS) and resolved to submit these financial statements to the 

Shareholders of the Company and it is expected its approval with no modifications. 

On February 23, 2012, the Board of Directors of the Company approved the issuance of these financial statements as of 

December 31, 2011 in accordance with International Financial Reporting Standards (NIIF) and resolved to submit these financial 

statements to the Shareholders of the Company and it is expected its approval with no modifications. 

On March 10, 2011, the Board of Directors of the Company resolved to submit for consideration of the Shareholders of the 

Company the financial statements for the year ended December 31, 2010. The financial statements as of December 31, 2011 and 

2010 will be presented in the coming Shareholder meeting and expect their approval with no modifications. 

 

10 

(2) Basis of Preparation 

 (a) Statement of Compliance 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

The financial statements have been prepared on the historical cost basis, except for certain assets and liabilities measured at fair 

value. Assets measured and presented at fair value are: recoverable tax credits, accounts receivable and cash and cash equivalents. 

The methods used for measuring fair value are discussed in more detail in Note 5. 

 

The financial statements are presented in U.S. dollar (dollar or US$.) and bolivars (bolivars or Bs.). The Company’s functional 

currency is the dollar, since the main economic environment in which Petrodelta, S.A. operates is the international market for crude 

oil and its products. In addition, a significant portion of its revenues, as well as most costs, expenses and investments are 

denominated in dollars. 

The financial statements in bolivars are presented for statutory purposes. 

All financial information presented in U.S. dollars and bolivars has been rounded in thousands. 

 

The preparation of financial statements in conformity with IFRS requires management to make estimates, judgments and 

assumptions that affect the application of accounting policies and the amounts of assets, liabilities, income and expense. The 

Company applies its best estimates and judgments; however, actual results may differ from initial estimates. 

Estimates and assumptions are reviewed periodically, and the effects of the revisions, if any, to accounting estimates are recognized 

in the period in which the estimate is revised and in any future periods affected. 

Significant areas of critical judgment in the application of accounting policies, which significantly affect financial statement 

amounts, are described in the following notes: 

 

 

 

Information on areas of uncertainty affecting management’s estimates which significantly affect financial statement amounts in 

future periods are described in the following notes: 

 

 

 

 

11 

 (b) Basis of Measurement 

 (c) Functional and Presentation Currency 

 (d) Use of estimates and judgments 

 • Note 3-g and 8—depletion, depreciation and amortization 

 • Note 3-h and 14—provision for asset retirement costs 

 • Note 3-f and 19—valuation of financial instruments 

 

• Notes 3-r and 14—measurement of contract-based retirement benefit obligations and other post-retirement benefits other 

than pensions, which is a PDVSA obligation with the employees assigned to the Company for subsequent billing once the 

employee is considered eligible for pension. 

 • Notes 3-d and 7-f—deferred income tax 

 • Notes 3-m and 20—commitments, contingencies and provisions in respect of environmental issues 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

The Company’s operations may be affected by the political, legislative, regulatory and legal environment, both at the national and 

international level. In addition, significant changes in prices or availability of crude oil and its products may have an impact on the 

Company’s results of operations in any given year. 

 

The accounting policies used for the preparation of these financial statements have been applied consistently for all periods presented and 

are summarized as follows:. 

 

Transactions in Foreign Currency 

Transactions in foreign currency (any currency different than the functional currency) are translated into the Company’s functional 

currency using the exchange rate in effect at the transaction date. Monetary assets and liabilities denominated in foreign currency 

are translated into U.S. dollars using the exchange rate prevailing at the date of the statement of financial position. Exchange gains 

or losses on monetary assets and liabilities resulting from this translation are presented as financial income or expenses in the 

statements of comprehensive income. Nonmonetary assets and liabilities in foreign currency are stated at fair value and translated to 

the functional currency using the exchange rate prevailing at the date fair value was determined. All other nonmonetary items 

denominated in foreign currency measured at historical cost are converted at the exchange rate at the date of the transaction. 

Translation to the Presentation Currency 

The Company’s financial statements were translated from dollars into bolivars, a currency other than the functional currency, in 

accordance with International Accounting Standard No. 21 The Effects of Changes in Foreign Exchange Rates. This standard 

requires each entity to determine its functional currency based on an analysis of the primary economic environment in which the 

entity operates, which is normally the one in which it primarily generates and expends cash. 

The financial statements were translated into bolivars using the following procedures: 

 

 

 

12 

(3) Summary of Significant Accounting Policies 

 (a) Foreign Currency 

 • Assets and liabilities in each statement of financial position at the exchange rates in effect at the date of such statement. 

 • Income and expenses in the statements of comprehensive income at the exchange rate at the date of transaction. 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

 

 

Income from sales of crude oil and gas, are measured at fair value of the cash receipts or amounts to be received, net of commercial 

discounts, and is recorded in the statements of comprehensive income when risks and significant rights of ownership are transferred 

to PDVSA Petróleo and MPPPM as stipulated in the hydrocarbon purchase sale agreement. Income is recognized when it can be 

reasonably measured and it is probable that future economic benefits will flow to the Company. Income from activities other than 

the Company’s main business is recognized when realized. Income is not recognized when there is significant uncertainty as to the 

recoverability of the obligation acquired by the buyer. All of the Company results are from continuing operations. During the years 

ended December 31, 2012, 2011 and 2010, the Company received accounting guidelines from its main shareholder, CVP, to 

recognize revenue from the sale of crude, royalty and extraction tax in accordance with the Law Creating a Special Contribution on 

Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (see Notes 7-g and 21). 

 

Financial income included in the statements of comprehensive income represents mainly the effects originated by modifications and 

dispositions in relation to exchange rates (see Note 18). 

Financial expenses included in the statements of comprehensive income represents changes (losses) in the fair value of financial 

assets (see Note 7-k) and the asset retirement obligation (see Notes 3-g and 3-m). 

Income and losses in foreign currencies are recognized on a net basis, either as financial income or financial expense, depending on 

the effect of foreign currency fluctuations resulting from a net asset or liability position. 

 

Income tax expense comprises current and deferred income tax. Income tax expense is recognized in the results for each year, 

except to the extent that it relates to items that should be directly recognized in other comprehensive income. 

Current income tax is the expected tax payable based on the taxable income for the year, using the methodology established by 

current laws and tax rates at the reporting date and any adjustment to taxes payable from previous years. Current income tax 

payable also includes tax responsibility derived from dividends declared. 

 

13 

 

• All exchange gain and losses generated as a result of the above, are recognized in the statement of comprehensive income as 

other comprehensive income and accumulated as a separate component of equity. 

 

• Equity accounts are translated at the exchange rate in effect at the date of each related transaction, except for retained 

earnings which are translated at the weighted-average rate for the relevant year. 

 (b) Revenue Recognition 

 (c) Financial Income and Expenses 

 (d) Income Tax 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Deferred income tax is recognized using the balance sheet liability method. Deferred tax assets and liabilities are recognized by the 

timing differences that exist between assets and liabilities values presented in the statement of financial position and their 

corresponding tax value, as well as operating losses and tax credit carry-forwards. The value of deferred tax assets and liabilities is 

determined based on tax rates expected to be applicable to taxable income for the year in which temporary differences will be 

recovered or settled pursuant to law. The effect on deferred assets and liabilities of changes in tax rates is recorded in the results for 

the year in which such changes become effective. 

A deferred tax asset is recognized only to the extent that future taxable income will be available for offsetting. Deferred tax assets 

are reviewed at each reporting date and reduced to the extent that it is no longer probable that the related tax benefit will be realized. 

 

Corresponds to contributions and funding the Company is obliged by law to carry out and are paid and recovered by PDVSA. These 

contributions are funding for endogenous projects, programs related to science, technology and innovation and funding of national 

programs in relation to antidrug activities and Sports Organic Law. 

 

Non-derivative financial instruments consist of recoverable tax credits, accounts receivable, cash and cash equivalents, accounts 

payable to suppliers, and other liabilities (see Note 5). 

Non-derivate financial instruments classified as at fair value through profit or loss are initially recognized at fair value, plus any 

direct transaction costs. 

Recoverable tax credits are accounted for at fair value after its initial recognition (see Note 7-k). All other non-derivative financial 

assets and liabilities are maintained at its original recognized value. 

A financial instrument is recorded when the Company engages or commits to the contractual clauses thereof. Financial assets are 

reversed if the Company’s contractual rights over the asset’s cash flows expire or if the Company transfers the financial asset to 

another entity without retaining control or a significant portion of the asset’s risks and rewards. Regular purchases and sales of 

financial assets are accounted for at trade date, which is generally the date on which the Company commits to purchase or sell the 

asset. Financial liabilities are derecognized when the Company’s specific contractual obligation expires or is paid. 

During the years ended December 31, 2012, 2011 and 2010, the Company conducted no transactions with derivative instruments. 

The balance of financial assets and liabilities are offset and the net amount shown in the statement of financial position when and 

only when, the Company has a legal right to offset amounts and intends to settle on a net basis or to realize the asset and settle the 

liability simultaneously. 

 

14 

 (e) Contributions and Funding for Social Development 

 (f) Financial Instruments 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Recognition and measurement 

Property, plant and equipment are stated at cost, net of accumulated depreciation and impairment losses (see Note 3-l). The 

successful efforts accounting method is used for exploration and production activities of crude oil and natural gas, taking into 

consideration what is established under IFRS 6 Exploration For and Evaluation of Mineral Resources in relation to accounting for 

exploration and evaluation expenditures, including the recognition of exploration and evaluation assets. All costs for development 

wells, related plant and equipment, and property used for oil recovery are recorded as part of the cost of the assets. Costs of 

exploratory wells are capitalized until it is determined whether they are commercially feasible; otherwise, such costs are charged to 

operating expenses. Other exploratory expenditures, including geological and geophysical costs, are expensed as incurred. 

The cost of property, plant, and equipment includes disbursements that are directly attributable to the acquisition of such assets and 

the amounts associated with asset retirement costs (see Note 3-h). 

Finance costs of projects requiring major investments, and costs incurred for specific financing of projects, are recognized as part of 

property, plant, and equipment, when can be directly related to the construction or acquisition of a qualifying asset. Capitalization 

of such costs is suspended during periods when the development of construction activity is interrupted, and capitalization ends 

when necessary activities are substantially complete for the utilization of a qualifying asset. An asset is considered qualified, when 

it requires a period of substantially time necessary before is ready for use. 

The cost of assets built by the Company includes materials and direct labor, as well as any other direct cost attributable to bringing 

the asset to working condition. Costs for dismantling and removal from the construction site are also included. 

All disbursements relating to construction or purchase of property, plant and equipment in the stage prior to implementation are 

stated at cost as work in progress. Once the assets are ready for use, they are transferred to the respective component of property, 

plant, and equipment and depreciation or amortization commences. 

Gain or loss generated by the sale, retirement or disposal of an asset from property, plant, and equipment, is determined by the 

difference between the amount received from sale, retirement or disposal, if any, and the net carrying value in the books of the 

Company, and is recognized as other income or expense, net in the statements of comprehensive income. 

Materials and supplies accounted for as inventory and considered strategic since they will be used as spare parts for two years 

operation in the production facilities and in specific investment projects are reported under property, plant, and equipment. 

 

15 

 (g) Property, Plant and Equipment 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Subsequent Costs 

Costs for major maintenance or general repairs, as well as replacement of significant parts of property, plant and equipment are 

capitalized when identified as a separate component of the asset to which such maintenance, repair and replacement corresponds 

and are depreciated between one maintenance period and the other. Disbursements for minor maintenance, repairs and renewals 

incurred to maintain facilities in operating conditions are expensed. 

Depletion, Depreciation and Amortization 

Depletion, depreciation, and amortization of capitalized costs related to wells and facilities for the production of crude oil and gas 

are determined by the units of production method by field, based on proved developed reserves, which include quantities of oil and 

gas that can be recovered from existing wells, with equipment and methods currently in use. The rates used are reviewed annually 

based on an analysis of reserves and are applied retroactively at the beginning of the year. Capitalized costs of other property, plant 

and equipment are depreciated over their estimated useful lives, mainly using the straight-line method with an average useful life of 

15 years for administrative buildings and between 3 and 5 years for the remaining assets 

When parts of a property, plant, and equipment asset have different useful lives, they are recorded separately as a significant 

component of that asset. 

Depreciation methods and average useful lives of property, plant, and equipment are reviewed annually. Land is not depreciated. 

 

The Company capitalizes estimated costs associated with obligations from retirement of assets used for exploration and crude oil 

and natural gas production activities, based on the future retirement plan for those assets. Cost is capitalized as part of the related 

long-lived asset and is amortized over its useful life with a charge to operating costs (see Note 3-m). 

 

Inventories are stated at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the normal 

course of business, less costs to complete and estimated selling costs. 

The cost of inventories of crude oil and its products is determined using the average cost method. 

Materials and supplies are valued mainly at average cost, less an allowance for possible losses, and are classified into two groups: 

current assets and non-current assets. 

The inventory obsolescence provision is calculated from analysis of stock behavior and aging reports that will eventually determine 

its use type and mobility in order to apply the corresponding obsolescence percentage. 

 

16 

 (h) Costs associated with Asset Retirement Costs 

 (i) Inventories 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Accounts receivable are accounted for according to price formulas established in the Hydrocarbon Purchase Sale Agreement 

between the Petrodelta, S.A. and PDVSA Petróleo, S.A. whereby the former undertake to sell and PDVSA Petróleo, S.A. 

undertakes to buy all hydrocarbons produced that are not being used in their operations within the delimited operating areas. At 

December 31, 2012, 2011 and 2010, the Company does not expect to incur losses on uncollectible accounts and, therefore, has not 

set aside a provision in this connection other than those described in the hydrocarbon purchase sale agreement with PDVSA 

Petróleo, S.A (see Notes 11 and 21). 

 

Petrodelta, S.A. considers as cash and cash equivalents the cash in hands and banks. At December 31, 2012, 2011 and 2010 

amounted to approximately US$.3,335 thousands, US$.2,342 thousands and US$.3,465 thousands (Bs.14,336 thousands, Bs.10,071 

thousands and Bs.14,900 thousands), respectively (see Note 12). 

 

Non-derivative Financial Assets 

Financial assets are assessed by the Company at the date of the financial statements to determine whether there is any objective 

evidence of impairment. A financial asset is impaired if there is objective evidence that one or more events have had a negative 

effect on the estimated future cash flows of the asset (see Note 6). 

Objective evidence that financial assets are impaired can include default or lack of compliance from debtors, restructuring a balance 

due to the Company in terms that may not be considered in other circumstances, signs that a debtor or issuer declares bankrupt or 

the instrument no longer has a market. 

Significant financial assets are reviewed individually to determine their impairment. The remaining financial assets with similar 

credit risk characteristics are evaluated as a group. 

In evaluating impairment, the Company uses historical trends of the probability of defaults, timing of recoveries and the amount of 

loss incurred, adjusted for management’s judgment as to whether current economic and credit conditions are such that the actual 

losses are likely to be greater or less than the suggested by historical trends. 

An impairment loss related to a financial asset is calculated as the difference between its carrying amount and the present value of 

the estimated future cash flows, discounted at the effective interest rate. Impairment losses are recognized in the statements of 

comprehensive income. An impairment loss is reversed if the amount can be related objectively to an event occurring after the 

impairment loss was recognized (see Note 19). 

Non-Financial Assets 

The carrying amounts of non-financial assets, excluding inventory and deferred tax, are reviewed at each reporting date of the 

statement of financial position to determine whether evidence of impairment exists. If any such indication exists, then the 

recoverable value of the asset is estimated. 

 

17 

 (j) Accounts Receivable 

 (k) Cash and Cash Equivalent 

 (l) Impairment in the Value of Assets 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

The recoverable value of an asset or cash-generating unit is the greater of its carrying value and its fair value, less direct selling 

expenses. When determining the carrying value, expected future net cash flows are discounted using present value techniques, using 

a discount rate before tax that reflects current market conditions over the time value of money and specific risks that the asset may 

bear. Impairment is determined by the Company based on cash-generating units, in accordance with its business segments, 

geographical locations and the final use of the production generated by each unit. A cash-generating unit is the assets grouped at the 

lowest levels for which there are separately identifiable cash flows. When evaluating impairment, goodwill acquired during 

business combinations is allocated among cash-generating units that are expected to benefit from combination synergies. 

An impairment loss is recognized when the carrying amount of an asset or its cash-generating unit exceeds its recoverable amount. 

Impairment loss is recognized in the statements of comprehensive income for the year and the asset cost is shown net of this 

impairment charge. 

Impairment losses can be reversed only if the reversion is related to a change in the estimates used after the impairment loss was 

recognized. This reversion shall not exceed the book value of assets net of depreciation or amortization as if the impairment had 

never been recognized. Impairment losses associated to goodwill are not reversed. 

 

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be 

reliably estimated, and it is probable that an outflow of economic benefits will be required to settle the obligation. When the effect 

of the time value of money is significant, the provision is determined by applying a discount rate associated with the estimated 

payment terms, if the terms can be estimated reliably as well as the risk associated with those obligations. 

Environmental Issues 

In conformity with the environmental policy established by the Company and following instructions from PDVSA and applicable 

current legislation, a liability is recognized when costs are likely and can be reasonably estimated. Environmental expenditures that 

relate to current or future revenues are expensed or capitalized as appropriate. Expenditures for past operations that do not 

contribute to generating current or future income are charged to expense. Recognition of these provisions coincides with the 

identification of an obligation for environmental remediation where Petrodelta, S.A. has sufficient information to determine a fair 

estimate of the respective cost. Subsequent adjustments to estimates, if necessary, are made upon obtaining additional information 

(see Notes 14 and 20). 

Asset Retirement 

Obligations associated with the retirement of long-lived assets are recognized at fair value on the date on which such obligation is 

incurred, based on future discounted cash flows. The fair values are determined based on current regulations and technologies. 

 

18 

 (m) Provisions 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Changes in fair values of obligations are added to or deducted from the cost of the respective asset. The adjusted depreciation 

amount of the asset is depreciated over its remaining useful life. Therefore, once its useful life has ended all subsequent changes in 

the fair value of the obligation are recognized in the statements of comprehensive income. The increase in the obligation for each 

year is recognized in the results of operations as financial expenses (see Note 14). 

Litigation and Other Claims 

Provision for litigations and claims are recognized in the event that legal action has been lodged, government investigations have 

been initiated and other legal actions are outstanding or subject to be filed in the future against the Company, as a result of past 

events, which may result in a probable outflow of economic benefits to pay for that obligation which may be reliably estimated (see 

Note 20). 

Damages to Land 

Liabilities for damage to land is recorded as a result of the regular activities carried out by the Company to access the different 

existing areas or new, for which third-party property or economic activity can be or are affected causing the need to compensate the 

economic effects caused. 

As a result of the expansion of the activities during the years 2010 to 2012, the Company caused damages to third parties and 

currently is in negotiation process with different owners. Management estimated potential liabilities as of December 31, 2012, 2011 

and 2010 (see Note 20). 

 

Royalties, extraction tax, and other related taxes are calculated according to the provisions of the Hydrocarbons Law and other laws 

regulating the oil industry (see Notes 1 and 7) and are recognized in the statements of comprehensive income when caused. 

 

19 

 (n) Royalties, extraction tax and other taxes 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Capital Stock 

Common shares are classified as equity. For the years ended December 31, 2012, 2011 and 2010, the Company has no preferred 

shares (see Note 13). 

Share Premium 

The Company recognizes as share premium any excess in the value of contributions made by shareholders for Company 

incorporation over the par value at the incorporation date (see Note 13). 

Legal Reserve 

The Venezuelan Code of Commerce requires companies to set aside 5% of their net income each year to a legal reserve until it 

reaches an amount equivalent to at least 10% of their capital stock in bolivars (see Note 13). 

Other Equity Reserves 

The Company has the policy of transferring from retained earnings to other equity reserves the net balance of the deferred tax asset. 

This reserve is recognized in retained earnings to the extent that such asset gets realized when the temporary differences that gave 

rise to it are deducted for tax purposes and consequently would be available for dividend payments (see Note 13 and 24-e). 

Dividend Distribution 

Dividend distribution to the Company’s shareholders is recognized as a liability in the financial statements in the period in which 

the dividends are approved by the shareholders of the Company (see Notes 13). 

 

The Company continually evaluates judgments used to record its accounting estimates, which are recorded based on historical 

experience and other factors, including expectation of future events that are believed to be reasonable under the circumstances. 

Significant future changes to assumptions established by management may significantly affect the carrying value of assets and 

liabilities. 

Below is a summary of the most significant accounting estimates made by the Company: 

Estimates of oil and gas Reserves 

Oil and gas reserves are key elements in the Company’s decision-making process. They are also important in evaluating impairment 

in the carrying amount of long-lived assets. Calculation of depreciation, amortization and depletion of property, plant and 

equipment accounts related to hydrocarbon production requires quantification of proved developed 

 

20 

 (o) Equity 

 (p) Accounting estimates requiring a high degree of Judgment 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

hydrocarbon reserves expected to be recovered by the Company in the future. Reserve estimates are only approximate amounts due 

to the high degree of judgment and specialization required to develop the information. Reserves are calculated by the support of 

specialized technical departments at Petróleos de Venezuela, S.A. (PDVSA) (related company that owns the Company’s main 

shareholder) and results are submitted for approval by Ministry of Popular Power for Oil and Mining (MPPPM) in order to 

guarantee the reasonableness of the information. Additionally, reserve studies are regularly updated to guarantee that any change in 

estimates is timely recorded in the Company’s financial statements. 

Reserves studies of crude oil and gas assigned to the Company are updated once a year by the superintendence of reservoir of the 

Company who possesses adequate technological elements necessary to determine reserves, and its impact in the statements of 

comprehensive income is reflected as of December 31, 2012, 2011, and 2010 (see Note 25). 

Assessment of impairment in the value of Property, Plant, and Equipment 

Management annually assesses impairment in the value of property, plant, and equipment. The main key assumptions considered by 

management to determine the recoverable amount of property, plant and equipment were income projections, oil prices, royalties, 

operating costs and the discount rate. Projections include proved developed reserves to be produced during the development period 

of production activities in the assigned fields. At December 31, 2012, 2011 and 2010, the Company has not identified impairment in 

the carrying value of property, plant, and equipment as a result of these estimates. 

Abandonment Cost Calculation 

The Company’s financial statements include an asset and a provision for property, plant, and equipment used in hydrocarbon 

production that is expected to be abandoned in the future and in relation to which the Company will make future disbursements. 

Assumptions considered for the calculation of this asset and the provision for abandonment (asset abandonment costs, date of 

abandonment, and inflation and discount rates) may vary depending on factors such as performance in the field, changes in 

technology and legal requirements. Assumptions made by the Company are recorded based on technical studies and management’s 

experience and are regularly reviewed (see Note 14). 

 

The Company does not disclose, as part of balances and transactions with related companies (see Note 21), transactions with 

government entities conducted in the normal course of business, the terms and conditions of which are consistently applied to other 

public and private entities and for which there are no other suppliers, i.e., supplies, electricity services, taxes, among others. 

 

21 

 (q) Related Party Transactions 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Following corporate instructions, the related company PDVSA Petróleo, S.A. assumed the employer role for employees who 

accepted the transfer, and are working as assigned employees to Petrodelta, S.A. operations. According to this, PDVSA Petróleo, 

S.A. administer, prepare and pay those employees’ payroll and labor benefits and invoice direct payroll and benefits to the 

Company, which recognize those costs against a liability to PDVSA Petróleo, S.A. The direct payroll and benefits costs are 

determined by PDVSA according the following policies: 

Termination Benefits 

The Company accrues for its liability in respect of employee termination benefits based on the provisions of the Venezuelan Labor 

Law and the prevailing oil-sector Collective Labor Agreement (see Note 22). Most of this accrual for indemnification has been 

deposited in trust accounts in the name of each employee. Amounts calculated for termination benefits according to the Labor 

Organic Law and Workers (see Note 23-b) for personnel assigned by PDVSA Petroleo to the Company are calculated and recorded 

based on actuarial reports. 

Profit Sharing and Bonuses 

Liabilities in respect of labor benefits and bonuses for staff, vacation leaves, and other benefits are accounted for as incurred along 

with the staff’s provision of services. 

During the years ended December 31, 2012, 2011 and 2010, the Company has not had direct employees and, therefore, has not 

recorded liabilities derived from these labor-related benefits except for the payroll related cost monthly billed to the Company by 

PDVSA Petróleos S.A. 

Retirement Plan 

The amount to be provision for retirement benefits is received from PDVSA based on actuarial studies. Net liabilities in respect of 

the retirement plan as defined in the contract are accounted for separately per each participant in said plan, by estimating the amount 

of future benefits to be acquired by staff versus their length of service during current and prior periods; said benefits are discounted 

in order to determine their current value, then it is deducted the fair market value of those assets associated to the plan. The discount 

rate reflects the yield rate that, as of the date of the financial statements, is reported through financial instruments issued by credit 

institutions with high ratings and maturity dates that are in line with those due dates applicable to said liabilities. This calculation is 

made by an actuary by using the projected unit credit method. 

Improvements made to the plan’s benefits, in connection with past service cost, are charged to the Company by PDVSA and 

expensed in the statements of comprehensive income over the estimated period that, on average, will last until the time that said 

benefits will be paid in full. As said benefits fall under irrevocable acquired rights after approval, said expense which is charged to 

the Company by PDVSA is recorded, immediately, in the statements of comprehensive income. 

 

22 

 (r) Accrual for Employee Benefits 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

The amount accounted for as income or expense is the share corresponding to the total of unrecorded actuarial earnings or loss in 

excess of 10% of the greater of these sums: a) the current value of liabilities in respect of those benefits defined as of that date; and 

b) the reasonable value of the plan’s assets as of that date. Said caps are computed and apply separately per each plan’s benefit so 

defined. 

Post-retirement Benefits other than Retirement 

Net liabilities in respect of post-retirement benefits other than retirement, as defined in the contract, equal the total of future benefits 

earned by PDVSA employees assigned to the Company along with their length of service during current and prior periods. Said 

benefits include mainly: health and dental plans, burial and funeral insurance, and food electronic card. Said liabilities are computed 

by using the projected unit credit method; then they are deducted to reflect their current value and, if applicable, the fair market 

value of related assets is deducted as well. The discount rate reflects the yield rate that, as of the date of the financial statements, is 

reported through financial instruments issued by credit institutions with high ratings and maturity dates that are in line with those 

due dates applicable to said liabilities. 

Past service cost and the actuarial income or loss are recorded by using the method set out in the retirement plan per the contract. 

The provision for this concept is provided by PDVSA which is based on actuarial studies. 

 

Certain new standards, amendments and interpretations to existing standards were not effective for the year ended December 31, 

2012 and have not been applied in the preparation of the Company’s financial statements. The most important standards, 

amendments and interpretations for the Company are as follows: 

 

 

 

23 

 (s) New accounting Standards not yet Adopted 

 

• In October 2012, the IASB published amendments to IFRS 10 Consolidated Financial Statements, IFRS 12 Disclosure of 

Interests in Other Entities and IAS 27 Separate Financial Statements in relation to Investments entities. The amendments

apply to a particular class of business that qualify as investment entities whose business purpose is to invest funds solely for 

returns from capital appreciation, investment income or both. Also, the amendments provide an exception to the 

consolidation requirements in IFRS 10 and require investment entities to measure particular subsidiaries at fair value through 

profit or loss, rather than consolidate them. Under IFRS 12 the amendments also set out disclosure requirements for 

investment entities. These amendments are effective from January 1, 2014 with early adoption permitted. 

 

• In June 2012, the IASB published amendments that are intended to provide additional transition relief in IFRS 10 

Consolidated Financial Statements , IFRS 11 Joint Arrangements and IFRS 12 Disclosure of Interests in Other Entities , 

by “limiting the requirement to provide adjusted comparative information to only the preceding comparative period”. Also, 

amendments were made to IFRS 11 and IFRS 12 to eliminate the requirement to provide comparative information for 

periods prior to the immediately preceding period. These amendments will be effective for fiscal periods beginning 

January 1, 2013. 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

 

 

 

 

The amendments are: 

 

 

24 

 

• In May 2012, the IASB concluded the 2009-2011 upgrade cycle which affected the following standards: IFRS 1 First-time 

Adoption of International Financial Reporting Standards on permitting repeated application of IFRS 1 and borrowing costs 

relating to qualifying assets for which the commencement date for capitalization is before the date of transition to IFRSs; 

IAS 1 Presentation of Financial Statements in relation to clarification of requirements on comparative information; IAS 16 

Property, Plant and Equipment in relation to classification of servicing equipment; IAS 32 Financial Instruments: 

Presentation which clarifies that tax effects of a distribution to holders of equity instruments should be accounted for in 

accordance with IAS 12 Income Taxes and IAS 34 Interim Financial Reporting in relation to interim reporting on segment 

information for total assets in order to enhance consistency with the requirements in IFRS 8 Operating Segments . These 

amendments are effective for annual periods beginning on or after January 1, 2013. 

 

• In December 2011, the IASB published 2 amendments to IFRS 7 Financial Instrument: Disclosures. The first amendment 

seeks to improve disclosures related to offsetting of financial assets and financial liabilities and will be effective for fiscal 

periods starting January 1, 2013. The second amendment deals about disclosure in relation to first time application of IFRS 9 

Financial Instruments and will be effective for fiscal periods starting January 1, 2015. 

 

• In December 2011, the IASB published amendments to IAS 32 Financial Instruments: Presentation . These amendments 

provide guidance when offsetting financial assets and financial liabilities. These amendments will be effective for fiscal 

periods starting January 1, 2014. 

 

• In June 2011, the IASB published an amended version of IAS 19: Employee Benefits, e ffective for annual periods beginning 

on or after January 1, 2013. The amendment improve the accounting for pensions and other post-retirement benefits by 

providing investors and other users of financial statements with a much clearer picture of an entity ́s obligations resulting 

from the provision of defined benefit plans and how those obligations will affect its financial position, financial performance 

and cash flow. 

 

• In May 2011, the IASB published amendments and new standards effective for annual periods beginning on or after 

1 January 2013. A summary of these publications: 

 

• IAS 27 Consolidated and Separate Financial Statements changed its title to IAS 27 Separate Financial Statements and 

IAS 27 has amended its objective to setting standards to be applied in accounting for investments in subsidiaries, 

jointly ventures, and associates when an entity elects, or is required by local regulations, to present separate (nonconsolidated) financial statements. 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

The new standards are: 

 

 

 

 

 

 

 

 

 

25 

 

• IAS 28 Investments in Associates and Joint Ventures has the objective to set out the requirements for the application of the 

equity method when accounting for investments in associates and joint ventures. 

 

• IFRS 10 Consolidated Financial Statements which is a replacement of sections of IAS 27 Separate Financial Statements and 

in its entirety of SIC 12 Consolidation – Special Purposes Entities, looks for having a single basis for consolidation for all 

entities, regardless of the nature of the investee, and that basis is control. 

 

• IFRS 11 Joint Arrangements which supersedes IAS 31 Interests in Joint Ventures and SIC—13 Jointly Controlled Entities—

Non Monetary Contributions by Venturers , classifies joint arrangements as either joint operations or joint ventures based on 

the parties rights and obligations and eliminates proportionate consolidation method requiring the use of equity accounting 

method for interests in joint ventures. 

 

• IFRS 12 Disclosure of Interests in Other Entities require extensive disclosures relating to an entity ́s interests in subsidiaries, 

joint arrangements, associates and unconsolidated structured entities to help users of its financial statements evaluate the 

nature of and risks associated with its interests in other entities and the effect of those interests in its financial statements. 

 

• IFRS 13 Fair Value Measurement establishes a single framework for measuring fair value required by other Standards and 

applies to both financial and non-financial items measured at fair value. 

 

• In November 2009, the IASB issued IFRS 9 Financial Instruments , effective for annual periods beginning on or after January 1, 

2013, with earlier application permitted. IFRS 9 replaces those parts of IAS 39 relating to the classification and measurement of 

financial assets. Key features are as follows: 

 

• Financial assets are required to be classified into two measurement categories: those to be measured subsequently at fair 

value, and those to be measured subsequently at amortized cost. The decision is to be made at initial recognition. The 

classification depends on the entity’s business model for managing its financial instruments and the contractual cash flow 

characteristics of the instrument. 

 

• An instrument is subsequently measured at amortized cost only if it is a debt instrument and both: (i) the objective of the 

entity’s business model is to hold the asset to collect the contractual cash flows, and (ii) the asset’s contractual cash flows 

represent only payments of principal and interest (that is, it has only “basic loan features”). All other debt instruments are to 

be measured at fair value through profit or loss. 

 

• All equity instruments are to be measured subsequently at fair value. Equity instruments that are held for trading will be 

measured at fair value through profit or 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

The Company completed the analysis of these standards and determined no significant effects on its financial statements. 

 

During 2012, came into effect certain standards and interpretations. The most important Petrodelta S.A. are: 

 

 

The Company’s accounting policies have been revised and modified, when necessary, to adopt the requirements established in these new 

standards or interpretations. Adoption of these standards and interpretations did not significantly affect the Company’s financial 

statements. 

 

On January 8, 2010, Official Gazette 39,342 was published containing Foreign Exchange Agreement No. 14, effective as of 

January 11, 2010, establishing exchange rates for the purchase and sale of currency, other than local currency, for legal entities as 

follows: 

 

 

26 

 

loss. For all other equity investments, an irrevocable election can be made at initial recognition, to recognize unrealized and 

realized fair value gains and losses through other comprehensive income rather than profit or loss. There is to be no 

recycling of fair value gains and losses to profit or loss. This election may be made on an instrument-by instrument basis. 

Dividends are to be presented in profit or loss, as long as they represent a return on investment. 

 (t) Recently Adopted Accounting Pronouncements 

 

• In June 2011, the IASB published amendments to IAS 1 Presentation of Financial Statements . These amendments came 

into effect from July 1, 2012 and provide guidelines on the way other comprehensive income is presented. 

 

• In December 2010, the IASB published amendments to IAS 12 Income Taxes effective for accounting periods beginning on 

or after January 1, 2012. The amendments set out in Deferred Tax: Recovery of Underlying Assets, provides a practical 

solution to the problem by introducing a presumption that recovery of the carrying amount will, normally be through sale. 

As a result of the amendments, SIC-21 Income Taxes—Recovery of Revalued Non-Depreciable Assets would no longer 

apply to investment properties carried at fair value. The amendments also incorporate into IAS 12 the remaining guidance 

previously contained in SIC-21, which is accordingly withdrawn. 

(4) Exchange Agreement with the Central Bank of Venezuela (BCV) 

 

• Payment in currency, other than local currency, transactions aimed at imports by the sector of food, health, education, 

machinery and equipment and science and technology, as well as payments for the activities of the public sector not related 

to petroleum, will be made at an exchange rate of Bs.2.60 per U.S. Dollar; payments of all other foreign currency sale 

transactions will be made at an exchange rate of Bs.4.30 per U.S. Dollar. 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

 

The previous paragraph is applicable to mix companies affiliates of PDVSA (See note 24-c). 

In addition, this Agreement enables legal entities, other than PDVSA, in the area of exports of goods and services to withhold and 

manage up to thirty percent (30%) of income in foreign currency from the exports made; this percentage will be used to cover 

expenses from export activities other than long-term debt. This Agreement also established that purchase and sale transactions of 

foreign currency with payment requested to the BCV before the effective date will be paid at an exchange rate of Bs.2.14 per 

U.S. Dollar and Bs.2.15 per U.S. Dollar, respectively, as established in Foreign Exchange Agreement No. 2, dated March 1, 2005. 

In May 2010, the government of the Bolivarian Republic of Venezuela established the Transactions System with Foreign Currency 

Securities (Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”)) for exchanging Bolivars. SITME’s purpose is 

to assist companies and individuals requiring foreign currency (U.S. dollars) for the import of goods and services into Venezuela. 

SITME may also be used for buying or selling of Venezuelan bonds. The Company does not have, and has not had, any transaction 

through SITME. 

On December 30, 2010, Foreign Exchange Agreement No. 14, effective as of January 1, 2011, was published in Official Gazette 

39,584. This Agreement sets the exchange rate at Bs.4.2893 per U.S. Dollar for purchases and Bs.4,30 per U.S. dollar for sales. This 

resolution supersedes Foreign Exchange Agreement No. 14, dated January 8, 2010, published in Official Gazette of the Bolivarian 

Republic of Venezuela 39,342, dated January 8, 2010; as well as Foreign Exchange Agreements No. 15, No. 16, No. 17, and any 

other provision that may come into conflict with this Foreign Exchange Agreement. 

The pronouncement of the Exchange Agreement No. 14 did not have an effect on the Company’s right to maintain foreign currency 

funds at financial institutions outside the country on revenues proceeds from sale of crude in order to make payments and 

disbursements (see Note 24-c). 

On November 21, 2005, the Exchange Agreement No. 9 was published in the Official Gazette No. 38,318, later revised on 

March 22, 2007 and published in the Official Gazette No. 38.650, which establishes that foreign currency obtained from 

hydrocarbon exports, must be sold to the Venezuelan Central Bank (BCV), except for foreign currency earmarked for activities 

conducted by PDVSA in conformity with the BCV Law Reform. Under this agreement, PDVSA and its subsidiaries may not 

maintain foreign currency funds in Venezuela for more than 48 hours, and establishes how these funds will be used by PDVSA. 

 

27 

 

• Payment of purchase of currency, other than local currency, obtained: i) by the public sector, other than those originating 

from hydrocarbon imports regulated by Foreign Exchange Agreement 9, will be made at an exchange rate of Bs.2.5935 per 

U.S. Dollar; and ii) the remaining purchases of foreign currency will be made at an exchange rate of Bs.4.2893 per U.S. 

Dollar. 

 

• Payment of currency purchase, other than local currency, transactions, originating from export of hydrocarbons, regulated 

under Foreign Exchange Agreement No. 9, will be made at an exchange rate of Bs.4.2893 and Bs.2.5935 per U.S. Dollar, 

pursuant to the provisions of the BCV, and proportions determined by that entity for payment of sale transactions. An 

exchange rate of Bs.2.5935, per U.S. Dollar will be applicable to at least 30% of those currencies purchase transactions, 

other than the local currency (see Note 18). 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Certain of the Company’s accounting policies and disclosures require the determination of fair values for financial and non-financial 

assets and liabilities. Fair values have been estimated for purposes of valuation and disclosure using available market information and 

appropriate valuation methods. When applicable, additional information on fair value estimates of assets and liabilities is disclosed in the 

specific notes to the statements of financial position. 

Non-Derivative Current Financial Assets and Liabilities 

The carrying amounts of financial assets and liabilities included in prepaid expenses and other assets, accounts receivable, cash and cash 

equivalents and accounts payable to suppliers approximate their fair value because of the short-term maturities of these instruments. 

The fair value of recoverable tax credits and other liabilities has been determined by discounting their carrying value based on estimation 

of future collections and payments, using interest rates calculated according to the inherent risk of the assessed instrument such as credit 

quality, liquidity, currency and other factors (see Note 7-k). 

The net carrying value of the account payable to PDVSA approximates the estimated fair value since its payment depends on the volume 

and nature of transactions conducted by the Company with the parent Company and its subsidiaries. 

Derivative Financial Assets and Liabilities 

The fair value of derivative financial instruments is based on the amount that the Company will receive or pay to terminate the 

agreements, taking into account current commodity prices, interest rate and the current creditworthiness of the parties involved. During 

the years ended December 31, 2012, 2011 and 2010, Petrodelta, S.A. did not engage in operations involving derivative financial 

instruments. 

Non-Derivative Financial Obligations 

The fair value of non-derivative financial obligations, which is determined for disclosure purposes, is calculated based on information 

provided by financial institutions and the present value of future principal and interest cash flows, discounted at the market interest rate at 

the reporting date, based on the inherent risk of those obligations. During the years ended December 31, 2012, 2011 and 2010, the 

Company did not engage in operations involving non derivative financial debt instruments. 

Accounts Payable with Related Parties 

The value of accounts payable to related parties approximate its fair value and are settle upon decisions adopted by PDVSA. 

 

28 

(5) Determination of Fair Values 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Local and international conditions, such as recession periods, inflation, interest rates, devaluation, and hydrocarbon price volatility may 

have a significant effect on the Company’s financial position. The Company is exposed to a variety of financial risks: market risk 

(including exchange rate fluctuation risk, interest rate risk and price risk), liquidity risk and capital risk. Financial instruments exposed to 

concentration of credit risk consist primarily of cash and trade accounts receivable (see Note 24-c). 

At December 31, 2012, 2011 and 2010, the Company’s cash is placed with local and foreign financial institutions. In addition, there is 

some concentration of credit risk in trade accounts receivable since all crude oil and gas produced is sold to PDVSA Petroleo, S.A. 

Market Risk 

Market risk is the risk that changes in market prices, including foreign exchange rates, interest rates or sales prices, will affect the 

Company’s income or the value of its financial instruments. The Company’s general risk management focuses on the uncertainty 

surrounding financial markets and seeks to minimize the potential adverse effects on the Company’s financial performance. 

The Company is exposed to risks stemming from changes in the sale price of hydrocarbons, which depend on external market factors. At 

December 31, 2012, 2011 and 2010, hydrocarbon sales prices are calculated based on predetermined formulas that consider the price of 

hydrocarbons in different international markets. Price fluctuations may have a significant impact on the Company’s income. At 

December 31, 2012, 2011 and 2010, the Company has no mechanisms in place to protect against exposure to hydrocarbon sales price 

fluctuations. 

In addition, the Company operates in Venezuela and is exposed to foreign exchange risk from variations in the exchange rate of the 

Bolívar relative to the U.S. dollar. Foreign exchange risk is mainly derived from future commercial operations and assets and liabilities 

recognized in bolivars. 

The Company has accounts receivable to PDVSA which earn interest on arrears 45 days after bills are due and is, therefore, exposed to 

interest rate fluctuation. 

Liquidity Risk 

It is the risk that the Company will no be able to comply with its financial liabilities through their maturity. The approach the Company 

maintains to manage this risk implies having enough cash and temporary investments as well as the availability of funds provided by its 

main shareholder, who supplies funds according to the Company needs. The Company permanently evaluates its future cash flows 

through short and long term projections from estimated sales and cash requirements which correspond mainly to operation and 

maintenance of production facilities. 

 

29 

(6) Financial Risk Management 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Capital Risk 

The Company is focused on safeguarding its ability to continue as a going concern, so that it can be strength and motor development of 

the region in which the Company operates, it allows to provide returns shareholders and to maintain an optimal capital structure to reduce 

the cost of capital. Capital consists of share capital, share premium, and retained earnings. 

The Company’s strategy has been progressively strengthening its equity situation through adjustments in light of changes in economic 

conditions and the risk characteristics of the operations. To strengthen the capital structure, the Company may decide on the strategy paid 

dividends, the creation or transfer of reserves and the sale of assets. 

 

Below is a summary of taxes affecting the Company’s operations, stated (in thousands): 

 

 

30 

(7) Taxes and Royalties 

 Years ended December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolívars 

Income tax expense (benefit): 

Income tax expense 127,080 190,577 189,780 546,444 819,481 816,054 

Deferred income tax (benefit) expense 76,030 (94,622 ) 72,251 326,929 (406,875 ) 310,679 

 

Total income tax expense 203,110 95,955 262,031 873,373 412,606 1,126,733 

 

 

 

 

 

 

 

 

 

 

 

 

 Years ended December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolívars 

Royalties and other taxes: 

Royalty on oil production (See Note 21) 276,620 260,007 181,252 1,189,466 1,118,030 779,384 

Royalty on gas production (See Note 21) 4,289 3,415 1,824 18,443 14,685 7,843 

Royalty for the municipalities 10,394 9,729 6,789 44,694 41,835 29,193 

Royalty for endogenous development projects 20,787 19,458 13,578 89,384 83,669 58,385 

Surface tax 558 235 201 2,399 1,011 865 

Windfall tax (see Note 7-l and 7-m) 291,355 237,632 14,116 1,252,827 1,021,817 60,697 

 

Royalty and other taxes 604,003 530,476 217,760 2,597,213 2,281,047 936,367 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Reconciliation between the nominal and the effective income tax rates for each year is shown below (in thousands): 

 

The increase in the effective tax rate as of December 31, 2012 with respect to December 31, 2011 is mainly attributable to: 

 

 

 

The current Income Tax Law allows tax losses to be carried forward for three years to offset future taxable income, except 

losses resulting from the application of the fiscal inflation adjustment, which can be carried forward one year, During the 

years ended December 31, 2012, 2011 and 2010 the Company had no tax loss carry forward. 

 

Venezuelan Income Tax Law requires an initial inflation adjustment to compute taxable income. The Law provides that the 

initially adjusted values of property, plant and equipment should be depreciated or amortized for tax purposes over the 

remaining useful lives of such assets. The Law also requires that an annual inflation adjustment be included in income tax 

reconciliation as a taxable or deductible item. 

 

31 

 (a) Income Tax 

 Years ended December 31, 

 2012 2011 2010 

 % 

U.S. 

Dollars Bolivars % 

U.S. 

Dollars Bolivars % 

U.S. 

Dollars Bolivars 

Profit before income tax: 

Net profit 85,993 369,769 232,460 999,577 78,000 335,400 

Income tax expense 203,110 873,373 95,955 412,606 262,031 1,126,733 

 

Profit before income tax 289,103 1,243,142 328,415 1,412,183 340,031 1,462,133 

 

Oil-sector nominal income tax rate 50 144,552 621,571 50 164,208 706,092 50 170,016 731,067 

Tax inflation adjustment (10 ) (27,971 ) (120,275 ) (9 ) (28,817 ) (123,913 ) (5 ) (16,325 ) (70,198 ) 

Deferred income tax 26 76,030 326,929 (29 ) (94,622 ) (406,875 ) 21 72,251 310,679 

Non-deductible provisions and other 4 10,499 45,148 17 55,186 237,302 11 36,089 155,185 

 

Effective rate 70 203,110 873,373 29 95,955 412,606 77 262,031 1,126,733 

 

 

 

 

 

 

 

 

 

 

 

 

 • Decrease in deferred tax asset considering new assumptions in future recovery. 

 

• Less proportion in the decrease from contributions mainly extraordinary windfall tax (see Note 7-m) paid by PDVSA on behalf of the 

Company during the year 2012 and deducted in the current year tax reconciliation. 

 (b) Tax Loss Carryforwards 

 (c) Tax Inflation Adjustment 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

According to the Income Tax Law, taxpayers subject to this tax that conduct import, export and loan transactions with 

related parties abroad are required to calculate income, costs and deductions applying the methodology set out in the Law. 

 

Official Gazette No. 38,529 of the Bolivarian Republic of Venezuela, published on September 25, 2006, modifies Article 

No. 11 of the Law regarding the rate applicable to companies engaged in hydrocarbon production and related activities, 

establishing a 50% general rate. However, only companies that conduct integrated or non-integrated activities related to 

exploration and production of non-associated gas, and processing, transportation, distribution, storage, marketing and export 

of gas and its components, or those exclusively engaged in refining of hydrocarbons or enhancement of heavy and extraheavy crude oil are subject to a 34% tax rate. Therefore, application of the 34% rate for companies incorporated under the 

joint venture agreements executed under the superseded Law Reserving Hydrocarbon Trade and Industry to the State is 

eliminated. 

 

The movements of deferred income tax asset (liability) shown in the results of each year are as follows (in thousands): 

 

 

32 

 (d) Transfer Pricing 

 (e) Income Tax Rate 

 (f) Deferred income Tax 

2012: 

2011 

Asset (Liability) 

Income (Loss) 

Recognized in income 

2012 

Asset (Liability) 

Net deferred tax at 

December 31, 2012 

(see Note 13) 

U.S. DollarsAccounts receivable and other assets 9,656 — 1,339 (32,428 ) 10,995 (32,428 ) (21,433 ) 

Property, plant, and equipment 62,520 (8,214 ) (57,438 ) (19,771 ) 5,082 (27,985 ) (22,903 ) 

Inventories 4,182 — (4,161 ) (7,653 ) 21 (7,653 ) (7,632 ) 

Accruals and other liabilities 78,704 (392 ) 43,690 392 122,394 — 122,394 

 

 155,062 (8,606 ) (16,570 ) (59,460 ) 138,492 (68,066 ) 70,426 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BolivarsAccounts receivable and other assets 41,521 — 5,758 (139,440 ) 47,279 (139,440 ) (92,161 ) 

Property, plant, and equipment 268,836 (35,320 ) (246,983 ) (85,016 ) 21,853 (120,336 ) (98,483 ) 

Inventories 17,983 — (17,893 ) (32,908 ) 90 (32,908 ) (32,818 ) 

Accruals and other liabilities 338,427 (1,686 ) 187,867 1,686 526,294 — 526,294 

 

 666,767 (37,006 ) (71,251 ) (255,678 ) 595,516 (292,684 ) 302,832 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

 

 

According with the Venezuelan Hydrocarbon Law (LOH), royalties are paid based on crude oil produced and associated 

natural gas processed in Venezuela. Volumes of hydrocarbons produced in traditional areas are taxed with a 30% rate. 

 

33 

2011: 

2010 

Asset (Liability) 

Income (Loss) 

Recognized in income 

2011 

Asset (Liability) 

Net deferred tax at 

December 31, 2011 

(see Note 13) 

U.S. DollarsAccounts receivable 3,200 — 6,456 — 9,656 — 9,656 

Property, plant, and equipment 18,184 (6,862 ) 44,336 (1,352 ) 62,520 (8,214 ) 54,306 

Inventories — (987 ) 5,169 — 4,182 — 4,182 

Accruals and other liabilities 38,821 (522 ) 39,883 130 78,704 (392 ) 78,312 

 

 60,205 (8,371 ) 95,844 (1,222 ) 155,062 (8,606 ) 146,456 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BolivarsAccounts receivable 13,760 — 27,761 — 41,521 — 41,521 

Property, plant and equipment 78,191 (29,507 ) 190,645 (5,813 ) 268,836 (35,320 ) 233,516 

Inventories — (4,244 ) 22,227 — 17,983 — 17,983 

Accruals and other liabilities 166,930 (2,244 ) 171,497 558 338,427 (1,686 ) 336,741 

 

 258,881 (35,995 ) 412,130 (5,255 ) 666,767 (37,006 ) 629,761 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2010: 

2009 

Asset (Liability) 

Income (Loss) 

Recognized in 

income 

Effect 

For 

variation 

in the 

exchange 

rat 

Effect of 

prior year 

adjustment 

2010 

Asset (Liability) 

Net deferred tax at 

December 31, 2010 

(see Note 13) 

U.S. DollarsAccounts receivable — (2.653 ) 4.527 — 1.326 — 3.200 — 3.200 

Property, plant and 

equipment 104.556 (7.179 ) (86.372 ) — — 317 18.184 (6.862 ) 11.322 

Inventories 4.520 — — (5.507 ) — — — (987 ) (987 ) 

Accruals and other 

liabilities 34.822 — 15.306 (522 ) (11.307 ) — 38.821 (522 ) 38.299 

 

 143.898 (9.832 ) (66.539 ) (6.029 ) (9.981 ) 317 60.205 (8.371 ) 51.834 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BolivarsAccounts receivable — (5.704 ) 19.464 — — — 13.760 — 13.760 

Property, plant and 

equipment 224.796 (15.435 ) (371.400 ) — 209.360 1.363 78.191 (29.507 ) 48.684 

Inventories 9.717 — (23.680 ) — 9.719 — — (4.244 ) (4.244 ) 

Accruals and other 

liabilities 74.868 — 65.818 (2.244 ) 26.244 — 166.930 (2.244 ) 164.686 

 

 309.381 (21.139 ) (309.798 ) (2.244 ) 245.323 1.363 258.881 (35.995 ) 222.886 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 (g) Royalties 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

The partial reform of the Hydrocarbon Law was approved in May 2006, whereby operators should pay 33.33% of the 

wellhead value of each barrel to the Venezuelan government by means of royalties and additional taxes. 

On November 14, 2006, a new calculation of royalties was established for companies that conduct primary oil activities in 

the country requiring that contents of sulphur and API gravity of liquid hydrocarbons extracted be measured on a monthly 

basis and be reported together with taxed production. This information will be part of the royalty payment price and will be 

used for calculation of any special advantage. This information will result in adjustments for gravity and sulphur, which will 

be published by Ministry of Popular Power for Energy and Mining (MPPPM). 

On April 18, 2011, the Venezuelan government published in the Extraordinary Official Gazette No. 6.022, by means of 

decree-law No. 8.163 of same date, the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices 

in the International Hydrocarbons Market (see Note 23-j). This Law, among other things, caps royalty, extraction tax, and 

export register tax at US$.70 per barrel. On October 3, 2011, the Company received accounting guidelines from CVP, to 

account for revenues from the sale of crude oil, royalty paid in kind and extraction tax according to this law. In regards to 

royalty for the volume of 30% of produced crude, the Company values and records the amount due for this concept at the 

US$.70 per barrel caps price from the date following the publication of the law and not according to the selling price of the 

barrel of crude. Royalty under prior Law and current Law for the years ended December 31, 2012, 2011 and 2010 amounted 

to US$.280,909 thousands, US$.263,422 thousands and US$.183,076 thousands (Bs.1,207,909 thousands, Bs.1,132,715 

thousands and Bs.787,227 thousands), respectively, included in the statements of comprehensive income under royalties and 

other taxes (see Note 21 and 24-d). 

 

The Venezuelan Hydrocarbon Law Reform establishes a rate equivalent to 33.33% of the value of all liquid hydrocarbons 

extracted from any reservoir, calculated on the same basis as for royalties. In determining this tax, the taxpayer may deduct 

the amount that would have been paid for royalty, including the additional royalty paid as special advantage. Petrodelta, S.A. 

incurred no tax in this connection for 2012, 2011 and 2010. 

 

The Venezuelan Hydrocarbon Law establishes a surface tax equivalent to 100 tax units for each square kilometer or fraction 

thereof per year for licensed areas that are not under production. This tax will increase by 2% during the first five years, and 

by 5% during all subsequent years. Petrodelta, S.A. incurred in this tax during 2012, 2011 and 2010 for US$.558 thousands, 

US$.235 thousands and US$.201 thousands (Bs.2,399 thousands, Bs.1,011 thousands and Bs.865 thousands), respectively, 

included in the statements of comprehensive income under royalties and other taxes. 

 

34 

 (h) Extraction Tax 

 (i) Surface Tax 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

The Venezuelan Hydrocarbon Law Reform establishes an internal consumption tax equivalent to 10% of the value of each 

cubic meter of hydrocarbon derivatives produced and consumed as fuel in internal operations, calculated on the final selling 

price. During the year ended December 31, 2012, Ministry of Popular Power for Energy and Mining (MPPPM) sent to the 

Company the tax return to pay for this tax corresponding to the period starting January 2007 to September 2012 for the 

amount of US$.1,193 thousands (equivalent to Bs.5,128 thousands), whereas corresponding to the year 2012 are US$.207 

thousands (Bs.890 thousands) and corresponding to the period 2007 to 2011 the amount of US$.986 thousands (Bs.4,638 

thousands). All this tax levied was recorded in the statement of comprehensive income during the year 2012. 

 

On March 26, 2009, under Official Gazette No. 39,147 modification of applicable tax rate for value added tax to 12% was 

published, having effect from April 1, 2009 to the report date. 

The VAT Law establishes an exemption on trading of certain hydrocarbon-derived fuels and also has authority to recover 

from the government certain tax credits originated from sales. Recoverable amounts bear no interest. 

Below is a summary of the movement of recoverable tax credits (in thousands): 

 

The Company management considers that the efforts made and agreements reached with the Government will permit to 

recover part of the tax credits during the year 2013. 

At December 31, 2012, the Company estimated the fair value of the tax credits to recover using the discount rate of 8.783%. 

At December 31, 2011 and 2010, the Company estimated the fair value of these tax credits to recover using a discount rate 

of 13.017%. These discount rates are calculated yearly by its main shareholder yearly with the financial statements of the 

prior year and using outside parameters updated each year. Furthermore, during the year ended December 31, 2011 

Management modified the years estimated to recover the tax credits from 2.5 years to 3 years. At December 31, 2012, 2011 

and 2010, the adjustment for US$.1.339 thousands, US$.6,623 thousands and US$.3,951 thousands (Bs.5.759 thousands, 

Bs.28,477 thousands and Bs.16,989 thousands), respectively, is included in the statements of comprehensive income under 

the category of financial expenses. 

 

35 

 (j) General Consumption Tax 

 (k) Value Added Tax (VAT) 

 December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolivars 

Recoverable amounts at the beginning of the year 25,858 13,453 17,922 111,193 57,848 38,532 

Generated during the year 20,062 19,028 8,443 86,268 81,822 36,305 

Adjustment to fair value (1,339 ) (6,623 ) (3,951 ) (5,759 ) (28,477 ) (16,989 ) 

Effect for variation in the exchange rate — — (8,961 ) — — — 

 

Recoverable amounts at the end of the year 44,581 25,858 13,453 191,702 111,193 57,848 

Non-current portion of recoverable tax credits (29,721 ) (17,239 ) (8,072 ) (127,801 ) (74,129 ) (34,710 ) 

 

Current portion of recoverable tax credits (See Note 11) 14,860 8,619 5,381 63,901 37,064 23,138 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

In April 2008, the National Executive of the Venezuelan Bolivarian Republic, by means of a decree-law, established a 

special contribution over extraordinary prices of the international hydrocarbons market, amended in July 2008, which levies 

the sale of crude oil whenever the average price for the month in question of the Venezuelan oil production exceeds the price 

of US$.70/barrel. The amount of said contribution equals 50% of the difference resulting of the average price per month and 

the aforementioned cap of US$.70/barrel. In addition, this decree-law sets forth that whenever the average price per month 

exceeds the price of US$.100/barrel, the total amount of said special contribution will be equivalent to 60% of the above 

defined difference (see Note 23-k). This law was superseded by the Law Creating a Special Contribution on Extraordinary 

Prices and Exorbitant Prices in the International Hydrocarbons Market (see Note 23-j) published on April 18, 2011. During 

the period this law was in effect until it was superseded on April 19, 2011, Petrodelta, S.A. incurred in this tax as of 

December 31, 2011 and 2010 US$.38,244 thousands and US$.14,116 thousands (Bs.164,449 thousands and Bs.60,697 

thousands), respectively, included in the statements of comprehensive income under royalties. 

 

On April 18, 2011, was published in the Extraordinary Official Gazette No. 6.022, by means of decree-law No. 8.163 of 

same date, the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International 

Hydrocarbons Market. This law supersedes the law on special contributions over extraordinary prices on the International 

Hydrocarbons Market (see Note 23-j), modifies the scheme to determine and pay royalty, extraction tax and export registry 

tax as per the LOH and creates a special contribution for extraordinary prices and exorbitant prices from the day after the 

law was published (see Note 23-k). From the date this law came into effect, April 19, 2011, Petrodelta S.A. incurred as 

special contribution from extraordinary prices and special contribution from exorbitant prices included in the statement of 

comprehensive income for the year ended December 31, 2012 and 2011 the amounts of US$.291,355 thousands and 

US$.199,388 thousands (Bs.1,252,827 thousands and Bs.857,368 thousands), respectively (see Notes 23-j and 24-d). 

 

The Company is subject to special advantage taxes, which are determined based on: a) an interest as additional royalty of 

3.33% on volumes of hydrocarbons extracted in the delimited areas assigned to Petrodelta S.A., and b) an amount equivalent 

to the difference, if any, between (i) 50% of the value of the hydrocarbons extracted in the delimited areas assigned to 

Petrodelta S.A. in each calendar year and (ii) the sum of payments made by the mixed companies to the Bolivarian Republic 

of Venezuela, for activities developed during the calendar year, for royalties on hydrocarbons and investments in 

endogenous development projects, equivalent to 1% of pre-tax income. Taxes for special advantages must be paid before 

April 20 of each year, pursuant to Exhibit F of the Agreement for Conversion into a 

 

36 

 (l) Law on Special Contributions over Extraordinary Prices of the International Hydrocarbons Market 

 

(m) Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons 

Market 

 (n) Other taxes 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Mixed Company. In relation to a) above, and the law that came into effect, published on April 18, 2011, creating a special 

contribution on extraordinary prices and exorbitant prices in the international hydrocarbons market (see Note 23-j), which 

establishes a caps price of US$.70 per barrel, Petrodelta, S.A. incurred in this tax during 2012, 2011 and 2010 for 

US$.31,181 thousands, US$.29,187 thousands and US$.20,367 thousands (Bs.134,078 thousands, Bs.125,504 thousands and 

Bs.87,578 thousands), respectively, included in the statements of comprehensive income under royalties. In relation to b) 

above, at December 31, 2012, 2011 and 2010, this special advantage tax was lower than what the Company paid and accrued 

for royalties and special advantages tax. 

Official Gazette No. 39.273 of the Bolivarian Republic of Venezuela, published on September 28, 2009, approved the 

modification of article regulating special advantages tax levied on mix companies to redistribute the use of funds by the 

additional royalty of 3.33% that mix companies have to pay on hydrocarbons volumes extracted from delimited areas. The 

modified article establish deliver 1.11% to municipalities where oil activities in the country take place and 2.22% for a 

special fund to be administered by the Executive branch to finance endogenous development projects. 

 

37 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Property, plant, and equipment, net at December 31 comprises the following (in thousands): 

 

 

38 

(8) Property, Plant, and Equipment, Net 

U.S. DollarsWells and 

production 

facilities 

Construction 

in progress 

Asset 

retirement 

costs 

Furniture 

and 

equipment 

Strategic 

inventories Total 

Cost: 

Balances at December 31, 2009 287,390 32,912 19,882 7,466 12,114 359,764 

Additions — 98,650 — 3,149 — 101,799 

Transfers and capitalization 52,807 (52,807 ) — — — — 

Retirements (35 ) — — — — (35 ) 

Strategic inventories — — — — (7,018 ) (7,018 ) 

Asset retirement obligation — — 2,043 — — 2,043 

 

Balances at December 31, 2010 340,162 78,755 21,925 10,615 5,096 456,553 

Additions — 132,995 — 4,961 — 137,956 

Transfers and capitalization 100,495 (100,495 ) — — — — 

Strategic inventories — — — — 1,124 1,124 

Asset retirement obligation — — 7,644 — 7,644 

 

Balances at December 31, 2011 440,657 111,255 29,569 15,576 6,220 603,277 

Additions — 177,349 — 6,871 — 184,220 

Transfers and capitalization 167,517 (167,517 ) — — — — 

Strategic inventories — — — — 6,742 6,742 

Asset retirement obligation — — 23,229 — — 23,229 

 

Balances at December 31, 2012 608,174 121,087 52,798 22,447 12,962 817,468 

 

Depletion, depreciation and amortization— 

Balances at December 31, 2009 85,919 — 5,524 2,879 — 94,322 

Depletion, depreciation, and amortization 36,490 — 2,677 1,262 — 40,429 

Retirements (14 ) — — — — (14 ) 

 

Balances at December 31, 2010 122,395 — 8,201 4,141 — 134,737 

Depletion, depreciation, and amortization 51,753 — 4,940 1,682 — 58,375 

 

Balances at December 31, 2011 174,148 — 13,141 5,823 — 193,112 

Depletion, depreciation, and amortization 80,362 — 2,806 2,837 — 86,005 

 

Balances at December 31, 2012 254,510 — 15,947 8,660 — 279,117 

 

 

 

 

 

 

 

 

 

 

 

 

Total net cost at December 31, 2012 353,664 121,087 36,851 13,787 12,962 538,351 

 

 

 

 

 

 

 

 

 

 

 

 

Total net cost at December 31, 2011 266,509 111,255 16,428 9,753 6,220 410,165 

 

 

 

 

 

 

 

 

 

 

 

 

Total net cost at December 31, 2010 217,767 78,755 13,724 6,474 5,096 321,816 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

During the years ended December 31, 2012, 2011, and 2010 the Company added production assets and construction in progress for 

approximately US$.184,220 thousands, US$.137,956 thousands and US$.101,799 thousands (Bs.792,147 thousands, Bs.593,211 

thousands and Bs.437,737 thousands), respectively. 

During the years ended December 31, 2012, 2011 and 2010, the Company assessed asset impairment, taking into account new market and 

business conditions, and determined that there was no evidence of impairment of production assets. 

At December 31, 2012, 2011 and 2010, accruals and other payables include US$.23,229 thousands, US$.7,644 thousands and US$.2,043 

thousands (Bs.99,886 thousands, Bs.32,869 thousands and Bs.8,785 thousands), respectively, in respect of the provision for asset 

retirement obligation (see Note 14). 

 

39 

BolivarsWells and 

production 

facilities 

Construction 

in progress 

Asset 

retirement 

costs 

Furniture 

and 

equipment 

Strategic 

inventories Total 

Cost: 

Balances at December 31, 2009 617,889 70,760 42,746 16,052 26,045 773,492 

Additions — 424,196 — 13,541 — 437,737 

Transfers and capitalization 227,070 (227,070 ) — — — — 

Retirements (151 ) — — — — (151 ) 

Strategic inventories — — — — (30,177 ) (30,177 ) 

Asset retirement obligation — — 8,785 — — 8,785 

Effect for variation in the presentation currency 617,889 70,760 42,746 16,052 26,045 773,492 

 

Balances at December 31, 2010 1,462,697 338,646 94,277 45,645 21,913 1,963,178 

Additions — 571,879 — 21,332 — 593,211 

Transfers and capitalization 432,129 (432,129 ) — — — — 

Strategic inventories — — — — 4,833 4,833 

Asset retirement costs — — 32,869 — — 32,869 

 

Balances at December 31, 2011 1,894,826 478,396 127,146 66,977 26,746 2,594,091 

Additions — 762,602 — 29,545 — 792,147 

Transfers and capitalization 720,323 (720,323 ) — — — — 

Strategic inventories — — — — 28,991 28,991 

Asset retirement obligation — — 99,886 — — 99,886 

 

Balances at December 31, 2012 2,615,149 520,675 227,032 96,522 55,737 3,515,115 

 

Depletion, depreciation and amortization— 

Balances at December 31, 2009 184,726 — 11,876 6,190 — 202,792 

Depletion, depreciation and amortization 156,907 — 11,511 5,427 — 173,845 

Retirements (60 ) — — — — (60 ) 

Effect for variation in the presentation currency 184,726 — 11,876 6,190 — 202,792 

 

Balances at December 31, 2010 526,299 — 35,263 17,807 — 579,369 

Depletion, depreciation and amortization 222,538 — 21,242 7,233 — 251,013 

 

Balances at December 31, 2011 748,837 — 56,505 25,040 — 830,382 

Depletion, depreciation and amortization 345,555 — 12,067 12,199 — 369,821 

 

Balances at December 31, 2012 1,094,392 — 68,572 37,239 — 1,200,203 

 

 

 

 

 

 

 

 

 

 

 

 

Total net cost at December 31, 2012 1,520,757 520,675 158,460 59,283 55,737 2,314,912 

 

 

 

 

 

 

 

 

 

 

 

 

Total net cost at December 31, 2011 1,145,989 478,396 70,641 41,937 26,746 1,763,709 

 

 

 

 

 

 

 

 

 

 

 

 

Total net cost at December 31, 2010 936,398 338,646 59,014 27,838 21,913 1,383,809 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

The balance of construction in progress mainly comprises investment projects for exploration and production activities related to drilling, 

maintenance, electrical systems, pipelines, well reconditioning and adaptation, expansion and infrastructure aimed at maintaining 

production capacity and adapting the infrastructure to production levels set out in the Corporation’s business plan. At December 31, 2012, 

2011 and 2010, the balance of construction in progress for investments related to the aforementioned activities amounts to approximately 

US$.121,087 thousands, US$.111,255 thousands and US$.78,755 thousands (Bs.520,675 thousands, Bs.478,396 thousands and 

Bs.338,646 thousands), respectively. 

 

Prepaid expenses and other assets comprise the following (in thousands): 

 

 

A summary of inventories is shown below (in thousands): 

 

 

40 

(9) Prepaid expenses and other assets 

 December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolivars 

Prepaid insurance 669 304 293 2,877 1,307 1,260 

Prepaid services 450 177 72 1,935 761 310 

Prepaid rent 42 42 42 181 180 180 

 

 1,161 523 407 4,993 2,248 1,750 

 

 

 

 

 

 

 

 

 

 

 

 

(10) Inventories 

 December 31, 

 2012 2011 2010 2012 2011 2010 

 Dólares Bolívares 

Materials and supplies 90,640 43,072 30,168 389,752 185,209 129,723 

Less: 

Inventory obsolescence provision (See Note 3-i) (41 ) (58 ) (75 ) (176 ) (249 ) (323 ) 

Materials and supplies classified as strategic inventory in other non-current 

assets (see Note 8) (12,962 ) (6,220 ) (5,096 ) (55,737 ) (26,746 ) (21,913 ) 

 

 77,637 36,794 24,997 333,839 158,214 107,487 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Accounts receivable comprise the following (in thousands): 

 

During the years ended December 31, 2012, 2011 and 2010, the Company offset accounts receivables and payables between PDVSA and 

its affiliates, including CVP with the Company in the amounts approximately of US$.565 million, US$.374 million and US$.281 million, 

respectively. These offsetting of accounts were approved by the Board of Directors of the Company. Exposure to credit risk related to 

accounts receivable are presented in Note 19. 

As of December 31, 2012 accounts receivable from sales of crude from El Salto field and for which shall be invoiced under the Boscán 

pricing formula once the amendment of the contract is approved and the contract is executed amounts to US$.352,721 thousands 

(Bs.1,516,704 thousands), whereas US$.301,950 thousands (Bs.1,298,386 thousands) corresponds to the year ended December 31, 2012 

and US$.50,772 thousands (Bs.218,319 thousands) corresponds to the period of October 2011 to December 2011 (see Note 1 and 24-a). 

Advances on windfall tax at December 31, 2012 corresponds to payments made by PDVSA Petroleo, on behalf of the Company, to 

MPPPM for special contributions on extraordinary prices and exorbitant prices in the international hydrocarbons market for the fourth 

quarter ending December 31, 2012 in the amount of US$.64,694 thousands (Bs.278,185 thousands). 

 

Cash and cash equivalent comprises the following (in thousands): 

 

 

41 

(11) Accounts Receivable 

 December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolivars 

Related parties (see Note 21) 1,232,199 912,652 499,313 5,298,456 3,924,404 2,147,046 

Current portion of recoverable tax credits (see Note 7 - k) 14,860 8,619 5,381 63,901 37,064 23,138 

Advances on windfall tax 64,694 — — 278,185 — — 

Other 1,549 1,517 1,662 6,660 6,523 7,147 

 

 1,313,302 922,788 506,356 5,647,202 3,967,991 2,177,331 

 

 

 

 

 

 

 

 

 

 

 

 

(12) Cash and Cash Equivalents 

 December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolivars 

Cash on hand 5 5 5 22 22 22 

Cash at banks 3,330 2,337 3,460 14,314 10,049 14,878 

 

 3,335 2,342 3,465 14,336 10,071 14,900 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Capital stock 

At December 31, 2012, 2011 and 2010, the Company’s nominal capital stock is represented by 1,500,000 common shares, fully 

authorized and paid in, with a par value of US$.4.65 each (Bs.10 each). 

The Company’s capital stock is divided into two types of shares: Class “A” and Class “B” shares. Only the Venezuelan government or 

Venezuelan state-owned companies can own Class “A” shares. In October 2007, when the Company was incorporated, shareholders 

made an initial capital contribution of approximately Bs.1,000 thousands (US$.465,000). Capital stock has been fully subscribed and paid 

in as follows: 

 

Legal Reserve 

Venezuelan companies are required to set aside a legal reserve. According to Venezuelan Law, the legal reserve is not available for 

dividend distribution. 

Deferred Tax Asset Equity Reserve 

In June 2009, CVP issued instructions to all mixed companies regarding the accounting for deferred tax assets. The mixed companies 

have been instructed to set up a reserve within the equity section of the balance sheet for deferred tax assets. The setting up of the reserve 

had no effect on the Company financial position, results of operations or cash flows. However, the new reserve reduces the amount of 

reserves available to pay of dividends in the future. Changes in the deferred tax asset are recorded in appropriation to (transfer from) other 

reserves. 

In August 2009, the Board of Directors of the Company approved the creation of the deferred tax asset equity reserve with retained 

earnings accumulated to end of June 2009 for US$.116,273 thousands (Bs.249,987 thousands). At December 31, 2012, 2011 and 2010, 

management has recorded as equity reserve and amount equal to the balance of the net of deferred tax asset and liability at that date 

equivalent to US$.70,426 thousands, US$.146,456 thousands and US$.51,834 thousands (Bs.302,832 thousands, Bs.629,761 thousands 

and Bs.222,886 thousands), respectively (see Note 7-f), which has been approved by the Board of Directors of the Company. At this date 

the financial statements for the year ended December 31, 2012, 2011 and 2010 have not been approved by the Shareholders and, 

consequently, the creation of the equity reserve for deferred tax asset has not been approved (see Note 24-e). 

 

42 

(13) Equity 

Shareholders 

Type of 

shares 

Number of 

shares US$. Bs. 

Share of 

equity 

Corporación Venezolana del Petróleo, S,A, (CVP) A 900,000 4,186,047 9,000,000 60 % 

HNR Finance, B,V, (HNR Finance) B 600,000 2,790,698 6,000,000 40 % 

 

 1,500,000 6,976,745 15,000,000 100 % 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Share premium 

The share premium is in respect of contributions of fixed assets and inventories made by shareholders in conformity with the Agreement 

for Conversion into a Mixed Company, whose value exceeds the par value of common shares issued. At December 31, 2012, 2011 and 

2010, the share premium amounts to approximately US$.212,451 thousands, equivalent to approximately Bs.456,770 thousands, included 

in equity. 

Class “A” share premiums are in respect of fixed assets contributed by CVP. The value of this share premium amounts to approximately 

US$.191,206 thousands, equivalent to approximately Bs.411,093 thousands, pursuant to Exhibit H of the Agreement for Conversion into 

a Mixed Company. 

Class “B” share premiums are in respect of fixed assets and inventories contributed by HNR Finance. The value of this share premium 

amounts to approximately US$.21,245 thousands, equivalent to approximately Bs.45,677 thousands, pursuant to Exhibit G of the 

Agreement for Conversion into a Mixed Company. 

In conformity with the Company’s bylaws, in case of Company liquidation, all assets will be transferred only to the Class “A” 

shareholder. 

Dividends 

On November 12, 2010, in Extraordinary Shareholders meeting the shareholders of the Company resolved to distribute and pay dividends 

in the amount of US$.30,550 thousands (Bs.131,365 thousands). This dividend corresponds to the remaining portion of retained earnings 

at the end of December 31, 2009 and is recorded as dividends payable at December 31, 2012 and 2011 in the statements of financial 

position for the amount resolved. 

On August 4, 2010, in Extraordinary Shareholders meeting the shareholders resolved to pay dividends based on retained earnings as of 

December 31, 2009 in the amount of US$.30,550 thousands (Bs.131,365 thousands). The dividend approved was paid on October 2010 to 

HNR Finance for its share in the Company in the amount of US$.12,220 thousands (Bs.52,546 thousands). At December 31, 2011 the 

portion of the dividend corresponding to CVP for US$.18,330 thousands (Bs.78,819 thousands) was paid by means of offsetting accounts 

receivable and payables between PDVSA and its Affiliates, including CVP, this transaction was approved by the board on January 12, 

2012 (see Note 21). 

 

43 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Effect for Variation of the Exchange Rate in the Presentation Currency 

The statement of changes in equity expressed in bolivars for the year ended December 31, 2010, includes the following effect originated 

for the variation of the official exchange rate when converting the financial statements from U.S. Dollars, (functional currency) to 

bolivars (presentation currency), in conformity with IAS 21 (see Note 3-a) (in thousands, net of restructured): 

 

In Board of Director meeting dated 10 March 2011 it was approved the proposal to submit for consideration to the Shareholders the 

distribution of the cumulative translation adjustment among the components of equity. At December 31, 2012 and 2011, this distribution 

is pending of approval by the shareholders of the Company. The following table shows the amounts at December 31, 2012 of different 

components of equity with the distribution of the translation adjustment once the shareholders of the Company have approved it (in 

thousands): 

 

 

44 

 Balances as of December 31, 2009 

 U.S. Dollars 

Bolivars 

before 

translation 

adjustment 

Bolivars after 

translation 

adjustment 

Translation 

adjustment 

Capital stock 6,977 15,000 30,000 15,000 

Shares premium 212,451 456,770 913,540 456,770 

Legal reserve and other reserves 134,764 289,742 579,484 289,742 

Retained earnings 70,729 152,068 304,136 152,068 

 

 424,921 913,580 1,827,160 

 

 

 

 

 

 

 

Translation adjustment 913,580 

 

 

 Balances as of December 31, 2012 

 

U.S. 

Dollars 

Bolivars 

Before 

translation 

adjustment 

Bolivars 

After 

translation 

adjustment 

Translation 

Adjustment 

Capital stock 6,977 15,000 30,000 15,000 

Share premium 212,451 456,770 913,541 456,771 

Legal reserve and other reserves 

Legal reserve 698 1,500 3,000 1,500 

Deferred tax equity reserve 70,426 302,832 302,832 — 

 

 71,124 304,332 305,832 1,500 

 

Retained earnings: 

Undistributable retained earnings at January 1, 2012 307,699 882,797 1,323,106 440,309 

Transfer from other reserves in 2012 76,030 326,928 326,928 — 

Total comprehensive income for the year 2012 85,993 369,769 369,769 — 

 

 469,722 1,579,494 2,019,803 440,309 

 

Equity 760,274 2,355,596 3,269,176 — 

 

 

 

 

 

 

 

 

Translation adjustment not allocated 913,580 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Provisions at December 31 comprise the following (in thousands): 

 

At December 31, 2012, 2011 and 2010, the provision for retirement benefits for personnel assigned to the Company amounts to 

US$.18.799 thousands, US$.11,556 thousands and US$.8,444 thousands, (Bs.80,835 thousands, Bs.49,691 thousands and Bs.36,309 

thousands), respectively. At December 31, 2012, 2011 and 2010, PDVSA sent a statement for the liability according to the report of an 

independent actuary firm. The Company has analyzed demographic and financial data, considers that it reasonably reflects the liability 

for such concept and adjusted the obligation at the date of the statements of financial position. This pension and retirement plan covers all 

PDVSA employees and mixed companies payroll. Pension cost is not tax deductible until future periods when the pension is settled in 

cash. The Company is not required to reimburse the pension costs to PDVSA until PDVSA pays them. 

Below are the movements of provisions during the year 2012, 2011 and 2010, (in thousands): 

 

 

45 

(14) Provisions 

 December 31, 

 2012 2011 2010 2012 2011 2010 

 Dólares Bolívares 

Provision for asset retirement costs (see Note 14) 70,425 41,518 29,798 302,828 178,527 128,131 

Provision for retirement benefits 18,799 11,556 8,444 80,835 49,691 36,309 

Provision for benefits payable 3,878 — — 16,676 — — 

Commitments and Contingencies (see Note 20) 1,563 1,799 2,093 6,719 7,736 9,000 

 

 94,665 54,873 40,335 407,058 235,954 173,440 

Less: Non-current portion of provisions (93,096 ) (53,068 ) (38,237 ) (400,314 ) (228,193 ) (164,419 ) 

 

Current portion 1,569 1,805 2,098 6,744 7,761 9,021 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. DollarsBalance at 

December 31, 

2011 Increase Decrease 

Balance at 

December 31, 

2012 

Current 

portion 

Noncurrent 

portion 

Provision for asset retirement costs 41,518 28,907 — 70,425 — 70,425 

Provision for retirement benefits 11,556 7,243 — 18,799 6 18,793 

Provision for benefits payable — 3,878 — 3,878 — 3,878 

Commitments and Contingencies (see Note 20) 1,799 — (236 ) 1,563 1,563 — 

 

Total provisions 54,873 40,028 (236 ) 94,665 1,569 93,096 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

 

 

 

46 

U.S. DollarsBalance at 

December 31, 

2010 Increase Decrease 

Balance at 

December 31, 

2011 

Current 

portion 

Noncurrent 

portion 

Provision for asset retirement costs 29,798 11,720 — 41,518 — 41,518 

Provision for retirement benefits 8,444 3,112 — 11,556 6 11,550 

Commitments and Contingencies (see Note 20) 2,093 — (294 ) 1,799 1,799 — 

 

Total provisions 40,335 14,832 (294 ) 54,873 1,805 53,068 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. DollarsBalance at 

December 

31, 2009 

Effect for 

variation 

in the 

presentation 

currency Increase Decrease 

Balance at 

December 

31, 2010 

Current 

portion 

Noncurrent 

portion 

Provision for asset retirement costs 24,416 — 5,382 — 29,798 — 29,798 

Provision for retirement benefits 9,184 (9,184 ) 13,036 (4,592 ) 8.444 5 8,439 

Commitments and Contingencies (see Note 20) — — 2,093 — 2,093 2,093 — 

 

Total provisions 33,600 (9,184 ) 20,511 (4,592 ) 40,335 2,098 38,237 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BolivarsBalance at 

December 31, 

2011 Increase Decrease 

Balance at 

December 31, 

2012 

Current 

portion 

Noncurrent 

portion 

Provision for asset retirement costs (see Note 9) 178,527 124,301 — 302,828 — 302,828 

Provision for retirement benefits 49,691 31,144 — 80,835 25 80,810 

Provision for benefits payable — 16,676 — 16,676 — 16,676 

Commitments and Contingencies (see Note 20) 7,736 (1,017 ) 6,719 6,719 — 

 

Total provisions 235,954 172,121 (1,017 ) 407,058 6,744 400,314 

 

 

 

 

 

 

 

 

 

 

 

 

BolivarsBalance at 

December 31, 

2010 Increase Decrease 

Balance at 

December 31, 

2011 

Current 

portion 

Noncurrent 

portion 

Provision for asset retirement costs 128,131 50,396 — 178,527 — 178,527 

Provision for retirement benefits 36,309 13,382 — 49,691 25 49,666 

Commitments and Contingencies (see Note 20) 9,000 (1,264 ) 7,736 7,736 

 

Total provisions 173,440 63,778 (1,264 ) 235,954 7,761 228,193 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

The movement of the provision for asset retirement costs at December 31 is shown below (in thousands): 

 

During 2012, Company management reviewed, based on new information, estimates on assumptions used for calculating the provision 

for asset retirement costs and modified the discount rate from 12.47% to 9.02% and the inflation rate from 2.48% to 2.41% which 

resulted in an increase in the estimation of the liability for this concept. 

At December 31, 2012, 2011 and 2010, the variation of the estimation in of the provision for well abandonment cost of US$.23,229 

thousands, US$.7,644 thousands and US$.2,043 thousands (Bs.99,886 thousands, Bs.32,869 thousands and Bs.8,785 thousands) is 

included the balance of property, plant and equipment (see Note 8). The Petrodelta, S.A. business plan as of December 31, 2012, 

contemplates the realization of hydrocarbons drilling and production activities until the year 2027; therefore, the accrual for asset 

retirement costs was calculated based on the disbursements for this concept during this period. 

 

47 

BolivarsBalance at 

December 31, 

2009 

Effect for 

variation in 

the 

presentation 

currency Increase Decrease 

Balance at 

December 31, 

2010 

Current 

portion 

NonCurrent 

portion 

Provision for asset retirement costs 52,494 52,494 23,143 — 128,131 — 128,131 

Provision for retirement benefits 19,746 — 36,309 (19,746 ) 36,309 21 36,288 

Commitments and Contingencies (see Note 20) — — 9,000 — 9,000 9,000 — 

 

Total provisions 72,240 52,494 68,452 (19,746 ) 173,440 9,021 164,419 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 U.S. Dollars Bolivars 

Balance at December 31, 2009 24,416 52,494 

Change on estimation 2,043 8,785 

Financial cost 3,339 14,358 

Effect for variation in the presentation currency — 52,494 

 

Balance at December 31, 2010 29,798 128,131 

Change on estimation 7,644 32,869 

Financial cost 4,076 17,527 

 

Balance at December 31, 2011 41,518 178,527 

Change on estimation 23,229 99,886 

Financial cost 5,678 24,415 

 

Balance at December 31, 2012 70,425 302,828 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Accruals and other liabilities at December 31 comprise the following (in thousands): 

 

Additionally, at December 31, 2012, 2011 and 2010, accruals and other payables include the accruals in respect of drilling services and 

infrastructure totaling US$.143,174 thousands, US$.63,879 thousands and US$.61,231 thousands (Bs.615,651 thousands, Bs.274,680 

thousands and Bs.263,293 thousands), respectively. 

 

Accounts payable comprise the following (in thousands): 

 

Foreign currency and liquidity risk exposure in respect of accounts payable to suppliers is shown in Note 19. 

 

48 

(15) Accruals and Other Liabilities 

 December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolivars 

Royalties 130,709 106,805 30,842 562,049 459,262 132,621 

Endogenous and social development 11,431 8,005 3,922 49,153 34,422 16,865 

Antidrug National Fund 13,828 10,746 7,418 59,461 46,208 31,897 

Science and Technology (LOCTI) 8,292 3,054 4,583 35,656 13,132 19,707 

Sport Organic Law 4,192 1,110 — 18,026 4,773 — 

Others: 

Accrued payables with PDVSA (see Note 21) 213,173 67,570 68,561 916,644 290,551 294,812 

Accrued payables to suppliers 119,209 58,888 48,442 512,599 253,218 208,302 

Income taxes withheld 1,185 1,509 2,888 5,096 6,489 12,418 

Other accruals 8,529 5,284 2,661 36,679 22,721 11,442 

 

 510,548 262,971 169,317 2,195,363 1,130,776 728,064 

 

 

 

 

 

 

 

 

 

 

 

 

(16) Accounts Payable 

 December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolivars 

Trade payables 94,747 68,815 21,022 407,412 295,905 90,395 

Related parties (see Note 21) 450,184 271,938 31,073 1,935,791 1,169,336 133,614 

 

Total 544,931 340,753 52,095 2,343,203 1,465,241 224,009 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Below is a summary of operational expenses incurred by the Company (in thousands): 

 

 

Financial income and expenses comprised the following (in thousands): 

 

Gain on variation of exchange rate 

On January 8, 2010, the Ministry of Finance and BCV published Exchange Agreement No. 14, in the Official Gazette No. 39.342, which 

went into effect January 11, 2010. This Exchange Agreement modified the official exchange rate for the purchase and sale of foreign 

currency denominated in U.S. Dollars. Therefore, all transactions and balances in Bolivars were converted to U.S. Dollars as per the new 

exchange rate, resulting in a net gain for the variation effect in the exchange rate due to the fact of maintaining a net liability monetary 

position in bolivars at the date when the variation of the exchange rate went into effect (see Note 4). 

Financial cost transferred from related party 

In accordance with Foreign Exchange Agreement 9, published in Official Gazette 38,318, dated November 21, 2005, currencies from the 

export of hydrocarbons that the Company sells PDVSA, must be sold to the BCV, except for those to be used at activities performed by 

PDVSA pursuant to the Amendment to the BCV Law, which compels the Company to sell to the BCV only the 

 

49 

(17) Operational Expenses 

 Years ended December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolivars 

Crude and gas operations 97,562 63,570 34,120 419,517 273,351 146,716 

Crude transportation 29,610 27,200 12,220 127,323 116,960 52,546 

Others 11,433 14,980 7,319 49,162 64,414 31,472 

 

 138,605 105,750 53,659 596,002 454,725 230,734 

 

 

 

 

 

 

 

 

 

 

 

 

(18) Financial Income and Expenses 

 Years ended December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolivars 

Financial income: 

Gain on variation of exchange rate — — 84,439 — — 363,088 

Other financial income — 7 9 — 30 38 

 

 — 7 84,448 — 30 363,126 

 

 

 

 

 

 

 

 

 

 

 

 

Financial expenses 

Adjustment to net realizable value on financial assets (see Note 7-k) 1,339 6,623 3,951 5,758 28,477 16,989 

Financial cost transferred from related party — — 19,475 — — 83,743 

Financial cost on provision for asset retirement costs (see Note 14) 5,678 4,076 3,339 24,415 17,527 14,358 

Other financial expenses 6 3 2 26 13 8 

 

 7,023 10,702 26,767 30,199 46,017 115,098 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

cash flows in currencies, other than local currencies, required to meet its obligations in bolivars. As of January 11, 2010, payment of 

those transactions with the BCV was made at the exchange rates of Bs.4.2893 and Bs.2.5935 per U.S. Dollar, in conformity with the rates 

established by the BCV for payment of sale transactions under the Foreign Exchange Agreement 14 (see Note 4). During the year 2010, 

the average exchange rate on those transactions was Bs.3.61 per U.S. Dollar, because of this PDVSA had recorded a financial expense for 

the difference between this average exchange rate and the official exchange rate. 

As a result of PDVSA paying, with resources from the sale of crude and gas, in local and foreign currency the liabilities of the Company 

for the services incurred as well as payroll related obligations assigned by PDVSA (see Note 21), during the year ended December 31, 

2010 the Company recorded US$.19,475 thousands (Bs.83,743 thousands) corresponding to its share for the difference in the average 

exchange rate mentioned before of Bs.3.61 and the official exchange rate of Bs.4.30 (see Note 4). 

 

Credit Risk 

Exposure to Credit Risk 

The book value of financial assets represents the highest level of credit risk exposure. A breakdown is shown below (in thousands): 

 

Aging of the account receivables are shown below (in thousands): 

 

 

50 

(19) Financial Instruments 

 December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolivars 

Accounts receivable (see Note 11) 1,232,199 912,652 499,313 5,298,456 3,924,404 2,147,046 

Recoverable tax credits (see Note 7-k) 44,581 25,858 13,453 191,702 111,193 57,848 

Accounts receivable other (see Note 11) 66,243 1,517 1,662 284,845 6,523 7,147 

Cash and cash equivalents (see Note 12) 3,335 2,342 3,465 14,336 10,071 14,900 

 

 1,346,358 942,369 517,893 5,789,339 4,052,191 2,226,941 

 

 

 

 

 

 

 

 

 

 

 

 

 December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolivars 

Under 30 days 709,815 469,607 206,410 3,052,205 2,019,311 887,563 

Between 31 and 180 days 106,050 131,447 260,375 456,015 565,222 1,119,613 

Between 180 days and one year 410,908 311,598 32,528 1,766,904 1,339,871 139,870 

More than one year 5,426 — — 23,332 — — 

 

 1,232,199 912,652 499,313 5,298,456 3,924,404 2,147,046 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Liquidity risk 

Maturity of financial liabilities, Short-term payable, including estimated interest payments and excluding the impact of offset agreements, 

is shown below (in thousands): 

 

Foreign Currency Risk 

Petrodelta, S.A. has the following monetary assets and liabilities denominated in currencies other than the U.S. Dollar, which were 

converted into U.S. Dollars at the exchange rate in effect at the statements of financial position (in thousands): 

 

The year-end exchange rate, the average exchange rate for the year and the interannual increases in the National Consumer Price Index 

(NCPI), as published by BCV, were as follows: 

 

Fair Value of Financial Instruments 

The following estimated amounts do not necessarily reflect the amounts at which the instruments could be exchanged in the current 

market, The use of different market assumptions and valuation methods can significantly affect the estimated fair values, The bases for 

determining the fair value are disclosed in Note 5 (in thousands): 

 

51 

 Book value Contractual cash flows 6 months or less 

 Non-derivative financial liabilities at December 31, 

 2012 2011 2010 2012 2011 2010 2012 2011 2010 

U.S. Dollars 

Accounts payable to suppliers (see Note 16) 94,747 68,815 21,022 94,747 68,815 21,022 94,747 68,815 21,022 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Bolivars 

Accounts payable to suppliers (see Note 16) 407,412 295,905 90,395 407,412 295,905 90,395 407,412 295,905 90,395 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 December 31, 

 2012 2011 2010 

Monetary assets: 

Bolivars 277,152 172,801 86,991 

 

 277,152 172,801 86,991 

 

Monetary liabilities: 

Bolivars 2,646,171 2,534,998 1,423,259 

 

 2,646,171 2,534,998 1,423,259 

 

Net monetary liability position (2.369,019 ) (2,362,197 ) (1,336,268 ) 

 

 

 

 

 

 

 December 31, 

 2012 2011 2010 

Exchange rate at year end (Bs./US$..1) 4.30 4.30 4.30 

 

 

 

 

 

 

Average exchange rate for the year (Bs./US$..1) 4.30 4.30 4.30 

 

 

 

 

 

 

Interannual increase in the NCPI (%) 20.10 27.57 27.18 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

 

 

At December 31, 2012 and 2011 the Company has recorded a provision for 6 labor related claims in the amount of US$.16 thousands 

(Bs.69 thousands). Should the outcome of existing lawsuits and claims be unfavorable to the Company, it could have a material adverse 

effect on its results of operations. Although it is not possible to predict the outcome, Company management, based in part on the opinion 

of its legal advisors, does not believe it is likely that losses related to the aforementioned legal procedures will exceed recognized 

estimated amounts or generate significant amounts that could affect the Company’s financial position or results of operations. 

 

52 

 

 December 31, 

 2012 2011 2010 

U.S. DollarsBook 

Value 

Fair 

Value 

Book 

Value 

Fair 

Value 

Book 

Value 

Fair 

Value 

Assets: 

Accounts receivable (see Note 11) 1,232,199 1,232,199 912,652 912,652 499,313 499,313 

 

 

 

 

 

 

 

 

 

 

 

 

Recoverable tax credits 44,581 44,581 25,858 25,858 13,453 13,453 

 

 

 

 

 

 

 

 

 

 

 

 

Advances on windfall tax (see Note 11) 64,694 64,694 — — — — 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable other (see Note 11) 1,549 1,549 1,517 1,517 1,662 1,662 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents (see Note 12) 3,335 3,335 2,342 2,342 3,465 3,465 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities: 

Accounts payable to suppliers (see Note 16) 94,747 94,747 68,815 68,815 21,022 21,022 

 

 

 

 

 

 

 

 

 

 

 

 

Other liabilities (included in provisions, accruals and other 

payables) (see Notes 14 and 15) 605,213 605,213 317,844 317,844 209,652 209,652 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts payables to shareholders and related companies 

(See Note 16) 450,184 450,184 271,938 271,938 31,073 31,073 

 

 

 

 

 

 

 

 

 

 

 

 

 December 31, 

 2012 2011 2010 

BolivarsBook 

Value 

Fair 

Value 

Book 

Value 

Fair 

Value 

Book 

Value 

Fair 

Value 

Assets: 

Accounts receivable (see Note 11) 5,298,456 5,298,456 3,924,404 3,924,404 2,147,046 2,147,046 

 

 

 

 

 

 

 

 

 

 

 

 

Recoverable tax credits 191,702 191,702 111,193 111,193 57,848 57,848 

 

 

 

 

 

 

 

 

 

 

 

 

Advances on windfall tax (see Note 11) 278,185 278,185 — — — — 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable other (see Note 11) 6,660 6,660 6,523 6,523 7,147 7,147 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents (see Note 12) 14,336 14,336 10,071 10,071 14,900 14,900 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities: 

Accounts payable to suppliers (see Note 16) 407,412 407,412 295,905 295,905 90,395 90,395 

 

 

 

 

 

 

 

 

 

 

 

 

Other liabilities (included in provisions, accruals and other 

payables) (see Notes 14 and 15) 2,602,421 2,602,421 1,366,730 1,366,730 901,504 901,504 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts payables to shareholders and related companies 

(see Note 16) 1,935,791 1,935,791 1,169,333 1,169,333 133,614 133,614 

 

 

 

 

 

 

 

 

 

 

 

 

(20) Commitments and Contingencies 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Compliance with Environmental Regulations 

The subsidiaries of CVP are subject to different environmental laws and regulations which may require significant expenditures to 

modify facilities and prevent or remedy the environmental effects from waste disposal and spills of pollutants. 

Petrodelta, S.A. and its parent company CVP are taking steps to prevent environmental risks, protect employee health and preserve the 

integrity of their facilities. 

Management estimated potential liabilities as of December 31, 2012, 2011 and 2010 amounting US$.1.563 thousands, US$.1,799 

thousands and US$.2,093 thousands (Bs.6.719 thousands, Bs.7,736 thousands and Bs.9,000 thousands), respectively, and were included 

in the results of these years. 

Agreements with the Organization of Petroleum Exporting Countries (OPEC) 

The Bolivarian Republic of Venezuela is a member of OPEC, an organization mainly dedicated to establishing agreements to maintain 

stable crude oil prices by setting production quotas. To date, the reduction in crude oil production resulting from changes in the 

production quotas set by OPEC and price fluctuations has not significantly affected the Company’s results of operations, cash flows or 

financial results. 

 

Petrodelta, S.A. considers its shareholders and related subsidiaries and affiliates, Company directors and executives, as well as other 

governmental institutions, as related parties. 

A summary of transactions and balances with related parties is shown below (in thousands): 

 

 

53 

(21) Related Party Transactions 

 December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolivars 

Activities for the year: 

Crude oil and natural gas sales 1,160,653 1,048,728 607,586 4,990,808 4,509,530 2,612,621 

 

 

 

 

 

 

 

 

 

 

 

 

Operational expenses 72,480 47,318 17,544 311,664 203,467 75,439 

 

 

 

 

 

 

 

 

 

 

 

 

Sales, general, administrative and selling expenses 7,623 4,322 3,868 32,779 18,585 16,632 

 

 

 

 

 

 

 

 

 

 

 

 

Production royalties for oil and gas 280,909 263,422 183,076 1,207,909 1,132,715 787,227 

 

 

 

 

 

 

 

 

 

 

 

 

Reimbursement of expenses 135,465 175,166 235,634 582,500 753,214 1,013,326 

 

 

 

 

 

 

 

 

 

 

 

 

Dividends paid to Shareholders — 18,330 43,346 — 78,819 186,388 

 

 

 

 

 

 

 

 

 

 

 

 

Balances at the end of the year: 

Accounts receivable (see Note 11) 1,232,199 912,652 499,313 5,298,456 3,924,404 2,147,046 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts payable to Shareholder B (see Note 16) 2,722 1,969 1,499 11,705 8,467 6,446 

 

 

 

 

 

 

 

 

 

 

 

 

Dividends payable to Shareholders A 30,550 30,550 18,330 131,365 131,365 78,819 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts payable to PDVSA 439,223 258,222 21,881 1,845,659 1,110,357 94,088 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

As of April 2006, due to the migration of operating agreements to mixed companies (see note 1), PDVSA Petróleo signed purchase and 

sale agreements with these companies, which set out that mixed companies will notify PDVSA Petróleo of the estimated volume of 

hydrocarbons expected to be delivered the following month. PDVSA Petróleo must pay the mixed companies for delivered volumes, net 

of volumes for royalties in kind and paid to the Venezuelan government. 

In conformity with the terms and conditions of the agreements, CVP mixed companies agree to sell and deliver to PDVSA Petróleo, and 

the latter agrees to purchase and receive from these mixed companies, crude oil and natural gas produced in the delimited areas that are 

not used for primary activities or for payment of royalties in kind to the Venezuelan government. 

Crude oil delivered from the Petrodelta fields to 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, except for the volumes of crude produced from El Salto field since October 2011 which 

the Company has agreed to amend the purchase sale agreement with PDVSA Petróleo so it can invoice PDVSA using as Boscán as a 

crude reference for El Salto field production since October 2011 (see Notes 1, 11 and 24-a). Market prices for both crude oil of the type 

produced (Merey 16 and Boscán) in the fields operated by Petrodelta averaged approximately US$.95.90, US$.98.52 and US$.70.57 per 

barrel for the year ended December 31, 2012, 2011 and 2010, respectively. 

During the years ended December 31, 2012 and 2011, the Company recorded estimated revenues, unbilled, for the sale of crude oil in the 

amount of US$.404.619 thousands (Bs.1.739.862 thousand) and US$.67.092 thousands (Bs.288.496 thousands), respectively, 

corresponding to Boscan crude production which is not provided for billing in the Purchase-Sale of Oil signed between the Company and 

PDVSA Petroleo, S.A. As of December 31, 2012 and 2011, the Company has accounts receivable of US$.352,721 thousands and 

US.$.50,772 thousands (Bs.1,516,704 thousands and Bs.218,319 thousands), respectively, for the delivery of such crude. The Company 

and PDVSA Petroleo, SA are in the process of revising the price formulas under the Contract, in order to include the respective 

amendment to begin the billing process. 

During the years ended December 31, 2012, 2011 and 2010, the Company sold crude oil and natural gas to PDVSA Petróleo for 

US$.1,160,653 thousands, US$.1,048,728 thousands and US$.607,586 thousands (Bs.4,990,808 thousands, Bs.4,509,530 thousands and 

Bs.2,612,621 thousands), respectively, included in the statements of comprehensive income under Income. On October 3, 2011, the 

Company received accounting guidelines from CVP, to account for revenues from the sale of crude oil, royalty and other taxes (see Notes 

7-g, 7-h and 7-j) due to the law that came into effect creating a special contribution on extraordinary prices and exorbitant prices in the 

international hydrocarbons market (see Note 23-j), which sets a 

 

54 

 December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollars Bolivars 

Other joint ventures 18,239 11,747 7,693 78,428 50,512 33,080 

 

 

 

 

 

 

 

 

 

 

 

 

Accrued payables with PDVSA 213,173 67,570 68,561 916,644 290,551 294,812 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

maximum price to pay for royalty at US$.70 per barrel. These guidelines modified the accounting procedure for recording and 

recognizing revenues from the sale of crude as well as recording and recognizing expense from royalty and other taxes. Since the 

Company pays royalty in kind for the crude produced and sells to PDVSA, and recognizes the amounts for revenues from the sale of 

crude and royalty in the statement of comprehensive income up until the law creating a special contribution on extraordinary prices and 

exorbitant prices in the international hydrocarbons market came into effect at the sales price, and according to new law and guidelines 

received recognizes as revenue for the sale of crude 70% of the barrels delivered to PDVSA plus 30% of royalty at the maximum price of 

US$.70 per barrel, income from the sale of crude oil and royalty expense on crude for the years ended December 31, 2012 and 2011, are 

presented undervalued in the amount of US$.102,357 thousands and US$.76,966 thousands (Bs.440,135 thousands and Bs.330,952 

thousands), respectively when compared to the procedure applied in prior periods. 

Following is a table, in thousands, that allows comparison of revenues and royalty calculated using prior and current procedure (in 

thousands): 

 

At December 31, 2012, 2011 and 2010, the statement of financial position includes US$.1,232,199 thousands, US$.912,652 thousands 

and US$.499,313 thousands (Bs.5,298,456 thousands, Bs.3,924,404 thousands and Bs.2,147,046 thousands) of accounts receivable for 

the crude and gas sales to PDVSA. 

During 2012, 2011 and 2010, PDVSA Petróleo charged Petrodelta, S.A. US$.888 million, US$.615 million and US$.246 million 

(Bs.3,816 million, Bs.2,642 million and Bs.1,197 million), respectively, for labor and other costs, taxes, royalties, cash advances, 

dividends, and operating costs. 

Certain Company directors hold key positions in other related entities; some of their attributions include influencing the operational and 

financial policies of these entities. 

At December 31, 2012, 2011 and 2010, transactions with related parties do not necessarily reflect the results that would have been 

obtained had these transactions been held with third parties. 

On December 28, 2012, the Company following instructions from its shareholder CVP proceeded to offset accounts receivables and 

payables between PDVSA and its affiliates, including CVP for royalties, contributions, taxes, advances and operational expenses 

outstanding as of November 30, 2012 resulting in a netting of US$.267 million (Bs.1,149 million) 

 

55 

 Year ended December 31, 

 2011 2010 2011 2010 

 US Dollars Bolivars 

Revenues from the sale of crude for the total volume of crude delivered 1,122,190 604,173 4,825,415 2,597,945 

Royalty capped at US$.70 (76,966 ) — (330,952 ) — 

 

Revenues from sale of crude 1,045,224 604,173 4,494,463 2,597,945 

 

 

 

 

 

 

 

 

Royalty in kind at crude oil sold price 336,973 181,252 1,448,982 779,384 

Royalty capped at US$.70 (76,966 ) — (330,952 ) — 

 

Royalty recorded in books (see Note 7) 260,007 181,252 1,118,030 779,384 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

at the prevailing exchange rate applicable at such date against the accounts receivable with PDVSA and its affiliates, including CVP, for 

the crude and gas sold and delivered outstanding as of November 30, 2012 at the prevailing exchange rate applicable at such date. 

On June 20, 2012, the Company following instructions from its shareholder CVP proceeded to offset accounts receivables and payables 

between PDVSA and its affiliates, including CVP for royalties, contributions, taxes, advances and operational expenses outstanding as of 

May 31, 2012 resulting in a netting of US$.298 million (Bs.1,282 million) at the prevailing exchange rate applicable at such date against 

the accounts receivable with PDVSA and its affiliates, including CVP, for the crude and gas sold and delivered outstanding as of May 31, 

2012 at the prevailing exchange rate applicable at such date. 

On January 12, 2012, the Company following instructions from its shareholder CVP proceeded to offset accounts receivables and 

payables between PDVSA and its affiliates, including CVP for royalties, contributions, taxes, advances, operational expenses and 

dividends payable to CVP approved by the shareholders of the Company on August 4, 3010 (see Note 13) against the Company accounts 

receivable with PDVSA and its affiliates, including CVP, for the crude and gas sold, outstanding as of December 31, 2011, resulting in a 

netting of US$.205 million (Bs.882 million) at the prevailing exchange rate applicable at such date. 

On October 28, 2011, the Company following instructions from its shareholder CVP proceeded to offset accounts receivables and 

payables between PDVSA and its affiliates, including CVP for royalties, contributions, taxes, advances and operational expenses against 

the Company accounts receivable with PDVSA and its affiliates, including CVP, for the crude and gas sold, outstanding as of 

September 30, 2011, resulting in a netting of US$.169 million (Bs.727 million) at the prevailing exchange rate applicable at such date. 

During February 2011, the Company following instructions from its shareholder CVP proceeded to offset accounts receivables and 

payables between PDVSA and its affiliates, including CVP with the Company outstanding as of December 31, 2009 at the exchange rate 

prevailing as of this date, resulting in a netting of US$.46 million (Bs.101 million). Additionally, in the same month and year, CVP sent 

instructions again to the Company to proceed and offset accounts receivables and payables between PDVSA and its affiliates, including 

CVP with the Company outstanding as of December 31, 2010, resulting in a netting of US$.195 million (Bs.838 million). Both nettings 

have been recorded in the month of December of 2010, and are included in the statements of financial position as of December 31, 2010. 

In June 10, 2010, the Company’s Board of Directors approved the offsetting of accounts payable to PDVSA and its affiliates, including 

CVP, for 2010 royalties, taxes, dividends payable at the end of 2009 and operational expenditures in the amount of US$.40 million 

(Bs.172 million) against the receivable from PDVSA and its affiliates, including CVP, for 2010 oil and gas deliveries. 

All compensation transactions have been approved by the Board of Directors of the Company. 

 

On July 20, 2012 the Collective Labor Agreement was signed, valid for the period from October 1, 2011 thru October 1, 2013, among the 

employees of the oil industry represented by the Venezuelan Unitary Federation of workers of the oil, gas, its similars and derivatives 

(FUTPV) 

 

56 

(22) Collective Labor Agreement 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

and the Ministry of Popular Power for Energy and Mining (MPPPM) and PDVSA. The Collective Labor Agreement establishes a salary 

raise and payroll and retirement benefits which has a significant impact on the Company’s payroll cost. The most significant impacts had 

an economic and social benefit on workers and are summarized as follows: 

 

 

 

 

Before, on January 20, 2010 the Collective Labor Agreement was signed, valid for the period from October 1, 2009 thru October 1, 2011, 

by workers leaders of the industry represented by the FUTPV and the Ministry of the MPPPM and PDVSA President. The Collective 

Labor Agreement establishes a salary raise and payroll and retirement benefits which has a significant impact on the Company’s payroll 

cost. The most significant impacts are: 

 

 

 

 

 

57 

 

i. Focus the contract to a higher social justice through increases in the quality of life of workers by supporting the adquisition 

of school supplies for their children, provide benefits for newborns, marriage, attention to handicapped people and financing 

turism packages for workers and their families under the Collective Labor Agreement. 

 

ii. A salary raise of Bs.40 daily from October 1, 2011. Payment of this increase was done Bs.30 at end of July 2012 and Bs.10 

from January 1, 2013. 

 iii. An increase in the monthly amount for electronic card for foods from Bs.1,700 to Bs. 2,700. 

 

iv. Provide 65 days of vacation bonus to contractual payroll and between 15 and 30 days of post-vacation bonus depending on 

the type of payroll. Also it was agreed to increase to Bs.200,000 the amount to finance housing acquisition. 

 

i. A salary raise of Bs.35 daily which represents an increase of 80% of current salary. The increase shall be pay in two 

portions, the first of Bs.25 at the signing of the contract and the second of Bs.10 from January 1st, 2011. 

 ii. An increase in the monthly amount for electronic card for foods from Bs.1,300 to Bs. 1,700. 

 iii. An increase in the retirement benefit from Bs. 1,000 to Bs. 1,600. 

 

iv. The increase will be retroactive from October 1, 2009 and not from January 21, 2009, being the date on which the prior 

contract expired, in compensation it was agreed a one-time bonus of Bs. 8.000 which has no effect in the severance benefits 

of employees. 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

 

On June 15, 2012 the National Executive published by means of decree-law No. 9,053 the Special Law on Severance Benefits 

National Fund in order to create the program National Fund for Severance Benefits which establishes the conditions to receive and 

manage deposits corresponding to the severance benefit guarantees of workers into government financial institutions. 

 

On April 30, 2012, the National Executive promoted by means of decree-law No. 8.938 the Labor Organic Law and Workers. On 

May 7, 2012 the National Assembly published on the Official Gazette No. 6,076 this organic law. The most significant aspects of 

this law are: 

 

 

 

 

The Company recognized a provision in respect of the impact of the new Labor Law, through the actuarial calculation prepared by 

independent actuaries contracted by PDVSA. 

 

On August 24, 2011, the National Assembly published on the Official Gazette 39,741 the Sports Organic Law promoted by the 

Executive branch of power. This law declares of national and general interest as well as a public service all activities for promoting, 

organizing and administering sports and physical activity in Venezuela. The law among other things creates the National Fund for 

the Development of Sports, Physical Activity and Physical Education to be constituted on contributions from companies and 

organizations, private or public, performing profit seeking economic activities within the national territory. These 

 

58 

(23) Laws, Resolutions and Legal Contributions 

 a) Special Law on Severance National Fund 

 b) Labor Organic Law and Workers 

 

(1) Obligation by employers to calculate severance benefits retroactively by a) paying employees the equivalent of 15 days of 

salary every quarter with the most recent salary, this right is acquired at the beginning of each quarter, b) after the first year 

of service, the employer will pay employees 2 days of salary for every year worked, cumulative until a maximum of 30 days 

is reached, c) when by any reason the working relation ends, severance benefits will be calculated for 30 days for every year 

worked or fraction over 6 months and calculated with the most recent salary earned. Workers will receive as severance 

benefits, the higher amount between a) and b) or c) as described above. Quarterly or annual payments shall be deposited in 

the National Fund for Severance Benefits under each workers name, or at a trust fund in financial institutions or at the 

employer ́s accounting records as long as workers authorize it in writing. 

 

(2) Increase in the rest periods woman have during pregnancy, providing as its main benefits 6 weeks prior to giving birth and 

20 weeks after, as well as prohibition by employers to resign labor relation up to 2 years after giving birth. 

 (3) Reduction of the daily working time to 5 working days and 2 resting days 

 (4) Increase in the number of holidays during the year 

 c) Sports organic Law 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

contributions are not deductible for income tax purposes and shall be 1% over net profit when net profit is above 20.000 tax units. 

As of December 31, 2012 and 2011 the Company has recorded as contribution under the Sport Organic Law the amount of 

US$.3,082 thousands and US$.1,110 thousands (Bs.13,253 thousands and Bs.4,773 thousands), respectively. 

On February 28, 2012, Official Gazette No. 39,872 was published containing decree-law No. 8.820 on partial regulation No.1 to the 

Sports Organic Law. The partial regulation scope the National Fund for the Development of Sports, Physical Activity, duties of the 

National Sports Institute, guidelines on the executions of resources and taxpayers subject to the law and their responsibilities, as 

well as means of making contributions. 

 

On May 18, 2011, the National Assembly published on the Official Gazette 39,676 the means of decree-law No. 8.204 promoted by 

the President of the Bolivarian Republic of Venezuela, the Law to Liquidate and Suppress the Endogenous Development Fund, an 

autonomous institute created by the Law for the Creation of the Endogenous Development Fund, published in the National Gazette 

38.500 on August 15, 2006. 

 

On December 17, 2010, the National Assembly approved the Law Authorizing the President of the Republic to issue Decree-Laws. 

The Enabling law was published in the extraordinary Official Gazette No. 6.009 and covers a range of areas for a term of 18 months 

after publication thereof. Under this law, the authorization encompasses areas involving the transformation of government 

institutions, popular participation, as well as economic, social, financial, tax and energy matters. 

 

On June 4, 2010, Official Gazette 39,439 was published containing Foreign Exchange Agreement 18, which establishes that the 

BCV will be in charge of regulating the terms and conditions for the negotiation, in local currency, and through the system accorded 

for that purpose, of securities of the Bolivarian Republic of Venezuela, its decentralized entities or any other issuing body, whether 

they are issued or to be issued in foreign currency. 

 

On February 11, 2010, Official Gazette 39,366 was published containing Ruling 001-2010, which establishes standards for the 

admissible discounts to the expense set forth under LOCTICSEP and its Regulation for payment corresponding to fiscal years 2006, 

2007 and 2008. This ruling establishes that only the following payments made by taxpayers during fiscal years 2006, 2007 and 2008 

may be subject to rebates: 

 

 

 

 

59 

 d) Law to Suppress and Liquidate the Endogenous Development Fund 

 e) Laws enacted under the Enabling Law 

 f) Foreign Exchange Agreement 18 

 g) Ruling 001-2010 by National Antidrugs Office (Oficina Nacional Antidrogas or ONA) 

 • Conduction of projects for comprehensive social prevention and development. 

 • Expenses under non-reimbursable technical assistance agreements. 

 • Funding or performance of activities under comprehensive social prevention. 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

On January 27, 2010, as a result of a material error, Foreign Exchange Agreement 15 was republished in Official Gazette 39,355, 

originally published in Official Gazette 39,349 dated January 19, 2010. This agreement contains new provisions and guidelines 

complementing the multiple exchange rate system created under Foreign Exchange Agreement 14 (see Note 4). The most relevant 

aspects of this agreement follow: 

 

 

 

On December 2010, the Partial Amendment to the Organic Law on Science and Technology and Innovation (LOCTI) was 

published. This amendment establishes that legal or private or publicly owned entities, domiciled in the Bolivarian Republic of 

Venezuela or abroad, performing economic activities within the national territory are under the obligation of paying on an annual 

basis an established percentage of their gross income from the previous year, in respect to their business area, as follows: 

 

 

 

 

On April 28, 2011, the Company received instructions from its shareholder, CVP, to reverse the expense of US$.4,583 thousands 

(Bs.19,707 thousands) and accrued at December 31, 2010, due to the fact that PDVSA has opted to file declaration on behave of its 

affiliates, including mix companies, and waive the liability on them, including Petrodelta, S.A. As of December 31, 2011, CVP sent 

instructions to the Company to record its share according to the law for its obligation corresponding to the year ended December 

2011 only. The provision recorded in the statements of financial position corresponding to the year ended December 31, 2012 and 

2011 amounts to US$.5,238 thousands and US$.3,054 thousands (Bs.22,523 thousands and Bs.13,132 thousands), respectively. 

 

60 

 h) Foreign Exchange Agreement 15 

 

• As to the Value Added Tax (VAT), imports of goods and services are subject to the exchange rate of Bs.2.60 per 

U.S. Dollar, for the food, health, education, machinery and equipment and science and technology sectors; Bs.4.30 per 

U.S. Dollar will be used for other sectors. With regards to exports of goods and services, the applicable exchange rate is 

Bs.4.2893 per U.S. Dollar. 

 

• In relation to customs, the applicable exchange rate is Bs.2.60 per U.S. Dollar for imports corresponding to the food, health, 

education, machinery and equipment and science and technology sectors; and Bs.4.30 per U.S. Dollar for all other imports. 

 i) Organic Law on Science and Technology and Innovation (LOCTI) 

 

• Two percent when economic activity is framed within those listed in the Law for the Control of Casinos, bingo Halls and 

Slot Machines, and any area related to industry and trade of Alcohol and snuff. 

 

• One percent for privately owned enterprises operating in business areas subject to the Organic Law on Hydrocarbons and 

Gaseous Hydrocarbons, including mining, processing and distribution activities. 

 

• Half percent for publicly owned companies if the business pursued is one of those listed in the Organic Law on 

Hydrocarbons and Gaseous Hydrocarbons including mining, processing and distribution activities. 

 • Half percent for any other business activity. 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

On April 18, 2011, the Venezuelan government published in the Extraordinary Official Gazette No. 6.022, by means of decree-law 

No. 8.163 of same date, the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International 

Hydrocarbons Market. This law modifies calculation and payment of royalty, extraction tax and export registry tax as per LOH and 

the special contribution for extraordinary prices and exorbitant prices from the date published. The law defines the contribution on 

Extraordinary Prices for 20 percent to be applied to the difference between the average monthly price up to US$.70 or less per 

barrel, on international markets for the Venezuelan liquid basket of hydrocarbons and the price fixed by the Venezuela budget for 

the relevant fiscal year (set at US$.50 and US$.40 per barrel for 2012 and 2011, respectively). The law also defines the contribution 

on Exorbitant Prices for (1) 80 percent when the average price mentioned before exceeds US$.70 per barrel but is less than US$.90 

per barrel; (2) 90 percent when the average price mentioned before exceeds US$.90 per barrel but is less than US$.100 per barrel; 

and (3) 95 percent when the average price mentioned before exceeds US$.100 per barrel. The law also established the maximum 

price to be used for calculating royalty paid in cash on production at US$.70 per barrel. This law supersedes the Law for Special 

Contributions on Extraordinary International Hydrocarbon Market Prices (see Note 23-k). 

On February 27, 2012, Official Gazette No. 39,871 was published the decree No. 8.807 modifying the articles 2 and 10 of the Law 

Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market. The 

partial reform indicates that the use of resources derived from this law be used in financing the Great Missions created by the 

National Executive, and projects of infrastructure, roads, health, education, among others. The development of the national 

production sector, among others areas. The partial reform also stipulates treasury aspects on how the contributions is to handle 

between PDVSA, the National Development Fund (FONDEN), and BCV (see Note 24-d). 

 

On April 15, 2008, the Law for Special Contributions on Extraordinary International Hydrocarbon Market Prices was published in 

Official Gazette No. 38,910 (See Note 23-j). Subsequently, Resolutions No. 151 and No. 195 of MPPPM were published in Official 

Gazette No. 38,939 of May 27, 2008 and Official Gazette No. 38,970 of July 10, 2008. This Law and its resolutions require entities 

that export or transport liquid hydrocarbons and hydrocarbon derivatives abroad to pay a special monthly contribution. The 

contribution will be equivalent to: a) 50% of the difference between the average monthly price of the Venezuelan crude oil basket 

and the threshold price of US$.70 per barrel and b) 60% of the difference between the average monthly price of the Venezuelan 

crude oil basket and the threshold price over US$.100 per barrel. This contribution shall be paid on every barrel of oil exported or 

transported abroad and shall be collected and paid monthly by MPPPM to the National Endowment Development Fund (FONDEN) 

for execution of infrastructure development projects, production and social development projects aimed at strengthening Communal 

Power. This Law became effective on April 15, 2008. This law was superseded by the law creating a special contribution on 

extraordinary prices and exorbitant prices in the international hydrocarbons market (see Note 23-j). 

 

61 

 j) Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market 

 k) Law for Special Contributions on Extraordinary International Hydrocarbon Market Prices 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

On September 15, 2010, the Antidrug Organic Law was published in Official Gazette No. 39,510. The LOD eliminates the Law on 

Narcotic and Psychotropic Substances (LOCTISEP) and its partial regulation published June 5, 1996 under Official Gazette 

No. 35,986. Among the significant changes are: 

 

 

 

 

 

On February 23, 2011, providence No. 0001-2011 was published in the Official Gazette No. 39.622, establishing that labor matters 

related to Projects for Integral Prevention on Drug Consumption must be presented to the National Antidrug Fund (FONA). The 

providence establishes that private and public companies must present between January 2 and April 30 the projects and all of their 

requirements to be executed in order to carry-out technical and economical evaluations necessary for the appropriate approval. 

Projects for Integral Prevention in regards to labor matters can only be submitted by those companies in which their fiscal year ends 

before the established time frame mentioned in order to be eligible and once the contribution of 1% has been paid. When companies 

can not submit projects, they can present them in the same timing period of the following year and the corresponding charge shall 

be the year immediately before to the year corresponding the contribution determination. 

During the years ended December 31, 2012, 2011 and 2010, the Company recognized and recorded an expense for US$.3,082 

thousands, US$.3,328 thousands and US$.4,813 thousands (Bs.13,253 thousands, Bs.14,311 thousands and Bs.20,697 thousands), 

respectively. 

 

62 

 l) Antidrug Oganic Law (LOD) 

 

• Taxable base is changed, previously considered base on net profit and now establishes as taxable base current period 

operating income. 

 

• Filing and payment of tribute is extended from 15 calendar days of the following taxable period, to 60 calendar days from 

the closing corresponding taxable period. 

 

• In relation to sanctions, the law establishes: 1) failure to comply the contribution of 1%, a penalty equivalent to double the 

amount due, if re-occur the penalty will be 3 times the corresponding contribution due, and 2) for not complying the special 

contribution of 2%, same penalty, before was 60,000 tax units or suspension of business activities during 1 year in case of 

re-occurrence. 

 

• In the prior law, donations made by persons or companies in favor of plans and programs established by the government in 

relation to drugs matter and approved by ONA, can be deducted for income tax purposes, previously approved by public 

document. In the new law, this last aspect is eliminated as a requisite for proceeding to deduct from income tax purposes. 

 

• Incorporates an obligation by government agencies and institutions, as well as public and private companies that employ 

more than 50 workers, to provide labor to rehabilitated persons, under the programs of social inclusions. 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

 

 

 

 

 

 

63 

(24) Subsequent Events 

 

a) On January 31, 2013, the Board endorsed the incorporation of Oil Price Formula with reference to Boscan, for incorporation in the 

Contract of Purchase Sale of Hydrocarbons and instructed to submit the formula to the corresponding administrative and financial 

authority level, and for the approval of the Petrodelta, S.A. Shareholders, which will allow the billing of the production of crude 

from “Campo El Salto”,. 

 

b) On February 6, 2013, providence No. SNAT/2013/0009 from the National Integrated Service on Tributes and Customs 

Administration (SENIAT) was published in Official Gazette No. 40,106 in which the current tax unit value was adjusted from Bs.90 

to Bs.107. 

 

c) On February 8, 2013, the Exchange Agreement No. 14 was published in the Official Gazette No. 40,108, which establishes the new 

official rate for the purchase and sale of the US Dollar and effective from February 9, 2013. The new purchase rate increased from 

Bs4.20 to Bs6.30 for one US Dollar. Likewise, it was published, a higher rank agency to optimize the exchange rate system in order 

to design, plan, and execute monetary strategies by the government, to reach higher efficiency and transparency providing foreign 

currency to the country economic sector. Decisions from this agency will be adopted by the Ministry of People Power for Planning 

and Finance as well as the Venezuela Central Bank (see Note 4). 

 

d) On February 20, 2013 the National Assembly approved to published in the Official Gazette No. 40,144, the reform to the law that 

creates a special contribution on extraordinary prices and exorbitant prices in the international hydrocarbons market published in the 

Extraordinary Official Gazette No. 6,022 by means of decree No. 8,163 from the Executive branch on April 18, 2011. The most 

significant aspects are: a) guarantee financing of social missions created by the government as well as projects related to 

infrastructure, roads, health, education, communication, agriculture, food and in general for the development of the national 

productive sector, b) modify the parameter that defines what constitutes contributions from extraordinary prices (under US$.80 per 

barrel) and what constitutes contribution from exorbitant prices (from US$.80 per barrel and up), c) establish the new intervals to 

apply the percentage to calculate such contributions, d) modify the maximum price to calculate and pay royalty at US$.80 per 

barrel, e) supersede decree No. 8,807 that modified this law and published in the Official gazette No. 39.871 on February 27, 2012 

(see Note 23-j); and e) eliminates dispositions on the law from the Venezuela Central Bank that regulates funding from PDVSA 

Petróleo to the National Development Fund (FONDEN) and any other provision of exceeding that collides with the present Law. 

 

e) On March 1, 2013 the Board of Directors of the Company approved the issuance of these financial statements as of December 31, 

2012 under International Financial Reporting Standards and resolved to submit these financial statements to the Shareholders of the 

Company for approval purposes. The financial statements cannot be modified once they have been issued and approved by the 

Shareholders of the Company. It also approved raising the Shareholders to the change of booking of deferred tax assets to the 

amount of US$.70,426 thousands (Bs.302,832 thousands) on retained earnings at December 31, 2012. 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

The following tables provide supplementary information on oil and gas exploration, development and production activities. All 

exploration and production activities are conducted mainly by CVP and Mixed Companies in Venezuela. 

Table I—Crude Oil and Natural Gas Reserves 

All crude oil and natural gas reserves located in Venezuela are owned by the Bolivarian Republic of Venezuela. Crude oil and natural gas 

reserves are estimated by PDVSA and reviewed by the People’s Power Ministry for Energy and Oil (MPPPM) using reserve criteria that 

are consistent with those prescribed by the American Petroleum Institute (API) of the United States of America. 

Proved reserves are the estimated quantities of crude oil and gas which, with reasonable certainty, are recoverable in future years from 

known deposits under existing economic and operating conditions. Due to the inherent uncertainties and limited nature of reservoir data, 

reserve estimates are subject to changes over time, as additional information becomes available. Proved reserves do not include additional 

volumes which may result from the extension of currently explored areas or from the application of secondary recovery processes not yet 

tested and determined to be economically feasible. 

Proved developed oil and gas reserves are the quantities that can be recovered from existing wells with existing equipment and methods. 

Proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage or from existing 

wells. 

A summary of annual changes in proved crude oil and natural gas reserves is shown below: 

 

 

At December 31, 2012, 2011 and 2010, certified reserves assigned to the Company amounted to 857,628 thousands, 499,237 thousands 

and 511,320 thousand barrels, respectively. Production for the year ended December 31, 2012, 2011 and 2010 was 13,172 thousands, 

11,390 thousands and 8,561 thousand barrels. 

 

64 

(25) Supplementary Information on Oil and Gas Exploration and Production Activities (unaudited) 

 (a) Conventional Crude Oil (in thousands of barrels) 

 Years ended December 31, 

 2012 2011 2010 

Proved developed and undeveloped reserves of conventional crude oil at 

January 1 499,237 511,320 206,823 

Revisions — (693 ) — 

Expansions and discoveries 371,563 — 313,058 

Production (13,172 ) (11,390 ) (8,561 ) 

 

Proved developed and undeveloped reserves of conventional crude oil at 

December 31 857,628 499,237 511,320 

 

 

 

 

 

 

Proved developed reserves of conventional crude oil at December 31 (included 

on the previous amount) 65,755 50,758 52,705 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

 

Natural gas production is shown on the basis of actual volumes before the extraction of liquefiable hydrocarbons. 

Table II—Costs Incurred in Exploration and Development Activities 

Exploration costs include costs incurred from geological and geophysical activities, and drilling and equipping exploratory wells. The 

Company did not conduct exploration activities in the year 2012. Development costs include those for drilling and equipping 

development wells, enhanced recovery projects and facilities to extract, treat and store crude oil and natural gas. Annual costs, 

summarized below, include amounts both expensed and capitalized for the Company’s conventional crude oil reserves (In thousands): 

 

 

65 

 (b) Natural Gas Reserves (in millions of cubic feet) 

 Years ended December 31, 

 2012 2011 2010 

Proved developed and undeveloped reserves of natural gas at January 1 532,082 548,880 266,292 

Revisions — (14,532 ) — 

Expansions and discoveries 175,546 — 284,792 

Production (2,171 ) (2,266 ) (2,204 ) 

 

Proved developed and undeveloped reserves of natural gas at December 31 705,457 532,082 548,880 

 

 

 

 

 

 

Proved developed reserves of natural gas at December 31 in Uracoa and 

Tucupita (included on the previous amount) 23,390 20,809 18,773 

 

 

 

 

 

 

 Conventional Crude 

 U.S. Dollars Bolivars 

 2012 2011 2010 2012 2011 2010 

Development costs 207,320 141,763 93,675 891,479 609,581 402,804 

 

Total costs incurred from development Activities 207,320 141,763 93,675 891,479 609,581 402,804 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Table III—Costs Recorded as Assets in Oil and Gas Production Activities 

Costs recorded as assets for oil and gas exploration and production activities, as well as the related accumulated depreciation and 

amortization at December 31 for PDVSA’s conventional and extra-heavy crude oil reserves are summarized below (In thousands): 

 

Table IV—Results of Operations for Oil and Gas Production Activities for Each Year (In thousands): 

 

Income from oil production is calculated at international market price as if all production were sold (see Note 21). 

Production costs are lifting costs incurred to operate and maintain productive wells and related facilities and equipment, including 

operating labor costs, materials, supplies, fuel consumed in operations and operating costs of natural liquid gas plants. 

 

66 

 Conventional Crude 

 U.S. Dollars Bolivars 

 2012 2011 2010 2012 2011 2010 

Assets used in production 660,972 470,226 362,087 2,842,181 2,021,972 1,556,974 

Equipment and facilities 22,447 15,576 10,615 96,522 66,977 45,645 

 

 683,419 485,802 372,702 2,938,703 2,088,949 1,602,619 

Accumulated Depletion, depreciation and amortization (279,117 ) (193,112 ) (134,737 ) (1,200,203 ) (830,382 ) (579,369 ) 

Construction in progress 121,087 111,255 78,755 520,675 478,396 338,646 

 

Total net costs capitalized as assets 525,389 403,945 316,720 2,259,175 1,736,963 1,361,896 

 

 

 

 

 

 

 

 

 

 

 

 

 Conventional Crude 

 Years ended December 31 

 U.S. Dollar Bolivars 

 2012 2011 2010 2012 2011 2010 

Net production income: 

Sales (see Note 21) 1,263,010 1,125,694 607,586 5,430,943 4,840,482 2,612,621 

Production costs (158,888 ) (113,985 ) (59,806 ) (683,219 ) (490,137 ) (257,162 ) 

Royalties in kind and other taxes (see Note 7 and Note 

21) (706,360 ) (607,442 ) (217,760 ) (3,037,348 ) (2,611,999 ) (936,367 ) 

Contributions and funding for social development (14,889 ) (7,241 ) (9,863 ) (64,023 ) (31,137 ) (42,414 ) 

Depletion, depreciation and Amortization (83,168 ) (56,693 ) (39,153 ) (357,622 ) (243,780 ) (168,358 ) 

 

Results of operation before income Tax 299,705 340,333 281,004 1,288,731 1,463,429 1,208,320 

Income tax (149 853 ) (170,167 ) (140,502 ) (644,366 ) (731,715 ) (604,160 ) 

 

Results production operation 149,852 170,166 140,502 644,365 731,714 604,160 

 

 

 

 

 

 

 

 

 

 

 

 
PETRODELTA, S.A. 

(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.) 

Notes to the financial statements 

December 31, 2012, 2011 and 2010 

 

Depreciation and amortization expenses relate to assets used in exploration and production activities. Income tax expense is computed 

using the statutory rate for the year. For these purposes, the results of production operations do not include finance costs and corporate 

overhead nor their associated tax effects. 

A summary of average per unit sale prices and production costs is shown below: 

 

 

67 

 Years ended December 31, 

 2012 2011 2010 2012 2011 2010 

 U.S. Dollar Bolivars 

Average sale price 

Crude oil per barrel 95,90 98.52 70.57 412.37 423.64 303.46 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas per barrel 1.54 1.54 1.54 6.62 6.62 6.62 

 

 

 

 

 

 

 

 

 

 

 

 

Average production cost per BOE 11.74 9.69 6.70 50.48 41.67 28.81 

 

 

 

 

 

 

 

 

 

 

 

 
EXHIBIT 99.2 

 

HNR Finance B.V. 

Prins Bernhardplein 200 

P.O. Box 990 

1000 AZ Amsterdam, Netherlands 

 

 Fortis Intertrust (Netherlands) B.V. – Director B 

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved, probable and possible reserves, future 

production, and income attributable to HNR Finance B.V.’s (“HNR Finance”) interest in certain properties located in the Greater Oficina Trend 

of Eastern Venezuela. These properties have been included in a company called Petrodelta S.A., in which HNR Finance has a 40 percent 

interest, and Corporación Venezolana del Petroleo S.A. (CVP) has 60 percent interest. The properties include six fields; Bombal, El Salto, 

Isleño, Temblador, Tucupita, and Uracoa, (“Petrodelta fields”). The reserves and income data were estimated based on the definitions and 

disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, 

Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, 

completed on February 15, 2013 and presented herein, was prepared for public disclosure by HNR Finance in filings made with the SEC in 

accordance with the disclosure requirements set forth in the SEC regulations. 

The properties evaluated by Ryder Scott represent 100 percent of the total net proved, probable and possible liquid hydrocarbon reserves 

and 100 percent of the total net proved, probable and possible gas reserves of HNR Finance as of December 31, 2012. 

The estimated reserves and future net income amounts presented in this report, as of December 31, 2012 are related to hydrocarbon 

prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the 

ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-themonth for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual 

future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the 

amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are 

summarized on the next page. 

 

 FAX (303) 623-4258 

 621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE (303) 623-9147 

 February 15, 2013 

Attention: Harvest (US) Holdings, Inc. – Director A 

1100 LOUISIANA, SUITE 3800 HOUSTON, TEXAS 77002-5218 TEL (713) 651-9191 FAX (713) 651-0849 

1015 4 STREET S.W. SUITE 600 CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790 TH 
HNR Finance 

February 15, 2013 

Page 2 

 

SEC PARAMETERS 

Estimated Net Reserves and Income Data 

Certain Interests of 

HNR Finance 

 

 

 

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold” or used in operations basis 

expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In 

this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$). 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 

 As of December 31, 2012 

 Proved 

 Developed 

Undeveloped 

 Total 

 Producing Non-Producing Proved 

Net Remaining Reserves 

Oil/Condensate—Barrels 15,158,007 449,977 27,553,515 43,161,499 

Gas—MMCF 19,467 2,917 6,628 29,012 

Income Data M$ 

Future Gross Revenue $ 1,008,929 $ 35,112 $ 1,595,043 $ 2,639,084 

Deductions 514,811 17,938 1,128,405 1,661,154 

 

Future Net Income (FNI) $ 494,118 $ 17,174 $ 466,638 $ 977,930 

Discounted FNI @ 10% $ 330,377 $ 10,261 $ 221,580 $ 562,218 

 Probable 

 Developed Total 

 Producing Undeveloped Probable 

Net Remaining Reserves 

Oil/Condensate—Barrels 10,408 68,334,688 68,345,096 

Gas—MMCF 1 53,655 53,656 

Income Data M$ 

Future Gross Revenue $ 709 $ 4,135,304 $ 4,136,013 

Deductions 348 2,829,432 2,829,780 

 

Future Net Income (FNI) $ 361 $ 1,305,872 $ 1,306,233 

Discounted FNI @ 10% $ 347 $ 583,390 $ 583,737 

 

Total Possible 

Undeveloped 

Net Remaining Reserves 

Oil/Condensate—Barrels 124,328,889 

Gas—MMCF 36,805 

Income Data M$ 

Future Gross Revenue $ 7,384,775 

Deductions 4,971,239 

 

Future Net Income (FNI) $ 2,413,536 

Discounted FNI @ 10% $ 912,113 
HNR Finance 

February 15, 2013 

Page 3 

 

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic 

software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C. The program was used 

at the request of HNR Finance. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and 

calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic 

summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding 

differences are not material. 

The deductions incorporate the normal direct costs of operating the wells, recompletion costs and development costs. Net taxes levied by 

the Venezuela government are incorporated into the “other taxes” and the “federal income tax” categories. The Windfall Profit Tax on oil 

levied by Venezuela pursuant to the Windfall Profit Tax Law of 2011 is incorporated as a deduction to net oil price received. The future net 

income is before the deduction of U.S. state and federal income taxes and general administrative overhead, and has not been adjusted for 

outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. 

Liquid hydrocarbon reserves account for approximately 99 percent and gas reserves account for the remaining 1 percent of total future 

gross revenue from proved reserves. Liquid hydrocarbon reserves account for approximately 98 percent and gas reserves account for the 

remaining 2 percent of total future gross revenue from probable reserves. Liquid hydrocarbon reserves account for approximately 99 percent 

and gas reserves account for the remaining 1 percent of total future gross revenue from possible reserves. 

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. 

Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary 

form as follows. 

 

The results shown above are presented for your information and should not be construed as our estimate of fair market value. 

Reserves Included in This Report 

The proved, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange 

Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum 

Reserves Definitions” is included as an attachment to this report. 

The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in 

this report. The proved, probable and possible developed non-producing reserves included herein consist of the behind pipe and shut-in 

categories. 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 

 

Discounted Future Net Income 

As of December 31, 2012 

Discount Rate 

Percent 

Total 

Proved 

Total 

Probable 

Total 

Possible 

5 $ 731,388 $ 866,760 $ 1,471,893 

8 $ 622,683 $ 682,661 $ 1,102,468 

12 $ 509,583 $ 500,064 $ 756,455 

15 $ 442,711 $ 397,636 $ 573,826 
HNR Finance 

February 15, 2013 

Page 4 

 

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved, 

probable and possible gas volumes presented herein include volumes of gas consumed in operations as reserves. 

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a 

given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty 

relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the 

date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the 

estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal 

classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further subclassified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At HNR Finance’s request, 

this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein. 

Proved oil and gas 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”. The SEC has defined reasonable certainty for proved 

reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” 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. 

Reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions 

change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and 

geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much 

more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a 

result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable 

and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the 

revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts. 

The reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce or a 

revenue interest in such production unless evidence indicates that contract renewal is reasonably certain. The expiration of the current contracts 

is on October 25, 2027. Furthermore, properties in Venezuela may be subjected to significantly varying contractual fiscal terms that affect the 

net revenue to HNR Finance for the production of these volumes. The prices and economic return received for these net volumes can vary 

significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
HNR Finance 

February 15, 2013 

Page 5 

 

discussed with HNR Finance the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and 

income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such 

contractual information nor our acceptance of HNR Finance’s representations regarding such contractual information should be construed as a 

legal opinion on this matter. 

Ryder Scott did not evaluate the country and geopolitical risks in Venezuela where HNR Finance operates and has interests. HNR 

Finance’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, 

but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension 

or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, 

environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and 

investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved, 

probable and possible reserves actually recovered and amounts of proved, probable and possible income actually received to differ significantly 

from the estimated quantities. 

The estimates of reserves presented herein were based upon a detailed study of the properties in which HNR Finance owns an interest; 

however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental 

liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating 

practices. 

Estimates of Reserves 

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of 

recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in 

accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating 

the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical 

procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These 

methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve 

evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and 

amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance 

characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property. 

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a 

range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is 

identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are 

estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by 

the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that 

addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable 

certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “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.” The SEC states that “possible reserves are those additional reserves 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
HNR Finance 

February 15, 2013 

Page 6 

 

that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of 

exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC 

definitions as noted above. 

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or 

engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised 

due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or 

geopolitical or economic risks as previously noted herein. 

The proved, probable, and possible reserves for the properties included herein were estimated by performance methods, the volumetric 

method, analogy, or a combination of methods. All of the proved producing reserves attributable to producing wells and/or reservoirs were 

estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, material balance 

and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through November, 2012 in those 

cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by HNR Finance or 

obtained from public data sources and were considered sufficient for the purpose thereof. 

All of the proved non-producing and undeveloped reserves included herein were estimated by a combination of the volumetric and 

analogy methods. All of the probable and possible reserves included herein were estimated by a combination of the volumetric and analogy 

methods. The volumetric analysis utilized pertinent well and seismic data supplied to Ryder Scott by HNR Finance or which we have obtained 

from public data sources that were available through November, 2012. The data utilized from the analogues as well as well and seismic data 

incorporated into our volumetric analysis were considered sufficient for the purpose thereof. 

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider 

many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and 

engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of 

future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to 

be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic 

producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of 

production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic 

conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. 

HNR Finance has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and 

reports and other data required for this investigation. In preparing our forecast of future proved, probable and possible production and income, 

we have relied upon data furnished by HNR Finance with respect to property interests owned, production and well tests from examined wells, 

normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, various taxes levied by the 

Venezuela government, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, 

adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. 

Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data 

furnished by HNR Finance. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates 

of reserves and future net revenues herein. 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
HNR Finance 

February 15, 2013 

Page 7 

 

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, 

and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The 

proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange 

Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, 

referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report 

comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations. 

Future Production Rates 

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production 

decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until 

a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has 

been established, this trend was used as the basis for estimating future production rates. 

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are 

not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by HNR 

Finance. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to 

unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, 

the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. 

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less 

than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, 

compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints 

set by regulatory bodies. 

Hydrocarbon Prices 

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the 

ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-themonth for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under 

contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the 

contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described. 

HNR Finance furnished us with the above mentioned average prices in effect on December 31, 2012. These initial SEC hydrocarbon 

prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the 

hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes 

the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price 

reference and benchmark prices may be defined by contractual arrangements. 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
HNR Finance 

February 15, 2013 

Page 8 

 

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark 

prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” 

The differentials used in the preparation of this report were furnished to us by HNR Finance. 

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the 

“average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before 

production taxes and the total net reserves by reserve category for the geographic area and presented in accordance with SEC disclosure 

requirements for each of the geographic areas included in the report. The average realized price before adjustment for Venezuela’s Windfall 

Profit tax is $ 89.77 /Bbl for the El Salto production and $ 100.41/Bbl for the production from the other fields. 

 

The yearly average gas sales price is $1.54 / MCF in all categories. The average price reflected in the proved producing category, and 

summaries including this category are affected by fuel gas use which is scheduled using a zero gas price. The effects of derivative instruments 

designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations. 

Costs 

Operating costs for the leases and wells in this report were furnished by HNR Finance and are based on the operating expense reports of 

HNR Finance and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and 

administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of 

corporate general administrative and overhead costs. The operating costs and foreign taxes furnished to us were accepted as factual data and 

reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by HNR 

Finance. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged 

directly to the leases or wells. 

Development costs were furnished to us by HNR Finance and are based on authorizations for expenditure for the proposed work or actual 

costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; 

however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included 

for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by HNR Finance 

were accepted without independent verification. 

The proved, probable and possible developed non-producing and undeveloped reserves in this report have been incorporated herein in 

accordance with HNR Finance’s plans to develop these reserves as of December 31, 2012. The implementation of HNR Finance’s development 

plans as presented to us and incorporated herein is subject to the approval process adopted by HNR Finance’s management. As 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 

Geographic 

Area Prod Field Area 

Price 

Reference 

Average 

Benchmark 

Prices 

Average 

Proved 

Realized 

Prices 

Average 

Probable 

Realized 

Prices 

Average 

Possible 

Realized 

Prices 

Venezuela Oil El Salto WTI Cushing $94.71/Bbl $56.87 /Bbl $56.87 /Bbl $56.87 /Bbl 

Venezuela Oil All Others WTI Cushing $94.71/Bbl $68.05 /Bbl $68.05 /Bbl $68.05 /Bbl 

Venezuela Gas All Fields Defined Contract NA $1.00/MCF $1.54/MCF $1.54/MCF 
HNR Finance 

February 15, 2013 

Page 9 

 

the result of our inquiries during the course of preparing this report, HNR Finance has informed us that the development activities included 

herein have been subjected to and received the internal approvals required by HNR Finance’s management at the appropriate local, regional 

and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE 

processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to HNR Finance. Additionally, HNR 

Finance has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their 

plans. 

Current costs used by HNR Finance were held constant throughout the life of the properties. 

Standards of Independence and Professional Qualification 

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout 

the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, 

Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large 

number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as 

officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and 

investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each 

engagement for our services. 

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of 

reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related 

topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education. 

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional 

accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s 

license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. 

We are independent petroleum engineers with respect to HNR Finance. Neither we nor any of our employees have any interest in the 

subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties 

which were reviewed. 

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder 

Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving 

the evaluation of the reserves information discussed in this report, are included as an attachment to this letter. 

Terms of Usage 

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set 

forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by HNR Finance. 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
HNR Finance 

February 15, 2013 

Page 10 

 

HNR Finance makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, HNR Finance has certain 

registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by 

reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of HNR Finance of the 

references to our name as well as to the references to our third party report for HNR Finance, which appears in the December 31, 2012 annual 

report on Form 10-K of HNR Finance. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by 

HNR Finance. 

We have provided HNR Finance with a digital version of the original signed copy of this report letter. In the event there are any 

differences between the digital version included in filings made by HNR Finance and the original signed report letter, the original signed report 

letter shall control and supersede the digital version. 

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please 

contact us if we can be of further service. 

 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 

Very truly yours, 

RYDER SCOTT COMPANY, L.P. 

TBPE Firm Registration No. F-1580 

/s/ Scott Wilson, P.E. 

Scott Wilson, P.E., M.B.A. 

Colorado License No. 36112 

Senior Vice President 

[SEAL] 
Professional Qualifications of Primary Technical Person 

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott 

Company, L.P. Mr. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and 

income presented herein. 

Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2000, is a Senior Vice President responsible for coordinating and 

supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, 

Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company. For more information regarding Mr. Wilson’s 

geographic and job specific experience, please refer to the Ryder Scott Company website at 

http://www.ryderscott.com/Experience/Employees.php. 

Mr. Wilson earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance 

from the University of Colorado in 1985, graduating from both with High Honors. He is a registered Professional Engineer by exam in the 

States of Alaska, Colorado, Texas, and Wyoming. He is also an active member of the Society of Petroleum Engineers; serving as co-Chairman 

of the SPE Reserves and Economics Technology Interest Group, and Gas Technology Editor for SPE’s Journal of Petroleum Technology. He is 

a member and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers. Mr. Wilson has published several 

technical papers, one book chapter, and has authored three US patents (two full and one pending). 

In addition to gaining experience and competency through prior work experience, the various boards of Professional Engineers require a 

minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson 

fulfills. As part of his continuing education, Mr. Wilson attends internally presented training as well as public forums relating to the definitions 

and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, 

Modernization of Oil and Gas Reporting, and Final Rule released January 14, 2009 in the Federal Register. Mr. Wilson attends additional hours 

of formalized external training covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir 

engineering and petroleum economics evaluation methods, procedures and software and ethics for consultants. 

Based on his educational background, professional training and more than 25 years of practical experience in the estimation and evaluation of 

petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III 

of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum 

Engineers as of February 19, 2007. 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS