10-K 1 bpz20131231_10k.htm FORM 10-K bpz20131231_10k.htm

 

 

 



 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

Form 10-K

 

 

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

 

For the fiscal year ended December 31, 2013

 

Or

 

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

 

For the transition period from                to

 

Commission File Number: 001-12697

 

BPZ Resources, Inc.

(Exact name of registrant as specified in its charter)

 

Texas

 

33-0502730

(State or other jurisdiction of incorporation)

 

(I.R.S. Employer Identification Number)

 

580 Westlake Park Blvd., Suite 525
Houston, Texas 77079
(Address of principal executive office)

 

Registrant’s telephone number, including area code:  (281) 556-6200

 

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

 

Title of Each Class

 

Name of Each Exchange on Which Registered

Common Stock, no par value

 

New York Stock Exchange

 

 

Securities registered pursuant to Section 12(g) of the Act:  None

 

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

 

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

 

Note — Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Exchange Act from their obligations under those Sections.

 

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 Web site, 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.   ☐

 

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

 

Large accelerated filer  ☐

 

Accelerated filer                    ☒

Non-Accelerated filer   ☐

 

Smaller reporting company   ☐

 

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

 

The number of shares of Common Stock held by non-affiliates as of June 30, 2013 was 62,229,599 shares, all of one class of common stock, no par value, having an aggregate market value of approximately $111,390,982 based upon the closing price of registrant’s common stock on such date of $1.79 per share as quoted on the New York Stock Exchange. For purposes of the foregoing calculation, all directors, executive officers, and 5% beneficial owners have been deemed affiliated.

 

 

 
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As of February 28, 2014 there were 118,604,622 shares of common stock, no par value, outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

 (1) Proxy Statement for 2013 Annual Meeting of Stockholders — Part III

 



 

 
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TABLE OF CONTENTS

 

PART I

   
     

Item 1.

Business

 4

Item 1A.

Risk Factors

12

Item 1B.

Unresolved Staff Comments

24

Item 2.

Properties

25

Item 3.

Legal Proceedings

34

Item 4

Mine Safety Disclosures

34

     

PART II

   

Item 5.

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

35

Item 6.

Selected Financial Data

37

Item 7.

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

38

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

78

Item 8.

Financial Statements and Supplementary Data

81

Item 9

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

135

Item 9A.

Controls and Procedures

135

Item 9B.

Other Information

137

     

PART III

   

Item 10.

Directors, Executive Officers and Corporate Governance

137

Item 11.

Executive Compensation

137

Item 12.

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

137

Item 13.

Certain Relationships and Related Transactions, and Director Independence

137

Item 14.

Principal Accountant Fees and Services

137

     

PART IV

   

Item 15.

Exhibits and Financial Statement Schedules

138

     

Glossary of Oil and Natural Gas Terms

139

     

Signatures

141

 

 
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PART I

 

BPZ Resources, Inc. cautions that this document contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in or incorporated by reference into this Form 10-K which address activities, events or developments which the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “may,” “will,” “should,” “could,” would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions are also intended to identify forward-looking statements. These statements are based on certain assumptions and analyses made by the management of BPZ in light of its experience and its perception of historical trends, current conditions and expected future developments, as well as other factors it believes are appropriate under the circumstances. The Company cautions the reader that these forward-looking statements are subject to risks and uncertainties, many of which are beyond its control, that could cause actual events or results to differ materially from those expressed or implied by the statements. See Item 1A. — “Risk Factors” included in this Form 10-K.

 

Unless the context requires otherwise, references in this Annual Report on Form 10-K to “BPZ”“we”, “us”, “our” and the “Company” refer to BPZ Resources, Inc., and its consolidated subsidiaries.

 

ITEM 1. BUSINESS

 

Overview

 

BPZ Resources, Inc., a Texas corporation, is based in Houston, Texas with offices in Lima, Peru and Quito, Ecuador. We are focused on the exploration, development and production of oil and natural gas in Peru and to a lesser extent Ecuador. We also intend to utilize part of our planned future natural gas production as a supply source for the complementary development of a gas-fired power generation facility in Peru which we expect to wholly- or partially-own.

 

We maintain a subsidiary, BPZ Exploración & Producción S.R.L. (“BPZ E&P”),  registered in Peru through our wholly-owned subsidiary BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership, and its subsidiary BPZ Energy, LLC, a Texas limited liability company. Currently, we, through BPZ E&P, have license contracts for oil and gas exploration and production covering a total of approximately 2.2 million gross (1.9 million net) acres, in four blocks, in northwest Peru. Our license contracts cover ownership of the following properties: 51% working interest in Block Z-1 (0.6 million gross acres), 100% working interest in Block XIX (0.5 million gross acres), 100% working interest in Block XXII (0.9 million gross acres) and 100% working interest in Block XXIII (0.2 million gross acres). The Block Z-1 contract was signed in November 2001, the Block XIX contract was signed in December 2003 and the Blocks XXII and XXIII contracts were signed in November 2007. Generally, according to the Organic Hydrocarbon Law No. 26221 and the regulations thereunder (the “Organic Hydrocarbon Law” or “Hydrocarbon Law”), the seven-year term for the exploration phase can be extended in each contract by an additional three years up to a maximum of ten years. However, this exploration extension is subject to government approval and specific provisions of each license contract can vary the exploration phase of the contract as established by the Hydrocarbon Law. The license contracts require us to conduct specified activities in the respective blocks during each exploration period in the exploration phase. If the exploration activities are successful, we may decide to enter the exploitation phase and our total contract term can extend up to 30 years for oil production and up to 40 years for gas production. In the event a block contains both oil and gas, as is the case in our Block Z-1, the 40-year term may apply to oil production as well. Our estimate of proved reserves has been prepared under the assumption that our license contract will allow production for the possible 40-year term for both oil and gas.

 

Additionally, through our wholly-owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, we own a 10% non-operating net profits interest in an oil and gas producing property, Block 2, located in the southwest region of Ecuador (the “Santa Elena Property”). In May 2013, the license agreement and operating agreement covering the property were extended from May 2016 through December 2029.

 

We are in the process of developing our Peruvian oil and gas reserves.  We entered commercial production for Block Z-1 in November 2010 and produce and sell oil from the Corvina and Albacora fields under our current sales contracts. We completed the installation of the new CX-15 platform in the Corvina field to continue the development of the field and continued our drilling campaign there with completion of the CX-15-1D well in December 2013 and the CX-15-2D well in January 2014. In February 2014 we spudded the third development well from the new CX-15 platform, the CX15-3D well. We also spudded the development well, the A-18D well, from the A platform in the Albacora field of Block Z-1 in September 2013 and completed it in December 2013. Another development well, the A-19D well, in the Albacora field was spudded in January 2014 and, after reaching the total depth, began production on March 1, 2014. From the time we began producing from the Corvina field in November 2007 and the Albacora field in December 2009, through December 31, 2013, the two fields have produced approximately 6.5 MMBbls (100% gross and net through December 14, 2012 and 51% net thereafter) of oil.

 

 
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On December 14, 2012 Perupetro S.A. (“Perupetro”), a corporation owned by the Peruvian government empowered to become a party in the contracts for the exploration and/or exploitation of hydrocarbons in order to promote these activities in Peru, approved the terms of the amendment to the Block Z-1 License Contract to recognize the sale of a 49% participating interest (“closing”), in offshore Block Z-1 to Pacific Rubiales Energy Corp. (“Pacific Rubiales”). Under terms of the agreements signed on April 27, 2012, we (together with our subsidiaries) formed an unincorporated joint venture with a Pacific Rubiales subsidiary, Pacific Stratus Energy S.A., to explore and develop the offshore Block Z-1 located in Peru. Pursuant to the agreements, Pacific Rubiales agreed to pay $150.0 million for a 49% participating interest, including reserves, in Block Z-1 and agreed to fund $185.0 million of our share of capital and exploratory expenditures in Block Z-1 (“carry amount”) from the effective date of the Stock Purchase Agreement (“SPA”), January 1, 2012. On December 30, 2012, the Peruvian Government signed the Supreme Decree for the execution of the amendment to the Block Z-1 License Contract.

 

At December 31, 2013, we had estimated net proved oil reserves of 16.1 MMBbls, of which 12.7 MMBbls were in the Corvina field and 3.4 MMBbls were from the Albacora field. Both fields are located in Block Z-1 offshore of northwest Peru. Of our total proved reserves, 3.2 MMBbls (19.9%) are classified as proved developed reserves consisting of proved developed producing reserves from 11 gross (5.6 net) wells, and 12.9 MMBbls (80.1%) are classified as proved undeveloped reserves. The process of estimating oil and natural gas reserves is complex and requires many assumptions that may turn out to be inaccurate. See Item 1A - “Risk Factors” for further information.

 

We have determined our reporting structure provides for only one operating segment as we only operate in Peru and currently have only one customer for our production. Information regarding our operating segment, including our revenues and long-lived assets can be found in the footnotes to our consolidated financial statements in Item 8 – “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

 

Our Business Plan

 

Our business plan is to enhance shareholder value through application of our knowledge of our targeted areas in Peru and to leverage management’s experience with the local suppliers and regulatory authorities to effectively and efficiently (i) identify and quantify the potential value of our oil and gas holdings in Peru; (ii) develop and increase production and cash flows from our identified holdings; (iii) create an additional revenue stream through implementation of our gas marketing strategy and (iv) bring working interest partners into some or all of our Peruvian blocks to facilitate the exploration and development of these blocks.

 

Our focus is to reappraise and develop properties that we control under license agreements in northwest Peru that have been explored by other companies that have reservoirs that appear to contain commercially productive quantities of oil and gas, as well as other areas that have geological formations that we believe potentially contain commercial amounts of hydrocarbons.

 

Our management team has extensive engineering, geological, geophysical, technical and operational experience and valuable knowledge of oil and gas operations throughout Latin America and, in particular, Peru.

 

Two of the four blocks (Block Z-1 and Block XXIII) contain structures drilled by previous operators who encountered hydrocarbons. However, at the time the wells were drilled, the operators did not consider it economically feasible to produce those hydrocarbons.  Having tested oil in Block Z-1 in our first well in the Corvina field in 2007 and our first well in Albacora in December 2009, we are focusing on development of the proved oil reserves in those two fields. Before considering further drilling activity in Block XIX, we are planning to acquire additional seismic data. In Block XXII, the environmental assessment process for an environmental permit is underway and approval must be received before anticipated drilling can begin in late 2014 or 2015. In January 2014, we spudded the first of three exploration wells, the Caracol 1X, in Block XXIII.

 

In the near term, management is focused on drilling operations at both the new platform, the CX-15, in the Corvina field and at the Albacora field, utilizing the results of the 1,600 square kilometers (“km”) of three dimensional (“3-D”) seismic survey in Block Z-1, and three exploratory wells in Block XXIII.

 

Credit Suisse Securities (USA) LLC is managing the formal process to find a joint venture partner for Blocks XIX and XXIII. The two Blocks comprise over 800,000 acres and hold both oil and gas potential, with Block XXIII bordering the northern part of the prolific Talara oil fields. Interested parties have reviewed the data, however, we believe it will be in the best interests of the Company to further de-risk the Block XXIII prospects by drilling up to three shallow exploratory wells on the large anticline identified by 3-D seismic to prove the existence of hydrocarbons before pursuing further partnering opportunities.

 

 
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In addition, our business plan includes a gas-to-power project as part of our overall gas marketing strategy, which entails the installation of a 10-mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and the building of an approximately 135 megawatt (“MW”) simple cycle electric generating plant. The proposed power plant site is located adjacent to an existing substation and power transmission lines which, with certain upgrades, are expected to be capable of handling up to 420 MW of power. The power generation facility may be wholly or partially owned by us, or wholly owned by a third party. The gas-to-power project is planned to generate a revenue stream by creating a market for the non-associated gas in our Corvina field that is currently shut-in. This project has not yet been financed and we continue to consider the alternatives for the project. Meanwhile, we have obtained certain permits and are in the process of obtaining additional permits to proceed with the project.

 

Available Information

 

We file annual, quarterly and periodic reports, proxy statements and other information with the Securities and Exchange Commission (the “SEC” or the “Commission”) in accordance with the Securities Exchange Act of 1934. You may read and copy this information at 100 F Street, N.E., Room 1580, Washington, D.C. 20549.

 

You can also obtain copies of such material from the Public Reference Section of the SEC, 100 F Street, N.E., Room 1580, Washington, D.C. 20549 at prescribed rates. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with it, like BPZ Resources, Inc. The SEC’s website can be accessed at http://www.sec.gov.

 

In addition, we maintain a website (www.bpzenergy.com) on which we also make available, free of charge, all of our above mentioned SEC filings, including Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Securities Act of 1934. These filings will be available as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

 

Our Competition

 

Intense competition exists in the oil and gas industry with respect to the acquisition of producing properties, undeveloped acreage, and rights to explore such properties. Many major and independent oil and gas companies actively pursue and bid for the mineral rights of desirable properties, and many companies have been actively engaged in acquiring oil and gas properties, specifically in Peru and Ecuador.

 

We believe our efforts in and knowledge of our targeted areas has given us a competitive advantage in Peru, and to a lesser extent, Ecuador. Although un-licensed tracts exist within our target area of Northwest Peru, the majority of our target areas are located within our Blocks. Increased demand for license contracts in surrounding areas may impact our ability to expand and grow in the future, particularly because many of our competitors have substantially greater financial and other resources, in addition to better name recognition and longer operating histories. As a result, we may not be able to compete successfully to acquire additional oil and gas properties in desirable locations.

 

Intense competition for access to drilling and other contract services and experienced technical and operating personnel needed to drill and complete wells also exists in the oil and gas industry. Competition for drilling and contract services in our target area exists and may affect our plan of operation. In addition, because we operate in a remote area of Peru, the limited availability of equipment could impact our operations or the cost of our operations. We continually monitor our operating plans and timelines to adapt to this dynamic environment. However, increasing future demand for drillers and contractors may limit our ability to execute in a timely manner and may negatively impact our ability to grow.

 

Customers

 

To date, all of our sales of oil in Peru have been made under contracts with the Peruvian national oil company, Petroleos del Peru - PETROPERU S.A. (“Petroperu”). However, we believe that the loss of our sole customer would not materially impact our business because we could readily find other purchasers for our oil production both in Peru and elsewhere in the world.

 

 
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Regulation Impacting Our Business

 

General

 

Various aspects of our oil and natural gas operations are currently or will be subject to various foreign laws and governmental regulations. These regulations may be changed from time to time in response to economic or political conditions.

 

Peru

 

Peruvian hydrocarbon legislation. Peru’s hydrocarbon legislation, which includes the Organic Hydrocarbon Law, governs our operations in Peru. This legislation covers the entire range of petroleum operations, defines the roles of Peruvian government agencies and related authorities which regulate and interact with the oil and gas industry, requires that investments in the petroleum sector be undertaken solely by private investors (either national or foreign), and provides for the promotion of the development of hydrocarbon activities based on free competition and free access to all economic activities. This regulation provides that pipeline transportation and natural gas distribution must be handled via contracts with the appropriate governmental authorities.

 

Under this legal system, Peru is the owner of the hydrocarbons located below the surface in its national territory. However, Peru has given the right to extract hydrocarbons to Perupetro. The Peruvian government also plays an active role in petroleum operations through the involvement of the Ministry of Energy and Mines (“MEM”), which is the body of the executive branch of the Peruvian government in charge of devising energy, mining and environmental protection policies, enacting the rules applicable to these sectors and supervising compliance with such policies and rules. The General Directorate of Hydrocarbons (“DGH”) is the agency of the Ministry of Energy and Mines responsible for regulating the optimum development of oil and gas fields and the Direccion General de Asuntos Ambientales Energeticos (“DGAAE”) is the agency of the Ministry of Energy and Mines responsible for reviewing and approving environmental regulations related to environment risks that result from hydrocarbon exploration and exploitation activities. The Environmental Evaluation and Fiscalization Entity (“OEFA”) is the agency within the Ministry of the Environment that is responsible for evaluating and ensuring compliance with applicable environmental rules covering hydrocarbon activities, and for sanctioning non-compliant companies.  The General Directorate of Mining and the Organismo Supervisor de la Inversión en Energía y Mineria (“OSINERGMIN”), an entity of the Ministry of the President, are responsible for ensuring compliance with occupational health and safety standards in the hydrocarbon industry. We are subject to the laws and regulations of all of these entities and agencies.

 

Perupetro generally enters into either license contracts or service contracts for hydrocarbon exploration and exploitation. Peru’s laws also allow for other contract models, but the models must be authorized by the Ministry of Energy and Mines. We only operate under license contracts and do not foresee operating under any services contracts in the immediate future. A company must be qualified by Perupetro to enter into hydrocarbon exploration and exploitation contracts in Peru. In order to qualify, the company must meet the standards under the Regulations Governing the Qualifications of Oil Companies. These qualifications generally require the company to have the technical, legal, economic and financial capacity to comply with all obligations it will assume under the contract. These requirements will depend on the characteristics of the area requested, the possible investments and the environmental protection rules governing the performance of its operations. When a contractor is a foreign investor, it is expected to incorporate a subsidiary company or registered branch in accordance with Peru’s laws and appoint local representatives who will interact with Perupetro.

 

Perupetro reviews a company’s qualification for each license contract to be signed by a company. Additionally, the qualification for foreign companies is granted in favor of the home office, in our case BPZ Resources, Inc., which provides a corporate guarantee to Perupetro. The corporate guarantee provides for joint and several liability to Perupetro with respect to the fulfillment of each minimum work program of the contract. BPZ Resources, Inc. and its corresponding subsidiary in Peru have been qualified by Perupetro with respect to our current contracts as required by regulation.

 

When operating under a license contract, the licensee is the owner of the hydrocarbons extracted from the contract area once the corresponding royalty has been paid to Perupetro. The licensee can market the hydrocarbons in any manner whatsoever and can fix hydrocarbon sales prices according to market forces, subject to a limitation in the case of natural emergencies, in which case the law stipulates such manner of marketing.

 

Licensees are obligated to submit quarterly reports to the DGH. Licensees must also submit a monthly economic report to the Central Reserve of Peru (“Banco Central de Reserva”). These reports are generally combined and delivered together with other operating reports required to be submitted to Perupetro.

 

 
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The duration of the license contracts is based on the nature of the hydrocarbons discovered. The license contract duration for crude oil is 30 years, while the contract duration for natural gas and condensates is 40 years. In the event a block contains both oil and gas, as is the case in our Block Z-1, the 40-year term may apply to oil exploration and production as well. The license contract commences on an agreed date, the effective date, established in the license contract. Most contracts typically include an exploration phase and an exploitation phase, unless the contract is solely an exploitation contract. Within the contract term, seven years is allotted to exploration, with the possibility of an extension of up to three years, granted at the discretion of Perupetro. A potential deferment period for a maximum of ten years is also available if certain factors recognized by law delay the economic viability of a discovery, such as a lack of transportation facilities or a lack of a market. The exploration phase is generally divided into several periods and each period includes a minimum work program. The term of the exploration phase may last longer than the prescribed seven years, or ten years if the three-year extension was granted, as the time elapsed for the approval of the respective environmental permits is not taken into consideration as part of the respective exploration period. However, the term of the license contract stays the same. The fulfillment of the minimum work program must be supported by an irrevocable bank guaranty, usually in the amount of fifty percent of the estimated value of the minimum work program.

 

We currently have four license contracts. As of March 12, 2014, we believe we are in compliance with all of the material requirements of each contract. We have executed certain letters of guaranty in favor of Perupetro to insure our performance under the license contracts. At December 31, 2013, we had $5.7 million in bonds posted at various dates to secure our obligation under the license contracts for Blocks XIX, XXII, XXIII and Z-1. The license contract bonds are partially secured by the deposit of restricted cash in the amount of $3.5 million with the financial institutions which issued the bonds. Should we fail to fulfill our minimum work program obligations under any of our license contracts without technical justification or other good cause, Perupetro could seek recourse to the bond or terminate the license contract. Additionally, we have $0.6 million of restricted cash for performance of work related to construction of our gas-to-power project.

 

Legislation in Peru was passed by Supreme Decree 088-2009 on December 13, 2009 with respect to regulating well testing and gas flaring. The legislation provides that all new wells may be properly placed on production testing for up to six months. If the operator believes a longer period for testing the well is needed to evaluate the productive capacity of the field, the legislation provides a process by which an operator can request an extension to allow for additional testing – extended well testing (“EWT”). After the initial six-month period or after an EWT program expires, the operator will be required to have the necessary gas and water reinjection equipment in place to continue operating the well according to existing environmental regulations.

 

Peruvian fiscal regime. Peru’s fiscal regime determines the government’s entitlement from petroleum activities. This regime is subject to change, which could negatively impact our business. However, the Organic Hydrocarbon Law and the Regulations Governing the Tax Stability Guaranty and Other Tax Rules of the Organic Hydrocarbon Law provide that the tax regime in force on the date of signing a contract will remain unchanged during the term of the contract. Therefore, any change to the tax regime, which results in either an increase or decrease in the tax burden, will not affect the operator.

 

License contracts include royalty payment schemes, which are usually a fixed percentage of the actual production that is verified by Perupetro. The regulations stipulate a minimum royalty payment of five percent for production less than 5,000 Boepd, increasing incrementally to a maximum of twenty percent for production greater than 100,000 Boepd. However, when a company bids for a license contract on a new area it can elect to voluntarily increase the royalty percentage above the sliding scale rate in its bid to improve its chances of success. See Item 2. “Properties” for further information regarding royalties applicable to each Block.

 

During the exploration phase, operators are exempt from import duties and other forms of taxation applicable to goods intended for exploration activities. Exemptions are withdrawn at the production phase, but exceptions are made in certain instances, and the operator may be entitled to temporarily import goods tax-free for a two-year period (“Temporary Import”). Temporary Import may be extended for additional one year periods for up to two years upon operator request, approval of the MEM and authorization of SUNAD (Peruvian Customs Agency).

 

Taxable income is determined by deducting allowable operating and administrative expenses, including royalty payments. Income tax is levied on the income of the operator based upon the legal corporate tax rate in effect at the date the license contract was signed. Operators engaged in the exploration and production of crude oil, natural gas and condensates must determine their taxable income separately for each license contract under which they operate. Where a contractor carries out these activities under different individual license contracts, it may offset its earnings before income tax under one license contract with losses under another license contract, for purposes of determining the corporate income tax, provided that the individual license contracts are held by the same company, as Peruvian tax law does not permit filing a consolidated tax return for related companies. However, under no circumstances can the investment in the producing property be amortized for tax purposes unless the company is under the commercial stage of production.

 

 
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Peruvian labor and safety legislation. Our operations in Peru are also subject to the Labor Law, which governs the labor force in the petroleum sector. In addition, the Organic Hydrocarbon Law and related Safety Regulations for the Petroleum Industry also regulate the safety and health of workers involved in the development of hydrocarbon activities. All entities engaged in the performance of activities related to the petroleum industry must provide the General Hydrocarbons Bureau with the list of their personnel on a semi-annual basis, indicating their nationality, specialty and position. These entities must also train their workers on the application of safety measures in the operations and control of disasters and emergencies. The regulations also contain provisions on accident prevention and personnel health and safety, which in turn include rules on living conditions, sanitary facilities, water quality at workplaces, medical assistance and first-aid services. Provisions specifically related to the exploration phase are also contained in the regulations and include safety measures related to camps, medical assistance, food conditions, and handling of explosives. Additional safety regulations may also become applicable as we expand and develop our operations.

 

The Labor laws and regulations also define the employer/employee relationship.  As such, employers can only terminate the employment relationship for just cause as established by Peruvian law.  If an employee is terminated for any reason other than those listed in the Law on Productivity and Labor Competitiveness, the employer will be required to pay an indemnity to the employee for arbitrary dismissal (calculated according to the length of service), or may be required to reinstate the employee.

 

The Constitution of Peru and Legislative Decree Nos. 677 and 892 give employees working in private companies engaged in activities generating income, as defined by the Income Tax Law, the right to share in a company’s profits. This profit sharing is carried out through the distribution by the company of a percentage of the annual income before tax. According to Article 3 of the United Nations International Standard Industrial Classification, BPZ Resources, Inc.’s tax category is classified under the “mining companies” section, which sets the rate at 8%. However, in Peru, the Hydrocarbons’ Law states, and the Supreme Court ruled, that hydrocarbons are not related to mining activities. Hydrocarbons are included under “Companies Performing other Activities,” and as a result, oil and gas companies pay profit sharing at a rate of 5%. The benefit granted by the law to employees is calculated on the basis of the “net income subject to taxation” and not on the net business or accounting income of companies. “Taxable income” is obtained after deducting from total revenues subject to income tax, the expenses required to produce them or maintain the source thereof.

 

Peruvian environmental regulation. Our operations are subject to numerous changing laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Peru has enacted specific environmental regulations applicable to the hydrocarbon industry. The Code on the Environment and the Natural Resources establishes a framework within which all specific laws and regulations applicable to each sector of the economy are to be developed. These laws and regulations are designed to ensure a continual balance of environmental and petroleum interests. The regulations stipulate certain environmental standards expected from contractors. They also specify appropriate sanctions to be enforced if a contractor fails to maintain such standards. The OEFA is the agency within the Ministry of the Environment that is responsible for evaluating and ensuring compliance with applicable environmental laws and regulations covering hydrocarbon activities, and for sanctioning non-compliant companies. 

 

The Environmental Regulations for Hydrocarbon Activities provide that companies participating in the implementation of projects, performance of work and operation of facilities related to hydrocarbon activities are responsible for the emission, discharge and disposal of wastes into the environment. Companies file an annual report describing the company’s compliance with the current environmental legislation.

 

Companies involved in hydrocarbon activities must also prepare and file an Environmental Impact Study (“EIS”) or Environment Impact Assessment (“EIA”) with the DGAAE, which is part of the Ministry of Energy and Mines, in order for a Company to demonstrate that its activities will not adversely affect the environment and to show compliance with the maximum permissible emission limits set forth by the Ministry of Energy and Mines. An EIS must be prepared for each project to be carried out. All of these proposals must be approved in advance by the DGAAE.

 

In May 2013, the Peruvian government enacted several Supreme Decrees that adopted special provisions to speed up administrative procedures, special provisions for the performance of administrative procedures and other measures to encourage private and public investment projects. These provisions establish reduced time periods for obtaining approvals to protect archaeological, water and other environmental resources, including approval of Environmental Impact Studies. These new measures are expected to speed up the hydrocarbon investments in the existing license contracts for the exploration and exploitation of hydrocarbons in Peru. We cannot, however, predict the actual effectiveness or benefits of these new measures.

 

 
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In addition, any party responsible for hydrocarbon activities must file an “Oil Spill and Emergency Contingency Plan” with the General Hydrocarbons Bureau, which is part of the Ministry of Energy and Mines. The plan must be updated at least once a year and must contain information regarding the measures to be taken in the event of spills, explosions, fires, accidents, evacuation, etc.

 

Peru has enacted amendments to its environmental law, imposing restrictions on the use of natural resources, interference with the natural environment, location of facilities, handling and storage of hydrocarbons, use of radioactive material, disposal of waste, emission of noise and other activities. Additionally, the laws require monitoring and reporting obligations in the event of any spillage or unregulated discharge of hydrocarbons.

 

Any failure to comply with environmental protection laws and regulations, the import of contaminated products, or the failure to keep a monitoring register or send reports to the General Hydrocarbons Bureau in a timely fashion could subject the company responsible for non-compliance to fines. In addition, the General Hydrocarbons Bureau may consider imposing a prohibition or restriction of the relevant activity, an obligation to compensate the aggrieved parties and/or an obligation to immediately restore the area. The company responsible for any default may also be subject to a suspension of operations for a term of one, two or three months, or indefinitely. Furthermore, any contract entered into with the Peruvian government, the implementation of which jeopardizes or endangers the protection or conservation of protected natural areas, may be terminated.

 

We are subject to all present and future Peruvian environmental regulations applicable to the petroleum industry. For example, we are required to obtain an environmental permit or approval from the government in Peru prior to conducting any seismic operations, drilling a well or constructing a pipeline in Peruvian territory, including the waters offshore in Peru where we currently conduct oil and gas operations. As in many countries, there is an element of uncertainty in how Peruvian authorities will enforce and supervise environmental compliance and standards. Further, we cannot predict any future regulation or the cost associated with future compliance.

 

Peruvian electric power legislation. Our business plan envisions the sale of natural gas for power generation or the generation of electricity to monetize our natural gas and the sale of such electric power in Peru. The basic laws of Peru governing electric power, which will apply to our future operations, are the Law of Electric Power Concessions and the Regulations for the Environmental Protection of Electric Power Activities, and the corresponding regulations for each, as well as additional related laws and regulations, including all legislation regarding Electric Power Tariffs and all regulations and technical norms created by the National Commission of Electric Power Tariffs.

 

Compliance with Existing Legislation in Peru

 

Although we believe our operations are and will continue to be in substantial compliance with existing legislation and requirements of Peruvian governmental bodies, our ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls. Our management team has extensive experience in dealing directly with the Peruvian government on energy projects. Therefore, we believe we are in a good position to understand and comply with local rules and regulations. However, our current permits and authorizations as well as our ability to obtain future permits and authorizations may, over time, be susceptible to increased scrutiny and greater complexity which could result in increased costs or delays in receiving appropriate authorizations.

 

Ecuador

 

SMC Ecuador, Inc., our wholly-owned subsidiary, has held its 10% non-operating net profits interest in the Santa Elena oil fields since 1997. We acquired all of the common stock of SMC Ecuador Inc. in 2004. As a non-operator, we are not directly subject to the laws and regulations of Ecuador covering the oil and gas industry and the environment. However, if we begin operating activities in Ecuador, we will be directly subject to such laws and regulations.

 

Environmental Compliance and Risks

 

As a licensee and operator of oil and gas properties in South America, and in particular Peru, we are subject to various national, state and local laws and regulations relating to the discharge of materials into, and the protection of, the environment. These laws and regulations may, among other things, impose liability on the licensee under an oil and gas license agreement for the cost of pollution clean-up resulting from operations, subject the licensee to liability for pollution damages, and require suspension or cessation of operations in affected areas.

 

 
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In addition to certain pollution coverage related to our surface facilities, we also maintain insurance coverage for seepage and pollution, cleanup and contamination from our wells. Regardless, no such coverage can insure us fully against all risks, including environmental risks. We are not aware of any environmental claims which would have a material impact upon our financial position or results of operations.

 

We will continue our efforts to comply with these requirements, which we believe are necessary to maintain successful long-term operations in the oil and gas industry. As part of this effort we have established guidelines for continuing compliance with environmental laws and regulations. In order to carry out our plan of operation, we are required to conduct environmental impact studies and obtain environmental approvals for operations. We have engaged outside consultants to perform these studies and assist us in obtaining necessary approvals. Our cost for these studies and assistance related to the Block Z-1, Block XIX, Block XXII and Block XXIII for the year ended December 31, 2013, 2012, and 2011 were approximately $0.3 million, $0.5 million, and $1.6 million, respectively.

 

We believe we are in compliance with national, state and local provisions regarding the regulation of discharge of materials into the environment, or otherwise relating to the protection of the environment. However, there is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not negatively impact our operations in the future.

 

Operational Hazards and Insurance

 

Our operations are subject to the usual hazards incidental to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution, releases of toxic gas and other environmental hazards and risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations.

 

As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such insurance is not available or because the costs are considered prohibitive. We currently have insurance coverage which we believe is adequate for our current stage of operations based on management’s assessment. Such insurance may not cover every potential risk associated with the drilling, production and processing of oil and gas. In particular, coverage is not obtainable for all types of environmental hazards. Additionally, the occurrence of a significant adverse event, the risks of which are not fully covered by our insurance policy, could have a material adverse effect on our financial condition and results of operations. Moreover, no assurance can be given that we will be able to maintain adequate insurance or increase current coverage amounts at rates we consider reasonable.

 

Research and Development

 

We seek to use advanced technologies in the evaluation of our oil and gas properties and in evaluating new opportunities. We generally do not develop such technologies internally, but our technical team works with outside vendors to test and utilize these technologies to the fullest extent practical, particularly in the application of geophysical, geological and engineering software. We do not believe we have incurred any quantifiable incremental costs in connection with research and development.

 

Employees

 

As of December 31, 2013, we employed 27 full-time employees of BPZ Resources, Inc., and 66 full-time employees within our subsidiaries BPZ E&P, BPZ Marine Peru S.R.L., and Soluciones Energeticas, S.R.L.

 

We believe that our relationship with our employees is satisfactory. None of our employees are currently represented by a union.

 

 
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ITEM 1A. RISK FACTORS

 

Risks Relating to the Oil and Natural Gas Industry, the Power Industry, and Our Business.

 

Our reserve estimates depend on many assumptions that may turn out to be inaccurate. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors that may turn out to be inaccurate. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the estimated value of reserves.

 

In order to prepare our reserve estimates, our independent petroleum engineers must project production rates and timing of development expenditures as well as analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process of estimating reserves also requires economic assumptions about matters, such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise, and can vary.

 

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates, and those variances may be material.  Any significant variance could materially affect the estimated quantities and estimated value of our reserves.

 

We continue to assess new data we have collected or will collect in the near future, including the continuing assessment of recently acquired 3-D seismic data, analysis of cores drawn or to be drawn from our drilling program, production from our recent drilling program and planned acquisition of additional two dimensional (“2-D”) and 3-D seismic data. The results of our assessments could affect reported reserves. In addition, our independent petroleum engineers may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

 

You should not assume that the estimated value of our proved reserves prepared in accordance with the SEC’s guidelines referred to in this report is the current market value of our estimated oil reserves. We base the estimated value of future net cash flows from our proved reserves on an unweighted arithmetic average of the first-day-of-the month price for each month during the 12-month calendar year and year-end costs. Actual future prices, costs, taxes and the volume of produced reserves may differ materially from those used in the estimated value.

 

We have entered into a significant joint venture. This joint venture may limit our operations and corporate flexibility in Block Z-1; actions taken by our joint venture partner in Block Z-1 may materially impact our financial position and results of operation, and we may not realize the benefits we expect from this joint venture. Various aspects of our Pacific Rubiales joint venture could materially impact us: The development of Block Z-1 is subject to the terms and conditions of a Joint Operating Agreement and we no longer have unlimited flexibility to control the development of this property. We share approval rights over major decisions and overall supervision of joint operations through a joint operating committee. Pacific Rubiales may have interests and goals that are inconsistent with ours. The performance of our joint venture partner’s obligations under the Joint Operating Agreement is outside of our direct control. The ability or failure of our joint venture partner to pay its funding commitment, including costs to be paid on our behalf during the term of the carry agreement, could increase our costs of operations or result in reduced drilling and production of oil and gas, or loss of rights to develop Block Z-1. These restrictions may preclude transactions that could be beneficial to our shareholders. Pacific Rubiales is the technical operator of the field under an Operating Services Agreement. Their ability to deliver the continued safe and efficient operations of the block under this agreement will have a material impact on us. Disputes between us and our joint venture partner, or actions taken by our joint venture partner, may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business. 

 

        We have not been profitable since we commenced operations and have historically had limited earnings from operations.  To date, we have been unable to support our exploration and development activities solely through earnings from operations.  While we currently have a working capital surplus, the sources of our working capital surplus have generally been equity issuances, debt financings and asset sales, rather than revenue from operations, and we may incur working capital deficits in the future.  We cannot provide any assurance that we will be profitable in the future or that we will be able to generate cash from operations or financings to fund working capital deficits.

 

 
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Our business involves many uncertainties and operating risks that may prevent us from realizing profits and can cause substantial losses. Our exploration and production activities may be unsuccessful for many reasons, including weather, the drilling of dry holes, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well will not ensure we will realize a profit on our investment. A variety of factors, including geological, regulatory and market-related factors can cause a well to become uneconomical or only marginally economical. Our business involves a variety of operating risks, including:

 

 

fires; 

 

explosions; 

 

blow-outs and surface cratering; 

 

uncontrollable flows of natural gas, oil and formation water; 

 

natural disasters, such as earthquakes, tsunamis, typhoons and other adverse weather conditions; 

 

pipe, cement, subsea well or pipeline failures; 

 

casing collapses; 

 

mechanical difficulties, such as lost or stuck oil field drilling and service tools; 

 

abnormally pressured formations; or 

 

environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

 

Experiencing any of these operating risks could lead to problems with any well bores, platforms, barges, gathering systems and processing facilities, which could adversely affect our present and future drilling operations. Affected drilling operations could further lead to substantial losses as a result of:

 

 

injury or loss of life; 

 

severe damage to and destruction of property, natural resources and equipment; 

 

pollution and other environmental damage; 

 

clean-up responsibilities; 

 

regulatory requirements, investigations and penalties; 

 

suspension of our operations; or 

 

repairs to resume operations.

 

If any of these risks occur, we may have to curtail or suspend any drilling or production operations and we could have our oil sales interrupted or suspended, which could have a material adverse impact on our financial condition, operations and ability to execute our business plan.

 

We require additional financing for the exploration and development of our oil and gas properties and the construction of our proposed power generation facility, pipeline and gas processing facility. Since becoming a public company in 2004, we have funded our operations with the net proceeds of sales of securities, debt financing and the sale of a 49% participating interest in Block Z-1 for $150.0 million in 2012. We began to generate revenues from operations in the fourth quarter of 2007. We will need additional financing to fully implement our development plan. As we continue to execute our business plan and expand our operations, our cash generation from operations along with our commitments are likely to increase and, therefore, the likelihood of our seeking additional financing, either through the equity markets, debt financing, joint ventures, asset sales or a combination thereof may occur.  If we are unable to timely generate or obtain adequate funds to finance our exploration and development plans, our ability to develop our oil and natural gas reserves may be limited or substantially delayed. Such limitations or delays could result in a failure to realize the full potential value of our properties (and could affect the value of our properties as recorded in our financial statements) or could result in the potential loss of our oil and gas properties if we were unable to meet our obligations under the license agreements, which could, in turn, limit our ability to repay our debts. Inability to timely generate or obtain funds also could cause us to delay, scale back or abandon our plans for construction of our power generation facility, pipelines and gas processing facility.

 

We may obtain future amounts required to fund our activities through additional equity and debt financing, joint venture arrangements, the sale of oil and gas interests, and/or future cash flows from operations. However, adequate funds may not be available when needed or may not be available on favorable terms. The exact nature and terms of such funding sources are unknown at this time, and there can be no assurance that we will obtain such funding or have funding available to adequately finance our future operations.

 

Changes in the financial and credit market may impact economic growth and may also affect our ability to obtain funding on acceptable terms. Global financial markets and economic conditions have been disruptive and volatile.  Accordingly, the equity capital markets can become exceedingly distressed.  Market discontinuities, credit risk pricing and weak economic conditions can make it difficult to obtain debt or equity capital funding. In addition, debt securities generally are susceptible to interest rate risk, which is the chance that bond prices overall will decline because of rising interest rates.

 

 
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Due to these and possibly other factors, we cannot be certain funding will be available when and if needed, and to the extent required, on acceptable terms.  If funding is not available as needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our exploratory and development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.

 

We have a limited operating history and have only been in commercial production in our Block Z-1 since November 2010. We are in the initial stages of developing our oil and natural gas reserves. We have transitioned from an extended well testing program into commercial production in the Corvina and Albacora fields in our Block Z-1 and have produced and sold oil under extended well testing programs in both fields in the past.  We are also subject to all of the risks inherent in attempting to expand a relatively new business venture. Such risks include, but are not limited to, the possible inability to profitably operate our existing properties or properties to be acquired in the future, our possible inability to fully fund the development requirements of such properties and our possible inability to acquire additional properties that will have a positive effect on our operations. We can provide no assurance that we will achieve a level of profitability that will provide a return on invested capital or that will result in an increase in the market value of our securities.  Accordingly, we are subject to the risk that because of these factors and other general business risks noted throughout these “Risk Factors,” we may not be able to profitably execute our plan of operation. 

 

As of December 31, 2013, approximately 80% of our estimated net proved reserves were undeveloped. There can be no assurance that all of these reserves will ultimately be developed or produced.  We own rights to oil and gas properties that have limited or no development. We can provide no guarantees that our properties will be developed profitably or that the potential oil and gas resources on the property will produce as expected if they are developed.

 

Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations.  The reserve data assumes that we will make significant capital expenditures to develop our reserves.  We have prepared estimates of our oil reserves and the costs associated with these reserves in accordance with industry standards.  However, the estimated costs may not be accurate, development may not occur as scheduled, or the actual results may not be as estimated.  Our estimates of reserves may change from time to time depending upon our ability to produce such reserves in a timely manner. We may not have or be able to obtain the capital we need to develop these proved reserves.

 

As of December 31, 2013, we had eight proved undeveloped reserve locations in the Corvina field or 5.0 MMBbls included in our proved oil reserves that are scheduled to be drilled after five years from initial disclosure of the related reserves. All proved undeveloped locations scheduled to be drilled after five years of initial disclosure are the result of unexpected governmental permitting delays, facilities limitations on the CX-11 offshore platform and contractual, as well as construction issues related to the CX-15 offshore platform in Block Z-1 located in environmentally sensitive remote locations. These proved undeveloped reserves are located in areas where we continue to actively drill. Our recognition of the proved undeveloped reserves scheduled to be drilled after the initial five year period could be, based on available precedent, challenged by regulatory authorities and there is a risk that our reserves would have to be revised to exclude these reserves. We believe the specific circumstances surrounding the drilling delays allow for inclusion of these reserves, but there is risk that our position may not prevail if challenged.

 

We may not be able to replace our reserves. Our future success will depend upon our ability to find, acquire and develop oil and gas reserves that are economically recoverable. Any reserves we develop will decline as they are produced unless we are able to conduct successful revitalization activities or are able to replace the reserves by acquiring properties containing proven reserves, or both. To develop reserves and achieve production, we must implement our development and production programs, identify and produce previously overlooked or by-passed zones and shut-in wells, acquire additional properties or undertake other replacement activities. We can give no assurance that our planned development, revitalization, and acquisition activities will result in significant reserves replacement or that we will have success in discovering and producing reserves economically. We may not be able to locate geologically satisfactory property, particularly since we will be competing for such property with other oil and gas companies, most of which have much greater financial resources than we do. Moreover, even if desirable properties are available to us, we may not have sufficient funds with which to acquire or develop them.

 

 
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Any failure to meet our debt obligations, including our Convertible Notes due 2015 or our Convertible Notes due 2017, would adversely affect our business and financial condition. During the first quarter of 2010, we issued $170.9 million of Convertible Notes due 2015 (the “2015 Convertible Notes”), which bear interest semi-annually at a rate of 6.50% per year. In the third quarter of 2013, we issued $143.8 million of Convertible Notes due 2017 (the “2017 Convertible Notes”), which bear interest semi-annually at a rate of 8.50% per year. Following the 2017 Convertible Notes issuance, in September 2013, we repurchased $85.0 million of the principal balance of the $170.9 million of the 2015 Convertible Notes. The 2015 Convertible Notes mature with repayment of $85.9 million (assuming no conversion by the note holders) due on March 1, 2015. If we experience any one of certain types of corporate transactions, holders of the notes may require us to repurchase, for cash, all or a portion of their notes. Any repurchase of the notes pursuant to these provisions will be for cash at a price equal to 100% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excluding, the purchase date. Should any 2015 Convertible Notes not be redeemed or converted or any 2017 Convertible Notes not be converted, repayment of such notes in cash is required at the applicable maturity date. We may not have sufficient funds to pay the interest, repurchase price or cash in respect of our conversion obligation when due. If we fail to pay interest on the notes, repurchase the notes or pay any cash payment due when required (whether on an interest payment date, at maturity, upon repurchase, upon conversion or otherwise), we will be in default under the indenture governing the notes. The indenture contains customary terms and covenants and events of default. If an event of default (as defined therein) occurs and is continuing, the trustee, by notice to us, or the holders of at least 25% in aggregate principal amount of the 2015 Convertible Notes or the 2017 Convertible Notes then outstanding, as applicable, by notice to us and the trustee, may declare the principal and accrued and unpaid interest (including additional interest or premium, if any) on the 2015 Convertible Notes or 2017 Convertible Notes, as applicable, to be due and payable. In the case of an event of default arising out of certain bankruptcy events (as set forth in the Indenture), the principal and accrued and unpaid interest (including additional interest or premium, if any), on the notes will automatically become due and payable.

 

Our ability to meet our current and future debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets or sell shares of common stock on terms that we do not find attractive, if it can be done at all.

 

We are assessing additional joint venture or partner relationships in our other blocks and our power generation project which subjects us to additional risks that could have a material adverse effect on the success of our operations, our financial position and our results of operations. We may enter into additional joint venture arrangements in the future for Block Z-1 or our other blocks and our power generation project. These third parties may have obligations that are important to the success of the joint venture, including technical and operational as well as the obligation to pay their share of capital and other costs of the joint venture. The performance of these obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside our direct control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely affected. Any joint venture arrangements we may enter into may involve risks not otherwise present when exploring and developing properties directly, including, for example:

 

 

our joint venture partners may share certain approval rights over major decisions;

 

our joint venture partners may not pay their share of the joint venture’s obligations, leaving us liable for their shares of joint venture liabilities;

 

we may incur liabilities as a result of actions taken by our joint venture partners;

 

our joint venture partners may have economic or business interests or goals that are inconsistent with, or adverse to, our interests or goals;

 

our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives; and

 

disputes between us and our joint venture partners may result in delays, litigation or operational impasses.

 

The risks described above or the failure to continue our joint venture or to resolve disagreements with our joint venture partner could adversely affect our ability to transact the business that is the subject of such joint venture and increase our expenses, which would in turn negatively affect our financial position and results of operations.

 

Our future operating revenue depends upon the performance of our properties. Our future operating revenue depends upon our ability to profitably operate our existing properties by drilling and completing wells that produce commercial quantities of oil and gas and our ability to expand our operations through the successful implementation of our plans to explore, acquire and develop additional properties. The successful development of oil and gas properties requires an assessment of potential recoverable reserves, future oil and gas prices, operating costs, potential environmental and other liabilities and other factors. Such assessments are necessarily inexact. No assurance can be given that we can produce sufficient revenue to operate our existing properties or acquire additional oil and gas producing properties and leases. We may not discover or successfully produce any recoverable reserves in the future, or we may not be able to make a profit from the reserves that we may discover. In addition, we regularly bring wells on or offline depending on technical performance, work-over requirements and, if applicable, testing period requirements.  In the event that we are unable to produce sufficient operating revenue to fund our future operations, we will be forced to seek additional third-party funding, if such funding can be obtained. Such options would possibly include debt financing, sale of equity interests, joint venture arrangements, or the sale of oil and gas interests. If we are unable to secure such financing on a timely basis, we could be required to delay or scale back our operations. If such unavailability of funds continued for an extended period of time, this could result in the termination of our operations and the loss of an investor’s entire investment.

 

 
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Future oil and natural gas price declines or unsuccessful exploration efforts may result in significant charges or a write-down of our asset carrying values.   We follow the successful efforts method of accounting for our investments in oil and natural gas properties.  Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred. Certain costs of exploratory wells are capitalized pending determinations that proved reserves have been discovered.  If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed.

 

The capitalized costs of our oil and natural gas properties, on a field basis, cannot exceed the estimated undiscounted future net cash flows of that field.  If net capitalized costs exceed undiscounted future net cash flows, we must write down the costs of each such field to our estimate of its fair market value.  Unproved properties are evaluated at the lower of cost or fair market value.  Accordingly, a significant decline in oil or natural gas prices or unsuccessful exploration efforts could cause a future write-down of capitalized costs.

 

We evaluate impairment of our proved oil and gas properties whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. In addition, write-downs would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues.  Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date even if oil or natural gas prices increase.

 

Demand for oil and natural gas is highly volatile.  A substantial or extended decline in oil prices and, to a limited extent, natural gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations as well as our ability to meet our capital expenditure obligations and financial commitments necessary to implement our business plan.  Any revenues, cash flow, profitability and future rate of growth we achieve will be greatly dependent upon prevailing prices for oil and gas. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms is also expected to be dependent on oil and gas prices.

 

Historically, oil and gas prices and markets have been volatile and are likely to be volatile again in the future. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand for oil and gas, market uncertainty, and a variety of additional factors beyond our control. Those factors include among others:

 

 

international political conditions (including wars and civil unrest, such as the recent unrest in the Middle East); 

 

the domestic and foreign supply of oil and gas; 

 

the level of consumer demand; 

 

weather conditions; 

 

domestic and foreign governmental regulations and other actions; 

 

actions taken by the Organization of Petroleum Exporting Countries (“OPEC”); 

 

the price and availability of alternative fuels; and 

 

overall global economic conditions.

 

 Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but may also reduce the amount of oil and natural gas we can produce economically, if any, and, as such, may have a negative impact on our reserves. A continuation of low or significant declines in oil and natural gas prices may materially affect our future business, financial condition, results of operations, liquidity and borrowing capacity, and may require a reduction in the carrying value of our oil and gas properties. While our revenues may increase if prevailing oil and gas prices increase significantly, exploration and production costs and acquisition costs for additional properties and reserves may also increase.  We currently do not enter into hedging arrangements or use derivative financial instruments such as crude oil forward and swap contracts to hedge our risk associated with fluctuations in commodity prices.

 

 
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 Our oil and gas operations involve substantial costs and are subject to various economic risks. Our oil and gas operations are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire producing properties and to drill exploratory wells. The cost and length of time necessary to produce any reserves may be such that it will not be economically viable. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration, development and production activities to be unsuccessful. In addition, the cost and timing of drilling, completing and operating wells is often uncertain. We also face the risk that the oil and/or gas reserves may be less than anticipated, that we will not have sufficient funds to successfully drill on the property, that we will not be able to market the oil and/or gas due to a lack of a market and that fluctuations in the prices of oil and/or gas will make development of those wells uneconomical. This could result in a total loss of our investments made in our operations.

 

We conduct offshore exploration, exploitation and production operations off the coast of northwest Peru, all of which are also subject to a variety of operating risks peculiar to the marine environment. Such risks include collisions, groundings and damage or loss from adverse weather conditions or interference from commercial or artesian fishing activities. These conditions can cause substantial damage to facilities, tankers and vessels, as well as interrupt operations. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, exploitation and acquisitions or result in loss of equipment and properties.

 

Disruptions of services provided by marine service providers could temporarily impair our operations and delay delivery of our oil to be sold. We depend on marine service providers to support our offshore operations in the Block Z-1.  These services include, among others, tender support barges for our drilling operations and tank vessels for oil storage and transportation.  Any disruptions or delay of the services provided by our marine service providers because of adverse weather or sea conditions, accidents, mechanical failures, scheduling conflicts with other tankers at the Talara refinery, insufficient personnel or other events could temporarily impair our operations, delay implementation of our business plan and increase our costs.

 

We currently have one customer for our crude oil sales and any disruption to their operations could temporarily impair our operations and delay delivery of our oil to be sold. The Company’s oil is delivered by vessel to the refinery owned by the Peruvian national oil company, Petroleos del Peru - PETROPERU S.A., in Talara, located approximately 70 miles south of the platform.  Produced oil is kept in production inventory until inventory quantities are at a sufficient level to make a delivery to the refinery in Talara.  Although all of the Company’s oil sales are to Petroperu, it believes that the loss of Petroperu as its sole customer would not materially impact the Company’s business because it could readily find other purchasers for the Company’s oil production both in Peru and throughout the world. However this could take time and effort to re-market this crude oil and there can be no guarantee that the Company will be successful at this effort. Should the Company not be successful it would impact the Company’s cash flows related to oil sales.

 

Risks Related to Our Geographic Location and Concentration

 

The geographic concentration of our properties in northwest Peru and southwest Ecuador subjects us to an increased risk of loss of revenue or curtailment of production from factors affecting that region specifically. The geographic concentration of our properties in northwest Peru and southwest Ecuador and adjacent waters means that some or all of our properties could be affected by the same event should that region, for example, experience:

 

 

natural disasters such as earthquakes and/or severe weather (such as the effects of “El Niño,” which can cause excessive rainfall and flooding in Peru and Ecuador); 

 

delays or decreases in production, the availability of equipment, facilities or services; 

 

delays or decreases in the availability of capacity to transport, gather or process production; or 

 

changes in the political or regulatory environment.

 

Because all our properties could experience the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area.

 

Our operations in Peru and Ecuador involve substantial costs and are subject to certain risks because the oil and gas industry in Peru and Ecuador is less developed in comparison to the United States. Because the oil and gas industry in Peru and Ecuador is less developed than in the United States, our drilling and development operations, in many instances, will take longer to complete and may cost more than similar operations in the United States. The availability of technical expertise and specific equipment and supplies may be more limited or costly in Peru and Ecuador than in the United States.  If we are unable to obtain or unable to obtain without undue cost drilling rigs, equipment, supplies or personnel, our exploitation and exploration operations could be delayed or adversely affected, which could have a material adverse effect on our business, financial condition or results of operations.  Furthermore, once oil and natural gas production is recovered, there are fewer ways to transport it to market for sale. Marine transportation for our offshore operations is subject to risks such as adverse weather conditions, collisions, groundings and other risks of damage or delay. Pipeline and trucking operations are subject to uncertainty and lack of availability. Oil and natural gas pipelines and truck transport travel through miles of territory and are subject to the risk of diversion, destruction or delay. We expect that such factors will continue to subject our international operations to economic and operating risks that companies with domestic operations do not experience.

 

 
17

 

 

Along with the general instability that comes from international operations, we face political and geographical risks specific to working in South America. All of our oil and gas properties are located in South America, and specifically in Peru and Ecuador. The success and profitability of our international operations may be adversely affected by risks associated with international activities, including:

 

 

economic, labor, and social conditions; 

 

local and regional political instability; 

 

tax laws (including host-country export, excise and income taxes and U.S. taxes on foreign operations); and 

 

fluctuations in the value of the U.S. dollar versus the local currencies in which oil and gas producing activities may be conducted.

 

Legal uncertainty, operating expenses and fluctuations in exchange rates may make our assumptions about the economic viability of our oil and gas properties incorrect. If these assumptions are incorrect, we may not be able to earn sufficient revenue to cover our costs of operations.

 

Social and political unrest in Peru and Peruvian election results could cause heightened scrutiny over oil and gas regulatory matters. Peru’s next municipal and regional political elections will be held later this year and the next Presidential election will be held in April of 2016. The electoral campaigns could bring heightened attention to various topics, including the regulation of oil and gas companies operating in Peru, and related environmental law compliance.  These elections and the result from the election could result in increased environmental regulation, including additional regulation and oversight of the hydrocarbon and mining sectors, and regulation to combat global climate change and decrease the emission of greenhouse gases.  In addition, the elections could result in increased scrutiny of the royalties on oil and gas production, which could help fund domestic social-regeneration projects. 

 

We are subject to numerous foreign laws and regulations of the oil and natural gas industry that can adversely affect the cost, manner or feasibility of doing business. Our operations are subject to extensive foreign laws and regulations relating to the exploration for oil and natural gas and the development, production and transportation of oil and natural gas, as well as electrical power generation.  Because the oil and gas industry in the countries in which we operate is less developed than elsewhere, changes in laws and interpretations of laws are more likely to occur than in countries with a more developed oil and gas industry.  Future laws or regulations, as well as any adverse change in the interpretation of existing laws or our failure to comply with existing legal requirements may harm our results of operations and financial condition. We may be required to make our share of contributions to large and unanticipated expenditures to comply with governmental regulations, such as:

 

 

work program guarantees and other financial responsibility requirements; 

 

taxation; 

 

royalty requirements; 

 

customer requirements;

 

employee compensation and benefit costs; 

 

operational reporting; 

 

environmental and safety requirements; and 

 

unitization requirements.

 

Under these laws and regulations, we could be liable for our share of:

 

 

personal injuries; 

 

property and natural resource damages;

 

unexpected employee compensation and benefit costs;

 

governmental infringements and sanctions; and 

 

unitization payments.

 

 
18

 

 

If we fail to comply with the terms of certain contracts related to our foreign operations, we could lose our rights under each of those contracts. The terms of each of our Peruvian oil and gas license contracts, require that we perform certain activities, such as seismic acquisition, processing and interpretations and the drilling of required wells in accordance with those contracts and agreements. We are also required to conduct environmental impact studies and environmental impact assessments and establish our ability to comply with environmental regulations.  Our failure to timely perform those activities as required could result in the suspension of our current production and sale of oil, the loss of our rights under a particular contract and/or the loss of the amounts we have posted as a guaranty for the performance of such activities, which would result in a significant loss to us.

 

Compliance with, or breach of, laws relating to the discharge of materials into, and the protection of, the environment can be costly and could limit our operations. As an owner or lessee and operator of oil and gas properties in Peru and Ecuador, we are subject to various national, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, (i) impose liability on the owner or lessee under an oil and gas lease for the cost of property damage, oil spills, discharge of hazardous materials, remediation and clean-up resulting from operations; (ii) subject the owner or lessee to liability for pollution damages and other environmental or natural resource damages; and (iii) require suspension or cessation of operations in affected areas. We have established practices for continued compliance with environmental laws and regulations and we believe the costs incurred by these policies and procedures so far have been necessary business costs in our industry. However, there is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not increase such compliance costs, or have a material adverse effect upon our capital expenditures, earnings or competitive position.

 

We are subject to laws and regulations that can adversely affect the cost, manner and feasibility of our planned operations. The exploration for, and the development, production and sale of oil and gas in South America, and the construction and operation of power generation and gas processing facilities and pipelines in South America are subject to extensive environmental, health and safety laws and regulations. Our ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls. For example, we are required to obtain an environmental permit or approval from the government in Peru prior to conducting seismic operations, drilling a well or constructing a pipeline in Peruvian territory, including the waters offshore of Peru, where we intend to conduct future oil and gas operations. We are also required to comply with numerous environmental regulations in order to transition from exploration into production in any new fields we develop.  Additionally, environmental laws and regulations promulgated in Peru impose substantial restrictions on, among other things, the use of natural resources, interference with the natural environment, the location of facilities, the handling and storage of hazardous materials such as hydrocarbons, the use of radioactive material, the disposal of waste, and the emission of noise and other activities. The laws create additional monitoring and reporting obligations in the event of any spillage or unregulated discharge of hazardous materials such as hydrocarbons. Failure to comply with these laws and regulations also may result in the suspension or termination of our planned drilling operations and subject us to administrative, civil and criminal penalties.

 

Our current permits and authorizations and our ability to obtain future permits and authorizations may, over time, be susceptible to increased scrutiny, resulting in increased costs, or delays in receiving appropriate authorizations. In particular, we may experience delays in obtaining permits and authorizations in Peru necessary for our operations.

 

Compliance with these laws and regulations may increase our costs of operations, as well as further restrict our foreign operations. Moreover, these laws and regulations could change in ways that substantially increase our costs. These laws and regulations have changed in the past and have generally imposed more stringent requirements that increase operating costs or require capital expenditures in order to remain in compliance. It is also possible that unanticipated developments could cause us to make environmental expenditures that are significantly higher than those we currently anticipate, thereby increasing our overall costs. Any failure to comply with these laws and regulations could cause us to suspend or terminate certain operations or subject us to administrative, civil or criminal penalties. Any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and our ability to implement our plan of operation.

 

 
19

 

 

Competition for oil and natural gas properties and prospects is intense; many of our competitors have larger financial, technical and personnel resources that give them an advantage in evaluating and obtaining properties and prospects. We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and natural gas and securing trained personnel and equipment. In addition, changes in Peruvian government regulation have enabled multinational and regional companies to enter the Peruvian energy market. We actively compete with other companies in our industry when acquiring new leases or oil and gas properties. Competition in our business activities has increased and will increase further, as existing and new participants expand their activities as a result of these regulatory changes. Many of our competitors possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than we have. For example, if several companies are interested in an area, Perupetro may choose to call for bids, either through international competitive biddings or through private bidding processes by invitation, and award the contract to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. Our competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical or personnel resources permit. Our competitors may also be able to pay more for productive oil and natural gas properties and exploratory prospects than we are able or willing to pay. On the acquisition opportunities made available to us, we may compete with other companies in our industry for properties operated by third parties through a private bidding process, direct negotiations or some combination thereof. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted. The availability of properties for acquisition depends largely on the business practices of other oil and natural gas companies, commodity prices, general economic conditions and other factors we cannot control or influence.

 

Our management team has limited experience in the power generation business. Our plan of operation includes constructing power generation and pipelines in Peru.  However, the experience of our management team has primarily been in the oil and natural gas exploration and production industry and we have limited experience in the power generation business. We have hired a Director of Gas-to-Power.  However, we continue relying on consultants and outside engineering and technical firms to provide the expertise to plan and execute the power generation aspects of our strategy and we have not yet hired all necessary full-time employees to manage this line of business. No assurance can be given that we will be able to recruit and hire qualified personnel on acceptable terms. Inability to hire such key technical personnel when necessary may adversely affect our gas-to-power project.

 

Construction and operation of power generation and pipelines involve significant risks and delays that cannot always be covered by insurance or contractual protections. The construction of power generation and pipelines involve many risks, including:

 

 

supply interruptions;  

 

work stoppages; 

 

labor disputes; 

 

social unrest; 

 

inability to negotiate acceptable construction, supply or other contracts; 

 

inability to obtain required governmental permits and approvals; 

 

weather interferences; 

 

unforeseen engineering, environmental and geological problems; 

 

unanticipated cost overruns; 

 

possible delays in the acquisition of support equipment necessary for our gas turbines; 

 

possible delays in transporting the necessary equipment to our planned facility in Northern Peru; 

 

possible delays in connection with power plant construction; 

 

possible delays or difficulties in completing financing arrangements for the gas-to-power project; and 

 

possible difficulties or delays with respect to any necessary Peruvian regulatory compliance.

 

The construction and future operation of these facilities involve all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performances below expected levels of output or efficiency. We intend to maintain commercially reasonable levels of insurance, where such insurance is available and cost-effective, obtain warranties from vendors and obligate contractors to meet certain performance levels. However, the coverage or proceeds of any such insurance, warranties or performance guarantees may not be adequate to cover lost revenues or increased expenses. Any of these risks could cause us to operate below expected capacity levels, which in turn could result in lost revenues, increased expenses and higher costs.

 

 The success of our gas-to-power project will depend, in part, on the existence and growth of markets for natural gas and electricity in Peru. Peru has a well-developed and stable market for electricity. Hydroelectric and gas-fired thermal power plants are the primary sources of electric generation, with each source providing approximately 50%. Hydroelectric plants are much less expensive to operate than plants that utilize natural gas, but they are subject to variable output based on rainfall and reservoir levels. Peru has natural gas reserves and production, but does not have a well-developed natural gas infrastructure, particularly in northwest Peru where we operate. Our immediate business plan relies on the continued stability of the power market in Peru. We currently do not expect to complete our power plant earlier than 2016. Further, we cannot guaranty that our efforts to complete the gas-to-power project will be successful. Our assessment of the future power market and demand in Peru and the near-term viability of the project could be inaccurate. We are subject to the following risks that:

 

 

relatively more favorable business conditions for hydroelectric plants, a material reduction in power demand or other competitive issues may adversely affect the demand and prices for the electricity that we expect to produce by the time the power plant is completed; 

 

 
20

 

 

 

our lifting costs could exceed the minimum wholesale power prices available, making the sale of our gas uneconomical; 

 

gas supply and reserves may not develop as anticipated; 

 

potential disruptions or changes to the regulation of the natural gas or power markets in the region could occur by the time our power plant is completed, or we may not receive the necessary environmental or other permits and governmental approvals necessary to operate our power plant or to proceed with the plant in a timely manner; 

 

although we plan to enter into long-term contracts to sell a significant part of our future power production, there can be no assurance that we will be successful in obtaining such contracts or that they will be on favorable terms; and 

 

we will be subject to the general commercial issues related to being in the power business, including the credit-worthiness of, and collections from future customers and the ability to profitably operate our future power plant.

 

We are subject to the Foreign Corrupt Practices Act (the “FCPA”), and our failure to comply with the laws and regulations thereunder could result in penalties which could harm our reputation and have a material adverse effect on our business, results of operations and financial condition.  We are subject to the FCPA, which generally prohibits companies and their intermediaries from making improper payments to foreign officials to secure any improper advantage for the purpose of obtaining or keeping business and/or other benefits. Since all of our oil and gas properties are in Peru and Ecuador, there is a risk of potential FCPA violations.  We have a FCPA policy and a compliance program designed to ensure that we, our employees and agents comply with the FCPA.  There is no assurance that such policy or program will work effectively all of the time or protect us against liability under the FCPA for actions taken by our agents, employees and intermediaries with respect to our business or any businesses that we acquire.  Any violation of these laws could result in monetary penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business. 

 

Other Business Risks

 

We are subject to routine and ongoing tax audits with the United States Internal Revenue Service (“IRS”) and tax authorities for other jurisdictions that could result in additional tax assessment. We have been subject to audits by the IRS and SUNAT, the tax and customs office in Peru. If the IRS or SUNAT disagrees with the positions taken by us on our tax returns, we could have additional tax liability, including interest and penalties. If our positions are not upheld through the appeal process and we ultimately pay such amounts, the payment could have an adverse effect on our financial results and cash flows.

 

Failure to generate taxable income and realize our deferred tax assets in Peru could have a material adverse effect on our financial position and results of operations. The assessment of deferred tax assets and of valuation allowances associated with deferred tax assets require management to make estimates and judgments about the realization of deferred tax assets, which realization will be primarily based on forecasts of future taxable income. Such estimates and judgments are inherently uncertain. We evaluate our deferred tax assets generated in Peru for realization annually or whenever there is an indication that they are not realizable. The ultimate realization of our foreign deferred tax assets is dependent upon the generation of future taxable income in Peru within the time periods required by applicable tax statutes. Should we determine in the future that it is more likely than not that some portion or all of our foreign deferred tax assets will not be realized, we will be required to record a valuation allowance in connection with these deferred tax assets. Such valuation allowance, if taken, would be recorded as a charge to income tax expense and our financial condition and operating results would be adversely affected in the period such determination is made.

 

A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss. Businesses have become increasingly dependent on digital technologies to conduct day-to-day operations. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial of service on websites.

 

The oil and gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, conduct reservoir modeling and reserves estimation, and for compliance reporting. The use of mobile communication devices has also increased rapidly. The complexity of the technologies needed to extract oil and gas in increasingly difficult physical environments, such as deepwater, and global competition for oil and gas resources make certain information more attractive to thieves.

 

 
21

 

 

We depend on digital technology, including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production and financial institutions, are also dependent on digital technology.

 

Our technologies, systems and networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

 

A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:

 

 

unauthorized access to seismic data, reserves information, operational results or other sensitive or proprietary information could have a negative impact on our competitive position in developing our oil and gas resources;

 

data corruption, communication interruption, or other operational disruption during drilling activities could result in a dry hole cost or even drilling incidents; 

 

data corruption or operational disruption of production infrastructure could result in loss of production or accidental discharge; 

 

a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt one of our major projects, effectively delaying the start of cash flows from the project; 

 

a cyber-attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues; 

 

a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues; 

 

a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and 

 

significant business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common stock.

 

Although to date we have not experienced any material losses relating to cyber incidents, there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

 

The loss of senior management or key technical personnel could adversely affect us. We have engaged certain members of management who have substantial expertise in the type of endeavors we presently conduct and the geographical areas in which we conduct them. We do not maintain any life insurance against the loss of any of these individuals. To the extent their services become unavailable, we will be required to retain other qualified personnel. There can be no assurance we will be able to recruit and hire qualified persons on acceptable terms.  Similarly, the oil and gas exploration industry requires the use of personnel with substantial technical expertise. In the event that the services of our current technical personnel become unavailable, we will need to hire qualified personnel to take their place. No assurance can be given that we will be able to recruit and hire such persons on acceptable terms.  Inability to replace lost members of management or key technical personnel may adversely affect us.

 

Insurance does not cover all risks. Exploration for, and the production of, oil and natural gas can be hazardous, involving unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can result in (i) damage to or destruction of wells and/or production facilities, (ii) damage to or destruction of formations, (iii) injury to persons, (iv) loss of life, or (v) damage to property, the environment or natural resources. As a result, we presently maintain insurance coverage in amounts consistent with our business activities and to the extent required by our license contracts. Such insurance coverage includes certain physical damage to our and third parties’ property, hull and machinery, protection and indemnity, employer’s liability, comprehensive third party general liability, workers’ compensation and certain pollution and environmental risks. However, we are not fully insured against all risks in all aspects of our business, such as political risk, civil unrest, war, business interruption, environmental damage and reservoir loss or damage. Further, no such insurance coverage can insure for all operational or environmental risks. The occurrence of an event that is not insured or not fully insured could result in losses to us. For example, uninsured or under insured environmental damages, property damages or damages related to personal injuries could divert capital needed to implement our plan of operation. If any such uninsured losses are significant, we may have to curtail or suspend our drilling or other operations until such time as replacement capital is obtained, if ever, and this could have a material adverse impact on our financial position.

 

 
22

 

 

Risk Factors Related to Our Securities

 

Investor profits, if any, may be limited for the near future. In the past, we have never paid a dividend. We do not anticipate paying any dividends in the near future. Accordingly, investors in our common stock may not derive any profits from their investment in us for the foreseeable future, other than through any price appreciation of our common stock that may occur. Further, any appreciation in the price of our common stock may be limited or nonexistent, or in fact it could decline, as long as we continue to have operating losses. We have not been profitable and have accumulated a deficit of operations totaling $431.6 million through December 31, 2013.  To date we have had limited revenue and no earnings from operations.  There can be no assurances that sufficient revenue to cover total expenses can be achieved until, if at all, we fully implement our operational plan.

 

Additional infusions of capital may have a dilutive effect on existing shareholders. To finance our operations, we may sell additional shares of our common stock.  During the first quarter of 2010, we issued $170.9 million of Convertible Notes that mature in 2015, of which $85.9 million remains outstanding, that, if converted to common stock, could significantly increase the amount of our common shares outstanding by up to approximately 14.5 million shares.  In September of 2013, we issued $143.8 million of Convertible Notes that mature in 2017 that, if converted to common stock, could significantly increase the amount of our common shares outstanding by up to approximately 35.9 million shares.  We currently have $500.0 million available under an effective shelf registration statement for debt securities, common stock, preferred stock, depositary shares and securities warrants, subscription rights, units or any combination thereof, which we may sell from time to time in one or more offerings pursuant to underwritten public offerings, negotiated transactions, at the market transactions, block trades or a combination of these methods. Our certificate of formation does not provide for preemptive rights, although by contract we have granted the International Finance Corporation (“IFC”) the right to purchase shares of our common stock to retain its proportionate ownership pursuant to the Subscription Agreement dated December 16, 2006 by and between IFC and us.  Any additional equity financing that we receive may involve substantial dilution to our then-existing shareholders. Furthermore, we may issue common stock to acquire properties, assets, or businesses. In the event that any such shares are issued, the proportionate ownership and voting power of other shareholders will be reduced. In addition, we are authorized to issue up to 25,000,000 shares of preferred stock, the rights and preferences of which may be designated by our Board of Directors. If we issue shares of preferred stock, such preferred stock may have rights and preferences that are superior to those of our common stock.

 

Our operations may not generate sufficient cash to enable us to service our debt, including our convertible notes. Our future cash flow may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt, including our convertible notes. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

 

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

 

 

refinancing or restructuring our debt;

 

selling assets; 

 

reducing or delaying capital investments; or

 

seeking to raise additional capital.

 

However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under our convertible notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

 

 
23

 

 

The market price of our common stock may be volatile. The market price of our common stock may be highly volatile and subject to wide fluctuations. In addition, the trading volume in our common stock may fluctuate and cause significant price variations to occur. If the market price of our common stock declines significantly, you may be unable to resell your shares at or above the price at which the shares were acquired. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future. Some of the factors that could adversely affect our share price or result in fluctuations in the price or trading volume of our common stock include:

 

 

actual or anticipated fluctuations in our results of operations; 

 

failure to be covered by securities analysts, or failure by us to meet securities analysts’ expectations; 

 

success of our operating strategies; 

 

decline in the stock price of companies that are our peers; 

 

realization of any of the risks described in this section; or 

 

general market and economic conditions.

 

Because we are in the initial stages of developing our oil and natural gas reserves, these market fluctuations may be more significant for us than they would be for a company with a longer operating history. In addition, the stock market has experienced in the past, and may in the future experience extreme price and volume fluctuations. These market fluctuations may materially and adversely affect the trading price of our common stock, regardless of our actual operating performance.

 

Our corporate organizational documents and the provisions of Texas law to which we are subject may delay or prevent a change in control of us that some shareholders may favor. Our certificate of formation and bylaws contain provisions that, either alone or in combination with the provisions of Texas law described below, may have the effect of delaying or making it more difficult for another person to acquire us by means of a hostile tender offer, open market purchases, a proxy contest or otherwise. These provisions include:

 

 

A board of directors classified into three classes of directors with each class having staggered, three-year terms. As a result of this provision, at least two annual meetings of shareholders may be required for the shareholders to change a majority of our board of directors.

 

The board’s authority to issue shares of preferred stock without shareholder approval, which preferred stock could have voting, liquidation, dividend or other rights superior to those of our common stock. To the extent any such provisions are included in any preferred stock, they could have the effect of delaying, deferring or preventing a change in control.

 

Our shareholders cannot act by less than unanimous written consent and must comply with the provisions of our bylaws requiring advance notification of shareholder nominations and proposals. These provisions could have the effect of delaying or impeding a proxy contest for control of us.

 

Provisions of Texas law, which we did not opt out of in our certificate of formation, that restrict business combinations with “affiliated shareholders” and provide that directors serving on staggered boards of directors, such as ours, may be removed only for cause.

 

Any or all of these provisions could discourage tender offers or other business combination transactions that might otherwise result in our shareholders receiving a premium over the then current market price of our common stock.

 

Shares eligible for future sale by our current shareholders may impair our ability to raise capital through the sale of our stock. As of December 31, 2013, we had 117.5 million shares of common stock issued and outstanding. In addition, we currently have outstanding 56.3 million shares of potentially dilutive securities, which mainly consist of approximately 35.9 million shares that are potentially convertible under our Convertible Notes due 2017, approximately 14.5 million shares that are potentially convertible under our Convertible Notes due 2015 and 5.9 million options granted under our 2005 and 2007 Long-Term Incentive Compensation Plan, as amended.  We have an additional 2.0 million shares of common stock allocated under our 2007 Long-Term Incentive Compensation Plan and our 2007 Directors’ Compensation Incentive Plan. We also have an additional 1.9 million shares of common stock allocated under our Employee Stock Purchase Plan. The possibility that substantial amounts of shares of our common stock may be sold in the public market may cause prevailing market prices for our common stock to decrease and thus could impair our ability to raise capital through the sale of our equity securities.

 

Our officers, directors, entities affiliated with them and certain institutional investors may exercise significant control over us. In the aggregate, our management and directors own or control approximately 5.9% of our common stock, and several institutional investors own approximately another 36.9% of our common stock, issued as of December 31, 2013.  These shareholders own in total approximately 42.8%, and, if acting together, would be able to significantly influence all matters requiring approval by our shareholders, including the election of directors and the approval of mergers or other business combination transactions.

 

 ITEM 1B. UNRESOLVED STAFF COMMENTS

 

None.

 

 
24

 

 

ITEM 2. PROPERTIES

 

Offices

 

Our corporate headquarters office is in Houston, Texas, where we lease approximately 13,300 square feet of office space under a lease agreement which expires in February 2016. We also currently lease administrative offices and warehouses in Peru. The administrative office and warehouse leased areas are approximately 11,600 square feet and 101,000 square feet, respectively. The administrative office lease expires in March 2019 and the warehouse lease expires in July 2038. Additionally, we lease an administrative office in Quito, Ecuador of 829 square feet under a month-to-month lease.

 

Properties in Peru

 
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We currently have rights to four properties in northwest Peru. We have working interests in license contracts of 51% in Block Z-1, 100% in Block XIX, 100% in Block XXII and 100% in Block XXIII. The license contracts afford an initial exploration phase of seven years. As described below, each license contract provides for additional exploration periods which can extend the exploration phase of the license contract. If exploration efforts are successful, the license contract’s term can extend up to 30 years for oil production and up to 40 years for gas production. In the event a block contains both oil and gas, as is the case in the Block Z-1 contract, the 40-year term may apply to oil production as well. These four blocks cover a combined area of approximately 2.2 million gross acres.

 

The following table is a summary of our properties in northwest Peru. As of December 31, 2013, only acreage in Block Z-1 has been partially developed.

 

PROPERTY

BASIN

 

BPZ'S OWNERSHIP

 

LICENSE CONTRACT SIGNED

 

UNDEVELOPED ACRES

   

DEVELOPED ACRES

   

PRODUCTIVE WELLS

(1) (2) (3)

 
                 

Gross

   

Net

   

Gross

   

Net

   

Gross

   

Net

 

Block Z-1

Tumbes/Talara

    51 %  

November 2001

    554,200       282,642       800       408       13       6.6  

Block XIX

Tumbes/Talara

    100 %  

December 2003

    473,000       473,000                                  

Block XXII

Lancones/Talara

    100 %  

November 2007

    912,000       912,000                                  

Block XXIII

Tumbes/Talara

    100 %  

November 2007

    230,000       230,000                                  

Total

                2,169,200       1,897,642       800       408       13       6.6  

 


(1)

Does not include the CX11-16X well which tested quantities of gas which we believe to be of commercial amounts and is currently shut-in. Until such time as sufficient funding has been secured and the necessary infrastructure is in place for our gas-to power project, we cannot classify any of these reserves as proved SEC reserves nor refer to the well as productive.

 

(2)

Includes all oil producing wells we have developed. At December 31, 2013, nine gross (4.6 net) wells were producing consistently and four gross (2.0 net) wells were producing intermittently.

 

(3)

Does not include the CX11-22D well which has been converted to a gas and water reinjection well, the A-12F well which has been converted to a gas reinjection well or the A-17D well which is a water reinjection well.

 

Description of Block Z-1 and License Contract

 

Block Z-1, a coastal offshore area encompassing approximately 555,000 gross acres, is situated at the southern end of the Gulf of Guayaquil in northwest Peru. Geologically, the block lies within the Tumbes Basin. From the coastline, water depths increase gradually. The average water depth of the area is approximately 200 feet and approximately 10% of the area has depths ranging from 500 feet up to 1,000 feet. Located within Block Z-1 are five structures which were drilled in the 1970s and 1980s by previous operators, including Tenneco Inc. and Belco Oil and Gas Corporation (“Belco”). These structures are known as the Albacora, Barracuda, Corvina, Delfin and Piedra Redonda fields. With the exception of the Barracuda field, the other four fields have had exploration wells drilled that tested positive for oil or gas in what we believe to be economic quantities while drilling at depths ranging from 6,000 to 12,000 feet. However, at the time the wells were drilled, it was not considered economically viable to produce and sell natural gas from the fields. Consequently, the wells were either suspended or abandoned.

 

In the Corvina field, five wells were drilled, including two wells drilled by Tenneco Inc. in the mid-1970s and three wells drilled by Belco in the late 1970s and early 1980s. Two drilling and production platforms were set up by Belco during this period in the Corvina field. The first platform was located in the East Corvina prospect field and, based on the engineering study, was not suitable for our future development plans and therefore requires us to build a new platform prior to initiating any drilling activities in this section of the Corvina field. The second platform, CX-11, is located in the West Corvina development field and is currently being used in our West Corvina drilling and production activities. All five of the previously drilled wells in the Corvina field encountered indications of natural gas and apparent reservoir-quality formations. In September 2012, our new CX-15 platform was anchored at the West Corvina field location, one mile south of the existing CX-11 platform. We completed the installation of the new CX-15 platform in the West Corvina field, and in July 2013 we spudded the first development well from the platform. Production from the first well began in October 2013. We have subsequently drilled and completed the second well and spudded our third well from this platform.

 

In the Albacora field, the original drilling and production platform, the A platform, was set by Tenneco Inc. in the mid-1970s, after discovering oil and gas with the 8X-2 well. Tenneco Inc. drilled two wells from that platform that were plugged and abandoned. In the late 1970s, Belco drilled three oil wells which produced oil for a very limited time. The Albacora field is located in the northern part of our offshore Block Z-1. The A platform is still in place in the Albacora field and has been repaired, refurbished and placed into service by us. In late 2009, we completed the A-14XD oil well that is still producing, and in 2010 we drilled a second well that was considered dry and was later converted into a water disposal well. After interpreting the new 3-D seismic, we spudded a new development well from the A platform in September 2013 which was completed and put into production in December 2013. We spudded a second development well in January 2014.

 

 
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In the Piedra Redonda field, two wells were drilled by Belco in the late 1970s and early 1980s. Indications of natural gas were present in both wells. One well was completed and tested gas on a long-term test, while the other well encountered abnormally high pressures and was abandoned for mechanical reasons prior to reaching its intended total depth. After conducting engineering feasibility studies, we have determined the existing platform located in the Piedra Redonda field is not suitable for our future development plans and therefore we must consider other options for development in this field. In any case, we do not expect to recomplete the previously drilled and completed well by Belco due to our uncertainty of the mechanical condition and potentially high wellhead pressure of the well.

 

We originally acquired our initial interest in Block Z-1 in a joint venture with Syntroleum Peru Holdings Limited, Sucursal del Peru, under an exploration and production license contract dated November 30, 2001, with an effective date of January 29, 2002. Under the original contract, BPZ owned a 5% non-operating working interest, along with the right of first refusal, in the Block. Syntroleum later transferred its interest to Nuevo Peru ltd., Sucursal del Peru. Subsequent to the merger of Nuevo Energy, Inc. and Plains Exploration and Production Company, Nuevo Energy, Inc. transferred its interest in Block Z-1 to BPZ which then assumed a 100% working interest, as well as the remaining obligations under the contract. Perupetro approved the assumption of Nuevo’s interest by BPZ and the designation of BPZ as a qualified operator under the contract in November 2004. This action was subject to official ratification and issuance of a Supreme Decree by the government of Peru, which was issued in February 2005. Accordingly, an amended contract was signed with Perupetro naming BPZ as the owner of 100% of the participation under the License Contract.

 

In December 2012, we completed the sale of a 49% participating interest in the Block Z-1 License Contract to Pacific Rubiales. We now own 51% participating interest in Block Z-1.

 

The License Contract provides for an initial exploration phase of seven years, and a three year extension of this phase at the discretion of Perupetro upon application by the Operator. Each period has a commitment for exploration activities and requires a financial guarantee to secure the performance of the work commitment during such period. Block Z-1 is currently in the exploitation phase.

 

The Block Z-1 License Contract permits us to keep the current contract area under exploration for a total of six additional years divided in three two-year periods with each committing us to additional exploration activities. The additional exploration commitment requires us to drill one exploratory well, or perform ten exploratory work units per each 10,000 hectares (approximately 25,000 acres), every two years for up to a maximum period of six years, in order to keep the remaining area under contract. We received approval from Perupetro for the initial two-year period and have committed to drill an exploratory well. The end date for the initial two-year period will be determined from the agreed approval date of the environmental permit with Perupetro.

 

A performance bond of $1.1 million was posted for cash collateral of $1.1 million related to the exploitation period. The performance bond will be released at the end of the exploitation period if the work commitment for that period has been satisfied. In addition, we are required to make technology transfer payments related to training costs of Perupetro professional staff during the exploration phase of $50,000 per year.

 

On November 21, 2007, we submitted a letter to Perupetro declaring a commercial discovery in the Block Z-1 field. On May 19, 2008 we filed the field development plan with Perupetro.  In November 2010, after obtaining an extension of our original proposed First Date of Commercial Production, we placed the Block Z-1 into commercial production.

  

Royalties under the contract vary from 5% to 20% based on production volumes on the entire Block. Royalties start at 5% if and when production is less than 5,000 Boepd and are capped at 20% if and when production surpasses 100,000 Boepd.

 

If we decide not to continue with an additional exploration work program beyond the initial exploration work program, we will only be allowed to keep each field discovered and the surrounding five kilometer area for the remainder of the contract life. Currently, we plan to continue our exploration activities to retain the additional area in Block Z-1.

 

 
27

 

 

Description of Block XIX and License Contract

 

Block XIX covers approximately 473,000 gross acres, lying entirely onshore and adjacent to Block Z-1 in northwest Peru. Geologically, the Block lies primarily within the Tumbes Basin of Oligocene-Neogene age, but also covers part of the Talara Basin to the south. Several older wells showed evidence of gas potential in the Mancora formation as well as oil shows from the Heath Formation. The sections of the Tumbes and Talara Basins in Block XIX are primarily exploratory areas and have had limited drilling and seismic activity. However, based on our assessment of available data, we expect the Mancora formation to continue from offshore in Block Z-1 in Piedra Redonda through Block XXIII, also under license to us, and into Block XIX, an area which spans approximately fifty miles.

 

In December 2003, we signed a license contract whereby we acquired a 100% interest in Block XIX. The term for the exploration period in Block XIX is seven years and can be extended under certain circumstances for an additional period of up to four years. If a commercial discovery is made during the exploration period, the contract will allow for the production of oil for a period of 30 years from the effective date of the contract and the production of gas for a period of 40 years. In the event a block contains both oil and gas, the 40-year term may apply to oil production as well. Royalties under the contract vary from 5% to 20% based on production volumes in the entire Block. Royalties start at 5% if and when production is less than 5,000 Boepd and are capped at 20% if and when production surpasses 100,000 Boepd.

 

The seven-year exploration phase in the Block XIX License Contract is divided into five periods of 18 months, 24 months, 15 months, 15 months and 12 months, respectively. We are in the fourth exploration period. After satisfying our commitments under the third exploration period by drilling the PLG-1X well in 2011, the fourth exploration period is under suspension while the approval of an environmental impact study by the DGAAE is obtained to conduct a limited 3-D seismic survey. We have received approval from Perupetro to conduct a limited 3-D seismic survey as part of our minimum work commitment for the fourth exploration period to further evaluate future drilling locations. An environmental assessment is currently in process to obtain an environmental permit for the additional seismic work. Once approval is obtained, we will reestablish timelines for the remaining exploration periods.

 

As of December 31, 2013, we had a $585,000 bond posted for $292,500 in cash collateral as required under the License Contract. The fifth exploration period will require a performance bond of $585,000. The performance bond amounts are not cumulative, and will be released at the end of each exploration period if the work commitment for that period has been satisfied. In addition, we are required to make technology transfer payments related to training costs of Perupetro professional staff during the exploration phase in the amount of $5,000 per year. We must declare a commercial discovery no later than the end of the last exploration period, including any extensions or deferments in order to retain the block.

 

Under the terms of the Block XIX License Contract, we are required to relinquish 20% of the least promising licensed acreage by the end of the fourth exploration period.  Accordingly, we intend to retain the most promising acreage identified.  At the end of the exploration phase, we may keep the remainder of the contract area, provided we commit to pursue and implement an additional work program every two years, for up to a maximum of four years. The additional exploration commitment requires us to drill one exploratory well, or conduct certain exploratory working equivalent units, every two years, for up to a maximum period of four years, in order to keep the remaining contract area. If we decide not to continue this minimum work program, we will only be allowed to keep the area over the fields discovered, plus a technical security zone around those areas.

 

Description of Block XXII and License Contract

 

On November 21, 2007, we signed a license contract whereby we acquired a 100% interest in Block XXII. Block XXII is located onshore in northwest Peru within the Lancones Basin of Cretaceous—Upper Eocene Age and covers an area of approximately 912,000 gross acres. The Lancones Basin, which includes the Muerto play, is primarily an exploratory area and has had limited drilling and seismic activity. The southern sector of this Block also covers the productive Talara basin of northwest Peru, near the Talara Refinery. The exploration period of the License Contract extends over a seven-year period divided into five periods of four periods of 18 months and a final period of 12 months. Under certain circumstances, the exploration periods may be extended for an additional period of up to three years. We are in the second exploration period and are currently awaiting the approval of an environmental impact study by the DGAAE in order to drill an exploratory well. We plan to conduct an additional 2-D seismic program as confirmation of potential drilling locations, and plan to drill exploratory wells after receipt of the necessary environmental permits. The timing of the actual drilling will depend on approval of the environmental permit, which is in process, and subsequent receipt of the necessary ancillary permits. Once approval is obtained, we will reestablish timelines for the remaining exploration periods. Drilling of the well in Block XXII is expected in late 2014 or 2015. In each subsequent period after the first 18 month period, we are required to drill an exploratory well or perform other equivalent work commitments. If a commercial discovery is made during the exploration period, the contract will allow for the production of oil for a period of 30 years from the effective date of the contract and the production of gas for a period of 40 years. In the event a block contains both oil and gas, the 40-year term may apply to oil production as well. Royalties under the contract vary from 15% to 30% based on production volumes in the entire Block. Royalties start at 15% if production is less than 5,000 Boepd and are capped at 30% if production surpasses 100,000 Boepd.

 

 
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In connection with the second exploration period, we were required to obtain a $650,000 performance bond that is secured by cash collateral in the amount of $350,000. Performance bond amounts are not cumulative, and will be released at the end of each exploration period if the work commitment for that period has been satisfied.

 

Under the Block XXII License Contract, we are required to relinquish at least 20% of the least prospective licensed acreage at the end of the third period and at least another 30% of the least prospective licensed acreage at the end of the fourth period such that at the end of the fourth period, we will have released 50% of the original agreement area. Accordingly, we intend to retain the most prospective acreage identified.  The contract does not call for any additional relinquishment of acreage within the contract area and we may retain the remaining un-relinquished area for the remainder of the contract life provided we continue executing a minimum work program as defined under the License Contract.  If we decide not to continue this minimum work program, we will only be allowed to keep the fields discovered and the surrounding five kilometer areas for the remainder of the contract life.

 

Description of Block XXIII and License Contract

 

On November 21, 2007, we signed a license contract whereby we acquired a 100% interest in Block XXIII, which consists of approximately 230,000 gross acres and is located onshore in northwest Peru between Blocks Z-1 and XIX. This Block is located in the Tumbes Basin, although in its southern section, the Talara Basin, sediments may be found deeper. The sections of the Tumbes and Talara Basins in Block XXIII are primarily exploratory areas and have had limited drilling and seismic activity. The exploration period of the License Contract extends over a seven-year period divided into two periods of 18 months and two periods of 24 months. We are in the second exploration period which expires in July 2014. We are required to complete 678 exploration work units which will determine the number of wells drilled in the second exploration period. Drilling on Block XXIII began in January 2014. If a commercial discovery is made during the exploration period, the contract will allow for the production of oil for a period of 30 years from the effective date of the contract and the production of gas for a period of 40 years. In the event the block contains both oil and gas, the 40-year term may apply to oil production as well. Royalties under the contract vary from 15% to 30% based on production volumes in the entire Block. Royalties start at 15% if production is less than 5,000 Boepd and are capped at 30% if production surpasses 100,000 Boepd.

 

In connection with the second exploration period, we were required to obtain a performance bond of $3.4 million that is secured by cash collateral in the amount of $1.7 million. Performance bond amounts are not cumulative, and will be released at the end of each exploration period if the work commitment for that period has been satisfied.

 

Under the Block XXIII License Contract, we are required to relinquish 20% of the least prospective licensed acreage at the end of the third period and at least another 30% of the least prospective licensed acreage at the end of the fourth period such that at the end of the fourth period, we will have released 50% of the original agreement area. Accordingly, we intend to retain the most prospective acreage identified.  The contract does not call for any additional relinquishment of acreage within the contract area and we may retain the remaining un-relinquished area for the remainder of the contract life provided we continue executing an exploration work program as defined under the License Contract.  If we decide not to continue this exploration work program, we will only be allowed to keep the fields discovered and the surrounding five kilometer areas for the remainder of the contract life.

 

Proved Reserves

 

Our estimated proved oil reserve quantities were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. NSAI was chosen based on its knowledge and experience of the region in which we operate. Numerous interpretations and assumptions are made in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Our actual reserves, future rates of production and timing of development expenditures may vary substantially from these estimates. See Item 1A Risk Factors, “Our reserve estimates depend on many assumptions that may turn out to be inaccurate,” and “As of December 31, 2013, we had eight proved undeveloped reserve locations in the Corvina filed or 5.0 MMBbls included in our proved oil reserves that are scheduled to be drilled after five years from initial disclosure” for further information. All of our proved reserves are in the Corvina and Albacora fields. Our net quantities of proved developed and undeveloped reserves of crude oil and standardized measure of future net cash flows are reflected in the table below. For further information about the basis of presentation of these amounts, see the “Supplemental Oil and Gas Disclosures (Unaudited)” under Item 8, “Financial Statements and Supplementary Data” contained herein.

 

As of December 31, 2013, we owned a 51% working interest in the Corvina and Albacora fields that require Peruvian government royalties of 5% to 20% of revenue depending on the level of production. The effect of these royalty interest payments is reflected in the calculation of our net proved reserves. Our estimate of proved reserves has been prepared under the assumption that our license contract will allow production for the possible 40-year term for both oil and gas, as more fully discussed under “Description of Block Z-1” above.

 

 
29

 

 

Net Proved Crude Oil Reserves and Future Net Cash Flows

As of December 31, 2013

Based on Average First Day-of-the-Month Fiscal-Year Prices

 

 

   

Actual

   

Estimated

Future Capital Expenditures

 
   

(In MBbls)

   

(In thousands)

 

Proved Developed Producing

    3,209     $ 4,027  

Proved Developed Not Producing

    -       -  

Proved Undeveloped

    12,915       99,276  

Total

    16,124     $ 103,303  
                 

Standardized Measure of Discounted Future Net Cash Flows, Discounted @ 10% (in thousands)

  $ 678,050          

 

These estimates are based upon a reserve report prepared by NSAI, independent petroleum engineers. NSAI used internally developed reserve estimates and criteria in compliance with the SEC guidelines based on data provided by us.  See Item 7.  “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Proved Reserves,”  “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Standardized Measure of Discounted Future Net Cash Flows” and “Supplemental Oil and Gas Disclosure,” in Item 8. “Financial Statements and Supplementary Data.” NSAI’s report is attached as Exhibit 99.1 to this Form 10-K.

 

The reserve volumes and values were determined under the method prescribed by the SEC, which requires the use of an average oil price, calculated as the twelve-month first day of the month historical average price for the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.  

 

Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process

 

Our policies regarding internal controls over the recording of reserves estimates requires reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles.

 

Our Vice President of Exploration and Production is responsible for compliance in reserves bookings and utilizes the reserves estimates made by our third party reserve consultant, NSAI, for the preparation of our reserve report. Our Vice President of Exploration and Production is a geologist with over 34 years of supervisory and operating experience in the domestic and international oil and gas industry.  Prior to joining BPZ Energy, he was employed by Occidental Petroleum Corporation for over 28 years in both Houston and Peru, where he held several positions including New Ventures Manager for Latin America and Exploration Manager for Peru. He holds a Bachelor of Science in Geological Sciences Degree from the University of Texas and is a Licensed Professional Geologist.

 

In addition, the Board of Directors has established a Technical Committee to provide review and oversight of our determination and certification of oil and gas reserves.  In providing review and oversight, the Committee may review the propriety of our methodology and procedures for determining the oil and gas reserves as well as the reserves estimates resulting from such methodology and procedures.  The Technical Committee may also review the qualifications, independence and performance of our independent reserve engineers. 

 

 
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The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Dan Paul Smith and Mr. Mike K. Norton. Mr. Smith has been practicing consulting petroleum engineering at NSAI since 1980. Mr. Smith is a Licensed Professional Engineer in the State of Texas (No. 49093) and has over 40 years of practical experience in petroleum engineering, with over 30 years experience in the estimation and evaluation of reserves. He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Norton has been practicing consulting petroleum geology at NSAI since 1989. Mr. Norton is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 441) and has over 34 years of practical experience in petroleum geosciences, with over 24 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

 

Reserve Technologies

 

The SEC allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. We used a combination of production and pressure performance, wireline wellbore measurements, analytical and simulation studies, offset analogies, seismic data and interpretation, geological data, interpretation, and modeling, wireline formation tests, geophysical logs and core data, and laboratory fluid studies to calculate our reserves estimates.

 

Development of Proved Reserves

 

As of December 31, 2013, we had net proved oil reserves of 16.1 MMBbls which represents a decrease from the net proved oil reserves at December 31, 2012 of 16.4 MMBbls.  In December 2012, we completed the sale of a 49% participating interest in the Block Z-1 License Contract. This resulted in sales of reserves in place of 16.4 MMbls of proved reserves. We now own a 51% participating interest in Block Z-1. The net proved oil reserves associated with proved developed producing wells increased by 1.5 MMBbls to 3.2 MMBbls in 2013 from 1.7 MMBbls in 2012. Reductions to proved developed non–producing reserves were 0.4 MMBbls, bringing the total of proved developed non–producing reserves at December 31, 2013 to none compared to 0.4 MMBbls in 2012. The net oil reserves associated with proved undeveloped areas decreased by 1.4 MMBbls to 12.9 MMBbls at December 31, 2013 from 14.3 MMBbls in 2012.

 

         Proved Undeveloped Reserves (“PUD” or “PUDs”)   

 

As of December 31, 2013, 12.9 MMBbls of PUDs were reported, a decrease of 1.4 MMBbls from December 2012. The following table shows changes in the PUDS for 2013:

 

 

   

MBbls

 
         

PUDS at January 1, 2013

    14,301  

Revisions of previous estimates

    (973 )

Purchases of minerals in place

    -  

Extensions, discoveries and other additions

    344  

Sales of reserves in place

    -  

Conversion to proved developed reserves

    (757 )
         

PUDS at December 31, 2013

    12,915  

 

In 2013, we had negative revisions to PUDs of 1.1 MMBbls of previous estimates due to performance revisions for the Corvina field.

 

 
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In 2013, we converted 0.8 MMBbls, or 5.6% of total year-end 2012 PUDs to developed status. As of December 31, 2013, we had a total quantity of 21 PUD locations contributing 12.9 MMBbls to our 2013 proved oil reserves.  Of the total 21 PUDs, 17 PUDs are associated with the Corvina field and 4 PUD locations are associated with the Albacora field. Costs incurred to advance the development of PUDs associated with Block Z-1 in 2013 were approximately $70.6 million, which was reimbursed by our partner in Block Z-1, Pacific Rubiales.  Costs incurred to advance the development of PUDs associated with Block Z-1 in 2012 were approximately $60.2 million, of which $56.8 million was reimbursed by our partner in Block Z-1, Pacific Rubiales.  Costs incurred to advance the development of PUDs associated with Block Z-1 in 2011 were approximately $26.6 million. As of December 31, 2013, we had 8 PUD locations in the Corvina field or 5.0 MMBbls included in our proved oil reserves that are scheduled to be drilled after five years of initial disclosure. Other than the PUD amounts in such 8 locations, as of December 31, 2013, we did not have any PUDs previously disclosed that have remained undeveloped for five years or more since initial disclosure. All 8 PUD locations scheduled to be drilled after five years are the result of unexpected governmental permitting delays, facilities limitations on the CX-11 offshore platform and contractual and construction issues related to the CX-15 offshore platform in Block Z-1 located in environmentally sensitive, remote locations. The 8 PUDs are located in areas where we continue to actively drill.  

 

In December 2012, the Company completed the sale of a 49% participating interest in the Block Z-1 License Contract. The Company now owns a 51% participating interest in Block Z-1.

 

Production, Average Sales Price and Production Costs.

 

The following table presents our oil sales volumes, average realized sales prices per Bbl and average production costs per Bbl for the indicated periods.

 

 

   

Sales (1)

Volumes (MBbls)

   

Average Sales

Price

   

Average 

Production 

Cost (2)

 
                         

2013

    506.9     $ 99.79     $ 49.11  

2012

    1,187.8     $ 103.31     $ 44.16  

2011

    1,379.6     $ 101.01     $ 36.82  

 

 

 

(1)

We inventory our oil that has not been sold. Therefore, per unit costs, after allocating operating costs to inventory, are based on sales volume.

 
       

 

(2)

Production costs include the oil production, transportation and workover costs as well as field maintenance and repair costs.

 

 

Acreage; Productive Wells

 

The following table shows the approximate number of developed and undeveloped acres as of December 31, 2013:

 

 

   

Acres

 
   

Gross

   

Net

 

Developed

    800       408  

Undeveloped

    2,169,200       1,897,642  

Total acreage

    2,170,000       1,898,050  

 

The number of gross and net productive development wells at December 31, 2013, 2012 and 2011 were 13.0 gross (6.6 net), 11.0 (5.6 net) and 11.0 (gross and net), respectively.

 

 
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Drilling Activity

 

The number of gross and net productive oil wells drilled in 2013, 2012 and 2011 were 2.0 gross (1.0 net), none, and 2.0 (gross and net), respectively. We did not drill any exploratory wells or have any dry holes in 2013 or 2012. We drilled one exploratory well (gross and net) in 2011, the PLG-1X in Block XIX, which we deemed to be a dry hole in the fourth quarter 2011. The following lists our successful development wells that were drilled during the year ended December 31, 2013:

 

Field and Well

 

Exploratory/Development

 

Drilling Depth

(feet)

 

Date Objective

Drilled/Tested/Completed

Corvina - CX15-1D

 

Development

    7,900  

4th quarter

Albacora - A-18D

 

Development

    12,600  

4th quarter

 

Successful exploratory and development wells refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated. For the purpose of this table, the term “completed” refers to the installation of equipment for the production of oil or natural gas.

 

The following table shows the number of wells in the process of drilling or in active completion stages and the number of wells suspended or waiting on completion at December 31, 2013:

 

   

Wells in process of drilling or in active completion

   

Wells suspended or waiting on completion

 
   

Exploration

   

Development (1)

   

Exploration (2)

   

Development

 

Gross

    -       1.0       1.0       -  

Net

    -       0.5       0.5       -  

 

Wells suspended or waiting on completion include exploration and development wells where drilling has occurred, but the wells are awaiting resumption of drilling or other completion activities.

 

(1) Represents the CX15-2D well.

 

(2) Represents the CX11-16X well.

 

 

2014 Activities 

 

Block Z-1

 

Corvina Field

 

We spudded the second development well from the CX-15 platform, the CX15-2D well, in November 2013, and it was completed in January 2014. We drilled the CX15-2D well near the existing CX11-18XD well to a measured depth of approximately 9,000 feet. Production from the CX15-2D well began in February 2014. We spudded the third development well from the CX-15 platform, the CX15-3D well, in February 2014.

 

Albacora Field

 

We spudded a development well, the A-19D, from the A platform in the Albacora field of Block Z-1 on January 1, 2014. The target depth of the A-19D well is approximately 12,400 feet. The A-19D well began production on March 1, 2014.

 

Block Z-1 Seismic

 

The joint technical team continues to interpret the Block Z-1 3-D seismic data.  

 

 
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Block XIX

 

We have received approval from Perupetro to conduct a limited 3-D seismic survey as part of our minimum work commitment for the fourth exploration period to further evaluate future drilling locations. The environmental assessment process is underway to obtain an environmental permit for the additional seismic work.

 

Block XXII

 

The timing of the additional seismic work and actual drilling on Block XXII will depend on approval of the environment assessment, which is underway, and subsequent receipt of the necessary ancillary permits. Drilling on Block XXII is expected in late 2014 or 2015.

 

Block XXIII

 

We spudded an exploration well, the Caracol 1X, on January 5, 2014. This is the first of three exploratory wells we plan to drill in Block XXIII in 2014. The target depth of the Caracol 1X well is approximately 3,500 feet. Logs have been run after reaching total depth to determine testing intervals, and casing has now been set to test the selected intervals. A number of intervals have been selected for testing and the testing is ongoing.

 

Marine

 

In December 2013, we entered into a Management Services Agreement with a third party marine operator to manage our marine fleet. We transferred our BPZ Marine S.R.L. employees to the new operator.

 

Property in Ecuador

 

Through our wholly-owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, we also own a 10% non-operating net profits interest in an oil and gas producing property, Block 2, located in the southwest region of the Santa Elena Property. The Santa Elena Property (operated by Pacifpetrol) is located west of the city of Guayaquil along the coast of Ecuador. Almost 3,000 wells have been drilled in the field since production began in the 1920s. There are approximately 1,300 active wells which produce approximately 1,300 barrels of oil per day. The majority of the wells produce intermittently by gas lift, mechanical pump or swabbing techniques. Crude oil is gathered in holding tanks and pumped via pipeline to an oil refinery in the city of Libertad, Ecuador. In May 2013, the license agreement and operating agreement covering the property were extended from May 2016 to December 2029.

 

In 2013, the Consortium, which includes us and three other partners, in order to extend the term of the contract from 2016 to 2029, agreed to additional work commitments to increase production in the Santa Elena field. Our total share of this commitment over the remaining life of the contract is $5.2 million (our 10% non-operating net profits interest) which amount is due throughout the period of 2014 through 2028. This commitment should be funded by cash on hand and cash generated from new production of the partnership. If the partnership does not have sufficient cash on hand, we may elect to make a cash contribution to the partnership for our 10% share of the commitment. If we elect not to make our 10% share contribution of the commitment, we would lose our rights in the Consortium and the Contract at the Santa Elena field.

 

ITEM 3. LEGAL PROCEEDINGS

 

From time to time, the Company may become a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, the Company is not currently a party to any proceeding that it believes could have a potentially material adverse effect on its financial condition, results of operations or cash flows.

 

ITEM 4. MINE SAFETY DISCLOSURES

 

 Not applicable.

 

 
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PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

Market Information

 

Our common stock, no par value, is listed on the New York Stock Exchange (“NYSE”) and on the Bolsa de Valores Exchange in Lima, Peru (BVL) under the symbol “BPZ.”

 

The following table sets forth, for the periods indicated, the high and low prices of a share of our common stock as reported on the NYSE.

  

   

High

   

Low

 
                 

2013

               

Fourth quarter

  $ 2.28     $ 1.58  

Third quarter

    2.55       1.75  

Second quarter

    2.52       1.67  

First quarter

    3.33       2.19  
                 

2012

               

Fourth quarter

  $ 3.20     $ 2.22  

Third quarter

    3.40       2.01  

Second quarter

    4.64       2.09  

First quarter

    4.34       2.69  

 

 

Holders

 

As of February 28, 2014, we had approximately 136 shareholders of record, and an estimated 12,683 beneficial owners of our common stock.

 

Dividends

 

We have never paid cash or other dividends on our stock.

 

For the foreseeable future, we intend to retain earnings, if any, to meet our working capital requirements and to finance future operations. Accordingly, we do not plan to declare or distribute cash dividends to the holders of our common stock in the foreseeable future.

 

Purchases of Equity Securities By the Issuer and Affiliated Purchasers

 

As of the date of this filing, we have not repurchased any of our equity securities and have not adopted a stock repurchase program.

 

Securities Authorized for Issuance Under Equity Compensation Plans

 

For information regarding securities authorized for issuance under equity compensation plans, see Note-12 — “Stockholders’ Equity” of the Notes to Consolidated Financial Statements in Item 8 herein.

 

 
35

 

 

Performance Graph

 

The following graph compares the cumulative total shareholder return for our Common Stock to that of (i) the Russell 2000 Stock Index and (ii) a customized peer group. The companies included in the customized Peer Group Composite, adjusted for the effects of industry consolidation, are Endeavor International Corp., Abraxas Petroleum Corp., Harvest Natural Resources, Inc., Callon Petroleum Co., PetroQuest Energy, Inc., Apco Oil and Gas International Inc., Vaalco Energy, Inc., Contango Oil & Gas Co., and Gran Tierra Energy Inc. “Cumulative total return” is defined as the change in share price during the measurement period, plus cumulative dividends for the measurement period (assuming dividend reinvestment), divided by the share price at the beginning of the measurement period. The graph assumes $100 was invested on January 1, 2008 in our Common Stock, the Russell 2000 Stock Index and the Peer Group Composite.

 

 

 

 

2008

2009

2010

2011

2012

2013

BPZ Resources, Inc.

  $ 100     $ 148     $ 74     $ 44     $ 49     $ 28  

Russell 2000 Stock Index

    100       125       157       148       170       233  

Peer Group Composite

    100       92       157       163       87       91  

 

 
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ITEM 6. SELECTED FINANCIAL DATA  

 

The following selected financial information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and the consolidated financial statements and the notes thereto included under Item 8. – “Financial Statements and Supplementary Data.”

 

 

   

For the Year Ended December 31,

 
                               

Operating Results:

 

2013

   

2012

   

2011

   

2010

   

2009

 
   

(In thousands, except per share and per barrel information)

 

Total net revenue

  $ 50,729     $ 122,958     $ 143,740     $ 110,464     $ 52,454  
                                         

Operating and administrative expenses:

                                       

Lease operating expense

    24,893       52,458       50,792       32,585       28,113  

General and administrative expense

    24,111       28,705       34,998       32,444       33,051  

Geological, geophysical and engineering expense

    2,184       43,787       12,917       19,318       7,975  

Dry hole costs

    -       -       13,082       32,778       -  

Depreciation, depletion and amortization expense

    27,214       45,873       38,944       33,755       25,803  

Standby costs

    4,311       5,340       4,529       7,487       -  

Other operating expense

    4,430       2,266       -       12,889       -  

Gain on divestiture

    -       (26,864 )     -       -       -  
                                         

Total operating and administrative expenses

    87,143       151,565       155,262       171,256       94,942  
                                         

Operating loss

    (36,414 )     (28,607 )     (11,522 )     (60,792 )     (42,488 )
                                         

Other income (expense):

                                       

Income from investment in Ecuador property, net

    152       62       412       740       1,208  

Interest expense

    (16,158 )     (16,115 )     (19,772 )     (11,618 )     -  

Loss on extinguishment of debt

    (7,222 )     (7,318 )     -       -       -  

Gain (loss) on derivatives

    242       (2,610 )     (2,046 )     -       -  

Interest income

    182       44       453       272       215  

Other income (expense)

    (4,268 )     (159 )     1,083       19       (1,312 )
                                         

Total other income (expense)

    (27,072 )     (26,096 )     (19,870 )     (10,587 )     111  

Loss before income taxes

    (63,486 )     (54,703 )     (31,392 )     (71,379 )     (42,377 )
                                         

Income tax expense (benefit)

    (5,775 )     (15,614 )     2,435       (11,608 )     (6,575 )

Net loss

  $ (57,711 )   $ (39,089 )   $ (33,827 )   $ (59,771 )   $ (35,802 )

Basic and diluted net loss per share

  $ (0.50 )   $ (0.34 )   $ (0.29 )   $ (0.52 )   $ (0.35 )

Basic and diluted weighted average common shares outstanding

    115,943       115,631       115,367       114,919       103,362  

Oil sales price per barrel, net

  $ 99.79     $ 103.31     $ 101.01     $ 72.53     $ 54.49  

Operating cost per barrel

  $ 49.11     $ 44.16     $ 36.82     $ 21.47     $ 29.21  
                                         

Balance Sheet Data:

                                       

Working Capital/(Deficit)

  $ 71,670     $ 58,839     $ 49,180     $ 22,703     $ 7,385  

Property, equipment and construction in progress, net

    217,753       238,557       381,602       342,507       262,517  

Total assets

    406,749       527,430       537,333       470,307       349,172  

Total long-term debt

    206,939       197,160       248,384       156,750       22,581  

Stockholders' equity

    137,475       186,300       222,452       251,326       271,957  
                                         

Cash Flow Data:

                                       

Cash flow provided by (used in) operating activites

    (52,627 )     (46,062 )     47,121       (5,125 )     (30,785 )

Cash flow provided by (used in) investing activities

    53,968       (65,838 )     (93,883 )     (158,104 )     (90,005 )

Cash flow provided by (used in) financing activities

    (27,486 )     137,268       93,182       156,834       133,620  

 

 
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and related notes contained elsewhere in this report. The following discussion includes forward-looking statements that reflect our plans, estimations and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this report.

 

Overview

 

We are an independent oil and gas company focused on the exploration, development and production of oil and natural gas in Peru and Ecuador. We also intend to utilize part of our planned future natural gas production as a supply source for the development of a gas-fired power generation facility in Peru, which we currently plan to wholly or partially - own. We have the license agreements for oil and gas exploration and production covering approximately 2.2 million gross (1.9 million net) acres in four blocks in northwest Peru and off the northwest coast of Peru in the Gulf of Guayaquil. We also own a 10% non-operating net profits interest in an oil and gas producing property, Block 2, located in the southwest region of the Santa Elena Property.

 

Our current activities and related planning are focused on the following objectives:

 

 

Continuing the offshore development drilling campaign from the new Corvina CX-15 platform and Albacora platform;

 

 

Optimizing oil production in the Corvina field in Block Z-1 with our joint venture partner Pacific Rubiales;

 

 

Processing and analyzing the data from the 3-D seismic survey in Block Z-1 to guide further exploration and development activities within the Block;

 

 

Working with Block Z-1 partner, Pacific Rubiales, to continue to develop the Corvina field and the Albacora field;

 

 

Explore the remainder of Block Z-1, starting with the Delfin prospect where we have received the permit to install a platform and begin drilling;

 

 

Continuing acquisition, processing and interpretation of seismic data to better understand the characteristics and potential of our onshore properties;

 

 

Executing an exploratory drilling campaign in Block XXIII;

 

 

Planning and permitting an on-shore drilling campaign to explore and appraise Block XXII and meet our applicable license requirements;

 

 

Identifying potential partners for our other operations; and

 

 

Continuing business development efforts for our gas-to-power project to monetize our natural gas resources, which we have identified in the Corvina field but for which no market has yet been secured and related financing has yet to be obtained.

 

Our activities in Peru include analysis and evaluation of technical data on our properties, preparation of the development plans for the properties, meeting requirements under the license contracts, procuring equipment for an extended drilling campaign, obtaining all necessary environmental, technical and operating permits, optimizing current production and obtaining preliminary engineering and design of the power plant and gas processing facilities.

 

 
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Oil Development

 

General

 

We plan to conduct additional drilling activities based in part on an ongoing assessment of economic efficiencies, license contract requirements, likely success and logistical issues such as scheduling, required maintenance and replacement of equipment and consultation with our joint venture partner with respect to Block Z-1.  This assessment could result in increased emphasis and activities on a given prospect and conversely, could result in decreased emphasis on a given prospect for a period of time.  In particular, we will assess allocation of our current resources among the Corvina, Albacora, and other Block Z-1 prospects and certain onshore prospects as they develop, along with our gas-to-power project.

 

Block Z-1

 

The Block Z-1 License Contract provides for an initial exploration phase of seven years, and exploration can continue in the exploitation phase for an additional six years. Each period has a commitment for exploration activities and requires a financial guarantee to secure the performance of the work commitment during such period. We are in the exploitation period in Block Z-1.

 

Divestiture

 

On April 27, 2012, we and Pacific Rubiales (together with its subsidiaries) executed a Stock Purchase Agreement under which we formed an unincorporated joint venture with Pacific Rubiales to explore and develop the offshore Block Z-1 located in Peru. Pursuant to the SPA, Pacific Rubiales agreed to pay $150.0 million for a 49% participating interest, including reserves, in Block Z-1 and agreed to fund $185.0 million of our share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012. In order to finalize the joint venture, Peruvian governmental approvals were needed to allow Pacific Rubiales to become a party to the Block Z-1 License Contract. Until the required approvals were obtained, Pacific Rubiales provided a $65.0 million down payment on the purchase price and other funds which we initially accounted for as loans to continue to fund our Block Z-1 capital and exploratory activities. These amounts were reflected as long-term debt prior to closing the transaction.

 

On December 14, 2012, Perupetro approved the terms of the amendment to the Block Z-1 License Contract to recognize the sale of a 49% participating interest in offshore Block Z-1 to Pacific Rubiales. We and Pacific Rubiales waived and modified certain contract conditions in order to close the transaction. On December 30, 2012, the Peruvian Government signed the Supreme Decree for the execution of the amendment to the Block Z-1 License Contract.

 

The development of Block Z-1 is subject to the terms and conditions of a Joint Operating Agreement with Pacific Rubiales that governs the legal, technical and operating rights and obligations of the parties with respect to the joint operations of Block Z-1. Under the agreement, we are the operator and responsible for the administrative, regulatory, government and community related duties, and Pacific Rubiales manages the technical and operating duties in Block Z-1. The Joint Operating Agreement will continue for the term of the License Contract and thereafter until all decommissioning obligations under the License Contract have been satisfied.

 

At closing, Pacific Rubiales exchanged certain loans along with an additional $85.0 million, plus other amounts due to us or from us under the SPA, for the interests and assets obtained from us under the SPA and under the Block Z-1 License Contract. Proceeds of $150.0 million (less transaction costs of $5.7 million) less the net book value of the assets sold of $117.4 million resulting in a gain on the sale of $26.9 million for the year ended December 31, 2012, which was recognized as a component of operating and administrative expenses in connection with the closing. Due to certain tax benefits resulting from the sale, the after tax gain was $31.1 million.

 

The transaction provided for an adjustment based upon the collection of revenues ($56.1 million) and the payment of expenses ($32.6 million) and income taxes ($5.2 million) attributable to the properties that took place after the effective date of January 1, 2012 and prior to the closing date, which was December 14, 2012. These amounts were settled by adjusting down $18.3 million of the carry amount. At December 31, 2013 and December 31, 2012, the carry amounts were $81.3 million and $126.3 million, respectively.

 

At December 31, 2013 and December 31, 2012, we reflected $23.9 million and $19.9 million, respectively, as other current liabilities and $16.8 million and $20.8 million, respectively, as other non-current liabilities for exploratory expenditures related to Block Z-1 under funding by Pacific Rubiales of the exploratory expenditures in Block Z-1 incurred in 2012. This amount will be settled by us and Pacific Rubiales under the terms of the SPA.

 

 
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Corvina Field 

 

We originally began producing oil from the CX-11 platform, located in the Corvina field within the offshore Block Z-1 in northwest Peru, under a well testing program that started on November 1, 2007.  The Corvina field was placed into commercial production on November 30, 2010.  On the CX-11 platform, we have completed a total of nine gross (4.6 net) oil wells, the CX11-23D, the CX11-22D, the CX11-17D, the CX11-19D, the CX11-15D, the CX11-21XD, the CX11-20XD, the CX11-18XD and the CX11-14D wells, one of which is currently being used as gas injection and/or water injection well. Produced oil is kept in production inventory until such time as it is delivered to the refinery. The oil is delivered by vessel to storage tanks at the refinery in Talara, owned Petroperu, which is located 70 miles south of the platform. 

 

 

The CX-15 platform was anchored in the West Corvina field, one mile south of the existing CX-11 platform, in the second half of September 2012. On November 8, 2012, we received an environmental permit from the DGAAE allowing us to begin the drilling and subsequent operation of all production and injection facilities on the new CX-15 platform at the Corvina field. We installed three pipelines between the two Corvina platforms and one pipeline from the CX-15 platform to discharge manifold for the floating storage and offloading vessel.

 

Modifications made to the platform monitoring and control systems to facilitate operation of the CX-15 platform are complete. Equipment is tracking platform response to weather and ocean conditions as well as draft. As a precaution, an anchoring system was installed to provide redundancy to the spud can, which anchors the platform. In July 2013, we spudded the first development well, the CX15-1D, from the new CX-15 platform. Production began in October 2013 from the CX15-1D well. On the CX-15 platform, we completed one gross (0.5 net) oil well, the CX15-1D well. We spudded the second development well, the CX15-2D, in November 2013. The well was drilled near the existing CX11-18XD well to a measured depth of approximately 9,000 feet. We completed the CX15-2D well in January 2014. Production from the CX15-2D well began in February 2014. We spudded the CX15-3D well in February 2014.

  

Production at each of the Corvina oil wells has declined differently, partly due to the fact that these wells were completed in different zones and some of the wells encountered mechanical problems. The wells have all initially shown typical solution gas drive behavior which can lead to significant production declines during the first year before leveling off to sustainable rates. We believe these results are influenced by technical/mechanical problems encountered with our initial wells, including unintentional production from intervals in the gas cap; however, it is possible we will see similar production declines with new Corvina wells. We believe that our recent initiation of gas reinjection into the gas cap is helping to slow production decline rates. The work planned during the development drilling program, as well as the data we plan to collect during this program, should help us to better understand future performance expectations. Further, our ability to produce indicated reserves in Corvina depends on our ability to finance our continued operations and get our produced oil to market. Any failure in meeting these requirements could negatively affect our indicated reserves and their value as reported under the SEC. Therefore, in the evaluation of reserves, we attempt to account for all possible delays we can reasonably predict and their impact on the production forecast and remaining reserves to be produced.

 

Albacora Field

 

The Albacora field is located in the northern part of our offshore Block Z-1 in northwest Peru.  The current area of interest within the Albacora field is located in water depths of less than 100 feet. We currently have completed a total of five gross (2.5 net) oil wells, one of which is currently being used as gas injection and/or water injection well. We had been producing oil from the Albacora field from December 2009 through late October 2012 under various extended well testing permits.

 

Installation of the gas and water reinjection equipment was completed on the Albacora A platform and the equipment was ready for reinjection start up early in the first quarter of 2012. We received the required environmental permit for gas injection on October 29, 2012. The Albacora field is no longer subject to an extended well testing program. We spudded a development well, the A-18D well, from the A platform in the Albacora field of Block Z-1 in September 2013. This well was completed in December 2013. We also spudded a development well, the A-19D well, from the A platform in the Albacora field of Block Z-1 on January 1, 2014. The target depth of the A-19D well is approximately 12,400 feet. The A-19D well began production on March 1, 2014.

 

 
40

 

 

Block Z-1 Seismic

 

We completed the 3-D seismic survey of the area to assess our prospects before conducting further drilling operations, as well as to comply with our exploration commitments under our Block Z-1 License Contract. On November 3, 2011, we received the environmental permit to acquire approximately 1,600 square km of 3-D seismic data in our offshore Block Z-1 that was granted by the DGAAE. The seismic survey began in the first quarter of 2012. A second seismic boat was contracted to acquire the remaining areas where the CGGVeritas Vantage vessel was unable to safely navigate. The 3-D seismic acquisition on the remaining areas of Block Z-1 commenced in September 2012 and was completed in February 2013. Processing the seismic data acquired in both phases was completed by Fugro Seismic Services (now CGGVeritas Vantage) in September 2013.

 

The technical team continues to interpret the Block Z-1 3-D seismic data.   

 

Block XIX

 

We have received approval from Perupetro to conduct a limited 3-D seismic survey as part of our minimum work commitment for the fourth exploration period to further evaluate future drilling locations. The environmental assessment process is underway to obtain an environmental permit for the additional seismic work.

 

Block XXII

 

As a result of the 258 km of 2-D seismic survey completed in 2011, three prospects and one lead have been defined. Evaluation continues and we expect to develop a detailed assessment of each prospect in order to define their technical merit and risk to determine their exploration potential. We expect to conduct an additional 2-D seismic program as confirmation of potential drilling locations, and plan to drill exploratory tests, after receipt of the necessary environmental permits.

 

We have notified Perupetro that the commitment for the second exploration period will be the drilling of one well. The timing of the actual drilling in Block XXII will depend on approval of the environment assessment, which is underway, and subsequent receipt of the necessary ancillary permits. Drilling in Block XXII is expected in late 2014 or 2015.

 

Block XXIII

 

In 2011, we acquired approximately 370 square km of 3-D seismic data and 312 km of 2-D seismic data which included certain areas of interest within the Palo Santo region and four other prospects that are a part of the Mancora gas play. The processing of the 3-D and 2-D data of Block XXIII has been completed and evaluated.

 

The environmental permits for the drilling of several prospects identified by the 2-D and 3-D seismic data acquired in 2011 on Block XXIII were approved in January 2013. We have received approval to move the previously agreed drilling locations to conform to the 3-D seismic results.

 

We are in the second exploration period. We spudded an exploration well, the Caracol 1X, on January 5, 2014. This is the first of three exploratory wells we plan to drill in Block XXIII in 2014. The target depth of the Caracol 1X well is approximately 3,500 feet. Logs have been run after reaching total depth to determine testing intervals, and casing has now been set to test the selected intervals. A number of intervals have been selected for testing and the testing is ongoing.

 

Marine Operations

 

In 2013, we provided barge construction supervision to a third party. In December 2013, we entered into a Management Services Agreement with a third party marine operator to manage our marine fleet. We transferred our BPZ Marine S.R.L. employees to the new operator.

 

Gas-to-Power Project

 

Our gas-to-power project entails the planned installation of an approximately 10-mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and a 135 MW net simple-cycle power generation facility.  The proposed power plant site is located adjacent to an existing substation near Zorritos and a 220 kilovolt transmission line which is now capable of handling up to 420 MW of power. The existing substation and transmission lines are owned and operated by third parties.

 

In order to support our proposed electric generation project, we commissioned an independent power market analysis for the region. The Peruvian electricity market is deregulated and power is transported through an interconnected national grid managed by the Committee for Economic Dispatching of Electricity. Based on this study, we believe we will be able to sell, under contract, economic quantities of electricity from the initial 135 MW power plant. The market study also indicates that there may be future opportunities for us to generate and sell significantly greater volumes of power into the Peruvian and possibly Ecuadorian power markets.  Accordingly, the revenues from the natural gas delivered to the power plant will be derived from the sale of electricity.

 

 
41

 

 

We currently estimate the gas-to-power project will cost approximately $153.5 million, excluding capitalized interest, working capital and 18% value-added tax which will be recovered via future revenue billings.  The $153.5 million includes $133.5 million for the estimated cost of the power plant and $20.0 million for the natural gas pipeline. While we have held initial discussions with several potential joint venture partners for the gas-to-power project in an attempt to secure additional financing and other resources for the project, we have not entered into any definitive agreements with a potential partner. In the event we are able to identify and reach an agreement with a potential joint venture partner, we may retain only a minority position in the project, or the power generation facility may be wholly owned by a third party. However, we, along with our Block Z-1 partner, expect to retain the responsibility for the construction and ownership of the pipeline. We have obtained certain permits and are in the process of obtaining additional permits to proceed with the project.

 

Financing Activities

 

Convertible Notes due 2017

 

During the third quarter of 2013, we closed on an offering of an aggregate of $143.8 million of convertible notes due 2017 which includes the exercise of the underwriter’s option to purchase an additional $18.8 million of the 2017 Convertible Notes in addition to the original offering of $125.0 million. The 2017 Convertible Notes are general senior unsecured obligations and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in the right of payment to all of our existing and future subordinated debt.  The 2017 Convertible Notes are effectively subordinate to any of our secured indebtedness we may have to the extent of the value of the assets collateralizing such indebtedness.  The 2017 Convertible Notes are not guaranteed by our subsidiaries.

 

The interest rate on the 2017 Convertible Notes is 8.50% per year with interest payments due on April 1st and October 1st of each year.  The 2017 Convertible Notes mature with repayment of $143.8 million (assuming no conversion) on October 1, 2017.

 

The conversion rate is 249.5866 shares per $1,000 principal amount (equal to an initial conversion price of approximately $4.0066 per share of common stock). Upon conversion, if conversion is elected by the noteholder, we must deliver, at our option, either (1) a number of shares of our common stock determined as set forth in the Indenture agreement dated September 24, 2013, (2) cash, or (3) a combination of cash and shares of our common stock.

 

For further information regarding the 2017 Convertible Notes see “Liquidity, Capital Resources and Capital Expenditures” below.

 

Convertible Notes due 2015

 

During the first quarter of 2010, we closed on a private offering for an aggregate of $170.9 million of convertible notes due 2015. The 2015 Convertible Notes are our general senior unsecured obligations and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness.  The 2015 Convertible Notes are effectively subordinate to all of our secured indebtedness to the extent of the value of the assets collateralizing such indebtedness.  The 2015 Convertible Notes are not guaranteed by our subsidiaries. In September 2013, we repurchased $85.0 million of the principal balance of the $170.9 million of the 2015 Convertible Notes leaving $85.9 million of the 2015 Convertible Notes outstanding.

 

For further information regarding the 2015 Convertible Notes see “Liquidity, Capital Resources and Capital Expenditures” below.

 

$75.0 Million Secured Debt Facility

 

On July 6, 2011, we and our subsidiaries entered into a credit agreement with Credit Suisse and other parties (collectively the “lenders”), whereby the lenders agreed to provide a $75.0 million secured debt facility in two loan tranches to our subsidiary, BPZ E&P. The full amount available under the $75.0 million secured debt facility was drawn down by us on July 7, 2011. In April 2012, we and the lenders amended the terms of the $75.0 million secured debt facility and in May 2012, we prepaid $40.0 million of the principal balance of the $75.0 million secured debt facility. In May 2013, we prepaid the remaining principal balance of the $75.0 million secured debt facility.

 

 
42

 

 

For further information regarding the $75.0 million secured debt facility see “Liquidity, Capital Resources and Capital Expenditures” below.

 

$40.0 Million Secured Debt Facility

 

In January 2011, we, through our subsidiaries, completed a credit agreement with Credit Suisse whereby Credit Suisse provided a $40.0 million secured debt facility to our power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L. On April 27, 2012, we and our subsidiaries, Empresa Eléctrica Nueva Esperanza S.R.L. and BPZ E&P, entered into a fourth amendment to the $40.0 million secured debt facility with Credit Suisse. In May 2013, we amended and restated the $40.0 million secured debt facility (which had been repaid by scheduled principal repayments to $25.5 million) by increasing the facility size and borrowing an additional $14.5 million. In September 2013, we prepaid the remaining principal balance of the $40.0 million secured debt facility.

 

For further information regarding the $40.0 million secured debt facility see “Liquidity, Capital Resources and Capital Expenditures” below.

 

Future Market Trends and Expectations

 

 Our business depends primarily on the level of current and future oil and gas demand and prices which may impact our ability to raise capital to finance the development of our current and future oil and gas opportunities, to continue developing our gas-to-power project, which anchors our gas monetizing strategy, and to maintain our commitments and obligations under our current and possible future license contracts. The world economies are continuing on the path to recovery, though at a gradual pace. Growth has resumed, but is modest and the downside risks remain significant. However, if financial conditions continue to improve, global growth could be stronger than projected.   Global economic growth drives demand for energy from all sources, including fossil fuels.  A lower future economic growth rate could result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.

 

Geopolitical activities across the globe will also have an impact on oil prices. Unrest and conflicts in the world, including the Middle East, with the Syrian uprisings, as well as instability in North Africa, particularly in Egypt, will continue to contribute the volatility of global oil prices.

 

Oil supply will also play a significant role in price volatility. The significant spare oil production capacity of Saudi Arabia, and their desire to maintain target prices, will continue to be a factor influencing the global price of oil. In addition, new North American supply increases are driving down the U.S. crude imports. Crude oil generated the largest single annual increase in liquids production in U.S. history in 2012. The impact of a continued increase of U.S. crude oil production would also contribute to putting pressure on global oil prices.

 

In response to our current economic environment, for 2014, we will continue to focus on oil development in Block Z-1 with our Block Z-1 partner, specifically in the Corvina and Albacora fields.

 

From a production perspective, our goal is to increase production during 2014 based on what is expected to be a multi-year drilling program from the CX-15 and Albacora platforms, while gearing up to explore some of the other Block Z-1 prospects.

 

Expected operational cash flow from Corvina and Albacora oil sales should contribute towards funding the 2014 capital expenditures budget. The majority of our share of the 2014 Block Z-1 capital expenditures budget should be funded by our partner under the carry agreement in place. In addition, we will continue to evaluate our options on additional financing as needed. We anticipate future results will be based on our production levels and current and future oil prices. When forecasting our 2014 performance, we relied on assumptions about the market for oil, our customers and suppliers, past results and operational and regulatory delays. We continue to be conservative in view of oil pricing, though there are forecasts both above and below what we would assume for the average spot price. Our results could materially differ from what we anticipate if any of our assumptions, such as major technical or mechanical well issues, commodity pricing, or production levels prove to be incorrect. In addition, our businesses’ operations, financial condition and results of operations are subject to numerous risks and uncertainties that, if realized, could cause our actual results to differ substantially from our forward-looking statements. These risks and uncertainties are further described in Item 1A. — “Risk Factors” of this report.

 

 
43

 

 

Results of Operations

 

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

 

   

Year Ended

December 31,

         
   

2013

   

2012

   

Increase/

(Decrease)

 

 

 

(in thousands except per bbl information)

         
Net sales volume:                        

Oil (MBbls)

    507       1,188       (681 )
                         

Net revenue:

                       

Oil revenue, net

  $ 50,585     $ 122,708     $ (72,123 )

Other revenue

    144       250       (106 )

Total net revenue

    50,729       122,958       (72,229 )
                         

Average sales price (approximately):

                       

Oil (per Bbl)

  $ 99.79     $ 103.31     $ (3.52 )
                         

Operating and administrative expenses:

                       

Lease operating expense

    24,893       52,458       (27,565 )

General and administrative expense

    24,111       28,705       (4,594 )

Geological, geophysical and engineering expense

    2,184       43,787       (41,603 )

Depreciation, depletion and amortization expense

    27,214       45,873       (18,659 )

Standby costs

    4,311       5,340       (1,029 )

Other operating expense

    4,430       2,266       2,164  

Gain on divestiture

    -       (26,864 )     26,864  

Total operating and administrative expenses

  $ 87,143     $ 151,565     $ (64,422 )
                         

Operating loss

  $ (36,414 )   $ (28,607 )   $ (7,807 )

 

Net Oil Revenue

 

For the year ended December 31, 2013, our net oil revenue decreased by $72.1 million to $50.6 million from $122.7 million for the same period in 2012. The decrease in net oil revenue is due to: (1) a decrease in the amount of oil sold of 681 MBbls, and (2) a decrease of $3.52, or 3.4%, in the average per barrel sales price received. Total sales for the year ended December 31, 2013 were 507 MBbls compared to 1,188 MBbls for the same period in 2012. We expect net oil revenues to increase in 2014 from higher production in 2014 compared to 2013 due to our development drilling program in Block Z-1 that began in the second half of 2013.

 

The decrease in amount of oil sold is due to the December 2012 sale of a 49% participating interest in Block Z-1 to Pacific Rubiales (approximately 582 MBbls for the year ended December 31, 2012) and lower oil production in the Corvina and Albacora fields.

 

The 2013 price/volume analysis is as follows:

  

   

(in thousands)

 

2012 Oil revenue, net

  $ 122,708  

Changes associated with sales volumes

    (70,341 )

Changes associated with prices

    (1,782 )

2013 Oil revenue, net

  $ 50,585  

 

 
44

 

 

For the year ended December 31, 2013, we had consistent oil production from nine gross (4.6 net) producing wells and intermittent production from four gross (2.0 net) wells. During the same period in 2012, we had consistent oil production from seven (3.6 net) producing wells and intermittent production from four (2.0 net) wells. Total oil production for the year ended December 31, 2013 was 514 MBbls compared to 1,185 MBbls for the same period in 2012. The transfer of a 49% participating interest in Block Z-1 to Pacific Rubiales was effective on December 14, 2012 and the entitlement to crude oil production from that day forward was allocated to each partner. The sharing of any production prior to that date was handled as an adjustment to the carry amount under the SPA.

 

On a pro forma basis, our production for the year ended December 31, 2012 would have been approximately 604 MBbls, assuming the sale of the 49% participating interest in Block Z-1 had closed on January 1, 2012.

 

The decrease in oil production is due to the December 2012 sale of a 49% participating interest in Block Z-1 to Pacific Rubiales (approximately 581 MBbls for the year ended December 31, 2013) and lower oil production in the Corvina field and in the Albacora field.

 

The revenues above are reported net of royalties owed to the government of Peru. Royalties are assessed by Perupetro as stipulated in the Block Z-1 License Agreement based on production levels.

 

The following table is the amount of royalty costs of approximately 5% of gross revenues for the year ended December 31, 2013 and 2012:

 

 

   

2013

   

2012

 
   

(in thousands)

 

Royalty costs

  $ 2,707     $ 6,605  
    $ 2,707     $ 6,605  

 

Other Revenue

 

For the year ended December 31, 2013, other revenue decreased $0.2 million to $0.1 million from $0.3 million for the same period in 2012.

 

During the year ended December 31, 2013, we recognized other revenue associated with the chartering of support vessels.

 

During the year ended December 31, 2012, we chartered one vessel to a third party for approximately two weeks in January, and two marine vessels to a third party for approximately one week in September.

 

Lease Operating Expense 

 

Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities, as well as crude oil transportation and inventory changes. These costs include, among others, workover expenses, maintenance and repairs expenses, operator fees, processing fees, insurance and transportation expenses.

 

For the year ended December 31, 2013, lease operating expenses decreased by $27.5 million to $25.0 million ($49.11 per Bbl) from $52.5 million ($44.16 per Bbl). The decrease is due to a reduction in lease operating expenses of approximately $25.7 million related to the sale of a 49% participating interest in Block Z-1 in December 2012. Additionally, repairs and maintenance expense decreased by $1.7 million due to fewer maintenance and repairs on vessel support services, fuel costs decreased by $1.1 million, contract pumping services decreased by $0.9 million due to reduced rent of hydraulic jet pumps used to assist oil production and other lease operating expenses decreased by $0.3 million. These decreases were offset by higher workover expenses of $2.2 million associated with the one major workover performed in 2013, compared to the one major less expensive workover in 2012. We expect lease operating expense to increase in 2014 due to increased production in Block Z-1 as a result of our development drilling program that began in the second half of 2013.

 

General and Administrative Expense

 

General and administrative expenses are overhead-related expenses, including employee compensation, legal, consulting and accounting fees, insurance, and investor relations expenses.

 

 
45

 

 

For the year ended December 31, 2013, general and administrative expenses decreased by $4.6 million to $24.1 million from $28.7 million for the same period in 2012.  Stock-based compensation expense, a subset of general and administrative expenses, was $2.8 million for the year ended December 31, 2013 and $2.8 million for the same period in 2012. Other general and administrative expenses decreased $4.6 million to $21.3 million from $25.9 million for the same period in 2012. The $4.6 million decrease is due to lower salary and related costs of $1.9 million due to fewer employees, lower non-income taxes of $1.3 million, lower consulting costs of $0.5 million and lower other general and administrative expenses of $0.9 million.

 

We expect our 2014 general and administrative expenses to be similar to our 2013 general and administrative expenses.

 

Geological, Geophysical and Engineering Expense

 

        Geological, geophysical and engineering expenses include laboratory, environmental and seismic acquisition related expenses.

 

The transfer of a 49% participating interest in Block Z-1 to Pacific Rubiales was effective on December 14, 2012 and the carry of exploratory expenditures for Block Z-1 by Pacific Rubiales began that day. Our share of the 2013 Block Z-1 exploratory expenditures was fully funded by our partner under the carry agreement in place.

 

For the year ended December 31, 2013, geological, geophysical and engineering expenses decreased $41.6 million to $2.2 million compared to $43.8 million for the same period in 2012. The decrease is due to the seismic acquisition activity associated with our seismic data acquisition plan for Block Z-1 that occurred in 2012 compared to the lower activity and funding of seismic expenses in Block Z-1 by Pacific Rubiales in 2013.

 

We expect our 2014 geological, geophysical and engineering expense to increase compared to our 2013 geological, geophysical and engineering expense for Blocks XIX, XXII and XXIII. We expect our share of the 2014 Block Z-1 exploratory expenditures to be fully funded by our partner under the carry agreement in place.

 

Dry Hole Costs

 

There were no dry hole costs for the year ended December 31, 2013 or December 31, 2012.

 

Depreciation, Depletion and Amortization Expense

 

                For the year ended December 31, 2013, depreciation, depletion and amortization expense decreased $18.7 million to $27.2 million from $45.9 million for the same period in 2012. We expect depreciation, depletion and amortization expense in 2014 to be approximately in the range of depreciation, depletion and amortization expense in 2013.

 

For the year ended December 31, 2013, depletion expense decreased $13.5 million to $18.0 million from $31.5 million during the same period in 2012. The decrease for the year ended December 31, 2013 compared to the same period in 2012 is due to lower production in the Corvina and Albacora fields in 2013 and the sale of a 49% participating interest in the Block Z-1 License Contract in December 2012.

 

For the year ended December 31, 2013, depreciation expense decreased $5.2 million to $9.2 million compared to $14.4 million for the same period in 2012. The decrease is due to assets included in the sale of a 49% participating interest in the Block Z-1 License Contract in December 2012 and the change in our method of estimating the depreciation of producing equipment to the unit-of-production method from a straight-line five-year life method, partially offset by a change in useful life, as a result of new laws, of two vessels used in our marine operations that is contributing an additional $0.6 million of depreciation expense per quarter which began in the third quarter of 2012 and is expected to continue through December 2014.

 

Standby Costs

 

For the year ended December 31, 2013, we incurred $4.3 million in standby rig costs.

 

During 2013, we had the Petrex-10 rig partially or fully on standby for approximately three months and two rigs, the Petrex-28 rig and Petrex-21 rig, partially or fully on standby for approximately five months. We expect standby costs to be lower in 2014 due to the drilling program at the CX-15 platform that began in late 2013.

 

 
46

 

 

For the year ended December 31, 2012, we incurred $5.3 million in standby rig costs.

 

During 2012, we had the Petrex-18 rig, which was previously leased to another operator in 2011, on standby through July 31, 2012. Our contract on this rig was amended and the contract was suspended from August 1, 2012 through April 30, 2013. We had the Petrex-28 rig on standby from September 2012 through December 2012, as we expected to use this rig in drilling operations on the new CX-15 platform. Additionally, in 2012, we had a workover rig, the Petrex-10, on standby for two months to allow for seismic acquisition activities where the workover rig was operating.

 

Other Operating Expense

 

For the year ended December 31, 2013, we reported $4.4 million of charges in the Consolidated Statements of Operations as “Other operating expense.” We expensed these costs related to historical pre-development drilling studies for drilling locations and platform technologies and associated capitalized interest as we believe that these locations and technologies may change and we do not see a future value for these studies.

 

For the year ended December 31, 2012, we reported $2.3 million of abandonment charges in the Consolidated Statements of Operations as “Other operating expense.” We accrued $2.3 million of abandonment costs related to a platform in the Piedra Redonda field in Block Z-1, as we are obligated to ensure the offshore platform does not cause a threat to navigation in the area or marine wildlife. The $2.3 million charge is in addition to the Piedra Redonda platform abandonment costs previously recorded in the third quarter of 2010.

 

Gain on Divestiture

 

On April 27, 2012, we and Pacific Rubiales (together with its subsidiaries) executed a SPA under which we formed an unincorporated joint venture to explore and develop the offshore Block Z-1 located in Peru. Pursuant to the SPA, Pacific Rubiales agreed to pay $150.0 million for a 49% participating interest, including reserves, in Block Z-1 and agreed to fund $185.0 million of our share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012. On December 14, 2012, Perupetro approved the terms of the amendment to the Block Z-1 License Contract to recognize the sale of a 49% participating interest in offshore Block Z-1 to Pacific Rubiales. We and Pacific Rubiales waived and modified certain contract conditions in order to close the transaction. On December 30, 2012, the Peruvian Government signed the Supreme Decree for the execution of the amendment to the Block Z-1 License Contract. The receipt of net proceeds ($150.0 million, less transaction costs of $5.7 million) in excess of the net book value of 49% of Block Z-1 historic assets of $117.4 million resulting in a pre-tax gain of $26.9 million for the year ended December 31, 2012. Tax impacts of this gain are reported under Income Taxes.

 

There were no similar gains in 2013.

 

Other Income (Expense)

 

Other income (expense) includes non-operating income items. These items include interest expense and income, loss on the extinguishment of debt, gains or losses on foreign currency transactions, income and amortization related to the investment in our Ecuador property, as well as gains or losses on derivative financial instruments. For the year ended December 31, 2013, total other expense increased $1.0 million to $27.1 million compared to $26.1 million during the same period in 2012. The increase is due to the following:

 

Interest expense: For the year ended December 31, 2013, we recognized approximately $16.2 million of net interest expense, which included $26.1 million of interest expense reduced by $9.9 million of capitalized interest expense. For the year ended December 31, 2012, we recognized approximately $16.1 million of net interest expense which includes $31.7 million of interest expense reduced by $15.6 million of capitalized interest expense. The increase of $0.1 million in net interest expense is due to lower capitalized interest of $5.7 million because of lower average construction in progress balances between the two periods as a result of the development of the CX-15 platform and Albacora production and gas injection facilities in 2012, partially offset by lower interest expense of $5.6 million resulting from a lower average of interest bearing debt outstanding between the two periods due to the $40.0 million principal debt prepayment made in May 2012 on the $75.0 million secured debt facility, scheduled principal repayments since March 2012 and the retirement of the remaining $30.5 million of the $75.0 million secured debt facility in May 2013.

 

 
47

 

 

Loss on extinguishment of debt: As a result of the prepayment of the remaining $30.5 million under the $75.0 million secured debt facility during the second quarter of 2013, we incurred $2.4 million of fees and prepayment premium and expensed $1.4 million of unamortized debt issue costs. These amounts were recognized as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations. As a result of the prepayment of the remaining $36.0 million under the $40.0 million secured debt facility during the third quarter of 2013, we incurred $2.0 million of fees and prepayment premium and expensed $1.7 million of unamortized debt issue costs. These amounts were recognized as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations. As a result of the repurchase of $85.0 million of principal amount of the 2015 Convertible Notes during the third quarter of 2013, approximately $12.2 million of the repayment was considered a retirement of debt. We recognized a gain on the retirement of the debt of approximately $0.2 million and this gain is included in the “Loss on extinguishment of debt” in the Consolidated Statement of Operations. For the year ended December 31, 2013, we reported $7.2 million as a loss on extinguishment of debt.

 

As a result of the prepayment and amendment to the $75.0 million secured debt facility during the second quarter of 2012, we incurred $5.8 million of fees and prepayment penalties and $1.1 million of debt issue costs. The $5.8 million in fees and prepayment penalties were recognized as a “Loss on extinguishment of debt” in the consolidated statement of operations of which 25% was paid at the time of the amendment and prepayment and 25% was paid at the time of each of the next three quarterly interest payment dates ending in January 2013. Approximately $1.5 million of the remaining $2.8 million of unamortized debt issue costs associated with the initial loan was expensed as a “Loss on extinguishment of debt” in the consolidated statement of operations when we prepaid $40.0 million of principal. For the year ended December 31, 2012, we reported $7.3 million as a loss on extinguishment of debt.

 

Gain (loss) on derivatives: In connection with obtaining the $40.0 million and $75.0 million secured debt facilities in January and July 2011, respectively, we entered into performance based arranger fees (“Performance Based Arranger Fee”) that we are accounting for as embedded derivatives. As a result of the fair value measurement at December 31, 2013 and 2012, respectively, from the measurement at January 1, 2013 and January 1, 2012, respectively, the gain associated with the embedded derivatives increased $2.9 million to a $0.3 million gain for the year ended December 31, 2013 from a $2.6 million loss for the same period in 2012.

 

Investment income: For the year ended December 31, 2013, income from our investment in Ecuador property, net of investment amortization, increased by $0.1 million to income of $0.2 million from income of $0.1 million in 2012.  For both periods, the dividends received were $0.3 million. For the year ended December 31, 2013 and 2012, investment income includes amortization expense of approximately $98,000 and $188,000, respectively.

 

Other income (expense): For the year ended December 31, 2013, other expense increased $4.1 million to $4.3 million compared to $0.2 million in the same period in 2012. For the year ended December 31, 2013, expenses of $2.5 million relating to the issuance of the 2017 Convertible Notes were included. There were no similar expenses for the same periods in 2012. Also, for the year ended December 31, 2013 and 2012, foreign currency losses were $1.2 million and $0.2 million, respectively.

 

Income Taxes 

 

The source of net loss before income tax expense (benefit) for the year ended December 31 is as follows (in thousands):

 

   

2013

   

2012

 

United States

  $ (31,163 )   $ (6,465 )

Foreign

    (32,323 )     (48,238 )

Loss before income taxes

  $ (63,486 )   $ (54,703 )

 

 
48

 

 

The income tax provision (benefit) for the year ended December 31 consists of the following (in thousands):

 

   

2013

   

2012

 

Current Taxes

               

Federal

  $ 668     $ -  

Foreign

    2,595       13,551  

Total Current

    3,263       13,551  
                 

Deferred Taxes

               

Federal

    -       -  

Foreign

    (9,038 )     (29,165 )

Total Deferred

    (9,038 )     (29,165 )

Total income tax expense (benefit)

  $ (5,775 )   $ (15,614 )

 

The income tax expense (benefit) for the year ended December 31 differs from the amount computed by applying the U.S. statutory federal income tax rate for the applicable year to consolidated net loss before income taxes as follows (in thousands):

 

   

2013

   

2012

 

Federal statutory income tax rate

  $ (21,585 )   $ (18,599 )

Increases (decreases) resulting from:

               

Peruvian income tax - rate difference less than 34% statutory

    3,341       7,791  

Permanent book/tax differences

    262       (621 )

Non-deductible intercompany expenses and other

    (198 )     2,763  

Effect of asset sale with retained oil intangible tax attribute

    -       (15,111 )

Effect of cumulative profit sharing adjustment

    -       (895 )

Effect of foreign exchange rate

    (1,462 )     (1,678 )

Current year foreign withholding tax

    1,690       1,699  

Change in valuation allowance

    11,509       9,037  
Uncertain tax positions     668       -  

Total income tax expense (benefit)

  $ (5,775 )   $ (15,614 )

 

 
49

 

 

A summary of the components of deferred tax assets, deferred tax liabilities and other taxes deferred at December 31 are presented below (in thousands):

 

 

   

2013

   

2012

 

Deferred Tax:

               

Asset:

               

Net Operating Loss

  $ 77,588     $ 57,698  

Deferred Compensation

    4,704       4,221  

Asset Basis Difference

    9,253       5,129  

Exploration Expense

    15,836       14,054  

Depletion

    -       3,652  

Asset Retirement Obligation

    809       593  

Overhead Allocation to Foreign Locations

    10,207       7,476  

Other

    2,078       2,069  

Liability:

               

Depreciation

    (6,272 )     (724 )

Other

    -       (30 )

Net Deferred Tax Asset

    114,203       94,138  
                 

Less Valuation Allowance

    (50,601 )     (38,896 )

Deferred tax asset

  $ 63,602     $ 55,242  

 

At December 31, 2013, we had recognized a gross deferred tax asset related to net operating loss carryforwards of $77.6 million before application of the valuation allowances. Net deferred tax assets in the foregoing table include the deferred consequences of the future reversal of Peruvian deferred tax assets and liabilities on the impact of the Peruvian employee profit share plan tax of $7.0 million in 2013 and $5.8 million in 2012.

 

At December 31, 2013, we had recognized a gross deferred tax asset related to net operating loss carryforwards attributable to the United States of $57.0 million, before application of the valuation allowances. As of December 31, 2013, we had a valuation allowance for the full amount of the domestic deferred tax asset of $46.8 million, resulting from the income tax benefit generated from net losses, as we believe, based on the weight of available evidence, that it is more likely than not that the deferred tax asset will not be realized prior to the expiration of net operating loss carryforwards in various amounts through 2033. Furthermore, because we had no operations within the U.S. taxing jurisdiction, it is likely that sufficient generation of revenue to offset our deferred tax asset is remote. 

 

At December 31, 2013, we had recognized a gross deferred tax asset related to net operating loss carryforwards attributable to foreign jurisdictions of $20.6 million, before application of the valuation allowances, attributable to foreign net operating losses, which begin to expire in 2014. We are subject to Peruvian income tax on its earnings at a statutory rate, as defined in the Block Z-1 License Contract, of 22%.  We assessed our ability to realize the deferred tax asset generated in Peru. We considered whether it is more likely than not that some portion or all of the deferred tax asset will not be realized. The ultimate realization of the deferred tax asset is dependent upon the generation of future taxable income in Peru during the periods in which those temporary differences become deductible. Based upon the level of historical taxable income, the availability of certain prudent and feasible income tax planning opportunities and projections for future taxable income over the periods in which the deferred tax assets are deductible, along with the transition into the commercial phase under the Block Z-1 License Contract, we believe it is more likely than not that we will realize the majority of the these deductible differences at December 31, 2013. In addition, we had a $3.8 million valuation allowance on certain foreign deferred tax assets related to overhead allocations and exploration activities on Blocks XIX, XXII and XXIII, as we believe we may not receive the full benefit of these deductions. As a result, we recognized a net deferred tax asset of $63.6 million related to our foreign operations as of December 31, 2013.

 

We recognized a total tax provision for the year ended December 31, 2013 of approximately $5.8 million. No provision for U.S. federal and state income taxes has been made for the difference in the book and tax basis of our investment in foreign subsidiaries as such amounts are considered permanently invested. Distribution of earnings, as dividends or otherwise, from such investments could result in U.S. federal taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable in various foreign countries. Due to our significant net operating loss carryforward position we have not recognized any excess tax benefit related to our stock compensation plans. ASC Topic 718, “Stock Compensation” (“ASC Topic 718”) prohibits the recognition of such benefits until the related compensation deduction reduces the current tax liability.

 

 
50

 

 

 

A reconciliation of the beginning and ending amount of unrecognized tax benefits at December 31 is as follows (in thousands):

 

   

2013

   

2012

 
                 

Balance January 1

  $ -     $ -  

Additions related to tax positions taken in the current year

    -       -  

Additions related to tax positions of prior years

    668       -  

Reductions related to tax positions of prior years

    -       -  

Reductions related to settlements with taxing authorities

    -       -  

Reductions related to lapses in statute of limitations

    -       -  

Balance December 31

  668     -  

 

The December 31, 2013 balance of unrecognized tax benefits includes $0.7 million that, if recognized, would impact our effective income tax rate. Over the next 12 months, we do not anticipate any reduction in the balance. We had accrued interest and penalties related to unrecognized tax benefits of $46,000 and none as of December 31, 2013 and 2012, respectively. Estimated interest and penalties related to potential underpayment on unrecognized tax benefits, if any, are classified as a component of income tax expense in the Consolidated Statement of Operations.

 

Net Loss

 

For the year ended December 31, 2013, our net loss increased $18.6 million to a net loss of $57.7 million, or ($0.50) per basic and diluted share, from a net loss of $39.1 million, or ($0.34) per basic and diluted share, for the same period in 2012.

 

 
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Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

 

 

   

Year Ended

December 31,

         
   

2012

   

2011

   

Increase/

(Decrease)

 

 

 

(in thousands except per bbl information)

         
Net sales volume:                        

Oil (MBbls)

    1,188       1,380       (192 )
                         

Net revenue:

                       

Oil revenue, net

  $ 122,708     $ 139,354       (16,646 )

Other revenue

    250       4,386       (4,136 )

Total net revenue

    122,958       143,740       (20,782 )
                         

Average sales price (approximately):

                       

Oil (per Bbl)

  $ 103.31     $ 101.01     $ 2.30  
                         

Operating and administrative expenses

                       

Lease operating expense

    52,458       50,792       1,666  

General and administrative expense

    28,705       34,998       (6,293 )

Geological, geophysical and engineering expense

    43,787       12,917       30,870  

Dry hole costs

    -       13,082       (13,082 )

Depreciation, depletion and amortization expense

    45,873       38,944       6,929  

Standby costs

    5,340       4,529       811  

Other operating expense

    2,266       -       2,266  

Gain on divestiture

    (26,864 )     -       (26,864 )

Total operating and administrative expenses

  $