10-K 1 bpz20141231_10k.htm FORM 10-K bpz20141231_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, 2014

 

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 (§ 229.405 of this chapter) 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, 2014 was 67,603,654 shares, all of one class of common stock, no par value, having an aggregate market value of approximately $208,219,254 based upon the closing price of registrant’s common stock on such date of $3.08 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.

 

 

As of February 28, 2015 there were 118,663,085 shares of common stock, no par value, outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

(1) Information required by Part III is incorporated by reference from Registrant’s proxy statement or an amendment to this Annual Report on Form 10-K, which will be filed with the Securities and Exchange Commission within 120 days after the end of its fiscal year ended December 31, 2014.



 
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TABLE OF CONTENTS

 

PART I

   

Item 1.

Business

 3

Item 1A.

Risk Factors

13

Item 1B.

Unresolved Staff Comments

29

Item 2.

Properties

30

Item 3.

Legal Proceedings

41

Item 4

Mine Safety Disclosures

42

     

PART II

   

Item 5.

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

43

Item 6.

Selected Financial Data

45

Item 7.

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

46

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

90

Item 8.

Financial Statements and Supplementary Data

92

Item 9

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

151

Item 9A.

Controls and Procedures

151

Item 9B.

Other Information

153

     

PART III

   

Item 10.

Directors, Executive Officers and Corporate Governance

153

Item 11.

Executive Compensation

153

Item 12.

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

153

Item 13.

Certain Relationships and Related Transactions, and Director Independence

153

Item 14.

Principal Accountant Fees and Services

153

     

PART IV

   

Item 15.

Exhibits, Financial Statement Schedules

154

     

Glossary of Oil and Natural Gas Terms

155

     

Signatures

 

158

 

 
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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. References herein to “Debtor” refer only to BPZ Resources, Inc.

 

ITEM 1. BUSINESS

 

Introduction

 

BPZ Resources, Inc., a Texas corporation, is based in Houston, Texas with offices in Victoria, Texas, Lima and Zorritos, 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 development of a gas-fired power generation facility in Peru, which may be wholly-owned or partially-owned, or may be wholly-owned by a third party.

 

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 agreements 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 and off the northwest coast of Peru in the Gulf of Guayaquil. 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.

 

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.

 

Voluntary Reorganization Under Chapter 11

 

We have not been profitable since we commenced operations and we require substantial capital expenditures as we advance development projects at Block Z-1 and exploration projects in our other Blocks. Currently, we require additional financing to continue to fund our capital expenditure program and implement our business plan. Our major sources of funding to date have been oil sales, equity and debt financing activities and asset sales.  The increased capital costs and debt service costs in the current economic environment for the oil and gas industry have placed a strain on our cash flow from operations and our ability to reduce our debt leverage.

 

 
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We currently have the following convertible notes outstanding: (i) $59.9 million principal amount of Convertible Notes due 2015 (the “2015 Convertible Notes”), which bear interest semi-annually at a rate of 6.50% per year, and (ii) $168.7 million principal amount of Convertible Notes due 2017 (the “2017 Convertible Notes”), which bear interest semi-annually at a rate of 8.50% per year. The 2015 Convertible Notes matured with repayment of approximately $62 million in principal and interest due on March 1, 2015. Our estimated capital and exploratory budget for 2015 calls for us to spend approximately $58.6 million in 2015 on capital and exploratory expenditures, excluding capitalized interest, for our three onshore Blocks in which we hold 100% working interests, and our share of the capital and exploratory expenditures for offshore Block Z-1 required under our Joint Venture Agreement with Pacific Rubiales. The carry amount Pacific Rubiales agreed to pay under the joint venture was completed in December 2014 and we are now responsible for funding our full share of capital expenditures and joint operating expenditures for Block Z-1.

 

The price of oil per barrel has dropped dramatically, particularly in the fourth quarter 2014 and continuing in the first quarter 2015, by more than half since its high in June 2014. In mid-October 2014, we withdrew our previously announced private placement offer of $150.0 million in senior secured notes due 2019 due to adverse market conditions.

 

On December 8, 2014, the Company received a notification from the New York Stock Exchange (“NYSE”) that the Company had fallen below the NYSE's continued listing standard relating to minimum share price, which requires a minimum average closing price of $1.00 per share over 30 consecutive trading days. The price has remained well below such threshold and the NYSE subsequently notified us on March 2, 2015 that it had determined to commence proceedings to delist our common stock.

 

As a result of the aforementioned events and circumstances, in December 2014 we engaged the services of Houlihan Lokey Capital Inc. (the “Advisors”) to assist us in analyzing various strategic alternatives and addressing our liquidity and capital structure, and formed a special committee of the Board of Directors to work with the Advisors. We engaged in discussions with representatives of our various debt holders regarding, among other items, the potential terms under which one or both bond issues could be restructured to provide a capital structure which would allow us to continue developing our oil and gas assets.  We have also pursued discussions with other potential investors regarding alternative financing solutions.  We decided that it was in the best long-term interest of all stakeholders, both credit and equity holders, to expeditiously address the Company's capital structure with the goal of reducing debt and the cost of capital to position the Company for the future, and on March 2, 2015 announced that we had decided not to pay approximately $62 million in principal and interest due on March 1, 2015 on our 2015 Convertible Notes and to use a 10-day grace period on principal due and a 30-day grace period on interest due to continue discussions with our debt holders.

 

We were unable to reach a mutually agreeable solution within the grace period for the principal amount due on the 2015 Convertible Notes and elected not to make the approximate $59.9 million in principal payment due at the end of the grace period for principal due. As a result, we are in default under the 2015 Convertible Notes, permitting the trustee for the 2015 Convertible Notes or the holders of at least 25% in aggregate principal amount of the outstanding 2015 Convertible Notes to declare the full amount of the principal and interest thereunder immediately due and payable. If the 2015 Convertible Notes were to be accelerated, an event of default would occur under the indenture for the 2017 Convertible Notes, permitting the trustee or the holders of at least 25% in aggregate principal amount of the outstanding 2017 Convertible Notes to also declare the full amount of the principal and interest thereunder immediately due and payable.

 

On March 9, 2015 (the “Petition Date”), BPZ Resources, Inc. (the “Debtor”) filed a voluntary petition for reorganization relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) to provide more time to find an appropriate solution to its financial situation and implement a plan of reorganization aimed at improving its capital structure. The Chapter 11 case is being administered by the Bankruptcy Court as Case No. 15-60016.

 

The filing of the Chapter 11 case constituted an event of default that triggered repayment obligations under the 2015 Convertible Notes and the 2017 Convertible Notes. The ability of the holders of the 2015 Convertible Notes and the 2017 Convertible Notes to seek remedies and enforce their rights under the indentures was automatically stayed as a result of the filing of the Chapter 11 case, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

 

Since the Petition Date, the Debtor has operated its business as a “debtor-in-possession” pursuant to Sections 1107(a) and 1108 of the Bankruptcy Code, which will allow the Debtor to continue operations during the reorganization proceedings.  The Debtor will remain in possession of its assets and properties, and its business and affairs will continue to be managed by its directors and officers, subject in each case to the supervision of the Bankruptcy Court. 

 

None of the Debtor’s direct or indirect subsidiaries or affiliates has filed for reorganization under Chapter 11 and none is expected to file for reorganization or protection from creditors under any insolvency or similar law in the U.S. or elsewhere. The Debtor’s subsidiaries will continue to operate outside of any reorganization proceedings. We therefore do not expect the Debtor’s filing for Chapter 11 protection to impact our license agreements.

 

 
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On the day after the Petition Date, the Debtor obtained approval from the Bankruptcy Court for a variety of “first day” motions to give the Debtor the authority to take a broad range of actions, including, among others, authority to maintain bank accounts and the cash management system, pay certain employee obligations, post-petition utilities and other customary relief. 

 

Overview

 

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 and permitting of the CX-15 platform in the Corvina field in November 2012 to continue the development of the field. In July 2013, we spudded the first development well from the CX-15 platform and have since completed drilling seven wells from the CX-15 platform. We also spudded a new development well from the A platform in the Albacora field of Block Z-1 in September 2013 and have completed drilling four wells thereafter from the A platform. From the time we began producing from the Corvina field in November 2007 and the Albacora field in December 2009, through December 31, 2014, the two fields have produced approximately 7.4 MMBbls (100% gross and net through December 14, 2012 and 51% net thereafter) of oil. Three onshore shallow exploration wells, ranging in depth from 3,500 to 3,800 feet, have been drilled at Block XXIII during 2014. We are planning to pursue a long term testing program in these Block XXIII prospects, starting with Piedra Candela, and potentially sell the tested gas under a pilot program to the local communities.

 

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.

 

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 operation 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 Block Z-1 License Contract and thereafter until all decommissioning obligations under the License Contract have been satisfied.

 

At December 31, 2014, we had estimated net proved oil reserves of 13.6 MMBbls, of which 9.8 MMBbls were in the Corvina field and 3.8 MMBbls were from the Albacora field. Both fields are located in Block Z-1 offshore of northwest Peru. Of our total proved reserves, 4.2 MMBbls (30.9%) are classified as proved developed reserves consisting of proved developed producing and proved developed non-producing reserves from 22 gross (11.2 net) wells, and 9.4 MMBbls (69.1%) 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 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.

 

 
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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 process for an environmental permit is underway and approval must be received before anticipated drilling can begin in 2016. Three onshore shallow exploration wells, ranging in depth from 3,500 to 3,800 feet, have been drilled at Block XXIII during 2014. These wells targeted the Caracol, El Cardo, and Piedra Candela prospects, which are on a six-mile trend. All three wells tested dry gas from the Mancora formation.

 

In the near term, management is focused on drilling operations at both the CX-15 platform in the Corvina field and at the A platform in the Albacora field, utilizing the results of the 1,600 square kilometers (“km”) of three dimensional (“3-D”) seismic survey in Block Z-1. We plan to pursue a long-term testing program in the Block XXIII prospects and are in preliminary discussions with a local compressed natural gas (CNG) distributor to purchase the gas produced as a result of the long-term testing program. Additional appraisal wells could be included in the long-term testing program if test results warrant. We have received the long-term gas testing permit.

 

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.

 

 
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Our Competition

 

The oil and gas industry can be highly competitive and we compete with numerous other companies. Our competitors in the exploration, development acquisition and production business include major integrated oil and gas companies as well as numerous independent companies, including many that have significantly greater financial resources. 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. Any 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.

 

Any increased demand for oil and gas impacts the competition for access to drilling and other contract services and experienced technical and operating personnel needed to drill and complete wells. 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, any limitations on availability of 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.

 

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, as well as the Ministry of Agriculture, the Ministry of Culture and the Dirección General de Capitanías y Guardacostas del Perú (“DICAPI”).

 

 
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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.

 

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 16, 2015, 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, 2014, 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 $1.6 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.

 

 
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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 the Superintendencia Nacional de Aduanas y de Administracion Tributaria (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.

 

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.

 

 
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Peruvian environmental regulation. Our operations are subject to numerous 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, and is therefore subject to change. 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.

 

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.

 

 
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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.

 

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, 2014, 2013, and 2012 were approximately $0.8 million, $0.3 million, and $0.5 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.

 

 
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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, 2014, we employed 25 full-time employees of BPZ Resources, Inc., and 75 full-time employees within our subsidiaries BPZ E&P and BPZ Marine Peru 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 Related to Bankruptcy.

 

BPZ Resources, Inc. (the “Debtor”) filed for reorganization under Chapter 11 of the Bankruptcy Code on March 9, 2015 (theChapter 11 Case”) and is subject to the risks and uncertainties associated with Chapter 11 cases. For the duration of the Chapter 11 Case, our operations and our ability to execute our business strategy will be subject to the risks and uncertainties associated with bankruptcy.   These risks and uncertainties include:  

 

 

our ability to develop, prosecute, confirm and consummate a plan of reorganization with respect to the Chapter 11 Case;

 

our ability to obtain Bankruptcy Court approval with respect to motions filed in the Chapter 11 Case from time to time;

 

the actions and decisions of our creditors and other third parties who have interests in the Chapter 11 Case that may be inconsistent with our plans;

 

the ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for us to propose and confirm a plan of reorganization, to appoint a U.S. trustee or to convert the Chapter 11 Case to a Chapter 7 case;

 

our ability to obtain and maintain normal payment and other terms with customers, vendors and service providers;

 

our ability to maintain contracts that are critical to our operations;

 

our ability to attract, motivate and retain key employees;

 

our ability to retain key vendors or secure alternative supply sources;

 

our ability to fund and execute our business plan;

 

our ability to obtain acceptable and appropriate financing, including debtor-in-possession financing if required; and

 

our ability to utilize net operating loss carryforwards.

 

These risks and uncertainties could affect our business and operations in various ways.  For example, negative events or publicity associated with the Chapter 11 Case could adversely affect our relationships with our vendors and employees, as well as with customers, which in turn could adversely affect our operations and financial condition.  Also, pursuant to the Bankruptcy Code, we need Bankruptcy Court approval for transactions outside the ordinary course of business, which may limit our ability to respond timely to events or take advantage of opportunities.  Because of the risks and uncertainties associated with the Chapter 11 Case, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 proceedings will have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern. In addition, our auditors have expressed substantial doubt about our ability to continue as a going concern. See the Report of Independent Registered Public Accounting Firm included under Item 8. “Financial Statements and Supplementary Data.”

  

As a result of the Chapter 11 Case, realization of assets and liquidation of liabilities are subject to uncertainty.  While operating under the protection of the Bankruptcy Code, and subject to Bankruptcy Court,  approval or otherwise as permitted in the normal course of business, we may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in our consolidated financial statements.  Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

 

A plan of reorganization or liquidation may result in holders of our capital stock receiving very limited or no distribution on account of their interests and cancellation of their existing stock. If certain requirements of the Bankruptcy Code are met, a Chapter 11 plan or reorganization can be confirmed notwithstanding its rejection by our equity securityholders and notwithstanding the fact that such equity securityholders do not receive or retain any property on account of their equity interests under the plan.

 

Operating under Bankruptcy Court protection for a long period of time may harm our business. Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity.  So long as the proceedings related to the Chapter 11 Case continue, our senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations.  A prolonged period of operating under Bankruptcy Court protection also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the proceedings related to the Chapter 11 Case continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our businesses successfully and will seek to establish alternative commercial relationships.

 

 
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Furthermore, so long as the proceedings related to the Chapter 11 Case continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 Case. The Chapter 11 Case filing will also likely require us to seek debtor-in-possession financing to fund operations. If we are unable to obtain such financing on favorable terms or at all, our chances of successfully reorganizing our business may be seriously jeopardized, the likelihood that we instead will be required to liquidate our assets may be enhanced, and, as a result, any securities in the Debtor could become further devalued or become worthless.

 

Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to a plan of reorganization.  Even once a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders to do business with a company that recently emerged from Chapter 11 proceedings.

 

We may not be able to obtain confirmation of a Chapter 11 Plan of Reorganization. To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a Chapter 11 plan of reorganization, solicit and obtain the requisite acceptances of such a plan and fulfill other statutory conditions for confirmation of such a plan, which have not occurred to date.  The confirmation process is subject to numerous, unanticipated potential delays, including a delay in the Bankruptcy Court’s commencement of the confirmation hearing regarding our plan.

 

We may not receive the requisite acceptances of constituencies in the proceedings related to the Chapter 11 Case to confirm our Plan.  Even if the requisite acceptances of our Plan are received, the Bankruptcy Court may not confirm such a plan.  The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims, preferred or common stock). 

 

If a Chapter 11 plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

 

We may be subject to claims that will not be discharged in the Chapter 11 Case, which could have a material adverse effect on our results of operations and profitability. The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation and specified debts arising afterwards. With few exceptions, all claims that arose prior to March 9, 2015 and before confirmation of a plan of reorganization (i) would be subject to compromise or treatment under the plan of reorganization or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Any claims not ultimately discharged by the Bankruptcy Court could have an adverse effect on our results of operations and profitability.

 

Even if a Chapter 11 Plan of Reorganization is consummated, we will continue to face risks. Even if a Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including certain risks that are beyond our control, such as further deterioration or other changes in economic conditions, changes in our industry, potential revaluing of our assets due to Chapter 11 proceedings, changes in consumer demand for, and acceptance of, our oil and gas and increasing expenses.  Some of these concerns and effects typically become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed.  As a result of these risks and others, there is no guaranty that a Chapter 11 plan of reorganization reflecting the Plan will achieve our stated goals.

 

In addition, at the outset of the Chapter 11 Case, the Bankruptcy Code gives the Debtor the exclusive right to propose the Plan and prohibited creditors, equity security holders and others from proposing a plan.  We have currently retained the exclusive right to propose the Plan.  If the Bankruptcy Court terminates that right, however, or the exclusivity period expires, there could be a material adverse effect on our ability to achieve confirmation of the Plan in order to achieve our stated goals.

 

Furthermore, even if our debts are reduced or discharged through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the proceedings related to the Chapter 11 Case.  Adequate funds may not be available when needed or may not be available on favorable terms.

 

 
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Transfers of our equity, or issuances of equity in connection with our restructuring, may impair our ability to utilize our federal income tax net operating loss carryforwards in the future. Under federal income tax law, a corporation is generally permitted to deduct from taxable income in any year net operating losses carried forward from prior years. We have net operating loss carryforwards related to the Debtor of approximately $163.0 million as of December 31, 2014. Our ability to deduct net operating loss carryforwards will be subject to a significant limitation if we were to undergo an “ownership change” for purposes of Section 382 of the Internal Revenue Code of 1986, as amended, during or as a result of our Chapter 11 proceedings and we are unable to qualify for the exception to the carryforward limit for corporations that have changed ownership under a Chapter 11 plan. Our ability to deduct net operating loss carryforwards would be reduced by the amount of any cancellation of debt income resulting from the proposed restructuring that is allocable to the Debtor.  

 

Our financial results may be volatile and may not reflect historical trends. While in bankruptcy, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities, contract terminations and rejections, and claims assessments may significantly impact our consolidated financial statements.  As a result, our historical financial performance is likely not indicative of our financial performance after the date of the filing of the Chapter 11 Case.  In addition, if we emerge from bankruptcy, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization.  In addition, if we emerge from bankruptcy, we may be required to adopt fresh start accounting.  If fresh start accounting is applicable, our assets and liabilities will be recorded at fair value as of the fresh start reporting date.  The fair value of our assets and liabilities may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets.  In addition, if fresh start accounting is required, our financial results after the application of fresh start accounting may be different from historical trends.

 

Our successful reorganization will depend on our ability to motivate key employees and successfully implement new strategies. Our success is largely dependent on the skills, experience and efforts of our people. In particular, the successful implementation of our business plan and our ability to successfully consummate a plan of reorganization will be highly dependent upon our management. Our ability to attract, motivate and retain key employees is restricted by provisions of the Bankruptcy Code, which limit or prevent our ability to implement a retention program or take other measures intended to motivate key employees to remain with the Company during the pendency of the bankruptcy. In addition, we must obtain Bankruptcy Court approval of employment contracts and other employee compensation programs.  The loss of the services of such individuals or other key personnel could have a material adverse effect upon the implementation of our business plan, including our restructuring program, and on our ability to successfully reorganize and emerge from bankruptcy.

 

The prices of our debt and equity securities are volatile and, in connection with our reorganization, holders of our securities may receive no payment, or payment that is less than the face value or purchase price of such securities. The market price for our common stock has been volatile and our current common stock could be cancelled for no value or current stockholders could be substantially diluted under an agreement we reach with a group of our bondholders.  Prices for our debt securities are also volatile and prices for such securities have generally been substantially below par.  We can make no assurance that the price of our securities will not fluctuate or decrease substantially in the future.  See “-- Our shares are subject to risks associated with trading in an over-the-counter market” for discussion of the risks of the Debtor’s securities trading in the over-the-counter market.

 

Accordingly, trading in our securities is highly speculative and poses substantial risks to purchasers of such securities, as holders may not be able to resell such securities or, in connection with our reorganization, may receive no payment, or a payment or other consideration that is less than the par value or the purchase price of such securities.

 

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

 

Oil and natural gas prices are 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 borrowing capacity and ability to obtain additional capital on attractive terms is also dependent on oil and gas prices.

 

 
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Historically, oil and gas prices and markets have been volatile and are likely to continue to be volatile in the future. The price of oil per barrel has dropped precipitously by more than half since its high in June 2014. 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 and other assets. 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.

  

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. The quality and reliability of this data can vary which in turn can have an effect on our reserve estimations. 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 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, availability of funds 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 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.

 

 
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We have entered into a significant joint venture that 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 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. In addition, the ability or failure of us to pay for our share of the funding commitment could impair our ability to participate in the benefits of those projects and operations and may result in the loss of our rights to develop Block Z-1 with our joint operating partner. 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. At times when we have had 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.

 

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. In addition, if we are unable to fund our commitments under the joint venture with Pacific Rubiales, we could lose certain rights to develop Block Z-1. 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.

 

In addition, 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, possibly resulting in further asset impairment charges. For the year ended December 31, 2014, we incurred impairments of $58.0 million related to our power plant and related equipment, due to recent developments, including Chapter 11 reorganization, that may change the extent or manner in which the asset may be used.

 

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.

 

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.

 

 
17

 

 

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 among others:

 

 

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 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, our possible inability to raise adequate amounts of debt or equity capital to meet our development obligations 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.

 

 
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As of December 31, 2014, approximately 69% 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.

 

We may not be able to drill proved undeveloped reserve locations included in our proved oil reserves that are scheduled to be drilled five years from initial disclosure of the related reserves. We may not be able to drill proved undeveloped locations scheduled to be drilled five years after their initial disclosure. This may result from 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. 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 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.

 

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. We currently have the following convertible notes outstanding: (i) $59.9 million principal amount of the 2015 Convertible Notes, which bear interest semi-annually at a rate of 6.50% per year, and (ii) $168.7 million principal amount of the 2017 Convertible Notes, which bear interest semi-annually at a rate of 8.50% per year. The 2015 Convertible Notes matured with repayment of $59.9 million due on March 1, 2015. We exercised a provision under the indenture governing the 2015 Convertible Notes providing for a 10-day grace period on principal due and a 30-day grace period on interest due for a total amount due of approximately $62 million. The grace period on the principal amount due expired on March 10, 2015 and the grace period for interest amount due will expire on March 30, 2015. As a result of our decision to not pay the principal and interest on the 2015 Convertible Notes when due on March 1, 2015 and after exercise of the grace period until March 10, 2015, a cross default provision contained on the 2017 Convertible Notes was triggered. In addition, on March 9, 2015, the Debtor filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code, which was an event of default under the Indentures for the 2015 Convertible Notes and the 2017 Convertible Notes. Therefore all of our debt and related interest is considered due and callable once the default provisions were triggered. The ability of the holders of the 2015 Convertible Notes and the 2017 Convertible Notes to seek remedies and enforce their rights under the Indentures was automatically stayed as a result of the filing of the Chapter 11 Case, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

 

As a result of the events of default, all debt has been classified as current at December 31, 2014. In addition, our auditors have expressed substantial doubt about our ability to continue as a going concern. See the Report of Independent Registered Public Accounting Firm included under Item 8. “Financial Statements and Supplementary Data.” Our ability to meet our current and future debt obligations and other expenses will depend on the outcome of our Chapter 11 restructuring and 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 future 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.

 

 
19

 

 

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.

 

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.

 

If the net capitalized costs of our oil and natural gas properties, on a field basis, exceed the estimated undiscounted future net cash flows of that field, we must write down the costs of that field to our estimate of its fair value. Unproved properties are evaluated at the lower of cost or fair value. Accordingly, a significant decline in oil or natural gas prices or unsuccessful exploration efforts could cause a future write-down of our capitalized oil and natural gas property costs. In addition, if we are unable to find a market for gas from our onshore gas wells in Peru or no significant further activities are conducted on such wells, we may write off the costs of such wells.

 

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.

 

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. Further our insurance may not adequately cover such events to reimburse us for the losses we may incur.

 

 
20

 

 

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. Our 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 CX-11 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 our oil sales are to Petroperu, we believe that the loss of Petroperu as our sole customer would not materially impact our business because we could readily find other purchasers for our 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 we will be successful at this effort. Should we not be successful it would impact our cash flows related to oil sales.

 

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.

 

Risks Related to Our Geographic Location and Concentration.

 

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 minimum work programs in each period under the contracts, 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 Peruvian operating subsidiary that holds the license contracts has posted guaranties as required in favor of Perupetro to insure performance for the minimum work program for the applicable period under the license contracts, generally in the amount of fifty percent of the estimated value of the minimum work program for the period. BPZ Resources, Inc. has also issued a parent company guaranty as required in favor of Perupetro providing for joint and several liability to Perupetro with respect to fulfillment of such minimum work programs for the applicable periods. If we (i) fail to timely perform those activities as required, (ii) we fail to maintain valid subsidiary or parent guaranties in favor of Perupetro and do not replace the guaranty within the time allowed under the license contract or (iii) there has been a declaration of insolvency, dissolution, liquidation or bankruptcy has been pronounced of the entity that granted the guaranty and we have not provided notice to Perupetro following receipt of Perupetro’s request for a replacement guaranty, identifying the company that will assume such guaranty, once qualified and accepted by Perupetro, then our current production and sale of oil could be suspended, we could lose our rights under a particular contract and/or lose the amounts we have posted as a guaranty for the performance of such activities, which would result in a significant loss to us.

  

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.

  

 
21

 

 

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.

 

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 among others:

 

 

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 Presidential election will be held in April 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, including an interpretation that the oil period under the License Contract in Peru will not extend to the full 40 year period provided for gas operations, 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.

  

 
22

 

 

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.

 

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.

 

 
23

 

 

BPZ E&P is subject to labor and health and safety regulations and may be exposed to liabilities and potential costs for compliance. BPZ E&P is subject to Peruvian government and local labor and health and safety laws and regulations that govern, among other things, the relationship between BPZ E&P and its employees and the health and safety of BPZ E&P’s employees. For example, according to the Peruvian Safety and Health at Work Law (Ley de Seguridad y Salud en el Trabajo), Law No. 29783, BPZ E&P is required to adopt certain measures to safeguard the health and safety of its employees, as well as third parties, in its facilities. If compliance by BPZ E&P with such requirements should be reviewed by the applicable authorities and if an adverse final decision that BPZ E&P violated any labor laws, including the Peruvian Safety and Health at Work Law, should be issued in an administrative process, BPZ E&P may be exposed to penalties and sanctions, including the payment of fines and, depending on the level of severity of the infraction, exposed to the closure of its facilities and/or stoppage of its operations and the cancellation or suspension of governmental registrations, authorizations and licenses, any one of which may result in interruption or discontinuity of activities in BPZ E&P’s facilities, and materially and adversely affect BPZ E&P.

 

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 Commercial Manager who has experience related to the power generation business. 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 2017. 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:

 

 

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;

 

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.

  

 
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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 material adverse effect on our business. We are subject to 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.

 

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 compete with other companies in our industry when acquiring new leases or oil and gas properties. Competition in our business activities has increased and may 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 size and current financial status may impair our ability to compete for oil and natural gas properties and prospects.

 

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 the tax and customs office in Peru (“SUNAT”). 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.

 

 
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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.

 

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.

 

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.

 

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 deep water, and global competition for oil and gas resources make certain information more attractive to thieves.

 

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.

 

 
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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.

 

Risk Factors Related to Our Securities.

 

The market price of our common stock has been and will likely continue to be volatile. The market price of our common stock has been 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. The market price and trading volume of our stock is likely to continue to be highly volatile due to the risks and uncertainties described in this section of the Form 10-K, as well as other factors including:

 

 

actual or anticipated fluctuations in our results of operations;

 

our voluntary filing under Chapter 11 of the United States Bankruptcy Code;

 

our delisting from the NYSE;

 

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.

 

From January 1, 2014 through December 31, 2014, the closing price of our common stock as reported on the NYSE ranged from a high of $3.40 to a low of $0.17. As a result of this volatility and our recent filing under Chapter 11 of the United States Bankruptcy Code, an investment in our stock is subject to substantial risk. A plan of reorganization may result in holders of our capital stock receiving very limited or no distribution on account of their interests and cancellation of their existing stock. Furthermore, the volatility of our stock price could negatively impact our ability to raise capital in the future.

 

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.

 

 
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Our shares are subject to risks associated with trading in an over-the- counter market. On March 2, 2015, we were notified by the NYSE that the staff of NYSE Regulation, Inc. had determined to commence proceedings to delist our common stock from the NYSE. Trading of our common stock on the NYSE was suspended immediately and currently only trades in the over-the-counter market. Securities traded in the over-the-counter market generally have significantly less liquidity than securities traded on a national securities exchange, through factors such as a reduction in the number of investors that will consider investing in the securities, the number of market makers in the securities, reduction in securities analyst and news media coverage and lower market prices than might otherwise be obtained.  As a result, holders of shares of our common stock may find it difficult to resell their shares at prices quoted in the market or at all.  Furthermore, because of the limited market and generally low volume of trading in our common stock that could occur, the share price of our common stock could be more likely to be affected by broad market fluctuations, general market conditions, fluctuations in our operating results, changes in the markets perception of our business, and announcements made by us, our competitors or parties with whom we have business relationships.  With respect to the Company, in some cases, we may be subject to additional compliance requirements under applicable state laws in the issuance of our securities.  The lack of liquidity in our common stock may also make it difficult for us to issue additional securities for financing or other purposes, or to otherwise arrange for any financing we may need in the future.  In addition, we may experience other adverse effects, including, without limitation, the loss of confidence in us by current and prospective suppliers, customers, employees and others with whom we have or may seek to initiate business relationships.

 

Investor profits, if any, may be limited for the foreseeable future. In the past, we have never paid a dividend. Further we have voluntarily filed for reorganization under Chapter 11 of the Bankruptcy Code and common shareholders may receive very limited, if any amount on their investment in the event a plan of reorganization is approved by the Bankruptcy Court as such plan may not assign any equity interest to prior shareholders. We do not anticipate paying any dividends in the near future following our reorganization. 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 and are subject to the Bankruptcy Court proceedings. We have not been profitable and have accumulated a deficit of operations totaling $539.5 million through December 31, 2014.  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 can complete our reorganization and fully implement our operational plan. Accordingly we urge extreme caution in making an investment decision with respect to our securities.

 

Additional infusions of capital may have a dilutive effect on existing shareholders. We have voluntarily filed for reorganization under Chapter 11 of the Bankruptcy Code and common shareholders may receive very limited, if any amount on their investment in the event a plan of reorganization is approved by the Bankruptcy Court as such plan may not assign any equity interest to prior shareholders. Any financing received through the Chapter 11 proceedings will be senior in priority to all of our other debt and equity.   

 

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 future additional equity financing that we receive may involve substantial dilution to our then-existing shareholders. 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 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.

  

 
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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. Further we have voluntarily filed for reorganization under Chapter 11 of the Bankruptcy Code and there may be a change in control on the execution of an agreed upon plan of reorganization through the Bankruptcy Court proceeding.

 

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 6.5% of our common stock, and several institutional investors own approximately another 22.2% of our common stock, issued as of December 31, 2014.  These shareholders own in total approximately 28.7%, 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. However we have voluntarily filed for reorganization under Chapter 11 of the Bankruptcy Code and the ability of our officers, directors and institutional investors to exercise significant control over us may be significantly diminished or removed entirely through the Bankruptcy Court proceeding.

 

 

 ITEM 1B. UNRESOLVED STAFF COMMENTS

 

None. 

 

 
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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 offices and warehouse leased areas are approximately 13,700 square feet and 105,000 square feet, respectively. The administrative offices leases expire in March 2016 and 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 and an office in Victoria, Texas.

 

 
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Properties in Peru

We currently have rights to four properties in northwest Peru. We have working interests in license contracts of 51% in offshore Block Z-1, 100% in onshore Block XIX, 100% in onshore Block XXII and 100% in onshore 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.

  

 
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The following table is a summary of our properties in northwest Peru. As of December 31, 2014, 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

                20

            10.2

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

                20

            10.2



(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, 2014, 17 gross (8.7 net) wells were producing consistently and 3 gross (1.5 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 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 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.

 

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 began drilling with a new development well from the A platform in September 2013 which was completed and put into production in December 2013.

 

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. We are evaluating the options for this platform. 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.

 

 
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We have received the permit to install a platform and begin exploratory drilling in the Piedra Redonda prospect. The Piedra Redonda prospect is located south of the Corvina field. Construction of the platform began in the third quarter of 2014. In 2015 we have agreed with our Block Z-1 partner and Perupetro to delay the installation of the Piedra Redonda platform. We will be storing the platform in the Gulf Island yards in Houma, Louisiana for a period of approximately twelve to eighteen months.

 

Also, we have received the permit to install a platform and begin exploratory drilling in the Delfin prospect. The Delfin prospect is located southwest of the Corvina field. Construction of the platform began in the third quarter of 2014. In 2015 we have agreed with our Block Z-1 partner and Perupetro to delay the installation of the Delfin platform and drilling of the Delfin well. We will be storing the platform in the Gulf Island yards in Houma, Louisiana for a period of approximately twelve to eighteen months.

 

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 $0.2 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.

 

 
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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. The environmental permit for the additional seismic work was received in August 2014 following the environmental assessment process. The request for approval of the Risk Assessment and Contingency Plan is underway. The fourth exploration phase expires in September 2015.

 

As of December 31, 2014, we had a $585,000 bond posted for $176,000 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 drill exploratory wells after receipt of the necessary environmental permits. 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. Once approval is obtained, we will reestablish timelines for the remaining exploration periods. Drilling of the well in Block XXII is expected in 2016. 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 $195,000. 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. We are required to complete 678 exploration work units which will determine the number of wells drilled in the second exploration period. We spudded an exploration well, the Caracol 1X, on January 5, 2014. This was the first of three exploratory wells drilled in Block XXIII in 2014. The depth of the Caracol 1X well is approximately 3,500 feet. The Cardo 2X exploratory well was spud in late March 2014, and reached a total depth of 3,800 feet in April 2014. The Piedra Candela 3X exploratory well was spud in late April 2014 and reached a total depth of 3,515 feet in May 2014. The Caracol 1X exploratory well tested dry gas from the Mancora formation, light oil from the Heath formation and dry gas from the Zorritos formation. The Cardo 2X exploratory well and the Piedra Candela 3X exploratory well tested dry gas from the Mancora formation. We are planning to pursue a long-term testing program in these Block XXIII prospects.

 

We are working on an EIA for future exploration in this Block. A request for modifying the EIA for seismic work is under evaluation by DGAAE.

 

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 $1.0 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.

 

 
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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 “We may not be able to drill proved undeveloped reserve locations included in our proved oil reserves that are scheduled to be drilled five years from initial disclosure of the related reserves.” 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, 2014, 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.

 

Net Proved Crude Oil Reserves and Future Net Cash Flows

As of December 31, 2014

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

 

 

   

Actual

   

Estimated

Future Capital

Expenditures

 
   

(In MBbls)

   

(In thousands)

 

Proved Developed Producing

    3,888     $ -  

Proved Developed Not Producing

    317       -  

Proved Undeveloped

    9,361       128,128  

Total

    13,566     $ 128,128  
                 

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

  $ 416,798          

 

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.

 

Our Vice President of Operations is responsible for the reserves recorded and utilizes the reserves estimates made by our third party reserve consultant, NSAI, for the preparation of our reserve report.  Our Vice President of Operations has over 30 years of experience in the oil and gas industry, including over 25 years working with Occidental Petroleum in various roles, more recently as Vice President & General Manager for Bolivian operations.  Our Vice President of Operations international career includes operational leadership roles in Ecuador, Colombia, Syria, Oman, Yemen, China, and Bangladesh.  He holds a Bachelor's degree in Petroleum Engineering and a MBA from the University of Texas, in Austin, Texas.

 

 
36

 

 

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. 

 

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, 2014, we had net proved oil reserves of 13.6 MMBbls which represents a decrease from the net proved oil reserves at December 31, 2013 of 16.1 MMBbls.   The net proved oil reserves associated with proved developed producing wells increased by 0.7 MMBbls to 3.9 MMBbls in 2014 from 3.2 MMBbls in 2013. Proved developed non–producing reserves increased 0.3 MMBbls to 0.3 MMBbls in 2014 from zero in 2013. The net oil reserves associated with proved undeveloped areas decreased by 3.5 MMBbls to 9.4 MMBbls at December 31, 2014 from 12.9 MMBbls in 2013.

 

 
37

 

  

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

 

As of December 31, 2014, 9.4 MMBbls of PUDs were reported, a decrease of 3.5 MMBbls from December 2013. The following table shows changes in the PUDs for 2014:

 

   

MBbls

 
         

PUDs at January 1, 2014

    12,915  

Revisions of previous estimates

    (1,572 )

Purchases of minerals in place

    -  

Extensions, discoveries and other additions

    2,157  

Sales of reserves in place

    -  

Conversion to proved developed reserves

    (4,139 )
         

PUDs at December 31, 2014

    9,361  

 

In 2014, we had negative revisions to PUDs of 1.4 MMBbls from previous estimates due to performance revisions for the Corvina field.

 

In 2014, we converted 4.1 MMBbls, or 31.8% of total year-end 2013 PUDs to developed status. As of December 31, 2014, we had a total quantity of 19 PUD locations contributing 9.4 MMBbls to our 2014 proved oil reserves.  Of the total 19 PUDs, 13 PUDs are associated with the Corvina field and 6 PUD locations are associated with the Albacora field. Costs incurred to advance the development of PUDs associated with Block Z-1 in 2014 were approximately $127.2 million, of which $124.6 million was funded by our partner in Block Z-1, Pacific Rubiales.  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 reimbursed by Pacific Rubiales include the Pacific Rubiales 49% participating interest. As a 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,  at December 31, 2013, certain PUD locations in Corvina field were included as proved oil reserves that were scheduled to be drilled five years after initial disclosure. In 2014, we completed nine development wells in the Corvina and Albacora fields and converted 31.8% of our 2013 PUD MMBbls to proved developed reserves. The drilling rig is in place and we plan to continue to drill to convert the PUDs. For 2015 we have wells that will be drilled five years after the initial disclosure, the timing of the development of these wells has been changed in conjunction with a shared development plan with our partner in Block Z-1. This shared development plan is not the same drilling plan we initially adopted when we were the sole operator of the Corvina and Albacora fields.  The current development plan would result in all PUDs being drilled by 2017.

 

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.

  

 

                   

Average

 
   

Sales (1)

   

Average Sales

   

Production

 
   

Volumes (MBbls)

   

Price

   

Cost (2)

 
                         

2014

    923.7     $ 90.36     $ 30.93  

2013

    506.9     $ 99.79     $ 49.11  

2012

    1,187.8     $ 103.31     $ 44.16  

 

(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.


 
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Acreage; Productive Wells

 

The following table shows the approximate number of developed and undeveloped acres as of December 31, 2014:

 

   

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, 2014, 2013 and 2012 were 20.0 gross (10.2 net), 13.0 gross (6.6 net) and 11.0 gross (5.6 net), respectively.

 

Drilling Activity

 

The number of gross and net productive oil wells drilled in 2014, 2013 and 2012 were 9.0 gross (4.6 net) 2.0 gross (1.0 net) and none, respectively. We drilled three exploratory wells (gross and net) in 2014, the Caracol 1X, the Cardo 2X and the Piedra Candela 3X in Block XXIII, and we plan to pursue a long-term testing program in theses Block XXIII prospects. We did not drill any exploratory wells or have any dry holes in 2013 or 2012. The following lists our successful development wells that were drilled during the year ended December 31, 2014:

 

Field and Well    Exploratory/Development   

Drilling Depth

(feet)

 

Date Objective
Drilled/Tested/Completed 

Corvina - CX15-2D

 

Development

 

8,767

 

1st quarter

Albacora - A-19D

 

Development

 

12,450

 

1st quarter

Corvina - CX15-3D

 

Development

 

7,735

 

2nd quarter

Albacora - A-21D

 

Development

 

12,530

 

2nd quarter

Corvina - CX15-5D

 

Development

 

8,500

 

3rd quarter

Corvina - CX15-7D

 

Development

 

8,314

 

3rd quarter

Albacora - A-26D

 

Development

 

12,700

 

3rd quarter

Corvina - CX15-10D

 

Development

 

8,038

 

4th quarter

Corvina - CX15-14D

 

Development

 

7,845

 

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

 

 
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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, 2014:

 

 

Wells in process

of drilling or

in active completion

 

Wells suspended or

waiting on completion

 

Exploration

 

Development (1)

 

Exploration (2)

 

Development

Gross

                  -

 

                         2.0

 

                    4.0

 

                     -

Net

                  -

 

                         1.0

 

                    3.5

 

                     -

 

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

 

(1) Represents the CX15-8D well and the A-27D well.

 

(2) Represents the CX11-16X well in Block Z-1, the Caracol 1X well, the Cardo 2X well and the Piedra Candela 3X well in Block XXIII.

 

2015 Activities

 

Block Z-1

 

Corvina Field

 

We spudded the CX15-8D development well in December 2014 and production began in February 2015. We spudded the CX15-9D development well in February 2015.

 

 

Albacora Field

 

We spudded the A-27D development well in October 2014 and production began in January 2015. The A-22D development well was spudded in January 2015.     

 

Delfin Prospect

 

We have received the permit to install a platform and begin exploratory drilling in the Delfin prospect. Construction of the platform began in the third quarter of 2014. In 2015 we have agreed with our Block Z-1 partner and Perupetro to delay the installation of the Delfin platform and drilling of the Delfin well. We will be storing the platform in the Gulf Island yards in Houma, Louisiana for a period of approximately twelve to eighteen months.

 

Piedra Redonda Prospect

 

We have received the permit to install a platform and begin exploratory drilling in the Piedra Redonda prospect. Construction of the platform began in the third quarter of 2014. In 2015 we have agreed with our Block Z-1 partner and Perupetro to delay the installation of the Piedra Redonda platform. We will be storing the platform in the Gulf Island yards in Houma, Louisiana for a period of approximately twelve to eighteen months.

 

Block Z-1 Seismic

 

The joint 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 permit for the additional seismic work was received in August 2014 following the environmental assessment process. The request for approval of the Risk Assessment and Contingency Plan is underway.

  

 
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Block XXII

 

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 2016.

 

Block XXIII

 

We spudded an exploration well, the Caracol 1X, on January 5, 2014. This was the first of three exploratory wells drilled in Block XXIII in 2014. The depth of the Caracol 1X well is approximately 3,500 feet. The Cardo 2X exploratory well was spud in late March 2014, and reached a total depth of 3,800 feet in April 2014. The Piedra Candela 3X exploratory well was spud in late April 2014 and reached a total depth of 3,515 feet in May 2014. The Caracol 1X exploratory well tested dry gas from the Mancora formation, light oil from the Heath formation and dry gas from the Zorritos formation. The Cardo 2X exploratory well and the Piedra Candela 3X exploratory well tested dry gas from the Mancora formation. We are planning to pursue a long-term testing program in these Block XXIII prospects.

 

We are working on an EIA for future exploration in this Block. A request for modifying the EIA for seismic work is under evaluation by DGAAE.

 

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 in the fourth quarter of 2013.

 

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, in order to extend the term of the contract from 2016 to 2029, the Consortium, which includes us and three other partners, 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 $4.8 million (our 10% non-operating net profits interest) which amount is due throughout the period of 2015 through 2028. This commitment is expected to be funded by cash on hand, cash generated from new production, or loans of the Consortium. If the Consortium does not have sufficient cash on hand, we may elect to make a cash contribution to the Consortium 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 for the Santa Elena field.

 

In the fourth quarter of 2014, the Consortium incurred a loan for the additional work commitments to increase production in the Santa Elena field. The Consortium loan is to be paid with cash generated from the production of the Santa Elena Field. Our total share of this loan would be $1.0 million (our 10% non-operating net profits interest) which amounts are due quarterly through the fourth quarter of 2017. If the Consortium does not have sufficient cash on hand, we would make a cash contribution to the Consortium for our 10% share of this loan.

 

ITEM 3. LEGAL PROCEEDINGS 

 

Legal Proceedings Related to the Chapter 11 Case

 

On March 9, 2015, BPZ Resources, Inc. filed a voluntary petition in the United States Bankruptcy Court for the Southern District of Texas Victoria Division (the “Bankruptcy Court”) seeking relief under the provisions of Chapter 11 of Title 11 of the United States Bankruptcy Code (the “Bankruptcy Code”). The Chapter 11 case is being administered under the caption In re BPZ Resources, Inc., Case No. 15-60016 (the “Chapter 11 Case”). The Company will continue to operate its business as “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As a result of the filing, attempts to collect, secure, or enforce remedies with respect to pre-petition claims against the Company are subject to the automatic stay provisions of section 362 of the Bankruptcy Code.  None of the Company’s direct or indirect subsidiaries has filed for reorganization under Chapter 11 and none are expected to file for reorganization or protection from creditors under any insolvency or similar law in the U.S. or elsewhere. The Chapter 11 Case is discussed in greater detail in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Voluntary Reorganization Under Chapter 11” and Item 8. “Financial Statements and Supplementary Data,” Note-2 “Liquidity and Capital Resources” to our Consolidated Financial Statements included herein.

 

 
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Other 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.” However, on March 2, 2015, we were notified by the NYSE that the staff of NYSE Regulation, Inc. (“NYSE Regulation”) had determined to commence proceedings to delist our common stock from the NYSE, as our share price was “abnormally low” pursuant to Section 802.01D of the NYSE Listed Company Manual. Trading of our common stock on the NYSE was suspended immediately. From March 3, 2015 through March 11, 2015, the Company traded under the symbol “BPZR,” Currently, the Company is traded under the symbol “BPZRQ.”

 

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

 
                 

2014

               

Fourth quarter

  $ 1.92     $ 0.17  

Third quarter

    3.23       1.91  

Second quarter

    3.40       2.42  

First quarter

    3.20       1.76  
                 

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  

 

 

Holders

 

As of February 28, 2015, we had approximately 120 shareholders of record, and an estimated 12,000 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-14 — “Stockholders’ Equity” of the Notes to Consolidated Financial Statements in Item 8 herein.

 

 
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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, 2009 in our Common Stock, the Russell 2000 Stock Index and the Peer Group Composite.

 

   

2009

   

2010

   

2011

   

2012

   

2013

   

2014

 

BPZ Resources, Inc.

  $ 100     $ 50     $ 30     $ 33     $ 19     $ 3  

Russell 2000 Stock Index

    100       125       118       136       186       193  

Peer Group Composite

    100       171       178       95       99       64  

 
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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:

 

2014

   

2013

   

2012

   

2011

   

2010

 
   

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

 

Total net revenue

  $ 83,897     $ 50,729     $ 122,958     $ 143,740     $ 110,464  
                                         

Operating and administrative expenses:

                                       

Lease operating expense

    28,571       24,893       52,458       50,792       32,585  

General and administrative expense

    23,730       24,111       28,705       34,998       32,444  

Geological, geophysical and engineering expense

    3,773       2,184       43,787       12,917       19,318  

Dry hole costs

    -       -       -       13,082       32,778  

Depreciation, depletion and amortization expense

    23,221       27,214       45,873       38,944       33,755  

Standby costs

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

Other operating expense

    4,277       4,430       2,266       -       12,889  

Asset impairments

    58,000       -       -       -       -  

Gain on divestiture

    -       -       (26,864 )     -       -  
                                         

Total operating and administrative expenses

    141,572       87,143       151,565       155,262       171,256  
                                         

Operating loss

    (57,675 )     (36,414 )     (28,607 )     (11,522 )     (60,792 )
                                         

Other income (expense):

                                       

Income from investment in Ecuador property, net

    217       152       62       412       740  

Interest expense

    (18,670 )     (16,158 )     (16,115 )     (19,772 )     (11,618 )

Loss on extinguishment of debt

    (1,245 )     (7,222 )     (7,318 )     -       -  

Gain (loss) on derivatives

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

Interest income

    790       182       44       453       272  

Other income (expense)

    (351 )     (4,268 )     (159 )     1,083       19  
                                         

Total other expense

    (19,257 )     (27,072 )     (26,096 )     (19,870 )     (10,587 )
                                         

Loss before income taxes

    (76,932 )     (63,486 )     (54,703 )     (31,392 )     (71,379 )

Income tax expense (benefit)

    30,974       (5,775 )     (15,614 )     2,435       (11,608 )

Net loss

  $ (107,906 )   $ (57,711 )   $ (39,089 )   $ (33,827 )   $ (59,771 )

Basic and diluted net loss per share

  $ (0.93 )   $ (0.50 )   $ (0.34 )   $ (0.29 )   $ (0.52 )

Basic and diluted weighted average common shares outstanding

    116,311       115,943       115,631       115,367       114,919  
                                         

Oil sales price per barrel, net

  $ 90.36     $ 99.79     $ 103.31     $ 101.01     $ 72.53  

Operating cost per barrel

  $ 30.93     $ 49.11     $ 44.16     $ 36.82     $ 21.47  
                                         

Balance Sheet Data:

                                       

Working Capital/(Deficit)

  $ (166,100 )   $ 71,670     $ 58,839     $ 49,180     $ 22,703  

Property, equipment and construction in progress, net

    165,971       217,753       238,557       381,602       342,507  

Total assets

    291,360       406,749       527,430       537,333       470,307  

Current maturity of long-term debt

    214,312       -       24,046       16,854       4,180  

Total long-term debt

    -       206,939       197,160       248,384       156,750  

Stockholders' equity

    33,398       137,475       186,300       222,452       251,326  
                                         

Cash Flow Data:

                                       

Cash flow provided by (used in) operating activites

    31,195       (52,627 )     (46,062 )     47,121       (5,125 )

Cash flow provided by (used in) investing activities

    (26,283 )     53,968       (65,838 )     (93,883 )     (158,104 )

Cash flow provided by (used in) financing activities

    (158 )     (27,486 )     137,268       93,182       156,834  

 

 
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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.

 

Introduction

 

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 may be wholly– owned or partially-owned, or may be wholly-owned by a third party. 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 Ecuador.

 

Voluntary Reorganization Under Chapter 11

 

We have not been profitable since we commenced operations and we require substantial capital expenditures as we advance development projects at Block Z-1 and exploration projects in our other Blocks. Currently, we require additional financing to continue to fund our capital expenditure program and implement our business plan. Our major sources of funding to date have been oil sales, equity and debt financing activities and asset sales.  The increased capital costs and debt service costs in the current economic environment for the oil and gas industry have placed a strain on our cash flow from operations and our ability to reduce our debt leverage.

 

We currently have the following convertible notes outstanding: (i) $59.9 million principal amount of Convertible Notes due 2015 (the “2015 Convertible Notes”), which bear interest semi-annually at a rate of 6.50% per year, and (ii) $168.7 million principal amount of Convertible Notes due 2017 (the “2017 Convertible Notes”), which bear interest semi-annually at a rate of 8.50% per year. The 2015 Convertible Notes matured with repayment of approximately $62 million in principal and interest due on March 1, 2015. Our estimated capital and exploratory budget for 2015 calls for us to spend approximately $58.6 million in 2015 on capital and exploratory expenditures, excluding capitalized interest, for our three onshore Blocks in which we hold 100% working interests, and our share of the capital and exploratory expenditures for offshore Block Z-1 required under our Joint Venture Agreement with Pacific Rubiales. The carry amount Pacific Rubiales agreed to pay under the joint venture was completed in December 2014 and we are now responsible for funding our full share of capital expenditures and joint operating expenditures for Block Z-1.

 

The price of oil per barrel has dropped dramatically, particularly in the fourth quarter 2014 and continuing in the first quarter 2015, by more than half since its high in June 2014. In mid-October 2014, we withdrew our previously announced private placement offer of $150.0 million in senior secured notes due 2019 due to adverse market conditions.

 

On December 8, 2014, the Company received a notification from the New York Stock Exchange (“NYSE”) that the Company had fallen below the NYSE's continued listing standard relating to minimum share price, which requires a minimum average closing price of $1.00 per share over 30 consecutive trading days. The price has remained well below such threshold and the NYSE subsequently notified us on March 2, 2015 that it had determined to commence proceedings to delist our common stock.

 

As a result of the aforementioned events and circumstances, in December 2014 we engaged the services of Houlihan Lokey Capital Inc. (the “Advisors”) to assist us in analyzing various strategic alternatives and addressing our liquidity and capital structure, and formed a special committee of the Board of Directors to work with the Advisors. We engaged in discussions with representatives of our various debt holders regarding, among other items, the potential terms under which one or both bond issues could be restructured to provide a capital structure which would allow us to continue developing our oil and gas assets.  We have also pursued discussions with other potential investors regarding alternative financing solutions.  We decided that it was in the best long-term interest of all stakeholders, both credit and equity holders, to expeditiously address the Company's capital structure with the goal of reducing debt and the cost of capital to position the Company for the future, and on March 2, 2015 announced that we had decided not to pay approximately $62 million in principal and interest due on March 1, 2015 on our 2015 Convertible Notes and to use a 10-day grace period on principal due and a 30-day grace period on interest due to continue discussions with our debt holders.

 

 
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We were unable to reach a mutually agreeable solution within the grace period for the principal amount due on the 2015 Convertible Notes and elected not to make the approximate $59.9 million in principal payment due at the end of the grace period for principal due. As a result, we are in default under the 2015 Convertible Notes, permitting the trustee for the 2015 Convertible Notes or the holders of at least 25% in aggregate principal amount of the outstanding 2015 Convertible Notes to declare the full amount of the principal and interest thereunder immediately due and payable. If the 2015 Convertible Notes were to be accelerated, an event of default would occur under the indenture for the 2017 Convertible Notes, permitting the trustee or the holders of at least 25% in aggregate principal amount of the outstanding 2017 Convertible Notes to also declare the full amount of the principal and interest thereunder immediately due and payable.

 

On March 9, 2015 (the “Petition Date”), BPZ Resources, Inc. (the “Debtor”) filed a voluntary petition for reorganization relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) to provide more time to find an appropriate solution to its financial situation and implement a plan of reorganization aimed at improving its capital structure. The Chapter 11 case is being administered by the Bankruptcy Court as Case No. 15-60016.

 

The filing of the Chapter 11 case constituted an event of default that triggered repayment obligations under the 2015 Convertible Notes and the 2017 Convertible Notes. The ability of the holders of the 2015 Convertible Notes and the 2017 Convertible Notes to seek remedies and enforce their rights under the indentures was automatically stayed as a result of the filing of the Chapter 11 case, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

 

Since the Petition Date, the Debtor has operated its business as a “debtor-in-possession” pursuant to Sections 1107(a) and 1108 of the Bankruptcy Code, which will allow the Debtor to continue operations during the reorganization proceedings.  The Debtor will remain in possession of its assets and properties, and its business and affairs will continue to be managed by its directors and officers, subject in each case to the supervision of the Bankruptcy Court. 

 

None of the Debtor’s direct or indirect subsidiaries or affiliates has filed for reorganization under Chapter 11 and none is expected to file for reorganization or protection from creditors under any insolvency or similar law in the U.S. or elsewhere. The Debtor’s subsidiaries will continue to operate outside of any reorganization proceedings. We therefore do not expect the Debtor’s filing for Chapter 11 protection to impact our license agreements.

 

On the day after the Petition Date, the Debtor obtained approval from the Bankruptcy Court for a variety of “first day” motions to give the Debtor the authority to take a broad range of actions, including, among others, authority to maintain bank accounts and the cash management system, pay certain employee obligations, post-petitition utilities and other customary relief.

 

Overview

 

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

 

 

At Block Z-1 with our joint venture partner, Pacific Rubiales;

 

 

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

 

 

Optimizing oil production in the Corvina and Albacora fields in Block Z-1;

 

 

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

 

 

Exploring the remainder of the Block, starting with the Delfin and Piedra Redonda prospects where we have received the permits to install platforms and begin exploratory drilling;

 

 

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

 

 

Executing a testing program of our gas discovery in Block XXIII, and planning a drilling program if the testing program warrants;

 

 

Planning and permitting an onshore 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.

  

 
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Our activities in Peru include analysis and evaluation of technical data on our properties, preparation of the exploration and 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.

 

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.

 

Further, our ability to produce reserves in the Corvina and Albacora fields 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 reserves and their value as reported under the Securities and Exchange Commission (“SEC”) rules. 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.

 

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 (in three two-year periods). 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 phase in Block Z-1 which requires one exploration well or 225 exploration work units in each of the three two-year periods. We received approval from Perupetro for the initial two-year period and have committed to drill an exploratory well. The initial two-year phase was originally set to expire in January 2015, but has been extended to July 2015. At the end of the third two-year period, we will be required by the License Contract to surrender back to Perupetro all unexplored areas 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 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 operation 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.

 

 
48

 

 

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.

 

The carry amount Pacific Rubiales agreed to pay under the joint venture was completed in December 2014 and we are now responsible for funding our full share of capital expenditures and joint operating expenditures for Block Z-1.

 

At December 31, 2013, the carry amount was $81.3 million.

 

At December 31, 2014 and December 31, 2013, we reflected $22.5 million and $23.9 million, respectively, as other current liabilities and zero and $16.8 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 is being settled by us and Pacific Rubiales under the terms of the SPA with cash payments under the liability of $14.4 million occurring in 2014.

 

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, 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 by 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 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. We made modifications to the platform monitoring and control systems to facilitate operation of the CX-15 platform. Equipment is tracking platform response to weather and ocean conditions as well as draft. As a precaution, we installed an anchoring system 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 CX-15 platform. Production from the CX15-1D well began in October 2013. In September 2014, the CX15-1D well was shut in due to sand intrusion. The well was then evaluated to determine the appropriate work plan. A workover will be scheduled for this well. We spudded the second development well, the CX15-2D, in November 2013. The CX15-2D 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 development well in February 2014 and production began in April 2014. In July 2014, the CX-15-3D well was shut in due to high water production. The well was then evaluated to determine the appropriate work plan. The CX15-3D well returned to production in September 2014. We spudded the CX15-5D development well in April 2014 and production began in July 2014. The CX15-7D development well was spudded in July 2014 and production began in September 2014. The CX15-10D development well was spudded in September 2014 and production began in October 2014. The CX15-14D development well was spudded in October 2014 and production began in December 2014. The CX15-8D development well was spudded in December 2014 and production began in February 2015. The CX15-9D development well was spud in February 2015.

  

 
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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 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 and in Albacora 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 in our public filings pursuant to SEC requirements. 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 nine gross (4.6 net) oil wells, two of which are currently being used as a gas injection or a 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. The A-18D well, which began producing at the end of 2013, was shut-in in late March 2014 due to gas intrusion. The well was sidetracked to a depth of 12,800 feet. The A-18D side track well was completed in September 2014 and production began in September 2014. 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 A-19D well began production on March 1, 2014. The A-21D development well was spud in early March 2014 and production began in May 2014. In July 2014, the A-21D well was shut in due to high water production. The well was then evaluated to determine the appropriate work plan. The A-21D well returned to production in September 2014. We spudded the A-26D development well in May 2014 and production began in July 2014. The A-27D development well was spudded in October 2014 and production began in January 2015. The A-22D development well was spudded in January 2015.

 

Piedra Redonda Prospect 

 

We have received the permit to install a platform and begin exploratory drilling in the Piedra Redonda prospect. The Piedra Redonda prospect is located south of the Corvina field. Construction of the platform began in the third quarter of 2014.

 

In 2015 we have agreed with our Block Z-1 partner and Perupetro to delay the installation of the Piedra Redonda platform. We will be storing the platform in the Gulf Island yards in Houma, Louisiana for a period of approximately twelve to eighteen months.

 

Delfin Prospect 

 

Also, we have received the permit to install a platform and begin exploratory drilling in the Delfin prospect. The Delfin prospect is located southwest of the Corvina field. Construction of the platform began in the third quarter of 2014.

 

In 2015 we have agreed with our Block Z-1 partner and Perupetro to delay the installation of the Delfin platform and drilling of the Delfin well. We will be storing the platform in the Gulf Island yards in Houma, Louisiana for a period of approximately twelve to eighteen months.

 

 
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Block Z-1 Seismic

 

We completed the 3-D seismic survey in February 2013 and seismic data processing of the area in September 2013 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.

 

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

 

Block XIX

 

We are in the fourth exploration period in Block XIX which requires 117 exploration work units which will determine our exploration commitment for the period. The fourth exploration period expires in September 2015.

 

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 permit for the additional seismic work was received in August 2014 following the environmental assessment process. The Risk Assessment and Contingency Plan has been submitted to the DGAAE for approval.

 

Block XXII

 

We are in the second exploration period in Block XXII which requires the drilling of one exploration well.

 

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 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 has been submitted to the DGAAE, and subsequent receipt of the necessary ancillary permits. Drilling in Block XXII is expected in 2016.

 

Block XXIII

 

We are in the second exploration period in Block XXIII which requires 678 exploration work units which will determine the number of wells drilled.

 

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 received approval to move the previously agreed drilling locations to conform to the 3-D seismic results.

 

We spudded an exploration well, the Caracol 1X, on January 5, 2014. This was the first of three exploratory wells drilled in Block XXIII in 2014. The depth of the Caracol 1X well is approximately 3,500 feet. The Cardo 2X exploratory well was spud in late March 2014, and reached a total depth of 3,800 feet in April 2014. The Piedra Candela 3X exploratory well was spud in late April 2014 and reached a total depth of 3,515 feet in May 2014. The Caracol 1X exploratory well tested dry gas from the Mancora formation, light oil from the Heath formation and dry gas from the Zorritos formation. The Cardo 2X exploratory well and the Piedra Candela 3X exploratory well tested dry gas from the Mancora formation. We are planning to pursue a long-term testing program in these Block XXIII prospects.

 

Marine Operations

 

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 Peru S.R.L. employees to the new operator in the fourth quarter of 2013.

 

 
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Gas-to-Power Project

 

Our gas-to-power project entails the planned installation of approximately 10-miles of 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.

 

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 principal amount 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 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. In April 2014, $26.0 million of the aggregate principal amount of the 2015 Convertible Notes were exchanged for an additional $25.0 million aggregate principal amount of 2017 Convertible Notes in a private transaction. As a result, we have $168.7 million principal amount of 2017 Convertible Notes outstanding at December 31, 2014.

 

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 the $168.7 million principal amount (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 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 principal amount 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 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 aggregate principal amount of the $170.9 million of the 2015 Convertible Notes leaving a principal balance of $85.9 million of the 2015 Convertible Notes outstanding. In April 2014, $26.0 million of the aggregate principal amount of the 2015 Convertible Notes were exchanged for an additional $25.0 million aggregate principal amount of 2017 Convertible Notes in a private transaction. As a result, we have $59.9 million principal amount of 2015 Convertible Notes outstanding at December 31, 2014.

 

 
52

 

 

For further information regarding the 2015 Convertible Notes 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 license contracts. The world economies are continuing on the path to recovery, though at a gradual pace, with a number of regions in the world showing mixed results. Growth has resumed, but is modest and the downside risks remain significant.  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 oil production capacity of Saudi Arabia, and their desire to maintain market share, is a factor influencing the global price of oil. In addition, new North American supply increases have driven down the U.S. crude imports. The impact of a continued increase of U.S. crude oil production will also contribute to putting pressure on global oil prices. The U.S. Energy Information Administration estimates that in 2014 the increase in the global supply of petroleum and other liquid fuels was nearly twice the increase in consumption, leading to lower prices and shrinking profits for oil producers. However, Peru continues to be a net importer of oil.

 

In response to our current economic environment, for 2015, we will continue to focus on oil development and exploration in Block Z-1 with our Block Z-1 partner, specifically development in the Corvina and Albacora fields and preparing for exploration in the Delfin and Piedra Redonda prospects, as well as onshore drilling campaigns to explore and appraise our other Blocks, as our available funds allow.

 

From a production perspective, our goal is to increase production during 2015 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 2015 capital expenditures budget. In addition, we will continue to evaluate our options on additional financing as needed taking into consideration our current reorganization of BPZ Resources, Inc. under Chapter 11 of the U.S. Bankruptcy Code. We anticipate future results will be based on our production levels, current and future oil prices and the outcome of the reorganization. When forecasting our 2015 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.

 

 
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Results of Operations

 

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

 

   

Year Ended

         
   

December 31,

         
   

2014

   

2013

   

Increase/

(Decrease)

 

Net sales volume:

 

(in thousands except per bbl information)

         

Oil (MBbls)

    924       507       417  
                         

Net revenue:

                       

Oil revenue, net

  $ 83,464     $ 50,585     $ 32,879  

Other revenue

    433       144       289  

Total net revenue

    83,897       50,729       33,168  
                         

Average sales price (approximately):

                       

Oil (per Bbl)

  $ 90.36     $ 99.79     $ (9.43 )
                         

Operating and administrative expenses:

                       

Lease operating expense

    28,571       24,893       3,678  

General and administrative expense

    23,730       24,111       (381 )

Geological, geophysical and engineering expense

    3,773       2,184       1,589  

Depreciation, depletion and amortization expense

    23,221       27,214       (3,993 )

Standby costs

    -       4,311       (4,311 )

Other operating expense

    4,277       4,430       (153 )

Asset impairments

    58,000       -       58,000  

Total operating and administrative expenses

  $ 141,572     $ 87,143     $ 54,429  
                         

Operating loss

  $ (57,675 )   $ (36,414 )   $ (21,261 )

 

Net Oil Revenue

 

For the year ended December 31, 2014, our net oil revenue increased by $32.9 million to $83.5 million from $50.6 million for the same period in 2013. The increase in net oil revenue is due to an increase in the amount of oil sold of 417 MBbls, partially offset by a decrease of $9.43, or 9.4%, in the average per barrel sales price received. Total sales for the year ended December 31, 2014 were 924 MBbls compared to 507 MBbls for the same period in 2013.

 

The increase in amount of oil sold for the year ended December 31, 2014 compared to the same period in 2013 is due to increased production in the Albacora field from the A-18D, A-19D, A-21D and A-26D wells and increased production from the CX-15 platform from the CX15-1D, CX15-2D, CX15-3D, CX15-5D, CX15-7D, CX15-10D and CX15-14D wells. We expect net oil revenues to decrease in 2015 from lower crude oil prices in 2015 compared to 2014 despite increased sales volumes from our development drilling program in Block Z-1 that began in the second half of 2013.

 

The 2014 price/volume analysis is as follows:

 

   

(in thousands)

 

2013 Oil revenue, net

  $ 50,585  

Changes associated with sales volumes

    41,595  

Changes associated with prices

    (8,716 )

2014 Oil revenue, net

  $ 83,464  

 

For the year ended December 31, 2014, the increase in oil production is due to increased production in the Albacora field as the A-18D, A-19D, A-21D and A-26D wells contributed to production volumes during 2014. At the Corvina field, the declines in production from the wells at the CX-11 platform were more than offset by the new production from the CX-15 platform’s CX15-1D, CX15-2D, CX15-3D, CX15-5D, CX15-7D, CX15-10D and CX15-14D wells. Total oil production for the year ended December 31, 2014 was 941 MBbls compared to 514 MBbls for the same period in 2013.

 

 
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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, 2014 and 2013:

 

   

2014

   

2013

 
   

(in thousands)

 

Royalty costs

  $ 4,674     $ 2,707  
    $ 4,674     $ 2,707  

 

Other Revenue

 

For the year ended December 31, 2014, other revenue increased $289,000 to $433,000 from $144,000 for the same period in 2013.

 

During the year ended December 31, 2014 and December 31, 2013, we recognized other revenue associated with the chartering of support vessels.

 

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, 2014, lease operating expenses increased by $3.6 million to $28.6 million ($30.93 per Bbl) from $25.0 million ($49.11 per Bbl) for the same period in 2013. The increase of $3.6 million is due to higher crude oil transportation expense of $6.7 million resulting from higher crude oil sales, higher fuel costs of $2.3 million and higher supply costs of $1.1 million due to increased activity in the Corvina and Albacora fields, partially offset by workover expenses decreasing $5.3 million due to no major workovers performed in 2014 compared to one major workover in 2013, lower costs of $1.0 million associated with the change in oil inventory for the year ended December 31, 2014 compared to the change in oil inventory for the year ended December 31, 2013, and lower other lease operating expenses of $0.2 million. We expect lease operating expense to increase in 2015 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.

 

For the year ended December 31, 2014, general and administrative expenses decreased by $0.4 million to $23.7 million from $24.1 million for the same period in 2013.  Stock-based compensation expense, a subset of general and administrative expenses, was $3.2 million for the year ended December 31, 2014 and $2.8 million for the same period in 2013. Other general and administrative expenses decreased $0.8 million to $20.5 million for the year ended December 31, 2014 compared to $21.3 million for the same period in 2013. The $0.8 million decrease is due to lower salary and related costs of $2.9 million due to fewer employees and lower other general and administrative expenses of $0.6 million, partially offset by a $1.4 million increase due to higher indirect charges from our Block Z-1 partner and a higher ship management fee of $1.3 million. We expect our 2015 general and administrative expenses to be lower than our 2014 general and administrative expenses given our cost reduction efforts put in to place under a lower crude oil price scenario.

 

Geological, Geophysical and Engineering Expense

 

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

 

 
55

 

 

For the year ended December 31, 2014, geological, geophysical and engineering expenses increased $1.6 million to $3.8 million compared to $2.2 million for the same period in 2013. This increase is due to higher consulting, salaries and software costs.

 

Our share of the 2014 and 2013 Block Z-1 exploratory expenditures was fully funded by our partner under the carry agreement in place.

 

We expect our 2015 geological, geophysical and engineering expense to decrease compared to our 2014 geological, geophysical and engineering expense for Blocks Z-1, XIX, XXII and XXIII as we work to contain all costs under the lower crude oil price environment.

 

Dry Hole Costs

 

There were no dry hole costs for the year ended December 31, 2014 or December 31, 2013.

 

Depreciation, Depletion and Amortization Expense

 

For the year ended December 31, 2014, depreciation, depletion and amortization expense decreased $4.0 million to $23.2 million from $27.2 million for the same period in 2013. We expect depreciation, depletion and amortization expense in 2015 to decrease from depreciation, depletion and amortization expense in 2014.

 

For the year ended December 31, 2014, depletion expense decreased $3.2 million to $14.8 million from $18.0 million during the same period in 2013. Depletion decreased in both periods due to capital costs in Block Z-1 reimbursed under the Carry Agreement with Pacific Rubiales and reserves added to the depletion base in 2014.

 

For the year ended December 31, 2014, depreciation expense decreased $0.8 million to $8.4 million compared to $9.2 million for the same period in 2013.

 

Standby Costs

 

For the year ended December 31, 2014, we incurred no 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.

 

In 2015 we have agreed with our Block Z-1 partner and Perupetro to delay the installation of the Delfin and Piedra Redonda platforms and drilling of the Delfin well. We will be storing the platforms in the Gulf Island yards in Houma, Louisiana for a period of approximately twelve to eighteen months. We will incur preparation, storage, and other charges of approximately $3.0 million to $4.0 million for our share of these costs in 2015.

 

Other Operating Expense

 

For the year ended December 31, 2014, we reported $4.3 million of charges in the Consolidated Statements of Operations as “Other operating expense.” We expensed these previously capitalized amounts related to marine operations, a drilling site location and certain equipment and associated capitalized interest as we do not see a future economic benefit in these costs.

 

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.

 

Asset Impairments

 

For the year ended December 31, 2014, we incurred impairments of $58.0 million related to our power plant and related equipment, using a fair value approach. Using a probability weighted income approach of different courses of action available to us for use of the power plant and related equipment to determine fair value, the assets were impaired for the difference between the carrying value of the assets and the result of the probability weighted discounted cash flows.

 

 
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For the year ended December 31, 2013, we had no asset impairments.

 

Gain on Divestiture

 

For the year ended December 31, 2014 and December 31, 2013, we had no gains on divestitures.

 

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, 2014, total other expense decreased $7.8 million to $19.3 million compared to $27.1 million during the same period in 2013.

 

The change is due to the following:

 

Interest expense: For the year ended December 31, 2014, we recognized approximately $18.7 million of net interest expense, which included $27.9 million of interest expense reduced by $9.2 million of capitalized interest expense. For the same period in 2013, we recognized $16.2 million in net interest expense, which included $26.1 million of interest expense reduced by $9.9 million of capitalized interest. The increase of $2.5 million in net interest expense is due to higher interest expense of $1.8 million resulting from a higher average interest cost of debt outstanding between the periods and lower interest capitalized of $0.7 million from a lower average construction in progress in the fourth quarter of 2014. In May 2013, we retired the remaining $30.5 million of the $75.0 million secured debt facility and in September 2013 we retired the remaining $36.0 million of the $40.0 million secured debt facility.

 

Loss on extinguishment of debt: For the year ended December 31, 2014 and December 31, 2013, respectively, we reported $1.2 million and $7.2 million as a loss on extinguishment of debt.

   

In April 2014, $26.0 million of the aggregate principal amount of the 2015 Convertible Notes were exchanged for an additional $25.0 million aggregate principal amount of 2017 Convertible Notes in a private transaction. As a result of the exchange during the second quarter of 2014, we incurred a $1.2 million loss.

 

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. 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. 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.

 

Gain (loss) on derivatives: As a result of the fair value measurement of the Performance Arranger Fees at September 30, 2014 and 2013, respectively, from the measurement at January 1, 2014, and January 1, 2013, respectively, the gain associated with the embedded derivatives decreased $0.3 million to a $2,000 gain for the year ended December 31, 2014 from a $0.3 million gain for the same period in 2013.

 

Other income (expense): For the year ended December 31, 2014, other income increased $4.6 million to $0.7 million of income compared to $3.9 million loss for the same period in 2013. For the year ended December 31, 2014 and 2013, interest income was $0.8 million and $0.2 million, respectively. For the year ended December 31, 2014 and 2013, foreign currency gains (losses), a component of other income, were ($0.6) million and ($1.2) million, respectively. 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 period in 2014.

 

 
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Income Taxes

 

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

 

   

2014

   

2013

 

United States

  $ (47,899 )   $ (31,163 )

Foreign

    (29,033 )     (32,323 )

Loss before income taxes

  $ (76,932 )   $ (63,486 )

 

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

 

   

2014

   

2013

 

Current Taxes

               

Federal

  $ -     $ 668  

Foreign

    1,431       2,595  

Total Current

    1,431       3,263  
                 

Deferred Taxes

               

Federal

    -       -  

Foreign

    29,543       (9,038 )

Total Deferred

    29,543       (9,038 )

Total income tax expense (benefit)

  $ 30,974     $ (5,775 )

 

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):

 

   

2014

   

2013

 

Federal statutory income tax rate

  $ (26,157 )   $ (21,585 )

Increases (decreases) resulting from:

               

Peruvian income tax - rate difference less than 34% statutory

    6,694       3,341  

Asset impairment

    7,767       -  

Permanent book/tax differences

    1,530       262  

Non-deductible intercompany expenses and other

    -       (198 )

Effect of asset sale with retained oil intangible tax attribute

    -       -  

Effect of cumulative profit sharing adjustment

    -       -  

Effect of foreign exchange rate

    (126 )     (1,462 )

Current year foreign withholding tax

    1,433       1,690  

Change in valuation allowance

    39,833       11,509  

Uncertain tax positions

    -       668  

Total income tax expense (benefit)

  $ 30,974     $ (5,775 )

 

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

 

   

2014

   

2013

 

Deferred Tax:

               

Asset:

               

Net Operating Loss

  $ 80,170     $ 77,588  

Deferred Compensation

    5,330       4,704  

Asset Basis Difference

    9,858       9,253  

Exploration Expense

    15,624       15,836  

Depletion

    -       -  

Asset Retirement Obligation

    809       809  

Overhead Allocation to Foreign Locations

    19,601       10,207  

Other

    1,342       2,078  

Liability:

               

Depreciation

    (6,429 )     (6,272 )

Other

    -       -  

Net Deferred Tax Asset

    126,305       114,203  
                 

Less Valuation Allowance

    (92,308 )     (50,601 )

Deferred tax asset

  $ 33,997     $ 63,602  

 

At December 31, 2014, we had recognized a gross deferred tax asset related to net operating loss carryforwards of $80.2 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 zero in 2014 and $7.0 million in 2013. For the year ended December 31, 2014, we established a full valuation allowance related to the $6.4 million deferred tax asset applicable to the Peruvian employee profit sharing plan as the more likely than not criteria as to whether the future benefits would be realized was not met.    

 

At December 31, 2014, we had recognized a gross deferred tax asset related to net operating loss carryforwards attributable to the United States of $62.7 million, before application of the valuation allowances. As of December 31, 2014, we had a valuation allowance for the full amount of the domestic deferred tax asset of $50.1 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 2034. 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. 

 

In 2011, we amended our 2009 U.S. Federal Tax return to elect to deduct our previously benefited foreign income tax credits.  This resulted in an increase to our net operating loss carryforward and the elimination of the foreign income tax credit carryforward previously accrued as a deferred tax asset.  Since we maintained a full valuation allowance against the net operating loss carryforward and the foreign tax credit carryforward deferred tax assets, the election to deduct the foreign tax credit resulted in no impact to overall tax expense.

 

At December 31, 2014, we had recognized a gross deferred tax asset related to net operating loss carryforwards attributable to foreign jurisdictions of $17.5 million, before application of the valuation allowances, attributable to foreign net operating losses, which begin to expire in 2015. We are subject to Peruvian income tax on our 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 do not believe it is more likely than not that we will realize all of the deductible differences at December 31, 2014. Therefore, we have recorded a $42.2 million valuation allowance composed of the following:

 

 

(1)

A $1.9 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,

 

(2)

A $15.4 million valuation allowance on the 2011 through 2013 BPZ E&P net operating losses that expire starting in 2015 as we believe we may not receive the full benefit of these deductions,

 

(3)

A $6.7 million valuation allowance on certain BPZ E&P overhead expenses that we believe we may not receive the full benefit of these deductions, and

 

(4)

A $11.8 million valuation allowance on the deferred tax assets of our foreign subsidiary engaging in the development of the gas-to-power project, as we considered it more likely than not that a portion or all of the subsidiary’s deferred tax assets will not be realized. Further, we will place a valuation allowance on future deferred tax assets of that same foreign subsidiary until we believe it is more likely than not the deferred tax assets will be realized.

 

 
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As a result, we recognized a net deferred tax asset of $34.0 million related to our foreign operations as of December 31, 2014.

 

We recognized a total tax provision for the year ended December 31, 2014 of approximately $31.0 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.

 

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