10-K 1 bpz_10k-123112.htm FORM 10-K bpz_10k-123112.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

Form 10-K
 
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

Or

o
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  o   No  x

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

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  x   No  o

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  x   No  o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   o

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  o
 
Accelerated filer                    x
Non-Accelerated filer   o
 
Smaller reporting company   o

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

The number of shares of Common Stock held by non-affiliates as of June 30, 2012 was 65,275,137 shares, all of one class of common stock, no par value, having an aggregate market value of approximately $165,146,097 based upon the closing price of registrant’s common stock on such date of $2.53 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, 2013 there were 116,923,217 shares of common stock, no par value, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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


 
1

 
 
TABLE OF CONTENTS

PART I
   
     
Item 1.
Business
 3
Item 1A.
Risk Factors
12
Item 1B.
Unresolved Staff Comments
25
Item 2.
Properties
26
Item 3.
Legal Proceedings
34
Item 4
Mine Safety Disclosures
35
     
PART II
   
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
36
Item 6.
Selected Financial Data
38
Item 7.
Management’s Discussion and Analysis of Financial Conditions and Results of Operations
39
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
78
Item 8.
Financial Statements and Supplementary Data
81
Item 9
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
135
Item 9A.
Controls and Procedures
135
Item 9B.
Other Information
137
     
PART III
   
Item 10.
Directors, Executive Officers and Corporate Governance
137
Item 11.
Executive Compensation
137
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
137
Item 13.
Certain Relationships and Related Transactions, and Director Independence
137
Item 14.
Principal Accountant Fees and Services
137
     
PART IV
   
Item 15.
Exhibits and Financial Statement Schedules
138
     
Glossary of Oil and Natural Gas Terms
139
     
Signatures
 
141

 
2

 

PART I

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

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

ITEM 1. BUSINESS

Overview

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

We maintain a subsidiary, BPZ Exploración & Producción S.R.L. (“BPZ E&P”),  registered in Peru through our wholly-owned subsidiary BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership, and its subsidiary BPZ Energy, LLC, a Texas limited liability company.  Currently, we, through BPZ E&P, have license contracts for oil and gas exploration and production covering a total of approximately 2.2 million gross (1.9 million net) acres, in four blocks, in northwest Peru. Our license contracts cover ownership of the following properties: 51% working interest in Block Z-1 (0.6 million gross acres), 100% working interest in Block XIX (0.5 million gross acres), 100% working interest in Block XXII (0.9 million gross acres) and 100% working interest in Block XXIII (0.2 million gross acres). The Block Z-1 contract was signed in November 2001, the Block XIX contract was signed in December 2003 and 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, provided that Perupetro S.A. (“Perupetro”), empowered to negotiate and enter into contracts for the exploration and exploitation of hydrocarbons on behalf of Peru in order to promote these activities in Peru, agrees to the extension and we comply with the minimum work programs and requirements of the exploration phase. However, 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.  
 
Additionally, through our wholly-owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, we own a 10% non-operating net profits interest in an oil and gas producing property, Block 2, located in the southwest region of Ecuador (the “Santa Elena Property”). The agreement covering the Santa Elena Property extends through May 2016.
 
We are in the process of developing our Peruvian oil and gas reserves.  We entered commercial production for the Block Z-1 in November 2010 and produce and sell oil under our current sales contract.  We completed the installation of the new CX-15 platform in the Corvina field to continue the development of the field.  We are also appraising the potential oil and natural gas reserves from the A platform in the Albacora field of Block Z-1.  We received the required environmental permit for gas and produced water injection at Albacora on October 29, 2012, and are producing and selling oil under our current sales contract.  Additionally, our activities in Peru include (i) analysis and evaluation of technical data on our properties, (ii) preparation of the development plans for the properties, (iii) meeting requirements under the license contracts, (iv) procuring equipment for an extended drilling campaign, (v) obtaining all necessary environmental, technical and operating permits, (vi) optimizing current production, (vii) conducting seismic surveys, (viii) and obtaining preliminary engineering and design of the power plant and gas processing facilities.  From the time we began producing from the CX-11 platform in the Corvina field in November 2007 and the Albacora field in December 2009, through December 31, 2012, we have produced approximately 5.9 MMBbls of oil.
 

 
3

 
 
On December 14, 2012 Perupetro approved the terms of the amendment to the Block Z-1 license contract to recognize the sale of a 49% participating interest (“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 relationship 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 million for a 49% participating interest in Block Z-1 and agreed to fund $185 million of our share of capital and exploratory expenditures in Block Z-1 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 Z-1 license contract.
 
At December 31, 2012, we had estimated net proved oil reserves of 16.4 MMBbls, of which 13.4 MMBbls were in the Corvina field and 3.0 MMBbls were from the Albacora field. Both fields are located in Block Z-1 offshore of northwest Peru.  Of our total proved reserves, 2.1 MMBbls (12.8%) are classified as proved developed reserves consisting of proved developed producing and proved developed non-producing reserves from 12 gross (6.1 net) wells, and 14.3 MMBbls (87.2%) are classified as proved undeveloped reserves.  The process of estimating oil and natural gas reserves is complex and requires many assumptions that may turn out to be inaccurate.  See Item 1A - “Risk Factors” for further information.

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

Our Business Plan

Our business plan is to enhance shareholder value through application of our knowledge of our targeted areas in Peru and to leverage management’s experience with the local suppliers and regulatory authorities to effectively and efficiently (i) identify and quantify the potential value of our oil and gas holdings in Peru; (ii) develop and increase production and cash flows from our identified holdings;  (iii) create an additional revenue stream through implementation of our gas marketing strategy and (iv) bring working interest partners into some or all of our Peruvian blocks to facilitate the exploration and development of these blocks.
 
Our focus is to reappraise and develop properties that we control under license agreements in northwest Peru that have been explored by other companies that have reservoirs that appear to contain commercially productive quantities of oil and gas, as well as other areas that have geological formations that we believe potentially contain commercial amounts of hydrocarbons.  Additionally, we are advancing our gas-to-power project to bring future natural gas production to market and monetize our natural gas holdings.

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 our offshore Block Z-1 in our first wells in the Corvina field in 2007 and our first well in Albacora in December 2009, we are initially focusing on development of the proved oil reserves in those two fields.  In June 2011, we drilled our first onshore well in Block XIX. The well tests yielded low rates of oil to surface with high water content of low-salinity.  In December 2011, we determined that this well had no further utility and therefore, declared the well a dry hole.  We are planning to acquire additional seismic data before considering further drilling activity in this block.
 
In the near term, management is focused on preparatory work for commencing drilling operations from the new platform, the CX-15, utilizing the results of the 1,600 square kilometers (“kms”) of 3-D seismic survey in Block Z-1 to optimize our future activities in the Block, and optimizing current production through workover activities at our current producing locations.  At our onshore locations we are in the process of obtaining the necessary permits to continue exploration activities utilizing our 3-D seismic data acquired in 2011, and focusing on maximizing the value of the acreage we hold for exploration though possible joint ventures.   
 
 
4

 
 
The data room for Blocks XIX and XXIII has been open, with Credit Suisse Securities (USA) LLC managing the formal process to find a joint venture partner for these onshore blocks.  Interested partners have been invited to review the data.  The two blocks comprise over 800,000 acres and hold both oil and gas potential, with Block XXIII bordering the northern part of the prolific Talara oil fields.  We are currently reviewing our alternatives for this block.
 
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. We currently plan to partially-own this power generation facility. 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 move forward with the project.
 
Available Information

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

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

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

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

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

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

 
5

 
 
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. All other petroleum activities are to be freely operated and are subject to local and international safety and environmental standards.

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

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

Perupetro reviews the qualification for each contract signed by a company. Additionally, the qualification for foreign companies is granted in favor of the home office or BPZ Resources, Inc., which provides a corporate guarantee to Perupetro which determines if it is jointly and severally liable before Perupetro with respect to the fulfillment of each minimum work program of the exploration phase, as well as each annual exploitation program handed to Perupetro. BPZ Resources, Inc. and its corresponding subsidiary in Peru have been qualified by Perupetro with respect to our current contracts as required by current regulation.

 
6

 
 
When operating under a license contract, the licensee is the owner of the hydrocarbons extracted from the contract area during the performance of operations 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 up to a three year extension, 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 fulfillment of work programs 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 15, 2013, we believe we were 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, 2012, we had $5.6 million in bonds posted at various dates to secure our obligation under the license contracts for Block XIX, XXII, XXIII and Z-1 and a drilling service agreement. The license contract bonds are partially secured by the deposit of restricted cash in the amount of $3.3 million with the financial institutions which issued the bonds.  Should we fail to fulfill our 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 $0.8 million of restricted cash to collateralize insurance bonds for import duties related to our construction barge and $0.6 million of restricted cash to secure the location for 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 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 properly,  the legislation provides a process by which an operator can request an extension to allow for additional testing – extended well testing (“EWT”).  After the initial six-month period or after an EWT program expires, the operator will be required to have the necessary gas and water reinjection equipment in place to continue operating the well according to existing environmental regulations.

Peruvian fiscal regime.  Peru’s fiscal regime determines the levels of 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 are subject to royalty payments, 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 to increase its chances to win a successful bid for a block.  See Item 2. “Properties” for further information regarding royalties applicable to each Block.

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

 
7

 
 
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 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, as long as the contract with the loss is in the commercial production phase or has been relinquished, 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 gives 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,” thus 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.
 
The profit sharing system takes the following factors into account: (1) calculation of profits to be distributed to each employee is based on (a) the number of days actually worked by each employee, and (b) in proportion to the remunerations of each employee; (2) number of days actually worked (including leave of absence, temporary shutdown of the workplace, and days not worked due to improper suspension by the employer); (3) remuneration (the full amount received by the employee for his services); (4) maximum profit share limit of 18 monthly remunerations; (5) remainder between the maximum percentage of company profits to be distributed and the maximum limit of the percentage corresponding to all employees; (6) timing of distributions (which should be made within thirty calendar days after expiration of the term for the filing of the Annual Income Tax Return); (7) default interest; (8) evidence of settlement of profits; and (9) deductible expenses.

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

 
8

 
The Organic Hydrocarbon Law also addresses the environmental regulatory regime in Peru. The law originally prohibited any mining or extractive operations within certain areas designated for protection.  We must comply with these obligations as we conduct our business on an ongoing basis. 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 by the DGAAE.

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. It must also contain information on the procedures, personnel and equipment required to be used and procedures to be followed to establish uninterrupted communication between the personnel, the government representatives, the General Hydrocarbons Bureau and other Peruvian government entities.

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.  The enactment and enforcement of environmental laws and regulations in Peru is relatively new. We are therefore uncertain 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 generation of electricity and the sale of such electric power in Peru. The basic laws of Peru governing electric power, which will apply to our future operations, are the Law of Electric Power Concessions and the Regulations for the Environmental Protection of Electric Power Activities, and the corresponding regulations for each, as well as additional related laws and regulations, including all legislation regarding Electric Power Tariffs and all regulations and technical norms created by the National Commission of Electric Power Tariffs.

Compliance with Existing Legislation in Peru

Although we believe our operations are and will continue to be in substantial compliance with existing legislation and requirements of Peruvian governmental bodies, our ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls. Our management team has many collective decades of 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.

 
9

 

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, 2012, 2011, and 2010 were approximately $0.5 million, $1.6 million, and $2.4 million, respectively.

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

Operational Hazards and Insurance

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

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

Research and Development

We seek to use advanced technologies in the evaluation of our oil and gas properties and in evaluating new opportunities. We generally do not develop such technologies internally, but our technical team works with outside vendors to test and utilize these technologies to the fullest extent practical, particularly in the application of geophysical and exploration software. We do not believe we have incurred any quantifiable incremental costs in connection with research and development.
 
 
10

 

Employees
 
As of December 31, 2012, we employed 27 full-time employees of BPZ Resources, Inc., and 217 full-time employees within our subsidiaries BPZ E&P, BPZ Marine Peru S.R.L., and Soluciones Energeticas, S.R.L.  We had one full-time employee in the Quito, Ecuador office.
 
We believe that our relationship with our employees is satisfactory.  None of our employees are currently represented by a union.

 
11

 
 
ITEM 1A.  RISK FACTORS
 
Risks Relating to the Oil and Natural Gas Industry, the Power Industry, and Our Business.
 
Our reserve estimates depend on many assumptions that may turn out to be inaccurate. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors that may turn out to be inaccurate. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the estimated value of reserves shown in this Annual Report.
 
In order to prepare our reserve estimates, our independent petroleum engineer must project production rates and timing of development expenditures as well as analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process 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. In addition, our independent petroleum engineers may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
 
One should not assume that the estimated value of our proved reserves prepared in accordance with the Commission’s guidelines referred to in this report is the current market value of our estimated oil reserves. We base the estimated value of future net cash flows from our proved reserves on an unweighted arithmetic average of the first-day-of-the month price for each month during the 12-month calendar year and year-end costs. Actual future prices, costs, taxes and the volume of produced reserves may differ materially from those used in the estimated value.
 
Except as required by applicable law, we undertake no duty to provide an update of this information to the public and do not intend to provide such an update of this information.
 
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.
 
As of December 31, 2012, approximately 87% 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.  We may not have or be able to obtain the capital we need to develop these proved reserves.
 
 
12

 
 
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 EWT programs in both fields in the past.  We are also subject to all of the risks inherent in attempting to expand a relatively new business venture. Such risks include, but are not limited to, the possible inability to profitably operate our existing properties or properties to be acquired in the future, our possible inability to fully fund the development requirements of such properties and our possible inability to acquire additional properties that will have a positive effect on our operations. We can provide no assurance that we will achieve a level of profitability that will provide a return on invested capital or that will result in an increase in the market value of our securities.  Accordingly, we are subject to the risk that because of these factors and other general business risks noted throughout these “Risk Factors,” we may not be able to profitably execute our plan of operation. 
 
We have not been profitable since we commenced operations and have historically had limited earnings from operations.  To date we have been unable to support our exploration and development activities solely through earnings from operations.  While we currently have a working capital surplus, the sources of our working capital surplus have generally been equity issuances, debt financings and asset sales rather than revenue from operations and we may incur working capital deficits in the future.  We cannot provide any assurance that we will be profitable in the future or that we will be able to generate cash from operations or financings to fund working capital deficits.
 
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 quarterly 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.
 
Our future operating revenue is dependent 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.
 
Competition for oil and natural gas properties and prospects is intense; many of our competitors have larger financial, technical and personnel resources that give them an advantage in evaluating and obtaining properties and prospects. We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and natural gas and securing trained personnel and equipment. In addition, changes in Peruvian government regulation have enabled multinational and regional companies to enter the Peruvian energy market. We actively compete with other companies in our industry when acquiring new leases or oil and gas properties. Competition in our business activities has increased and will increase further, as existing and new participants expand their activities as a result of these regulatory changes. Many of our competitors possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than we have. For example, if several companies are interested in an area, Perupetro  may choose to call for bids, either through international competitive biddings or through private bidding processes by invitation, and award the contract to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. Our competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical or personnel resources permit. Our competitors may also be able to pay more for productive oil and natural gas properties and exploratory prospects than we are able or willing to pay. On the acquisition opportunities made available to us, we 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.
 
 
13

 
 
Future oil and natural gas declines or unsuccessful exploration efforts may result in significant charges or a write-down of our asset carrying values.   We follow the successful efforts method of accounting for our investments in oil and natural gas properties.  Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred. Certain costs of exploratory wells are capitalized pending determinations that proved reserves have been discovered.  If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed.
 
The capitalized costs of our oil and natural gas properties, on a field basis, cannot exceed the estimated undiscounted future net cash flows of that field.  If net capitalized costs exceed undiscounted future net cash flows, we must write down the costs of each such field to our estimate of its fair market value.  Unproved properties are evaluated at the lower of cost or fair market value.  Accordingly, a significant decline in oil or natural gas prices or unsuccessful exploration efforts could cause a future write-down of capitalized costs.
 
We evaluate impairment of our proved oil and gas properties whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. In addition, write-downs would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues.  Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date even if oil or natural gas prices increase.
 
Demand for oil and natural gas is highly volatile.  A substantial or extended decline in oil prices and to a limited extent natural gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations as well as our ability to meet our capital expenditure obligations and financial commitments necessary to implement our business plan.  Any revenues, cash flow, profitability and future rate of growth we achieve will be greatly dependent upon prevailing prices for oil and gas. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms is also expected to be dependent on oil and gas prices.
 
Historically, oil and gas prices and markets have been volatile and are likely to be volatile again in the future. For example, oil and natural gas prices increased to historical highs in 2008 and then declined significantly over the last two quarters of 2008. These prices will likely continue to be volatile in the future. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand for oil and gas, market uncertainty, and a variety of additional factors beyond our control. Those factors include among others:
                 
 
international political conditions (including wars and civil unrest, such as the recent unrest in the Middle East);
 
the domestic and foreign supply of oil and gas;
  the level of consumer demand;
  weather conditions;
  domestic and foreign governmental regulations and other actions;
  actions taken by the Organization of Petroleum Exporting Countries (“OPEC”);
  the price and availability of alternative fuels; and
  overall economic conditions.
 
Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but may also reduce the amount of oil and natural gas we can produce economically, if any, and, as such, may have a negative impact on our reserves.  A continuation of low or significant declines in oil and natural gas prices may materially affect our future business, financial condition, results of operations, liquidity and borrowing capacity, and may require a reduction in the carrying value of our oil and gas properties. While our revenues may increase if prevailing oil and gas prices increase significantly, exploration and production costs and acquisition costs for additional properties and reserves may also increase.  We currently do not enter into hedging arrangements or use derivative financial instruments such as crude oil forward and swap contracts to hedge our risk associated with fluctuations in commodity prices.
 
 
14

 
 
Any failure to meet our debt obligations, or the occurrence of a continuing default under our debt facilities or our Convertible Notes due 2015, would adversely affect our business and financial condition.  On January 27, 2011, we and our subsidiaries, Empresa Eléctrica Nueva Esperanza S.R.L. and BPZ E&P, entered into a Credit Agreement with Credit Suisse, as lender and administrative agent, dated January 27, 2011, wherein Credit Suisse provided a $40.0 million secured debt facility to our power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L., and we and our subsidiary, BPZ E&P, agreed to unconditionally guarantee the debt facility on an unsecured basis.

In addition, on July 6, 2011, we and our subsidiary, BPZ E&P, entered into a Credit Agreement with Credit Suisse, as administrative agent and lender, Standard Bank PLC (“Standard Bank”), as lender and mandated lead arranger, and Credit Suisse International, as lead arranger, wherein the lenders provided a $75.0 million secured debt facility to BPZ E&P, and we agreed to unconditionally guarantee the $75.0 million secured debt financing. 

The $40.0 million secured debt facility is secured, in part, by three LM6000 gas-fired packaged power units that were purchased by us from GE through our power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L. The $40.0 million secured debt financing is also secured by certain other equipment and property pledged in favor of Credit Suisse and Credit Suisse International.  We and our subsidiary, BPZ E&P, also agreed to unconditionally guarantee the $40.0 million secured debt facility on an unsecured basis. 

The $75.0 million secured debt facility is secured by (i) 51% of BPZ E&P’s Block Z-1 property on the northwest coast of Peru, (ii) 51% of the wellhead oil production of Block Z-1, (iii) 51% of BPZ E&P’s rights, title and interests under the Block Z-1 license contract, as amended and assigned, with Perupetro, (iv) a collection account (including BPZ E&P’s deposits and investments), (v) 51% of BPZ E&P’s right, title and interests under current and future contracts in connection with the sale of crude oil and/or gas produced and sold at Block Z-1, together with related receivables, (vi)  BPZ E&P’s capital stock, (vii) a debt service reserve account, and (viii) certain other property that is subject to a lien in favor of Credit Suisse. We and our subsidiary BPZ Energy LLC also agreed to unconditionally guarantee the remaining portion of the $75.0 million secured debt facility.

The debt facilities require us to comply with various operational and other covenants and provide for events of default customary for agreements of this type.

We recently amended our secured debt facilities to extend the compliance dates for certain covenants, to accommodate for delays in our development of our projects resulting from various factors.  In addition, we have recently requested and received waivers for not meeting certain production covenants.  Further amendments or waivers could become necessary and we can give no assurance we will be able to obtain such amendments, in which case we could default on our obligations to our lenders.

If an event of default occurs, Credit Suisse shall, upon the request of the majority lenders, or may, by notice to the borrower, (i) immediately terminate the lending commitments; (ii) declare all or part of the principal amount of the loans, together with accrued interest, immediately due and payable, without demand; provided that, all lending commitments shall automatically terminate and all amounts due and payable on any loan will automatically become immediately due and payable without notice if the borrower or any guarantor and any of their respective subsidiaries appoint a receiver, liquidator or trustee, make a general assignment for the benefit of their creditors, become insolvent, go bankrupt, liquidate, or are subject to certain monetary judgments exceeding in the aggregate, $3.0 million under the $40.0 million debt facility, or $30.0 million under the $75.0 million debt facility; and/or (iii) liquidate the security collateral and apply the proceeds thereof to pay the loans.  In addition, each of the debt facilities provides for a mandatory prepayment of the loans under certain circumstances.

At December 31, 2012, the remaining principal outstanding of $32.7 million under the $40.0 million debt facility and $35.0 million under the $75.0 million debt facility are fully secured with funds held in respective debt service reserve accounts.

 
15

 
 
In addition to our two debt facilities, during the first quarter of 2010, we issued $170.9 million of Convertible Notes due 2015, which bear interest semi-annually at a rate of 6.50% per year.  The Convertible Notes mature with repayment of $170.9 million (assuming no conversion by the note holders) due on March 1, 2015.  If a fundamental change occurs, holders of the notes may require us to repurchase, for cash, all or a portion of their notes.  In addition, upon conversion of the notes by any of the note holders, should the conditions for conversion occur, if we have elected to deliver cash in respect of all or a portion of our conversion obligation (other than solely cash in lieu of fractional shares), we will be required to pay cash in respect of all or a portion of our conversion obligation.  Should any notes not be redeemed or converted, repayment of the notes in cash is required at the maturity date.  We may not have sufficient funds to pay the interest, repurchase price or cash in respect of our conversion obligation when due.  If we fail to pay interest on the notes, repurchase the notes or pay any cash payment due when required (whether on an interest payment date, at maturity, upon repurchase, upon conversion or otherwise), we will be in default under the indenture governing the notes.  The indenture contains customary terms and covenants and events of default.  If an event of default (as defined therein) occurs and is continuing, the trustee, by notice to us, or the holders of at least 25% in aggregate principal amount of the Convertible Notes due 2015 then outstanding by notice to us and the trustee, may declare the principal and accrued and unpaid interest (including additional interest or premium, if any) on the Convertible Notes due 2015 to be due and payable.  In the case of an event of default arising out of certain bankruptcy events (as set forth in the Indenture), the principal and accrued and unpaid interest (including additional interest or premium, if any), on the notes will automatically become due and payable.

Our ability to meet our current and future debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control.  If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets or sell shares of common stock on terms that we do not find attractive, if it can be done at all.
 
We 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 on September 10, 2004, we have funded our operations with the net proceeds of (i) approximately $288 million in various private and public offerings of our common stock, (ii) $186.4 million in convertible debt financing, including $170.9 million of convertible debt financing sold in a private offering and $15.5 million in convertible debt financing from the International Finance Corporation (“IFC”) that was converted into approximately 1.5 million shares of our common stock in May 2008, (iii) $40.0 million in a credit facility with Credit Suisse AG, Cayman Islands Branch (“Credit Suisse”) in January 2011 (iv) $75.0 million in a credit facility with Credit Suisse and other parties in July 2011,  and (v) 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 venture or a combination thereof may occur.  If we are unable to timely generate or obtain adequate funds to finance our exploration and development plans, our ability to develop our oil and natural gas reserves may be limited or substantially delayed. Such limitations or delays could result in a failure to realize the full potential value of our properties or could result in the potential loss of our oil and gas properties if we were unable to meet our obligations under the license agreements, which could, in turn, limit our ability to repay our debts. Inability to timely generate or obtain funds also could cause us to delay, scale back or abandon our plans for construction of our power generation facility, pipelines and gas processing facility.
 
Future amounts required to fund our activities may be obtained 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, combined with the volatility of oil and natural gas prices, may also affect our ability to obtain funding on acceptable terms.  Global financial markets and economic conditions have been disrupted and volatile.  Accordingly, the equity capital markets can become exceedingly distressed.   Market discontinuities, credit risk pricing and the weak economic conditions, can make it difficult to obtain debt or equity capital funding.
 
Due to these and possibly other factors, we cannot be certain funding will be available 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.
 
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.
 
 
16

 

 
Our business involves many uncertainties and operating risks that may prevent us from realizing profits and can cause substantial losses. Our exploration and production activities may be unsuccessful for many reasons, including weather, the drilling of dry holes, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well will not ensure we will realize a profit on our investment. A variety of factors, including geological, regulatory and market-related factors can cause a well to become uneconomical or only marginally economical. Our business involves a variety of operating risks, including:
 
  · fires;
  · explosions;
  · blow-outs and surface cratering;
  · uncontrollable flows of natural gas, oil and formation water;
  natural disasters, such as earthquakes, tsunamis, typhoons and other adverse weather conditions;
  · pipe, cement, subsea well or pipeline failures;
  · casing collapses;
  · mechanical difficulties, such as lost or stuck oil field drilling and service tools;
  · abnormally pressured formations; or
  · environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.
 
Experiencing any of these operating risks could lead to problems with any well bores, platforms, 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 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.
 
Disruption of services provided by our vessels and tankers could temporarily impair our operations and delay delivery of our oil to be sold.  We depend on our marine fleet, which includes the deck barges BPZ-01, BPZ-02 and the crane barge Don Fernando, to act as support vessels for our offshore operations in our Corvina and Albacora fields in Block Z-1. In addition, we have two tank barges, the Nuuanu and Namoku, to use in support of our offshore oil production operations.  Both vessels are currently being used as a floating storage and offloading facility.  In addition, we have time chartered a double hull tank vessel to transport crude oil from our offshore production and storage facilities in the Corvina and Albacora fields to the Talara refinery approximately 70 miles south of the platform.  Any disruption or delay of the services to be provided by our vessels or tanker because of adverse weather conditions, accidents, mechanical failures, insufficient personnel or other events could temporarily impair our operations, delay implementation of our business plan, and increase our costs.
 
 
17

 

 
The geographic concentration of our properties in northwest Peru and southwest Ecuador subjects us to an increased risk of loss of revenue or curtailment of production from factors affecting that region specifically. The geographic concentration of our properties in northwest Peru and southwest Ecuador and adjacent waters means that some or all of our properties could be affected by the same event should that region, for example, experience:
 
  · natural disasters such as earthquakes and/or severe weather (such as the effects of “El Niño,” which can cause excessive rainfall and flooding in Peru and Ecuador); 
  · delays or decreases in production, the availability of equipment, facilities or services; 
  · delays or decreases in the availability of capacity to transport, gather or process production; or 
  · changes in the political or regulatory environment.
 
Because all our properties could experience the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area.
 
Our operations in Peru and Ecuador involve substantial costs and are subject to certain risks because the oil and gas industry in Peru and Ecuador is less developed in comparison to the United States. Because the oil and gas industry in Peru and Ecuador is less developed than in the United States, our drilling and development operations, in many instances, will take longer to complete and may cost more than similar operations in the United States. The availability of technical expertise and specific equipment and supplies may be more limited or costly in Peru and Ecuador than in the United States.  If we are unable to obtain or unable to obtain without undue cost drilling rigs, equipment, supplies or personnel, our exploitation and exploration operations could be delayed or adversely affected, which could have a material adverse effect on our business, financial condition or results of operations.  Furthermore, once oil and natural gas production is recovered, there are fewer ways to transport it to market for sale. Marine transportation for our offshore operations is subject to risks such as adverse weather conditions, collisions, groundings and other risks of damage or delay. Pipeline and trucking operations are subject to uncertainty and lack of availability. Oil and natural gas pipelines and truck transport travel through miles of territory and are subject to the risk of diversion, destruction or delay. We expect that such factors will continue to subject our international operations to economic and operating risks that companies with domestic operations do not experience.
 
Along with the general instability that comes from international operations, we face political and geographical risk specific to working in South America. Presently, all of our oil and gas properties are located in South America, and specifically in Peru and Ecuador. The success and profitability of our international operations may be adversely affected by risks associated with international activities, including:
 
  · economic, labor, and social conditions; 
  · local and regional political instability; 
  · tax laws (including host-country export, excise and income taxes and U.S. taxes on foreign operations); and 
  · fluctuations in the value of the U.S. dollar versus the local currencies in which oil and gas producing activities may be conducted.
 
This instability of laws, expenses of operations 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. We believe there has been recent heightened scrutiny over regulatory matters concerning oil and gas exploration and production and the award of licensing contracts in Peru, in large part due to social and political change.  In the last decade, Peru has experienced numerous occasions of social unrest, some violent at times, as a result of an increase in extractive industry development.
 
Peru’s most recent municipal and regional political elections were held in November 2010, and the next ones will be held in 2014.  The Peruvian Presidential and Congressional election was held in April 2011.  Mr. Ollanta Humala narrowly won the run-off Presidential election and took office on July 28, 2011, for a five-year term.  The campaigning leading up to the elections caused heightened attention to various topics, including the regulation of oil and gas companies operating in Peru, and related environmental law compliance.  For example, Mr. Humala has called for 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, during his campaign Mr. Humala proposed to raise royalties on oil and gas production, which would help fund domestic social-regeneration projects.  The Humala administration also recently negotiated with mining companies to raise royalties and taxes on the mining sector in Peru.  While spokespersons for the new administration have stated the new administration intends to honor existing contracts, avoid nationalization and support continued development of oil and gas activities, as a result of these elections, a shift in policy could occur with respect to the regulation of oil and gas companies making it more difficult or expensive to operate in such an environment.  
 
 
18

 

Similarly, in December 2011 President Humala replaced a significant part of his cabinet including the Prime Minister and the Minster of Energy & Mines, after the prime minister and cabinet members resigned following President Humala’s declaration of a state of emergency in the region of Cajamarca following seemingly intractable protests over the environmental issues of a major new mining development in the region.  In July 2012, there were additional cabinet changes due to anti-mining protests.
 
We are subject to numerous foreign laws and regulations of the oil and natural gas industry that can adversely affect the cost, manner or feasibility of doing business. Our operations are subject to extensive foreign laws and regulations relating to the exploration for oil and natural gas and the development, production and transportation of oil and natural gas, as well as electrical power generation.  Because the oil and gas industry in the countries in which we operate is less developed than elsewhere, changes in laws and interpretations of laws are more likely to occur than in countries with a more developed oil and gas industry.  Future laws or regulations, as well as any adverse change in the interpretation of existing laws or our failure to comply with existing legal requirements may harm our results of operations and financial condition. In particular, there are indications that the administration in Ecuador may increase state intervention in the economy via new legislation and tightening control of areas such as energy, which could have a significant impact on our investment in that country or our ability to operate in the future in that country. We may be required to make our share of contributions to large and unanticipated expenditures to comply with governmental regulations, such as:
 
  ·
work program guarantees and other financial responsibility requirements;
  ·
taxation;
  ·
royalty requirements;
  ·
customer requirements;
  employee compensation and benefit costs;
  operational reporting;
  environmental and safety requirements; and
  unitization requirements.
 
Under these laws and regulations, we could be liable for our share of:
 
  ·
personal injuries;
  ·
property and natural resource damages;
  ·
unexpected employee compensation and benefit costs;
  ·
governmental infringements and sanctions; and
  unitization payments.
 
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.
 
 
19

 
 
We are subject to environmental regulatory and permitting 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.  For example, in 2009, we attempted to acquire 3-D seismic data in Block Z-1, but stopped our seismic acquisition program at the request of the government.  The environmental permit to acquire approximately 1,600 square kms of 3-D seismic data in our offshore Block Z-1 was eventually granted by the DGAAE on November 3, 2011.
 
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.
 
Our management team has limited experience in the power generation business and we need additional funding to construct power generation and pipelines. Our plan of operation includes constructing power generation and pipelines in Peru, and in the future, potentially Ecuador.  However, the experience of our management team has primarily been in the oil and natural gas exploration and production industry and we have limited experience in the power generation business. We have hired a Director of Gas-to-Power.  However, we continue relying on consultants and outside engineering and technical firms to provide the expertise to plan and execute the power generation aspects of our strategy and we have not yet hired all necessary full-time employees to manage this line of business. If we do not have sufficient funds or if we are unable to successfully find partners to participate in our gas-to-power project, we will need to find alternative sources of funding for the construction of the power generation, which may not be available when needed or available on favorable terms.
 
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.
 
 
20

 

 
The ongoing 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 until 2015. Our assessment of the future power market and demand in Peru could be inaccurate. We are subject to the following risks that:
 
  ·
relatively more favorable business conditions for hydroelectric plants, a material reduction in power demand or other competitive issues may adversely affect the demand and prices for the electricity that we expect to produce by the time the power plant is completed;
  ·
our lifting costs could exceed the minimum wholesale power prices available, making the sale of our gas uneconomical;
  ·
gas supply and reserves may not deliver as forecasted;
  ·
potential disruptions or changes to the regulation of the natural gas or power markets in these countries 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;
 
although we plan to enter into long-term contracts to sell a significant part of our future power production, there can be no assurance that we will be successful in obtaining such contracts or that they will be on favorable terms; and
  ·
we will be subject to the general commercial issues related to being in the power business, including the credit-worthiness of, and collections from future customers and the ability to profitably operate our future power plant.
 
We are assessing additional joint venture or partner relationships in our other Blocks and 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.  In April 2012, we selected a joint venture partner concerning our interest and operations under our offshore Block Z-1 License Contract, and we may enter into additional joint venture arrangements in the future for this or our other Blocks and 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 an action 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.
 
 
 
21

 
 
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.
 
If we fail to comply with the terms of certain contracts related to our foreign operations, we could lose our rights under each of those contracts. The terms of each of our Peruvian oil and gas license contracts, require that we perform certain activities, such as seismic acquisition, processing and interpretations and the drilling of required wells in accordance with those contracts and agreements. We are also required to conduct environmental impact studies and environmental impact assessments and establish our ability to comply with environmental regulations.  Our failure to timely perform those activities as required could result in the suspension of our current production and sale of oil, the loss of our rights under a particular contract and/or the loss of the amounts we have posted as a guaranty for the performance of such activities, which would result in a significant loss to us.
 
We are subject to the Foreign Corrupt Practices Act (the “FCPA”), and our failure to comply with the laws and regulations thereunder could result in penalties which could harm our reputation and have a material adverse effect on our business, results of operations and financial condition.  We are subject to the FCPA, which generally prohibits companies and their intermediaries from making improper payments to foreign officials to secure any improper advantage for the purpose of obtaining or keeping business and/or other benefits. Since all of our oil and gas properties are in Peru and Ecuador, there is a risk of potential FCPA violations.  We have a FCPA policy and a compliance program designed to ensure that we, our employees and agents comply with the FCPA.  There is no assurance that such policy or program will work effectively all of the time or protect us against liability under the FCPA for actions taken by our agents, employees and intermediaries with respect to our business or any businesses that we acquire.  Any violation of these laws could result in monetary penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business. 

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

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

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

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

A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:
 
  ·
unauthorized access to seismic data, reserves information 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.
 
 
 
22

 
 
Although to date we have not experienced any material losses relating to cyber incidents, there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
 
The loss of senior management or key technical personnel could adversely affect us. We have engaged certain members of management who have substantial expertise in the type of endeavors we presently conduct and the geographical areas in which we conduct them. We do not maintain any life insurance against the loss of any of these individuals. To the extent their services become unavailable, we will be required to retain other qualified personnel. There can be no assurance we will be able to recruit and hire qualified persons on acceptable terms.  Similarly, the oil and gas exploration industry requires the use of personnel with substantial technical expertise. In the event that the services of our current technical personnel become unavailable, we will need to hire qualified personnel to take their place. No assurance can be given that we will be able to recruit and hire such persons on acceptable terms.  Inability to replace lost members of management or key technical personnel may adversely affect us.
 
Insurance does not cover all risks. Exploration for, and the production of, oil and natural gas can be hazardous, involving unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can result in (i) damage to or destruction of wells and/or production facilities, (ii) damage to or destruction of formations, (iii) injury to persons, (iv) loss of life, or (v) damage to property, the environment or natural resources. As a result, we presently maintain insurance coverage in amounts consistent with our business activities and to the extent required by our license contracts. Such insurance coverage includes certain physical damage to our and third parties’ property, hull and machinery, protection and indemnity, employer’s liability, comprehensive third party general liability, workers’ compensation and certain pollution and environmental risks. However, we are not fully insured against all risks in all aspects of our business, such as political risk, civil unrest, war, business interruption, environmental damage and reservoir loss or damage. Further, no such insurance coverage can insure for all operational or environmental risks. The occurrence of an event that is not insured or not fully insured could result in losses to us. For example, uninsured or under insured environmental damages, property damages or damages related to personal injuries could divert capital needed to implement our plan of operation. If any such uninsured losses are significant, we may have to curtail or suspend our drilling or other operations until such time as replacement capital is obtained, if ever, and this could have a material adverse impact on our financial position.
 
We have entered into a significant joint venture. This joint venture limits 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. On April 27, 2012, we entered into a joint venture relationship with Pacific Rubiales concerning Block Z-1, which on December 14, 2012 Perupetro approved the terms of the amendment to the Block Z-1 license contract to recognize the sale of a 49% participating interest.  The following aspects of this joint venture could materially impact the Company: 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. The performance of our joint venture partner’s obligations under the Joint Operating Agreement is outside of our direct control. The ability or failure of our joint venture partner to pay its funding commitment, including costs to be paid on our behalf during the drilling term, could increase our costs of operations or result in reduced drilling and production of oil and gas, or loss of rights to develop Block Z-1. These restrictions may preclude transactions that could be beneficial to our shareholders. Pacific Rubiales will become the technical operator of the field under and Operating Services Agreement. Their ability to deliver the continued safe and efficient operations of the block under this agreement will have a material impact to the Company. Disputes between us and 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. 
 
Disclosure of certain operating information as required by Section 1504 of the Dodd-Frank Act could have a negative impact on our competitiveness.  On August 22, 2012, the SEC issued final rules: Disclosure of Payments by Resource Extraction Issuers (Final Rules), as required by the Dodd-Frank Act. As a result, beginning in 2014, we must provide information about the type and total amount of payments made for each project related to the commercial development of oil, natural gas, or minerals, and the type and total amount of payments made to each government. Disclosure of this type of information could put us at a competitive disadvantage to companies that are not required to make such disclosures. 
 
 
23

 
 
Risks Relating to Our Securities
 
Investor profits, if any, may be limited for the near future. In the past, we have never paid a dividend. We do not anticipate paying any dividends in the near future. Accordingly, investors in our common stock may not derive any profits from their investment in us for the foreseeable future, other than through any price appreciation of our common stock that may occur. Further, any appreciation in the price of our common stock may be limited or nonexistent as long as we continue to have operating losses. We have not been profitable and have accumulated deficits of operations totaling $373.9 million through December 31, 2012.  To date we have had limited revenue and no earnings from operations.  There can be no assurances that sufficient revenue to cover total expenses can be achieved until, if at all, we fully implement our operational plan.
 
The market price and trading volume of our common stock may be volatile.  The market price of our common stock may be highly volatile and subject to wide fluctuations. In addition, the trading volume in our common stock may fluctuate and cause significant price variations to occur.  If the market price of our common stock declines significantly, you may be unable to resell your shares at or above the price at which the shares were acquired.  We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future.  Some of the factors that could adversely affect our share price or result in fluctuations in the price or trading volume of our common stock include:
 
·       actual or anticipated fluctuations in our results of operations; 
·       failure to be covered by securities analysts, or failure by us to meet securities analysts’ expectations; 
·       success of our operating strategies; 
·       decline in the stock price of companies that are our peers; 
·       realization of any of the risks described in this section; and
·       general market and economic conditions.
 
Because we are a relatively new public company, these fluctuations may be more significant for us than they would be for a company whose stock has been publicly traded over an extended period of time.
 
In addition, the stock market has experienced in the past, and may again 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.
 
Additional infusions of capital may have a dilutive effect on existing shareholders. To finance our operations, we may sell additional shares of our common stock.  During the first quarter of 2010, we issued $170.9 million of Convertible Notes that mature in 2015 that, if converted to common stock, could significantly increase the amount of our common shares outstanding by up to approximately 28.9 million shares.  We currently have $134.6 million in common stock available under an effective shelf registration statement, and another $500.0 million available under the same shelf registration statement for debt securities, common stock, preferred stock, depositary shares and securities warrants, subscription rights, units, and guarantees of debt securities or any combination thereof, which we may sell from time to time in one or more offerings pursuant to underwritten public offerings, negotiated transactions, at the market transactions, block trades or a combination of these methods. Our certificate of formation does not provide for preemptive rights.  Any additional equity financing that we receive may involve substantial dilution to our then-existing shareholders. Furthermore, we may issue common stock to acquire properties, assets, or businesses. In the event that any such shares are issued, the proportionate ownership and voting power of other shareholders will be reduced. In addition, we are authorized to issue up to 25,000,000 shares of preferred stock, the rights and preferences of which may be designated by our Board of Directors. If we issue shares of preferred stock, such preferred stock may have rights and preferences that are superior to those of our common stock.
 
Our operations may not generate sufficient cash to enable us to service our debt, including the Convertible Notes due 2015, the $40.0 million credit facility with Credit Suisse or the $75.0 million credit facility with Credit Suisse.  Our future cash flow may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business.  A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt, including the Convertible Notes due 2015, the $40.0 million credit facility with Credit Suisse and the $75.0 million credit facility with Credit Suisse. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.
 
 
24

 
 
If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:
 
 
refinancing or restructuring our debt;
 
selling assets;
 
reducing or delaying capital investments; or
 
seeking to raise additional capital.
 
However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.  At December 31, 2012, the remaining principal outstanding of $32.7 million under the $40.0 million debt facility and $35.0 million under the $75.0 million debt facility are fully secured with funds held in respective debt service reserve accounts.
 
Shares eligible for future sale by our current shareholders may impair our ability to raise capital through the sale of our stock. As of December 31, 2012, we had 116.9 million shares of common stock issued and outstanding. In addition, we currently have outstanding 34.4 million shares of potentially dilutive securities, which mainly consist of approximately 28.9 million shares that are potentially convertible under our Convertible Notes due 2015 and 5.5 million options granted under our 2005 and 2007 Long-Term Incentive Compensation Plan, as amended.  We also have an additional 2.9 million shares of common stock allocated under our 2007 Long-Term Incentive Compensation Plan and our 2007 Directors’ Compensation Incentive Plan.  The possibility that substantial amounts of shares of our common stock may be sold in the public market may cause prevailing market prices for our common stock to decrease and thus could impair our ability to raise capital through the sale of our equity securities.
 
Our officers, directors, entities affiliated with them and certain institutional investors may exercise significant control over us. In the aggregate, our management and directors own or control approximately 5.6% of our common stock, and several institutional investors own approximately another 38.3% of our common stock, issued as of December 31, 2012.  These shareholders own in total approximately 43.9%, 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.
 
Our corporate organizational documents and the provisions of Texas law, which we are subject to, 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 elect out of in our certificate of formation, that restrict business combinations with “affiliated shareholders” and provide that directors serving on staggered boards of directors, such as ours, may be removed only for cause.
 
Any or all of these provisions could discourage tender offers or other business combination transactions that might otherwise result in our shareholders receiving a premium over the then current market price of our common stock.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

 
25

 

ITEM 2.   PROPERTIES

Offices

Our corporate headquarters office is in Houston, Texas, where we lease approximately 13,300 square feet of office space under a lease agreement which expires in February 2016. We also currently lease administrative offices and warehouses in Peru. The administrative office and warehouse leased areas are approximately 22,500 square feet and 101,000 square feet, respectively. The administrative office lease expires in July 2014 and the warehouse lease expires in December 2014. Additionally, we lease an administrative office in Quito, Ecuador of 829 square feet under a month-to-month lease.
 


Properties in Peru
 
 
 
 
26

 
 
We currently have rights to four properties in northwest Peru. We have working interests in license contracts for 51% in Block Z-1, 100% in Block XIX, 100% in Block XXII and 100% in Block XXIII. The license contracts afford an initial exploration phase of seven years.  As described below, each license contract provides for additional exploration periods which can extend the exploration phase of the license contract.  If exploration efforts are successful, the license contracts 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 acres.

The following table is a summary of our properties in northwest Peru. As of December 31, 2012, 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
                11
              5.6
Block XIX
Tumbes/Talara
100%
December 2003
       473,000
       473,000
       
Block XXII
Lancones/Talara
100%
November 2007
       912,000
       912,000
       
Block XXIII
Tumbes/Talara
100%
November 2007
       230,000
       230,000
       
Total
     
    2,169,200
    1,897,642
           800
           408
                11
              5.6
 

(1)
Does not include the CX11-16X well which tested quantities of gas which we believe to be of commercial amounts and is currently shut-in. Until such time as sufficient funding has been secured and the necessary infrastructure is in place for our gas-to power project, we cannot classify any of these reserves as proved SEC reserves nor refer to the well as productive.

(2)
Includes all oil producing wells we have developed.  At December 31, 2012, seven gross (3.6 net) wells were under production and four gross (2.0 net) wells were producing intermittently.

(3)
Does not include the CX11-22D or A-12F wells as these wells have been converted to either water or gas reinjection wells.

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 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 is located in the East Corvina prospect field and, based on the engineering study, is not suitable for our future development plans and therefore requires us to build a new platform prior to initiating any drilling activities in this section of the Corvina field. The second platform, CX-11, is located in the West Corvina development field and is currently being used in our West Corvina drilling and production activities.  All five of the previously drilled wells in the Corvina field encountered indications of natural gas and apparent reservoir-quality formations.  In September 2012, our new CX-15 platform was anchored at the West Corvina field location, one mile south of the existing CX-11 platform.  On November 8, 2012, we received an environmental permit from the DGAAE allowing us to begin the drilling and subsequent operation of all production and injection facilities on the new CX-15 platform at the Corvina field.
 
In the Albacora field, three wells were drilled and produced oil for a very limited time. The original drilling and production platform set up by Tenneco Inc. during this period is still in place in the Albacora field and has been repaired, refurbished and placed into service by us. The Albacora field is located in the northern part of our offshore Block Z-1.  It consists of approximately 7,500 gross acres and, is located in water depths of less than 200 feet.

 
27

 
 
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, while the other well encountered abnormally high pressures and was abandoned for mechanical reasons prior to reaching its intended total depth.  After conducting engineering feasibility studies, we have determined the existing platform located in the Piedra Redonda field is not suitable for our future development plans and therefore we must consider other options for development in this field.  In any development plan, we do not expect to recomplete the previously drilled and completed well by Belco due to our uncertainty of the mechanical condition and potentially high wellhead pressure of the well.

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

In December 2012, we completed the sale of a 49% participating interest in the Block Z-1 license contract to Pacific Rubiales.  We now own 51% participating interest in Block Z-1.
 
Although Perupetro denied our request to extend the exploration phase by three years, the Block Z-1 License Contract permits us to keep the current contract area, provided we commit to additional exploration activities every two years, for a maximum period of up to six years.  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 contract area.  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 approval date of the environmental permit.
 
A performance bond of $1.0 million was posted for cash collateral of $1.0 million related to the fourth exploration period. The performance bond will be released at the end of the exploration period if the work commitment for that period has been satisfied. In 2012, we completed sufficient 3-D seismic to satisfy the requirement of the fourth exploration period.  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. 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.
 
 
28

 
 
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 the fields discovered and the surrounding five kilometer areas for the remainder of the contract life. Currently, we plan to continue our exploration activities to retain the additional area in Block Z-1.

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, the Mancora formation is expected 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 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. 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.  Once approval is obtained, we will reestablish timelines for the remaining exploration periods.
 
As of December 31, 2012, we had a $585,000 bond posted for $292,500 in cash collateral as required under the license contract. The fifth exploration period will require a performance bond of $585,000. The performance bond amounts are not cumulative, and will be released at the end of each exploration period if the work commitment for that period has been satisfied. In addition, we are required to make technology transfer payments related to training costs of Perupetro professional staff during the exploration phase in the amount of $5,000 per year. We must declare a commercial discovery no later than the end of the last exploration period, including any extensions or deferments in order to retain the block.

Under the terms of the Block XIX License Contract, we are required to relinquish 20% of the least prospective licensed acreage by the end of the fourth exploration period.  Accordingly, we intend to retain the most prospective 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 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 a well. Once approval is obtained, we will reestablish timelines for the remaining exploration periods. Drilling of the well in Block XXII is not expected to begin earlier than late 2014.   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.  Royalties start at 15% if production is less than 5,000 Boepd and are capped at 30% if production surpasses 100,000 Boepd.

 
29

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

Under the Block XXII License Contract, we are required to relinquish at least 20% of the least prospective original agreement area at the end of the third period and at least another 30% of the original agreement area 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; however, the 18-month timeframe to conduct exploration activities is on suspension until an approval of an environmental impact study, by the DGAAE in order to drill a well is obtained.  The environmental assessment was approved in January 2013.  We will reestablish timelines for the remaining exploration periods. 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.  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 $3,390,000 that is secured by cash collateral in the amount of $1,695,000. 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 XXIII License Contract, we are required to relinquish 20% of the least prospective original agreement area at the end of the third period and at least another 30% of the original agreement area at the end of the fourth period such that at the end of the fourth period, we will have released 50% of the original agreement area. Accordingly, we intend to retain the most prospective acreage identified.  The contract does not call for any additional relinquishment of acreage within the contract area and we may retain the remaining un-relinquished area for the remainder of the contract life provided we continue executing an exploration work program as defined under the license contract.  If we decide not to continue this exploration work program, we will only be allowed to keep the fields discovered and the surrounding five kilometer areas for the remainder of the contract life.

Proved Reserves

Our estimated proved oil reserve quantities were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers.  NSAI was chosen based on its knowledge and experience of the region in which we operate.  Numerous uncertainties arise in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures.  These uncertainties are greater for properties which are undeveloped or have a limited production history, such as our properties in Northern Peru.  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” 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.

 
30

 
 
As of December 31, 2012, 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, 2012
Based on Average First Day-of-the-Month Fiscal-Year Prices

   
Actual
   
Estimated
 Future Capital
Expenditures
 
   
(In MBbls)
   
(In thousands)
 
Proved Developed Producing
    1,679     $ 1,020  
Proved Developed Not Producing
    446       102  
Proved Undeveloped
    14,301       80,292  
Total
    16,426     $ 81,414  
                 
Standardized Measure of Discounted Future Net Cash Flows, Discounted @ 10% (in thousands)
  $ 891,313          
 
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, effective December 31, 2009, 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.  
 
As of December 31, 2012, we did not have any proved undeveloped reserves previously disclosed that have remained undeveloped for five years or more.

Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process

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

Our Chief Operating Officer is responsible for compliance in reserves bookings and utilizes the reserves estimates made by our third party reserve consultant, NSAI, for the preparation of our reserve report. Our Chief Operating Officer is a chemical engineer with over 36 years of supervisory and operating experience in the domestic and international oil and gas industry.  He holds a Bachelor of Science in Chemical Engineering Degree from Louisiana State University.

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. 

 
31

 
 
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 Smith and Mr. John Hattner.  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 30 years of practical experience in petroleum engineering and 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. Hattner has been practicing consulting petroleum geology at NSAI since 1991.  Mr. Hattner is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 559) and has over 30 years of practical experience in petroleum geosciences, with over 20 years experience in the estimation and evaluation of reserves.  He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary's College of California in 1989 with a Master of Business Administration Degree.  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’s revised rules, effective as of year-end 2009 reporting, expanded the technologies that a company can use to establish reserves. The SEC now 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, 2012, we had proved reserves of 16.4 MMBbls which represents a decrease from the proved reserves at December 31, 2011 of 34.7 MMBbls.  In December 2012, we completed the sale of a 49% participating interest in the Block Z-1 license contract.  This resulted in sales of reserves in place of 16.4 MMbls of proved reserves. We now own a 51% participating interest in Block Z-1.  The proved reserves associated with proved developed producing wells decreased by 2.8 MMBbls to 1.7 MMBbls in 2012 from 4.5 MMBbls in 2011.  Reductions to proved developed non–producing reserves were 1.7 MMBbls, bringing the total of proved developed non–producing reserves at December 31, 2012 to 0.4 MMBbls compared to 2.1 MMBbls in 2011.  The reserves associated with proved undeveloped areas decreased by 13.8 MMBbls to 14.3 MMBbls at December 31, 2012 from 28.1 MMBbls in 2011.

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)
 
                   
2012
    1,187.8     $ 103.31     $ 44.16  
2011
    1,379.6     $ 101.01     $ 36.82  
2010
    1,517.7     $ 72.53     $ 21.47  
                         
(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.
 
 
 
32

 

Acreage; Productive Wells

The following table shows approximately the number of developed and undeveloped acres as of December 31, 2012:

   
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, 2012, 2011 and 2010 were 11.0 gross (5.6 net), 11.0 (gross and net) and 10.0 (gross and net), respectively.

Drilling Activity

The number of gross and net productive oil wells drilled in 2012, 2011 and 2010 were none, 2.0 (gross and net), and 3.0 (gross and net), respectively.  We did not drill any exploratory wells or have any dry holes in 2012.  We drilled one  exploratory well (gross and net) in 2011, the PLG-1X, which we deemed to be a dry hole in the fourth quarter 2011.  We drilled one exploratory well (gross and net) in 2010, the A-17D, which we deemed to be a dry hole in September 2010.  In connection with the declaration as a dry hole of the A-17D well, we also wrote off the two previous attempts to drill this well, the A-15D (gross and net) and the A-16D (gross and net) wells.

2013 Activities

Block Z-1

Corvina Field

The timing of the first well spud at the CX-15 platform is now expected to occur in March 2013 or April 2013, with first oil production expected during second or third quarter of 2013.

The CX-11 workover program has also been affected by the delays in the pipe laying project in Corvina related to barge logistics and has resumed in February 2013.
 
We expect to obtain and install a Lease Automatic Custody Transfer unit for use at the Corvina field in the second quarter of 2013.  The LACT unit will be installed on a double hull floating storage and offloading vessel which will be anchored in the Corvina field.

Albacora Field

The existing contract for the Petrex 18 rig has been renegotiated to allow for improved day rates and cancellation terms, and availability to use it should the new 3-D seismic data dictate a return to drilling.
 
 
33

 

Block Z-1 Seismic Acquisition

The 3-D seismic acquisition on the remaining areas of Block Z-1 commenced in September 2012, with completion in February 2013.

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.  An environmental assessment is currently being prepared to obtain an environmental permit for the additional seismic work.
 
The data room for Block XIX has been open, with Credit Suisse Securities (USA) LLC managing the formal process to find a joint venture partner for this onshore block.  Interested partners have been reviewing the data.

Block XXII

The timing of the actual drilling on Block XXII will depend on approval of the environment assessment, which is currently being prepared, and subsequent receipt of the necessary ancillary permits.  Drilling on Block XXII is expected no earlier than 2014.

Block XXIII

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 was approved in January 2013.  Drilling on Block XXIII is expected during the second half of 2013.

The data room for Block XXIII has been open, with Credit Suisse Securities (USA) LLC managing the formal process to find a joint venture partner for this onshore block.  Interested partners have been reviewing the data.

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 Ecuador (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. The agreement covering the property extends through May 2016.
 
ITEM 3. LEGAL PROCEEDINGS

Navy Tanker Litigation

On October 24, 2007, Tecnomarine SAC, a contractor to BPZ E&P, entered into two short-term agreements with the Peruvian Navy’s commercial branch to charter two small tankers for use in our offshore oil production operation.  On January 30, 2008, one of the tankers, the Supe, sank after catching fire. Neither of the Peruvian governmental agencies charged with investigating the incident found fault with Tecnomarine SAC or our subsidiary, BPZ E&P.  A lawsuit was nonetheless filed on December 18, 2008 in the 152nd Judicial District Court of Harris County, Texas by two crewmembers and the family and estate of two deceased sailors injured in the incident, claiming negligence and gross negligence on the part of BPZ Resources, Inc. and BPZ Energy, Inc. (now known as BPZ Energy LLC), parent entities of BPZ E&P, that were not parties to the charter agreement and were not involved in the operations.
 
On May 8, 2012, the 152nd Judicial District Court of Harris County, Texas dismissed Plaintiffs’ lawsuit against BPZ Resources, Inc. and BPZ Energy, Inc., granting defendants’ motion to dismiss on the basis of forum non conveniens.  The order is conditioned upon the Peruvian Courts accepting jurisdiction over the matter.

On March 4, 2013, we settled all significant claims brought by the crewmembers of the Supe, and this matter is now substantially concluded.  The naval officer in charge of the Supe at the time of the incident did not settle his potential claims; however, the Company views any potential liability arising from the claims of the officer in charge of the Supe as remote.

 
34

 
 
ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.
 
 
35

 
 
PART II

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

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

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

   
High
   
Low
 
             
2012
           
Fourth quarter
  $ 3.20     $ 2.22  
Third quarter
    3.40       2.01  
Second quarter
    4.64       2.09  
First quarter
    4.34       2.69  
                 
2011
               
Fourth quarter
  $ 3.54     $ 2.40  
Third quarter
    4.38       2.07  
Second quarter
    5.57       2.91  
First quarter
    6.83       4.41  


 
Holders

As of February 28, 2013, we had approximately 148 shareholders of record, and an estimated 13,154 beneficial owners of our common stock.

Dividends

We currently intend to retain all future earnings to fund the development and growth of our business.  We have never paid cash or other dividends on our stock.  In addition, our $40.0 million secured debt facility and our $75.0 million secured debt facility restrict us from paying dividends until after the Pacific Rubiales Farm-Out Settlement Date (as defined therein) so long as immediately before the dividend payment is made and immediately after giving effect to the dividend on a pro forma basis there is no default and the consolidated leverage ratio for the most recently ended fiscal quarter and the three immediately preceding fiscal quarters is less than 0.75:1.00.
 
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.
 
 
36

 
 
Securities Authorized for Issuance Under Equity Compensation Plans

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

Performance Graph

The following graph compares the cumulative total shareholder return for the our Common Stock to that of (i) the Russell 2000 Stock Index, and (ii) two customized peer groups, the 2012 Peer Group Composite and the 2011 Peer Group Composite.  The companies included in the 2012 Peer Group Composite are Endeavor International Corp., Crimson Exploration Inc., 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..  The companies included in 2011 Peer Group Composite, adjusted for the effects of industry consolidation, are Contango Oil & Gas, Co, Harvest Natural Resources, Inc., Far East Energy Corp, and Carrizo Oil & Co Inc.  The Company has chosen to change the performance index from that used in the Company’s 2011 Form 10-K, the 2011 Peer Group Composite, to the 2012 Peer Group Composite because it believes that the 2012 Peer Group represents companies of similar size or geographic focus and the impact of the acquisition of one of the companies that was in the 2011 Peer Group Composite.  “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, 2007 in our Common Stock, the Russell 2000 Stock Index, the 2011 Peer Group Composite and the 2012 Peer Group Composite.
 
 
    2007     2008     2009     2010     2011     2012  
BPZ Resources, Inc.   $ 100     $ 57     $ 85     $ 43     $ 25     $ 28  
Russell 2000 Stock Index     100       65       82       102       97       111  
2011 Peer Group Composite     100       65       67       88       77       62  
2012 Peer Group Composite     100       71       66       111       115       62  
 
 
37

 

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:
 
2012
   
2011
   
2010
   
2009
   
2008
 
                               
   
(In thousands, except per share and per barrel information)
 
Total net revenue
  $ 122,958     $ 143,740     $ 110,464     $ 52,454     $ 62,955  
                                         
Operating and administrative expenses:
                                 
Lease operating expense
    52,458       50,792       32,585       28,113       11,649  
General and administrative expense
    31,806       38,600       32,655       33,258       42,094  
Geological, geophysical and engineering expense
    40,686       9,315       19,107       7,768       794  
Dry hole costs
    -       13,082       32,778       -       -  
Depreciation, depletion and amortization expense
    45,873       38,944       33,755       25,803       16,062  
Standby costs
    5,340       4,529       7,487       -       -  
Other expense
    2,266       -       12,889       -       -  
Gain on divestiture
    (26,864 )     -       -       -       -  
                                         
Total operating  and administrative expenses
    151,565       155,262       171,256       94,942       70,599  
                                         
Operating loss
    (28,607 )     (11,522 )     (60,792 )     (42,488 )     (7,644 )
                                         
Other income (expense):
                                       
Income from investment in Ecuador property, net
    62       412       740       1,208       718  
Interest expense
    (16,115 )     (19,772 )     (11,618 )     -       -  
Loss on extinguishment of debt
    (7,318 )     -       -       -       -  
Loss on derivatives
    (2,610 )     (2,046 )     -       -       -  
Interest income
    44       453       272       215       319  
Other income (expense)
    (159 )     1,083       19       (1,312 )     102  
                                         
Total other income (expense)
    (26,096 )     (19,870 )     (10,587 )     111       1,139  
                                         
Loss before income taxes
    (54,703 )     (31,392 )     (71,379 )     (42,377 )     (6,505 )
                                         
Income tax expense (benefit)
    (15,614 )     2,435       (11,608 )     (6,575 )     3,141  
                                         
Net loss
  $ (39,089 )   $ (33,827 )   $ (59,771 )   $ (35,802 )   $ (9,646 )
                                         
Basic and diluted net loss per share
  $ (0.34 )   $ (0.29 )   $ (0.52 )   $ (0.35 )   $ (0.12 )
                                         
Basic and diluted weighted average common shares outstanding
    115,631       115,367       114,919       103,362       77,390  
                                         
Oil sales price per barrel, net
  $ 103.31     $ 101.01     $ 72.53     $ 54.49     $ 76.23  
Operating cost per barrel
  $ 44.16     $ 36.82     $ 21.47     $ 29.21     $ 14.11  
                                         
Balance Sheet Data:
                                       
Working Capital/(Deficit)
  $ 58,839     $ 49,180     $ 22,703     $ 7,385     $ (30,562 )
Property, equipment and construction in progress, net
    238,557       381,602       342,507       262,517       193,934  
Total assets
    527,430       537,333       470,307       349,172       235,365  
Total long-term debt
    197,160       248,384       156,750       22,581       15,018  
Stockholders' equity
    186,300       222,452       251,326       271,957       159,180  
                                         
Cash Flow Data:
                                       
Cash flow provided by (used in) operating activites
    (46,062 )     47,121       (5,125 )     (30,785 )     48,722  
Cash flow provided by (used in) investing activities
    (65,838 )     (93,883 )     (158,104 )     (90,005 )     (102,185 )
Cash flow provided by (used in) financing activities
    137,268       93,182       156,834       133,620       51,266  
 
 
38

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

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

Overview

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

Our current activities and related planning are focused on the following objectives:
 
 
·
Optimizing oil production in the Corvina and Albacora fields in Block Z-1;
 
 
·
Initiating an offshore drilling campaign from the new CX-15 platform;
 
 
·
Processing and analyzing the data from the three dimensional (“3-D”)  seismic survey in Block Z-1 to guide further exploration and development activities within the block;
 
 
·
Transitioning the technical, including field, operations in Block Z-1 to our partner in the block, Pacific Rubiales;
 
 
·
Continuing acquisition, processing and interpretation of seismic data both onshore and offshore to better understand the characteristics and potential of our properties;
 
 
·
Planning and permitting an on-shore drilling campaign to explore and appraise our properties 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 Corvina but for which no market has yet been secured and related financing has yet to be obtained.

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

Extended Well Testing Regulation
 
On December 13, 2009, legislation regulating well testing in Peru became effective under a Supreme Decree issued by the government of Peru.  The regulation provides that all new wells may be placed in production testing for up to six months.  If the operator believes additional time for testing is needed to properly evaluate the productive capacity of the field, and can technically justify such need, a request for the well to enter into an EWT period must be submitted to the DGH, the agency of the Peruvian Ministry of Energy and Mines responsible for regulating the optimum development of oil and gas fields.  After the initial six-month period or after an approved EWT program expires, the operator will be required to have the necessary gas and water reinjection equipment in place to continue producing the well according to existing environmental regulations.  Additionally, during both the initial six-month testing period and any extended period that may be granted, we must also obtain gas flaring permits for each well in order for us to be in compliance with Peruvian environmental legislation.

 
39

 
 
Block Z-1 Transition into Commercial Production
 
The Corvina field was put into commercial production on November 30, 2010 in accordance with the revised First Date of Commercial Production approved by Perupetro, and is no longer subject to the EWT regulations described above.

Albacora Extended Well Testing Program
 
We installed and commissioned all the necessary equipment for the reinjection of gas and produced water on the Albacora platform and 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.
 
Environmental Permit for the CX-15 Platform at the Corvina Field

In September 2012, our new CX-15 platform was anchored at the West Corvina field location, one mile south of the existing CX-11 platform.

On November 8, 2012, we received an environmental permit from the DGAAE allowing us to begin the drilling and subsequent operation of all production and injection facilities on the new CX-15 platform at the Corvina field.
 
The timing of the first well spud at the CX-15 platform is now expected to occur in late March 2013 or early April 2013, with first oil production expected during second or third quarter of 2013.
 
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.  This assessment could result in increased emphasis and activities on a given prospect and conversely, could result in decreased emphasis on a given prospect for a period of time.  In particular, we will assess allocation of our current resources among the Corvina, Albacora, and other Block Z-1 prospects and certain onshore prospects as they develop, along with our gas-to-power project.
 
Block Z-1

The Block Z-1 License Contract provides for an initial exploration phase of seven years, and exploration can continue in the exploitation phase for an additional six years.  Each period has a commitment for exploration activities and requires a financial guarantee to secure the performance of the work commitment during such period.  Block Z-1 was in the fourth exploration period in 2012.  In January 2013, after Perupetro denied our request to extend the exploration phase, we moved to the exploitation period in Block Z-1.
 
Divestiture
 
On April 27, 2012, we and Pacific Rubiales (together with its subsidiaries) executed a SPA under which we formed an unincorporated joint venture relationship 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 in Block Z-1 and agreed to fund $185.0 million of our share of capital and exploratory expenditures in Block Z-1 (the “carry amount”) 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 had agreed to provide us 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 the completion of the contractual arrangements.

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

 
40

 
 
At closing, Pacific Rubiales exchanged certain loans along with an additional $85.0 million, plus any 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 resulted in a gain on the sale that was recognized as a component of operating and administrative expenses in connection with the closing of $26.9 million.  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 an effective date of January 1, 2012 and prior to the closing which was effective on December 14, 2012.  These amounts were considered settled by adjusting down by $18.3 million the unused portion of the agreed carry amount of $185.0 million by Pacific Rubiales for our share of capital and exploratory expenditures in Block Z-1.  At December 31, 2012 the carry amount was $126.3 million.

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

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.  The Corvina field consists of approximately 47,000 acres in water depths of less than 300 feet.  We have completed a total of nine gross (4.6 net) oil wells, the CX11-23D, the CX11-22D, the CX11-17D, the CX11-19D, the CX11-15D, the CX11-21XD, the CX11-20XD, the CX11-18XD and the CX11-14D wells, some of which are currently being used as gas injection and/or water injection wells.  Produced oil is kept in production inventory until such time that 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. 
 
Since the initiation in late 2011, the Corvina gas cap reinjection program has shown positive results.  This gas cap reinjection program has been combined with ongoing artificial lift measures at both fields to optimize our oil production.  During 2012, we began a new six-well workover program at the Corvina CX-11 platform using a conventional workover rig, the Petrex 10, at an estimated total cost of $12 million to optimize production. The workover program, among other objectives, was intended to and did correct a mechanical problem in one of the two active CX-11 gas reinjection wells that was affecting the performance of two oil producing wells. This mechanical problem started in early July 2012, and reduced the field's production to approximately 2,000 bopd gross. This workover program began in August 2012 and the work on the CX-11-19D well was successful in decreasing gas production and allowing improved oil production rates.  At December 31, 2012 Corvina oil production was approximately 2,300 bopd gross.  The Petrex 10 workover rig was on standby awaiting completion of the pipe laying work in the Corvina field well at December 31, 2012.  It is now in use on the CX-11 platform.
 
Fabrication of the new CX-15 platform was completed in the Wison Nantong yard in China.  The CX-15 platform has 24 drilling slots and comes with all of the required production and reinjection equipment. The platform and additional ancillary equipment was shipped to Peru for installation at Corvina.  The CX-15 platform was set in the second half of September 2012. On November 8, 2012, we received an environmental permit from the DGAAE allowing us to begin the drilling and subsequent operation of all production and injection facilities on the new CX-15 platform at the Corvina field.  We are installing three pipelines between the two Corvina platforms and one pipeline from the CX-15 platform to the pipeline end manifold and the floating storage and offloading vessel.  We experienced difficulties with the installation of these pipelines due to mechanical issues with the pipe laying barge and unexpected strong deep currents in the Corvina field that significantly delayed divers from completing key tasks during the pipe laying project.  The timing of the first well spud at the CX-15 platform is now expected to occur in March 2013 or April 2013, with first oil production expected during second or third quarter 2013.
 
 
41

 
 
Further, we are working on obtaining and installing a Lease Automatic Custody Transfer (“LACT”) unit at the Corvina field to meet the agreed date to comply with applicable regulations.  We expect to obtain and install the LACT unit in the second quarter of 2013 on a floating storage and offloading vessel.

Many of the Corvina oil wells have seen initial production decline rates of approximately 50% during the first year of production before stabilizing. Although each of the Corvina 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, they 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. The representative rates of production decline remain to be determined, because the effective production mechanism in the Corvina field has yet to be fully understood, although we believe that our recent initiation of gas reinjection into the gas cap is helping to slow production decline rates. Further, our ability to produce indicated reserves in Corvina depends on our ability to finance our continued operations and get our produced oil to market.  Any failure in meeting these requirements could negatively affect our indicated reserves and their value as reported under 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.

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 200 feet. We currently have completed a total of four gross (2.0 net) oil wells.  We had been producing oil from the Albacora field from December 2009 through late October 2012 under various EWT permits.
 
The EWT permit, obtained in July 2011, was granted based upon having new zones opened to enable additional testing from October 1, 2011 through February 2012.  Additional zones were opened in the A-14XD, A-13E and A-9G wells mentioned above.  In the A-14XD well, a deeper zone was opened and comingled with the previous completion causing the well to produce formation water from a deeper zone.  Subsequently, plugs were set to isolate the zone that produced water and a two hydraulic jet pump installed to temporarily assist the well with production.  That well has since recovered to normal production rates.  At the same time we were conducting interference testing during the third quarter of 2011, well work was completed on the pre-existing A-12F well to convert it to a dual purpose well, and on the A-17D well to convert it to a water injector.  The costs associated with these wells were capitalized.
 
In 2012, with the EWT permit and the use of hydraulic jet pumps, production has increased for the A-14XD, A-13E and the A-9G wells in 2012 compared to 2011.  The A-12F well has been primarily used as a gas injector.

Installation of the Albacora gas and water reinjection equipment was completed 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 gas and water reinjection equipment is operating in a routine manner now.  In addition, our request was granted by the General Directorate of Hydrocarbons (“DGH”) to permit testing on the A-12F well to allow a determination to be made whether to use this well as either a gas injector or oil producer.
 
In addition, we completed the 3-D seismic survey of the area to assess our prospects before conducting further drilling operations, as well as to comply with our exploration commitments under our license contracts. On November 3, 2011, we received the environmental permit to acquire approximately 1,600 square kms of 3-D seismic data in our offshore Block Z-1 that was granted by the DGAAE.  The seismic survey began in the first quarter of 2012.  A second seismic boat was contracted to acquire the remaining areas where the CGGVeritas Vantage vessel was unable to safely navigate.  Processing the seismic data acquired to date is underway by Fugro Seismic Services.  The 3-D seismic acquisition on the remaining areas of Block Z-1 commenced in September 2012, with completion in February 2013.
 
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.  An environmental assessment is currently being prepared to obtain an environmental permit for the additional seismic work.
 
 
42

 
 
Block XXII
 
As a result of the 258 kms 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 plan an additional 2-D seismic program in 2013, after receipt of the necessary environmental permits.
 
We have notified Perupetro that our commitment for the second exploration period will be the drilling of one well.  The timing of the actual drilling will depend on approval of the environment assessment, which is currently being prepared, and subsequent receipt of the necessary ancillary permits.  Drilling on Block XXII is expected no earlier than 2014.
 
Block XXIII
 
For Block XXIII, in 2011 we acquired approximately 370 square kms of 3-D seismic data and 312 kms 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 the Block is completed and is being 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 was approved in January 2013.
 
We are now in the second exploration period.  Drilling on Block XXIII is expected during the second half of 2013.

Marine Operations
 
During 2012 we chartered one vessel to a third party for approximately two weeks in January, two marine vessels to a third party for approximately one week in September.  We also provided barge construction supervision to a third party in October, November and December 2012.
 
Gas-to-Power Project
 
Our gas-to-power project entails the installation of an approximately 10-mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and a 135 megawatt (“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, after the Peruvian government completes its expansion, is expected to be 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 (known as “COES”). 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 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 only retain a minority position in the project. 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 move forward with the project.
 
 
43

 
 
Financing Activities
 
$75.0 Million Secured Debt Facility
 
In April 2012, we, through our subsidiaries, entered into an amendment of the $75.0 million secured debt financing (the “$75.0 million secured debt facility”) with Credit Suisse.  Pursuant to the amendment, we made a $40.0 million voluntary principal prepayment, together with accrued and unpaid interest, of the $75.0 million secured debt facility. In connection with the prepayment, we incurred a prepayment fee of $5.8 million payable in four equal installments, the first of which was paid on the prepayment date and the remaining of which were paid on the specified interest payment dates in July 2012, October 2012 and January 2013.  The amendment to the $75.0 million secured debt facility also extended the maturity of the facility to July 2015, with revised principal repayments due in quarterly installments that range from $2.0 million to $4.5 million commencing in January 2013 and extending through July 2015.  In connection with the Closing Letter Agreement, we entered into an amendment of the credit agreements in place with Credit Suisse AG, Cayman Island Branch to effect the transfer and Completion as described in the Closing Letter Agreement.  As was previously anticipated in the fourth amendments to the credit agreements, we were required to fund the debt service reserve accounts related to the credit agreements in the amounts of outstanding principal.  For further information regarding the $75.0 million secured debt facility see “Liquidity, Capital Resources and Capital Expenditures” below.
 
$40.0 Million Secured Debt Facility
 
Also, in April 2012, we, through our subsidiaries, entered into an amendment to the $40.0 million secured debt financing (the “$40.0 million secured debt facility”) with Credit Suisse.  The amendment sets a revised principal repayment schedule such that we are scheduled to repay the outstanding principal amount of each loan in eleven consecutive quarterly installments on the respective payment dates beginning in July 2012, thereby extending the maturity to January 2015.  The $40.0 million secured debt facility has a revised annual interest rate of the three month LIBOR rate plus 8%. In connection with the Closing Letter Agreement, we entered into an amendment of the credit agreements in place with Credit Suisse AG, Cayman Island Branch to effect the transfer and Completion of the transfer of a 49% participating interest in Block Z-1 as described in the Closing Letter Agreement.  As was previously anticipated in the fourth amendments to the credit agreements, we were required to fund the debt service reserve accounts related to the credit agreements in the amounts of outstanding principal. For further information regarding the $40.0 million secured debt facility see “Liquidity, Capital Resources and Capital Expenditures” below.

Pacific Rubiales Loans

On April 27, 2012, we and Pacific Rubiales executed a SPA where 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 in Block Z-1 and agreed to fund $185.0 million of the our share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012 (together, the “Pacific Rubiales Loans”).  Until the required approvals were obtained, Pacific Rubiales had agreed to provide us $65.0 million and other funds as loans to continue to fund our Block Z-1 capital and exploratory activities.  These amounts were reflected as long-term debt prior to the completion of the contractual arrangements.

On December 14, 2012 Perupetro approved the terms of the amendment to the Block Z-1 license contract to recognize the sale of a 49% participating interest, in offshore Block Z-1 to Pacific Rubiales.  We and Pacific Rubiales waived and modified certain contract conditions in order to close the transaction.  On December 30, 2012, the Peruvian Government signed the Supreme Decree for the execution of the amendment to the Z-1 license contract.
 
At closing, Pacific Rubiales exchanged certain loans along with an additional $85.0 million, plus any 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.
 
We also reflected $19.9 million as other current liabilities and $20.8 million as other non-current liabilities for exploratory expenditures related to Block Z-1 under funding by Pacific Rubiales of the exploratory expenditures in Block Z-1 incurred in 2012.  This amount will be settled by the Company and Pacific Rubiales under the terms of the SPA.
 
 
44

 
 
Future Market Trends and Expectations
 
 Our business depends primarily on the level of current and future oil and gas demand and prices which may impact our ability to raise capital to finance the development of our current and future oil and gas opportunities, to continue developing our gas-to-power project, which anchors our gas monetizing strategy, and to maintain our commitments and obligations under our current and possible future license contracts.  The world economies are continuing on the path to recovery, though at a gradual pace. Many believe that, while the worst of the financial crisis seems to be over, the global economy remains delicate. Growth has resumed, but is modest and downside risks remain significant. However, if crisis risks do not materialize and financial conditions continue to improve, global growth could be stronger than projected.   Global economic growth drives demand for energy from all sources, including fossil fuels.  A lower future economic growth rate could result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.

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

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

In response to our current economic environment, for 2013, we have decided to focus on oil development in Block Z-1 with our Block Z-1 partner, specifically in the Corvina and Albacora fields and monitor operating and general and administrative expenses in an effort to enhance shareholder value.
 
From a production perspective, our goal is to increase production during 2013 based on beginning what is expected to be a multi-year drilling program from the CX-15 platform.
 
Expected operational cash flow from Corvina and Albacora oil sales as well as the proceeds from the sale of a 49% participating interest in Block Z-1 should contribute towards funding the 2013 capital expenditures budget.  Our 2013 Block Z-1 capital expenditures budget should be fully funded by our partner under the carry agreement in place.   In addition, we will continue to evaluate our options on additional financing as needed. We anticipate future results will be based on our production levels and current and future oil prices. When forecasting our 2013 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.
 
 
45

 
 
Results of Operations
 
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

   
Year Ended
December 31,
       
   
2012
   
2011
   
Increase/ (Decrease)
 
Net sales volume:
 
(in thousands except per bbl information)
       
Oil  (MBbls)
    1,188       1,380       (192 )
                         
Net revenue:
                       
Oil revenue, net
  $ 122,708     $ 139,354     $ (16,646 )
Other revenue
    250       4,386       (4,136 )
Total net revenue
    122,958       143,740       (20,782 )
                         
Average sales price (approximately):
                       
Oil (per Bbl)
  $ 103.31     $ 101.01     $ 2.30  
                         
Operating and administrative expenses:
                       
Lease operating expense
    52,458       50,792       1,666  
General and administrative expense
    31,806       38,600       (6,794 )
Geological, geophysical and engineering expense
    40,686       9,315       31,371  
Dry hole costs
    -       13,082       (13,082 )
Depreciation, depletion and amortization expense
    45,873       38,944       6,929  
Standby costs
    5,340       4,529       811  
Other  expense
    2,266       -       2,266  
Gain on divestiture
    (26,864 )     -       (26,864 )
Total operating and administrative expenses
  $ 151,565     $ 155,262     $ (3,697 )
                         
Operating loss
  $ (28,607 )   $ (11,522 )   $ (17,085 )
 
Net Oil Revenue

For the year ended December 31, 2012, our net oil revenue decreased by $16.7 million to $122.7 million from $139.4 million for the same period in 2011.  The decrease in net oil revenue is due to a decrease in the amount of oil sold of 192 MBbls, partially offset by an increase of $2.30, or 2.3%, in the average per barrel sales price received.

The 2012 price/volume analysis is as follows:
 
   
(in thousands)
 
2011 Oil revenue, net
  $ 139,354  
Changes associated with sales volumes
    (19,377 )
Changes associated with prices
    2,731  
2012 Oil revenue, net
  $ 122,708  
 
For the year ended December 31, 2012 we had consistent oil production from seven gross (3.6 net) producing wells and intermittent production from four gross (2.0 net) wells.  During the same period in 2011, we had consistent oil production from five (gross and net) producing wells and intermittent production from six (gross and net) wells.  Total oil production for the year ended December 31, 2012 was 1,185 MBbls compared to 1,376 MBbls for the same period in 2011.  The transfer of a 49% participating interest in Block Z-1 to Pacific Rubiales was effective on December 14, 2012 and the entitlement to crude oil production from that day forward was allocated to each partner.  The sharing of any production prior to that date was handled as an adjustment to the carry amount under the SPA.  Total sales for the year ended December 31, 2012 was 1,188 MBbls compared to 1,380 MBbls for the same period in 2011.

 
46

 
 
The decrease in oil production in 2012 is due to higher than expected decline rates in oil production in the Corvina field, a mechanical problem in one of the two active CX-11 gas reinjection wells that was affecting the performance of two oil producing wells in the Corvina field and our recent sale of a 49% participating interest in Block Z-1, partially offset by higher oil production 2012 from the Albacora field due to the availability of the EWT permit and the use of hydraulic jet pumps.

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, 2012 and 2011:
 
       
   
2012
   
2011
 
   
(in thousands)
 
Royalty costs
  $ 6,605     $ 7,469  
 
  $ 6,605     $ 7,469  
 

Other Revenue

For the year ended December 31, 2012, other revenue decreased $4.1 million to $0.3 million from $4.4 million for the same period in 2011.  During the year ended December 31, 2012 we chartered one vessel to a third party for approximately two weeks in January, and two marine vessels to a third party for approximately one week in September.  During the year ended December 31, 2011, we chartered one marine vessel to a third party for a nine-month period and another marine vessel for a twelve-month period.

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, 2012, lease operating expenses increased by $1.7 million to $52.5 million ($44.16 per Bbl) from $50.8 million ($36.82 per Bbl) for the same period in 2011.  The increase in the lease operating expenses is due to increased repair and maintenance expenses of $2.1 million, increased lease operating costs associated with oil inventory of $1.5 million, increased contract services of $1.4 million, increased insurance costs of $0.5 million, increased salary expenses of $0.5 million, increased security expense of $0.5 million, increased equipment rental expense of $0.4 million and increased other lease operating expenses of $0.7 million, partially offset by lower workover costs of $5.9 million.  We expect lease operating expense to decrease in 2013 due to our recent sale of a 49% participating interest in Block Z-1.  The transfer of a 49% participating interest in Block Z-1 to Pacific Rubiales was effective on December 14, 2012 and the sharing of lease operating expenses began from that day forward and was allocated to each partner. The sharing of any lease operating expenses prior to that date was handled as an adjustment to the carry amount under the SPA.

The following details the significant items contributing to the increase in lease operating expense of $2.8 million for the year ended December 31, 2012 compared to the year ended December 31, 2011:

Repairs and maintenance: For the year ended December 31, 2012, repairs and maintenance expense increased $2.1 million compared to the same period in the prior year.  The increase in repairs and maintenance expense is primarily due to increased support vessel services of $4.2 million and higher platform maintenance of $1.2 million.  These costs were partially offset by lower non-recurring incident charges of $2.0 million, lower drydocking costs of $1.1 million and lower other repair and maintenance activities of $0.2 million.

 
47

 
 
Transfers of costs to/from oil inventory: During the year ended December 31, 2012, approximately $1.1 million of oil inventory costs were added to lease operating expense as we sold more oil (1,188 MBbls) than we produced (1,185 MBbls), resulting in a reduction of oil inventory.  In the same period in 2011, approximately $0.4 million of oil inventory costs were removed from lease operating expense, even though we sold more oil (1,380 MBbls) than we produced (1,376 MBbls).  The increase in costs of $1.5 million was due to higher costs in 2012, including costs associated with Albacora production due to the interference testing.

Contract services: For the year ended December 31, 2012, we had the necessary equipment and production facilities at both the Corvina CX-11 platform and the Albacora A-platform to process the oil produced from those fields.  However, in the fourth quarter of 2011, we rented hydraulic jet pumps to stimulate and assist oil production in both the Corvina and Albacora fields and continued to use these services in the first six months of 2012 in both fields.  In the third quarter of 2012, we purchased the pump used in the Corvina field and continued to lease the pumps used in the Albacora field. As a result, contract service costs increased $1.4 million for the year ended December 31, 2012.

Workovers: For the year ended December 31, 2012, workover expense decreased $5.9 million compared to the same period in 2011.  The decrease in workover expense for the year ended December 31, 2012 is due to one major workover and three minor workovers in 2012 compared to three major workovers in 2011.

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, 2012, general and administrative expenses decreased by $6.8 million to $31.8 million from $38.6 million for the same period in 2011.  Stock-based compensation expense, a subset of general and administrative expenses, decreased by $1.2 million to $2.8 million for the year ended December 31, 2012 from $4.0 million for the same period in 2011.  The decrease in stock-based compensation expense is due to the vesting of the majority of awards granted in 2008, which were granted at times when the grant date fair value of the awards was higher due to the then higher price of our common stock.  As a result, our stock-based compensation expense declined since a majority of these older awards vested prior to 2012 and these are not contributing as much expense as compared to the same period in 2011.  Other general and administrative expenses decreased $5.6 million to $29.0 million from $34.6 million for the same period in 2011.  The $5.6 million decrease is due to lower consulting costs of $1.7 million, a decrease in a reserve against a claim of $1.5 million, lower salary and related costs of $1.4 million, lower legal costs of $0.8 million and lower other general and administrative costs of $0.2 million.

Geological, Geophysical and Engineering Expense

Geological, geophysical and engineering expenses include laboratory, environmental and seismic acquisition related expenses. For the year ended December 31, 2012, geological, geophysical and engineering expenses increased $31.4 million to $40.7 million compared to $9.3 million for the same period in 2011.  The increase is due to increased seismic acquisition activity associated with our seismic data acquisition plan for Block Z-1 in 2012, compared to our seismic data acquisition activities for Block XXII and Block XXIII in 2011.  We expect geological, geophysical and engineering expense to decrease in 2013 due to our recent sale of a 49% participating interest in Block Z-1.  The transfer of a 49% participating interest in Block Z-1 to Pacific Rubiales was effective on December 14, 2012 and the carry of exploratory expenditures for Block Z-1 by Pacific Rubiales began from that day forward.  Our share of the 2013 Block Z-1 exploratory expenditures should be fully funded by our partner under the carry agreement in place.
 
Dry Hole Costs

For the year ended December 31, 2011, we wrote off $13.1 million of exploratory dry hole costs related to the onshore Pampa la Gallina (PLG-1X) exploratory well in Block XIX.  In December 2011, after completing the technical review of information obtained during the drilling of the PLG-1X well, management decided the well had no further utility.

There were no similar expenses for the same period in 2012.

Depreciation, Depletion and Amortization Expense

For the year ended December 31, 2012, depreciation, depletion and amortization expense increased $7.0 million to $45.9 million from $38.9 million for the same period in 2011.  We expect depreciation, depletion and amortization expense to decrease in 2013 due to our recent sale of a 49% participating interest in Block Z-1, as our share of future production will be only 51%.

 
48

 
 
For the year ended December 31, 2012, depletion expense increased $4.7 million to $31.5 million from $26.8 million during the same period in 2011.  The increase is due to a lower reserve base in the Corvina and Albacora fields in 2012.
 
For the year ended December 31, 2012, depreciation expense increased $2.3 million to $14.4 million compared to $12.1 million for the same period in 2011 due to (1) increased production equipment and general equipment added toward the end of 2011 and (2) a change in useful life, as a result of new laws, of two vessels used in Marine operations that began contributing an additional $0.6 million of depreciation expense per quarter beginning in the third quarter of 2012 and is expected to continue through December 2014.

Standby Costs
 
For the year ended December 31, 2012, we incurred $5.3 million in standby rig costs.
 
During 2012, we had the Petrex-18 rig, which was previously leased to another operator in 2011, on standby through July 31, 2012.  Our contract on this rig was amended and the contract was suspended from August 1, 2012 through April 30, 2013.  We had the Petrex-28 rig on standby from September 2012 through December 2012, and expect to use this rig in drilling operations on the new CX-15 platform.  Additionally, in 2012, we had a workover rig, the Petrex-10, on standby for two months to allow for seismic acquisition activities where the workover rig was operating.  We expect standby costs to be lower in 2013 due to the amended contract for the Petrex-18 rig, and the beginning of the drilling program at the CX-15 platform.
 
For the year ended December 31, 2011, we incurred $4.5 million in standby costs, which includes $3.9 million of standby rig costs.  Additionally, we incurred $0.6 million of allocated expenses associated with drilling operations for the year ended December 31, 2011. 
 
During 2011, we had the Petrex-09 rig on standby for nine months during the year ending December 31, 2011.  This rig was returned to Petrex in January 2012.

Other Expense

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

There were no similar expenses for the same period in 2011.

Gain on Divestiture

On April 27, 2012, we and Pacific Rubiales (together with its subsidiaries) executed a SPA under which we formed an unincorporated joint venture relationship 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 in Block Z-1 and agreed to fund $185.0 million of our share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012. On December 14, 2012 Perupetro approved the terms of the amendment to the Block Z-1 license contract to recognize the sale of a 49% participating interest in offshore Block Z-1 to Pacific.  We and Pacific Rubiales waived and modified certain contract conditions in order to close the transaction.  On December 30, 2012, the Peruvian Government signed the Supreme Decree for the execution of the amendment to the Z-1 license contract. The gain on divestiture before tax results from the receipt of net proceeds (the $150.0 million, less transaction costs of $5.7 million) being greater than the net book value of 49% of Block Z-1 historic assets of $117.4 million. Tax impacts of this gain are reported under Income Taxes.

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, 2012, total other expense increased $6.2 million to $26.1 million compared to $19.9 million during the same period in 2011.  The increase is due primarily to the following:

 
49

 
 
Interest expense: For the year ended December 31, 2012, we recognized approximately $16.1 million of net interest expense which includes $31.7 million of interest expense reduced by $15.6 million of capitalized interest expense.  For the same period in 2011, we recognized $19.8 million of net interest expense, which included $30.5 million of interest expense reduced by $10.7 million of capitalized interest.  The decrease of $3.7 million in net interest expense for the year ended December 31, 2012 compared to the same period in 2011 is due to increased capitalized interest of $4.9 million because of higher average construction in progress balances between the two periods as a result of the CX-15 platform and Albacora production and gas injection facilities, which is partially offset by  higher interest expense of $1.2 million due to a higher average of interest bearing debt outstanding between the two periods.

Loss on extinguishment of debt: As a result of the prepayment and amendment to the $75.0 million secured debt facility during the second quarter of 2012, we incurred $5.8 million of fees and prepayment penalties and $1.1 million of debt issue costs.  The $5.8 million in fees and prepayment penalties were recognized as a “Loss on extinguishment of debt” in the consolidated statement of operations 25% was paid at the time of the amendment and prepayment and 25% was paid at the time of each of the next three quarterly interest payment dates ending in January 2013.  Approximately $1.5 million of the remaining $2.8 million of unamortized debt issue costs associated with the initial loan was expensed as a “Loss on extinguishment of debt” in the consolidated statement of operations when we prepaid $40.0 million of principal.  For the year ended December 31, 2012, we reported $7.3 million as a loss on extinguishment of debt.  There were no similar expenses for the same period in 2011.
 
Loss on derivatives: In connection with obtaining the $40.0 million and $75.0 million secured debt facilities in January and July 2011, respectively, we entered into performance based arranger fees (“Performance Based Arranger Fee”) that we are accounting for as embedded derivatives.  As a result of the fair value measurement at December 31, 2012 and 2011, respectively, from the measurement at January 1, 2012 and inception of the derivatives in 2011, respectively, the loss associated with the embedded derivatives increased $0.6 million to a $2.6 million loss for the year ended December 31, 2012 from a $2.0 million loss for the same period in 2011.
 
Investment income: For the year ended December 31, 2012, income from our investment in Ecuador property, net of investment amortization, decreased by $0.3 million to income of $0.1 million from income of $0.4 million in 2011.  For both periods, the difference is due to dividends received of $0.3 million during the year ended December 31, 2012, compared to $0.6 million in dividends received during the year ended December 31, 2011.  For both the year ended December 31, 2012 and 2011, investment income includes amortization expense of approximately $188,000 in each period.

Income Taxes
 
The source of net loss before income tax expense (benefit) for the year ended December 31, 2012 and 2011 is as follows (in thousands):
 
   
2012
   
2011
 
United States
  $ (6,465 )   $ (14,148 )
Foreign
    (48,238 )     (17,244 )
Loss before income taxes
  $ (54,703 )   $ (31,392 )
 
 
50

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

   
2012
   
2011
 
Current Taxes
           
Federal
  $ -     $ -  
Foreign
    13,551       179  
Total Current
    13,551       179  
                 
Deferred Taxes
               
Federal
  $ -     $ -  
Foreign
    (29,165 )     2,256  
Total Deferred
    (29,165 )     2,256  
Total income tax expense (benefit)
  $ (15,614 )   $ 2,435  
 
The income tax expense (benefit) for the year ended December 31, 2012 and 2011 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):
 
   
2012
   
2011
 
Federal statutory income tax rate
  $ (18,599 )   $ (10,673 )
Increases (decreases) resulting from:
               
Peruvian income tax - rate difference less than 34% statutory
    7,791       2,771  
Permanent book/tax differences
    (621 )     1,016  
Non-deductible intercompany expenses and other
    2,763       4,623  
Effect of asset sale with retained oil intangilble tax attribute
    (15,111 )     -  
Effect of cumulative profit sharing adjustment
    (895 )     -  
Effect of foreign exchange rate
    (1,678 )     -  
Effect of change from crediting foreign withholding tax to deducting foreign withholding tax
    -       2,338  
Current year foreign withholding tax
    1,699       2,201  
Change in valuation allowance
    9,037       159  
Total income tax expense (benefit)
  $ (15,614 )   $ 2,435  
 
 
51

 

A summary of the components of deferred tax assets, deferred tax liabilities and other taxes deferred at December 31, 2012 and 2011 are presented below (in thousands):

   
2012
   
2011
 
Deferred Tax:
           
Asset:
           
Net Operating Loss
  $ 57,698     $ 39,515  
Deferred Compensation
    4,221       3,667  
Foreign Tax AMT
    -       7  
Asset Basis Difference
    5,129       -  
Exploration Expense
    14,054       13,982  
Depletion
    3,652       94  
Asset Retirement Obligation
    593       141  
Overhead Allocation to Foreign Locations
    7,476       5,073  
Other
    2,069       1,365  
Liability:
               
Preoperation Expenses
    -       -  
Depreciation
    (724 )     (18 )
Asset Basis Difference
    -       (7,871 )
Other
    (30 )     -  
Net Deferred Tax Asset
  $ 94,138     $ 55,955  
                 
Less Valuation Allowance
    (38,896 )     (29,859 )
Deferred tax asset
  $ 55,242     $ 26,096  
 
At December 31, 2012, we had recognized a gross deferred tax asset related to net operating loss carryforwards of $57.7 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 $5.8 million in 2012 and $3.9 million in 2011.

At December 31, 2012, we had recognized a gross deferred tax asset related to net operating loss carryforwards attributable to the United States of $43.0 million, before application of the valuation allowances.  As of December 31, 2012, we had a valuation allowance for the full amount of the domestic deferred tax asset of $35.8 million, resulting from the income tax benefit generated from net losses, as we believe, based on the weight of available evidence, that it is more likely than not that the deferred tax asset will not be realized prior to the expiration of net operating loss carryforwards in various amounts through 2032. 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 its 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, 2012, we had recognized a gross deferred tax asset related to net operating loss carryforwards attributable to foreign jurisdictions of $14.7 million, before application of the valuation allowances, attributable to foreign net operating losses, which begin to expire in 2014.  We are subject to Peruvian income tax on its earnings at a statutory rate, as defined in the Block Z-1 License Contract, of 22%.  We assessed the realizability of the deferred tax asset generated in Peru.  We considered whether it is more likely than not that some portion or all of the deferred tax asset will not be realized.  The ultimate realization of the deferred tax asset is dependent upon the generation of future taxable income in Peru during the periods in which those temporary differences become deductible.  Based upon the level of historical taxable income, the availability of certain prudent and feasible income tax planning opportunities and projections for future taxable income over the periods in which the deferred tax assets are deductible, along with the transition into the commercial phase under the Block Z-1 License Contract, we believe it is more likely than not that it will realize the majority of the these deductible differences at December 31, 2012.  In addition, we had a $3.5 million valuation allowance on certain foreign deferred tax assets related to overhead allocations and exploration activities on Blocks XIX, XXII and XXII, as we believe we may not receive the full benefit of these deductions.  As a result, we recognized a net deferred tax asset of $55.3 million related to our foreign operations as of December 31, 2012.

 
52

 
 
We recognized a total tax provision for the year ended December 31, 2012 of approximately $15.6 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 prohibits the recognition of such benefits until the related compensation deduction reduces the current tax liability.
 
Estimated interest and penalties related to potential underpayment on unrecognized tax benefits, if any, are classified as a component of tax expense in the Consolidated Statement of Operations.  We did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the year.  We did not have any uncertain tax positions generated from unrecognized tax benefits resulting from differences between positions taken in tax returns and amounts recognized in the financial statements as of December 31, 2012 or December 31, 2011.

Net Loss

For the year ended December 31, 2012, our net loss increased $5.3 million to a net loss of $39.1 million, or ($0.34) per basic and diluted share, from a net loss of $33.8 million, or ($0.29) per basic and diluted share, for the same period in 2011.
 
 
53

 

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
 
   
Year Ended
December 31,
       
   
2011
   
2010
   
Increase/ (Decrease)
 
Net sales volume:
 
(in thousands except per bbl information)
       
Oil (MBbls)
    1,380       1,518       (138 )
                         
Net revenue:
                       
Oil revenue, net
  $ 139,354     $ 110,075       29,279  
Other revenue
    4,386       389       3,997  
Total net revenue
    143,740       110,464       33,276  
                         
Average sales price (approximately):
                       
Oil (per Bbl)
  $ 101.01     $ 72.53     $ 28.48  
                         
Operating and administrative expenses
                       
Lease operating expense
    50,792       32,585       18,207  
General and administrative expense
    38,600       32,655       5,945  
Geological, geophysical and engineering expense
    9,315       19,107       (9,792 )
Dry hole costs
    13,082       32,778       (19,696 )
Depreciation, depletion and amortization expense
    38,944       33,755       5,189  
Standby costs
    4,529       7,487       (2,958 )
Other expense
    -       12,889       (12,889 )
Total operating and administrative expenses
    155,262       171,256       (15,994 )
                         
Operating loss
  $ (11,522 )   $ (60,792 )   $ 49,270  
 
Net Oil Revenue
 
On November 30, 2010, we placed the Corvina field into commercial production. Prior to that time all oil sales were from oil produced under the Peruvian well testing regulations.  Additionally, all oil sales from the Albacora field were from oil produced under the Peruvian well testing regulations as described above.
 
For the year ended December 31, 2011, our net oil revenue increased by $29.3 million to $139.4 million from $110.1 million for the same period in 2010.  The increase in net oil revenue is due to an increase of $28.48, or 39.3%, in the average per barrel sales price received, partially offset by a decrease in the amount of oil sold of 138 MBbls.

The 2011 price/volume analysis is as follows:

   
(in thousands)
 
2010 Oil revenue, net
  $ 110,075  
Changes associated with sales volumes
    (10,017 )
Changes associated with prices
    39,296  
2011 Oil revenue, net
  $ 139,354  
 
 
54

 

For the year ended December 31, 2011 we had consistent oil production from five (gross and net) producing wells and intermittent production from six (gross and net) wells.  During the same period in 2010, we had intermittent oil production from six (gross and net) producing wells in the Corvina field and one (gross and net) producing well in the Albacora field.  Total oil production for the year ended December 31, 2011 was 1,376 MBbls compared to 1,527 MBbls for the same period in 2010.  Total sales for the year ended December 31, 2011 was 1,380 MBbls compared to 1,518 MBbls for the same period in 2010.

The decrease in oil production is due to (1) having high first year production rates for four wells, the, the CX11-17D, CX11-19D, A-14XD, and CX11-23D, in 2010 with no similar occurrences in 2011; (2) higher decline rates than expected in oil production; and (3) oil production from the Albacora field being adversely affected by the timing of permits to produce the field as well as technical issues detailed under Albacora Field above.

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.  However, the royalty calculation is based on the prior five-day average of a blend of crude oil prices before the crude oil delivery date, as opposed to the price we receive for oil which is based on the prior two-week average of a blend of crude oil prices before the crude oil delivery date.  For the year ended December 31, 2011 and 2010, the revenues we received are net of royalty costs of approximately 5% of gross revenues or $7.5 million and $6.3 million, respectively.
 
Other Revenue
 
After suspending our drilling operations at the A platform in the Albacora field in Block Z-1 in October 2010, another operator chartered two of our support vessels, the BPZ-02 and Don Fernando, for a one-year term.  For the year ended December 31, 2011 and 2010, we recognized approximately $4.4 million and $0.4 million, respectively, of other revenue associated with the chartering of those vessels.  In September 2011, the third party operator chartering the Don Fernando returned the vessel to us.  In January 2012, the third party operator chartering the BPZ-02 returned the vessel to us.
 
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.  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, 2011, lease operating expenses increased by $18.2 million to $50.8 million ($36.82 per Bbl) from $32.6 million ($21.47 per Bbl) for the same period in 2010.  The increase in the lease operating expenses is due to increased workover expenses of $10.1 million,  increased repair and maintenance expenses of $3.9 million, increased insurance costs of $1.9 million, increased salary and related expense of $1.2 million, increased contract labor and consulting services of $1.1 million, increased equipment rental of $0.9 million, increased supplies of $0.7 million, increased fuel costs of $0.7 million, a increase in the costs associated with oil inventory due to the small buildup of oil inventory in 2010 of $0.4 million,  increased other transportation expense of $0.2 million and increased other lease operating expenses of $0.9 million.  Partially offsetting these increases to expense are decreases in contract services of $1.8 million, decreases in crude oil transportation costs of $1.1 million and lab fees of $0.9 million.

The following details the significant items contributing to the increase in lease operating expense of $18.2 million for the year ended December 31, 2011 compared to the year ended December 31, 2010:

Workovers: For the year ended December 31, 2011, workover expense increased $10.1 million compared to the same period in 2010.  The increase in workover expense for the year ended December 31, 2011 is due to three major workovers in 2011 compared to a completion of one major workover and three minor workovers in 2010.

Repairs and maintenance: For the year ended December 31, 2011, repairs and maintenance expense increased $3.9 million compared to the same period in the prior year.

During the year ended December 31, 2011, the increase in maintenance and repair expense was due to an incident that occurred while moving certain equipment during our workover campaign from Albacora to Corvina.  As a result of the incident, we incurred approximately $2.0 million of additional expense for repairs to damaged equipment.  During the year ended December 31, 2011, we incurred approximately $1.8 million related to a new maintenance and repair program to provide support for the Corvina compression facilities.  In addition, the BPZ-01 vessel completed a scheduled dry dock for maintenance and repairs at a total cost of approximately $1.4 million.  There were no similar expenses for the same periods in 2010.  These amounts were offset by approximately $1.3 million of expenses primarily related to lower third party maintenance and support vessels and Don Fernando maintenance and repair expenses.

 
55

 
 
Salaries and insurance costs:  For the year ended December 31, 2011, insurance costs increased $1.9 million compared to the same period in 2010.  The reason for the increase is due to an increase in value of property insured, increases in specific areas of coverage and the increased activity in 2011 compared to the same period in 2010.  For the year ended December 31, 2011, salaries increased $1.2 million compared to the same period in 2010.  The reason for the increase is the additional personnel required to operate the permanent facilities on the Corvina platform and to operate an increased number of wells in 2011 compared to 2010.

Albacora lease operating expenses: For the year ended December 31, 2011, we incurred approximately $5.4 million of lease operating expenses over six months to conduct repairs and field maintenance with limited associated oil production. We incurred four months of lease operating expenses with no associated oil production during the first half of 2011 because the production from the A-14XD well was suspended in late January 2011 when our extended well testing permit and gas flaring permit expired.  Production resumed in the second quarter of 2011. During the fourth quarter of 2011, we had two months of limited oil production from the Albacora field as we attempted to manage technical difficulties encountered with each of the wells.
 
Contract services: For the year ended December 31, 2011, we had the necessary equipment and production facilities at both the Corvina CX-11 platform and Albacora A-platform to process the oil produced from those fields.  During the same period in 2010, we had to rent the pumps and separators from third parties.  However in the fourth quarter of 2011, we rented hydraulic jet pumps to stimulate and assist oil production in both the Corvina and Albacora fields. As a result, contract service costs decreased $1.8 million for the year ended December 31, 2011 compared to the same period in 2010.

Crude oil transportation: In connection with the suspension of oil production at the Albacora field during the six months ended June 30, 2011 and limited oil production during the three months ended December 31, 2011, we incurred reduced oil transportation costs compared to the same periods in the prior year. As a result, crude oil transportation costs decreased $1.1 million during the year ended December 31, 2011 compared to the same period in 2010.
 
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, 2011, general and administrative expenses increased by $5.9 million to $38.6 million from $32.7 million for the same period in 2010, and include the costs related to third party marine operating costs in 2011.  Stock-based compensation expense, a subset of general and administrative expenses, decreased by $1.8 million to $4.0 million for the year ended December 31, 2011 from $5.8 million for the same period in 2010. The decrease in stock-based compensation expense is due to the vesting of the majority of awards granted in 2007 and 2008, which were granted at times when the grant date fair value of the awards was higher due to the high price of our common stock. Therefore, our stock-based compensation expense has declined as a majority of these older awards have vested and are not contributing as much expense as compared to the same period in 2010.  Other general and administrative expenses increased $7.7 million to $34.6 million from $26.9 million for the same period in 2010. The $7.7 million increase is due to increases in salary and salary related costs of $5.5 million, an increase of $1.5 million due to placing a reserve against a claim, increased community relations expense of $0.6 million and increased other expenses of $0.1 million.

 Contributing to the change in salary and related expenses are (i) increased salary and benefits associated with more new employees in 2011 and additional severance costs incurred as more employees left in 2011 than in 2010, (ii) an increase in discretionary bonuses and (iii) an increase in benefits related to Peruvian employee vacation accruals.
 
Geological, Geophysical and Engineering Expense
 
Geological, geophysical and engineering expenses include laboratory, environmental and seismic acquisition related expenses. For the year ended December 31, 2011, geological, geophysical and engineering expenses decreased $9.8 million to $9.3 million compared to $19.1 million for the same period in 2010.  The reason for the decrease in geological, geophysical and engineering expense is due to decreased seismic data acquisition and processing expenses of $9.2 million related to Block XXII and Block XXIII in 2010, and decreased environmental, laboratory and consulting expenses of $0.6 million for the year ended December 31, 2011 compared to the same period in 2010.

 
56

 
 
Dry Hole Costs

For the year ended December 31, 2011, we wrote off $13.1 million of exploratory dry hole costs related to the onshore Pampa la Gallina (PLG-1X) exploratory well in Block XIX.  In December 2011, after completing technical review of information obtained during the drilling of the PLG-1X well, management decided the well had no further utility.

For the year ended December 31, 2010, we wrote off $17.9 million of exploratory dry hole costs related to the A-17D well in the Albacora field which, in September 2010, was determined to have no commercial quantities of hydrocarbons. In addition, we wrote off $14.9 million of suspended well costs for two previously drilled wells, the A-15D and A-16D, as those wells were intended to follow the same trajectory and reach the same location as the A-17D well, but neither reached the target due to mechanical problems and both wells were junked and abandoned.
 
Depreciation, Depletion and Amortization Expense
 
 For the year ended December 31, 2011, depreciation, depletion and amortization expense increased $5.1 million to $38.9 million from $33.8 million for the same period in 2010.
 
For the year ended December 31, 2011, depletion expense decreased $1.7 million to $26.8 million from $28.5 million during the same period in 2010.  The decrease in depletion expense is mainly due to the higher reserves associated with the Corvina field (6.3 MMBbls average in 2011 versus 5.7 MMBbls average in 2010) resulting in lower depletion rates in 2011 and overall lower production compared to the same period in 2010.
 
For the year ended December 31, 2011, depreciation expense increased $6.8 million to $12.1 million compared to $5.3 million for the same period in 2010 due to (1) increased production and injection equipment added at the end of 2010 and in 2011 to support our operations and (2) reduced capitalization of depreciation on support equipment to construction in progress, due to less drilling in 2011. For the year ended December 31, 2011, we capitalized approximately $0.3 million of depreciation expense on support equipment to construction in progress compared to $1.8 million for the same period in 2010.

Standby Costs
 
After completing the CX11-23D well in the Corvina field and the A-17D well in the Albacora field at the end of the third quarter of 2010, we suspended drilling operations until we could complete a seismic data acquisition program planned for the first quarter of 2012 and fabricate and install a new drilling platform in Block Z-1.  As a result, for the year ended December 31, 2011, we incurred $4.5 million in standby costs compared to $7.5 million for the same period in 2010.  These amounts include $3.9 million and $4.9 million, respectively, of standby rig costs for the years ended December 31, 2011 and 2010.  Additionally, we incurred $0.6 million and $2.6 million, respectively, of allocated expenses associated with drilling operations for the year ended December 31, 2011 and 2010.

Other Expense

For the year ended December 31, 2010, we reported $12.9 million of charges as “Other expense.” These charges include $10.7 million of charges related to certain engineering, consulting, environmental and legal costs for our planned gas plant, pipeline and gas-to-power project and $2.2 million of charges related to the abandonment of two platforms. With respect to the $10.7 million of charges related to the planned gas plant, pipeline and gas-to-power project, during the third quarter of 2010, management determined that there is no future benefit expected from these engineering and development costs associated with our current gas plant, pipeline and gas-to-power project plans.  Accordingly, we wrote off these costs. With respect to the $2.2 million of platform abandonment costs, we determined that two previously built platforms, one located in the Piedra Redonda field and the CX-13 platform located in the eastern part of the Corvina field, both of which were in existence when we acquired the rights to the offshore Block Z-1 in northwest Peru, are not suitable for our future oil development plans. Accordingly, we wrote off the $1.4 million costs incurred to evaluate the feasibility of refurbishing and using these platforms. In addition, we accrued $0.8 million of abandonment costs related to the Piedra Redonda platform as we are obligated to ensure the platform does not cause a threat to marine vessels operating in the area or marine wildlife. There were no similar expenses for the same periods in 2011.

 
57

 
 
Other Income/(Expense)
 
 Other income (expense) includes non-operating income items.  These items include interest expense and income, 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, 2011, total other expense increased $9.3 million to $19.9 million compared to $10.6 million during the same period in 2010.  The increase is due primarily to the following:

Interest expense: For the year ended December 31, 2011, we recognized approximately $19.8 million of net interest expense which includes $30.5 million of interest expense reduced by $10.7 million of capitalized interest expense.  For the same period in 2010, we recognized $11.6 million of net interest expense, which included $21.2 million of interest expense reduced by $9.6 million of capitalized interest.  The increase of $8.2 million in net interest expense for the year ended December 31, 2011, compared to the same period in 2010, is due to having higher debt outstanding in 2011 compared to 2010.
 
Loss on derivatives: In connection with obtaining the $40.0 million and $75.0 million secured debt facilities, we entered into a Performance Based Arranger Fee that we are accounting for as an embedded derivative.  As a result of the fair value measurement of this fee for the respective facilities for the year ended December 31, 2011, we recorded a $2.0 million loss.  There were no similar expenses incurred by us during the year ended December 31, 2010.
 
Investment income: For the year ended December 31, 2011, income from our investment in Ecuador property, net of investment amortization, decreased by $0.3 million to income of $0.4 million from income of $0.7 million in 2010.  For both periods, the difference is due to dividends received of $0.9 million during the year ended December 31, 2010, compared to $0.6 million in dividends received during the year ended December 31, 2011.  For both the year ended December 31, 2011 and 2010, investment income includes amortization expense of approximately $188,000 in each period.
 
Income Taxes
 
The source of loss before income tax expense (benefit) for the year ended December 31, 2011 and 2010 is as follows (in thousands):
 
   
2011
   
2010
 
United States
  $ (14,148 )   $ (12,688 )
Foreign
    (17,244 )     (58,691 )
Loss before income taxes
  $ (31,392 )   $ (71,379 )
 
The income tax provision (benefit) for the year ended December 31, consists of the following (in thousands):

   
2011
   
2010
 
Current Taxes
           
Federal
  $ -     $ (200 )
Foreign
    179       2,151  
Total Current
    179       1,951  
                 
Deferred Taxes
               
Federal
  $ -     $ -  
Foreign
    2,256       (13,559 )
Total Deferred
    2,256       (13,559 )
Total income tax expense (benefit)
  $ 2,435     $ (11,608 )
 
 
58

 

The income tax expense (benefit) for the year ended December 31, 2011 and 2010 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):

   
2011
   
2010
 
Federal statutory income tax rate
  $ (10,673 )   $ (24,269 )
Increases (decreases) resulting from:
               
Peruvian income tax - rate difference less than 34% statutory
    2,771       5,763  
Permanent book/tax differences
    1,016       (365 )
Non-deductible intercompany expenses and other
    4,623       (2,922 )
Effect of change from crediting foreign withholding tax to deducting foreign withholding tax
    2,338       -  
Current year foreign withholding tax
    2,201       -  
Change in valuation allowance
    159       10,185  
Total income tax expense (benefit)
  $ 2,435     $ (11,608 )

A summary of the components of deferred tax assets, deferred tax liabilities and other taxes deferred at December 31, 2011 and 2010 are presented below (in thousands):

   
2011
   
2010
 
Deferred Tax:
           
Asset:
           
Net Operating Loss
  $ 39,515     $ 27,039  
Deferred Compensation
    3,667       2,658  
Foreign Tax AMT
    7       3,535  
Exploration Expense
    13,982       10,720  
Depletion
    94       9,148  
Asset Retirement Obligation
    141       105  
Overhead Allocation to Foreign Locations
    5,073       6,326  
Other
    1,365       681  
Liability:
               
Preoperation Expenses
    -       (275 )
Depreciation
    (18 )     (18 )
Asset Basis Difference
    (7,871 )     (1,849 )
Other
    -       -  
Net Deferred Tax Asset
  $ 55,955     $ 58,070  
                 
Less Valuation Allowance
    (29,859 )     (29,698 )
Deferred tax asset
  $ 26,096     $ 28,372  

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 $3.9 million in 2011 and $4.3 million in 2010.  At December 31, 2011, we had recognized a gross deferred tax asset related to net operating loss carryforwards of $39.5 million before application of the valuation allowances.

At December 31, 2011, we had recognized a gross deferred tax asset related to net operating loss carryforwards attributable to United States of $31.9 million, before application of the valuation allowances.  As of December 31, 2011, we had a valuation allowance for the full amount of the domestic deferred tax asset of $27.1 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 2031. 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 US 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.

 
59

 
 
At December 31, 2011, we had recognized a gross deferred tax asset related to net operating loss carryforwards attributable to foreign jurisdictions of $7.6 million, before application of the valuation allowances, attributable to foreign net operating losses, which begin to expire in 2014.  We are subject to Peruvian income tax on earnings at a statutory rate, as defined in the Block Z-1 License Contract, of 22%.  We assessed the realizability of the deferred tax asset generated in Peru.  We considered whether it is more likely than not that some portion or all of the deferred tax asset will not be realized.  The ultimate realization of the deferred tax asset is dependent upon the generation of future taxable income in Peru during the periods in which those temporary differences become deductible.  Based upon the level of historical taxable income, the availability of certain prudent and feasible income tax planning opportunities and projections for future taxable income over the periods in which the deferred tax assets are deductible, along with the transition into the commercial phase under the Block Z-1 License Contract, we believe it is more likely than not that we will realize the majority of the these deductible differences at December 31, 2011.  As a result, we recognized a net deferred tax asset of $26.1 million, related to foreign operations, as of December 31, 2011.  In addition we had a $2.8 million valuation allowance on certain foreign deferred tax assets related to overhead allocations and exploration activities on Blocks XIX, XXII and XXII as we may not receive the full benefit of these deductions.

As a result, we recognized a total tax provision for the year ended December 31, 2011 of approximately $2.4 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 did not recognize any excess tax benefit related to its stock compensation plans.  ASC Topic 718 prohibits the recognition of such benefits until the related compensation deduction reduces the current tax liability.

Estimated interest and penalties related to potential underpayment on unrecognized tax benefits, if any, are classified as a component of tax expense in the Consolidated Statement of Operations.  We did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the year.  We did not have any uncertain tax positions generated from unrecognized tax benefits resulting from differences between positions taken in tax returns and amounts recognized in the financial statement as of December 31, 2011 or December 31, 2010.

Net Loss

For the year ended December 31, 2011, our net loss decreased $26.0 million to a net loss of $33.8 million, or ($0.29) per basic and diluted share, from net loss of $59.8 million, or ($0.52) per basic and diluted share, for the same period in 2010.

Proved Reserves

We are focused on the development and production of our holdings in Peru.  Future profitability partially depends on commodity prices and the cost of finding and developing oil and gas reserves. Reserves growth can be achieved through successful exploration and development drilling and improved recovery of producing properties.

Extensions, Discoveries and Other Additions

In 2012, the reserve analysis prepared by NSAI included no extensions, discoveries and other additions.  In 2011, there were no extensions, discoveries and other additions.  The 2010 extensions, discoveries and other additions of 2.6 MMBbls were due to additional wells drilled in the Corvina field.

Revisions of Previous Estimates

The 2012 reserve analysis prepared by NSAI included negative revisions due to performance of 0.7 MMBbls.  The negative revisions were due to workovers pending on the 14D and 15D wells at the Corvina CX-11 platform, as well as removal of the Albacora A12F well from the proved category given its required conversion to a gas injection well.   The 2012 reserve report prepared by NSAI used a $108.10 per barrel price.  The 2011 reserve analysis prepared by NSAI included negative revisions due to performance of 3.2 MMBbls, partially offset by positive revisions due to price of 0.4 MMBbls.   The negative revisions were due to the lower than expected performance of our 2010 proved developed non producing wells that were intervened in 2011 in the Corvina field and in the Albacora field.  The 2011 reserve report prepared by NSAI used a $106.56 per barrel price.  The 2010 reserve analysis  prepared by NSAI included positive revisions due to price of approximately 347 MBbls that was partially offset by negative revisions of approximately 28 MBbls due to performance.  The 2010 reserve report prepared by NSAI used a $76.92 per barrel price.

 
60

 
 
Sales of Reserves in Place

The 2012 reserve analysis prepared by NSAI included sales in place of 16.4 MMBbls that relates to our sale of a 49% participating interest in Block Z-1.  There were no sales in place in 2011 and 2010.

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,” 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.

Standardized Measure of Discounted Future Net Cash Flows

 At December 31, 2012, the discounted estimated future net cash flows after-tax (at 10%) from our proved reserves were $0.9 billion (measured in accordance with the regulations of the SEC and the Financial Accounting Standards Board). This amount was calculated based on the 12-month average beginning-of-month prices for the year, held flat for the life of the reserves.  The decrease of $0.6 billion, or 42%, in 2012 compared to 2011 is primarily due to our sale of a 49% participating interest under the Block Z-1 license contract.  We now own a 51% participating interest in Block Z-1.  See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates” and Item 8. “Supplemental Oil and Gas Disclosure,” of this Form 10-K.

The present value of future net cash flows does not purport to be an estimate of the fair value of our proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil.

Liquidity, Capital Resources and Capital Expenditures

At December 31, 2012, we had cash and cash equivalents of $83.5 million, an accounts receivable balance of $24.5 million and working capital of $58.8 million.
 
At December 31, 2012, we had trade accounts payable and accrued liabilities of $56.0 million.

At December 31, 2012, our outstanding debt consisted of 2015 Convertible Notes whose net amount of $153.5 million includes the $170.9 million of principal reduced by $17.4 million of the remaining unamortized discount, $32.7 million outstanding under the $40.0 million secured debt facility and $35.0 million outstanding under the $75.0 million secured debt facility.  At December 31, 2012 the balance in both the debt service reserves accounts for both the $40.0 million secured debt facility and the $75.0 million secured debt facility was $32.7 million and $35.0 million respectively.  At December 31, 2012, the current and long-term portions of our long-term debt were $24.0 million and $197.2 million, respectively.